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Exhibit 99.2

 

February 9, 2015

Dear Atlas Energy, L.P. Unitholder:

We are pleased to inform you that the board of directors of the general partner of Atlas Energy, L.P. has approved the distribution of approximately 26.0 million common units representing a 100% limited liability company interest in Atlas Energy Group, LLC, which we also refer to as “New Atlas,” a Delaware limited liability company and wholly owned subsidiary of Atlas Energy that will hold all of Atlas Energy’s assets and businesses other than those related to its “Atlas Pipeline Partners” segment. Following the separation, New Atlas will hold all of Atlas Energy’s businesses other than its midstream business, including holding the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in Atlas Resource Partners, L.P. (a publicly traded master limited partnership and independent developer and producer of natural gas, crude oil and natural gas liquids), Atlas Energy’s general and limited partner interests in its exploration and production development subsidiary, which currently conducts operations in the mid-continent region of the United States, its general and limited partner interests in Lightfoot Capital Partners, a limited partnership investment business, and its other natural gas and oil exploration and production assets.

The distribution will be made by Atlas Energy on a pro rata basis to its common unitholders, and, as a result of the distribution, New Atlas will become a separate, publicly traded company. We expect the distribution of New Atlas common units to occur on February 28, 2015 by way of a pro rata distribution to Atlas Energy unitholders. Each Atlas Energy unitholder will receive one common unit of New Atlas for every two common units of Atlas Energy held by such unitholder at the close of business on February 25, 2015, the record date of the distribution. Atlas Energy will not distribute any fractional common units of New Atlas, but instead will distribute cash in lieu of any fractional common unit of New Atlas that you would have received after application of the above ratio. Following the distribution, Atlas Energy will no longer own any common units of New Atlas and, as more fully described in the accompanying information statement, the New Atlas unitholders will elect the board of directors of New Atlas.

Immediately following the distribution, Atlas Energy will continue to hold, directly or indirectly, the general partner interest, incentive distribution rights and Atlas Energy’s common units in Atlas Pipeline Partners, L.P. (a publicly traded master limited partnership and midstream energy service provider engaged in natural gas gathering, processing and treating services), and Atlas Energy will be acquired by Targa Resources Corp. through a merger of a subsidiary of Targa Resources with and into Atlas Energy, with Atlas Energy surviving this merger as a subsidiary of Targa Resources. We refer to this merger as the “Atlas Merger.” In addition, Atlas Pipeline Partners will be acquired by Targa Resources Partners LP through a merger of a subsidiary of Targa Resources Partners with and into Atlas Pipeline Partners, with Atlas Pipeline Partners surviving this merger as a subsidiary of Targa Resources Partners. We refer to this merger as the “APL Merger.” The distribution, the Atlas Merger and the APL Merger are each conditioned on the other and will each occur only if the other occurs or will occur.

The New Atlas common units issued in the distribution will be in book-entry form only, which means that no physical stock certificates will be issued. If you own your Atlas Energy common units through a broker, your brokerage account will be credited with the new common units of New Atlas. If you have an account with Atlas Energy’s transfer agent, the new common units of New Atlas will be credited to that account. Unitholder approval of the distribution is not required, and you are not required to take any action to receive your common units of New Atlas. Following the distribution, if you are an Atlas Energy unitholder on the record date, you will receive common units of New Atlas, in addition to the merger consideration of 0.1809 of a share of Targa Resources Corp. common stock, par value $0.001 per share, and $9.12 in cash, without interest, that you will receive as a result of the Atlas Merger. Your New Atlas units will not be affected by the Atlas Merger.

In general, the distribution of common units of New Atlas by Atlas Energy should not be taxable for U.S. federal income tax purposes, except to the extent that the aggregate amount of money you receive (including cash received in lieu of fractional units), or are deemed to receive, as a result of the distribution, exceeds the tax basis in your interest in Atlas Energy common units immediately before the distribution. The rules governing the tax consequences of the distribution are complex. You are urged to read the summary of the U.S. federal income tax consequences of the distribution later in this information statement and to consult your own tax advisor regarding the tax consequences of the distribution to you in your particular circumstances.

New Atlas has been authorized to have its common units listed on the New York Stock Exchange under the symbol “ATLS,” subject to official notice of distribution. Following the Atlas Merger, Atlas Energy will be delisted from and will cease to trade on the New York Stock Exchange.

We have prepared an information statement, which describes the distribution of common units of New Atlas in detail and contains important information about New Atlas. We are mailing to all Atlas Energy common unitholders a notice with instructions on how to access the information statement online and receive hard copies. No action is required by you, but we urge you to read this information statement carefully. For additional information about the mergers of Atlas Energy and Targa Resources and of Atlas Pipeline Partners and Targa Resources Partners, we encourage you to read Atlas Energy’s separate proxy statement/prospectus relating to the Atlas Merger.

We want to thank you for your continued support of Atlas Energy, and we look forward to your support of New Atlas in the future.

 

Edward E. Cohen Chief Executive Officer Atlas Energy GP, LLC		Jonathan Z. Cohen Executive Chairman of the Board of Directors Atlas Energy GP, LLC

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INFORMATION STATEMENT

ATLAS ENERGY GROUP, LLC

 

 

This information statement is being furnished in connection with the distribution by Atlas Energy, L.P. to its unitholders of approximately 26.0 million common units representing a 100% limited liability company interest in Atlas Energy Group, LLC (which we refer to in this information statement as “New Atlas”), which will, at the time of the distribution, hold, directly or indirectly, all of Atlas Energy’s assets and businesses, other than those related to its “Atlas Pipeline Partners” segment. Following the separation, New Atlas will hold all of Atlas Energy’s businesses other than its midstream business, including holding the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in Atlas Resource Partners, L.P. (a publicly traded master limited partnership and independent developer and producer of natural gas, crude oil and natural gas liquids), Atlas Energy’s general and limited partner interests in its exploration and production development subsidiary, which currently conducts operations in the mid-continent region of the United States, its general and limited partner interests in Lightfoot Capital Partners, a limited partnership investment business, and its other natural gas and oil exploration and production assets.

The distribution will be made by Atlas Energy on a pro rata basis to its unitholders, and, as a result of the distribution, New Atlas will become a separate, publicly traded company. For every two common units of Atlas Energy held of record by you as of the close of business on February 25, 2015, the record date for the distribution, you will receive one common unit of New Atlas. You will receive cash in lieu of any fractional common unit of New Atlas that you would have received after application of the above ratio. We expect the distribution to occur on February 28, 2015, which we refer to as the “distribution date.” Following the distribution, Atlas Energy will no longer own any common units of New Atlas and, as more fully described in the accompanying information statement, the New Atlas unitholders will elect the board of directors of New Atlas.

Immediately following the distribution, Atlas Energy, which will continue to hold the assets related to its “Atlas Pipeline Partners” segment, will be acquired by Targa Resources Corp. through a merger of a subsidiary of Targa Resources with and into Atlas Energy, with Atlas Energy surviving the merger as a subsidiary of Targa Resources. We refer to this merger as the “Atlas Merger.” In addition, Atlas Pipeline Partners will be acquired by Targa Resources Partners LP through a merger of a subsidiary of Targa Resources Partners with and into Atlas Pipeline Partners, with Atlas Pipeline Partners surviving this merger as a subsidiary of Targa Resources Partners. We refer to this merger as the “APL Merger.” The distribution, the Atlas Merger and the APL Merger are each conditioned on the other and will each occur only if the other occurs or will occur. This information statement is being sent to you to describe the distribution and requires no action by you. Please refer to the proxy statement/prospectus relating to the Atlas Merger for additional information regarding that transaction and the APL Merger.

In general, the distribution of common units of New Atlas by Atlas Energy should not be taxable for U.S. federal income tax purposes, except to the extent that the aggregate amount of money you receive (including cash received in lieu of fractional units), or are deemed to receive, as a result of the distribution exceeds the tax basis in your interest in Atlas Energy common units immediately before the distribution. The rules governing the tax consequences of the distribution are complex. You are urged to read the summary of the U.S. federal income tax consequences of the distribution later in this information statement and to consult your own tax advisor regarding the tax consequences of the distribution to you in your particular circumstances.

As discussed under “The Separation and Distribution—Trading Prior to the Distribution Date,” if you sell your Atlas Energy common units in the “regular-way” market before the distribution, you also will be selling your right to receive New Atlas common units in connection with the distribution.

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The distribution, the Atlas Merger and the APL Merger will each occur only if the other occurs or will occur. If the conditions to the Atlas Merger (including, among others, approval of the Atlas Merger by the Atlas Energy unitholders and the Targa Resources stockholders) are not satisfied or waived, the conditions to the distribution will not be satisfied, and Atlas Energy will not be required to complete the distribution. Likewise, if the conditions to the APL Merger (including, among others, approval of the APL Merger by the Atlas Pipeline Partners unitholders) are not satisfied or waived, the conditions to the distribution will not be satisfied, and Atlas Energy will not be required to complete the distribution. As a result, the record date for the distribution, the distribution date and the closing date for the Atlas Merger will be the same day.

Following the distribution, if you are an Atlas Energy unitholder on the record date, you will receive common units of New Atlas, in addition to the merger consideration of 0.1809 of a share of Targa Resources Corp. common stock, par value $0.001 per share, and $9.12 in cash, without interest, that you will receive as a result of the Atlas Merger. Your New Atlas units will not be affected by the Atlas Merger.

No vote of Atlas Energy unitholders is required in connection with the distribution. Therefore, you are not being asked for a proxy, and you are requested not to send us a proxy, in connection with the distribution. Atlas Energy is seeking approval from its unitholders for the Atlas Merger at a special meeting of Atlas Energy unitholders to be held on February 20, 2015. In connection with the special meeting, Atlas Energy has distributed a proxy statement/prospectus, which we refer to as the “Proxy Statement,” to all unitholders of its common units. The Proxy Statement contains a proxy and describes the procedures for voting shares of Atlas Energy common units and other details regarding the special meeting. As a result, the registration statement on Form 10 of which this information statement is a part does not contain a proxy and is not intended to constitute solicitation material under U.S. federal securities law.

If the conditions for consummating the distribution and the Atlas Merger (including, among others, approval of the Atlas Merger by the Atlas Energy unitholders and the Targa Resources stockholders) are satisfied or waived, no further action on your part is necessary for you to receive the common units of New Atlas. You do not need to take any action for the distribution to occur. You do not need to pay any consideration, exchange or surrender your existing common units of Atlas Energy or take any other action to receive your New Atlas common units. However, you will be required to surrender your common units of Atlas Energy in order to receive, for each common unit you own of Atlas Energy, 0.1809 of a share of Targa Resources Corp. common stock and $9.12 in cash, without interest, in connection with the Atlas Merger. That process is described in more detail in the Proxy Statement relating to the Atlas Merger.

All of the outstanding New Atlas common units are currently owned by Atlas Energy. There currently is no public trading market for such common units, although we expect that a limited market, commonly known as a “when-issued” trading market, will develop shortly before the record date for the distribution, and we expect “regular-way” trading of New Atlas common units to begin on the first trading day following the distribution date. New Atlas has been authorized to have its common units listed on the New York Stock Exchange under the ticker symbol “ATLS,” subject to official notice of distribution. Following the Atlas Merger, Atlas Energy will be delisted from and will cease to trade on the NYSE.

This information statement will be made publicly available at www.materialnotice.com beginning February 9, 2015, and notices of this information statement’s availability will be first sent to Atlas Energy unitholders on or about February 9, 2015.

 

 

In reviewing this information statement, you should carefully consider the matters described in the section entitled “Risk Factors” beginning on page 31 of this information statement.

 

 

Neither the U.S. Securities and Exchange Commission nor any state securities commission has approved or disapproved of any of the securities of Atlas Energy Group, LLC or determined whether this information statement is truthful or complete. Any representation to the contrary is a criminal offense.

This information statement does not constitute an offer to sell or the solicitation of an offer to buy any securities.

 

 

The date of this information statement is February 9, 2015.

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TABLE OF CONTENTS

 

		Page
NOTE REGARDING THE USE OF CERTAIN TERMS			ii
INDUSTRY AND MARKET DATA			ii
QUESTIONS AND ANSWERS ABOUT THE DISTRIBUTION			1
INFORMATION STATEMENT SUMMARY			10
SUMMARY HISTORICAL AND UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION			26
SUMMARY RESERVE DATA			29
RISK FACTORS			31
FORWARD-LOOKING STATEMENTS			66
THE SEPARATION AND DISTRIBUTION			69
CASH DISTRIBUTION POLICY			76
CAPITALIZATION			107
SELECTED FINANCIAL DATA			108
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			113
BUSINESS			155
MANAGEMENT			186
DIRECTORS			189
COMPENSATION DISCUSSION AND ANALYSIS			198
EXECUTIVE COMPENSATION			210
DESCRIPTION OF MATERIAL INDEBTEDNESS			232
SECURITY OWNERSHIP OF MANAGEMENT, DIRECTORS AND PRINCIPAL UNITHOLDERS			233
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			234
CONFLICTS OF INTEREST AND DUTIES			243
DESCRIPTION OF OUR COMMON UNITS			247
OUR LIMITED LIABILITY COMPANY AGREEMENT			249
CERTAIN U.S. FEDERAL INCOME TAX MATTERS			260
WHERE YOU CAN FIND MORE INFORMATION			280
GLOSSARY OF TERMS			281
INDEX TO FINANCIAL STATEMENTS			F-1
ANNEX A—THIRD AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT OF ATLAS ENERGY GROUP, LLC			A-1

 

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NOTE REGARDING THE USE OF CERTAIN TERMS

Except as otherwise indicated or unless the context otherwise requires, the information included in this information statement, including the combined financial statements of New Atlas, assumes the completion of all the transactions referred to in this information statement in connection with the separation and distribution. References to New Atlas’s business assume that it contains all of Atlas Energy, L.P.’s assets and businesses, other than those related to its “Atlas Pipeline Partners” segment. Unless the context otherwise requires, references in this information statement to “Atlas Energy Group, LLC,” “Atlas Energy Group,” “New Atlas,” “we,” “us,” “our” and “our company” refer to Atlas Energy Group, LLC a Delaware limited liability company, and its combined subsidiaries and whose common units will be distributed in the distribution.

References in this information statement to “Atlas Energy” or “Atlas Energy, L.P.” refer to Atlas Energy, L.P., a Delaware limited partnership. References in this information statement to “ARP” or “Atlas Resource Partners” refer to Atlas Resource Partners, L.P., a Delaware limited partnership. References in this information statement to “APL” or “Atlas Pipeline Partners” refer to Atlas Pipeline Partners, L.P., a Delaware limited partnership and subsidiary of Atlas Energy. References in this information statement to “Atlas Pipeline Partners GP” refer to Atlas Pipeline Partners GP, LLC, a Delaware limited liability company that is the general partner of APL. References in this information statement to “AEI” refer to Atlas Energy, Inc. the former owner of Atlas Energy’s general partner. References to “Targa Resources” refer to Targa Resources Corp., a Delaware corporation, and references to “Targa Resources Partners” refer to Targa Resources Partners LP, a Delaware limited partnership and subsidiary of Targa Resources.

INDUSTRY AND MARKET DATA

In this information statement, we rely on and refer to information and statistics regarding the natural gas and oil production and development industries. We obtained this data from independent publications or other publicly available information that we believe to be reliable.

 

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QUESTIONS AND ANSWERS ABOUT THE DISTRIBUTION

 

What is New Atlas?

New Atlas is the name by which we refer to Atlas Energy Group, LLC following the separation of Atlas Energy’s midstream business from the remainder of its businesses. Following the separation, New Atlas will hold all of Atlas Energy’s businesses other than its midstream business, including holding:

 

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the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in Atlas Resource Partners;

 

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Atlas Energy’s general and limited partner interests in its exploration and production development subsidiary, which currently conducts operations in the mid-continent region of the United States;

 

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Atlas Energy’s general and limited partner interests in Lightfoot Capital Partners, a limited partnership investment business; and

 

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Atlas Energy’s natural gas development and production assets in the Arkoma Basin, which Atlas Energy acquired in July 2013.

 

Following the separation, Atlas Energy will continue to hold, directly or indirectly, the general partner interest, incentive distribution rights and Atlas Energy’s common units in Atlas Pipeline Partners, L.P. (a publicly traded master limited partnership and midstream energy service provider engaged in natural gas gathering, processing and treating services).

 

Atlas Energy currently owns all of the limited liability company interests of New Atlas. The board of directors of the general partner of Atlas Energy has approved the distribution to the Atlas Energy unitholders of approximately 26.0 million common units representing a 100% limited liability company interest in New Atlas. We refer to this distribution of common units as the “distribution.”

 

Why is Atlas Energy separating New Atlas’s business and distributing its common units?

Atlas Energy is undertaking the separation of New Atlas from Atlas Energy in the manner described in this information statement and the distribution of the common units of New Atlas in connection with its entry on October 13, 2014, into an Agreement and Plan of Merger (which we refer to as the “Atlas merger agreement”) with Targa Resources and a newly formed subsidiary of Targa Resources. The Atlas merger agreement provides for such newly formed subsidiary to merge with and into Atlas Energy, with Atlas Energy surviving the merger as a subsidiary of Targa Resources. We refer to this transaction as the “Atlas Merger.” Atlas Energy agreed in the Atlas merger agreement that, prior to the Atlas Merger, it will transfer its assets and liabilities other than those related to its “Atlas Pipeline Partners” segment to New Atlas and effect a pro rata distribution to the Atlas unitholders of New Atlas common units representing a 100% interest in New Atlas.

 

On October 13, 2014, Atlas Energy also entered into an Agreement and Plan of Merger (which we refer to as the “APL merger agreement”) with APL, Atlas Pipeline Partners GP, Targa Resources,

 

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Targa Resources Partners, Targa Resources Partners’ general partner and a newly formed subsidiary of Targa Resources Partners. APL and Targa Resources Partners are publicly traded subsidiaries of Atlas Energy and Targa Resources, respectively. The APL merger agreement provides for the newly formed subsidiary of Targa Resources Partners to merge with and into APL, with APL surviving the merger as a subsidiary of Targa Resources Partners. We refer to this second merger as the “APL Merger.”

 

The distribution and the Atlas Merger are each conditioned on the other and will each occur only if the other occurs. In addition, the Atlas Merger and the APL Merger are each conditioned on each other, which means that the distribution is effectively conditioned on the APL Merger. For additional information about the mergers of Atlas Energy and Targa Resources Corp. and of APL and Targa Resources Partners, please read Atlas Energy’s separate proxy statement/prospectus relating to the Atlas Merger.

 

Why is Atlas Energy Group furnishing this document?

Atlas Energy is making this document publicly available to provide information to holders of common units of Atlas Energy as of the close of business on February 25, 2015, the record date for the distribution. Each record holder as of the record date is entitled to receive one common unit of New Atlas for every two common units of Atlas Energy held at the close of business on the record date. This document will help you understand how the separation and distribution will affect your investment in Atlas Energy and your investment in New Atlas after the separation and distribution.

 

How will the separation of New Atlas occur?

The separation will be accomplished through a transaction in which Atlas Energy will transfer to New Atlas all of its businesses to the extent they are not related to its “Atlas Pipeline Partners” segment. Following such transfer, which we refer to as the “separation,” New Atlas will own, directly or indirectly, the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in Atlas Resource Partners, L.P., Atlas Energy’s general partner and limited partner interests in Atlas Energy’s exploration and production development subsidiary and, its general and limited partner interests in Lightfoot Capital Partners, a limited partnership investment business, and its other natural gas and oil exploration and production assets. After the separation, Atlas Energy will distribute to its unitholders, on a pro rata basis, approximately 26.0 million common units representing a 100% limited liability company interest in New Atlas.

 

What is the record date for the distribution?

We expect the record date for the distribution to be the close of business on February 25, 2015.

 

When will the distribution occur?

We expect that the distribution date will be the same date as the closing date for the Atlas Merger, which we expect to be February 28, 2015. The distribution will be made to holders of record of Atlas Energy common units as of the record date.

 

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What do unitholders need to do to participate in the distribution?

Holders of Atlas Energy common units as of the record date will not be required to take any action to receive New Atlas common units in the distribution, but you are urged to read this entire information statement carefully. No unitholder approval of the distribution is required or sought. You are not being asked for a proxy, and you are requested not to send us a proxy. You will not be required to make any payment, surrender or exchange of your Atlas Energy common units or to take any other action to receive your New Atlas common units. The distribution will not affect the number of outstanding Atlas Energy common units or any rights of Atlas Energy common units.

 

How will common units of New Atlas be issued?

You will receive New Atlas common units through the same channels that you currently use to hold or trade Atlas Energy common units. If you own Atlas Energy common units as of the close of business on the record date, Atlas Energy, with the assistance of Broadridge Corporate Issuer Solutions, Inc., or Broadridge, the distribution agent, will electronically issue New Atlas common units to you or to your brokerage firm on your behalf by way of direct registration in book-entry form. New Atlas will not issue paper certificates. If you are a registered unitholder of Atlas Energy (meaning you own your units directly through an account with Atlas Energy’s transfer agent), Broadridge will mail you a book-entry account statement that reflects the number of New Atlas common units you own. If you own your Atlas Energy common units through a bank or brokerage account, your bank or brokerage firm will credit your account with the New Atlas common units.

 

Following the distribution, unitholders whose common units are held at the transfer agent may request that their common units of New Atlas be transferred to a brokerage or other account at any time. You should consult your broker if you wish to transfer your units.

 

How many common units of New Atlas will I receive in the distribution?

Atlas Energy will distribute to you one common unit of New Atlas for every two common units of Atlas Energy held at the close of business on the record date. Based on approximately 52.0 million common units of Atlas Energy that are expected to be outstanding as of the record date, a total of approximately 26.0 million common units of New Atlas will be distributed. For additional information on the distribution, see “The Separation and Distribution” beginning on page 69.

 

Will New Atlas issue fractional units in the distribution?

No. New Atlas will not issue fractional common units in the distribution. Fractional units that Atlas Energy unitholders otherwise would have been entitled to receive will instead be aggregated and sold in the public market by the distribution agent. The aggregate net cash proceeds of these sales will be distributed ratably to those unitholders who would otherwise have been entitled to receive fractional units. Recipients of cash in lieu of fractional units will not be entitled to any interest on the amounts of payment made in lieu of fractional units.

 

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What are the conditions to the distribution?

The distribution is subject to the satisfaction (or waiver by the general partner of Atlas Energy, subject to the restrictions set forth below) of the following conditions:

 

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the U.S. Securities and Exchange Commission (the “SEC”) shall have declared effective our registration statement on Form 10, of which this information statement is a part, and no stop order relating to the registration statement is in effect;

 

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the transfer of assets and liabilities from Atlas Energy to New Atlas shall have been completed in accordance with the separation and distribution agreement;

 

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any required actions and filings with regard to state securities and blue sky laws of the United States (and any comparable laws under any foreign jurisdictions) shall have been taken and, where applicable, have become effective or been accepted;

 

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the transaction agreements relating to the separation shall have been duly executed and delivered by the parties thereto;

 

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no order, injunction or decree issued by any court or agency of competent jurisdiction or other legal restraint or prohibition preventing consummation of the separation, distribution or any of the transactions contemplated by the separation and distribution agreement or any ancillary agreement, shall be in effect;

 

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our common units to be distributed shall have been accepted for listing on the NYSE, subject to official notice of issuance;

 

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Atlas Energy shall retain at least $5,000,000 of cash, and its net working capital (including retained cash) as of the distribution shall be no less than $5,000,000;

 

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Atlas Energy shall have received, or shall receive simultaneously with the distribution, certain payments from Targa Resources under the Atlas merger agreement and the proceeds from the cash transfers from New Atlas, as described in “Certain Relationships and Related Person Transactions—Separation and Distribution Agreement—Cash Transfers”; and

 

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the conditions required for consummating the Atlas Merger, as set forth in the Proxy Statement relating to that transaction, shall have been satisfied or waived (other than the condition that the distribution shall have occurred).

Neither Atlas Energy nor New Atlas will be permitted to amend, waive, supplement or modify any provision of the separation and distribution agreement, or make any determination as to the satisfaction or waiver of the conditions to the distribution, in a manner that is materially adverse to Atlas Energy, Targa Resources or their affiliates or that would prevent or materially impede consummation of the Atlas Merger without first obtaining Targa Resources’ consent. Atlas Energy and New Atlas cannot assure you that any or all of these conditions will be met. In addition, if the Atlas merger agreement is terminated before the distribution, the separation

 

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agreement will be automatically terminated and Atlas Energy will not be required to go forward with the separation. For a complete discussion of all of the conditions to the distribution, see “The Separation and Distribution—Conditions to the Distribution” beginning on page 74.

 

Atlas Energy also entered into the APL merger agreement with APL, Atlas Pipeline Partners GP, Targa Resources, Targa Resources Partners, Targa Resources Partners’ general partner and a newly formed subsidiary of Targa Resources Partners providing for the APL Merger to occur. The Atlas Merger and the APL Merger are each conditioned on the other and will each occur only if the other occurs or will occur. As a result, the distribution is indirectly conditioned on the satisfaction of the conditions required for consummating the APL Merger. For additional information about the merger of APL and Targa Resources Partners, please read Atlas Energy’s separate proxy statement/prospectus relating to the Atlas Merger.

 

What do I have to do to participate in the Distribution?

Pursuant to the terms of the separation and distribution agreement, the distribution is conditioned on the satisfaction or waiver of the conditions to consummating the Atlas Merger. Pursuant to the terms of the Atlas merger agreement, the approval by a majority of the outstanding Atlas Energy unitholders of the Atlas merger agreement and the Atlas Merger, and the approval of Targa Resources’ issuance of shares in the Atlas Merger by a majority of the holders of Targa Resources common stock voting at a special meeting to approve such issuance are conditions to the Atlas Merger. Unless waived by the general partner of Atlas Energy (subject to the restrictions described above), these approvals are therefore conditions to the distribution. Atlas Energy is seeking approval from the holders of Atlas Energy common units at a special meeting of Atlas Energy’s unitholders to be held on February 20, 2015. In connection with the special meeting, Atlas Energy has distributed a proxy statement/prospectus (also referred to as the “Proxy Statement”) to all record holders of its common units. The Proxy Statement contains a proxy and describes the procedures for voting your Atlas Energy common units and other details regarding the special meeting.

 

Holders of Atlas Energy common units as of February 25, 2015, the record date, will not need to pay any cash or deliver any other consideration, including any of their Atlas Energy common units, in order to receive units of New Atlas in the distribution.

 

What if I want to sell my common units of Atlas Energy or New Atlas?

You should consult with your financial advisors, such as your stockbroker, bank or tax advisor. Neither Atlas Energy nor New Atlas makes any recommendations on the purchase, retention or sale of common units of Atlas Energy or New Atlas.

 

If you sell your Atlas Energy common units prior to the record date or sell your entitlement to receive common units of New Atlas in the distribution on or prior to the distribution date, you will not be entitled to receive any New Atlas common units in the distribution.

 

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What is “regular-way” and “ex-distribution” trading?

Beginning shortly before the record date, it is expected that there will be two markets in Atlas Energy, L.P. common units: a “regular-way” market and an “ex-distribution” market. Common units of Atlas Energy that trade in the “regular-way” market will trade with an entitlement to common units of New Atlas distributed pursuant to the distribution. Common units of Atlas Energy that trade in the “ex-distribution” market will trade without an entitlement to common units of New Atlas distributed pursuant to the distribution.

 

If you decide to sell any common units of Atlas Energy before the distribution date, you should make sure your stockbroker, bank or other nominee understands whether you want to sell your common units of Atlas Energy with or without your entitlement to New Atlas common units pursuant to the distribution.

 

Where will I be able to trade common units of New Atlas?

There is not currently a public market for the common units of New Atlas. New Atlas has been authorized to list its common units on the New York Stock Exchange, or the NYSE, under the symbol “ATLS,” subject to official notice of distribution. We anticipate that trading in common units of New Atlas will begin on a “when-issued” basis on or shortly before the record date and that “regular-way” trading in such common units will begin on the first trading day following the distribution date. If trading begins on a “when-issued” basis, you may purchase or sell common units of New Atlas up to and through the distribution date, but your transaction will not settle until after the distribution date. We cannot predict the trading prices for our common units before, on or after the distribution date. For more information regarding “regular-way” trading and “when-issued” trading, see the section entitled “The Separation and Distribution—Trading Prior to the Distribution Date” on page 74.

 

Will the number of common units of Atlas Energy that I own change as a result of the distribution?

No. The number of common units of Atlas Energy that you own will not change as a result of the distribution. However, as a result of the Atlas Merger, which will occur immediately following the distribution, each common unit you own of Atlas Energy will be converted into the right to receive 0.1809 of a share of TRGP common stock and $9.12 of cash, without interest. Following the Atlas Merger, Targa Resources will own all common units of Atlas Energy. Atlas Energy unitholders will own approximately 18% of the combined company on a fully diluted basis, and existing Targa Resources stockholders will own the remaining approximately 82% of the combined company on a fully diluted basis.

 

What will happen to the listing of Atlas Energy common units?

After the Atlas Merger, Atlas Energy common units will be delisted and will cease to be traded on the NYSE.

 

What are the material U.S. federal income tax consequences of the distribution of our common units by Atlas Energy?

In general, the distribution of common units of New Atlas by Atlas Energy to a U.S. holder (as defined in the section entitled “Certain U.S. Federal Income Tax Matters” beginning on page 260) of common units of Atlas Energy should not be taxable to the U.S. holder for U.S. federal income tax purposes, except to the extent that the aggregate amount of money such holder receives (including cash received in lieu of fractional units), or is deemed to receive, as a result

 

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of the distribution, exceeds the tax basis in such holder’s interest in Atlas Energy common units immediately before the distribution.

 

The rules governing the tax consequences of the distribution are complex. You are urged to read the summary of the U.S. federal income tax consequences of the distribution in the section entitled “Certain U.S. Federal Income Tax Matters” beginning on page 260 and to consult your own tax advisor regarding the tax consequences of the distribution to you in your particular circumstances.

 

How will I determine the initial basis that I will have in the New Atlas common units I receive in the distribution?

A U.S. holder’s initial basis in the common units of New Atlas received by such U.S. holder in the distribution generally will be equal to Atlas Energy’s adjusted basis in such common units immediately before the distribution for U.S. federal income tax purposes. However, such U.S. holder’s initial basis in such common units shall not exceed the adjusted basis of such U.S. holder’s interest in Atlas Energy, reduced by any money distributed in the same transaction. Atlas Energy expects to provide unitholders with information regarding its adjusted basis for U.S. federal income tax purposes of our common units distributed in the distribution.

 

The rules governing the determination of a unitholder’s initial basis of New Atlas common units distributed in the distribution and the other tax consequences of the distribution are complex. You are urged to read the summary of the U.S. federal income tax consequences of the distribution in the section entitled “Certain U.S. Federal Income Tax Matters” beginning on page 260 and to consult your own tax advisor regarding the determination of your initial basis in our common units distributed to you in the distribution and the other tax consequences of the distribution to you in your particular circumstances.

 

Does New Atlas plan to pay distributions?

The determination of the amount of future cash distributions declared, if any, is at the sole discretion of New Atlas’s board of directors and will depend on various factors affecting New Atlas’s financial conditions and other matters the board of directors deems relevant.

 

New Atlas expects to adopt a cash distribution policy under which New Atlas will distribute to its common unitholders, within 50 days after the end of each quarter, all of its “available cash” for that quarter, which generally means all cash on hand of the company at the end of the quarter less reserves that its board of directors determines are appropriate to provide for the proper conduct of the partnership’s business, to comply with applicable law or any of New Atlas’s debt instruments and to provide funds for distributions to the holders of its limited liability company interests for any one or more of the next four quarters.

 

All decisions regarding the payment of distributions by New Atlas will be made by its board of directors from time to time in accordance with New Atlas’s limited liability company agreement.

 

New Atlas believes, based on the assumptions and considerations discussed in the section entitled “Cash Distribution Policy—

 

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Estimated Initial Cash Available for Distribution” beginning on page 79, that upon completion of the distribution, New Atlas’s initial quarterly distribution will, subject to proration as described below, be equal to $0.55 per common unit, or $2.20 per common unit on an annualized basis. This equates to an aggregate cash distribution of approximately $14.4 million per quarter, or approximately $57.8 million per year. New Atlas’s ability to make cash distributions at the initial distribution rate will be subject to the factors described in the section entitled “Cash Distribution Policy—General—Restrictions and Limitations on Our Cash Distribution Policy” beginning on page 77. We cannot assure you that any distributions will be declared or paid by us, and there is no guarantee of distributions at a particular level or of any distributions being made. We did not use quarter-by-quarter estimates in concluding that there would be sufficient cash available for distribution to pay the initial quarterly distribution on all of our common units during the twelve months ending December 31, 2015. For more information, see the section entitled “Cash Distribution Policy” beginning on page 76.

 

We expect to pay a prorated cash distribution for the first quarter that we are a publicly traded company. This prorated cash distribution will be paid for the period beginning on the distribution date for the New Atlas common units and ending on the last day of that fiscal quarter. Any cash distributions received by New Atlas from Atlas Resource Partners between the date of the most recent cash distribution to the Atlas Energy unitholders prior to the distribution date for the New Atlas common units and such distribution date will be included in New Atlas’s first cash distribution.

 

What will the relationship be between Atlas Energy and New Atlas following the separation?

New Atlas will enter into a separation and distribution agreement with Atlas Energy to effect the separation and distribution and provide a framework for New Atlas’s relationship with Atlas Energy after the separation and will also enter into an employee matters agreement and an operating agreement for certain Atlas Energy assets in Tennessee. These agreements will provide for the allocation between Atlas Energy and New Atlas of the employees, assets, liabilities and obligations (including investments, property and employee benefits and tax-related assets and liabilities) of Atlas Energy attributable to periods before, at and after New Atlas’s separation from Atlas Energy and will govern the relationship between New Atlas and Atlas Energy subsequent to the completion of the separation. Following the Atlas Merger, Atlas Energy will be a wholly owned subsidiary of Targa Resources.

 

For more information, see the sections entitled “Risk Factors—Risks Relating to the Separation” beginning on page 52 and “Certain Relationships and Related Party Transactions” beginning on page 234.

 

Who will manage New Atlas after the separation?

New Atlas’s management team has extensive experience and background in natural gas and oil master limited partnerships and natural gas and oil development. Atlas Energy, together with its predecessors and affiliates, has been involved in the energy industry since 1968. The Atlas Energy

 

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senior personnel currently responsible for managing our assets and capital raising will continue to do so and will become our management team upon completion of the separation and distribution. For more information, see the section entitled “Management.”

 

What are the estimated costs and expenses that New Atlas expects to incur in the separation and distribution?

New Atlas expects to incur one-time expenditures of between approximately $1.0 million and $1.5 million, in addition to advisory fees, in connection with the separation and distribution. Such one-time expenditures include, among others, costs for branding the new company, NYSE listing fees, investor and other stakeholder communications, printing costs and fees of the distribution agent.

 

Are there risks to owning New Atlas common units?

Yes. New Atlas’s business is subject to both general and specific risks relating to its business, the separation and its being a separate publicly traded company. These risks are described in the section entitled “Risk Factors” beginning on page 31. We encourage you to read that section carefully.

 

Who will be the distribution agent, transfer agent and registrar for the New Atlas common units?

The distribution agent, transfer agent, and registrar for the Atlas Energy common units will be Broadridge Corporate Issuer Solutions, Inc. For questions relating to the transfer or mechanics of the distribution, you should contact:

Broadridge Corporate Issuer Solutions, Inc.

Attention: Atlas Energy, L.P. Representative

P.O. Box 1342

Brentwood, NY 11717

 

Where can I get more information about Atlas Energy and New Atlas?

Before the separation, if you have any questions relating to the separation, you should contact:

Atlas Energy, L.P.

Investor Relations

Park Place Corporate Center One

1000 Commerce Drive, 4th Floor

Pittsburgh, Pennsylvania 15275

(877) 280-2857

 

After the separation, if you have any questions relating to New Atlas common units or the distribution of our common units, you should contact:

Atlas Energy Group, LLC

Investor Relations

Park Place Corporate Center One

1000 Commerce Drive, 4th Floor

Pittsburgh, Pennsylvania 15275

(877) 280-2857

 

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RISK FACTORS

You should carefully consider each of the following risk factors and all of the other information set forth in this information statement. The risk factors generally have been separated into seven groups: (1) risks relating to our business, (2) risks relating to our and ARP’s exploration and production operations, (3) risks relating to ARP’s drilling partnerships, (4) risks relating to the separation, (5) risks relating to the ownership of our common units, (6) tax risks to unitholders and (7) risks relating to our conflicts of interest. Based on the information currently known to us, we believe that the following information identifies the most significant risk factors affecting our company in each of these categories of risks. However, the risks and uncertainties our company faces are not limited to those set forth in the risk factors described below. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also adversely affect our business. In addition, past financial performance may not be a reliable indicator of future performance, and historical trends should not be used to anticipate results or trends in future periods. For information on risks relating to the Atlas Merger, please see the Proxy Statement.

If any of the following risks and uncertainties develops into actual events, these events could have a material adverse effect on our business, financial condition or results of operations. In such case, the trading price of our common units could decline.

Risks Relating to Our Business

Our primary assets are our partnership interests, including the IDRs, in ARP and, therefore, our cash flow is dependent on the ability of ARP to make distributions in respect of those partnership interests.

The amount of cash that ARP can distribute to its partners, including us, each quarter principally depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter and will depend on, among other things:

 

•

the amount of natural gas and oil ARP produces;

 

•

the price at which ARP sells its natural gas and oil;

 

•

the level of ARP’s operating costs;

 

•

ARP’s ability to acquire, locate and produce new reserves;

 

•

the results of ARP’s hedging activities;

 

•

the level of ARP’s interest expense, which depends on the amount of ARP’s indebtedness and the interest payable on it; and

 

•

the level of ARP’s capital expenditures.

In addition, the actual amount of cash that ARP will have available for distribution will also depend on other factors, some of which are beyond ARP’s control, including:

 

•

ARP’s ability to make working capital borrowings to pay distributions;

 

•

the cost of acquisitions, if any;

 

•

fluctuations in ARP’s working capital needs;

 

•

timing and collectability of receivables;

 

•

restrictions on distributions imposed by lenders;

 

•

the strength of financial markets and our ability to access capital or borrow funds; and

 

•

the amount, if any, of cash reserves established by ARP’s general partner in its discretion for the proper conduct of ARP’s business.

 

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Because of these factors, we cannot guarantee that ARP will have sufficient available cash to pay a specific level of cash distributions to its partners. You should also be aware that the amount of cash that ARP has available for distribution depends primarily upon its cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, ARP may make cash distributions during periods when it records net losses and may not make cash distributions during periods when it records net income.

We may not have sufficient cash to pay distributions.

Our ability to fund our operations, pay debt service and to make distributions to our unitholders may fluctuate based on the level of distributions ARP makes to its partners and the cash flows generated by our assets.

Our ability to distribute cash to our unitholders will be limited by a number of factors, including:

 

•

interest expense and principal payments on any current or future indebtedness;

 

•

restrictions on distributions contained in any future debt agreements;

 

•

our general and administrative expenses, including expenses we incur as a result of being a public company;

 

•

expenses of our subsidiaries other than ARP, including tax liabilities of our corporate subsidiaries, if any; and

 

•

reserves that we believe are prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

We cannot guarantee that in the future we will be able to pay distributions or that any distribution we make will be at or above our previous quarterly distribution levels. The actual amount of cash that is available for distribution to our unitholders will depend on numerous factors, many of which are beyond our control.

The assumptions underlying the forecast of cash distributions that we include in the section entitled “Cash Distribution Policy” are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause our actual cash distributions to differ materially from our forecast, and we did not use quarter-by-quarter estimates in concluding that there would be sufficient cash available for distribution to pay the initial quarterly distribution on all of our common units during the forecast period.

The forecast of cash available for distribution set forth in the section entitled “Cash Distribution Policy” includes our forecast of our results of operations, EBITDA, adjusted EBITDA and distributable cash flow for the twelve months ending December 31, 2015. Our ability to pay the full initial quarterly distribution in the forecast period is based on a number of assumptions that may not prove to be correct and that are discussed in the section entitled “Cash Distribution Policy—Significant Forecast Assumptions.” Our financial forecast has been prepared by management and we have neither received nor requested an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties, including those discussed in this information statement, which could cause there to be material differences between our forecast and our actual results. In addition, we did not use quarter-by-quarter estimates in concluding that there would be sufficient cash available for distribution to pay the initial quarterly distribution on all of our common units during the forecast period. If the forecasted results are not achieved, we may not be able to make cash distributions on our common units at the quarterly distribution rate, and the market price of our common units may decline materially.

 

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Our ability to meet our future financial needs may be adversely affected by our cash distribution policy.

Our cash distribution policy, which is consistent with our limited liability company agreement, will require us to distribute all of our available cash quarterly. Given that our cash distribution policy will be to distribute available cash and not retain it, we may not have enough cash to meet our needs if any of the following events occur:

 

•

an increase in our operating expenses;

 

•

an increase in general and administrative expenses;

 

•

an increase in principal and interest payments on our outstanding debt; or

 

•

an increase in working capital requirements.

If distributions on our common units are not paid with respect to any fiscal quarter, including those at the anticipated initial quarterly distribution rate, our common unitholders will not be entitled to receive that quarter’s payments in the future.

Our distributions to our common unitholders will not be cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter, including those at the anticipated initial quarterly distribution rate, our common unitholders will not be entitled to receive that quarter’s payments in the future.

Economic conditions and instability in the financial markets could negatively affect our and our subsidiaries’ businesses which, in turn, could affect the cash we have to make distributions to our unitholders.

Our and our subsidiaries’ operations are affected by the financial markets and related effects in the global financial system. The consequences of an economic recession and the effects of the financial crisis include a lower level of economic activity and increased volatility in energy prices. This may result in a decline in energy consumption and lower market prices for oil and natural gas and has previously resulted in a reduction in drilling activity in our subsidiaries’ service areas. Any of these events may adversely affect our and our subsidiaries’ revenues and ability to fund capital expenditures and, in the future, may affect the cash that we have available to fund our operations, pay required debt service on our credit facilities and make distributions to our unitholders.

Potential instability in the financial markets, as a result of recession or otherwise, can cause volatility in the markets and may affect our and our subsidiaries’ ability to raise capital and reduce the amount of cash available to fund operations. We cannot be certain that additional capital will be available to us or our subsidiaries to the extent required and on acceptable terms. Disruptions in the capital and credit markets could negatively affect our and our subsidiaries’ access to liquidity needed for our businesses and affect flexibility to react to changing economic and business conditions. We and our subsidiaries may be unable to execute our growth strategies, take advantage of business opportunities or to respond to competitive pressures, any of which could negatively affect our business.

A weakening of the current economic situation could have an adverse impact on producers, key suppliers or other customers, or on our or our subsidiaries’ lenders, causing them to fail to meet their obligations. Market conditions could also affect our or our subsidiaries’ derivative instruments. If a counterparty is unable to perform its obligations and the derivative instrument is terminated, our and our subsidiaries’ cash flow and ability to pay distributions could be affected which in turn affects the amount of distributions that we are able to make to our unitholders. The uncertainty and volatility surrounding the global financial system may have further impacts on our business and financial condition that we currently cannot predict or anticipate.

Hedging transactions may limit our potential gains or cause us to lose money.

Pricing for natural gas, NGLs and oil has been volatile and unpredictable for many years. To limit exposure to changing natural gas and oil prices, we and our subsidiaries may use financial and physical hedges for

 

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production. Physical hedges are not deemed hedges for accounting purposes because they require firm delivery of natural gas and are considered normal sales of natural gas. We and our subsidiaries generally limit these arrangements to smaller quantities than those projected to be available at any delivery point.

In addition, we and our subsidiaries may enter into financial hedges, which may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties in compliance with the Dodd-Frank Wall Street Reform and Consumer Protection Act, which we refer to as the Dodd-Frank Act. The futures contracts are commitments to purchase or sell hydrocarbons at future dates and generally cover one-month periods for up to six years in the future. The over-the-counter derivative contracts are typically cash settled by determining the difference in financial value between the contract price and settlement price and do not require physical delivery of hydrocarbons.

These hedging arrangements may reduce, but will not eliminate, the potential effects of changing commodity prices on cash flow from operations for the periods covered by the hedging arrangement. Furthermore, while intended to help reduce the effects of volatile commodity prices, such transactions, depending on the hedging instrument used, may limit potential gains if commodity prices were to rise substantially over the price established by the hedge. If, among other circumstances, production is substantially less than expected, the counterparties to the futures contracts fail to perform under the contracts or a sudden, unexpected event materially changes commodity prices, we and our subsidiaries may be exposed to the risk of financial loss. In addition, it is not always possible to engage in a derivative transaction that completely mitigates exposure to commodity prices and interest rates. The financial statements may reflect a gain or loss arising from an exposure to commodity prices and interest rates for which we and our subsidiaries are unable to enter into a completely effective hedge transaction.

Due to the accounting treatment of derivative contracts, increases in prices for natural gas, crude oil and NGLs could result in non-cash balance sheet reductions and non-cash losses in our statement of operations.

With the objective of enhancing the predictability of future revenues, from time to time we and ARP enter into natural gas, NGLs and crude oil derivative contracts. We and our subsidiaries account for these derivative contracts by applying the mark-to-market accounting treatment required for these derivative contracts. We and our subsidiaries could recognize incremental derivative liabilities between reporting periods resulting from increases or decreases in reference prices for natural gas, crude oil and NGLs, which could result in the recognition of a non-cash loss in the consolidated combined statements of operations and a consequent non-cash decrease in equity between reporting periods. Any such decrease could be substantial. In addition, we and our subsidiaries may be required to make cash payments upon the termination of any of these derivative contracts.

Regulations adopted by the Commodity Futures Trading Commission could have an adverse effect on our and our subsidiaries’ ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our and their business.

The Dodd-Frank Act is intended to change fundamentally the way swap transactions are entered into, transforming an over-the-counter market in which parties negotiate directly with each other into a regulated market in which most swaps are to be executed on registered exchanges or swap execution facilities and cleared through central counterparties. These statutory requirements must be implemented through regulation, primarily through rules adopted by the Commodity Futures Trading Commission. Many market participants will be newly regulated as swap dealers or major swap participants, with new regulatory capital requirements and other regulations that impose business conduct rules and mandate how they hold collateral or margin for swap transactions. All market participants will be subject to new reporting and recordkeeping requirements. The new regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our existing or future derivative activities. As a commercial end-user which uses

 

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swaps to hedge or mitigate commercial risk, rather than for speculative purposes, we are permitted to opt out of the clearing and exchange trading requirements, but we could nevertheless be exposed to greater liquidity and credit risk with respect to our hedging transactions if we do not use cleared and exchange-traded swaps.

Counterparties to our derivative instruments that are federally insured depository institutions are required to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new regulations could significantly increase the cost of derivative contracts; materially alter the terms of derivative contracts; reduce the availability of derivatives to protect against risks we and ARP encounter; reduce our and ARP’s ability to monetize or restructure our and ARP’s derivative contracts in existence at that time; and increase our and ARP’s exposure to less creditworthy counterparties. If we and ARP reduce or change the way we use derivative instruments as a result of the legislation or regulations, our and ARP’s results of operations may become more volatile and cash flows may be less predictable, which could adversely affect our and ARP’s ability to plan for and fund capital expenditures. The legislation was also intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our and ARP’s revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our and ARP’s consolidated financial position, results of operations and/or cash flows.

The scope and costs of the risks involved in our or our subsidiaries making acquisitions may prove greater than estimated at the time of the acquisition, and our subsidiaries may be unsuccessful in integrating the operations from future acquisitions and realizing the anticipated benefits of these acquisitions.

Any acquisition involves potential risks, including, among other things:

 

•

the validity of our assumptions about reserves, future production, revenues, processing volumes, capital expenditures and operating costs;

 

•

an inability to successfully integrate the businesses acquired;

 

•

a decrease in liquidity by using a portion of available cash or borrowing capacity under respective revolving credit facilities to finance acquisitions;

 

•

a significant increase in interest expense or financial leverage if additional debt to finance acquisitions is incurred;

 

•

the assumption of unknown environmental or title and other liabilities, losses or costs for which we or our subsidiary are not indemnified or for which the indemnity is inadequate;

 

•

the diversion of management’s attention from other business concerns and increased demand on existing personnel;

 

•

the incurrence of other significant charges, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges;

 

•

unforeseen difficulties encountered in operating in new geographic areas;

 

•

customer or key employee losses at the acquired businesses; and

 

•

the failure to realize expected growth or profitability.

The scope and cost of these risks may be materially greater than estimated at the time of the acquisition. Our future acquisition costs may also be higher than those we have achieved historically. Any of these factors could adversely affect future growth and the ability to make or increase distributions. In addition, the integration of

 

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previously independent operations can be a complex, costly and time-consuming process. The difficulties of combining these systems, as well as any operations we or our subsidiaries may acquire in the future, include, among other things:

 

•

operating a significantly larger combined entity;

 

•

the necessity of coordinating geographically disparate organizations, systems and facilities;

 

•

integrating personnel with diverse business backgrounds and organizational cultures;

 

•

consolidating operational and administrative functions;

 

•

integrating internal controls, compliance under the Sarbanes-Oxley Act of 2002 and other corporate governance matters;

 

•

the diversion of management’s attention from other business concerns;

 

•

customer or key employee loss from the acquired businesses;

 

•

a significant increase in indebtedness; and

 

•

potential environmental or regulatory liabilities and title problems.

Costs incurred and liabilities assumed in connection with an acquisition and increased capital expenditures and overhead costs incurred to expand operations could harm our subsidiaries’ businesses or future prospects, and result in significant decreases in gross margin and cash flows.

ARP may issue additional units, which may increase the risk of not having sufficient available cash to make distributions at prior per unit distribution levels.

ARP has wide discretion to issue additional limited partner units, including units that rank senior to its common units and the incentive distribution rights as to quarterly cash distributions, on the terms and conditions established by its general partner. The payment of distributions on additional ARP common units may increase the risk of ARP being unable to make distributions at its prior per unit distribution levels. To the extent new ARP limited partner units are senior to the ARP common units and the incentive distribution rights, their issuance will increase the uncertainty of the payment of distributions on the common units and the incentive distribution rights. Neither the common units nor the incentive distribution rights are entitled to any arrearages from prior quarters.

Reduced incentive distributions from ARP will disproportionately affect the amount of cash distributions to which we are entitled.

We are entitled to receive incentive distributions from ARP with respect to any particular quarter only if ARP distributes more than $0.46 per common unit for such quarter. Our incentive distribution rights in ARP entitle us to receive percentages increasing up to 48% of all cash distributed by ARP. Distribution by ARP above $0.60 per common unit per quarter would result in our incremental cash distributions to be the maximum 48%. Our percentage of the incremental cash distributions reduces from 48% to 23% if ARP’s distribution is between $0.51 and $0.60, and to 13% if ARP’s distribution is between $0.47 and $0.50. As a result, lower quarterly cash distributions per share from ARP have the effect of disproportionately reducing the amount of all incentive distributions that we receive as compared to cash distributions we receives on our 2.0% general partner interest in ARP.

We, as ARP’s general partner, may limit or modify the incentive distributions we are entitled to receive from ARP in order to facilitate the growth strategy of ARP. Our board of directors can give this consent without a vote of our unitholders.

We are ARP’s general partner and own the incentive distribution rights in ARP that entitle us to receive increasing percentages, of any cash distributed by ARP as it reaches certain target distribution levels in any quarter. To facilitate acquisitions by ARP, we may elect to limit the incentive distributions we are entitled to

 

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receive with respect to a particular acquisition or unit issuance contemplated by ARP. This is because a potential acquisition might not be accretive to ARP’s common unitholders as a result of the significant portion of that acquisition’s cash flows, which would be paid as incentive distributions to us. By limiting the level of incentive distributions in connection with a particular acquisition or issuance of units of ARP, the cash flows associated with that acquisition could be accretive to ARP’s common unitholders as well as substantially beneficial to us. In doing so, our board of directors (which is also ARP’s board of directors) would be required to consider obligations to ARP’s investors and its obligations to us.

ARP’s common unitholders have the right to remove their general partner with the approval of the holders of 66 2/3% of all units, which would cause us to lose our general partner interest and incentive distribution rights in ARP and the ability to manage them.

We currently manage ARP through our ownership of its general partner interest. ARP’s partnership agreement gives common unitholders of ARP the right to remove the general partner of ARP upon the affirmative vote of holders of 66 2/3% of ARP’s outstanding common units. If we were removed as general partner of ARP, we would receive cash or common units in exchange for our 2.0% general partner interest and the incentive distribution rights, but we would lose the ability to manage ARP or receive future distributions. Although the common units or cash we would receive are intended under the terms of ARP’s partnership agreement to fully compensate us in the event such an exchange is required, the value of these common units or investments we make with the cash over time may not be equivalent to the value of the general partner interest and the incentive distribution rights had we retained them.

If we are not fully reimbursed or indemnified for obligations and liabilities we incur in managing the business and affairs of ARP, the value of our common units could decline.

In our capacity as the general partner of ARP, we may make expenditures on ARP’s behalf for which we will seek reimbursement from ARP. In addition, under Delaware partnership law, we have, in our capacity as ARP’s general partner, unlimited liability for the obligations of ARP, such as ARP’s debts and environmental liabilities, except for those contractual obligations of ARP that are expressly made without recourse to the general partner. To the extent we incur obligations on behalf of ARP, we are entitled to be reimbursed or indemnified by ARP. If ARP is unable or unwilling to reimburse or indemnify us, we may be unable to satisfy these liabilities or obligations, which would reduce the value of our common units.

If in the future we cease to manage and control ARP through our ownership of its general partner interests, we may be deemed to be an investment company.

If we cease to manage and control ARP and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, such as the purchase and sale of securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates.

If we had to register as an investment company, we would also be unable to qualify as a partnership for U.S. federal income tax purposes and would be treated as a corporation for U.S. federal income tax purposes. We would pay U.S. federal income tax on our taxable income at the corporate tax rate, distributions to you would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced, which would result in a material reduction in distributions to

 

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you and a reduction in the value of our common units. For a discussion of the U.S. federal income tax implications if we were treated as a corporation in any taxable year, please see the section entitled “Certain U.S. Federal Income Tax Matters—Partnership Status.”

Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for our or ARP’s services.

In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climate changes, the U.S. Environmental Protection Agency, or “EPA,” adopted regulations under existing provisions of the federal Clean Air Act that require entities that produce certain gases to inventory, monitor and report such gases. The EPA also adopted rules to regulate greenhouse gas emissions through traditional major source construction and operating permit programs. The EPA confirmed the permitting thresholds in July 2012. These permitting programs require consideration of and, if deemed necessary, implementation of the best available control technology to reduce greenhouse gas emissions, which could result in us or ARP incurring additional costs for emissions control and higher costs of doing business.

Risks Relating to Our and ARP’s Exploration and Production Operations

If commodity prices decline significantly, our cash flow from operations will decline.

Our revenue, profitability and cash flow substantially depend upon the prices and demand for natural gas and oil. The natural gas, NGLs and oil markets are very volatile, and a drop in prices can significantly affect our financial results and impede our growth. Changes in natural gas, NGLs and oil prices will have a significant impact on the value of our and ARP’s reserves and on our cash flow. Prices for natural gas, NGLs and oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas, NGLs or oil, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

•

the level of domestic and foreign supply and demand;

 

•

the price and level of foreign imports;

 

•

the level of consumer product demand;

 

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weather conditions and fluctuating and seasonal demand;

 

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overall domestic and global economic conditions;

 

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political and economic conditions in natural gas and oil producing countries, including those in the Middle East and South America;

 

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the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

 

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the impact of the U.S. dollar exchange rates on natural gas and oil prices;

 

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technological advances affecting energy consumption;

 

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domestic and foreign governmental relations, regulations and taxation;

 

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the impact of energy conservation efforts;

 

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the cost, proximity and capacity of natural gas pipelines and other transportation facilities; and

 

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the price and availability of alternative fuels.

In the past, the prices of natural gas, NGLs and oil have been extremely volatile, and we expect this volatility to continue. During the year ended December 31, 2013, the NYMEX Henry Hub natural gas index price ranged

 

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from a high of $4.46 per MMBtu to a low of $3.11 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $110.53 per Bbl to a low of $86.68 per Bbl. During the year ended December 31, 2014, the NYMEX Henry Hub natural gas index price ranged from a high of $7.92 per MMBtu to a low of $2.75 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $107.62 per Bbl to a low of $53.27 per Bbl. Between January 1, 2015 and January 29, 2015, the NYMEX Henry Hub natural gas index price ranged from a high of $3.29 per MMBtu to a low of $2.88 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $52.69 per Bbl to a low of $44.45 per Bbl.

Competition in the natural gas and oil industry is intense, which may hinder our and ARP’s ability to acquire natural gas and oil properties and companies and to obtain capital, contract for drilling equipment and secure trained personnel.

We and ARP operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital through ARP’s Drilling Partnerships, contracting for drilling equipment and securing trained personnel. Our and ARP’s competitors may be able to pay more for natural gas, NGLs and oil properties and drilling equipment and to evaluate, bid for and purchase a greater number of properties than our and/or ARP’s financial or personnel resources permit. Moreover, competitors for investment capital may have better track records in their programs, lower costs or stronger relationships with participants in the oil and gas investment community than we or ARP have. All of these challenges could make it more difficult for us and ARP to execute our and its growth strategy. We and ARP may not be able to compete successfully in the future in acquiring leasehold acreage or prospective reserves or in raising additional capital.

Furthermore, competition arises not only from numerous domestic and foreign sources of natural gas and oil but also from other industries that supply alternative sources of energy. Competition is intense for the acquisition of leases considered favorable for the development of natural gas and oil in commercial quantities. Product availability and price are the principal means of competition in selling natural gas and oil. Many of our and ARP’s competitors possess greater financial and other resources than we or it have, which may enable them to identify and acquire desirable properties and market their natural gas and oil production more effectively than we or ARP can.

Shortages of drilling rigs, equipment and crews, or the costs required to obtain the foregoing in a highly competitive environment, could impair our and ARP’s operations and results.

Increased demand for drilling rigs, equipment and crews, due to increased activity by participants in our and ARP’s primary operating areas or otherwise, can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services could restrict our and ARP’s ability to drill the wells and conduct the operations that we or it currently have planned. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our and ARP’s revenues.

Many of our and ARP’s leases are in areas that have been partially depleted or drained by offset wells.

Our and ARP’s key operating project areas are located in active drilling areas in the Arkoma Basin, Mississippi Lime, Marble Falls, Utica Shale and Marcellus Shale, and many of our and ARP’s leases are in areas that have already been partially depleted or drained by earlier offset drilling. This may inhibit our and ARP’s ability to find economically recoverable quantities of natural gas in these areas.

Our and ARP’s operations require substantial capital expenditures to increase our and its asset base. If we or ARP are unable to obtain needed capital or financing on satisfactory terms, our and ARP’s asset base will decline, which could cause revenues to decline and affect its and our ability to pay distributions.

The natural gas and oil industry is capital intensive. Because we expect that we will distribute our available cash to our unitholders each quarter in accordance with the terms of our limited liability company agreement, we expect that we will rely primarily on external financing sources such as commercial bank borrowings and the issuance of debt and equity securities to fund any expansion and investment capital expenditures. If we or ARP are

 

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unable to obtain sufficient capital funds on satisfactory terms with capital raised through equity and debt offerings, cash flow from operations, bank borrowings and the Drilling Partnerships, we and ARP may be unable to increase or maintain our or its inventory of properties and reserve base, or be forced to curtail drilling or other activities. This could cause ARP’s and our revenues to decline and diminish its and our ability to service any debt that it or we may have at such time. If we or ARP do not make sufficient or effective expansion capital expenditures, including with funds from third-party sources, we and ARP will be unable to expand our business operations, and may not generate sufficient revenue or have sufficient available cash to pay distributions on its or our units.

We and ARP depend on certain key customers for sales of our and its natural gas, crude oil and NGLs. To the extent that these customers reduce the volumes of natural gas, crude oil and NGLs they purchase or process from us or ARP, or cease to purchase or process natural gas, crude oil and NGLs from us or ARP, our and ARP’s revenues and cash available for distribution could decline.

We and ARP market the majority of our and its natural gas production to gas marketers directly or to third-party plant operators who process and market our and ARP’s gas. Crude oil produced from our and ARP’s wells flows directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting for an oil company. Natural gas liquids are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas to meet pipeline specifications for transport or sale to end users or marketers operating on the receiving pipeline. To the extent these and other key customers reduce the amount of natural gas, crude oil and NGLs they purchase from us or ARP, our and ARP’s revenues and cash available for distributions to unitholders could temporarily decline in the event it is unable to sell to additional purchasers.

An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price that we or ARP receive for our or its production could significantly reduce our or its cash available for distribution and adversely affect our or its financial condition.

The prices that we or ARP receive for our oil and natural gas production sometimes reflect a discount to the relevant benchmark prices, such as NYMEX. The difference between the benchmark price and the price that we or ARP receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead price that we or ARP receive could significantly reduce our cash available for debt service and adversely affect our or ARP’s financial condition. We and ARP use the relevant benchmark price to calculate our hedge positions, and in certain areas, we and ARP do not have any commodity derivative contracts covering the amount of the basis differentials we experience in respect of our production. As such, we and ARP will be exposed to any increase in such differentials, which could adversely affect our results of operations.

Some of our and ARP’s undeveloped leasehold acreage is subject to leases that may expire in the near future.

As of September 30, 2014, none of the leases covering our approximately 29,173 net undeveloped acres, or 0.0%, are scheduled to expire on or before December 31, 2014, while leases covering approximately 8,418 of ARP’s 789,030 net undeveloped acres, or 1.1%, are scheduled to expire on or before December 31, 2014. An additional 4.7% and 0.7% of ARP’s net undeveloped acres are scheduled to expire in each of the years 2015 and 2016, respectively. If we or ARP are unable to renew these leases or any leases scheduled for expiration beyond their expiration date, on favorable terms, we or ARP will lose the right to develop the acreage that is covered by an expired lease, which would reduce our or ARP’s cash flows from operations.

Drilling for and producing natural gas and oil are high-risk activities with many uncertainties.

Our and ARP’s drilling activities are subject to many risks, including the risk that we or ARP will not discover commercially productive reservoirs. Drilling for natural gas and oil can be uneconomic, not only from

 

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dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our and ARP’s drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

 

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the high cost, shortages or delivery delays of equipment and services;

 

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unexpected operational events and drilling conditions;

 

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adverse weather conditions;

 

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facility or equipment malfunctions;

 

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title problems;

 

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pipeline ruptures or spills;

 

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compliance with environmental and other governmental requirements;

 

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unusual or unexpected geological formations;

 

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formations with abnormal pressures;

 

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injury or loss of life;

 

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environmental accidents such as gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment or oil leaks, including groundwater contamination;

 

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fires, blowouts, craterings and explosions; and

 

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uncontrollable flows of natural gas or well fluids.

Any one or more of these factors could reduce or delay our or ARP’s receipt of drilling and production revenues, thereby reducing our or ARP’s earnings, and could reduce revenues in one or more of ARP’s Drilling Partnerships, which may make it more difficult to finance ARP’s drilling operations through sponsorship of future partnerships. Any of these events can also cause substantial losses, personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.

Although we and ARP maintain insurance against various losses and liabilities arising from operations, insurance against all operational risks is not available to us or ARP. Additionally, we and ARP may elect not to obtain insurance if we or ARP believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could reduce our or ARP’s results of operations.

The physical effects of climatic change have the potential to damage facilities, disrupt operations and production activities and cause us and ARP to incur significant costs in preparing for or responding to those effects.

Climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to facilities from powerful winds or rising waters in low lying areas, disruption of production activities either because of climate-related damages to facilities or costs of operation potentially rising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on financing and operations by disrupting the transportation or process-related services

 

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provided by midstream companies, service companies or suppliers with whom we or ARP have a business relationship. We and ARP may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

Unless we and ARP replace our and its natural gas and oil reserves, the reserves and production will decline, which would reduce cash flow from operations and income.

Producing natural gas and oil reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our and ARP’s natural gas and oil reserves and production and, therefore, cash flow and income are highly dependent on our and ARP’s success in efficiently developing and exploiting reserves and economically finding or acquiring additional recoverable reserves. Our and ARP’s ability to find and acquire additional recoverable reserves to replace current and future production at acceptable costs depends on generating sufficient cash flow from operations and other sources of capital, for ARP, principally from the sponsorship of new Drilling Partnerships, all of which are subject to the risks discussed elsewhere in this section.

A decrease in natural gas prices could subject our and ARP’s oil and gas properties to a non-cash impairment loss under U.S. generally accepted accounting principles.

U.S. generally accepted accounting principles require oil and gas properties and other long-lived assets to be reviewed for impairment whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. We and ARP test our and its oil and gas properties on a field-by-field basis, by determining if the historical cost of proved properties less the applicable depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on our and ARP’s economic interests and our and its plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. We and ARP estimate prices based on current contracts in place at the impairment testing date, adjusted for basis differentials and market related information, including published future prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. Further declines in the price of natural gas may cause the carrying value of our and ARP’s oil and gas properties to exceed the expected future cash flows, and a non-cash impairment loss would be required to be recognized in the financial statements for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

Properties that we or ARP acquire may not produce as projected and we or ARP may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

Both we and ARP may acquire properties with natural gas reserves. Reviews of acquired properties are often incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. A detailed review of records and properties may not necessarily reveal existing or potential problems and may not permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well that we or ARP acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we or ARP inspect a well. Any unidentified problems could result in material liabilities and costs that negatively affect our or ARP’s financial condition and results of operations. Even if we or ARP are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems, the indemnity may not be fully enforceable or the amount of losses that can be recovered may be limited by floors and caps.

 

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Our and ARP’s acquisitions may prove to be worth less than the amount paid, or provide less than anticipated proved reserves, because of uncertainties in evaluating recoverable reserves, well performance, and potential liabilities as well as uncertainties in forecasting oil and natural gas prices and future development, production and marketing costs.

Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, development potential, well performance, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Our and ARP’s estimates of future reserves and estimates of future production for its acquisitions are initially based on detailed information furnished by the sellers and subject to review, analysis and adjustment by its internal staff, typically without consulting independent petroleum engineers. Such assessments are inexact and their accuracy is inherently uncertain, which means that proved reserves estimates may exceed actual acquired proved reserves. We and ARP perform a review of the acquired properties that we believe are generally consistent with industry practices. Nevertheless, such a review may not permit us or ARP to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Neither we nor ARP inspect every well. Even when we or ARP inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. As a result of these factors, the purchase price we or ARP pay to acquire oil and natural gas properties may exceed the value we or ARP realize.

Reviews of the properties included in the acquisitions are inherently incomplete because it is generally not feasible to perform an in-depth review of the individual properties involved in each acquisition given the time constraints imposed by the applicable acquisition agreement. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and potential.

We or ARP may not identify all risks associated with the acquisition of oil and natural gas properties or existing wells, and any indemnification received from sellers may be insufficient to protect us or ARP from such risks, which may result in unexpected liabilities and costs to us or ARP.

We and ARP have acquired and may make additional acquisitions of undeveloped oil and gas properties from time to time, subject to available resources. Any future acquisitions will require an assessment of recoverable reserves, title, future oil and natural gas prices, operating costs, potential environmental hazards, potential tax and other liabilities and other factors. Generally, it is not feasible for us or ARP to review in detail every individual property involved in a potential acquisition. In making acquisitions, we and ARP generally focus most of the title, environmental and valuation efforts on the properties that we or ARP believe to be more significant, or of higher value. Even a detailed review of properties and records may not reveal all existing or potential problems, nor would it permit us or ARP to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Neither we nor ARP inspect in detail every well that we or ARP acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we or ARP perform a detailed inspection. Any unidentified problems could result in material liabilities and costs that negatively affect our or ARP’s financial condition and results of operations.

Even if we or ARP are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems, the indemnity may not be fully enforceable, the amount of recoverable losses may be limited by floors and caps, or the financial wherewithal of such seller may significantly limit our ability to recover our costs and expenses. Any limitation on the ability to recover the costs related any potential problem could materially affect our or ARP’s financial condition and results of operations.

 

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Ownership of our and ARP’s oil, gas and NGLs production depends on good title to our and ARP’s respective properties.

Good and clear title to our and ARP’s oil and gas properties is important. Although we and ARP will generally conduct title reviews before the purchase of most oil, gas, NGLs and mineral producing properties or the commencement of drilling wells, such reviews do not assure that an unforeseen defect in the chain of title will not arise to defeat a claim, which could result in a reduction or elimination of the revenue received by us or ARP from such properties.

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions or by state environmental agencies.

Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example:

 

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New York has imposed a de facto moratorium on the issuance of permits for high volume, horizontal hydraulic fracturing until state administered environmental and public health studies are finalized. The Department of Environmental Conservation, or “NYDEC,” accepted comments on its revised proposal to amend state regulations to address high-volume hydraulic fracturing through January 11, 2013, and NYDEC has not issued final regulations. In October 2012, the NYDEC asked the New York Department of Health, or “NYDH,” to assess the health impacts of high volume hydraulic fracturing. The NYDH has not completed its assessment, nor has a deadline been set by which it will complete its review. New York is not expected to take any final action or make any decision regarding hydraulic fracturing until after the health review is completed by NYDH and the NYDEC, through the environmental impact statement, is satisfied that hydraulic fracturing can be done safely in New York State.

 

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Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed. On February 14, 2012, legislation was passed in Pennsylvania requiring, among other things, disclosure of chemicals used in hydraulic fracturing. We refer to this legislation as the “2012 Oil and Gas Act.” To implement the new legislative requirements, on December 14, 2013 the Pennsylvania Department of Environmental Protection, or “PADEP,” proposed amendments to its environmental regulations at 25 PA. Code Chapter 78, Subchapter C, pertaining to environmental protection performance standards for surface activities at oil and gas well sites. According to PADEP, the conceptual changes would update existing requirements regarding containment of regulated substances, waste disposal, site restoration and reporting releases, and would establish new planning, notice, construction, operation, reporting and monitoring standards for surface activities associated with the development of oil and gas wells. PADEP has also proposed to add new requirements for addressing impacts to public resources, identifying and monitoring orphaned and abandoned wells during hydraulic fracturing activities, and submitting water withdrawal information necessary to secure a required water management plan. The public comment period on the proposed amendments to PADEP’s proposed amendments at 25 PA. Code Chapter 78, Subchapter C closed on March 14, 2014, and PADEP is in the process of reviewing and considering over 24,000 comments received during the comment period. Additionally, the PADEP announced in June 2014 that it also intends to propose amendments to its present environmental regulations at 25 PA. Code Chapter 78, Subchapters D (relating to well drilling, operation and plugging) and H (relating to underground gas storage). Lastly, PADEP is in the process of splitting its 25 Pa. Code Chapter 78 regulations, which apply to oil and gas well sites, into two parts as a result of a Pennsylvania General Assembly legislative bill that passed in July 2014 as a companion to Pennsylvania’s budget for 2014 to 2015. 25 Pa. Code Chapter 78 will apply to conventional wells and 25 Pa. Code Chapter 78A will apply to unconventional wells.

 

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•

Ohio has in recent years expanded its oil and gas regulatory program. In June 2012, Ohio passed legislation that made several significant amendments to the state’s oil and gas laws, including additional permitting requirements, chemical disclosure requirements, and site investigation requirements for horizontal wells. In June 2013, legislation was adopted imposing sampling requirements and disposal restrictions on certain drilling wastes containing naturally occurring radioactive material and requiring the state regulatory authority to adopt rules on the design and operation of facilities that store, recycle, or dispose of brine or other oil and natural gas related waste materials. In February 2014, the regulatory authority proposed rules imposing detailed construction standards on well pads, and in April 2014, Ohio announced new standard drilling permit conditions to address concerns regarding seismic activity in certain parts of the state.

 

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In September 2012, the Texas Railroad Commission approved new regulations relating to the commercial recycling of produced water and/or hydraulic fracturing flowback fluid. In June 2013, the Texas Railroad Commission adopted new rules regarding well casing, cementing, drilling, completion and well control for ensuring hydraulic fracturing operations do not contaminate nearby water resources.

 

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On April 12, 2013, the West Virginia Legislature passed a legislative rule titled “Rules Governing Horizontal Well Development,” which became effective on July 1, 2013. The rule imposes more stringent regulation of horizontal drilling and was promulgated to provide further direction in the implementation and administration of the Natural Gas Horizontal Well Control Act that became effective on December 14, 2011.

In addition to state law, local land use restrictions, such as municipal ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. Recent changes regarding local land use restrictions in Pennsylvania occurred because of decisions of the Pennsylvania Supreme and Commonwealth Courts. On December 19, 2013, when the Pennsylvania Supreme Court issued its Robinson Township v. Commonwealth of Pennsylvania ruling, which invalidated key sections of the 2012 Oil and Gas Act that placed limits on the regulatory authority of local governments. Additionally, the Pennsylvania Supreme Court remanded a number of issues to the Commonwealth Court for further decision. On July 17, 2014, the Commonwealth Court ruled on the remanded issues. The cumulative effect of the Supreme and Commonwealth Court rulings is that all of the challenged provisions relating to local ordinances contained in the 2012 Oil and Gas Act are invalid, except for the definitions section and most of the updated preemption language in the 2012 Oil and Gas Act that was included from the 1984 Oil and Gas Act. While the total impact of these rulings are not clear and will occur over an extended period of time, an immediate impact of the ruling may be increased regulatory impediments and disputes at the local government level. On June 30, 2014, the New York Court of Appeals issued its opinion in Wallach v. Town of Dryden affirming local zoning laws adopted by two upstate municipalities that prohibited oil and gas-related activities within their borders. Specifically, the Court of Appeals ruled that there was nothing within the plain language, statutory scheme and legislative history of the New York Oil, Gas and Solution Mining Law that manifested an intent by the legislature to preempt a municipality’s home rule authority to regulate land use. If state, local or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells. Generally, Federal, state and local restrictions and requirements are applied consistently to similar types of producers (e.g., conventional, unconventional, etc.), regardless of size of the producing company.

Although, to date, the hydraulic fracturing process has not generally been subject to regulation at the federal level, there are certain governmental reviews either under way or being proposed that focus on environmental aspects of hydraulic fracturing practices, and some federal regulation has taken place. A few of these initiatives are listed here, although others may exist now or be implemented in the future. In April 2012, President Obama established an Interagency Working Group to Support Safe and Responsible Development of Unconventional Domestic Natural Gas Resources with the purpose of coordinating the policies and activities of agencies

 

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regarding unconventional gas development. The EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel as an additive under the Safe Drinking Water Act, or “SDWA.” In May 2012, the EPA issued draft permitting guidance for oil and gas hydraulic fracturing activities using diesel fuel. After reviewing comments submitted on the draft guidance, which were due by August 23, 2012, the EPA submitted its draft guidance to the White House Office of Management and Budget in September 2013. In February 2014, the EPA released its revised final guidance document on SDWA underground injection control permitting for hydraulic fracturing using diesel fuels, along with responses to selected substantive public comments on the EPA’s previous draft guidance, a fact sheet and a memorandum to the EPA’s regional offices regarding implementation of the guidance. The process for implementing the EPA’s final guidance document may vary across the states depending on the regulatory authority responsible for implementing the SDWA Underground Injection Control program in each state. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. For example, the EPA is currently studying the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The EPA issued a progress report regarding the hydraulic fracturing study on December 21, 2012. However, the progress report did not provide any results or conclusions. On December 9, 2013, the EPA’s Hydraulic Fracturing Study Technical Roundtable of subject-matter experts from a variety of stakeholder groups met to discuss the work underway to answer the hydraulic fracturing study’s key research questions. Individual research projects associated with the EPA’s study were recently published in July 2014. Research results are expected to be released in draft form in late 2014 for review by the public and the EPA Science Advisory Board. The EPA has not provided an anticipated date for completion of the report after peer review. In 2013, the EPA indicated that it intended to propose a draft water quality criteria document that would update the aquatic life water quality criteria for chloride by the summer of 2014. However, the EPA has yet to propose the draft water quality criteria document and it has not provided an updated timeframe for the proposal. The EPA announced in its September 2014 “Final 2012 and Preliminary 2014 Effluent Guidelines Program Plans” document that it intends to continue a rulemaking effort to potentially revise the effluent limitation guidelines for the Oil and Gas Extraction Point Source Category to address pretreatment standards for shale gas extraction. The EPA proposed in that same document a detailed study of centralized waste treatment facilities that accept oil and gas extraction wastewater. On May 4, 2012, the U.S. Department of the Interior, Bureau of Land Management proposed a rule that includes provisions requiring disclosure of chemicals used in hydraulic fracturing and construction standards for hydraulic fracturing on federal lands. On May 24, 2013, the Bureau of Land Management published a revised proposed rule to regulate hydraulic fracturing on federal and Indian lands. The comment period closed on August 23, 2013 and the revised proposed rule drew more than 175,000 comments. A final rule is expected to be issued in 2014 or 2015.

Certain members of the U.S. Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, and Congress has asked the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing. In addition, Congress requested the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. On December 16, 2013, the U.S. Energy Information Administration published an abridged version of its Annual Energy Outlook 2014 with projections to 2040 report, with the full report released on May 7, 2014. These ongoing proposed studies, depending on their degree of pursuit and any meaningful results obtained, could result in initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or one or more other regulatory mechanisms. If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local level, such laws could make it more difficult or costly for us to perform hydraulic fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude our ability to drill wells. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could be significantly affected. Some of the potential effects of changes in Federal, state or local regulation of hydraulic fracturing operations could include, but are not limited to, the following: additional permitting requirements, permitting

 

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delays, increased costs, changes in the way operations, drilling and/or completion must be conducted, increased recordkeeping and reporting, and restrictions on the types of additives that can be used, among other potential effects that are not listed here. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

The third parties on whom we or ARP rely for gathering and transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting its business.

The operations of the third parties on whom we or ARP rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulation. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we or ARP pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we or ARP rely could have a material adverse effect on our or ARP’s business, financial condition, results of operations and ability to make distributions to unitholders.

Our and ARP’s drilling and production operations require adequate sources of water to facilitate the fracturing process and the disposal of flowback and produced water. If we or ARP are unable to dispose of the flowback and produced water from the strata at a reasonable cost and within applicable environmental rules, our and ARP’s ability to produce gas economically and in commercial quantities could be impaired.

A significant portion of our and ARP’s natural gas extraction activity utilizes hydraulic fracturing, which results in water that must be treated and disposed of in accordance with applicable regulatory requirements. Environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our or ARP’s operations and financial performance. For example, Pennsylvania requires the development, submission and approval of a water management plan before hydraulically fracturing an unconventional well. The requirements of these plans continue to be modified by proposed amendments to state regulations and agency policies and guidance. For Pennsylvania operations located in the Susquehanna River Basin, the Susquehanna River Basin Commission regulates consumptive water uses, water withdrawals, and the diversions of water into and out of the Susquehanna River Basin, and specific approvals are required prior to initiating drilling activities. In June 2012, Ohio passed legislation that established a water withdrawal and consumptive use permit program in the Lake Erie watershed. If certain withdrawal thresholds are triggered due to water needs for a particular project, ARP will be required to develop a Water Conservation Plan and obtain a withdrawal permit for that project.

Our and ARP’s ability to collect and dispose of water will affect production, and potential increases in the cost of water treatment and disposal may affect profitability. The imposition of new environmental initiatives and regulations could include restrictions on our or ARP’s ability to conduct hydraulic fracturing or disposal of produced water, drilling fluids and other substances associated with the exploration, development and production of gas and oil. For example, in July 2012, the Ohio Department of Natural Resources promulgated amendments to the regulations governing disposal wells in Ohio. The rules provide the Department with the authority to require certain testing as part of the process for obtaining a permit for the underground injection of produced water, and require all new disposal wells to be equipped with continuous pressure monitors and automatic shut off devices.

Recently promulgated rules regulating air emissions from oil and natural gas operations could cause us and ARP to incur increased capital expenditures and operating costs.

In August 2012, the EPA published final rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source

 

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Performance Standards, which we refer to as the “NSPS,” to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The NSPS require operators, starting in 2015, to reduce volatile organic compound (“VOC”) emissions from oil and natural gas production facilities by conducting “green completions” for hydraulic fracturing, that is, recovering rather than venting the gas and NGLs that come to the surface during completion of the fracturing process. The NSPS also establish specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment. In addition, effective in 2012, the rules establish new notification requirements before conducting hydraulic fracturing and more stringent leak detection requirements for natural gas processing plants. The NSPS became effective October 15, 2012 and will likely require a number of modifications to our operations, including the installation of new equipment. Compliance with the new rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

States are also proposing more stringent requirements in air permits for well sites and compressor stations. For example, Pennsylvania recently revised its list of sources exempt from air permitting requirements such that previously exempted types of sources associated with oil and gas exploration and production now are required to: (1) obtain an air permit or (2) satisfy specific requirements (emission limits, monitoring and recordkeeping) in order to claim the permit exemption. In conjunction with this proposal, Pennsylvania has finalized revisions to its General Permit for Natural Gas Production Facilities to impose additional and more stringent requirements and emission limits. Ohio is also considering revising its current General Permit for Natural Gas Production Operations to cover emissions from completion activities.

Impact fees and severance taxes could materially increase liabilities.

In an effort to offset budget deficits and fund state programs, many states have imposed impact fees and/or severance taxes on the natural gas industry. In February 2012, Pennsylvania implemented an impact fee for unconventional wells drilled there. An unconventional gas well is a well that is drilled into an unconventional formation, which would include the Marcellus Shale. The impact fee, which changes from year to year, is computed using the prior year’s trailing 12- month NYMEX natural gas price and is based upon a tiered pricing matrix. Based upon natural gas prices for 2013, the impact fee for qualifying unconventional horizontal wells spudded during 2013 was $50,000 per well and the impact fee for unconventional vertical wells was $10,000 per well. The impact fee is due by April 1 of the year following the year that a horizontal unconventional well is spudded or a vertical unconventional well is put into production. The fee will continue for 15 years for a horizontal unconventional well and 10 years for a vertical unconventional well. ARP estimates that the impact fee for its wells including the wells in its Drilling Partnerships will be approximately $1 million for the year ended December 31, 2014.

On May 14, 2014, the Ohio General Assembly passed a substitute version of a bill, H.B.375, introduced on December 4, 2013, that significantly changes Ohio’s severance tax on the production of oil and gas, and the bill is now under consideration by the Ohio Senate. Under the General Assembly’s bill, the tax on the production of oil and gas from conventional wells would be lowered to $0.10/Bbl oil and $0.015/Mcf natural gas, and the tax on the production of oil and gas from unconventional wells would become 2.5% of net proceeds at the wellhead for both oil and gas from the first sale of that oil or gas.

President Obama’s budget proposals for 2014 included proposed provisions with significant tax consequences. If enacted, U.S. tax laws could be amended to eliminate certain deductions for drilling, exploration and development and the mandatory funding of certain public lands and research and development of transportation alternatives.

 

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Because we and ARP handle natural gas, NGLs and oil, we and ARP may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of substances into the environment.

How we and ARP plan, design, drill, install, operate and abandon natural gas wells and associated facilities are matters subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:

 

•

the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions;

 

•

the federal Clean Water Act and comparable state laws and regulations that impose obligations related to spills, releases, streams, wetlands and discharges of pollutants into regulated bodies of water;

 

•

the federal Resource Conservation and Recovery Act, or “RCRA,” and comparable state laws that impose requirements for the handling and disposal of waste, including produced waters, from our and ARP’s facilities;

 

•

the federal Comprehensive Environmental Response, Compensation, and Liability Act, or “CERCLA,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us and ARP or at locations to which we and ARP have sent waste for disposal; and

 

•

wildlife protection laws and regulations such as the Migratory Bird Treaty Act that requires operators to cover reserve pits during the cleanup phase of the pit, if the pit is open more than 90 days.

Complying with these requirements is expected to increase costs and prompt delays in natural gas production. There can be no assurance that we or ARP will be able to obtain all necessary permits and, if obtained, that the costs associated with obtaining such permits will not exceed those that previously had been estimated. It is possible that the costs and delays associated with compliance with such requirements could cause us or ARP to delay or abandon the further development of certain properties.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. These enforcement actions may be handled by the EPA and/or the appropriate state agency. In some cases, the EPA has taken a heightened role in oil and gas enforcement activities. For example, in 2011, EPA Region III requested the lead on all oil and gas related violations in the United States Army Corps of Engineers’ Pittsburgh District. The EPA, the United States Army Corps of Engineers and the United States Department of Justice have been actively pursuing instances of unpermitted stream and wetland impacts. We also understand that the EPA has taken an increased interest in assessing operator compliance with the Spill Prevention, Control and Countermeasures regulations, set forth at 40 CFR Part 112.

Certain environmental statutes, including RCRA, CERCLA, the federal Oil Pollution Act and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where certain substances have been disposed of or otherwise released, whether caused by our or ARP’s operations, the past operations of its predecessors or third parties. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

There is an inherent risk that we or ARP may incur environmental costs and liabilities due to the nature of the businesses and the substances handled. For example, an accidental release from one of our or ARP’s wells could subject it or the applicable subsidiary to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the

 

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possibility exists that stricter laws, regulations or enforcement policies may be enacted or adopted and could significantly increase our or ARP’s compliance costs and the cost of any remediation that may become necessary. Neither we nor ARP may be able to recover remediation costs under our insurance policies.

We and ARP are subject to comprehensive federal, state, local and other laws and regulations that could increase the cost and alter the manner or feasibility of doing business.

Our and ARP’s operations are regulated extensively at the federal, state and local levels. The regulatory environment in which we and ARP operate include, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our and ARP’s activities will be subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our and ARP’s operations and limit the quantity of natural gas we may produce and sell. A major risk inherent in a drilling plan is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could inhibit our ability to develop our respective properties. The natural gas and oil regulatory environment could also change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, reduce our profitability. For example, Pennsylvania’s General Assembly approved legislation in February 2012 that imposes significant, costly requirements on the natural gas industry, including the imposition of increased bonding requirements and impact fees for gas wells, based on the price of natural gas and the age of the well. Proposed regulations associated with this legislation have been released for public comment by the Pennsylvania state agencies and, if finalized, will affect how natural gas operations are conducted in Pennsylvania. West Virginia has promulgated regulations associated with its existing Horizontal Well Control Act and is signaling that additional regulations are on the horizon. We and ARP may be put at a competitive disadvantage to larger companies in the industry that can spread these additional costs over a greater number of wells and these increased regulatory hurdles over a larger operating staff.

Estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our and ARP’s reserves.

Underground accumulations of natural gas and oil cannot be measured in an exact way. Natural gas and oil reserve engineering requires subjective estimates of underground accumulations of natural gas and oil and assumptions concerning future natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Our and ARP’s engineers prepare estimates of our proved reserves. Over time, our and ARP’s internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of our and ARP’s reserve estimates were made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we and ARP will make certain assumptions regarding future natural gas prices, production levels and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect estimates of reserves, the economically recoverable quantities of natural gas and oil attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Our and ARP’s PV-10 and standardized measure are calculated using natural gas prices that do not include financial hedges. Numerous changes over time to the assumptions on which our and ARP’s reserve estimates are based, as described above, often result in the actual quantities of natural gas and oil we and ARP ultimately recover being different from the reserve estimates.

 

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The present value of future net cash flows from our and ARP’s proved reserves is not necessarily the same as the current market value of the estimated natural gas reserves. We and ARP base the estimated discounted future net cash flows from proved reserves on historical prices and costs, but actual future net cash flows from our natural gas properties will also be affected by factors such as:

 

•

actual prices received for natural gas;

 

•

the amount and timing of actual production;

 

•

the amount and timing of capital expenditures;

 

•

supply of and demand for natural gas; and

 

•

changes in governmental regulations or taxation.

The timing of both the production and incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor that we and ARP use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the company or the natural gas and oil industry in general.

Any significant variance in our or ARP’s assumptions could materially affect the quantity and value of reserves, the amount of PV-10 and standardized measure, and the financial condition and results of operations. In addition, our and ARP’s reserves or PV-10 and standardized measure may be revised downward or upward based upon production history, results of future exploitation and development activities, prevailing natural gas and oil prices and other factors. A material decline in prices paid for our or ARP’s production can reduce the estimated volumes of reserves because the economic life of the wells could end sooner. Similarly, a decline in market prices for natural gas or oil may reduce our or ARP’s PV-10 and standardized measure.

Risks Relating to ARP’s Drilling Partnerships

ARP or its subsidiaries may be exposed to financial and other liabilities as the managing general partner of the Drilling Partnerships.

ARP or one of its subsidiaries serves as the managing general partner of the Drilling Partnerships and will be the managing general partner of new Drilling Partnerships that it sponsors. As a general partner, ARP or one of its subsidiaries will be contingently liable for the obligations of the partnerships to the extent that partnership assets or insurance proceeds are insufficient. ARP has agreed to indemnify each investor partner in the Drilling Partnerships from any liability that exceeds such partner’s share of the Drilling Partnership’s assets.

ARP may not be able to continue to raise funds through its Drilling Partnerships at desired levels, which may in turn restrict its ability to maintain drilling activity at recent levels.

ARP has sponsored limited and general partnerships to finance certain of its development drilling activities. Accordingly, the amount of development activities that ARP will undertake depends in large part upon its ability to obtain investor subscriptions to invest in these partnerships. ARP has raised $150.0 million, $127.1 million and $141.9 million in calendar years 2013, 2012 and 2011, respectively. In the future, ARP may not be successful in raising funds through these Drilling Partnerships at the same levels, and it also may not be successful in increasing the amount of funds it raises. ARP’s ability to raise funds through its Drilling Partnerships depends in large part upon the perception of investors of their potential return on their investment and their tax benefits from investing in them, which perception is influenced significantly by ARP’s historical track record of generating returns and tax benefits to the investors in its existing partnerships.

In the event that ARP’s Drilling Partnerships do not achieve satisfactory returns on investment or the anticipated tax benefits, ARP may have difficulty in maintaining or increasing the level of Drilling Partnership

 

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fundraising. In this event, ARP may need to seek financing for drilling activities through alternative methods, which may not be available, or which may be available only on a less attractive basis than the financing it realized through these Drilling Partnerships, or it may determine to reduce drilling activity.

Changes in tax laws may impair ARP’s ability to obtain capital funds through Drilling Partnerships.

Under current federal tax laws, there are tax benefits to investing in Drilling Partnerships, including deductions for intangible drilling costs and depletion deductions. Both the Obama Administration’s budget proposal for fiscal year 2014 and other recently introduced legislation included proposals that would, among other things, eliminate or reduce certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs and certain environmental clean-up costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted in future years and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development. The repeal of these oil and gas tax benefits, if it happens, would result in a substantial decrease in tax benefits associated with an investment in ARP’s Drilling Partnerships. These or other changes to federal tax law may make investment in the Drilling Partnerships less attractive and, thus, reduce ARP’s ability to obtain funding from this significant source of capital funds.

Fee-based revenues may decline if ARP is unsuccessful in sponsoring new Drilling Partnerships.

ARP’s fee-based revenues are based on the number of Drilling Partnerships it sponsors and the number of partnerships and wells it manages or operates. If ARP is unsuccessful in sponsoring future Drilling Partnerships, its fee-based revenues may decline.

ARP’s revenues may decrease if investors in the Drilling Partnerships do not receive a minimum return.

ARP has agreed to subordinate a portion of its share of production revenues, net of corresponding production costs, to specified returns to the investor partners in the Drilling Partnerships, typically 10% to 12% per year for the first five to eight years of distributions. Thus, ARP’s revenues from a particular Drilling Partnership will decrease if the Drilling Partnership does not achieve the specified minimum return. For the years ended December 31, 2013, 2012 and 2011, $9.6 million, $6.3 million and $4.0 million, respectively, of ARP’s revenues, net of corresponding production costs, were subordinated, which reduced ARP’s cash distributions received from the Drilling Partnerships.

Risks Relating to the Separation

We have no operating history as a separate public company, and our historical and pro forma financial information is not necessarily representative of the results that we would have achieved had we been the owner or operator of our assets and may not be a reliable indicator of our future results.

The historical information in this information statement refers to our business as operated by and integrated with Atlas Energy. Our historical and pro forma financial information included in this information statement is derived from the consolidated financial statements and accounting records of Atlas Energy. Therefore, the historical and pro forma financial information included in this information statement does not necessarily reflect the financial condition, results of operations or cash flows that we would have achieved as a separate publicly traded company or as the owner or operator of our assets during the periods presented or those that we will achieve in the future, primarily as a result of the following factors:

 

•

Prior to the separation, our assets were operated by Atlas Energy, rather than as a separate company. Atlas Energy or one of its affiliates performed various corporate functions for us and/or our assets,

 

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including tax administration, cash management, accounting, information services, human resources, ethics and compliance programs, real estate management, investor and public relations, certain governance functions (including internal audit) and external reporting. Our historical financial results and the consolidated pro forma financial results reflect allocations of corporate expenses from Atlas Energy for these and similar functions. These allocations may be less than the comparable expenses we would have incurred had we operated as a separate publicly traded company.

 

•

After the completion of the separation, the cost of capital for our business may be higher than Atlas Energy’s cost of capital prior to the separation.

 

•

Other significant changes may occur in our cost structure, management, financing and business operations as a result of our operations as a company separate from Atlas Energy managed by our board of directors.

For additional information about the past financial performance of our business and the basis of presentation of the historical combined financial statements and the unaudited pro forma combined financial statements of our business, see the sections entitled “Summary Historical and Unaudited Pro Forma Combined Financial Information,” “Selected Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical financial statements and accompanying notes included elsewhere in this information statement.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

We may have been able to receive better terms from unaffiliated third parties than the terms provided in our agreements with Atlas Energy.

The agreements related to our separation from Atlas Energy, including the separation and distribution agreement, employee matters agreement and other agreements, were negotiated in the context of our separation from Atlas Energy and Atlas Energy’s pending merger with Targa Resources. We were still part of Atlas Energy at this time and, accordingly, these agreements may not reflect terms that would have been reached between unaffiliated parties. The terms of the agreements that were negotiated in the context of our separation relate to, among other things, allocation of assets, liabilities, rights, indemnifications and other obligations between Atlas Energy and us as well as certain ongoing arrangements between Atlas Energy and us. If these agreements had been negotiated with unaffiliated third parties, they might have been more favorable to us. For more information, see the section entitled “Certain Relationships and Related Party Transactions” beginning on page 234.

We may not achieve some or all of the expected benefits of the separation.

We may not be able to achieve the full strategic and financial benefits expected to result from the separation, or such benefits may be delayed or not occur at all. These expected benefits include the following:

 

•

The separation will facilitate deeper understanding by investors of the different businesses of Atlas Energy and New Atlas, allowing investors to more transparently value the merits, performance and future prospects of each company, which could increase overall unitholder value.

 

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•

The separation will create an acquisition currency in the form of units that will enable New Atlas to purchase, and to assist ARP in purchasing, developed and undeveloped resources to accelerate growth of its natural gas and oil production and development business without diluting Atlas Energy unitholders’ participation in growth at Atlas Pipeline Partners, L.P., a publicly traded partnership, the general partner of which is owned by Atlas Energy, or it successors. Current industry trends have created a significant opportunity for New Atlas to grow, and to assist ARP in growing, through the acquisition of assets being sold to close the funding gap created by the success of low-risk unconventional resources.

 

•

The separation will allow each business to more effectively pursue its own distinct operating priorities and strategies, and will enable the management of both companies to pursue unique opportunities for long-term growth and profitability.

 

•

The separation will create independent equity structures that will afford each company direct access to capital markets and facilitate the ability to capitalize on its unique growth opportunities.

 

•

The separation will provide enhanced liquidity to holders of Atlas Energy common units, who will hold two separate publicly traded securities that they may seek to retain or monetize.

 

•

The separation will provide investors with two distinct and targeted investment opportunities with different investment and business characteristics, including opportunities for growth, capital structure, business model, and financial returns.

We may not achieve the anticipated benefits for a variety of reasons, including potential loss of synergies (if any) from operating as one company, potential for increased costs, potential disruptions to the businesses as a result of the separation, potential for the two companies to compete with one another in the marketplace, risks of being unable to achieve the benefits expected to be achieved by the separation, risk that the plan of separation might not be completed, and both the one-time and ongoing costs of the separation. If we fail to achieve some or all of the benefits expected to result from the separation, or if such benefits are delayed, our business, financial conditions and results of operations could be adversely affected.

Atlas Energy may fail to perform under various transaction agreements that will be executed as part of the separation.

In connection with the separation, we and Atlas Energy will enter into a separation and distribution agreement, an employee matters agreement and certain other agreements to effect the separation and distribution and provide a framework for our relationship with Atlas Energy after the separation. These agreements will provide for the allocation between Atlas Energy and us of the employees, assets, liabilities and obligations (including investments, property and employee benefits and tax-related assets and liabilities) of Atlas Energy attributable to periods before, at and after our separation from Atlas Energy and will govern the relationship between us and Atlas Energy subsequent to the completion of the separation. We will rely on Atlas Energy to satisfy its performance and payment obligations under these agreements. Following the consummation of the Atlas Merger, Atlas Energy will be a subsidiary of Targa Resources. If Atlas Energy and/or Targa Resources is unable to satisfy Atlas Energy’s obligations under these agreements, including its indemnification obligations, we could incur operational difficulties or losses.

After our separation from Atlas Energy, we will have debt obligations that could restrict our ability to pay cash distributions and have negative impact on our financing options and liquidity position.

As of September 30, 2014, on a pro forma basis after giving effect to the new financing arrangements that New Atlas expects to enter into in connection with the separation and after giving effect to the application of the net proceeds of such financing, New Atlas’s total indebtedness would have been $155.0 million.

This debt could have important consequences to New Atlas and its investors, including:

 

•

requiring a substantial portion of New Atlas’s cash flow to make interest payments on this debt;

 

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•

making it more difficult to satisfy debt service and other obligations;

 

•

increasing the risk of a future credit ratings downgrade of its debt, which could increase future debt costs and limit the future availability of debt financing;

 

•

increasing New Atlas’s vulnerability to general adverse economic and industry conditions;

 

•

reducing the cash flow available to fund capital expenditures and other corporate purposes and to grow New Atlas’s business;

 

•

limiting New Atlas’s flexibility in planning for, or reacting to, changes in its business and the industry;

 

•

placing New Atlas at a competitive disadvantage relative to its competitors that may not be as leveraged with debt;

 

•

limiting New Atlas’s ability to borrow additional funds as needed or take advantage of business opportunities as they arise; and

 

•

limiting New Atlas’s ability to pay cash distributions.

To the extent that New Atlas incurs additional indebtedness, the risks described above could increase. In addition, New Atlas’s actual cash requirements in the future may be greater than expected. New Atlas’s cash flow may not be sufficient to repay all of the outstanding debt as it becomes due, and New Atlas may not be able to borrow money, sell assets or otherwise raise funds on acceptable terms, or at all, to refinance New Atlas’s debt.

The U.S. federal income tax consequences of the separation depend on the status of Atlas Energy as a partnership for U.S. federal income tax purposes on the date of the distribution. If the IRS were successful in asserting that Atlas Energy should be treated as a corporation for U.S. federal income tax purposes on the date of the distribution, then Atlas Energy and unitholders of Atlas Energy who receive our common units in the distribution may be subject to significant tax liability.

The U.S. federal income tax consequences of the distribution depend on the status of Atlas Energy as a partnership for U.S. federal income tax purposes on the date of the distribution. We believe that Atlas Energy should be treated as a partnership for U.S. federal income tax purposes on the date of the distribution, and Atlas Energy files U.S. federal income tax returns on that basis. However, neither we nor Atlas Energy has requested, nor plan to request, a ruling from the IRS on this matter. The IRS could assert that Atlas Energy should be treated as a corporation for U.S. federal income tax purposes. If the IRS were successful in asserting that Atlas Energy should be treated as a corporation for U.S. federal income tax purposes, then Atlas Energy and unitholders of Atlas Energy who receive our common units in the distribution may be subject to significant tax liability.

If the IRS were successful in asserting that Atlas Energy should be treated as a corporation for U.S. federal income tax purposes on the date of the distribution, Atlas Energy would be subject to tax on gain, if any, that it would have recognized if it had sold our common units received by unitholders of Atlas Energy in the distribution in a taxable sale for their fair market value. In addition, in such case, each unitholder of Atlas Energy who receives our common units in the distribution would be treated as if the unitholder had received a distribution equal to the fair market value of our common units that were distributed to the unitholder, which generally would be treated as either taxable dividend income to the unitholder, to the extent of Atlas Energy’s current or accumulated earnings and profits or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in its units of Atlas Energy, or taxable capital gain, after the unitholder’s tax basis in such units of Atlas Energy is reduced to zero. Accordingly, taxation of Atlas Energy as a corporation on the date of the distribution could result in materially adverse tax consequences to Atlas Energy and unitholders of Atlas Energy who receive our common units in the distribution.

For further information, unitholders should read the section entitled “Certain U.S. Federal Income Tax Matters” beginning on page 260 and consult their own advisors concerning the U.S. federal, state, local and

 

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foreign tax consequences to them of the distribution, including in the event the IRS were successful in asserting that Atlas Energy should be treated as a corporation for U.S. federal income tax purposes on the date of the distribution.

Risks Relating to the Ownership of Our Common Units

We cannot be certain that an active trading market for our common units will develop or be sustained after the distribution and, following the distribution, our unit price may fluctuate significantly. If the unit price declines after the distribution, you could lose a significant part of your investment.

A public market for our common units does not currently exist. We anticipate that prior to the record date for the distribution, trading of shares of our common units will begin on a “when-issued” basis and will continue through the distribution date, but we cannot guarantee that an active trading market will develop or be sustained for our common units after the separation. Nor can we predict the prices at which our common units may trade after the separation, the effect of the separation and distribution on the trading prices of our common units or whether the combined market value of our common units and Atlas Energy’s common units will be less than, equal to or greater than the market value of Atlas Energy common units prior to the separation and distribution.

The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:

 

•

changes in securities analysts’ recommendations and their estimates of our financial performance;

 

•

the public’s reaction to our press releases, announcements and our filings with the SEC;

 

•

fluctuations in broader securities market prices and volumes, particularly among securities of natural gas and oil companies and securities of publicly traded limited partnerships and limited liability companies;

 

•

changes in market valuations of similar companies;

 

•

departures of key personnel;

 

•

commencement of or involvement in litigation;

 

•

variations in our quarterly results of operations or those of other natural gas and oil companies;

 

•

variations in the amount of our quarterly cash distributions;

 

•

future issuances and sales of our units; and

 

•

changes in general conditions in the U.S. economy, financial markets or the natural gas and oil industry.

In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.

Sales of our common units following the distribution may cause our unit price to decline.

Sales of substantial amounts of our common units in the public market following the distribution, or the perception that these sales may occur, could cause the market price of our common units to decline. In addition, the sale of these units could impair our ability to raise capital through the sale of additional common units.

Increases in interest rates could adversely affect our unit price.

Credit markets are continuing to experience low interest rates. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our and ARP’s financing costs to increase accordingly. As with other yield-oriented securities, our unit price is affected by the level of our and ARP’s cash distributions

 

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and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units. A rising interest rate environment could have an adverse impact on our unit price and our and ARP’s ability to issue additional equity or to incur debt to make acquisitions or for other purposes and could affect our and ARP’s ability to make cash distributions at our and ARP’s intended levels.

The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not solely on profitability.

The amount of cash that we have available for distribution depends primarily on our cash flow, including cash reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses, and we may not make cash distributions during periods when we record net income.

There is no guarantee that our unitholders will receive distributions from us.

While our cash distribution policy, consistent with the terms of our limited liability company agreement, will require that we distribute all of our available cash quarterly, our cash distribution policy will be subject to the following restrictions and limitations and may be changed at any time, including in the following ways:

 

•

We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including increases in our general and administrative expenses, principal or interest payments on our future outstanding debt, elimination of future distributions from ARP, the effect of working capital requirements and anticipated cash needs of us or ARP.

 

•

Our cash distribution policy will be, and ARP’s cash distribution policy is, subject to restrictions on distributions under any credit facility we enter into and under ARP’s credit facilities, respectively, such as material financial tests and covenants and limitations on paying distributions during an event of default.

 

•

Our board of directors will have the authority under our amended and restated limited liability company agreement to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders. The establishment of those reserves could result in a reduction in future cash distributions to our unitholders pursuant to our stated cash distribution policy.

 

•

Our limited liability company agreement, including the cash distribution policy contained therein, may be amended by a vote of the holders of a majority of our common units.

 

•

Even if our cash distribution policy is not amended, modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our board of directors, taking into consideration the terms of our limited liability company agreement.

 

•

We can issue additional units, including units that are senior to the common units, without the consent of our unitholders so long as we do not exceed 20% of our common units then outstanding (or senior units convertible into such common units), and these additional units would dilute common unitholders’ ownership interests.

 

•

Under Section 18-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

Because of these restrictions and limitations on our cash distribution policy and our ability to change our cash distribution policy, we may not have available cash to distribute to our unitholders, and there is no guarantee that our unitholders will receive quarterly distributions from us.

 

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If we do not pay distributions on our common units in any fiscal quarter, our unitholders are not entitled to receive distributions for such prior periods in the future.

Our distributions to our unitholders are not cumulative. Consequently, if we do not pay distributions on our common units with respect to any quarter, our unitholders are not entitled to such payments in the future.

Our cash distribution policy limits our ability to grow.

Because we will distribute our available cash rather than reinvesting it in our business, our growth may not be as significant as businesses that reinvest their available cash to expand ongoing operations. If we issue additional common units or incur debt to fund acquisitions and expansion and investment capital expenditures, the payment of distributions on those additional units or interest on that debt could increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our limited liability company agreement on our ability to issue additional units, including units ranking senior to the common units.

A significant number of our common units may be traded following the distribution, which may cause our unit price to decline.

Any sales of substantial amounts of our common units in the public market or the perception that such sales might occur, in connection with the distribution or otherwise, may cause the market price of our common units to decline. Upon completion of the distribution, we expect that we will have an aggregate of approximately 26.0 million common units issued and outstanding on February 28, 2015. These common units will be freely tradeable without restriction or further registration under the U.S. Securities Act of 1933, as amended, or the “Securities Act,” unless the shares are owned by one of our “affiliates,” as that term is defined in Rule 405 under the Securities Act. We are unable to predict whether large amounts of our common units will be sold in the open market following the distribution. We are also unable to predict whether a sufficient number of buyers would be in the market at that time.

Unitholders may have liability to repay distributions that were wrongfully distributed to them, or other liabilities with respect to ownership of our units.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 18-607 of the Delaware Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to members on account of their membership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of the impermissible distribution, members who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable for the obligations of the transferring member to make contributions to the limited liability company that are known to such purchaser of common units at the time it became a member and for unknown obligations if the liabilities could be determined from the limited liability company agreement.

We may issue additional common units without the consent of our unitholders, which will dilute existing members’ ownership interest in us and may increase the risk that we will not have sufficient available cash to make distributions.

Our limited liability company agreement authorizes us to issue an unlimited number of limited liability company interests of any type without the approval of our unitholders on terms and conditions established by our board of directors at any time subject to certain limitations under existing NYSE listing rules. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

•

our unitholders’ proportionate ownership interest in us will decrease;

 

•

the amount of cash available for distribution on each unit may decrease;

 

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•

the relative voting strength of each previously outstanding unit may be diminished;

 

•

the ratio of taxable income to distributions may increase; and

 

•

the market price of the common units may decline.

Certain provisions of our limited liability company agreement and Delaware law could deter acquisition proposals and make it difficult for a third party to acquire control of us. This could have a negative effect on the price of our common units.

Our limited liability company agreement contains provisions that are intended to deter coercive takeover practices and inadequate takeover bids and to encourage prospective acquirers to negotiate with our board of directors rather than to attempt a hostile takeover. These provisions include:

 

•

a board of directors that is divided into three classes with staggered terms, and this classified board provision could have the effect of making the replacement of incumbent directors more time consuming and difficult;

 

•

rules regarding how our common unitholders may present proposals or nominate directors for election;

 

•

the inability of our common unitholders to call a special meeting;

 

•

the inability of our common unitholders to remove directors; and

 

•

the ability of our directors, and not unitholders, to fill vacancies on our board of directors.

These provisions are intended to protect our common unitholders from coercive or otherwise unfair takeover tactics by requiring potential acquirers to negotiate with our board of directors and by providing our board of directors with more time to assess any acquisition proposal. These provisions are not intended to make us immune from takeovers. However, these provisions will apply even if an offer may be considered beneficial by some of our unitholders and could delay or prevent an acquisition that our board of directors determines is in our best interest and that of our unitholders. These provisions may also prevent or discourage attempts to remove and replace incumbent directors. Any of the foregoing provisions could limit the price that some investors might be willing to pay for our common units.

Our unitholders who fail to furnish certain information requested by our board of directors or who our board of directors determines are not eligible citizens may not be entitled to receive distributions in kind upon our liquidation and their common units will be subject to redemption.

We have the right to redeem all of the units of any holder that is not an eligible citizen if we are or become subject to federal, state, or local laws or regulations that, in the determination of our board of directors, create a substantial risk of cancellation or forfeiture of any property in which we have an interest because of the nationality, citizenship or other related status of any member. Our board of directors may require any member or transferee to furnish information about his nationality, citizenship or related status. If a member fails to furnish information about his nationality, citizenship or other related status within a reasonable period after a request for the information or our board of directors determines after receipt of the information that the member is not an eligible citizen, the member may be treated as a non-citizen assignee. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation. Furthermore, we have the right to redeem all of the common units of any holder that is not an eligible citizen or fails to furnish the requested information.

Common units held by persons who are non-taxpaying assignees will be subject to the possibility of redemption.

If our board of directors determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof

 

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thereof) of one or more of our members, has, or is reasonably likely to have, a material adverse effect on our ability to operate our assets or generate revenues from our assets, then our board of directors may adopt such amendments to our limited liability company agreement as it determines are necessary or appropriate to obtain proof of the U.S. federal income tax status of our members (and their owners, to the extent relevant) and permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rate that can be charged to customers by our subsidiaries or who fails to comply with the procedures instituted by our board of directors to obtain proof of the U.S. federal income tax status.

Tax Risks to Unitholders

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for U.S. federal income tax purposes or we were to become subject to a material amount of entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution.

The anticipated after-tax benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.

We are currently treated as a partnership for U.S. federal income tax purposes, which requires that 90% or more of our gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code. Qualifying income is defined as income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil, or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy and timber). We may not meet this requirement or current law may change so as to cause, in either event, us to be treated as a corporation for U.S. federal income tax purposes or otherwise be subject to U.S. federal income tax. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed as corporate distributions, and no income, gain, loss, deduction or credit would flow through to them. Because a tax may be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Therefore, our treatment as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and therefore result in a substantial reduction in the value of our common units.

Current law or our business may change so as to cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to unitholders would be reduced.

Unitholders may be required to pay taxes on income from us even if they do not receive any cash distributions from us.

Unitholders will be required to pay U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

 

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Our ratio of taxable income to cash distributions will be much greater than the ratio applicable to holders of common units in ARP.

Our ratio of taxable income to cash distributions will be much greater than the ratio applicable to holders of common units in ARP. Other holders of common units in ARP will receive remedial allocations of deductions from ARP. Although we will receive remedial allocations of deductions from ARP, remedial allocations of deductions to us will be very limited. In addition, our ownership of ARP incentive distribution rights will cause more taxable income to be allocated to us from ARP than will be allocated to holders who hold only common units in ARP. If ARP is successful in increasing its distributions over time, our income allocations from our ARP incentive distribution rights will increase, and, therefore, our ratio of taxable income to cash distributions will increase. Because our ratio of taxable income to cash distributions will be greater than the ratio applicable to holders of common units in ARP, our unitholders’ allocable taxable income will be significantly greater than that of a holder of common units in ARP who receives cash distributions from ARP equal to the cash distributions our unitholders would receive from us.

Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

A successful IRS contest of the U.S. federal income tax positions we take may harm the market for our common units, and the costs of any contest will reduce cash available for distribution.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter that affects us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and a court may disagree with some or all of those positions. Any contest with the IRS may lower the price at which our common units trade. In addition, our costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

We will treat each holder of our common units as having the same tax benefits without regard to the common units held. The IRS may challenge this treatment, which could reduce the value of the common units.

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing U.S. Treasury regulations. A successful IRS challenge to those positions could reduce the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns.

The sale or exchange of 50% or more of our or ARP’s capital and profits interest within a 12-month period will result in the termination of our or ARP’s partnership for U.S. federal income tax purposes.

We will be considered to have terminated our partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interest in our capital and profits within a 12-month period.

 

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Likewise, ARP will be considered to have terminated their partnerships for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interest in ARP’s capital and profits within a 12-month period. The termination would, among other things, result in the closing of our or ARP’s taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income for the year in which the termination occurs. Thus, if this occurs, the unitholder will be allocated an increased amount of U.S. federal taxable income for the year in which we are considered to be terminated as a percentage of the cash distributed to the unitholder with respect to that period.

Tax gain or loss on the disposition of our common units could be more or less than expected because prior distributions in excess of allocations of income will decrease unitholders’ tax basis in their units.

If unitholders sell any of their common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those units. Prior distributions, and the allocation of losses (including depreciation deductions), to them in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that unit, will, in effect, become taxable income to them if the unit is sold at a price greater than their tax basis in that unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to them. The current maximum marginal U.S. federal income tax rate on ordinary income is 39.6% plus a 3.8% Medicare surtax on investment income. As a result, a unitholder may incur a tax liability in excess of the amount of cash it receives from the sale.

Unitholders may be subject to state and local taxes and return filing requirements, including in states where they do not live, as a result of investing in our common units.

In addition to U.S. federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or ARP do business or own property now or in the future, even if our unitholders do not reside in any of those jurisdictions. Our unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We and ARP presently anticipate that substantially all of our income will be generated in Alabama, Colorado, New Mexico, Ohio, Oklahoma, Pennsylvania, Texas and West Virginia. As we and ARP make acquisitions or expand our business, we and ARP may do business or own assets in other states in the future. It is the responsibility of each unitholder to file all U.S. federal, foreign, state and local tax returns that may be required of such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.

The IRS may challenge our tax treatment related to transfers of units, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. If the IRS were to challenge this method or new U.S. Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

ARP has adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between us and the public unitholders of ARP. The IRS may challenge this treatment, which could adversely affect the value of ARP’s common units and our common units.

When we or ARP issue additional units or engage in certain other transactions, ARP determines the fair market value of its assets and allocates any unrealized gain or loss attributable to such assets to the capital accounts of its unitholders and us. Although ARP may from time to time consult with professional appraisers

 

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regarding valuation matters, including the valuation of its assets, ARP makes many of the fair market value estimates of its assets itself using a methodology based on the market value of its common units as a means to measure the fair market value of its assets. ARP’s methodology may be viewed as understating the value of its assets. In that case, there may be a shift of income, gain, loss and deduction between certain ARP unitholders and us, which may be unfavorable to such ARP unitholders. Moreover, under ARP’s current valuation methods, subsequent purchasers of our common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to their tangible assets and a lesser portion allocated to their intangible assets. The IRS may challenge ARP’s valuation methods, or our or ARP’s allocation of the Section 743(b) adjustment attributable to ARP’s tangible and intangible assets, and allocations of income, gain, loss and deduction between us and certain of ARP’s unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain on the sale of common units by our unitholders and could have a negative impact on the value of our common units or result in audit adjustments to the tax returns of our unitholders without the benefit of additional deductions.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

Risks Relating to Our Conflicts of Interest

Although we control ARP and our Development Subsidiary through our ownership of their general partner interests, we owe duties to each such entity and its unitholders, which may conflict with our interests.

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, including between us (as the general partner of ARP), on the one hand, and ARP and its limited partners, on the other hand, as well as between the general partner of our new Development Subsidiary, on the one hand, and our Development Subsidiary and its limited partners, on the other hand. Our directors and officers and the Development Subsidiary’s general partner each have a duty to manage each limited partnership in a manner beneficial to us, its owner. At the same time, these directors and officers have a duty to manage each limited partnership in a manner they believe is beneficial to the partnership’s interests. Our board of directors and the board of directors of our Development Subsidiary’s general partner, or our ARP’s or our Development Subsidiary’s respective conflicts committees, will resolve any such conflict and have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

Conflicts of interest may arise in the following situations, among others:

 

•

the allocation of shared overhead expenses;

 

•

the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ARP or our Development Subsidiary, on the other hand;

 

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•

the determination and timing of the amount of cash to be distributed to our subsidiaries’ partners and the amount of cash reserved for the future conduct of their businesses;

 

•

the decision as to whether the limited partnerships should make acquisitions, and on what terms; and

 

•

any decision we make in the future to engage in business activities independent of, or in competition with our subsidiaries.

Certain of our officers and directors may have actual or potential conflicts of interest because of their positions, and their duties may conflict with those of the officers and directors of ARP and our Development Subsidiary’s general partners.

Our officers and directors have duties to manage our business in a manner beneficial to us but since we are also the general partner of ARP, our directors and officers have duties to manage ARP in a manner beneficial to ARP. Certain of our expected executive officers and non-independent directors also serve as executive officers and directors of our Development Subsidiary’s general partner, and, as a result, have duties to manage the Development Subsidiary in a manner beneficial to it. Consequently, these directors and officers may encounter situations in which their obligations to one or more of our subsidiaries, on one hand, and us, on the other hand, are in conflict. The resolution of these conflicts of interest may not always be in our best interest or that of our unitholders. Additionally, some directors and officers may own units, options to purchase units or other equity awards which may be significant for some of these persons. Their positions, and the ownership of such equity of equity awards creates, or may create the appearance of, conflicts of interest when they are faced with decisions that could have different implications for such subsidiaries than the decisions have for us.

Our affiliates and ARP may in certain circumstances compete with us or with each other, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses, and this could adversely affect our results of operations and cash available for distribution to our unitholders.

Neither our limited liability company agreement nor the partnership agreement of ARP prohibits ARP or our affiliates from owning assets or engaging in businesses that compete directly or indirectly with us, our affiliates or ARP. In addition, ARP and its affiliates may acquire, develop or dispose of additional assets related to the production and development of oil, natural gas and NGLs or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. As a result, competition among these entities could adversely affect ARP’s or our results of operations and cash available for paying required debt service on our credit facilities or making distributions.

Pursuant to the terms of our limited liability company agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to our directors or executive officers or any of their affiliates. Some of these executive officers and directors also serve as officers of ARP. No such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any unitholder for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Therefore, ARP and its affiliates may compete with us for investment opportunities and may own an interest in entities that compete with us on an operations basis.

Our limited liability company agreement eliminates our directors’ and officers’ fiduciary duties to holders of our common units and restricts the remedies available to holders of our common units for actions taken by our directors and officers.

Our limited liability company agreement contains provisions that eliminate any fiduciary standards to which our directors and officers and their affiliates could otherwise be held by state fiduciary duty laws. Instead, our directors and officers are accountable to us and our unitholders pursuant to the contractual standards set forth in

 

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our limited liability company agreement. Our limited liability company agreement reduces the standards to which our directors and officers would otherwise be held by state fiduciary duty law and contains provisions restricting the remedies available to unitholders for actions taken by our directors or officers or their affiliates. For example, it provides that:

 

•

whenever our board of directors or officers make a determination or take, or decline to take, any other action in such capacity, our directors and officers are required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard (including fiduciary standards) imposed by Delaware law or any other law, rule or regulation or at equity;

 

•

our directors and officers will not have any liability to us or our unitholders for decisions made in their capacity as a director or officer so long as they acted in good faith, meaning they believed that the decision was not adverse to our interests; and

 

•

our directors and officers will not be liable for monetary damages to us or our unitholders for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

It will be presumed that, in making decisions and taking, or declining to take, actions, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any unitholder or the company, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. The existence of all conflicts of interest disclosed in this information statement, and any actions of our directors and officers taken in connection with such conflicts of interest, have been approved by all of our unitholders pursuant to our limited liability company agreement. See “Conflicts of Interest and Duties” beginning on page 243.

By accepting or purchasing a common unit, a unitholder agrees to be bound by the provisions of the limited liability company agreement, including the provisions discussed above and, pursuant to the terms of our limited liability company agreement, is treated as having consented to various actions contemplated in our limited liability company agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read “Conflicts of Interest and Duties—No Fiduciary Duties” beginning on page 244.

 

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FORWARD-LOOKING STATEMENTS

This information statement and other materials Atlas Energy and New Atlas have filed or will file with the SEC contains, or will contain forward-looking statements regarding business strategies, market potential, future financial performance and other matters. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “might,” “plan,” “potential,” “predict” or “should” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. We have based these forward-looking statements on our current expectations, assumptions, estimates and projections. While we believe these expectations, assumptions, estimates and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. Some of the key factors that could cause actual results to differ from our expectations include:

 

•

the risk that Atlas’s unitholders or Targa Resources’ stockholders do not approve the Atlas Merger or that APL’s unitholders do not approve the APL Merger;

 

•

termination of the Atlas merger agreement as a result of a competing proposal;

 

•

the inability to obtain regulatory approvals required for the Atlas Merger or the APL Merger on the proposed terms and schedule or without conditions that are not anticipated;

 

•

the failure of the conditions to the closing of the Atlas Merger or the APL Merger to be satisfied or waived;

 

•

potential adverse reactions or changes to business or employee relationships, including those resulting from the announcement or completion of the Atlas Merger or the distribution;

 

•

uncertainties as to the timing of the Atlas Merger and the distribution;

 

•

competitive responses to the proposed Atlas Merger and/or distribution;

 

•

unexpected costs, charges or expenses resulting from the Atlas Merger or the distribution;

 

•

litigation relating to the merger;

 

•

the outcome of potential litigation or governmental investigations related to the Atlas Merger, the APL Merger or the distribution;

 

•

our ability to operate the assets we will acquire in connection with the distribution, and the costs of such operation;

 

•

the demand for natural gas, oil, NGLs and condensate;

 

•

the price volatility of natural gas, oil, NGLs and condensate;

 

•

changes in the market price of our common units;

 

•

future financial and operating results;

 

•

economic conditions and instability in the financial markets;

 

•

resource potential;

 

•

realized natural gas and oil prices;

 

•

success in efficiently developing and exploiting our and ARP’s reserves and economically finding or acquiring additional recoverable reserves;

 

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•

the accuracy of estimated natural gas and oil reserves;

 

•

the financial and accounting impact of hedging transactions;

 

•

the ability to fulfill the respective substantial capital investment needs of us and ARP;

 

•

expectations with regard to acquisition activity, or difficulties encountered in connection with acquisitions;

 

•

the limited payment of dividends or distributions, or failure to declare a dividend or distribution, on outstanding common units or other equity securities;

 

•

any issuance of additional common units or other equity securities, and any resulting dilution or decline in the market price of any such securities;

 

•

restrictive covenants in our and ARP’s indebtedness that may adversely affect operational flexibility;

 

•

potential changes in tax laws that may impair the ability to obtain capital funds through investment partnerships;

 

•

the ability to raise funds through the investment partnerships or through access to capital markets;

 

•

the ability to obtain adequate water to conduct drilling and production operations, and to dispose of the water used in and generated by these operations, at a reasonable cost and within applicable environmental rules;

 

•

impact fees and severance taxes;

 

•

changes and potential changes in the regulatory and enforcement environment in the areas in which we and ARP conduct business;

 

•

the effects of intense competition in the natural gas and oil industry;

 

•

general market, labor and economic conditions and related uncertainties;

 

•

the ability to retain certain key customers;

 

•

dependence on the gathering and transportation facilities of third parties;

 

•

the availability of drilling rigs, equipment and crews;

 

•

potential incurrence of significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment;

 

•

uncertainties with respect to the success of drilling wells at identified drilling locations;

 

•

ability to identify all risks associated with the acquisition of oil and natural gas properties, pipeline, facilities or existing wells, and the sufficiency of indemnifications we receive from sellers to protect us from such risks;

 

•

expirations of undeveloped leasehold acreage;

 

•

uncertainty regarding operating expenses, general and administrative expenses and finding and development costs;

 

•

exposure to financial and other liabilities of the managing general partners of the investment partnerships;

 

•

the ability to comply with, and the potential costs of compliance with, new and existing federal, state, local and other laws and regulations applicable to our and ARP’s business and operations;

 

•

ability to integrate operations and personnel from acquired businesses;

 

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•

exposure to new and existing litigations;

 

•

the potential failure to retain certain key employees and skilled workers;

 

•

development of alternative energy resources; and

 

•

the various risks and other factors considered by our board of directors, as described under “The Separation and Distribution—Reasons for the Separation and Distribution” beginning on page 70.

The foregoing list is not exclusive. Other factors that could cause actual results to differ from those implied by the forward-looking statements in this document are more fully described in the “Risk Factors” section of this information statement beginning on page 31. Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included or incorporated by reference in this document speak only as of the date on which the statements were made. We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments except as required by law.

 

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THE SEPARATION AND DISTRIBUTION

Background

On October 13, 2014, Atlas Energy announced that it had entered into the Atlas merger agreement with Targa Resources and a wholly owned subsidiary of Targa Resources providing for such wholly owned subsidiary to merge with and into Atlas Energy, with Atlas Energy surviving as a subsidiary of Targa Resources. Atlas Energy also agreed that pursuant to a separation and distribution agreement substantially in the form attached to the Atlas merger agreement, Atlas Energy would contribute its non-midstream businesses to New Atlas and distribute approximately 26.0 million common units representing a 100% interest in New Atlas to the Atlas Energy unitholders. Atlas Energy has designated Atlas Energy Group, LLC, which is currently the general partner of Atlas Resource Partners, L.P., as the entity with which it will effect these transactions. We refer to Atlas Energy Group, LLC in this information statement as “New Atlas.”

New Atlas is a limited liability company that has elected for U.S. federal income tax purposes to be taxed as a partnership, which Atlas Energy management believed was the most appropriate structure due to the long-lived nature of the assets to be contributed as part of the separation, their expected ability to generate steady cash flows over time, and the potential for tax-efficient growth through future acquisitions, among other considerations. The number of common units to be distributed and the other financial terms of the distribution were determined by management and the board of directors of Atlas Energy’s general partner based on an analysis of the trading price per unit or share of selected comparable companies that were deemed relevant due to their business, structure and market capitalization.

Immediately following completion of the separation and distribution, New Atlas will hold:

 

•

the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in Atlas Resource Partners, a publicly traded Delaware master limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations in basins across the United States;

 

•

Atlas Energy’s general and limited partner interests in its exploration and production development subsidiary, which currently conducts operations in the mid-continent region of the United States;

 

•

Atlas Energy’s general and limited partner interests in Lightfoot Capital Partners, a limited partnership investment business; and

 

•

Atlas Energy’s direct natural gas development and production assets in the Arkoma Basin, which Atlas Energy acquired in July 2013.

Atlas Energy will continue to hold (in addition to its own general partner):

 

•

the general partner interest, incentive distribution rights and its common units in Atlas Pipeline Partners, L.P., a publicly traded Delaware master limited partnership and midstream energy service provider engaged in natural gas gathering, processing and treating services.

Pursuant to the terms of the separation and distribution agreement, the distribution of approximately 26.0 million common units in New Atlas, as described in this information statement, is subject to the satisfaction or waiver of certain conditions, including the satisfaction of all conditions to consummating the Atlas Merger (other than the condition that the distribution shall have occurred). We cannot provide any assurances that the distribution will be completed. Furthermore, because the distribution is conditioned on the satisfaction of all conditions to consummating the Atlas Merger, the approval by the holders of a majority of Atlas Energy’s common units of the Atlas merger agreement and the Atlas Merger is a condition to Atlas Energy’s obligation to effect the distribution. Atlas Energy is seeking such approval from the holders of Atlas Energy common units at a special meeting of Atlas Energy’s unitholders to be held on February 20, 2015. We are not asking you to take any other action, make any payment or surrender or exchange any of your common units of Atlas Energy for common units of New Atlas in connection with the distribution.

 

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Atlas Energy also entered into the APL merger agreement with APL, Atlas Pipeline Partners GP, Targa Resources, Targa Resources Partners, Targa Resources Partners’ general partner and a newly formed subsidiary of Targa Resources Partners providing for the APL Merger to occur. The Atlas Merger and the APL Merger are each conditioned on the other and will each occur only if the other occurs or will occur. As a result, the distribution is indirectly conditioned on the satisfaction of the conditions required for consummating the APL Merger. For a more detailed description of the conditions to the distribution, see the section entitled “The Separation and Distribution—Conditions to the Distribution” beginning on page 74.

Immediately following consummation of the distribution, Atlas Energy and Targa Resources will consummate the Atlas Merger, pursuant to which each common unit of Atlas Energy issued and outstanding immediately prior to the closing of the Atlas Merger will be converted into the right to receive 0.1809 of a share of Targa Resources common stock and $9.12 in cash, without interest. Immediately after the closing of the Atlas Merger, former Atlas Energy unitholders will own approximately     % of the combined company on a fully diluted basis, and existing Targa Resources stockholders will own the remaining approximately     % of the combined company on a fully diluted basis.

Reasons for the Separation and Distribution

The board of directors of Atlas Energy’s general partner believes, in light of its asset make-up and other factors, that separating Atlas Energy into two publicly traded companies is in the best interests of Atlas Energy and its unitholders and has concluded that the separation and distribution will provide each company with certain opportunities and benefits. A wide variety of factors were considered by the board of directors of Atlas Energy’s general partner in evaluating the separation. Among other things, the board of directors considered the following opportunities and benefits:

 

•

The separation will enable Atlas Energy unitholders to keep an interest in Atlas Energy’s non-midstream assets following the Atlas Merger with Targa Resources.

 

•

The separation will facilitate deeper understanding by investors of the different businesses of Atlas Energy and New Atlas, allowing investors to more transparently value the merits, performance and future prospects of each company, which could increase overall unitholder value.

 

•

The separation will create an acquisition currency in the form of units that will enable New Atlas to purchase, and to assist ARP and the Development Subsidiary in purchasing, developed and undeveloped resources to accelerate growth of its natural gas and oil production and development business without diluting Atlas Energy unitholders’ participation in growth at Atlas Pipeline Partners, L.P., a publicly traded partnership the general partner of which is owned by Atlas Energy, and following the APL Merger, growth in Targa Resources Partners. Current industry trends have created a significant opportunity for New Atlas to grow, and to assist ARP and the Development Subsidiary in growing, through the acquisition of assets being sold to close the funding gap created by the success of low-risk unconventional resources.

 

•

The separation will allow each business to more effectively pursue its own distinct operating priorities and strategies, and will enable the management of both companies to pursue unique opportunities for long-term growth and profitability.

 

•

The separation will create independent equity structures that will afford each company direct access to capital markets and facilitate the ability to capitalize on its unique growth opportunities.

 

•

The separation will provide enhanced liquidity to holders of Atlas Energy common units, who will hold two separate publicly traded securities that they may seek to retain or monetize.

 

•

The separation will provide investors with two distinct and targeted investment opportunities with different investment and business characteristics, including opportunities for growth, capital structure, business model and financial returns.

 

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Neither we nor Atlas Energy or any of their affiliates can assure you that, following the separation and distribution, any of the benefits described above or otherwise will be realized to the extent anticipated or at all. The board of directors of Atlas Energy’s general partner also considered a number of potentially negative factors in evaluating the separation, including potential loss of synergies (if any) from operating as one company, potential for increased costs, potential disruptions to the businesses as a result of the separation, potential for the two companies to compete with one another in the marketplace, risks of being unable to achieve the benefits expected to be achieved by the separation, risk that the plan of separation might not be completed and both the one-time and ongoing costs of the separation. The board of directors of Atlas Energy’s general partner concluded that notwithstanding these potentially negative factors, separation would be in the best interests of Atlas Energy and its unitholders.

In view of the wide variety of factors considered in connection with the evaluation of the separation and the complexity of these matters, the board of directors of Atlas Energy’s general partner did not find it useful to, and did not attempt to, quantify, rank or otherwise assign relative weights to the factors considered. The individual members of the board of directors of Atlas Energy’s general partner may have given different weights to each of the factors.

In addition, completion of the distribution is a condition to the Atlas Merger, and indirectly the APL Merger. For more information on the Atlas Merger, see the Proxy Statement.

Contribution of Assets Prior to the Distribution

We were formed as a limited liability company in Delaware in October 2011 to serve as the general partner of Atlas Resource Partners, L.P. In connection with the separation, Atlas Energy will contribute to us all of Atlas Energy’s businesses and assets other than those related to its “Atlas Pipeline Partners” segment. As a result of this contribution, we will hold, directly or indirectly, the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in Atlas Resource Partners, L.P., a publicly traded Delaware master limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations in basins across the United States, Atlas Energy’s general and limited partner interests in its exploration and production Development Subsidiary, which currently conducts operations in the mid-continent region of the United States, its general partner and limited partner interests in Lightfoot Capital Partners, a limited partnership investment business, and its other natural gas and oil exploration and production assets. As part of the plan to separate such businesses from such segment, Atlas Energy plans to transfer to us its equity interests in Atlas Resource Partners as well as the general partner and limited partner interests of the Development Subsidiary and certain entities that operate its other natural gas and oil exploration and production business and hold its general and limited partner interests in Lightfoot Capital Partners.

When and How You Will Receive Common Units in the Distribution

We expect that Atlas Energy will distribute approximately 26.0 million of our common units (other than common units sold as a result of fractional units) on February 28, 2015, the distribution date. The distribution will be made to all holders of record of Atlas Energy common units on February 25, 2015, the record date for the distribution. We expect that the distribution date and the closing date for the Atlas Merger will be the same day. Atlas Energy’s transfer agent and registrar, Broadridge Corporate Issuer Solutions, Inc., also referred to as “Broadridge,” will serve as transfer agent and registrar for the New Atlas common units and as distribution agent in connection with the distribution of New Atlas common units.

If you own Atlas Energy common units of the close of business on the record date, the New Atlas common units that you are entitled to receive in the distribution will be issued electronically, as of the distribution date, to your account as follows:

 

•

Registered Unitholders. If you own your Atlas Energy common units directly (either in book-entry form through an account at Atlas Energy’s transfer agent, Broadridge, and/or if you hold physical paper

 

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stock certificates), you will receive your New Atlas common units by way of direct registration in book-entry form. Registration in book-entry form refers to a method of recording unit ownership when no physical paper share certificates are issued to unitholders, as is the case in this distribution.

Commencing on or shortly after the distribution date, the distribution agent will mail to you an account statement that indicates the number of New Atlas common units that have been registered in book-entry form in your name. If you have any questions concerning the mechanics of having your ownership of our common units registered in book-entry form, we encourage you to contact Broadridge at the address set forth in this information statement.

 

•

Beneficial Unitholders. Most Atlas Energy unitholders hold their Atlas Energy units beneficially through a bank or brokerage firm. In such cases, the bank or brokerage firm would be said to hold the units in “street name” and ownership would be recorded on the bank or brokerage firm’s books. If you hold your Atlas Energy common units through a bank or brokerage firm, your bank or brokerage firm will credit your account for the New Atlas common units that you are entitled to receive in the distribution. If you have any questions concerning the mechanics of having your common units held in “street name,” we encourage you to contact your bank or brokerage firm.

Transferability of Our Common Units

Our common units that will be distributed in the distribution will be transferable without registration under the Securities Act, except for common units received by persons who may be deemed to be our affiliates. Persons who may be deemed to be our affiliates after the distribution generally include individuals or entities that control, are controlled by or are under common control with us, which may include certain of our executive officers, directors or principal unitholders. Securities held by our affiliates will be subject to resale restrictions under the Securities Act. Our affiliates will be permitted to sell our common units only pursuant to an effective registration statement or an exemption from the registration requirements of the Securities Act, such as the exemption afforded by Rule 144 under the Securities Act.

Number of Our Common Units that You Will Receive

For every two common units of Atlas Energy that you own at the close of business on February 25, 2015, the record date, you will receive one of our common units. No fractional common unit will be distributed. Instead, if you are a registered holder, the transfer agent will aggregate fractional units into whole units, sell the whole units in the open market at prevailing market prices and distribute the aggregate cash proceeds (net of discounts and commissions) of the sales pro rata (based on the fractional unit that such holder would otherwise be entitled to receive) to each holder who otherwise would have been entitled to receive a fractional unit in the distribution. The transfer agent, in its sole discretion, without any influence by Atlas Energy or us, will determine when, how, through which broker-dealer and at what price to sell the whole unit. Any broker-dealer used by the transfer agent will not be an affiliate of either Atlas Energy or us. Neither we nor Atlas Energy will be able to guarantee any minimum sale price in connection with the sale of these shares. Recipients of cash in lieu of fractional shares will not be entitled to any interest on the amounts of payment made in lieu of fractional shares.

The receipt of cash in lieu of fractional shares of our common units may be taxable to you for U.S. federal income tax purposes. See “Certain U.S. Federal Income Tax Matters” beginning on page 260 for a summary of the material U.S. federal income tax consequences of the distribution. We estimate that it will take approximately two weeks from the distribution date for the distribution agent to complete the distributions of the aggregate net cash proceeds. If you hold your Atlas Energy common units through a bank or brokerage firm, your bank or brokerage firm will receive, on your behalf, your pro rata share of the aggregate net cash proceeds of the sales and will electronically credit your account for your share of such proceeds.

 

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Treatment of Equity Based Compensation

As of the distribution date, each Atlas Energy phantom unit and unit option will be adjusted, as described in Compensation Discussion and Analysis—Elements of Atlas Energy’s Compensation Program—Going Forward.

Incurrence of Debt

In connection with the distribution, New Atlas expects to incur approximately $155 million of debt pursuant to a term loan facility. The net proceeds of such debt are expected to fund a cash transfer of $150 million to Atlas Energy, as described in “Certain Relationships and Related Party Transactions—Separation and Distribution Agreement—Cash Transfers.”

Results of the Distribution

After our separation from Atlas Energy and the distribution, we will be a separate, publicly traded company. Immediately after the distribution, Atlas Energy will no longer hold any of our common units. As a result, following the separation and distribution, the New Atlas unitholders will elect our board of directors. Immediately following the distribution, we expect to have approximately 170 unitholders of record, based on the number of registered holders of Atlas Energy common units as of January 29, 2015 and approximately 26.0 million New Atlas common units outstanding. The actual number of common units to be distributed will be determined at the close of business on February 25, 2015, the record date for the distribution, and will reflect any exercise of Atlas Energy options between the date that the board of directors of Atlas Energy’s general partner declares the distribution and the record date for the distribution. The distribution will not affect the number of outstanding Atlas Energy common units or any rights of Atlas Energy unitholders. Atlas Energy will not distribute any fractional shares of our common units.

Before the separation, we will enter into a separation and distribution agreement, an employee matters agreement, an operating agreement for certain Atlas Energy assets in Tennessee and other agreements with Atlas Energy to effect the separation and provide a framework for the relationships between us and Atlas Energy after the separation. These agreements will provide for the allocation between Atlas Energy and New Atlas of Atlas Energy’s assets, liabilities and obligations (including investments, property and employee benefits and tax-related assets and liabilities) of Atlas Energy attributable to periods before, at and after our separation from Atlas Energy and will govern the relationship between us and Atlas Energy subsequent to the completion of the separation. Following the Atlas Merger, Atlas Energy will be a wholly owned subsidiary of Targa Resources. For a more detailed description of these agreements, see “Certain Relationships and Related Party Transactions” beginning on page 234.

Effect on Atlas Energy Common Units

The number of outstanding common units of Atlas Energy will not change as a result of the distribution. As a result of the Atlas Merger, which will occur immediately following the distribution, you will receive 0.1809 of a share of Targa Resources common stock and $9.12 in cash, without interest, for each Atlas Energy common unit you own. Immediately after the closing of the Atlas Merger, Atlas Energy unitholders will own approximately 18% of the combined company on a fully diluted basis, and Targa Resources shareholders will own the remaining approximately 82% of the combined company on a fully diluted basis. For more information on when and how you will receive Targa Resources common shares in the Atlas Merger, please refer to the Proxy Statement.

Market for Our Common Units

There is currently no public market for our common units. A condition to the distribution is authorization of the listing of our common units on the NYSE, subject to official notice of issuance. We have been authorized to list our common units on the NYSE under the symbol “ATLS,” subject to official notice of distribution. We have not and will not set the initial price of our common units. The initial price will be established by the public markets.

 

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We cannot predict the price at which our common units will trade after the distribution. In fact, the sum of (1) the trading price of our common units that each Atlas Energy unitholder will receive in the distribution and (2) the merger consideration received by such unitholder from Targa Resources may not equal the “regular-way” trading price of an Atlas Energy common unit immediately prior to the distribution. The price at which our common unit trades may fluctuate significantly, particularly until an orderly public market develops. Trading prices for our common units will be determined in the public markets and may be influenced by many factors. See “Risk Factors—Risks Relating to the Ownership of Our Common Units—Sales of our common units following the distribution may cause our unit price to decline” on page 56.

Trading Prior to the Distribution Date

Beginning shortly before the record date, we expect that there will be two markets in Atlas Energy common units: a “regular-way” market and an “ex-distribution” market. Atlas Energy common units that trade on the “regular-way” market will trade with an entitlement to our common units that will be distributed pursuant to the distribution. Atlas Energy common units that trade on the “ex-distribution” market will trade without an entitlement to our common units that will be distributed pursuant to the distribution. Therefore, if you sell Atlas Energy common units in the “regular-way” market up to and including the distribution date, you will be selling your right to receive our common units in the distribution. If you sell Atlas Energy common units on the “ex-distribution” market up to and including through the distribution date, you will receive our common units that you would be entitled to receive pursuant to your ownership as of the record date of the Atlas Energy common units.

Furthermore, beginning shortly before the record date and continuing up to and including through the distribution date, we expect that there will be a “when-issued” market in our common units. “When-issued” trading refers to a sale or purchase made conditionally because the security has been authorized but not yet issued. The “when-issued” trading market will be a market for our common units that will be distributed to Atlas Energy unitholders on the distribution date. If you owned Atlas Energy common units at the close of business on the record date, you would be entitled to receive a certain number of our common units distributed pursuant to the distribution. You may trade this entitlement to our common units, without the Atlas Energy common units that you own, on the “when-issued” market. On the first trading day following the distribution date, “when-issued” trading with respect to our common units will end, and “regular-way” trading will begin.

Conditions to the Distribution

We expect that the distribution will be effective on February 28, 2015, the distribution date, provided that, among other conditions described in this information statement, the following conditions shall have been satisfied or waived by the general partner of Atlas Energy, subject to the restrictions set forth below:

 

•

the SEC shall have declared effective our registration statement on Form 10, of which this information statement is a part, and no stop order relating to the registration statement is in effect;

 

•

the transfer of assets and liabilities from Atlas Energy to New Atlas shall have been completed in accordance with the separation and distribution agreement;

 

•

any required actions and filings with regard to state securities and blue sky laws of the United States (and any comparable laws under any foreign jurisdictions) shall have been taken and, where applicable, have become effective or been accepted;

 

•

the transaction agreements relating to the separation shall have been duly executed and delivered by the parties thereto;

 

•

no order, injunction or decree issued by any court or agency of competent jurisdiction or other legal restraint or prohibition preventing consummation of the separation, distribution or any of the transactions contemplated by the separation and distribution agreement or any ancillary agreement, shall be in effect;

 

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•

our common units to be distributed shall have been accepted for listing on the NYSE, subject to official notice of issuance;

 

•

Atlas Energy shall retain at least $5,000,000 of cash, and its net working capital (including retained cash) as of the distribution shall be no less than $5,000,000;

 

•

Atlas Energy shall have received, or shall receive simultaneously with the distribution, certain payments from Targa Resources under the Atlas merger agreement and the proceeds from the cash transfers from New Atlas, as described in “Certain Relationships and Related Party Transactions—Separation and Distribution Agreement—Cash Transfers”; and

 

•

the conditions required for consummating the Atlas Merger, as set forth in the Proxy Statement relating to that transaction, shall have been satisfied or waived (other than the condition that the distribution shall have occurred).

Atlas Energy also entered into the APL merger agreement with APL, Atlas Pipeline Partners GP, Targa Resources, Targa Resources Partners, Targa Resources Partners’ general partner and a newly formed subsidiary of Targa Resources Partners providing for the APL Merger to occur. The Atlas Merger and the APL Merger are each conditioned on the other and will each occur only if the other occurs. As a result, the distribution is indirectly conditioned on the satisfaction of the conditions required for consummating the APL Merger. For additional information about the merger of APL and Targa Resources Partners, please read Atlas Energy’s separate proxy statement/prospectus relating to the Atlas Merger.

Subject to the terms and conditions of the Atlas merger agreement, the separation and distribution agreement may not be terminated prior to the distribution without the mutual consent of Atlas Energy and Targa Resources. Neither Atlas Energy nor New Atlas will be permitted to amend, waive, supplement or modify any provision of the separation and distribution agreement, or make any determination as to the satisfaction or waiver of the conditions to the distribution, in a manner that is materially adverse to Atlas Energy, Targa Resources or their affiliates or that would prevent or materially impede consummation of the Atlas Merger without first obtaining Targa Resources’ consent.

So long as it first obtains Targa Resources’ consent, Atlas Energy will have the discretion to determine (and change) the terms of, and whether to proceed with, the distribution. To the extent it determines to so proceed, Atlas Energy will have the sole and absolute discretion to determine the record date for the distribution and the distribution date and distribution ratio. The fulfillment of the foregoing conditions does not create any obligations on the part of Atlas Energy to its unitholders to effect the distribution or in any way limit Atlas Energy’s right to terminate the separation or distribution agreement or alter the consequences of any such termination from those specified in the agreement. Any determination made by the board of Atlas Energy’s general partner prior to the distribution concerning the satisfaction or waiver of any or all of the conditions to the distribution shall be conclusive and binding on Atlas Energy and New Atlas. Atlas Energy does not intend to notify its unitholders of any modifications to the terms of the separation and distribution that, in the judgment of the board of directors of its general partner, are not material. For example, the board of directors of Atlas Energy’s general partner might consider to be material such matters as significant changes to the distribution ratios, the assets to be contributed or the liabilities to be assumed in the separation. To the extent that the board of directors of Atlas Energy’s general partner determines that any modifications by Atlas Energy changes the material terms of the distribution, Atlas Energy will notify its unitholders in a manner reasonably calculated to inform them about the modification as may be required by law, by, for example, publishing a press release, filing a current report on Form 8-K, or circulating a supplement to the information statement.

 

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CASH DISTRIBUTION POLICY

Set forth below is a summary of the significant provisions of our limited liability company agreement and ARP’s limited partnership agreement that relate to our and ARP’s cash distributions and a forecast of our quarterly cash distribution rate. You should read the following discussion of our cash distribution policy in conjunction with the more detailed information regarding the factors and assumptions upon which our cash distribution policy is based in “—Significant Forecast Assumptions” and “—Sensitivity Analysis” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and material risks inherent in our and ARP’s business.

For additional information regarding our historical and pro forma operating results, you should refer to our audited historical financial statements for the years ended December 31, 2013, 2012 and 2011, our unaudited historical financial statements for the nine months ended September 30, 2014 and 2013, and our pro forma financial statements for the nine months ended September 30, 2014 and the year ended December 31, 2013, each included elsewhere in this information statement.

General

Rationale for Our Cash Distribution Policy

The amount of distributions paid under our cash distribution policy and the decision to make any distribution will be determined by our board of directors in its discretion, taking into account the terms of our limited liability company agreement. Our cash distribution policy reflects a basic judgment, given our current asset base, that our unitholders will be better served by the distribution of our available cash (which is defined in our limited liability company agreement and is net of any expenses and reserves established by our board of directors) than by our retaining such available cash. It is the current policy of our board of directors that we should increase our level of cash distributions per unit only when, in its judgment, it believes that:

 

•

we have sufficient reserves and liquidity for the proper conduct of our business; and

 

•

we can maintain such an increased distribution level for a sustained period.

The amount of “available cash,” which is defined in our limited liability company agreement, will be determined by our board of directors after the completion of the distribution and will be based upon recommendations from our management. Because we believe that we will generally finance any expansion capital expenditures and investment capital expenditures from external financing sources, we believe that our investors are best served by our distributing all of our available cash. In addition, because we are not subject to entity-level U.S. federal income tax as a partnership, we have more cash to distribute to you than would be the case if we were subject to U.S. federal income tax. Our cash distribution policy is consistent with the terms of our limited liability company agreement, which requires that we distribute all of our available cash.

The board of directors intends to adopt a cash distribution policy that will require, pursuant to our amended and restated limited liability company agreement, that we distribute all of our available cash quarterly to our unitholders within 50 days following the end of each calendar quarter in accordance with their respective percentage interests. Our cash distribution policy will be consistent with the terms of our limited liability company agreement. Under our limited liability company agreement, available cash will be defined to mean generally, for each fiscal quarter, all cash on hand at the date of determination of available cash in respect of such quarter, less the amount of cash reserves established by our board of directors, which will not be subject to a cap, to:

 

•

comply with applicable law;

 

•

comply with any agreement binding upon us or our subsidiaries (exclusive of ARP and Lightfoot and their respective subsidiaries);

 

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•

provide for future capital expenditures, debt service and other credit needs as well as any federal, state, provincial or other income tax that may affect us in the future; or

 

•

otherwise provide for the proper conduct of our business.

These reserves will not be restricted by magnitude, but only by type of future cash requirements with which they can be associated. Our available cash will also include cash on hand resulting from borrowings made after the end of the quarter. When our board of directors determines our quarterly distributions, it will consider current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level. Our distributions to limited partners will not be cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter, our unitholders will not be entitled to receive such payments in the future.

Restrictions and Limitations on Our Cash Distribution Policy

While our cash distribution policy, consistent with the terms of our limited liability company agreement, will require that we distribute all of our available cash quarterly, our cash distribution policy will be subject to the following restrictions and limitations and may be changed at any time, including in the following ways:

 

•

We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including increases in our general and administrative expenses, principal or interest payments on our future outstanding debt, elimination of future distributions from ARP, the effect of working capital requirements and anticipated cash needs of us or ARP.

 

•

Our cash distribution policy will be, and ARP’s cash distribution policy is, subject to restrictions on distributions under any credit facility we enter into and under ARP’s credit facilities, respectively, such as material financial tests and covenants and limitations on paying distributions during an event of default.

 

•

Our board of directors will have the authority under our amended and restated limited liability company agreement to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders. The establishment of those reserves could result in a reduction in future cash distributions to our unitholders pursuant to our stated cash distribution policy.

 

•

Our limited liability company agreement, including the cash distribution policy contained therein, may be amended by a vote of the holders of a majority of our common units.

 

•

Even if our cash distribution policy is not amended, modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our board of directors, taking into consideration the terms of our limited liability company agreement.

 

•

We can issue additional units, including units that are senior to the common units, without the consent of our unitholders, subject to existing NYSE listing rules, and these additional units would dilute common unitholders’ ownership interests.

 

•

Under Section 18-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

Because of these restrictions and limitations and our ability to change our cash distribution policy, we may not have available cash to distribute to our unitholders, and there is no guarantee that our unitholders will receive quarterly distributions from us.

Our Cash Distribution Policy Will Limit Our Ability to Grow

Because we will distribute our available cash rather than reinvesting it in our business, our growth may not be as significant as businesses that reinvest their available cash to expand ongoing operations. Because our primary cash-generating assets currently consist of our partnership interests in ARP, including incentive

 

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distribution rights, our growth initially will be dependent upon ARP’s ability to increase its quarterly distribution per unit. If we issue additional common units or incur debt to fund acquisitions, and expansion and investment capital expenditures, the payment of distributions on those additional units or interest on that debt could increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our limited liability company agreement on our ability to issue additional units, including units ranking senior to the common units, although existing NYSE listing rules requires unitholder approval for us to issue common units in excess of 20% of our common units then outstanding (or senior units convertible into such common units).

ARP’s Ability to Grow is Dependent on its Ability to Access External Growth Capital

Consistent with the terms of its partnership agreement, ARP has distributed to its partners most of the cash generated by its operations. This has required it to rely upon external financing sources, such as commercial borrowings and other debt and equity issuances, to fund its acquisition and growth capital expenditures. If ARP is unable to finance growth externally, its cash distribution policy will significantly impair its ability to grow. If ARP issues additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that ARP will be unable to maintain or increase its per unit distribution level, which in turn may affect the available cash that we have to distribute to our unitholders. The incurrence of additional commercial or other debt to finance ARP’s growth strategy would result in increased interest expense to ARP, which in turn may affect the available cash that we have to distribute to our unitholders.

Distributions of Cash Upon Liquidation

If we dissolve in accordance with our limited liability company agreement, we will sell or otherwise dispose of our assets in a process called a liquidation. We will first apply the proceeds of liquidation to the payment of our creditors in the order of priority provided in our limited liability company agreement and by law and, thereafter, we will distribute any remaining proceeds to the unitholders in accordance with their respective capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

Adjustments to Capital Accounts

We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the unitholders’ capital account balances equaling the amount that they would have been if no earlier positive adjustments to the capital accounts had been made.

Our Initial Quarterly Distribution Rate

New Atlas believes, based on the assumptions and considerations discussed in the section entitled “Cash Distribution Policy—Estimated Initial Cash Available for Distribution” beginning on page 79, that upon completion of the distribution of the New Atlas common units, New Atlas’s initial quarterly distribution will, subject to proration as described below, be equal to $0.55 per common unit, or $2.20 per common unit on an annualized basis. This equates to an aggregate cash distribution of approximately $14.4 million per quarter, or approximately $57.8 million per year. New Atlas’s ability to make cash distributions at the initial distribution rate will be subject to the factors described in the section entitled “Cash Distribution Policy—General— Restrictions and Limitations on Our Cash Distribution Policy” beginning on page 77. We cannot assure you that any distributions will be declared or paid by us, and there is no guarantee of distributions at a particular level or

 

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of any distributions being made. We did not use quarterly estimates in concluding that there would be sufficient distributable cash flow to pay the initial quarterly distributions on our common units for the year ending December 31, 2015. We did not use quarterly estimates in concluding that there would be sufficient distributable cash flow to pay the initial quarterly distributions on our common units for the year ending December 31, 2015. For more information, see the section entitled “Cash Distribution Policy—General—Restrictions and Limitations on Our Cash Distribution Policy” beginning on page 77.

We expect to pay a prorated cash distribution for the first quarter that we are a publicly traded company. This prorated cash distribution will be paid for the period beginning on the distribution date for the New Atlas common units and ending on the last day of that fiscal quarter. Any cash distributions received by New Atlas from Atlas Resource Partners related to the period beginning on the date of the most recent cash distribution to the Atlas Energy unitholders prior to the distribution date for the New Atlas common units and ending on such distribution date will be included in this prorated cash distribution.

The following table sets forth the estimated aggregate distribution amounts payable on our common units during the year following the completion of the distribution of the New Atlas common units at our initial distribution rate of $0.55 per common unit (or $2.20 per common unit on an annualized basis).

 

						Initial Quarterly Distribution
		Number of Units				One Quarter				Four Quarters
Common units			26,250,000			$	14,437,500			$	57,750,000

Our cash distributions will not be cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter, including those at the anticipated initial quarterly distribution rate, our common unitholders will not be entitled to receive that quarter’s payments in the future.

Overview of Presentation

In the sections that follow, we present the basis for our belief that we will be able to pay our initial quarterly distribution of $0.55 per common unit for each quarter during the year ending December 31, 2015. In those sections, we present:

 

•

Our “Estimated Initial Cash Available for Distribution” in which we present our estimated Adjusted EBITDA necessary for us to have sufficient cash available for distribution to pay distributions at the initial quarterly distribution rate on all the outstanding common units for each quarter for the year ending December 31, 2015.

 

•

Our “Unaudited Pro Forma Cash Available for Distribution,” in which we present the amount of pro forma available cash we would have had available for distribution to our unitholders in the twelve months ended September 30, 2014 and December 31, 2013, based on our pro forma financial statements included elsewhere in this information statement. Our calculation of pro forma available cash in this table should only be viewed as a general indication of the amount of available cash that we might have generated had we been formed in an earlier period.

Estimated Initial Cash Available for Distribution

We forecast that our estimated initial cash available for distribution for the year ending December 31, 2015 will be approximately $62.2 million. This amount would exceed the amount of cash available for distribution we must generate to support the payment of the initial quarterly distributions for four quarters on our common units outstanding immediately after the distribution date by $2.8 million for the year ending December 31, 2015. The number of outstanding units on which we have based our estimate does not include any common units that may be issued under the long-term incentive plan that we will adopt prior to the closing of the distribution.

 

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We do not as a matter of course make public projections of financial information. Our forecast information below presents, to our best knowledge and belief, our expected results of operations and cash flows for the year ending December 31, 2015. Our forecast financial information reflects our judgment as of the date of this information statement of conditions we expect to exist and the course of action we expect to take during the year ending December 31, 2015. Please read below under the section entitled “Cash Distribution Policy—Significant Forecast Assumptions” for further information as to the significant assumptions we have made for the financial forecast. There will likely be differences between our forecast and actual results, and those differences could be material.

Our forecast financial information is a forward-looking statement and should be read together with the historical and pro forma financial statements and the accompanying notes included elsewhere in this information statement and together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 113. This forecast was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions on which we base our belief that we can generate sufficient distributable cash flow on an annual basis to pay the full initial quarterly distributions on our common units for the year ending December 31, 2015. We did not use quarterly estimates in concluding that there would be sufficient distributable cash flow to pay the initial quarterly distributions on our common units for the year ending December 31, 2015. Historically, our distributable cash flow has varied significantly on a quarterly basis as a result of seasonal changes and other factors. For more information regarding these factors, please read “Risk Factors—Risks Relating to Our Business.” As a result of the quarterly seasonal and other variations in our distributable cash flow and the inherent difficulty in projecting the precise timing of revenue and expenses, we believe that any estimate of our quarterly distributable cash flow would involve a high degree of potential inaccuracy. To the extent that there is a shortfall of quarterly distributable cash flow compared with the initial quarterly distributions on our common units during the year ending December 31, 2015, we believe we will be able to utilize cash on hand or borrowings under any credit facility we enter into to fund the shortfall, with such amounts replenished in subsequent quarters.

The prospective financial information included in this information statement has been prepared by, and is the responsibility of, our management. Grant Thornton LLP has neither compiled nor performed any procedures with respect to the accompanying prospective financial information and, accordingly, Grant Thornton LLP does not express an opinion or any other form of assurance with respect thereto. The Grant Thornton LLP report included in this information statement relates to our historical financial information. It does not extend to the prospective financial information and should not be read to do so.

When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this information statement, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate our estimated distributable cash flow.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the forecast or to update this forecast to reflect events or circumstances after the date of this information statement. Therefore, you are cautioned not to place undue reliance on this prospective financial information.

 

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New Atlas

Estimated Cash Available for Distribution⁽¹⁾

 

		Year Ending December 31, 2015
Atlas Resource Partners, L.P.
Revenues:
Gas and oil production		$	539,500
Well construction and completion			307,400
Administration and oversight			22,100
Well services			27,400
Gathering and processing			8,600
Other			100
Total revenues			905,100
Costs and Expenses:
Gas and oil production			203,800
Well construction and completion			267,300
Well services			10,400
Gathering and processing			10,400
General and administrative expense			45,900
Depreciation, depletion and amortization			233,200
Total costs and expenses			771,000
Operating income			134,100
Interest expense			(82,125	)
Net income			51,975
Preferred limited partner dividends			(19,000	)
Net income attributable to common limited partners and the general partner		$	32,975
Plus:
Preferred limited partner dividends			19,000
Interest expense			82,125
Depreciation, depletion and amortization			233,200
EBITDA			367,300
Plus: Non-cash stock compensation expense			18,000
Adjusted EBITDA			385,300
Less: Interest expense			(82,125	)
Less: Preferred limited partner dividends			(19,000	)
Plus: Amortization of deferred finance costs			12,075
Less: Expansion capital expenditures			139,700
Plus: Financing for expansion capital expenditures			(139,700	)
Less: Maintenance capital expenditures			(67,400	)
Distributable cash flow attributable to common limited partners and the general partner		$	228,850
Cash Distributions(2):
Common limited partner units owned by 3rd parties		$	149,700
Common limited partner units owned by New Atlas			49,600
Total cash distributions to common limited partner units			199,300
Incentive distribution rights and general partner 2% interest			16,500
Total cash distributions		$	215,800
Per limited partner unit		$	2.36

 

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		Year Ending December 31, 2015
New Atlas cash distributions and dividends
Common limited partner units owned by New Atlas		$	49,600
Incentive distribution rights and general partner 2% interest			16,500
Preferred limited partner dividends			8,800
Total cash distributions/dividends to New Atlas		$	74,900
Excess of distributable cash flow after cash distributions		$	13,050
New Atlas
Revenues:
Atlas Resource Partners, L.P. revenue		$	905,100
Development Subsidiary revenue			56,600
Direct gas and oil production			13,475
Other			1,725
Total revenues			976,900
Costs and Expenses:
Atlas Resource Partners, L.P. costs and expenses			771,000
Development Subsidiary costs and expenses			26,300
Direct gas and oil production			6,200
General and administrative expense			9,050
Depreciation, depletion and amortization			5,500
Total costs and expenses			818,050
Operating income			158,850
Atlas Resource Partners, L.P. interest expense			(82,025	)
Interest expense			(17,150	)
Net income		$	59,675
Plus:
Atlas Resource Partners, L.P. interest expense			82,025
Interest expense			17,150
Depreciation, depletion and amortization			5,500
EBITDA			164,350
Less: Atlas Resource Partners, L.P. operating income			(134,100	)
Plus: Atlas Resource Partners, L.P. cash distributions			74,900
Less: Development Subsidiary operating income			(30,300	)
Plus: Development Subsidiary cash distributions and fees earned			3,000
Adjusted EBITDA			77,850
Less: Interest expense			(17,150	)
Plus: Amortization of deferred finance costs			1,400
Less: Maintenance capital expenditures			(1,600	)
Distributable cash flow		$	60,500
Cash distributions:
Initial distribution per common unit		$	2.20
Common units outstanding			26,250
Aggregate initial distributions to common unitholders		$	57,750
Excess of distributable cash flow after cash distributions		$	2,750

 

(1)	Amounts may not recalculate due to rounding.

(2)	These amounts assume an average of 84.4 million ARP common limited partner units outstanding for the period.

 

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Significant Forecast Assumptions

The forecast has been prepared by and is the responsibility of management. The forecast reflects management’s judgment as of the date of this information statement of conditions we expect to exist and the course of action we expect to take during the year ending December 31, 2015. While the assumptions discussed below are not all-inclusive, they include those that we believe are material to our forecasted results of operations, and any assumptions not discussed below were not deemed to be material. We believe we have a reasonable, objective basis for these assumptions. We believe our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. There will likely be differences between our forecast and our actual results and those differences could be material. If the forecasted results are not achieved, we may not be able to make cash distributions on our common units at the quarterly distribution rate.

Atlas Resource Partners, L.P. Significant Forecast Assumptions

Our cash flow is currently generated principally from cash distributions we receive from ARP. For the year ending December 31, 2015, we have forecasted that ARP will generate operating income of $134.1 million, or approximately 84% of our $158.9 million of operating income for the period. In addition, we have forecasted that ARP will pay us $74.9 million of cash distributions for the year ending December 31, 2015, or approximately 96% of our $77.9 million of Adjusted EBITDA for the period. As such, we have reflected in the table below the significant forecast assumptions for ARP’s operations, revenues and expenses for the year ending December 31, 2015:

 

						Historical
		Year Ending December 31, 2015				Twelve Months Ended September 30, 2014				Year Ended December 31, 2013
Revenues:
Gas and oil production key assumptions:
Wells initiated:
Gross			133				126				103
Net(1)			53				69				66
Wells connected:
Gross			144				124				117
Net(1)			58				74				80
Net production volume per day:
Natural gas (mcfd)			221,443				226,948				158,886
Crude oil (bpd)			7,179				2,421				1,329
NGL (bpd)			4,408				3,683				3,473
Total (mcfed)			290,964				263,577				187,701
Average sales prices:
Natural Gas (per Mcf):
Total realized price, after hedges		$	3.74			$	3.75			$	3.47
Total realized price, before hedges		$	3.22			$	3.84			$	3.25
Hedge percentage (on production volume)			72	%			77	%			79	%
Basis and btu differentials included in pricing		$	(0.31	)		$	(0.41	)		$	(0.37	)
Crude oil (per Bbl):
Total realized price, after hedges		$	78.15			$	89.83			$	91.01
Total realized price, before hedges		$	62.72			$	93.55			$	95.88
Hedge percentage (on production volume)			68	%			91	%			100	%
Basis differentials included in pricing		$	(5.00	)		$	(5.11	)		$	(2.04	)

 

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						Historical
		Year Ending December 31, 2015				Twelve Months Ended September 30, 2014				Year Ended December 31, 2013
NGL (per Bbl):
Total realized price, after hedges		$	22.50			$	30.59			$	28.71
Total realized price, before hedges		$	18.63			$	32.13			$	29.43
Hedge percentage (on production volume)			26	%			38	%			18	%
Partnership management key assumptions:
Partnership management funds raised (in millions)		$	275.0			$	155.6			$	150.0
Partnership management wells initiated			97				101				75
Well construction and completion cost mark-up			15	%			15	%			15	%
Administration and oversight—fee per well initiated			$100,000 to $500,000				$100,000 to $400,000				$100,000 to $400,000
Administration and oversight fee per well per month		$	75			$	75			$	75
Gross well services per well fee			$100 to $2,000				$100 to $2,000				$100 to $2,000
Expenses:
Gas and oil production key assumptions:
Production costs (per Mcfe):
Lease operating expenses		$	1.43			$	1.21			$	1.09
Production taxes			0.27				0.25				0.18
Transportation and compression			0.25				0.26				0.24
Total		$	1.94			$	1.73			$	1.50

 

(1)	Includes (i) ARP’s percentage interest in the wells in which it has a direct ownership interest and (ii) its percentage interest in the wells based on its percentage ownership in the drilling partnerships.

Gas and oil production revenue. ARP’s forecasted natural gas and oil production volumes, net to its equity interest in the production of its investment partnerships and including its direct interests in producing wells, for the year ending December 31, 2015 assumes that currently producing wells will produce at the rates forecasted in its December 31, 2013 reserve report, and have been adjusted for current well performance and acquisition activity. The forecasted production volumes also include new production from an estimated 144 additional gross wells (58 net wells) ARP projects to connect during the year ending December 31, 2015, consisting of (i) 107 gross wells (34 net wells) which ARP intends to drill and connect on behalf of its investment partnerships and (ii) 37 gross direct interest wells (24 net wells), both of which ARP assumes will produce at rates consistent with wells of similar characteristics contained in its December 31, 2013 reserve report, adjusted for current well performance. ARP has assumed no significant interruptions of production volumes due to mechanical issues such as compressor breakdowns and sales line maintenance. Further, ARP has assumed no significant logistical issues related to new well hookups, such as delays in pipeline construction, permitting and right-of-ways which it primarily depends on gathering system service providers to complete.

Of the 133 additional wells that ARP projects to be initiated during the year ending December 31, 2015, 98 of the wells were recognized as proved, undeveloped locations at December 31, 2013, with total estimated reserves of 97 Bcfe. At the present time, ARP has no new information to adjust its reserve estimates for these wells and, as such, expect to convert 97 Bcfe of estimated reserves from proved undeveloped reserves to proved developed reserves. These wells are estimated to be connected at various dates through 2015, subject to change due to factors including operational issues and weather, and ARP estimates that these 98 wells will produce an aggregate gross production of 9 Bcfe (3 Bcfe net production) during the year ending December 31, 2015, subject to business plan changes, market factors and operational factors. The remaining 35 wells that ARP projects to

 

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initiate during the year ending December 31, 2015 are primarily related to projected drilling activities in Eagle Ford Shale, an acquisition which ARP completed in November 2014, and the Marcellus Shale, of which certain proved undeveloped locations were created through developmental drilling during the nine months ended September 30, 2014.

The 75.9 MMcfed increase in overall production from 187.7 MMcfed for the year ended December 31, 2013 to 263.6 MMcfed for the twelve months ended September 30, 2014 was principally due to partial year contributions from the EP Energy assets, which were acquired in July 2013, the GeoMet assets, which were acquired in April 2014, and the Rangely assets, which were acquired in June 2014, as well as production increases from new drilling, partially offset from natural production declines in other wells. The 27.4 MMcfed increase in overall production from 263.6 MMcfed for the twelve months ended September 30, 2014 to 291.0 MMcfed for the year ending December 31, 2015 is principally due to production from the Eagle Ford Shale assets, which ARP acquired in November 2014, and a full year of production from the acquisitions of the GeoMet and Rangely assets as well as production increases from new drilling, partially offset from natural production declines in other wells.

ARP’s forecasted commodity prices for the year ending December 31, 2015 were based upon average forward prices as of December 4, 2014, with natural gas and crude oil based upon prices quoted on the New York Mercantile Exchange, or NYMEX, and NGLs based upon Mont Belvieu, as quoted by the Oil Price Information Service, or OPIS, for a composite barrel, each on a first-day-of-the-month price. The actual prices that ARP realize for these commodities reflect various adjustments to the applicable NYMEX- and OPIS-based prices due to transportation, quality and regional price differentials, as well as the effect of ARP’s commodity price hedges. ARP’s forecasted estimated commodity prices are principally based on NYMEX and OPIS forward prices for the applicable commodities, but adjusted to take into account third-party market analysis and management’s own judgment.

ARP gas and oil production revenue for the year ending December 31, 2015 includes a $5.1 million reduction for the estimated impact of subordination of its production revenue to investor partners within its investment partnerships, compared with $12.0 million for the twelve months ended September 30, 2014 and $15.2 million for the year ended December 31, 2013. ARP’s decrease in the subordination of production revenue to investor partners within its investment partnerships between the year ending December 31, 2015 and the twelve months ended September 30, 2014 and the year ended December 31, 2013 is due primarily to improved performance of certain programs and other programs concluding their subordination period.

Gas and oil production costs and expenses. ARP’s estimated total natural gas and oil production costs and expenses consist of its equity interest in the production costs and expenses of its investment partnerships and as well as the production costs and expenses associated with its direct interests in producing wells. ARP’s lease operating expenses are comprised primarily of direct labor costs, repair and maintenance costs, and production materials. ARP total estimated production costs per mcfe for the year ending December 31, 2015 are $1.94 per mcfe, compared with $1.72 per mcfe for the twelve months ended September 30, 2014 and $1.50 per mcfe for the year ended December 31, 2013. The increase between the periods is primarily due to an increase in crude oil production volumes as a percentage of total production volumes. ARP’s production costs and expenses have a significant fixed cost component, such as labor and repair and maintenance costs, that cause increases in crude oil and NGL volumes, which generate fewer hydrocarbon production units than natural gas, to result in an increase in production costs per mcfe as oil and NGL volumes increase as a percentage of total volumes.

ARP gas and oil production costs and expenses for the year ending December 31, 2015 includes a $2.4 million reduction for the estimated impact of its proportionate share of lease operating expenses associated with the subordination of its production revenue to investor partners within its investment partnerships, compared with $4.2 million for the twelve months ended September 30, 2014 and $5.6 million for the year ended December 31, 2013. ARP’s decrease in the proportionate share of lease operating expenses associated with the subordination of its production revenue between the year ending December 31, 2015 and the twelve months ended September 30, 2014 and the year ended December 31, 2013 is due primarily to improved performance of certain programs and other programs concluding their subordination period.

 

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Partnership management revenue and costs and expenses. ARP has estimated that it will raise approximately $275.0 million through its investment partnerships during the year ending December 31, 2015 and that its equity interest in such partnerships will be approximately 28.5%. ARP also estimated that it will raise approximately $225.0 million through its investment partnerships during the year ending December 31, 2014, and that its equity interest in such partnerships will be approximately 32.6%.

For the administration and oversight monthly fee for each investment partnership well of $75, ARP has estimated that it will charge the fee on approximately 4,625 investment partnership wells for the year ending December 31, 2015. For the well services monthly fee for each operated investment partnership well of $100 to $2,000, ARP has estimated that it will charge the fee on approximately 4,925 investment partnership wells for the year ending December 31, 2015. Well services revenue also includes fees for services ARP personnel perform on investment partnership wells. ARP estimates that its well services profit margin will be approximately 62% for the year ending December 31, 2015, compared with 57% for the twelve months ended September 30, 2014 and 51% for the year ended December 31, 2013. The increase in profit margin between these periods is primarily due to an increase in service fees charged to investment partnership wells for ARP’s salt water gathering and disposal systems in the Mississippi Lime and Marble Falls areas, which generally have lower ongoing operating and maintenance costs as a percentage of service fees charged than other well service fees.

General and administrative expense. ARP has forecasted general and administrative expense of $45.9 million for the year ending December 31, 2015, as compared with $65.2 million for the twelve months ended September 30, 2014 and $78.1 million for the year ended December 31, 2013. The decrease in general and administrative expense between the forecasted year ending December 31, 2015 and the twelve month periods ended September 30, 2014 and December 31, 2013 is due primarily to costs incurred during the historical periods related to consummated acquisitions, including the EP Energy assets in July 2013, the GeoMet assets in April 2014, and the Rangely assets in June 2014. ARP did not include any consummated acquisitions in its forecast for the year ending December 31, 2015.

Interest expense. ARP has estimated that its interest expense for the year ending December 31, 2015 will be approximately $82.1 million, compared with $55.2 million for the twelve months ended September 30, 2014 and $34.3 million for the year ended December 31, 2013. The increase in interest expense between these periods is primarily due to a full year of interest expense on borrowings under ARP’s senior secured credit facility and senior notes that were utilized to fund its historical capital expenditures and acquisitions, including the EP Energy assets in July 2013, the GeoMet assets in April 2014, and the Rangely assets in June 2013, as well as the Eagle Ford Shale assets, which ARP acquired in November 2014. ARP’s estimate of interest expense for the year ending December 31, 2015 is based upon the following significant assumptions:

 

•

$700.0 million of senior notes outstanding with a weighted average interest rate of 8.4%;

 

•

approximately $760.0 million of weighted average borrowings outstanding on ARP’s senior secured credit facility, including borrowings to fund forecasted capital expenditures for the year ending December 31, 2015, at a weighted average interest rate of 2.6%, which is based upon an estimated London Interbank Offer Rate (also referred to as “LIBOR”) of 0.6%. ARP’s weighted LIBOR for the historical nine months ended September 30, 2014 was 0.2%;

 

•

approximately $10.0 million of capitalized interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use; and

 

•

approximately $1.2 million of commitment fees for the unused portion of ARP’s senior secured credit facility.

Preferred dividends. ARP has estimated that it will pay $19.0 million of preferred limited partner dividends for the year ending December 31, 2015, based upon an average of 3,665,000 units outstanding of its 8.625% Class D cumulative redeemable perpetual preferred units, 3,749,986 units outstanding of its Class C convertible preferred units at the same quarterly distribution rate to its common units, and 3,836,554 units outstanding of its

 

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Class B convertible preferred units at the same quarterly distribution rate to its common units. The Class B convertible preferred units are mandatorily convertible into an equivalent number common units on July 25, 2015.

Maintenance capital expenditures. Oil and gas assets naturally decline in future periods and, as such, ARP recognizes the estimated capitalized cost of stemming such decline in production margin for the purpose of stabilizing its cash available for distribution and cash distributions, which it refers to as maintenance capital expenditures. ARP calculates the estimate of maintenance capital expenditures by first multiplying its forecasted future full year production margin by its expected aggregate production decline of proved developed producing wells. Maintenance capital expenditures are then the estimated capitalized cost of wells that will generate an estimated first year margin equivalent to the production margin decline, assuming such wells are connected on the first day of the calendar year. ARP does not incur specific capital expenditures expressly for the purpose of maintaining or increasing production margin, but such amounts are a hypothetical subset of wells it expects to drill in future periods, including Marcellus Shale, Utica Shale, Mississippi Lime and Marble Falls wells, on undeveloped acreage already leased. Estimated capitalized cost of wells included within maintenance capital expenditures are also based upon relevant factors, including utilization of public forward commodity exchange prices, current estimates for regional pricing differentials, estimated labor and material rates and other production costs. ARP’s estimated maintenance capital expenditures for the year ending December 31, 2015 of $67.4 million, compared with $44.8 million and $28.2 million for the twelve month periods ended September 30, 2014 and December 31, 2013, respectively, are the sum of the estimate calculated the year ending December 31, 2014 plus estimates for the decline in production margin from new wells connected during the year ending December 31, 2015.

Expansion capital expenditures. ARP considers expansion capital expenditures to be any capital expenditure costs expended that are not maintenance capital expenditures—generally, this will include expenditures to increase, rather than maintain, production margin in future periods, as well as land, gathering and processing, and other non-drilling capital expenditures. ARP has estimated that it will incur $139.7 million of expansion capital expenditures for the year ending December 31, 2015, compared with $153.2 million and $232.0 million for the twelve month periods ended September 30, 2014 and December 31, 2013, respectively, primarily to drill direct interest and investment partnership wells. ARP expects its expansion capital expenditures to be funded through borrowings under its senior secured credit facility.

 

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New Atlas Significant Forecast Assumptions

We have reflected in the table below our significant forecast assumptions, other than for ARP’s operations, revenues and expenses previously detailed, for the year ending December 31, 2015:

 

						Historical
		Year Ending December 31, 2015				Twelve Months Ended September 30, 2014				Year Ended December 31, 2013
Revenues:
New Atlas direct natural gas production key assumptions:
Net natural gas production volume per day (mcfd)(1)			9,484				11,652				12,130
Total realized price, after hedges		$	3.89			$	3.84			$	3.68
Total realized price, before hedges		$	3.39			$	3.94			$	3.41
Hedge percentage (on production volume)			66	%			66	%			81	%
Basis and btu differentials included in pricing		$	(0.15	)		$	(0.36	)		$	(0.16	)
Development Subsidiary gas and oil production key assumptions:
Net production volume per day:
Natural gas (mcfd)			1,347				511				21
Crude oil (bpd)			2,316				97				7
NGL (bpd)			220				66				3
Total (mcfed)			16,561				1,491				79
Average sales prices:
Natural Gas realized price (per Mcf)		$	3.37			$	4.20			$	3.63
Crude oil realized price (per Bbl)		$	62.92			$	93.50			$	93.16
NGL realized price (per Bbl)		$	22.05			$	31.58			$	34.88
Expenses:
New Atlas direct natural gas production key assumptions:
Production costs (per Mcfe)		$	1.80			$	1.47			$	1.54
Development Subsidiary gas and oil production key assumptions:
Production costs (per Mcfe)		$	1.26			$	3.00			$	2.77

 

(1)

The historical data for the twelve month periods ended September 30, 2014 and December 31, 2013 reflect production volume from July 31, 2013, the date of acquisition, through the end of the respective period, and are reflected on a per day basis based upon the number of days in the period from the acquisition date.

New Atlas direct natural gas production revenue. Our forecasted direct net natural gas production volumes for the year ending December 31, 2015 assumes that currently producing wells will produce at the rates forecasted in Atlas Energy’s December 31, 2013 reserve report, and have been adjusted for current well performance. The forecasted production volume does not include production from any new wells drilled and connected during the year ending December 31, 2015. We have assumed no significant interruptions of production volumes due to mechanical issues such as compressor breakdowns and sales line maintenance.

Our forecasted natural gas price for the year ending December 31, 2015 was based upon the average forward prices as of December 4, 2014, which was based upon prices quoted on NYMEX on a first-day-of-the-month price. The actual prices that we realize for natural gas reflect various adjustments to the NYMEX-based price due to regional price differentials, as well as the effect of our commodity price hedges. Our forecasted estimated commodity prices are principally based on NYMEX forward prices, but adjusted to take into account third-party market analysis and management’s own judgment.

 

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New Atlas direct natural gas production costs and expenses. Our production costs and expenses primarily consist of direct labor costs, repair and maintenance costs, production materials, transportation costs and severance taxes.

General and administrative expense. We have forecasted general and administrative expense of $9.1 million for the year ending December 31, 2015, as compared with $7.4 million and $7.6 million for the twelve month periods ended September 30, 2014 and December 31, 2013, respectively.

Interest expense. In accordance with the Atlas merger agreement and the separation and distribution agreement, prior to the distribution, New Atlas will enter into one or more financing arrangements pursuant to which it will transfer $150.0 million to Atlas Energy as a cash distribution. Atlas Energy will use this cash distribution as well as a payment due from Targa Resources under the Atlas merger agreement to repay Atlas Energy’s outstanding indebtedness at or prior to the effective time of the distribution. For more information, see the section entitled “Certain Relationships and Related Party Transactions—Separation and Distribution Agreement—Cash Transfers.” New Atlas currently expects to enter into a term loan similar to Atlas Energy’s currently outstanding term loan to effect these financing arrangements. We have therefore assumed that we will issue a term loan of approximately $155.0 million, with net proceeds received of approximately $150.0 million, at an interest rate of 10.0% for the year ending December 31, 2015. As such, we have estimated interest expense for the year ending December 31, 2015 of $17.2 million, compared with $11.3 million and $5.4 million of interest expense for the twelve month periods ended September 30, 2014 and December 31, 2013, respectively, which reflect the allocation of interest expense associated with Atlas Energy’s term loan for those historical periods prior to the separation and distribution. The increase in interest expense between the twelve months ended September 30, 2014 and the year ended December 31, 2013 is primarily due to a full year of interest expense on ATLS term loan, which was issued in July 2013.

In preparing the estimates, we and ARP have assumed that there will be no material change in the following matters, and thus they will have no impact on our cash available for distribution:

 

•

There will not be any material expenditures related to new federal, state or local regulations in the areas where we and ARP operate;

 

•

There will not be any material change in the natural gas and oil industry or in market, regulatory and general economic conditions that would affect our cash flow;

 

•

We and ARP will not undertake any extraordinary transactions that would materially affect our or ARP’s cash flow; and

 

•

There will be no material nonperformance or credit-related defaults by suppliers, customers or vendors.

While we and ARP believe that the assumptions we used in preparing the estimates set forth above are reasonable based upon management’s current expectations concerning future events, they are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties, including those described in “Risk Factors” elsewhere in this information statement that could cause actual results to differ materially from those we anticipate. If our and ARP assumptions are not realized, the actual available cash that we and ARP generate could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay the initial quarterly distribution or any amount on all of our outstanding units with respect to the four calendar quarters for the year ending December 31, 2015 or thereafter, in which event the market price of the common units may decline materially.

Sensitivity Analysis

Our ability to generate sufficient cash from our operations and cash distributions from ARP to pay cash distributions to our unitholders at the initial quarterly cash distribution rate for the year ending December 31, 2015 is a function of the following primary variables:

 

•

The amount of hydrocarbons we and ARP produce;

 

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•

The price at which we and ARP sell our hydrocarbons; and

 

•

The amount of funds raised from ARP’s investment partnerships.

In the paragraphs below, we discuss the impact that changes in these variables, holding all other variables constant, would have on our ability to generate sufficient cash from our operations, including cash distributions received from ARP, to pay the initial quarterly cash distributions on our outstanding units.

Production volume changes. For purposes of our estimates set forth above, ARP has assumed that its net production is approximately 106.2 Bcfe during the year ending December 31, 2015. If ARP’s actual net production realized during the year ending December 31, 2015 is 10% more (or 10% less) than such estimate (that is, if actual net realized production is 95.6 Bcfe or 116.8 Bcfe, representing a pro rata change in natural gas, oil and NGLs), we estimate that ARP’s estimated cash available to pay cash distributions would change by approximately $30.0 million. Also, we have assumed that our net production from direct gas and oil production will total 3.5 Bcfe during the year ending December 31, 2015. If our actual net production realized during the year ending December 31, 2015 is 10% (or 10% less) than such estimate (that is, if actual net realized production is 3.1 Bcfe or 3.8 Bcfe), we estimate that our estimated cash available to pay cash distributions would change by approximately $0.7 million.

Commodity price changes. For purposes of our estimates set forth above, ARP has assumed that its weighted average net realized commodity price before hedges for its net production volumes is $3.22 per Mcf for natural gas, $62.72 per barrel for crude oil and $18.63 per barrel for NGLs. If the average realized commodity price for ARP’s net production volumes that are unhedged were to change by 10%, we estimate that ARP’s estimated cash available to pay cash distributions would change by approximately $13.9 million, assuming no changes in any other variables and inclusive of ARP’s commodity derivative contracts. Also, we have assumed that our weighted average net realized natural gas price for our net production volume is $3.39 per Mcf for natural gas. If the average realized natural gas price for our net production volume that is unhedged were to change by 10%, we estimate that our estimated cash available to pay distributions would change by approximately $0.4 million, assuming no changes in any other variables and inclusive of our commodity derivative contracts.

Funds raised changes. For purposes of our estimates set forth above, ARP has assumed funds raised from its investment partnerships will total $275.0 million during the year ending December 31, 2015. If actual funds raised during such period are 10% more or less than our estimate, we estimate that our estimated cash available for distribution change by approximately $5.5 million.

Unaudited Pro Forma Available Cash for Distribution

On a pro forma basis, assuming the distribution of the New Atlas common units contemplated in this information statement occurred on July 1, 2013 for the twelve months ended September 30, 2014 and on January 1, 2013 for the year ended December 31, 2013, our cash available for distribution for the twelve months ended September 30, 2014 and the year ended December 31, 2013 would have been $64.4 million and $62.2 million, respectively. The amount of cash available for distribution we must generate to support the payment of our initial quarterly distributions for four quarters on our common units outstanding immediately after the distribution date for the New Atlas common units is $57.8 million (or an average of approximately $14.4 million per quarter). As a result, we would have had sufficient distributable cash flow to pay the full initial quarterly distributions on our common units for the twelve months ended September 30, 2014 and the year ended December 31, 2013.

On a pro forma basis, ARP’s cash available for distribution for the twelve months ended September 30, 2014 and the year ended December 31, 2013 would have been $243.1 million and $184.1 million, respectively. The amount of cash available for distribution ARP must generate to support the payment of its pro forma

 

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quarterly distributions on its limited partner units outstanding, the general partner 2% interest and incentive distribution rights for the pro forma twelve month periods ended September 30, 2014 and December 31, 2013 would have been $208.6 million and $208.0 million, respectively (based upon a forecasted cash distribution per limited partner unit of $2.36 for the year ending December 31, 2015, or $0.59 per quarter per limited partner unit). As a result, ARP would have had sufficient distributable cash flow to pay the pro forma quarterly distributions on its common units, general partner 2% interest and incentive distribution rights for the twelve months ended September 30, 2014 by $34.5 million, but insufficient distributable cash flow to pay such amounts for the year ended December 31, 2013 by $23.9 million. The shortfall for the year ended December 31, 2013 is primarily attributable to:

 

•

lower historical cash flows from ARP’s Eagle Ford Shale assets, which were acquired in November 2014 and included as a pro forma adjustment, compared with the cash flows currently supporting ARP’s cash distribution due to increased production volume and well drilling activity during the nine months ended September 30, 2014. See “Business—Gas and Oil Acquisitions” beginning on page 162 for further information; and

 

•

ARP’s forecast for the year ending December 31, 2015 assumes $275.0 million of funds raised from its investment partnerships, compared with $155.6 million and $150.0 million for the twelve month periods ended September 30, 2014 and December 31, 2013, respectively. As such, neither pro forma period includes the fees associated with the deployment of the additional investment partnership funds raised. ARP estimates that it will raise $225.0 million from its investment partnerships for the year ending December 31, 2014.

We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts do not purport to present our results of operations had the distribution of the New Atlas common units contemplated by this information statement actually been completed as of the dates indicated. In addition, the cash available for distributions is primarily a cash accounting concept, while our unaudited pro forma combined historical financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma available cash for distributions only as a general indication of the amount of cash available for distributions that we might have generated had we been formed on the dates indicated.

The following table illustrates, on a pro forma basis, for the twelve months ended September 30, 2014 and the year ended December 31, 2013, the amount of cash that would have been available for distributions to our unitholders assuming in each case that the distribution of the New Atlas common units contemplated by this information statement had been consummated on the dates indicated.

 

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New Atlas

Unaudited Pro Forma Cash Available for Distributions⁽¹⁾

 

		Four Fiscal Quarters Ended September 30, 2014				Year Ended December 31, 2013
Atlas Resource Partners, L.P.
Revenues:
Gas and oil production		$	595,643			$	526,615
Well construction and completion			202,507				167,883
Administration and oversight			15,426				12,277
Well services			23,230				19,492
Gathering and processing			15,324				15,676
Other			476				24
Total revenues			852,606				741,967
Costs and Expenses:
Gas and oil production			208,984				200,513
Well construction and completion			176,093				145,985
Well services			10,031				9,515
Gathering and processing			16,145				18,012
General and administrative expense			48,399				48,140
Depreciation, depletion and amortization			269,169				192,818
Asset impairment			38,014				38,014
Total costs and expenses			766,835				652,997
Operating income			85,771				88,970
Interest expense			(72,076	)			(70,621	)
Loss on asset sales and disposals			(638	)			(987	)
Net income (loss)			13,057				17,362
Preferred limited partner dividends			(24,804	)			(24,804	)
Net loss attributable to common limited partners and the general partner		$	(11,747	)		$	(7,442	)
Plus:
Preferred limited partner dividends			24,804				24,804
Interest expense			72,076				70,621
Depreciation, depletion and amortization			269,169				192,818
Asset impairment			38,014				38,014
EBITDA			392,316				318,815
Plus: Non-cash loss on asset sales and disposals			638				987
Plus: Non-cash stock compensation expense			8,813				12,679
Adjusted EBITDA			401,767				332,481
Less: Interest expense			(72,076	)			(70,621	)
Less: Preferred limited partner dividends			(24,804	)			(24,804	)
Plus: Amortization of deferred finance costs			8,225				7,075
Less: Expansion capital expenditures			153,226				232,037
Plus: Financing for expansion capital expenditures			(153,226	)			(232,037	)
Less: Maintenance capital expenditures			(70,000	)			(60,000	)
Distributable cash flow attributable to common limited partners and the general partner		$	243,112			$	184,131
Pro Forma Cash Distributions(2):
Common limited partner units owned by 3rd parties		$	142,600			$	142,000
Common limited partner units owned by New Atlas			49,500				49,500
Total cash pro forma distributions to common limited partner units			192,100				191,500
Incentive distribution rights and general partner 2% interest			16,500				16,500
Total pro forma cash distributions		$	208,600			$	208,000
Per limited partner unit		$	2.36			$	2.36

 

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		Four Fiscal Quarters Ended September 30, 2014				Year Ended December 31, 2013
Pro Forma New Atlas cash distributions and dividends
Common limited partner units owned by New Atlas		$	49,500			$	49,500
Incentive distribution rights and general partner 2% interest			16,500				16,500
Preferred limited partner dividends			8,800				8,800
Total pro forma cash distributions/dividends to New Atlas		$	74,800			$	74,800
Excess (shortfall) of distributable cash flow after pro forma cash distributions		$	34,512			$	(23,869	)
New Atlas(3)
Revenues:
Atlas Resource Partners, L.P. revenue		$	852,606			$	741,967
Development Subsidiary revenue			4,865				302
Direct gas and oil production			16,318				16,349
Other			1,015				321
Total revenues			874,804				758,939
Costs and Expenses:
Atlas Resource Partners, L.P. costs and expenses			766,835				652,997
Development Subsidiary costs and expenses			10,649				3,945
Direct gas and oil production			6,255				6,561
General and administrative expense			5,618				6,011
Depreciation, depletion and amortization			6,676				5,869
Total costs and expenses			796,033				675,383
Operating income			78,771				83,556
Atlas Resource Partners, L.P. interest expense and loss on asset sale/disposal			(72,714	)			(71,608	)
Interest expense			(16,900	)			(16,900	)
Net loss		$	(10,843	)		$	(4,952	)
Plus:
Atlas Resource Partners, L.P. interest expense and loss on asset sale/disposal			72,714				71,608
Interest expense			16,900				16,900
Depreciation, depletion and amortization			6,676				5,869
EBITDA			85,447				89,425
Less: Atlas Resource Partners, L.P. operating income			(85,770	)			(88,970	)
Plus: Atlas Resource Partners, L.P. cash distributions			74,800				74,800
Less: Development Subsidiary operating income			5,784				3,643
Plus: Development Subsidiary cash distributions and fees earned			414				40
Adjusted EBITDA			80,675				78,938
Less: Interest expense			(16,900	)			(16,900	)
Plus: Amortization of deferred finance costs			1,400				1,400
Less: Maintenance capital expenditures			(1,200	)			(1,200	)
Distributable cash flow		$	63,975			$	62,238
Pro forma cash distributions:
Initial distribution per common unit		$	2.20			$	2.20
Common units outstanding			26,250				26,250
Aggregate pro forma initial distributions to common unitholders		$	57,750			$	57,750
Excess of distributable cash flow after pro forma cash distributions		$	6,225			$	4,488

 

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(1)	Amounts may not recalculate due to rounding.

(2)

Reflects pro forma distributions for the period shown based upon average ARP common limited partner units outstanding of 81.4 million and 81.2 million for the twelve month periods ended September 30, 2014 and December 31, 2013, respectively. Also reflects ARP’s forecasted cash distribution per limited partner unit of $2.36 for the year ending December 31, 2015, or $0.59 per quarter per limited partner unit. Cash distributions per common limited partner unit for the historical twelve month periods ended September 30, 2014 and December 31, 2013 were $2.33 and $2.19, respectively.

(3)

New Atlas’s financial results included within this Unaudited Pro Forma Cash Available for Distribution table have been adjusted from the amounts presented within the Unaudited Pro Forma Combined Financial Data included elsewhere within this information statement to reflect the pro forma results of ARP’s acquisitions of assets from GeoMet, Inc. (“GeoMet”) on May 12, 2014 and in the Eagle Ford Shale on November 5, 2014, as well as New Atlas’s acquisitions of assets from its Arkoma assets on July 25, 2013. Management of ARP and New Atlas determined that each transaction did not meet the Securities and Exchange Commission’s tests of significance when measured at the acquisition date and, as such, audited historical and pro forma financial statements were not prepared for both transactions. Management of New Atlas believes the inclusion of such data, which has been derived from the respective seller’s unaudited financial statements for the periods presented prior to their May 12, 2014, November 5, 2014 and July 25, 2013, respectively, dates of acquisition, provides a reader with a better understanding of New Atlas’s unaudited pro forma available cash for distribution for the periods presented. Management of New Atlas has also reflected pro forma adjustments to its and ARP’s financing of the transactions as well as maintenance capital expenditure assumptions for the pro forma periods. A summary of the pro forma adjustments to reflect the transactions are as follows:

 

		Year ended September 30, 2014
		Unaudited Pro Forma				Arkoma				GeoMet				Eagle Ford Shale				Adjustments				Adjusted Unaudited Pro Forma
Revenues:
Atlas Resource Partners, L.P. revenue		$	745,595			$	—			$	23,333			$	83,678			$	—			$	852,606
Direct gas and oil production			16,318				—				—				—				—				16,318
Development Subsidiary revenue and other			5,880				—				—				—				—				5,880
Total revenues			767,793				—				23,333				83,678				—				874,804
Costs and Expenses:
Atlas Resource Partners, L.P. costs and expenses			710,803				—				16,384				39,648				—				766,835
Development Subsidiary costs and expenses			10,649				—				—				—				—				10,649
Direct gas and oil production			6,255				—				—				—				—				6,255
General and administrative expense			5,695				(77	)			—				—				—				5,618
Depreciation, depletion and amortization			6,676				—				—				—				—				6,676
Total costs and expenses			740,078				(77	)			16,384				39,648				—				796,033
Operating income			27,715				77				6,949				44,030				—				78,771
Atlas Resource Partners, L.P. interest expense and loss on asset sale/disposal			(65,028	)			—				—				(7,686	)			—				(72,714	)
Interest expense			(16,900	)			—				—				—				—				(16,900	)
Net income (loss)		$	(54,213	)		$	77			$	6,949			$	36,344			$	—			$	(10,843	)

 

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		Year ended December 31, 2013
		Unaudited Pro Forma				Arkoma				Geo Met				Eagle Ford Shale				Adjustments				Adjusted Unaudited Pro Forma
Revenues:
Atlas Resource Partners, L.P. revenue		$	664,336			$	—			$	38,209			$	39,422			$	—			$	741,967
Direct gas and oil production			6,821				9,528				—				—				—				16,349
Development Subsidiary revenue and other			623				—				—				—				—				623
Total revenues			671,780				9,528				38,209				39,422				—				758,939
Costs and Expenses:
Atlas Resource Partners, L.P. costs and expenses			602,564				—				31,388				19,046				—				652,998
Development Subsidiary costs and expenses			3,945				—				—				—				—				3,945
Direct gas and oil production			2,861				3,700				—				—				—				6,561
General and administrative expense			8,162				(2,151	)			—				—				—				6,011
Depreciation, depletion and amortization			3,020				2,849				—				—				—				5,869
Total costs and expenses			620,552				4,398				31,388				19,046				—				675,384
Operating income			51,228				5,130				6,821				20,376				—				83,555
Atlas Resource Partners, L.P. interest expense and loss on asset sale/disposal			(63,921	)			—				—				(7,686	)			—				(71,607	)
Interest expense			(16,900	)			—				—				—				—				(16,900	)
Net income (loss)		$	(29,593	)		$	5,130			$	6,821			$	12,690			$	—			$	(4,952	)

ARP’s Cash Distribution Policy

Minimum Quarterly Distributions

ARP currently intends to distribute to the holders of its common units, Class B preferred units and general partner Class A units at least a minimum quarterly distribution of $0.40 per unit, or $1.60 per unit per year, to holders of its Class C preferred units $0.51 per unit per quarter, or $2.04 per unit per year and to holders of its Class D preferred units a guaranteed payment of $0.54 per unit per quarter, or $2.16 per unit per year, representing the Class D preferred units’ stated distribution rate of 8.625%, to the extent ARP has sufficient available cash after it establishes appropriate reserves and pay fees and expenses, including payments to its general partner in reimbursement of costs and expenses it incurs on ARP’s behalf. ARP’s minimum quarterly distribution is intended to reflect the level of cash that it expects to be available for distribution per common unit, preferred unit and general partner Class A unit each quarter. There is no guarantee that ARP will pay the minimum quarterly distribution, or any distribution, in any quarter, and ARP will be prohibited from making any distributions to unitholders if it would cause an event of default or an event of default is existing under an ARP credit agreement.

It is our current policy, as ARP’s general partner, that ARP should raise its quarterly cash distribution only when the general partner believes that:

 

•

ARP has sufficient reserves and liquidity for the proper conduct of its business; and

 

•

ARP can maintain such an increased distribution level for a sustained period.

While this is ARP’s current policy, we, in our capacity as ARP’s general partner, may alter the policy in the future when and if we determine such alteration to be appropriate.

 

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Quarterly Distributions of Available Cash

ARP’s partnership agreement requires that it make distributions of all available cash (as defined in its partnership agreement) within 45 days after the end of each quarter, beginning with the quarter ending March 31, 2012, to holders of record on the applicable record date. For these purposes, “available cash” generally means, for any of ARP’s fiscal quarters:

 

•

all cash on hand at the end of the quarter (including amounts available for working capital purposes under a credit facility, commercial paper facility or other similar financing arrangement);

 

•

less the amount of cash reserves established by ARP’s general partner at the date of determination of available cash for the quarter in order to:

 

•

provide for the proper conduct of ARP’s business (including reserves for working capital, operating expenses, future capital expenditures and credit needs and potential acquisitions);

 

•

comply with applicable law and any of ARP’s debt instruments or other agreements; or

 

•

provide funds for distributions to (1) ARP’s unitholders for any one or more of the next four quarters or (2) with respect to ARP’s incentive distribution rights (provided that ARP’s general partner may not establish cash reserves for future distributions on ARP’s common units and general partner Class A units unless it determines that the establishment of such reserves will not prevent ARP from distributing the minimum distribution on all common units and general partner Class A units);

 

•

plus, if ARP’s general partner so determines, all or any portion of cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

Working capital borrowings are borrowings that are made under ARP’s credit facility or another arrangement and used solely for working capital purposes or to pay distributions to unitholders.

Operating Surplus and Capital Surplus

General

All cash ARP distributes to unitholders will be characterized as either “operating surplus” or “capital surplus.” ARP’s partnership agreement requires that it distribute available cash from operating surplus differently than available cash from capital surplus.

Definition of Operating Surplus

Operating surplus generally means:

 

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$60 million (as described below);

 

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plus all of ARP’s cash receipts after its separation from Atlas Energy, including working capital borrowings but excluding cash from (1) borrowings that are not working capital borrowings, (2) sales of equity and debt securities and (3) sales or other dispositions of assets outside the ordinary course of business;

 

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plus working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter;

 

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plus cash distributions paid on equity securities that ARP may issue after its separation from Atlas Energy to finance all or a portion of the construction, acquisition, development, replacement or improvement of a capital asset (such as equipment or reserves) during the period beginning on the date that ARP enters into a binding obligation to commence the construction, acquisition, development or

 

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improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset begins producing in paying quantities, the date it is placed into service or the date that it is abandoned or disposed of;

 

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plus cash distributions paid (including incremental incentive distributions) on equity issued to pay the construction period interest on debt incurred (including periodic net payments under related interest rate swap arrangements), or to pay construction period distributions on equity issued, to finance the capital improvements or capital assets referred to above;

 

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less ARP’s operating expenditures (as defined below);

 

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less the amount of cash reserves established by ARP’s general partner to provide funds for future operating expenditures;

 

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less all working capital borrowings not repaid within twelve months after having been incurred or repaid within such twelve-month period with the proceeds of additional working capital borrowings;

 

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less any cash loss realized on disposition of an investment capital expenditure.

If a working capital borrowing, which increases operating surplus, is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will not be treated as a reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

“Operating expenditures” is defined in ARP’s partnership agreement, and generally means all of ARP’s cash expenditures, including:

 

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taxes;

 

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reimbursement of expenses to ARP’s general partner and its affiliates;

 

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payments made in the ordinary course of business on hedge contracts;

 

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director and officer compensation;

 

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repayment of working capital borrowings;

 

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debt service payments; and

 

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estimated maintenance capital expenditures.

Operating expenditures do not include:

 

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repayment of working capital borrowings previously deducted from operating surplus pursuant to the penultimate bullet point of the definition of operating surplus when the repayment actually occurs;

 

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payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings;

 

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expansion capital expenditures;

 

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actual maintenance capital expenditures;

 

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investment capital expenditures;

 

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payment of transaction expenses relating to interim capital transactions;

 

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distributions to ARP unitholders and distributions with respect to ARP’s incentive distribution rights; or

 

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repurchases of equity interests except to fund obligations under employee benefit plans.

 

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Operating surplus does not reflect actual cash on hand that is available for distribution to ARP unitholders. For example, it includes a provision that will enable ARP, if it chooses, to distribute as operating surplus up to $60 million of cash that ARP receives in the future from non-operating sources, such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including in the definition of operating surplus certain cash distributions on equity securities would be to increase operating surplus by the amount of the cash distributions. As a result, ARP may also distribute as operating surplus up to the amount of the cash distributions it receives from non-operating sources.

None of actual maintenance capital expenditures, investment capital expenditures or expansion capital expenditures are subtracted from operating surplus. Because actual maintenance capital expenditures, investment capital expenditures and expansion capital expenditures include interest payments (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all of the portion of the construction, acquisition, development, replacement or improvement of a capital asset (such as equipment or reserves) during the period from when ARP enters into a binding commitment to commence the construction, acquisition, development or improvement of a capital asset or replacement of a capital asset until the earlier to occur of the date any such capital asset is placed into service or the date that it is abandoned or disposed of, such interest payments and equity distributions are also not subtracted from operating surplus (except, in the case of maintenance capital expenditures, to the extent such interest payments and distributions are included in estimated maintenance capital expenditures).

Capital Expenditures

Estimated maintenance capital expenditures reduce operating surplus, but expansion capital expenditures, actual maintenance capital expenditures and investment capital expenditures do not.

Maintenance Capital Expenditures. Maintenance capital expenditures are those capital expenditures ARP expect to make on an ongoing basis to maintain its current production levels over the long term. ARP expects that a primary component of maintenance capital expenditures will be capital expenditures associated with the replacement of equipment and oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage and other similar assets), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property, including to offset expected production declines from producing properties. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of a replacement asset that is paid in respect of the period beginning on the date that ARP enters into a binding obligation to commence construction or development of the replacement asset and ending on the earlier to occur of the date the replacement asset is placed into service or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

Because ARP’s maintenance capital expenditures can be irregular, the amount of actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to ARP unitholders if ARP subtracted actual maintenance capital expenditures from operating surplus. To address this issue, ARP’s partnership agreement will require that an estimate of the average quarterly maintenance capital expenditures (including estimated plugging and abandonment costs) necessary to maintain its asset base over the long term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of ARP’s general partner at least once a year. ARP will make the estimate at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of future estimated maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will affect ARP’s business. Any adjustment to this estimate will be prospective only.

 

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The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:

 

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it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the minimum quarterly distribution to be paid on all the units for that quarter;

 

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it will increase ARP’s ability to distribute as operating surplus cash it receives from non-operating sources;

 

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in quarters where estimated maintenance capital expenditures exceed actual maintenance capital expenditures, it will be more difficult for ARP to raise its distributions above the minimum quarterly distribution because the amount of estimated maintenance capital expenditures will reduce the amount of cash available for distribution to ARP unitholders, even in quarters where there are no corresponding actual capital expenditures; conversely, the use of estimated maintenance capital expenditures in calculating operating surplus will have the opposite effect for quarters in which actual maintenance capital expenditures exceed our estimated maintenance capital expenditures; and

 

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it will be more difficult for ARP to raise distribution above the minimum quarterly distribution and pay incentive distribution rights.

Expansion Capital Expenditures

Expansion capital expenditures are those capital expenditures that ARP expects will increase the production of its oil and gas properties over the long term. Examples of expansion capital expenditures include the acquisition of reserves or equipment, the acquisition of new leasehold interests, or the development, exploitation and production of an existing leasehold interest, to the extent such expenditures are incurred to increase the production of ARP’s oil and gas properties over the long term. Expansion capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of a capital improvement that is paid in respect of the period beginning on the date that ARP enters into a binding obligation to commence construction or development of the capital improvement and ending on the earlier to occur of the date the capital improvement is placed into service or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered expansion capital expenditures.

Investment Capital Expenditures

Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of ARP’s undeveloped properties in excess of the maintenance of its asset base, but which are not expected to expand its asset base for more than the short term.

Capital expenditures that are made in part for maintenance capital purposes and in part for investment capital or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditure by the board of directors of ARP’s general partner based upon its good faith determination.

 

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Definition of Capital Surplus

Capital surplus is defined in ARP’s partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Capital surplus would generally be generated by:

 

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borrowings (including sales of debt securities) other than working capital borrowings;

 

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sales of debt and equity securities; and

 

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sales or other dispositions of assets for cash, other than inventory, accounts receivable and other assets disposed of in the ordinary course of business or as part of normal retirement or replacement of assets.

Characterization of Cash Distributions

ARP treats all available cash distributed as distributed from operating surplus until the sum of all available cash distributed since ARP began operations equals its total operating surplus from such date until the end of the quarter that immediately preceded the distribution. ARP will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. Operating surplus includes up to $60 million that does not reflect actual cash on hand that is available for distribution to our unitholders. This provision enables ARP, if it so chooses, to distribute as operating surplus up to this amount of cash it receives in the future from non-operating sources such as asset sales, issuances of securities and borrowings that would otherwise be distributed as capital surplus. ARP does not currently anticipate that it will make any distributions from capital surplus.

Distributions of Available Cash from Operating Surplus

ARP will make distributions of available cash from operating surplus for any quarter in the following manner:

 

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first, 2% to the holders of ARP’s general partner Class A units (which are held by ARP’s general partner) and 98% to the holders of ARP’s Class B preferred units and Class D preferred units, each pro rata, until each Class B preferred unitholder has received $0.40 per outstanding Class B preferred unit and there has been distributed in respect of each Class D preferred unit then outstanding the amount specified in the certificate of designation for the Class D preferred units;

 

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second, 2% to the holders of ARP’s general partner Class A units and 98% to the holders of ARP’s Class C preferred units, each pro rata, until there has been distributed in respect of each Class C preferred unit then outstanding the amount specified in the certificate of designation for the Class C preferred units;

 

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third, to the holders of the incentive distribution rights, which will initially be New Atlas following the separation, (A) 13/85ths of such amount paid pursuant to “second” above that is between $0.46 per outstanding unit for such quarter, which we refer to as the “first target distribution,” and $0.50 per outstanding unit for such quarter, which we refer to as the “second target distribution”; (B) 23/75ths of such amount paid pursuant to “second” above that is between the second target distribution and $0.60 per outstanding unit for such quarter, which we refer to as the “third target distribution”; and (C) 48/50ths of such amount paid pursuant to “second” above that is over the third target distribution for such quarter;

 

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fourth, 2% to the holders of ARP’s general partner Class A units and 98% to the holders of ARP’s common units, each pro rata, until there has been distributed in respect of each common unit then outstanding an amount equal to the minimum quarterly distribution for such quarter;

 

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fifth, 2% to the holders of ARP’s general partner Class A units and 98% to the holders of ARP’s common units and Class B preferred units, each pro rata, until there has been distributed in respect of each common unit and Class B preferred unit then outstanding an amount equal to the first target distribution for such quarter; and

 

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after that, in the manner described in “Cash Distribution Policy—ARP’s Cash Distribution Policy—Incentive Distribution Rights.”

 

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Adjusted operating surplus for any period generally means operating surplus generated during that period, less:

 

1.

any net increase in working capital borrowings with respect to that period; and

 

2.

any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period;

and plus:

 

3.

any net decrease in working capital borrowings made with respect to that period;

 

4.

any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium; and

 

5.

any net decrease made in subsequent periods in cash reserves for operating expenditures initially established with respect to such period to the extent such decrease results in a reduction of adjusted operating surplus in subsequent periods pursuant to item 2 above.

Operating surplus generated during a period is equal to the difference between:

 

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the operating surplus determined at the end of that period; and

 

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the operating surplus determined at the beginning of that period.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive increasing amounts of quarterly distributions of available cash from operating surplus after ARP has made payments in excess of the first target distribution and the tests described below have been met. Following the separation, New Atlas will hold all of ARP’s incentive distribution rights, but may transfer these rights separately from the general partner interest in ARP, without the consent of the ARP unitholders. ARP will make incentive distributions to New Atlas, in its capacity as ARP’s general partner, for any quarter in which it has distributed available cash from operating surplus to ARP unitholders in an amount equal to the first target distribution, as follows:

 

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first, 2% to the holders of ARP’s general partner Class A units and 85% to the holders of ARP’s common units and Class B preferred units, each pro rata, and 13% to the holders of the incentive distribution rights, until there has been distributed in respect of each common unit and Class B preferred unit then outstanding an amount equal to the second target distribution for such quarter;

 

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second, 2% to the holders of ARP’s general partner Class A units and 75% to the holders of ARP’s common units and Class B preferred units, each pro rata, and 23% to the holders of the incentive distribution rights, until there has been distributed in respect of each common unit and Class B preferred unit then outstanding an amount equal to the third target distribution for such quarter; and

 

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after that, 2% to the holders of ARP’s general partner Class A units and 50% to the holders of ARP’s common units and Class B preferred units, each pro rata, and 48% to the holders of the incentive distribution rights.

The general partner Class A units represent a 2% general partner interest in ARP, and the holders of such units are entitled to 2% of ARP’s cash distributions, without any requirement to make a capital contribution to ARP. The 2% sharing ratio of the general partner Class A units will not be reduced if ARP issues additional common units in the future. Because the 2% sharing ratio will not be reduced if ARP issues additional common units, and in order to ensure that each general partner Class A unit represents the same percentage economic interest in ARP as one common unit, if ARP issues additional common units, it will also issue to ARP’s general partner, for no additional consideration and without any requirement to make a capital contribution, an additional number of general partner Class A units so that the total number of outstanding Class A units after such issuance equals 2% of the sum of the total number of common units and general partner Class A units after such issuance.

 

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Right to Reset Incentive Distribution Levels

The holder of ARP’s incentive distribution rights, which, following the separation, will initially be New Atlas, has the right under ARP’s partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to ARP’s general partner would be set. If ARP’s general partner transfers all or a portion of the incentive distribution rights in the future, then the holder or holders of a majority of the incentive distribution rights will be entitled to exercise this right.

ARP’s general partner does not have the right to reset the minimum quarterly distributions payable to holders of ARP’s Class B preferred units, Class C preferred units or Class D preferred units without the consent of such holders. Upon a reset of the minimum quarterly distribution amount, holders of Class B preferred units shall continue to have the right to receive distributions equal to the greater of (i) $0.40 and (ii) the quarterly distribution payable to holders of common units for the most recently completed quarter, in each case multiplied by the number of common units into which such Class B preferred unit is then convertible, holders of Class C preferred units shall continue to have the right to receive distributions equal to the greater of (a) $0.51 and (b) the quarterly distribution payable to holders of common units for the most recently completed quarter, in each case multiplied by the number of common units into which such Class C preferred unit is then convertible and holders of Class D preferred units shall continue to have the right to receive distributions equal to the greater of (1) $0.54 and (2) the quarterly distribution payable to holders of common units for the most recently completed quarter, in each case multiplied by the number of common units into which such Class D preferred unit is then convertible.

The right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions are based may be exercised, without approval of ARP’s unitholders or the conflicts committee of the board of directors of ARP’s general partner, at any time when ARP has made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for the prior four consecutive fiscal quarters. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset, and there will be no incentive distributions paid under the reset target distribution levels. ARP anticipates that the holder of the incentive distribution rights would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to such holder.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment of incentive distribution payments based on the target cash distributions prior to the reset, the holder of the incentive distribution rights will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by such holder for the two quarters prior to the reset event, as compared to the average cash distributions per common unit during this period.

The number of common units that the holder of the incentive distribution rights would be entitled to receive from ARP in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to:

 

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the average amount of cash distributions received by the holder of the incentive distribution rights in respect of such rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election;

 

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divided by the average of the amount of cash distributed per common unit during each of these two quarters.

 

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Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per ARP general partner Class A unit and ARP common unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that ARP would distribute all of its available cash from operating surplus for each quarter thereafter as follows:

 

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first, 2% to holders of ARP’s general partner Class A units and 98% to the holders of ARP’s common units, each pro rata, until each holder receives an amount per unit equal to 115% of the reset minimum quarterly distribution for that quarter;

 

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second, 2% to the holders of ARP’s general partner Class A units and 85% to the holders of ARP’s common units, each pro rata, and 13% to ARP’s general partner, until each holder of ARP’s general partner Class A units and holder of ARP’s common units receives an amount per unit equal to 125% of the reset minimum quarterly distribution for the quarter;

 

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third, 2% to the holders of ARP’s general partner Class A units and 75% to the holders of ARP’s common units, each pro rata, and 23% to ARP’s general partner, until each holder of ARP’s general partner Class A units and each holder of ARP’s common units receives an amount per unit equal to 150% of the reset minimum quarterly distribution for the quarter; and

 

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after that, 2% to the holders of ARP’s general partner Class A units and 50% to the holders of ARP’s common units, each pro rata, and 48% to ARP’s general partner.

The holder of the incentive distribution rights will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, but it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under ARP’s partnership agreement.

Distributions from Capital Surplus

ARP distributes available cash from capital surplus, if any, in the following manner:

 

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first, 2% to the holders of ARP’s general partner Class A units and 98% to the holders of ARP’s Class B preferred units and Class D preferred units, each pro rata, until a hypothetical holder of a Class B preferred unit acquired on the date the Class B units were initially issued has received aggregate distributions of available cash that are deemed to be capital surplus in an amount equal to the face value of the Class B preferred units and a hypothetical holder of a Class D preferred unit acquired on the date the Class D units were initially issued has received aggregate distributions of available cash that are deemed to be capital surplus in an amount equal to the face value of the Class D preferred units;

 

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second, 2% to the holders of ARP’s general partner Class A units and 98% to the holders of ARP’s Class C preferred units, each pro rata, until a hypothetical holder of a Class C preferred unit acquired on the date the Class C units were initially issued has received aggregate distributions of available cash that are deemed to be capital surplus in an amount equal to the face value of the Class C preferred units;

 

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third, 2% to the holders of ARP’s general partner Class A units and 98% to the holders of ARP’s common units, each pro rata, until distributions have been paid on each common unit from capital surplus in an aggregate amount equal to the initial unrecovered unit price (as defined below); and

 

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after that, ARP will distribute all available cash from capital surplus as if it were from operating surplus.

ARP’s partnership agreement treats a distribution from capital surplus as the repayment of an investment in ARP’s units, which we refer to as the “unrecovered unit price.” The initial “unrecovered unit price” will be equal

 

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to the average of the closing prices of an ARP common unit on the NYSE for the five trading days immediately following the completion of the distribution. Any distributions from capital surplus after the distribution will reduce the unrecovered unit price. In addition, any distribution of capital surplus will also reduce the minimum quarterly distribution, the first target distribution, the second target distribution and the third target distribution, which we refer to in this document as “target distribution levels.” Each of the target distribution levels will be reduced in connection with a distribution of capital surplus to an amount equal to the then-applicable target distribution level multiplied by a fraction, the numerator of which is the unrecovered unit price immediately prior to such distribution of capital surplus, and the denominator of which is the unrecovered unit price immediately after such distribution of capital surplus.

After the minimum quarterly distribution and the target distribution levels have been reduced to zero, ARP will treat all distributions of available cash from all sources as if they were from operating surplus. Because the minimum quarterly distribution and the target distribution levels will have been reduced to zero, ARP’s general partner will then be entitled to receive 50% of all distributions of available cash in its capacity as general partner and holder of the incentive distribution rights, in addition to any distributions to which it may be entitled as a holder of units.

Distributions from capital surplus will not reduce the minimum quarterly distribution or target distribution levels for the quarter in which they are distributed.

Adjustment of Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjustments made upon a distribution of available cash from capital surplus, ARP will proportionately adjust the minimum quarterly distribution, target distribution levels and any other amounts calculated on a per unit basis upward or downward, as appropriate, if any combination or subdivision of common units occurs. For example, if a two-for-one split of the common units occurs, ARP will reduce the minimum quarterly distribution and the target distribution levels.

ARP will not make any adjustment for the issuance of additional common units for cash or property.

ARP may also adjust the minimum quarterly distribution and the target distribution levels if legislation is enacted or if existing law is modified or interpreted in a manner that causes ARP to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes. In this event, ARP will reduce the minimum quarterly distribution and the target distribution levels for each quarter after that time to amounts equal to the product of:

 

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the minimum quarterly distribution and each of the target distribution levels; and

 

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one minus the sum of:

 

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the highest marginal federal income tax rate which could apply to the partnership that is taxed as a corporation;

 

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plus the effective overall state and local income tax rate that would have been applicable in the preceding calendar year as a result of the new imposition of the entity level tax, after taking into account the benefit of any deduction allowable for federal income tax purposes for the payment of state and local income taxes, but only to the extent of the increase in rates resulting from that legislation or interpretation.

For example, assuming ARP is not previously subject to state and local income tax, if ARP became taxable as a corporation for federal income tax purposes and subject to a maximum marginal federal, and effective state and local, income tax rate of 40%, then ARP would reduce the minimum quarterly distribution and the target distribution levels to 60% of the amount immediately before the adjustment.

 

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Distributions of Cash Upon Liquidation

When ARP commences dissolution and liquidation, it will sell or otherwise dispose of its assets and adjust the partners’ capital account balances to reflect any resulting gain or loss. ARP will first apply the proceeds of liquidation to the payment of its creditors in the order of priority provided in ARP’s partnership agreement and by law. Then ARP will pay $26.03 per unit plus all unpaid distributions to the holders of ARP’s Class B preferred units and $25.00 per unit plus all unpaid distributions to the holders of ARP’s Class D preferred units, in each case subject to adjustment. Then ARP will pay $23.10 per unit plus all unpaid distributions to the holders of ARP’s Class C preferred units, subject to adjustment. After that, ARP will distribute the proceeds to the other unitholders and ARP’s general partner in accordance with their capital account balances, as so adjusted.

ARP maintains capital accounts in order to ensure that the partnership’s allocations of income, gain, loss and deduction are respected under the Internal Revenue Code of 1986, as amended, or the “Code.” The balance of a partner’s capital account also determines how much cash or other property the partner will receive on liquidation of the partnership. A partner’s capital account is credited with (increased by) the following items:

 

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the amount of cash and fair market value of any property (net of liabilities) contributed by the partner to the partnership, and

 

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the partner’s share of “book” income and gain (including income and gain exempt from tax).

A partner’s capital account is debited with (reduced by) the following items:

 

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the amount of cash and fair market value (net of liabilities) of property distributed to the partner, and

 

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the partner’s share of loss and deduction (including some items not deductible for tax purposes).

Partners are entitled to liquidating distributions in accordance with their capital account balances.

Upon ARP’s liquidation, any gain, or unrealized gain attributable to assets distributed in kind, will be allocated to the partners in the following manner:

 

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first, to ARP’s partners who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

 

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second, 2% to the holders of ARP’s general partner Class A units and 98% to the holders of ARP’s common units, each pro rata, until the capital account for each common unit is equal to the sum of:

 

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the unrecovered unit price,

 

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plus the amount of the unpaid minimum quarterly distribution for the quarter during which ARP’s liquidation occurs;

 

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third, 2% to the holders of ARP’s general partner Class A units and 98% to holders of ARP’s common units, each pro rata, until there has been allocated under this paragraph an amount per unit equal to:

 

•

the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of ARP’s existence,

 

•

less the cumulative amount per unit of any distribution of available cash from operating surplus in excess of the minimum quarterly distribution per unit that was distributed 2% to the holders of ARP’s general partner Class A units and 98% to the holders of ARP’s common units, each pro rata, for each quarter of our existence;

 

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fourth, 2% to the holders of ARP’s general partner Class A units and 85% to the holders of ARP’s common units, each pro rata, and 13% to the holders of the incentive distribution rights, until there has been allocated under this paragraph an amount per unit equal to:

 

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the excess of the second target distribution per unit over the first target distribution per unit for each quarter of ARP’s existence,

 

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•

less the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that was distributed 2% to the holders of ARP’s general partner Class A units and 85% to the holders of ARP’s common units, each pro rata, and 13% to the holder of the incentive distribution rights for each quarter of our existence; and

 

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fifth, 2% to the holders of ARP’s general partner Class A units and 75% to the holders of ARP’s common units, each pro rata, and 23% to the holder of the incentive distribution rights, until there has been allocated under this paragraph an amount per unit equal to:

 

•

the excess of the third target distribution per unit over the second target distribution per unit for each quarter of ARP’s existence,

 

•

less the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that was distributed 2% to the holders of ARP’s general partner Class A units and 75% to the holders of ARP’s common units, each pro rata, and 23% to the holder of the incentive distribution rights for each quarter of ARP’s existence; and

 

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after that, 50% to the holders of ARP’s common units and 2% to the holders of ARP’s general partner Class A units, each pro rata, and 48% to the holder of the incentive distribution rights.

Upon ARPs liquidation, any loss will generally be allocated to ARP’s general partner and the unitholders in the following manner:

 

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first, 2% to the holders of ARP’s general partner Class A units and 98% to the holders of ARP’s common units, each pro rata, until the capital accounts of the common unitholders have been reduced to zero; and

 

•

after that, 100% to ARP’s general partner.

In addition, ARP will make interim adjustments to the capital accounts at the time it issues additional equity interests or makes distributions of property. ARP will base these adjustments on the fair market value of the interests or the property distributed and will allocate any gain or loss resulting from the adjustments to the unitholders and ARP’s general partner in the same manner as gain or loss are allocated upon liquidation. In the event that ARP makes positive interim adjustments to the capital accounts, it will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional equity interests or distributions of property or upon ARP’s liquidation in a manner that results, to the extent possible, in the capital account balances of ARP’s general partner equaling the amount that would have been ARP’s general partner’s capital account balances if ARP had not made any earlier positive adjustments to the capital accounts.

 

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CAPITALIZATION

The following table, which should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “New Atlas Operations and Subsidiaries Unaudited Pro Forma Condensed Combined Financial Statements” and the financial statements and accompanying notes included elsewhere in this information statement, sets forth our cash and cash equivalents and combined capitalization as of September 30, 2014 on a historical basis and on a pro forma basis after giving effect to the contribution to New Atlas of all of Atlas Energy’s businesses other than its “Atlas Pipeline Partners” segment, along with the related issuance of 26.0 million common units of New Atlas to Atlas Energy.

 

		As of September 30, 2014
		Historical				Pro forma
		(in thousands)
Cash and cash equivalents		$	56,755			$	54,855
Debt:
New Atlas Term loan facility			148,500				155,000
ARP Credit facility			660,000				660,000
ARP 7.75% Senior Notes			374,525				374,525
ARP 9.25% Senior Notes			248,497				248,497
Total Debt, including current position			1,431,522				1,438,022
Equity:
Equity			336,532				—
Members’ equity			—				330,718
Accumulated other comprehensive income			15,744				15,744
			352,276				346,462
Non-controlling interests			978,379				978,379
Total equity			1,330,655				1,324,841
Total capitalization		$	2,762,177			$	2,762,863

 

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SELECTED FINANCIAL DATA

The following table presents selected historical condensed combined financial data for our predecessor, the New Atlas Operations (which is also referred to as “New Atlas”), as of and for the periods indicated. New Atlas consists of Atlas Energy’s interests in the following, which we currently own or which Atlas Energy has transferred, or will transfer to us prior to the distribution:

 

•

Atlas Resource Partners, L.P. (also referred to as “Atlas Resource Partners” or “ARP”), a publicly traded Delaware master limited partnership (NYSE: ARP) and an independent developer and producer of natural gas, crude oil and NGLs, with operations in basins across the United States. ARP sponsors and manages tax-advantaged investment partnerships (“Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas and oil production activities. At September 30, 2014, we owned 100% of the general partner Class A units and all of the incentive distribution rights in ARP, and Atlas Energy owned an approximate 27.7% limited partner interest (20,962,485 common and 3,749,986 Class C preferred limited partner units) in ARP;

 

•

Atlas Energy Development Subsidiary (also referred to as the “Development Subsidiary”), a subsidiary partnership that conducts natural gas and oil operations initially in the mid-continent region of the United States, currently in the Marble Falls formation in the Fort Worth Basin and Mississippi Lime area of the Anadarko Basin in Oklahoma. At September 30, 2014, Atlas Energy owned a 3.1% limited partner interest in the Development Subsidiary and 80.0% of its outstanding general partner Class A units, which are entitled to receive 2.0% of the cash distributed without any obligation to make further capital contributions;

 

•

Lightfoot Capital Partners, L.P. (referred to as “Lightfoot L.P.”) and Lightfoot Capital Partners GP, LLC (referred to as “Lightfoot GP”), the general partner of Lightfoot L.P. (also referred to, collectively, as “Lightfoot”), entities which incubate new MLPs and invest in existing MLPs. At September 30, 2014, Atlas Energy had an approximate 15.9% general partner interest and 12.0% limited partner interest in Lightfoot; and

 

•

coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma, which were acquired by Atlas Energy in July 2013.

The condensed combined statement of operations data for the nine months ended September 30, 2014 and 2013 and the condensed combined balance sheet data as of September 30, 2014 have been derived from New Atlas’s unaudited interim combined consolidated financial statements included elsewhere in this information statement. The condensed combined statement of operations data for the years ended December 31, 2013, 2012 and 2011 and the condensed combined balance sheet data as of December 31, 2013 and 2012 are derived from New Atlas’s audited combined consolidated financial statements included elsewhere in this information statement. The condensed combined statement of operations data for the years ended December 31, 2010 and 2009 and the condensed combined balance sheet data for those same periods are derived from the unaudited financial statements of the business transferred to AEI in February 2011, which is further described below. The unaudited combined consolidated financial statements have been prepared on the same basis as the audited combined consolidated financial statements and, in the opinion of our management, include all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the information set forth herein.

The selected historical condensed combined financial and other operating data presented below should be read in conjunction with New Atlas’s audited combined consolidated financial statements and accompanying notes beginning on page F-13, unaudited combined consolidated financial statements and accompanying notes beginning on page F-66 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 113. New Atlas’s combined consolidated financial information may not be indicative of our future performance and does not necessarily reflect what our financial position and results of operations would have been had New Atlas operated as an independent, publicly traded company during the periods presented, including changes that will occur in our operations and capitalization as a result of the

 

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separation from Atlas Energy and the distribution. For more information regarding these anticipated changes, see “New Atlas Operations and Subsidiaries Unaudited Pro Forma Condensed Combined Financial Statements” beginning on page F-2.

We have derived the selected financial data set forth in the following table for each of the years ended December 31, 2013, 2012 and 2011, with the exception of combined consolidated balance sheet data for the year ended December 31, 2011, from our combined consolidated financial statements appearing elsewhere in this report, which have been audited by Grant Thornton LLP, independent registered public accounting firm. We derived the financial data for the years ended December 31, 2010 and 2009, as well as combined consolidated balance sheet data for the year ended December 31, 2011, from our unaudited combined consolidated financial statements, which are not included in this report.

The combined consolidated financial statements include our accounts and that of our consolidated subsidiaries, all of which are wholly owned at December 31, 2013, except for ARP and our Development Subsidiary, which we control (see Note 2 to New Atlas’s audited combined consolidated financial statements, on page F-18). Due to the structure of our ownership interests in ARP and our Development Subsidiary, in accordance with generally accepted accounting principles, we consolidate the financial statements of ARP and our Development Subsidiary into our combined consolidated financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in ARP and our Development Subsidiary are reflected as income (loss) attributable to non-controlling interests in our combined consolidated statements of operations and as a component of equity on our combined consolidated balance sheets. Throughout this section, when we refer to “our” combined consolidated financial statements, we are referring to the consolidated results for us and our wholly owned subsidiaries and the consolidated results of ARP and our Development Subsidiary, adjusted for non-controlling interests.

On February 17, 2011, Atlas Energy acquired certain producing natural gas and oil properties, an investment management business that sponsors tax-advantaged direct investment natural gas and oil partnerships, and other assets (the “Transferred Business”) from AEI, the former owner of Atlas Energy’s general partner. In accordance with prevailing accounting literature, we determined that the acquisition of the Transferred Business constituted a transaction between entities under common control. In comparison to the acquisition method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in our combined consolidated financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect to the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, we reflected the impact of the acquisition of the Transferred Business on our combined consolidated financial statements in the following manner:

 

•

Recognized the assets and liabilities assumed from the Transferred Business at their historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to equity;

 

•

Retrospectively adjusted our combined consolidated balance sheets, our combined consolidated statements of operations, our combined consolidated statements of equity, our combined consolidated statements of comprehensive income (loss) and our combined consolidated statements of cash flows to reflect our results consolidated with the results of the Transferred Business as of or at the beginning of the respective period;

 

•

Adjusted the presentation of our combined consolidated statements of operations to reflect the results of operations attributable to the Transferred Business prior to the date of acquisition as a reduction of net income (loss) to determine income (loss) attributable to common limited partners. However, the Transferred Business’s historical financial statements prior to the date of acquisition do not reflect general and administrative expenses and interest expense. The Transferred Business was not managed by AEI as a separate business segment and did not have identifiable labor and other ancillary costs. The

 

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general and administrative and interest expenses of AEI prior to the date of acquisition, including the exploration and production business segment, related primarily to business activities associated with the business sold to Chevron in February 2011 and not activities related to the Transferred Business.

In February 2012, the board of directors of Atlas Energy’s general partner, which we refer to as “the Atlas Energy Board,” approved the formation of ARP as a newly created exploration and production master limited partnership and the related transfer of substantially all of our natural gas and oil development and production assets and the partnership management business to ARP on March 5, 2012. The Atlas Energy Board also approved the distribution of approximately 5.24 million ARP common units to its unitholders, which were distributed on March 13, 2012 using a ratio of 0.1021 ARP limited partner units for each of Atlas Energy’s common units owned on the record date of February 28, 2012.

The following table should be read together with our combined consolidated financial statements and notes beginning on page F-13).

 

		Nine Months Ended September 30,								Year Ended December 31,
		2014				2013				2013				2012				2011				2010				2009
		(in thousands, except per unit data)
Statement of operations data:
Revenues:
Gas and oil production		$	342,456			$	176,190			$	273,906			$	92,901			$	66,979			$	93,050			$	112,979
Well construction and completion			126,917				92,293				167,883				131,496				135,283				206,802				372,045
Gathering and processing			11,287				11,639				15,676				16,267				17,746				14,087				18,839
Administration and oversight			12,072				8,923				12,277				11,810				7,741				9,716				15,554
Well services			18,441				14,703				19,492				20,041				19,803				20,994				17,859
Other, net			1,167				(14,459	)			(14,135	)			(3,346	)			16,527				2,126				(1,502	)
Total revenues			512,340				289,289				475,099				269,169				264,079				346,775				535,774
Costs and expenses:
Gas and oil production			134,590				64,837				100,178				26,624				17,100				23,323				25,557
Well construction and completion			110,363				80,255				145,985				114,079				115,630				175,247				315,546
Gathering and processing			11,900				13,767				18,012				19,491				20,842				20,221				25,269
Well services			7,525				7,009				9,515				9,280				8,738				10,822				9,330
General and administrative			63,487				73,037				89,957				75,475				27,688				11,381				15,832
Chevron transaction expense			—				—				—				7,670				—				—				—
Depreciation, depletion and amortization			177,513				86,392				139,916				52,582				31,938				40,758				43,712
Asset impairment			—				—				38,014				9,507				6,995				50,669				156,359
Total costs and expenses			505,378				325,297				541,577				314,708				228,931				332,421				591,605
Operating income (loss)			6,962				(36,008	)			(66,478	)			(45,539	)			35,148				14,354				(55,831	)
Gain (loss) on asset sales and disposal			(1,683	)			(2,035	)			(987	)			(6,980	)			90				(2,947	)			—
Interest expense			(51,474	)			(24,704	)			(39,712	)			(4,548	)			(4,244	)			—				—
Net income (loss)			(46,195	)			(62,747	)			(107,177	)			(57,067	)			30,994				11,407				(55,831	)
Other financial data:
Adjusted EBITDA(1)		$	61,131			$	39,300			$	57,508			$	37,009			$	65,254				105,781				144,240
Balance sheet data (at period end):
Property, plant and equipment, net		$	2,728,650			$	2,243,190			$	2,186,683			$	1,302,228			$	525,454			$	508,484			$	503,386
Total assets			3,153,276				2,494,571				2,455,870				1,526,652				732,641				668,144				702,193
Total debt, including current portion			1,431,522				1,098,279				1,091,959				357,050				—				—				—
Total equity			1,330,655				1,138,544				1,043,996				868,804				485,348				400,794				363,176
Cash flow data:
Net cash provided by (used in) operating activities		$	(26,583	)		$	(78,459	)		$	3,841			$	13,524			$	83,410			$	59,586			$	24,279
Net cash used in investing activities			(671,897	)			(990,279	)			(1,053,524	)			(837,825	)			(57,984	)			(98,745	)			(92,141	)
Net cash provided by financing activities			744,592				1,047,037				1,037,038				792,863				29,282				39,159				67,862
Capital expenditures			(162,726	)			(205,827	)			(267,480	)			(127,226	)			(47,324	)			(93,608	)			(93,903	)
Operating data:(2)
Net production:
Natural gas (Mcfd)			238,158				137,725				163,992				69,408				31,403				35,855				38,644
Oil (Bpd)			2,882				1,301				1,336				330				307				373				427
Natural gas liquids (Bpd)			3,807				3,441				3,476				974				444				499				101
Total (Mcfed)			278,290				166,178				192,866				77,232				35,912				41,090				41,814

 

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		Nine Months Ended September 30,								Year Ended December 31,
		2014				2013				2013				2012				2011				2010				2009
		(in thousands, except per unit data)
Average sales price:
Natural gas (per Mcf):(3)
Total realized price, after hedge(3)		$	3.79			$	3.39			$	3.48			$	3.29			$	4.98			$	7.08			$	7.54
Total realized price, before hedge(3)		$	4.08			$	3.20			$	3.25			$	2.60			$	4.53			$	4.60			$	4.04
Oil (per Bbl):(3)
Total realized price, after hedge		$	89.87			$	91.19			$	91.02			$	94.02			$	89.70			$	77.31			$	71.34
Total realized price, before hedge		$	93.46			$	96.50			$	95.86			$	91.32			$	89.07			$	71.37			$	57.41
Natural gas liquids (per Bbl):(3)
Total realized price, after hedge		$	30.56			$	28.01			$	28.71			$	31.97			$	48.26			$	37.78			$	36.19
Total realized price, before hedge		$	32.14			$	28.52			$	29.43			$	31.97			$	48.26			$	37.78			$	36.19
Production costs (per Mcfe):
Lease operating expenses(4)		$	1.26			$	1.11			$	1.08			$	0.82			$	1.09			$	1.27			$	1.10
Production taxes		$	0.27			$	0.17			$	0.18			$	0.12			$	0.10			$	0.04			$	0.03
Transportation and compression		$	0.26			$	0.22			$	0.25			$	0.24			$	0.43			$	0.65			$	0.68
Total production costs		$	1.80			$	1.51			$	1.50			$	1.19			$	1.61			$	1.96			$	1.80

 

(1)

We define Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion and amortization, plus certain non-cash items such as compensation expenses associated with unit issuances to our directors and employees. Adjusted EBITDA is not a measure of performance calculated in accordance with GAAP. Although not prescribed under GAAP, we believe the presentation of Adjusted EBITDA is relevant and useful because it helps our investors to understand our operating performance and makes it easier to compare our results with other companies that have different financing and capital structures or tax rates. Adjusted EBITDA should not be considered in isolation of, or as a substitute for, net income as an indicator of operating performance or cash flows from operating activities as a measure of liquidity. Adjusted EBITDA, as we calculate it, may not be comparable to Adjusted EBITDA measures reported by other companies. Adjusted EBITDA is also a financial measurement that, with certain negotiated adjustments, will be utilized within our proposed new credit facility. In addition, Adjusted EBITDA does not represent funds available for discretionary use or the payment of distributions. The following reconciles our net income to Adjusted EBITDA for the periods indicated:

 

		Nine Months Ended September 30,								Year Ended December 31,
		2014				2013				2013				2012				2011				2010				2009
		(in thousands, except per unit data)
Net income (loss)		$	(46,195	)		$	(62,747	)		$	(107,177	)		$	(57,067	)		$	30,994			$	11,407			$	(55,831	)
Atlas Resource net (income) loss attributable to New Atlas owners			1,323				19,766				32,463				34,718				(19,899	)			—				—
Development Subsidiary net loss attributable to New Atlas owners			3,560				3,354				4,036				—				—				—				—
Loss (income) attributable to non-controlling interests			33,828				31,484				58,389				17,184				—				—				—
New Atlas interest expense			8,446				2,559				5,388				353				4,244				—				—
New Atlas depreciation, depletion and amortization			4,987				1,331				3,020				—				1,069				40,758				43,712
Asset impairment			—				—				—				—				—				50,669				156,359
EBITDA			5,949				(4,253	)			(3,881	)			(4,812	)			16,408				102,834				144,240
Cash distributions earned from ARP			54,564				41,123				58,347				31,270				—				—				—
Cash distributions earned from Development Subsidiary			133				—				26				—				—				—				—
E&P Operations Adjusted EBITDA prior to spinoff on March 5, 2012			—				—				—				9,111				49,182				—				—
Acquisition and related costs			77				1,831				2,151				2,000				—				—				—
Premiums paid on swaption derivative contracts			—				2,287				2,287				—				—				—				—
(Gain) loss on asset sales and disposal			(3	)			—				—				—				(3	)			2,947				—
Other			411				(1,688	)			(1,422	)			(560	)			(333	)			—				—
Adjusted EBITDA		$	61,131			$	39,300			$	57,508			$	37,009			$	65,254			$	105,781			$	144,240

 

(2)	“Mcf” represents thousand cubic feet; “Mcfe” represents thousand cubic feet equivalents; “Mcfd” represents thousand cubic feet per day; “Mcfed” represents thousand cubic feet equivalents per day; and “Bbls” and “Bpd” represent barrels and barrels per day.

(3)	Excludes the impact of subordination of ARP’s production revenue to investor partners within its Drilling Partnerships for the nine months ended September 30, 2014 and 2013 and the years ended December 31, 2013, 2012, 2011, 2010 and 2009. Including the effect of this subordination, the

 

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average realized gas sales price was $3.69 per Mcf ($3.97 per Mcf before the effects of financial hedging) and $3.12 per Mcf ($2.93 per Mcf before the effects of financial hedging) for the nine months ended September 30, 2014 and 2013, respectively, and $3.23 per Mcf ($3.00 per Mcf before the effects of financial hedging), $2.76 per Mcf ($2.08 per Mcf before the effects of financial hedging), $4.28 per Mcf ($3.83 per Mcf before the effects of financial hedging), $5.78 per Mcf ($3.30 per Mcf before the effects of financial hedging) and $7.13 per Mcf ($3.62 per Mcf before the effects of financial hedging) for years ended December 31, 2013, 2012, 2011, 2010, and 2009, respectively.

(4)

Excludes the effects of ARP’s proportionate share of lease operating expenses associated with subordination of its production revenue to investor partners within its Drilling Partnerships for the nine months ended September 30, 2014 and 2013 and the years ended December 31, 2013, 2012, 2011, 2010 and 2009. Including the effects of these costs, lease operating expenses per Mcfe were $1.24 per Mcfe ($1.77 per Mcfe for total production costs) and $1.03 per Mcfe ($1.43 per Mcfe for total production costs) for the nine months ended September 30, 2014 and 2013, respectively and $1.00 per Mcfe ($1.42 per Mcfe for total production costs), $0.58 per Mcfe ($0.94 per Mcfe for total production costs), $0.80 per Mcfe ($1.41 per Mcfe for total production costs), $1.24 per Mcfe ($1.77 per Mcfe for total production costs) and $1.03 per Mcfe ($1.43 per Mcfe for total production costs) for the years ended December 31, 2013, 2012, 2011, 2010 and 2009, respectively.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The historical financial statements included in this information statement reflect substantially all the assets, liabilities and operations of our and Atlas Energy’s controlled subsidiaries to be contributed to us prior to the distribution. We refer to our, Atlas Energy’s and such subsidiaries’ assets, liabilities and operations as New Atlas or our predecessor. The discussion and analysis presented below refer to and should be read in conjunction with the audited combined consolidated financial statements and related notes, the unaudited interim combined consolidated financial statements and related notes and the unaudited pro forma combined financial statements, each included elsewhere in this information statement. The following discussion may contain forward-looking statements that reflect our plans, estimates and beliefs. The words “believe,” “expect,” “anticipate,” “project,” and similar expressions, among others, generally identify “forward-looking statements,” which speak only as of the date the statements were made. The matters discussed in these forward-looking statements are subject to risks, uncertainties and other factors that could cause actual results to differ materially from those made, projected or implied in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this information statement, particularly in “Risk Factors” and “Forward-Looking Statements” beginning on pages 31 and 66, respectively. We believe the assumptions underlying the combined consolidated financial statements are reasonable. However, our predecessor’s combined consolidated financial statements included herein may not necessarily reflect our results of operations, financial position and cash flows in the future or what they would have been had our predecessor been a separate, stand-alone company during the periods presented.

As explained above, except as otherwise indicated or unless the context otherwise requires, the information included in this discussion and analysis assumes the completion of all the transactions referred to in this information statement in connection with the separation and distribution. Unless the context otherwise requires, references in this information statement to “New Atlas,” “the partnership,” “we,” “us,” “our” and “our company,” when used in a historical context or in the present tense, refer to the businesses and subsidiaries that are currently owned by Atlas Energy Group, LLC or that Atlas Energy will contribute to Atlas Energy Group, LLC in connection with the completion of all of the transactions referred to in this information statement in connection with the separation and distribution and, when used prospectively, refer to Atlas Energy Group, LLC, a Delaware limited liability company, and its combined subsidiaries. References in this information statement to “Atlas Energy” or “Atlas Energy, L.P.” refer to Atlas Energy, L.P., a Delaware limited partnership, and its consolidated subsidiaries, unless the context otherwise requires. References in this information statement to “ARP” or “Atlas Resource Partners” refer to Atlas Resource Partners, L.P., a Delaware limited partnership. References in this information statement to “Atlas Energy Group, LLC” or “Atlas Energy Group, LLC” prior to the separation refer to Atlas Energy Group, LLC, a Delaware limited liability company that is currently the general partner of ARP. References in this information statement to “APL” or “Atlas Pipeline Partners” refer to Atlas Pipeline Partners, L.P., a Delaware limited partnership and subsidiary of Atlas Energy. References in this information statement to “AEI” refer to Atlas Energy, Inc. the former owner of Atlas Energy’s general partner. References to “Targa Resources” refer to Targa Resources Corp., a Delaware corporation, and references to “Targa Resources Partners” refer to Targa Resources Partners LP, a Delaware limited partnership and subsidiary of Targa Resources.

Introduction

Management’s discussion and analysis, which we refer to in this information statement as “MD&A,” of our results of operations and financial condition is provided as a supplement to the audited financial statements and unaudited interim financial statements and footnotes thereto included elsewhere herein to help provide an understanding of our financial condition, changes in financial condition and results of our operations.

MD&A is organized as follows:

 

•

Separation from Atlas Energy—This section provides an overview of the decision to separate New Atlas from Atlas Energy and of the conditions and costs of the separation.

 

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•

Business Overview—This section provides a general description of our business.

 

•

Financial Presentation—This section describes the major principles used to prepare the financial statements, including the allocation methodology and adjustments made to present our combined consolidated financial statements.

 

•

Results of Operations—This section provides an analysis of our results of operations for the nine months ended September 30, 2014 and 2013, and for the fiscal years ended December 31, 2013, 2012 and 2011.

 

•

Other Costs and Expenses—This section provides a discussion of our other costs and expenses for the nine months ended September 30, 2014 and 2013, and for the fiscal years ended December 31, 2013, 2012 and 2011.

 

•

Liquidity and Capital Resources—This section provides a discussion of our financial condition and cash flows for the nine months ended September 30, 2014 and 2013, and for the fiscal years ended December 31, 2013, 2012 and 2011. It also includes a discussion of how the separation will affect our capital resources.

 

•

Internal Controls and Procedures—This section describes our current internal controls and procedures.

 

•

Critical Accounting Policies and Estimates—This section describes the accounting policies and estimates that we consider most important for our business, the application of which requires significant judgment.

 

•

Quantitative and Qualitative Disclosures About Market Risk—This section describes our potential exposure to the risk of loss arising from adverse changes in natural gas and oil prices.

Separation from Atlas Energy

On October 13, 2014, Atlas Energy announced that it had entered into the Atlas merger agreement with Targa Resources and a wholly owned subsidiary of Targa Resources providing for such wholly owned subsidiary to merge with and into Atlas Energy, with Atlas Energy surviving as a subsidiary of Targa Resources (also referred to as the “Atlas Merger”). Atlas Energy also agreed that pursuant to a separation and distribution agreement substantially in the form attached to the Atlas merger agreement, Atlas Energy would separate its midstream business from the remainder of its businesses. The separation would occur through Atlas Energy’s contribution of its other businesses, including its exploration and production business, to New Atlas and distribute approximately 26.0 million common units representing a 100% interest in New Atlas to the Atlas Energy unitholders. Atlas Energy has designated New Atlas, which is currently a wholly owned subsidiary of Atlas Energy, as the entity with which it will effect these transactions. New Atlas was formed in Delaware in October 2011 to serve as the general partner of Atlas Resource Partners, L.P. Following the separation, New Atlas will hold all of Atlas Energy’s assets and businesses, other than those related to its “Atlas Pipeline Partners” segment, in connection with the separation and distribution described in this information statement.

The distribution of approximately 26.0 million common units in New Atlas, as described in this information statement, is subject to the satisfaction or waiver of certain conditions, including, among others, the SEC declaring effective the registration statement of which this information statement forms a part. We cannot assure you that any or all of these conditions will be met. For a complete discussion of all of the conditions to the distribution, see “The Separation and Distribution—Conditions to the Distribution” beginning on page 74.

Atlas Energy is undertaking the separation of New Atlas from Atlas Energy in the manner described in this information statement and the distribution of the common units of New Atlas in connection with its entry into the Atlas merger agreement. Atlas Energy agreed in the Atlas merger agreement that, prior to the Atlas Merger, it will transfer its assets and liabilities other than those related to its “Atlas Pipeline Partners” segment to New Atlas and effect a pro rata distribution to the Atlas unitholders of New Atlas common units representing a 100% interest in

 

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New Atlas. On October 13, 2014, Atlas Energy also entered into the APL merger agreement with APL, Atlas Pipeline Partners GP, Targa Resources, Targa Resources Partners, Targa Resources Partners’ general partner and a newly formed subsidiary of Targa Resources Partners. APL and Targa Resources Partners are publicly traded subsidiaries of Atlas Energy and Targa Resources, respectively. The APL merger agreement provides for the newly formed subsidiary of Targa Resources Partners to merge with and into APL, with APL surviving the merger as a subsidiary of Targa Resources Partners. We refer to this second merger as the “APL Merger.”

The distribution and the Atlas Merger are each conditioned on the other and will each occur only if the other occurs or will occur. In addition, the Atlas Merger and the APL Merger are each conditioned on each other, which means that the distribution is effectively conditioned on the APL Merger. For additional information about the mergers of Atlas Energy and Targa Resources Corp. and of APL and Targa Resources Partners, please read Atlas Energy’s separate proxy statement/prospectus relating to the Atlas Merger.

In connection with the separation, we expect to incur one-time expenditures of between approximately $1.0 million and $1.5 million, excluding advisory fees. These expenditures primarily consist of one-time transaction-related costs and are excluded from the unaudited pro forma condensed combined financial statements. We expect to fund these costs through cash from operations, cash on hand and, if necessary, cash available from other borrowings. Additionally, we will incur increased costs as a result of becoming an independent, publicly traded company, primarily from establishing or expanding the corporate support for our business. We believe cash flow from operations will be sufficient to fund these additional corporate expenses.

We do not anticipate that increased costs solely from becoming an independent, publicly traded company will have an adverse effect on our growth rate in the future.

Business Overview

We are a Delaware limited liability company formed in October 2011 by Atlas Energy to serve as the general partner of Atlas Resource Partners, L.P., which is described below. Following the separation, we will hold Atlas Energy’s assets and businesses, other than those related to its “Atlas Pipeline Partners” segment, including holding the following:

 

•

the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in Atlas Resource Partners (which is also referred to as “ARP”), a publicly traded Delaware master limited partnership and an independent developer and producer of natural gas, crude oil and NGLs, with operations in basins across the United States. ARP sponsors and manages tax-advantaged investment partnerships, in which it coinvests, to finance a portion of its natural gas and oil production activities. As of September 30, 2014, we owned 100% of the general partner Class A units and all of the incentive distribution rights in ARP, and Atlas Energy owned an approximate 27.7% limited partner interest (consisting of 20,962,485 common and 3,749,986 preferred limited partner units) in ARP;

 

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Atlas Energy’s general partner and limited partner interests in the Development Subsidiary, a partnership that currently conducts natural gas and oil operations initially in the mid-continent region of the United States. As of September 30, 2014, Atlas Energy owned a 3.1% limited partner interest in the Development Subsidiary and 80.0% of its outstanding general partner Class A units, which are entitled to receive 2.0% of the cash distributed without any obligation to make further capital contributions;

 

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Atlas Energy’s interests in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, its general partner, which incubate new MLPs and invest in existing MLPs. At September 30, 2014, Atlas Energy had an approximate 15.9% general partner interest and 12.0% limited partner interest in Lightfoot; and

 

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direct natural gas development and production assets in the Arkoma Basin, which Atlas Energy acquired in July 2013.

 

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In February 2012, the board of directors of Atlas Energy’s general partner approved the formation of ARP as a newly created exploration and production master limited partnership and the related transfer of substantially all of its natural gas and oil development and production assets and the partnership management business to ARP on March 5, 2012. The board of directors of Atlas Energy’s general partner also approved the distribution of approximately 5.24 million ARP common units to Atlas Energy’s unitholders, which were distributed on March 13, 2012 using a ratio of 0.1021 ARP limited partner units for each of its common units owned on the record date of February 28, 2012.

On February 17, 2011, Atlas Energy acquired certain assets and liabilities, which are also referred to as the “Transferred Business,” from AEI, including the following exploration and production assets that were transferred to ARP on March 5, 2012:

 

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AEI’s investment management business, which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which ARP funds a portion of its natural gas and oil well drilling;

 

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proved reserves located in the Appalachian Basin, the Niobrara formation in Colorado, the New Albany Shale of west central Indiana, the Antrim Shale of northern Michigan and the Chattanooga Shale of northeastern Tennessee; and

 

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certain producing natural gas and oil properties, upon which ARP is the developer and producer.

In addition to the exploration and production assets, the Transferred Business also included all of the ownership interests in Atlas Energy GP, LLC, Atlas Energy’s general partner, and a direct and indirect ownership interest in Lightfoot.

Financial Presentation

Our combined consolidated financial statements were derived from the accounts of Atlas Energy and its controlled subsidiaries. Because a direct ownership relationship did not exist among all the various entities comprising our combined consolidated financial statements, Atlas Energy’s net investment in us is shown as equity in the combined consolidated financial statements. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the combined consolidated balance sheets and related combined consolidated statements of operations. Such estimates included allocations made from the historical accounting records of Atlas Energy, based on management’s best estimates, in order to derive our financial statements. Actual balances and results could be different from those estimates. All significant intercompany transactions and balances have been eliminated in the combination of the financial statements.

On February 17, 2011, Atlas Energy acquired certain producing natural gas and oil properties, an investment management business that sponsors tax-advantaged direct investment natural gas and oil partnerships, and other assets, which are also referred to as the “Transferred Business,” from AEI, the former owner of Atlas Energy’s general partner. In accordance with prevailing accounting literature, management of Atlas Energy determined that the acquisition of the Transferred Business constituted a transaction between entities under common control. In comparison to the acquisition method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in our combined consolidated financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect to the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, we reflected the impact of the acquisition of the Transferred Business on our combined consolidated financial statements in the following manner:

 

•

Recognized the assets and liabilities assumed from the Transferred Business at their historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to equity;

 

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Retrospectively adjusted our combined consolidated balance sheets, our combined consolidated statements of operations, our combined consolidated statements of equity, our combined consolidated statements of comprehensive income (loss) and our combined consolidated statements of cash flows to reflect our results consolidated with the results of the Transferred Business as of or at the beginning of the respective period;

 

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Adjusted the presentation of our combined consolidated statements of operations to reflect the results of operations attributable to the Transferred Business prior to the date of acquisition as a reduction of net income (loss) to determine income (loss) attributable to common limited partners. However, the Transferred Business’s historical financial statements prior to the date of acquisition do not reflect general and administrative expenses and interest expense. The Transferred Business was not managed by AEI as a separate business segment and did not have identifiable labor and other ancillary costs. The general and administrative and interest expenses of AEI prior to the date of acquisition, including the exploration and production business segment, related primarily to business activities associated with the business sold to Chevron in February 2011 and not to activities related to the Transferred Business.

Results of Operations

Gas and Oil Production

Production Profile. Currently, our gas and oil production revenues and expenses consist of our and ARP’s gas and oil production activities. Currently, our gas and oil production entails the production generated by our assets acquired in the Arkoma Acquisition and our wells drilled in the Marble Falls play. ARP has focused its natural gas, crude oil and NGL production operations in various shale plays throughout the United States. ARP had certain agreements that restricted its ability to drill additional wells in certain areas of Pennsylvania, New York and West Virginia, including portions of the Marcellus Shale, which expired on February 17, 2014. We, our Development Subsidiary, and ARP have established production positions in the following operating areas:

 

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the Eagle Ford Shale in southern Texas, in which our Development Subsidiary and ARP acquired acreage and producing wells in November 2014;

 

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the Barnett Shale and Marble Falls play in the Fort Worth Basin in northern Texas. The Barnett Shale contains mostly dry gas and the Marble Falls play, in which both ARP and our Development Subsidiary own acreage and producing wells, contains liquids rich natural gas and oil. ARP established its position following its acquisitions of assets from Carrizo Oil & Gas, Inc., Titan Operating, LLC and DTE Energy Company during 2012. We refer to these acquisitions as the “Carrizo,” “Titan” and “DTE” acquisitions;

 

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coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming, where ARP established a position following its acquisition of certain assets from EP Energy during 2013, which is also referred to as the “EP Energy Acquisition,” the Arkoma Basin in eastern Oklahoma, where we established a direct position following our acquisition of certain assets from EP Energy E&P Company, L.P. in July 2013 in what is also referred to as the “Arkoma Acquisition,” as well as the Cedar Bluff area of West Virginia and Virginia, where ARP established a position following its acquisition of assets from GeoMet Inc. in May 2014, which is also referred to as the “GeoMet Acquisition”;

 

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the Rangely field in northwest Colorado, a mature tertiary CO2 flood with low-decline oil production, where ARP has a 25% non-operated net working interest position following its acquisition on June 30, 2014, which is referred to as the “Rangely Acquisition”;

 

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the Appalachian Basin, including the Marcellus Shale, a rich, organic shale that generally contains dry, pipeline-quality natural gas, and the Utica Shale, which lies several thousand feet below the Marcellus Shale, is much thicker than the Marcellus Shale and trends primarily towards wet natural gas in the central region and dry gas in the eastern region;

 

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the Mississippi Lime and Hunton plays in northwestern Oklahoma, an oil and NGL-rich area, in which ARP established a position following its acquisition from Equal in 2012; and

 

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other operating areas, including the Chattanooga Shale in northeastern Tennessee, which enables ARP to access other formations in that region such as the Monteagle and Ft. Payne Limestone; the New Albany Shale in southwestern Indiana, a biogenic shale play with a long-lived and shallow decline profile; and the Niobrara Shale in northeastern Colorado, a predominantly biogenic shale play that produces dry gas.

The following table presents the number of wells we, our Development Subsidiary, and ARP drilled, both gross and for the net interest, and the number of gross wells we, our Development Subsidiary, and ARP turned in line during the nine months ended September 30, 2014 and 2013 and the years ended December 31, 2013, 2012 and 2011:

 

		Nine Months Ended September 30,								Year Ended December 31,
		2014				2013				2013				2012				2011
New Atlas Direct:
Gross wells drilled			—				—				—				—				—
Our share of gross wells drilled			—				—				—				—				—
Gross wells turned in line			—				—				—				—				—
Net wells turned in line			—				—				—				—				—
		Nine Months Ended September 30,								Year Ended December 31,
		2014				2013				2013				2012				2011
Development Subsidiary:
Gross wells drilled			11				—				2				—				—
Our share of gross wells drilled			11				—				2				—				—
Gross wells turned in line			10				—				2				—				—
Net wells turned in line			10				—				2				—				—
		Nine Months Ended September 30,								Year Ended December 31,
		2014				2013				2013				2012				2011
Atlas Resource:
ARP gross wells drilled			98				75				103				105				160
ARP’s share of gross wells drilled(1)			52				49				66				42				31
ARP gross wells turned in line			90				83				117				154				99
ARP net wells turned in line(1)			53				59				80				43				28

 

(1)	Includes (i) ARP’s percentage interest in the wells in which it has a direct ownership interest and (ii) ARP’s percentage interest in the wells based on its percentage ownership in its Drilling Partnerships.

 

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Production Volumes. The following table presents total net natural gas, crude oil and NGL production volumes and production per day for the nine months ended September 30, 2014 and 2013 and the years ended December 31, 2013, 2012 and 2011:

 

		Nine Months Ended September 30,								Year Ended December 31,
		2014				2013				2013				2012				2011
Production:(1)(2)
Atlas Resource:(3)
Appalachia:
Natural gas (MMcf)			10,670				9,187				13,397				12,403				9,597
Oil (000’s Bbls)			106				79				121				102				105
NGLs (000’s Bbls)			11				1				8				4				6
Total (MMcfe)			11,373				9,672				14,171				13,036				10,262
Coal-bed Methane:
Natural gas (MMcf)			32,441				7,037				17,465				—				—
Oil (000’s Bbls)			—				—				—				—				—
NGLs (000’s Bbls)			—				—				—				—				—
Total (MMcfe)			32,441				7,037				17,465				—				—
Barnett/Marble Falls:
Natural gas (MMcf)			15,955				18,075				23,744				10,561				—
Oil (000’s Bbls)			304				231				295				10				—
NGLs (000’s Bbls)			746				753				1,004				173				—
Total (MMcfe)			22,256				23,979				31,539				11,661				—
Rangely:
Natural gas (MMcf)			—				—				—				—				—
Oil (000’s Bbls)			236				—				—				—				—
NGLs (000’s Bbls)			24				—				—				—				—
Total (MMcfe)			1,562				—				—				—				—
Mississippi Lime/Hunton:
Natural gas (MMcf)			1,719				1,294				1,779				510				—
Oil (000’s Bbls)			101				39				63				3				—
NGLs (000’s Bbls)			143				78				118				30				—
Total (MMcfe)			3,181				1,997				2,859				705				—
Other operating areas:
Natural gas (MMcf)			897				1,248				1,609				1,929				1,866
Oil (000’s Bbls)			6				5				7				6				7
NGLs (000’s Bbls)			92				107				138				150				156
Total (MMcfe)			1,489				1,923				2,477				2,865				2,847
Total Atlas Resource:
Natural gas (MMcf)			61,682				36,840				57,993				25,403				11,462
Oil (000’s Bbls)			754				355				485				121				112
NGLs (000’s Bbls)			1,016				939				1,268				357				162
Total (MMcfe)			72,302				44,607				68,511				28,267				13,108

 

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		Nine Months Ended September 30,								Year Ended December 31,
		2014				2013				2013				2012				2011
New Atlas Direct:
Natural gas (MMcf)			3,156				759				1,856				—				—
Oil (000’s Bbls)			—				—				—				—				—
NGLs (000’s Bbls)			—				—				—				—				—
Total (MMcfe)			3,156				759				1,856				—				—
Development Subsidiary:
Natural gas (MMcf)			179				—				8				—				—
Oil (000’s Bbls)			33				—				3				—				—
NGLs (000’s Bbls)			23				—				1				—				—
Total (MMcfe)			515				—				29				—				—
Total production:
Natural gas (MMcf)			65,017				37,599				59,857				25,403				11,462
Oil (000’s Bbls)			787				355				488				121				112
NGLs (000’s Bbls)			1,039				939				1,269				357				162
Total (MMcfe)			75,973				45,366				70,396				28,267				13,108
Production per day:(1)(2)
Atlas Resource:(3)
Appalachia:
Natural gas (Mcfd)			39,083				33,651				36,705				33,889				26,292
Oil (Bpd)			390				291				332				278				287
NGLs (Bpd)			40				5				22				10				17
Total (Mcfed)			41,661				35,428				38,825				35,618				28,116
Coal-bed Methane:
Natural gas (Mcfd)			118,833				25,775				47,848				—				—
Oil (Bpd)			—				—				—				—				—
NGLs (Bpd)			—				—				—				—				—
Total (Mcfed)			118,833				25,775				47,848				—				—
Barnett/Marble Falls:
Natural gas (Mcfd)			58,445				66,208				65,053				28,855				—
Oil (Bpd)			1,114				847				808				28				—
NGLs (Bpd)			2,732				2,757				2,751				473				—
Total (Mcfed)			81,523				87,834				86,409				31,861				—
Rangely:
Natural gas (Mcfd)			—				—				—				—				—
Oil (Bpd)			865				—				—				—				—
NGLs (Bpd)			89				—				—				—				—
Total (Mcfed)			5,721				—				—				—				—
Mississippi Lime/Hunton:
Natural gas (Mcfd)			6,295				4,739				4,873				1,392				—
Oil (Bpd)			368				144				171				8				—
NGLs (Bpd)			524				285				322				81				—
Total (Mcfed)			11,651				7,315				7,834				1,926				—

 

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		Nine Months Ended September 30,								Year Ended December 31,
		2014				2013				2013				2012				2011
Other operating areas:
Natural gas (Mcfd)			3,287				4,571				4,408				5,271				5,111
Oil (Bpd)			24				19				18				16				20
NGLs (Bpd)			337				394				378				410				427
Total (Mcfed)			5,453				7,044				6,786				7,827				7,796
Total Atlas Resource:
Natural gas (Mcfd)			225,943				134,945				158,886				69,408				31,403
Oil (Bpd)			2,761				1,301				1,329				330				307
NGLs (Bpd)			3,722				3,441				3,473				974				444
Total (Mcfed)			264,843				163,397				187,701				77,232				35,912
New Atlas Direct:
Natural gas (Mcfd)			11,560				2,780				5,085				—				—
Oil (Bpd)			—				—				—				—				—
NGLs (Bpd)			—				—				—				—				—
Total (Mcfed)			11,560				2,780				5,085				—				—
Development Subsidiary:
Natural gas (Mcfd)			656				—				21				—				—
Oil (Bpd)			121				—				7				—				—
NGLs (Bpd)			85				—				3				—				—
Total (Mcfed)			1,887				—				79				—				—
Total production per day:
Natural gas (Mcfd)			238,158				137,725				163,992				69,408				31,403
Oil (Bpd)			2,882				1,301				1,336				330				307
NGLs (Bpd)			3,807				3,441				3,476				974				444
Total (Mcfed)			278,290				166,178				192,866				77,232				35,912

 

(1)

Production quantities consist of the sum of (i) the proportionate share of production from wells in which we and ARP have a direct interest, based on the proportionate net revenue interest in such wells, and (ii) ARP’s proportionate share of production from wells owned by the Drilling Partnerships in which it has an interest, based on ARP’s equity interest in each such Drilling Partnership and based on each Drilling Partnership’s proportionate net revenue interest in these wells.

(2)

“MMcf” represents million cubic feet; “MMcfe” represent million cubic feet equivalents; “Mcfd” represents thousand cubic feet per day; “Mcfed” represents thousand cubic feet equivalents per day; and “Bbls” and “Bpd” represent barrels and barrels per day. Barrels are converted to Mcfe using the ratio of approximately 6 Mcf to one barrel.

(3)

Appalachia includes ARP’s production located in Pennsylvania, Ohio, New York and West Virginia; Coal-bed methane includes ARP’s production located in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming; Rangely includes ARP’s 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado; Other operating areas include ARP’s production located in the Chattanooga, New Albany and Niobrara Shales.

 

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Production Revenues, Prices and Costs. Production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised all of our proved reserves and 83% of ARP’s proved reserves on an energy equivalent basis at December 31, 2013. The following table presents production revenues and average sales prices for our direct interest, our Development Subsidiary, and ARP’s natural gas, oil, and NGLs production for the nine months ended September 30, 2014 and 2013 and the years ended December 31, 2013, 2012 and 2011, along with average production costs, which include lease operating expenses, taxes, and transportation and compression costs, in each of the reported periods:

 

		Nine Months Ended September 30,								Year Ended December 31,
		2014				2013				2013				2012				2011
Production revenues (in thousands):
New Atlas Direct:
Natural gas revenue		$	12,197			$	2,700			$	6,821			$	—			$	—
Oil revenue			—				—				—				—				—
NGLs revenue			—				—				—				—				—
Total revenues		$	12,197			$	2,700			$	6,821			$	—			$	—
Development Subsidiary:
Natural gas revenue		$	756			$	—			$	28			$	—			$	—
Oil revenue			3,081				—				241				—				—
NGLs revenue			726				—				33				—				—
Total revenues		$	4,563			$	—			$	302			$	—			$	—
Atlas Resource:
Natural gas revenue		$	227,036			$	114,789			$	186,229			$	70,151			$	49,096
Oil revenue			67,626				32,394				44,160				11,351				10,057
NGLs revenue			31,034				26,307				36,394				11,399				7,826
Total revenues		$	325,696			$	173,490			$	266,783			$	92,901			$	66,979
Total production revenues:
Natural gas revenue		$	239,989			$	117,489			$	193,078			$	70,151			$	49,096
Oil revenue			70,707				32,394				44,401				11,351				10,057
NGLs revenue			31,760				26,307				36,427				11,399				7,826
Total revenues		$	342,456			$	176,190			$	273,906			$	92,901			$	66,979
Average sales price:
New Atlas Direct:
Natural gas (per Mcf):(1)
Total realized price, after hedge		$	3.86			$	3.56			$	3.68			$	—			$	—
Total realized price, before hedge		$	4.11			$	3.35			$	3.41			$	—			$	—
Oil (per Bbl):(1)
Total realized price, after hedge		$	—			$	—			$	—			$	—			$	—
Total realized price, before hedge		$	—			$	—			$	—			$	—			$	—
NGLs (per Bbl):(1)
Total realized price, after hedge		$	—			$	—			$	—			$	—			$	—
Total realized price, before hedge		$	—			$	—			$	—			$	—			$	—
Development Subsidiary:
Natural gas (per Mcf):(1)
Total realized price, after hedge		$	4.22			$	—			$	3.63			$	—			$	—
Total realized price, before hedge		$	4.22			$	—			$	3.63			$	—			$	—
Oil (per Bbl):(1)
Total realized price, after hedge		$	93.52			$	—			$	93.16			$	—			$	—
Total realized price, before hedge		$	93.52			$	—			$	93.16			$	—			$	—
NGLs (per Bbl):(1)
Total realized price, after hedge		$	31.45			$	—			$	34.88			$	—			$	—
Total realized price, before hedge		$	31.45			$	—			$	34.88			$	—			$	—

 

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		Nine Months Ended September 30,								Year Ended December 31,
		2014				2013				2013				2012				2011
Atlas Resource:
Natural gas (per Mcf):(1)
Total realized price, after hedge(2)		$	3.79			$	3.39			$	3.47			$	3.29			$	4.98
Total realized price, before hedge(2)		$	4.07			$	3.19			$	3.25			$	2.60			$	4.53
Oil (per Bbl):(1)
Total realized price, after hedge		$	89.71			$	91.19			$	91.01			$	94.02			$	89.70
Total realized price, before hedge		$	93.45			$	96.50			$	95.88			$	91.32			$	89.07
NGLs (per Bbl):(1)
Total realized price, after hedge		$	30.54			$	28.01			$	28.71			$	31.97			$	48.26
Total realized price, before hedge		$	32.16			$	28.52			$	29.43			$	31.97			$	48.26
Total:
Natural gas (per Mcf):(1)
Total realized price, after hedge(2)		$	3.79			$	3.39			$	3.48			$	3.29			$	4.98
Total realized price, before hedge(2)		$	4.08			$	3.20			$	3.25			$	2.60			$	4.53
Oil (per Bbl):(1)
Total realized price, after hedge		$	89.87			$	91.19			$	91.02			$	94.02			$	89.70
Total realized price, before hedge		$	93.46			$	96.50			$	95.86			$	91.32			$	89.07
NGLs (per Bbl):(1)
Total realized price, after hedge		$	30.56			$	28.01			$	28.71			$	31.97			$	48.26
Total realized price, before hedge		$	32.14			$	28.52			$	29.43			$	31.97			$	48.26
Production costs (per Mcfe):(1)
New Atlas Direct:
Lease operating expenses		$	0.86			$	0.77			$	0.79			$	—			$	—
Production taxes		$	0.26			$	0.21			$	0.21			$	—			$	—
Transportation and compression		$	0.33			$	0.56			$	0.54			$	—			$	—
		$	1.45			$	1.54			$	1.54			$	—			$	—
Development Subsidiary:
Lease operating expenses		$	2.51			$	—			$	—			$	—			$	—
Production taxes		$	0.50			$	—			$	—			$	—			$	—
Transportation and compression		$	—			$	—			$	—			$	—			$	—
		$	3.01			$	—			$	—			$	—			$	—
Atlas Resource:
Lease operating expenses(3)		$	1.27			$	1.12			$	1.09			$	0.82			$	1.09
Production taxes		$	0.27			$	0.17			$	0.18			$	0.12			$	0.10
Transportation and compression		$	0.26			$	0.22			$	0.24			$	0.24			$	0.43
		$	1.80			$	1.51			$	1.50			$	1.19			$	1.61
Total production costs:
Lease operating expenses(3)		$	1.26			$	1.11			$	1.08			$	0.82			$	1.09
Production taxes		$	0.27			$	0.17			$	0.18			$	0.12			$	0.10
Transportation and compression		$	0.26			$	0.22			$	0.25			$	0.24			$	0.43
		$	1.80			$	1.51			$	1.50			$	1.19			$	1.61

 

(1)	“Mcf” represents thousand cubic feet; “Mcfe” represents thousand cubic feet equivalents; and “Bbl” represents barrels.

(2)

Excludes the impact of subordination of ARP’s production revenue to investor partners within its Drilling Partnerships for the nine months ended September 30, 2014 and 2013, and the years ended December 31, 2013, 2012 and 2011. Including the effect of this subordination, the average realized gas sales price was $3.68 per Mcf ($3.96 per Mcf before the effects of financial hedging) and $3.12 per Mcf ($2.92 per Mcf before the effects of financial hedging) for the nine months ended September 30 2014 and 2013, respectively, and $3.23 per Mcf ($3.00 per Mcf before the effects of financial hedging), $2.76 per Mcf

 

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($2.08 per Mcf before the effects of financial hedging) and $4.28 per Mcf ($3.83 per Mcf before the effects of financial hedging) for years ended December 31, 2013, 2012 and 2011, respectively.

(3)

Excludes the effects of ARP’s proportionate share of lease operating expenses associated with subordination of its production revenue to investor partners within its Drilling Partnerships for the nine months ended September 30, 2014 and 2013, and for years ended December 31, 2013, 2012 and 2011. Including the effects of these costs, total lease operating expenses per Mcfe were $1.25 per Mcfe ($1.78 per Mcfe for total production costs) and $1.04 per Mcfe ($1.43 per Mcfe for total production costs) for the nine months ended September 30, 2014 and 2013, and $1.00 per Mcfe ($1.42 per Mcfe for total production costs), $0.58 per Mcfe ($0.94 per Mcfe for total production costs) and $0.80 per Mcfe ($1.41 per Mcfe for total production costs) for the years ended December 31, 2013, 2012 and 2011, respectively.

Nine Months Ended September 30, 2014 Compared with the Nine Months Ended September 30, 2013. Total production revenues were $342.5 million for the nine months ended September 30, 2014, an increase of $166.3 million from $176.2 million for the nine months ended September 30, 2013. This increase consisted of a $118.3 million increase attributable to our and ARP’s newly acquired coal-bed methane assets and a $22.2 million increase attributable to ARP’s newly acquired Rangely assets, a $10.1 million increase attributable to our and ARP’s Mississippi Lime/Hunton assets, a $9.2 million increase attributable to our and ARP’s Barnett Shale/Marble Falls operations, a $7.6 million increase attributable to ARP’s Appalachia assets due primarily to the Marcellus and Utica Shale wells drilled.

Total production costs were $134.6 million, an increase of $69.8 million from $64.8 million for the nine months ended September 30, 2013. This increase primarily consisted of a $49.8 million increase attributable to production costs associated with our and ARP’s newly acquired coal-bed methane assets, an $11.4 million increase primarily attributable to new well connections, consisting of $6.8 million attributable to our and AGP’s Barnett Shale/Marble Falls assets, $1.9 million attributable to ARP’s Appalachia operations, and $2.7 million attributable to our and ARP’s Mississippi Lime/Hunton assets, a $7.1 million increase attributable to ARP’s newly acquired Rangely assets, and a $1.5 million decrease in the credit received against ARP’s lease operating expenses pertaining to the subordination of its revenue within its Drilling Partnerships. Total production costs per Mcfe increased to $1.80 per Mcfe for the nine months ended September 30, 2014 from $1.51 per Mcfe for the comparable prior year period primarily as a result of the increases in our oil and natural gas liquids production.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Total production revenues were $273.9 million for the year ended December 31, 2013, an increase of $181.0 million from $92.9 million for the year ended December 31, 2012. This increase primarily consisted of a $110.1 million increase primarily attributable to new wells drilled, consisting of a $92.6 million increase attributable to our and ARP’s Barnett Shale/Marble Falls operations, a $15.4 million increase attributable to ARP’s Mississippi Lime/Hunton assets and a $2.1 million increase attributable to ARP’s Appalachian assets, and a $72.9 million increase attributable to our and ARP’s newly acquired coal-bed methane assets.

Total production costs were $100.2 million for the year ended December 31, 2013, an increase of $73.6 million from $26.6 million for the year ended December 31, 2012. This increase was due primarily to a $39.8 million increase associated with ARP’s 2012 acquisitions in the Barnett Shale/Marble Falls and Mississippi Lime/Hunton plays, a $28.7 million increase associated with our and ARP’s current year acquisition of coal-bed methane assets, a $3.6 million increase in ARP’s Appalachia-based transportation, labor and other production costs, and a $1.4 million decrease in ARP’s credit received against its lease operating expenses pertaining to the subordination of its revenue within its Drilling Partnerships. Total production costs per Mcfe increased to $1.50 per Mcfe for the year ended December 31, 2013 from $1.19 per Mcfe for the comparable prior year period primarily as a result of the increase in ARP’s oil and natural gas liquids volumes during the current period.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Total production revenues were $92.9 million for the year ended December 31, 2012, an increase of $25.9 million from $67.0 million for the year ended December 31, 2011. This increase consisted of a $31.4 million increase

 

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attributable to ARP’s newly acquired Barnett Shale/Marble Falls operations and a $3.2 million increase attributable to ARP’s newly acquired Mississippi Lime/Hunton assets, partially offset by an $8.7 million decrease primarily attributable to ARP’s Appalachia assets.

Total production costs were $26.6 million for the year ended December 31, 2012, an increase of $9.5 million from $17.1 million for the year ended December 31, 2011. This increase was due primarily to an $11.7 million increase associated with ARP’s 2012 acquisitions in the Barnett Shale/Marble Falls and Mississippi Lime/Hunton plays, and a $0.9 million increase in ARP’s Appalachia-based labor and other costs, partially offset by a $2.9 million increase in ARP’s credit received against lease operating expenses pertaining to the subordination of its revenue within its Drilling Partnerships. Total production costs per Mcfe decreased to $1.19 per Mcfe for the year ended December 31, 2012 from $1.61 per Mcfe for the comparable prior year period primarily as a result of ARP’s increase in natural gas volumes during the year ended December 31, 2012.

Well Construction and Completion

Drilling Program Results. Currently, our well construction and completion revenues and expenses consist solely of ARP’s activities. The number of wells ARP drills will vary within ARP’s partnership management segment depending on the amount of capital it raises through its Drilling Partnerships, the cost of each well, the depth or type of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. The following table presents the amounts of Drilling Partnership investor capital raised and deployed (in thousands), as well as the number of gross and net development wells ARP drilled for its Drilling Partnerships during the nine months ended September 30, 2014 and 2013 and the years ended December 31, 2013, 2012 and 2011. There were no exploratory wells drilled during the nine months ended September 30, 2014 and 2013 and the years ended December 31, 2013, 2012 and 2011.

 

		Nine Months Ended September 30,								Year Ended December 31,
		2014				2013				2013				2012				2011
Drilling partnership investor capital:
Raised		$	19,610			$	13,964			$	149,967			$	127,071			$	141,929
Deployed		$	126,917			$	92,293			$	167,883			$	131,496			$	135,283
Gross partnership wells drilled:
Appalachia
Marcellus Shale			—				—				—				10				14
Utica			4				3				3				5				—
Ohio			—				—				—				7				3
Barnett/Marble Falls			52				29				51				4				—
Mississippi Lime/Hunton			17				15				21				11				—
Chattanooga			—				—				—				—				5
Niobrara			—				—				—				51				138
Total			73				47				75				88				160
Net partnership wells drilled:
Appalachia
Marcellus Shale			—				—				—				10				11
Utica			4				3				3				5				—
Ohio			—				—				—				7				3
Barnett/Marble Falls			40				14				25				2				—
Mississippi Lime/Hunton			17				15				21				9				—
Chattanooga			—				—				—				—				5
Niobrara			—				—				—				51				138
Total			61				32				49				84				157

 

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Well construction and completion revenues and costs and expenses incurred represent the billings and costs associated with the completion of wells for Drilling Partnerships ARP sponsors. The following table sets forth information relating to these revenues and the related costs and number of net wells associated with these revenues during the periods indicated (dollars in thousands):

 

		Nine Months Ended September 30,								Years Ended December 31,
		2014				2013				2013				2012				2011
Average construction and completion:
Revenue per well		$	2,476			$	3,871			$	3,276			$	1,444			$	886
Cost per well			2,153				3,366				2,849				1,253				757
Gross profit per well		$	323			$	505			$	427			$	191			$	129
Gross profit margin		$	16,554			$	12,038			$	21,898			$	17,417			$	19,653
Partnership net wells associated with revenue recognized(1):
Appalachia
Marcellus Shale			—				6				4				7				15
Utica			3				2				5				2				—
Ohio			—				—				—				8				2
Barnett/Marble Falls			37				7				24				2				—
Mississippi Lime/Hunton			11				9				18				7				—
Chattanooga			—				—				—				2				4
New Albany/Antrim			—				—				—				—				3
Niobrara			—				—				—				63				129
Total			51				24				51				91				153

 

(1)	Consists of ARP’s Drilling Partnership net wells for which well construction and completion revenue was recognized on a percentage of completion basis.

Nine Months Ended September 30, 2014 Compared with the Nine Months Ended September 30, 2013. Well construction and completion segment margin was $16.6 million for the nine months ended September 30, 2014, an increase of $4.6 million from $12.0 million for the nine months ended September 30, 2013. This increase consisted of an $8.9 million increase related to a greater number of wells recognized for revenue within ARP’s Drilling Partnerships, partially offset by a $4.3 million decrease associated with ARP’s lower gross profit margin per well. Average revenue and cost per well decreased between periods due primarily to capital deployed for lower cost Marble Falls wells within ARP’s Drilling Partnerships during the nine months ended September 30, 2014 compared with capital deployed for higher cost Marcellus Shale wells during the prior year period.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Well construction and completion segment margin was $21.9 million for the year ended December 31, 2013, an increase of $4.5 million from $17.4 million for the year ended December 31, 2012. This increase consisted of a $12.1 million increase associated with ARP’s higher gross profit margin per well, partially offset by a $7.6 million decrease related to a lower number of wells recognized for revenue within ARP’s Drilling Partnerships. Average revenue and cost per well increased between periods due primarily to higher capital deployed for Utica Shale, Mississippi Lime play, and Marble Falls play wells within ARP’s Drilling Partnerships during the year ended December 31, 2013, compared with higher capital deployed for lower cost Niobrara Shale wells during the prior year period.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Well construction and completion segment margin was $17.4 million for the year ended December 31, 2012, a decrease of $2.3 million from $19.7 million for the year ended December 31, 2011. This decrease consisted of a $7.9 million decrease related to a decreased number of wells recognized for revenue within ARP’s Drilling Partnerships, partially

 

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offset by a $5.6 million increase associated with higher gross profit margin per well. Average revenue and cost per well increased between periods due primarily to higher capital deployed for Marcellus Shale and Utica Shale wells within the Drilling Partnerships during 2012.

At December 31, 2013, our combined consolidated balance sheet includes $49.4 million of “liabilities associated with drilling contracts” for funds raised by ARP’s Drilling Partnerships that have not been applied to the completion of wells due to the timing of drilling operations, and thus had not been recognized as well construction and completion revenue on our combined consolidated statements of operations. ARP expects to recognize this amount as revenue during 2014.

Administration and Oversight

Currently, our administration and oversight revenues and expenses consist solely of ARP’s activities. Administration and oversight fee revenues represent supervision and administrative fees earned for the drilling and subsequent ongoing management of wells for ARP’s Drilling Partnerships. Typically, ARP receives a lower administration and oversight fee related to shallow, vertical wells it drills within the Drilling Partnerships, such as those in the Marble Falls and Niobrara Shale, as compared to deep, horizontal wells, such as those drilled in the Marcellus Shale and the Utica Shale.

Nine Months Ended September 30, 2014 Compared with the Nine Months Ended September 30, 2013. Administration and oversight fee revenues were $12.1 million for the nine months ended September 30, 2014, an increase of $3.2 million from $8.9 million for the nine months ended September 30, 2013. This increase was due to increases in the number of wells spud within the current year period compared with the prior year period, particularly within the Marble Falls Shale and Mississippi Lime plays.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Administration and oversight fee revenues were $12.3 million for the year ended December 31, 2013, an increase of $0.5 million from $11.8 million for the year ended December 31, 2012. This increase was due primarily to current year period increases in the number of wells drilled within the Mississippi Lime Shale and Marble Falls play, partially offset by a decrease in the number of Marcellus Shale wells drilled during the current year period.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Administration and oversight fee revenues were $11.8 million for the year ended December 31, 2012, an increase of $4.1 million from $7.7 million for the year ended December 31, 2011. This increase was primarily due to an increase in the number of horizontal wells drilled in both the Mississippi Lime and Utica Shale during the year ended December 31, 2012 and an increase in the number of Marcellus Shale wells drilled during the year ended December 31, 2012 in comparison to the prior year period.

Well Services

Currently, our well services revenues and expenses consist solely of ARP’s activities. Well services revenue and expenses represent the monthly operating fees ARP charges and the work ARP’s service company performs, including work performed for ARP’s Drilling Partnership wells during the drilling and completing phase as well as ongoing maintenance of these wells and other wells for which ARP serves as operator.

Nine Months Ended September 30, 2014 Compared with the Nine Months Ended September 30, 2013. Well services revenues were $18.4 million for the nine months ended September 30, 2014, an increase of $3.7 million from $14.7 million for the nine months ended September 30, 2013. Well services expenses were $7.5 million for the nine months ended September 30, 2014, an increase of $0.5 million from $7.0 million for the nine months ended September 30, 2013. The increase in well services revenue is primarily related to the increased utilization of ARP’s salt water gathering and disposal systems within the Mississippi Lime and Marble Falls plays by ARP’s Drilling Partnership wells. The increase in well services expense is primarily related to higher labor costs.

 

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Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Well services revenues were $19.5 million for the year ended December 31, 2013, a decrease of $0.5 million from $20.0 million for the year ended December 31, 2012. Well services expenses were $9.5 million for the year ended December 31, 2013, an increase of $0.2 million from $9.3 million for the year ended December 31, 2012. The decrease in well services revenue is primarily related to lower equipment rental revenue during the year ended December 31, 2013 as compared with the comparable prior year period. The increase in well services expense is primarily related to higher well labor costs.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Well services revenues were $20.0 million for the year ended December 31, 2012, an increase of $0.2 million from $19.8 million for the year ended December 31, 2011. Well services expenses were $9.3 million for the year ended December 31, 2012, an increase of $0.6 million from $8.7 million for the year ended December 31, 2011. The increase in well services revenue is primarily related to higher equipment rental revenue during the year ended December 31, 2012 as compared with the comparable prior year period. The increase in well services expenses is primarily related to higher well labor costs.

Gathering and Processing

Currently, our gathering and processing margin consists solely of ARP’s activities. Gather and processing revenues and expenses include gathering fees ARP charges to its Drilling Partnership wells and the related expenses and gross margin for ARP’s processing plants in the New Albany Shale and the Chattanooga Shale. Generally, ARP charges a gathering fee to its Drilling Partnership wells equivalent to the fees it remits. In Appalachia, a majority of ARP’s Drilling Partnership wells are subject to a gathering agreement, whereby ARP remits a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, ARP charges its Drilling Partnership wells a 13% gathering fee. As a result, some of its gathering expenses within our partnership management segment, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%.

Nine Months Ended September 30, 2014 Compared with the Nine Months Ended September 30, 2013. Our net gathering and processing expense for the nine months ended September 30, 2014 was $0.6 million, a favorable movement of $1.5 million compared with net processing expense of $2.1 million for the nine months ended September 30, 2013. This favorable movement was principally due to an increase in gathering fees from ARP’s new Marcellus Shale Drilling Partnership wells in Northeastern Pennsylvania, which are utilizing its gathering pipeline.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Our net gathering and processing expense for the year ended December 31, 2013 was $2.3 million, a favorable movement of $0.9 million compared with net expense of $3.2 million for the year ended December 31, 2012. This favorable decrease was principally due to an increase in gathering fees associated with ARP’s new Marcellus wells in Northeastern Pennsylvania.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Our net gathering and processing expense for the year ended December 31, 2012 was $3.2 million, comparable with $3.1 million for the year ended December 31, 2011. This unfavorable increase was principally due to an increase in natural gas volume in the Appalachian Basin between the periods, partially offset by a decrease in ARP’s average realized natural gas price.

Other, Net

Nine Months Ended September 30, 2014 Compared with the Nine Months Ended September 30, 2013. Other, net for the nine months ended September 30, 2014 was revenue of $1.2 million as compared with expense of $14.5 million for the comparable prior year period. This favorable movement was primarily due to the

 

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$16.9 million decrease in premium amortization associated with our and ARP’s swaption derivative contracts for production volumes related to wells acquired from EP Energy in the prior year period, partially offset by a $1.6 million decrease in income from our equity investment in Lightfoot.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Other, net for the year ended December 31, 2013 was expense of $14.1 million as compared with expense of $3.3 million for the comparable prior year period. This unfavorable movement was primarily due to $16.8 million of premium amortization associated with our and ARP’s swaption derivative contracts for production volumes related to wells we and ARP acquired from EP Energy in the current year period, partially offset by a $4.6 million decrease in premium amortization associated with ARP’s swaption derivative contracts for production volumes related to wells it acquired from Carrizo in the prior year period, and a $1.1 million increase in income from the equity investment in Lightfoot.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Other, net for the year ended December 31, 2012 was expense of $3.3 million as compared with revenue of $16.5 million for the comparable prior year period. This unfavorable movement was primarily due to a $15.0 million decrease in our equity earnings from Lightfoot, and $4.6 million of premium amortization associated with ARP’s swaption derivative contracts for production volumes related to wells it acquired from Carrizo in 2012. During the year ended December 31, 2011, we recorded a gain of $15.0 million pertaining to our share of Lightfoot LP’s gain recognized on the sale of International Resource Partners LP in March 2011.

Other Costs and Expenses

General and Administrative Expenses

The following table presents our direct general and administrative expenses and those attributable to our Development Subsidiary and ARP for each of the respective periods (in thousands):

 

		Nine Months Ended September 30,								Years Ended December 31,
		2014				2013				2013				2012				2011
General and Administrative expenses:
New Atlas Direct		$	5,523			$	5,916			$	8,162			$	6,352			$	152
Development Subsidiary			7,070				3,354				3,732				—				—
Atlas Resource Partners			50,894				63,767				78,063				69,123				27,536
Total		$	63,487			$	73,037			$	89,957			$	75,475			$	27,688

Nine Months Ended September 30, 2014 Compared with the Nine Months Ended September 30, 2013. Total general and administrative expenses decreased to $63.5 million for the nine months ended September 30, 2014 from $73.0 million for the nine months ended September 30, 2013. Our $5.5 million of general and administrative expenses for the nine months ended September 30, 2014 represents a $0.4 million decrease from the comparable prior year period due to a $0.4 million decrease in salaries, wages and other corporate activities. Development Subsidiary’s $7.1 million of general and administrative expenses for the nine months ended September 30, 2014 represents a $3.7 million increase from the comparable prior year period due to a $3.6 increase in salaries, wages, and other corporate activities and a $0.1 million increase in third-party services. ARP’s $50.9 million of general and administrative expenses for the nine months ended September 30, 2014 represents a $12.9 million decrease from the comparable prior year period primarily due to a $13.1 million decrease in non-recurring transaction costs related to ARP’s acquisitions of assets in the current and prior year periods and a $3.9 million decrease in ARP’s non-cash compensation expense, partially offset by a $4.1 million increase in salaries and wages and other corporate activities due to the growth of its business.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Total general and administrative expenses increased to $90.0 million for the year ended December 31, 2013 from $75.5 million for

 

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the year ended December 31, 2012. Our $8.2 million of general and administrative expenses for the year ended December 31, 2013 represents a $1.8 million increase from the comparable prior year period, due to a $1.7 million increase in salaries, wages and other corporate activities and a $0.1 million increase in third-party services. Development Subsidiary’s $3.7 million of general and administrative expenses for the year ended December 31, 2013 represents a $3.7 million increase from the comparable prior year period due to a $3.5 increase in salaries, wages, and other corporate activities and a $0.2 million increase in third-party services. ARP’s $78.1 million of general and administrative expenses for the year ended December 31, 2013 represents an $8.9 million increase from the comparable prior year period, which was primarily due to a $7.7 million increase in non-recurring transaction costs related to ARP’s 2013 acquisitions of assets and a $1.8 million increase in non-cash compensation expense, partially offset by a $0.5 million decrease in other corporate activities.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Total general and administrative expenses increased to $75.5 million for the year ended December 31, 2012 from $27.7 million for the year ended December 31, 2011. Our $6.4 million of general and administrative expenses for the year ended December 31, 2012 represents a $6.2 million increase from the comparable year period, which was primarily related to a $5.6 million increase in salaries and wages and a $0.6 million increase in other corporate activities. ARP’s $69.1 million of general and administrative expenses for the year ended December 31, 2012 represents a $41.6 million increase from the comparable prior year period, which was primarily due to a $22.1 million increase in non-recurring transaction costs related to ARP’s 2012 acquisitions of assets, an $18.6 million unfavorable movement related to a decrease in net reimbursements ARP received under its transition services agreement with Chevron, which expired during the first quarter of 2012, and a $10.8 million increase in non-cash compensation expense, partially offset by a $9.9 million decrease in salaries, wages and other corporate activities.

Chevron Transaction Expense

During the year ended December 31, 2012, ARP recognized a $7.7 million charge regarding its reconciliation process with Chevron related to certain amounts included within the contractual cash transaction adjustment, which was settled in October 2012.

Depreciation, Depletion and Amortization

The following table presents depreciation, depletion and amortization expense that was attributable to our direct, our Development Subsidiary, and ARP for each of the respective periods (dollars in thousands):

 

		Nine Months Ended September 30,								Years Ended December 31,
		2014				2013				2013				2012				2011
Depreciation, depletion and amortization:
New Atlas Direct		$	4,987			$	1,331			$	3,020			$	—			$	—
Development Subsidiary			1,436				—				133				—				—
Atlas Resource Partners			171,090				85,061				136,763				52,582				31,938
Total		$	177,513			$	86,392			$	139,916			$	52,582			$	31,938

Total depreciation, depletion and amortization increased to $177.5 million for the nine months ended September 30, 2014, compared with $86.4 million for the comparable prior year period, which was primarily due to an $88.5 million increase in our, Development Subsidiary’s, and ARP’s depletion expense resulting from the acquisitions consummated during 2013.

Total depreciation, depletion and amortization increased to $139.9 million for the year ended December 31, 2013 compared with $52.6 million for the comparable prior year period, which was primarily due to an $85.9 million increase in our and ARP’s depletion expense resulting from the acquisitions consummated during 2013 and 2012.

 

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Total depreciation, depletion and amortization increased to $52.6 million for the year ended December 31, 2012, compared with $31.9 million for the comparable prior year period, which was primarily due to a $19.6 million increase in ARP’s depletion expense.

The following table presents our and ARP’s depletion expense per Mcfe for our and ARP’s operations for the respective periods (in thousands, except per Mcfe data):

 

		Nine Months Ended September 30,								Years Ended December 31,
		2014				2013				2013				2012				2011
Depletion expense:
Total		$	170,063			$	81,500			$	132,860			$	47,000			$	27,430
Depletion expense as a percentage of gas and oil production revenue			50	%			46	%			49	%			51	%			41	%
Depletion per Mcfe		$	2.24			$	1.80			$	1.89			$	1.66			$	2.09

Nine Months Ended September 30, 2014 Compared with the Nine Months Ended September 30, 2013. Depletion expense was $170.0 million for the nine months ended September 30, 2014, an increase of $88.5 million compared with $81.5 million for the nine months ended September 30, 2013. Depletion expense of gas and oil properties as a percentage of gas and oil revenues increased to 50% for nine months ended September 30, 2014, compared with 46% for the nine months ended September 30, 2013, which was primarily due to an increase in ARP’s depletion expense associated with the increased oil and natural gas liquids volumes resulting from ARP’s drilling program. Depletion expense per Mcfe was $2.24 for nine months ended September 30, 2014, an increase of $0.44 per Mcfe from $1.80 per Mcfe for the nine months ended September 30, 2013, which was primarily due to an increase in ARP’s depletion expense associated with its oil and natural gas liquids wells drilled between the periods. Depletion expense increased between periods, principally due to an overall increase in production volume.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Depletion expense was $132.9 million for the year ended December 31, 2013, an increase of $85.9 million compared with $47.0 million for the year ended December 31, 2012. Depletion expense of gas and oil properties as a percentage of gas and oil revenues decreased to 49% for the year ended December 31, 2013, compared with 51% for the year ended December 31, 2012, which was primarily due to an increase in ARP’s oil and natural gas liquids revenues as a result of ARP’s acquisitions in 2012. Depletion expense per Mcfe was $1.89 for the year ended December 31, 2013, an increase of $0.23 per Mcfe from $1.66 per Mcfe for the year ended December 31, 2012, which was primarily related to the increase in ARP’s oil and natural gas liquids production between the periods. Depletion expense increased between periods, principally due to an overall increase in production volume.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Depletion expense was $47.0 million for the year ended December 31, 2012, an increase of $19.6 million compared with $27.4 million for the year ended December 31, 2011. ARP’s depletion expense of gas and oil properties as a percentage of gas and oil revenues increased to 51% for the year ended December 31, 2012, compared with 41% for the year ended December 31, 2011, which was primarily due to a decrease in realized natural gas prices between the periods. Depletion expense per Mcfe was $1.66 for the year ended December 31, 2012, a decrease of $0.43 per Mcfe from $2.09 for the year ended December 31, 2011, which was primarily related to lower depletion expense per Mcfe for the assets acquired from the Carrizo and Titan acquisitions and the addition of reserves for new Marcellus Shale wells, which began production during the year ended December 31, 2012. Depletion expense increased between the periods, principally due to an overall increase in production volume.

Asset Impairment

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Asset impairment for the year ended December 31, 2013, was $38.0 million compared with $9.5 million for the comparable prior year

 

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period. ARP recognized $38.0 million of asset impairments related to gas and oil properties within property, plant and equipment, net on our combined consolidated balance sheet, primarily for its shallow natural gas wells in the New Albany Shale and its unproved acreage in the Chattanooga Shale and the New Albany Shale. During the year ended December 31, 2012, ARP recognized $9.5 million of asset impairment related to gas and oil properties within property, plant and equipment on our combined consolidated balance sheet for its shallow natural gas wells in the Antrim Shale and the Niobrara Shale. These impairments by ARP related to the carrying amount of these gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2013 and 2012 and ARP’s intention not to drill on certain expiring unproved acreage. The estimate of fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices in comparison to their carrying values at December 31, 2013 and 2012.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Asset impairment for the year ended December 31, 2012, was $9.5 million compared with $7.0 million for the comparable prior year period. During the year ended December 31, 2012, ARP recognized $9.5 million of asset impairment related to gas and oil properties within property, plant and equipment on our combined consolidated balance sheet for its shallow natural gas wells in the Antrim Shale and the Niobrara Shale. During the year ended December 31, 2011, ARP recognized $7.0 million of asset impairment related to gas and oil properties within property, plant and equipment on our combined consolidated balance sheet for its shallow natural gas wells in the Niobrara Shale. These impairments related to the carrying amounts of these gas and oil properties being in excess of ARP’s estimates of their fair value at December 31, 2012 and 2011. The estimates of fair values of these gas and oil properties were impacted by, among other factors, the deterioration of natural gas prices in comparison to their carrying values at December 31, 2012 and 2011.

Gain (Loss) on Asset Sales and Disposal

Nine Months Ended September 30, 2014 Compared with the Nine Months Ended September 30, 2013. During the nine months ended September 30, 2014 and 2013, losses on asset sales and disposal were $1.7 million and $2.0 million, respectively. The $1.7 million loss on asset sales and disposal for the nine months ended September 30, 2014 was primarily related to ARP’s sale of producing wells in the Niobrara Shale in connection with the settlement of a third-party farm-out agreement. The $2.0 million loss on asset sales and disposal for the nine months ended September 30, 2013 was primarily related to ARP’s decision not to drill wells on leasehold property that expired in the New Albany Shale and the Chattanooga Shale during the period.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. During the years ended December 31, 2013 and 2012, losses on asset sales and disposal were $1.0 million and $7.0 million, respectively. The $1.0 million loss on asset sales and disposal for the year ended December 31, 2013 primarily pertained to a loss as a result of ARP’s sale of its Antrim assets in Michigan. During the year ended December 31, 2012, ARP recognized a $7.0 million loss on asset sales and disposal related to its decision to terminate a farm-out agreement with a third party for well drilling in the South Knox area of the New Albany Shale that was originally entered into in 2010. The farm-out agreement contained certain well drilling milestones which needed to be met in order for ARP to maintain ownership of the South Knox processing plant. During 2012, ARP management decided not to continue progressing towards these milestones due to the then current natural gas price environment. As a result, ARP forfeited its interest in the processing plant and recorded a loss related to the net book value of the assets during the year ended December 31, 2012.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. During the year ended December 31, 2012, loss on asset sales and disposal was $7.0 million, compared to a gain of $0.1 million for the year ended December 31, 2011. ARP recognized a $7.0 million loss on asset sales and disposal for the year ended December 31, 2012, which pertained to ARP’s decision to terminate a farm-out agreement with a third party for well drilling in the South Knox area of the New Albany Shale that was originally entered into in 2010. The farm-out agreement contained certain well drilling milestones which needed to be met in order for ARP to maintain ownership of the South Knox processing plant. During 2012, ARP management decided not to continue

 

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progressing towards these milestones due to the then current natural gas price environment. As a result, ARP forfeited its interest in the processing plant and recorded a loss related to the net book value of the assets during the year ended December 31, 2012.

Interest Expense

The following table presents our interest expense and that which was attributable to ARP for each of the respective periods:

 

		Nine Months Ended September 30,								Years Ended December 31,
		2014				2013				2013				2012				2011
Interest Expense:
New Atlas		$	8,446			$	2,559			$	5,388			$	353			$	4,244
Atlas Resource Partners			43,028				22,145				34,324				4,195				—
Total		$	51,474			$	24,704			$	39,712			$	4,548			$	4,244

Nine Months Ended September 30, 2014 Compared with the Nine Months Ended September 30, 2013. Total interest expense increased to $51.5 million for the nine months ended September 30, 2014, compared with $24.7 million for the nine months ended September 30, 2013. This $26.8 million increase was due to our $5.9 million increase and a $20.9 million increase related to ARP. The $5.9 million increase in our interest expense consisted of a $6.2 million increase associated with our term loan facility, including a $0.6 million increase in the amortization of deferred financing costs, partially offset by a $0.3 million decrease associated with our credit facility. The $20.9 million increase in ARP’s interest expense consisted of a $13.4 million increase associated with the July 2013 issuance of 9.25% ARP Senior Notes, a $6.0 million increase associated with higher weighted-average outstanding borrowings under its revolving credit facility net of capitalized interest amounts, a $2.6 million increase associated with the June 2014 issuance of an additional $100.0 million of the 7.75% ARP Senior Notes, and a $1.3 million increase associated with a full three quarters’ impact of the January 2013 issuance of $275.0 million of the 7.75% ARP Senior Notes, partially offset by a $2.4 million decrease associated with amortization of deferred financing costs. The decrease in amortization associated with deferred financing costs was primarily related to the accelerated amortization associated with the retirement of ARP’s then-existing term loan credit facility and the reduction in its revolving credit facility borrowing base subsequent to its issuance of the 7.75% ARP Senior Notes in the prior year period and the decrease in amortization of deferred financing costs resulting from ARP’s amended credit facility in the prior year. Our Development Subsidiary had no interest expense for the nine months ended September 30, 2014 and 2013.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Total interest expense increased to $39.7 million for the year ended December 31, 2013, compared with $4.5 million for the year ended December 31, 2012. This $35.2 million increase was due to our $5.0 million increase and a $30.1 million increase related to ARP. The $5.0 million increase in our interest expense consisted of $4.2 million associated with our term loan facility, a $0.5 million increase in the amortization of deferred financing costs primarily associated with our term loan facility and a $0.3 million increase associated with our credit facility. The $30.1 million increase in ARP’s interest expense consisted of a $20.9 million increase associated with ARP’s issuance of the 7.75% ARP Senior Notes in January 2013, a $10.1 million increase associated with the issuance of the 9.25% ARP Senior Notes in July 2013, a $7.8 million increase in the amortization of deferred financing costs and a $3.1 million increase associated with higher weighted-average outstanding borrowings under ARP’s revolving credit facility and a term loan credit facility which was retired in January 2013, partially offset by interest capitalized on ARP’s ongoing capital projects. The increase in amortization associated with deferred financing costs includes an increase of $5.3 million associated with ARP’s revolving credit facility, $3.2 million of accelerated amortization related to the retirement of ARP’s term loan credit facility and the reduction in its revolving credit facility borrowing base subsequent to its issuance of the 7.75% ARP Senior Notes and $1.2 million associated with ARP’s issuance of senior notes,

 

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partially offset by a $1.9 million decrease in amortization expense related to the extension of ARP’s credit facility maturity date from 2016 to 2018. Our Development Subsidiary had no interest expense for the years ended December 31, 2013 and 2012.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Total interest expense increased to $4.5 million for the year ended December 31, 2012, compared with $4.2 million for the year ended December 31, 2011. This $0.3 million increase was due to a $4.2 million increase related to ARP, partially offset by our $3.9 million decrease. Our $3.9 million decrease in interest expense was primarily due to $3.1 million of accelerated amortization of deferred financing costs for our bridge credit facility that was entered into in connection with our closing of the acquisition of the Transferred Business and $0.4 million in interest expense related to borrowings from affiliates during the prior year period. The bridge credit facility was replaced in March 2011 by our previous credit facility, which was transferred to ARP in March 2012. The $4.2 million increase in ARP’s interest expense was primarily associated with outstanding borrowings under the transferred credit facility and amortization of deferred financing costs associated with the credit facility. There was no interest expense for ARP for the year ended December 31, 2011. Our Development Subsidiary had no interest expense for the years ended December 31, 2012 and 2011.

Loss (Income) Attributable to Non-Controlling Interests

Nine Months Ended September 30, 2014 Compared with the Nine Months Ended September 30, 2013. Loss attributable to non-controlling interests was $33.8 million for the nine months ended September 30, 2014, compared with a loss of $31.5 million for the comparable prior year period. Loss (income) attributable to non-controlling interests includes an allocation of ARP’s and Development Subsidiary’s net income (loss) to non-controlling interest holders. The increase in loss attributable to non-controlling interests between the nine months ended September 30, 2014 and the prior year comparable period was primarily due to an increase in Development Subsidiary’s net loss during the nine months ended September 30, 2014, as compared to the comparable prior year period and a decrease in our ownership interests in ARP between the periods, partially offset by a decrease in ARP’s net loss during the nine months ended September 30, 2014, as compared to the comparable prior year period.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Loss attributable to non-controlling interests was $58.4 million for the year ended December 31, 2013, compared with a loss of $17.2 million for the comparable prior year period. Loss (income) attributable to non-controlling interests includes an allocation of ARP’s and the Development Subsidiary’s net income (loss) to non-controlling interest holders. The increase in loss attributable to non-controlling interests between the year ended December 31, 2013, and the prior year comparable period was primarily due to an increase in ARP’s net loss between periods and a decrease in our ownership interests in ARP during the year ended December 31, 2013.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Loss attributable to non-controlling interests was $17.2 million for the year ended December 31, 2012. There were no non-controlling interests for the year ended December 31, 2011. Loss (income) attributable to non-controlling interests includes an allocation of ARP’s net income (loss) to non-controlling interest holders. The increase in loss attributable to non-controlling interests between the year ended December 31, 2012 and the prior year comparable period was due to ARP’s net loss for the year ended December 31, 2012.

Liquidity and Capital Resources

General

Historically, our primary sources of liquidity are cash distributions received with respect to our ownership interests in ARP, our Development Subsidiary, Lightfoot and our cash generated from operations. Also following the closing of the separation and related transactions, we intend to make cash distributions to our limited partners at an initial distribution rate of $0.55 per common unit per quarter ($2.20 per common unit on

 

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an annualized basis)—see “Cash Distribution Policy” beginning on page 76. Our primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures, and quarterly distributions to our unitholders, which we expect to fund through operating cash flow, and cash distributions received.

Atlas Resource Partners. ARP’s primary sources of liquidity are cash generated from operations, capital raised through Drilling Partnerships, and borrowings under its credit facility (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities”). ARP’s primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures and distributions to its unitholders and us, as general partner. In general, ARP expects to fund:

 

•

cash distributions and maintenance capital expenditures through existing cash and cash flows from operating activities;

 

•

expansion capital expenditures and working capital deficits through cash generated from operations, additional borrowings and capital raised through Drilling Partnerships; and

 

•

debt principal payments through additional borrowings as they become due or by the issuance of additional common units or asset sales.

ARP relies on cash flow from operations and its credit facility to execute its growth strategy and to meet its financial commitments and other short-term liquidity needs. ARP cannot be certain that additional capital will be available to the extent required and on acceptable terms. We and our subsidiaries believe that we will have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve-month period. However, we and our subsidiaries are subject to business, operational and other risks that could adversely affect our cash flow. We and our subsidiaries may supplement our cash generation with proceeds from financing activities, including borrowings under our proposed credit facility, ARP’s credit facility and other borrowings, the issuance of additional limited partner units, the sale of assets and other transactions.

Cash Flows—Nine Months Ended September 30, 2014 Compared with the Nine Months Ended September 30, 2013

Net cash used in operating activities of $26.6 million for the nine months ended September 30, 2014 represented a favorable movement of $51.9 million from net cash used in operating activities of $78.5 million for the comparable prior year period. The $51.9 million favorable movement was derived principally from a favorable movement of $103.6 million in net loss, excluding non-cash items and a $2.7 million favorable movement in working capital, partially offset by a $54.4 million unfavorable movement in distributions paid to non-controlling interests. The non-cash charges which impacted net loss primarily included an increase of $91.1 million in depreciation, depletion and amortization, a $16.6 million favorable movement in net loss and a $2.1 million favorable movement in equity income and distributions related to unconsolidated subsidiaries, partially offset by a $3.9 million decrease in non-cash compensation expense, a $2.0 million decrease in amortization of deferred financing costs and a $0.3 million decrease in loss on asset sales and disposal. The movement in cash distributions to non-controlling interest holders was due principally to increases in cash distributions of ARP. The movement in working capital was due to an $86.2 million favorable movement in accounts payable and accrued liabilities, primarily due to the timing of ARP’s capital program and the growth of ARP’s business during the nine months ended September 30, 2014, partially offset by an $83.5 million unfavorable movement in accounts receivable, prepaid expenses and other.

Net cash used in investing activities of $671.9 million for the nine months ended September 30, 2014 represented a favorable movement of $318.4 million from net cash used in investing activities of $990.3 million for the comparable prior year period. This favorable movement was principally due to a $270.0 million decrease in net cash paid for our and ARP’s acquisitions, a $43.1 million decrease in capital expenditures and a $5.3 million favorable movement in other assets. See further discussion of capital expenditures under “—Capital Requirements.”

 

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Net cash provided by financing activities of $744.6 million for the nine months ended September 30, 2014 represented an unfavorable movement of $302.4 million from net cash provided by financing activities of $1,047.0 million for the comparable prior year period. This unfavorable movement was principally due to a decrease of $413.1 million for the net proceeds from ARP’s long-term debt, a decrease of $94.4 million in repayments of our and ARP’s revolving credit facilities and a $74.7 million unfavorable movement in net investment from (distribution to) Atlas Energy, partially offset by an increase of $150.1 million of net proceeds primarily from ARP’s equity offerings, an increase of $116.4 million for our and ARP’s borrowings under our and ARP’s respective revolving credit facilities and a $13.3 million favorable movement in deferred financing costs, distribution equivalent rights and other. The gross amount of borrowings and repayments under the revolving credit facilities included within net cash provided by financing activities in the combined consolidated statements of cash flows, which are generally in excess of net borrowings or repayments during the period or at period end, reflect the timing of cash receipts, which generally occur at specific intervals during the period and are utilized to reduce borrowings under the revolving credit facilities, and payments, which generally occur throughout the period and increase borrowings under the revolving credit facilities for us and ARP, which is generally common practice for our business and industries.

Cash Flows—Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012

Net cash provided by operating activities of $3.8 million for the year ended December 31, 2013 represented an unfavorable movement of $9.7 million from net cash provided by operating activities of $13.5 million for the comparable prior year period. The $9.7 million unfavorable movement was derived principally from a $61.1 million unfavorable movement in distributions paid to non-controlling interests and a $17.6 million unfavorable movement in working capital, partially offset by a $69.0 million favorable movement in net loss excluding non-cash items. The movement in cash distributions to non-controlling interest holders was due principally to increases in cash distributions of ARP. The movement in working capital was due to a $58.0 million unfavorable movement in accounts payable and accrued liabilities, primarily due to the timing of ARP’s capital program, partially offset by a $40.4 million favorable movement in accounts receivable, prepaid expenses and other. The non-cash charges which impacted net loss primarily included an increase of $87.3 million of depreciation, depletion and amortization, an increase of $28.5 million in asset impairment, an increase of $8.3 million in amortization of deferred financing costs and an increase of $1.9 million in compensation expense, partially offset by an unfavorable movement of $50.1 million in net loss, a decrease of $6.0 million in loss on asset sales and disposal and an unfavorable movement of $0.9 million in equity and distributions related to unconsolidated subsidiaries.

Net cash used in investing activities of $1,053.5 million for the year ended December 31, 2013 represented an unfavorable movement of $215.7 million from net cash used in investing activities of $837.8 million for the comparable prior year period. This unfavorable movement was principally due to a $140.3 million increase in capital expenditures, a $71.0 million increase in net cash paid for our and ARP’s acquisitions and a $4.4 million unfavorable movement in other assets. See further discussion of capital expenditures under “—Capital Requirements.”

Net cash provided by financing activities of $1,037.0 million for the year ended December 31, 2013 represented a favorable movement of $244.1 million from net cash provided by financing activities of $792.9 million for the comparable prior year period. This movement was principally due to a $510.4 million increase in net proceeds from the issuance of ARP’s long-term debt, a $434.9 million increase in our and ARP’s borrowings under our and its revolving credit facilities and a $44.0 million favorable movement in the net investment from (distribution to) Atlas Energy, partially offset by a $580.4 million increase in repayments of our and ARP’s revolving and term loan credit facilities, a $156.9 million decrease in net proceeds primarily from ARP’s equity offerings and a $7.9 million unfavorable movement in deferred financing costs, distribution equivalent rights and other. The unfavorable movement in deferred financing costs, distribution equivalent rights and other is primarily due to the increase in deferred financing costs associated with our and ARP’s revolving and term loan credit facilities. The gross amount of borrowings and repayments under the revolving credit facilities included within net cash provided by financing activities in the combined consolidated statements of cash flows, which are

 

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generally in excess of net borrowings or repayments during the period or at period end, reflect the timing of cash receipts, which generally occur at specific intervals during the period and are utilized to reduce borrowings under the revolving credit facilities, and payments, which generally occur throughout the period and increase borrowings under the revolving credit facilities for us and ARP, which is generally common practice for our and ARP’s industries.

Cash Flows—Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011

Net cash provided by operating activities of $13.5 million for the year ended December 31, 2012 represented an unfavorable movement of $69.9 million from net cash provided by operating activities of $83.4 million for the comparable prior year period. The $69.9 million unfavorable movement was derived principally from a $45.7 million unfavorable movement in net income (loss) excluding non-cash items, a $14.0 million unfavorable movement in distributions paid to non-controlling interests and a $10.1 million unfavorable movement in working capital. The non-cash charges which impacted net income (loss) included an $88.1 million unfavorable movement in net income (loss) and a $0.2 million unfavorable movement in equity income and distributions from unconsolidated companies, partially offset by a $20.6 million increase in depreciation, depletion and amortization, a $10.8 million increase in compensation expense, a $7.1 million favorable movement in (gain) loss on asset sales and disposal, a $2.5 million increase in asset impairment and a $1.6 million increase in amortization of deferred financing costs. The unfavorable movement in net income (loss) was primarily due to ARP’s net loss for the year ended December 31, 2012. The movement in cash distributions to non-controlling interest holders was due to increases in the cash distributions of ARP. The movement in working capital was principally due to a $60.9 million unfavorable movement in accounts receivable, prepaid expenses and other, partially offset by a $50.7 million favorable movement in accounts payable and accrued liabilities, primarily due to the timing of ARP’s capital program.

Net cash used in investing activities of $837.8 million for the year ended December 31, 2012 represented an unfavorable movement of $779.8 million from net cash used in investing activities of $58.0 million for the comparable prior year period. This unfavorable movement was principally due to a $709.8 million increase in net cash paid for ARP’s acquisitions and a $79.9 million increase in capital expenditures, partially offset by a favorable movement in other assets of $9.9 million. The net cash paid for acquisitions included cash paid for ARP’s transactions related to the Carrizo, Titan, Equal and DTE acquisitions. See further discussion of capital expenditures under “—Capital Requirements.”

Net cash provided by financing activities of $792.9 million for the year ended December 31, 2012 represented a favorable movement of $763.6 million from net cash provided by financing activities of $29.3 million for the comparable prior year period. This movement was principally due to a $672.7 million increase in our and ARP’s borrowings under the respective revolving credit facilities and a $483.3 million increase in net proceeds from ARP’s equity offerings related to the Carrizo and DTE acquisitions, partially offset by a $315.7 million increase in repayments of ARP’s revolving credit facility, a $60.1 unfavorable movement in net investment from (distribution to) Atlas Energy and a $16.6 million unfavorable movement in deferred financing costs, distribution equivalent rights and other, primarily due to deferred financing costs paid in association with ARP’s additional credit facility as a result of the acquisitions in 2012. The gross amount of borrowings and repayments under the revolving credit facilities included within net cash provided by financing activities in the combined consolidated statements of cash flows, which are generally in excess of net borrowings or repayments during the period or at period end, reflect the timing of cash receipts, which generally occur at specific intervals during the period and are utilized to reduce borrowings under the revolving credit facilities, and payments, which generally occur throughout the period and increase borrowings under the revolving credit facilities, for us and ARP, which is generally common practice for our and their industries.

ARP’s July 2012 acquisition of Titan in exchange for 3.8 million ARP common units and 3.8 million newly created convertible Class B preferred units (which had an estimated collective value of $193.2 million, based upon the closing price of ARP’s publicly traded units as of the acquisition close date) represented a non-cash transaction during the year ended December 31, 2012.

 

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Capital Requirements

Currently, our and our subsidiaries’ capital requirements are as follows:

Natural gas and oil production. The capital requirements of our and ARP’s natural gas and oil production consist primarily of:

 

•

maintenance capital expenditures—oil and gas assets naturally decline in future periods and, as such, we and ARP recognize the estimated capitalized cost of stemming such decline in production margin for the purpose of stabilizing our and ARP’s distributable cash flow and cash distributions, which we refer to as maintenance capital expenditures. We and ARP calculate the estimate of maintenance capital expenditures by first multiplying forecasted future full year production margin by expected aggregate production decline of proved developed producing wells. Maintenance capital expenditures are then the estimated capitalized cost of wells that will generate an estimated first-year margin equivalent to the production margin decline, assuming such wells are connected on the first day of the calendar year. We and ARP do not incur specific capital expenditures expressly for the purpose of maintaining or increasing production margin, but such amounts are a subset of hypothetical wells we and ARP expect to drill in future periods, including Marcellus Shale, Utica Shale, Mississippi Lime and Marble Falls wells, on undeveloped acreage already leased. Estimated capitalized cost of wells included within maintenance capital expenditures are also based upon relevant factors, including historical costs of similar wells and characteristics of each individual well. First-year margin from wells included within maintenance capital are also based upon relevant factors, including utilization of public forward commodity exchange prices, current estimates for regional pricing differentials, estimated labor and material rates and other production costs. Estimates for maintenance capital expenditures in the current year are the sum of the estimate calculated in the prior year plus estimates for the decline in production margin from wells connected during the current year and production acquired through acquisitions; and

 

•

expansion capital expenditures—we and ARP consider expansion capital expenditures to be any capital expenditure costs expended that are not maintenance capital expenditures—generally, this will include expenditures to increase, rather than maintain, production margin in future periods, as well as land, gathering and processing, and other non-drilling capital expenditures.

For the year ended December 31, 2015, we expect capital expenditures of $207.1 million, including maintenance capital expenditures to be $67.4 million. We anticipate financing our future capital expenditures through cash generated from operations, additional borrowings and capital raised through the Development Subsidiary and ARP’s Drilling Partnerships.

 

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The following table summarizes consolidated maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented (in thousands):

 

		Nine Months Ended September 30,								Years Ended December 31,
		2014				2013				2013				2012				2011
New Atlas Direct and Development Subsidiary
Maintenance capital expenditures		$	900			$	300			$	600			$	—			$	—
Expansion capital expenditures			11,341				1,531				3,343				—				—
Total		$	12,241			$	1,831			$	3,943			$	—			$	—
Atlas Resource Partners
Maintenance capital expenditures		$	46,300			$	21,000			$	31,500			$	10,200			$	9,833
Expansion capital expenditures			104,185				182,996				232,037				117,026				37,491
Total		$	150,485			$	203,996			$	263,537			$	127,226			$	47,324
Consolidated
Maintenance capital expenditures		$	47,200			$	21,300			$	32,100			$	10,200			$	9,833
Expansion capital expenditures			115,526				184,527				235,380				117,026				37,491
Total		$	162,726			$	205,827			$	267,480			$	127,226			$	47,324

New Atlas Direct and Development Subsidiary. During the nine months ended September 30, 2014, our total direct capital expenditures consisted primarily of the gathering and processing and during the year ended December 31, 2013, our total direct capital expenditures consisted primarily of gathering and processing, wells drilled, and leasehold acquisition costs. During the nine months ended September 30, 2014, and during the year ended December 31, 2013, Development Subsidiary’s total capital expenditures consisted primarily of the wells drilled and leasehold acquisition costs.

Atlas Resource Partners. During the nine months ended September 30, 2014, ARP’s $150.5 million of total capital expenditures consisted primarily of $64.9 million for wells drilled exclusively for its own account compared with $94.1 million for the comparable prior year period, $41.8 million of investments in its Drilling Partnerships compared with $64.4 million for the prior year comparable period, $18.3 million of leasehold acquisition costs compared with $17.6 million for the prior year comparable period, and $25.5 million of corporate and other costs compared with $27.9 million for the prior year comparable period, which primarily related to an increase in capitalized interest expense.

During the year ended December 31, 2013, ARP’s $263.5 million of total capital expenditures consisted primarily of $110.8 million for wells drilled exclusively for its own account compared with $27.3 million for the comparable prior year period, $92.3 million of investments in its Drilling Partnerships compared with $54.4 million for the prior year comparable period, $20.9 million of leasehold acquisition costs compared with $35.6 million for the prior year comparable period, and $39.5 million of corporate and other costs compared with $9.9 million for the prior year comparable period, which primarily related to an increase in capitalized interest expense.

During the year ended December 31, 2012, ARP’s $127.2 million of total capital expenditures consisted primarily of $54.4 million of investments in its Drilling Partnerships compared with $28.2 million for the prior year comparable period, $27.3 million for wells drilled exclusively for its own account compared with $0.6 million for the prior year comparable period, $35.6 million of leasehold acquisition costs compared with $9.5 million for the prior year comparable period, and $9.9 million of corporate and other compared with $9.0 million for the prior year comparable period. The increase in investments in ARP’s Drilling Partnerships was principally the result of the cancellation of the Fall 2010 drilling program and the resulting reduction of partnership capital deployed during 2011. Capital expenditures related to ARP’s investments in its Drilling Partnerships are generally incurred in the period subsequent to the period in which the funds were raised. The net increase in

 

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leasehold acquisition costs principally related to additional Marcellus Shale and Utica Shale acreage acquired through subsequent leasehold acquisitions in the region during the year ended December 31, 2012.

We and ARP continuously evaluate acquisitions of gas and oil assets. In order to make any acquisitions in the future, we and ARP believe we will be required to access outside capital either through debt or equity placements or through joint venture operations with other energy companies. There can be no assurance that we or ARP will be successful in our and ARP’s efforts to obtain outside capital.

As of September 30, 2014, we and our subsidiaries are committed to expending approximately $65.4 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

Off-Balance Sheet Arrangements

As of September 30, 2014, our off-balance sheet arrangements were limited to ARP’s letters of credit outstanding of $4.4 million, and commitments to spend $65.4 million related to capital expenditures.

ARP is the managing general partner of the Drilling Partnerships and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. ARP has structured certain Drilling Partnerships to allow limited partners to have the right to present their interests for purchase. Generally for Drilling Partnerships with this structure, ARP is not obligated to purchase more than 5% to 10% of the units in any calendar year, no units may be purchased during the first five years after closing for the Drilling Partnership, and ARP may immediately suspend the presentment structure for a Drilling Partnership by giving notice to the limited partners that it does not have adequate liquidity for redemptions. In accordance with the Drilling Partnership agreement, the purchase price for limited partner interests would generally be based upon a percentage of the present value of future cash flows allocable to the interest, discounted at 10%, as of the date of presentment, subject to estimated changes by ARP to reflect current well performance, commodity prices and production costs, among other items. Based on its historical experience, as of December 31, 2013, the management of ARP believes that any such estimated liability for redemptions of limited partner interests in Drilling Partnerships which allow such transactions would not be material.

Cash Distributions

Our board of directors intends to adopt a cash distribution policy that will require, pursuant to our amended and restated limited liability company agreement, that we distribute all of our available cash quarterly to our unitholders within 50 days following the end of each calendar quarter in accordance with their respective percentage interests. As a result, we expect that we will rely upon external financing sources, including commercial borrowings and other debt and common unit issuances, to fund our acquisition and expansion capital expenditures, as well as our working capital needs.

Atlas Resource Partners’ Cash Distribution Policy. ARP’s partnership agreement requires that it distribute 100% of available cash to its common and preferred unitholders and to us, as ARP’s general partner, within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all of ARP’s cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments. We, as ARP’s general partner, are granted discretion under the partnership agreement to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated.

On January 29, 2014, ARP’s board of directors approved a modification to its distribution payment practice to a monthly distribution program. This new policy took effect for the month of January 2014, for which its monthly cash distribution will be paid in March 2014. Monthly cash distributions will be paid approximately 45 days following the end of each respective monthly period.

 

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As of September 30, 2014, ARP’s partnership agreement provides that available cash will generally be distributed: first, 98% to ARP’s Class B preferred unitholders and 2% to us as general partner until there has been distributed to each Class B preferred unit the greater of $0.40 and the distribution payable to common unitholders; second, 98% to ARP’s Class C preferred unitholders and 2% to us as general partner until there has been distributed to each outstanding Class C preferred unit the greater of $0.51 and the distribution payable to common unitholders; thereafter, 98% to ARP’s common unitholders and 2% to us as general partner. These distribution percentages are modified to provide for incentive distributions to be paid to us, as ARP’s general partner, if quarterly distributions exceed specified targets. Incentive distributions are generally defined as all cash distributions paid to ARP’s general partner that are in excess of 2% of the aggregate amount of cash being distributed. The incentive distribution rights will entitle us to receive an increasing percentage of cash distributed by ARP as it reaches specified targets.

Credit Facilities

As of September 30, 2014, we had not guaranteed any of ARP’s debt obligations. As of September 30, 2014, our Development Subsidiary had no outstanding debt instruments or facilities.

Term Loan Facility

As of September 30, 2014, $148.5 million was outstanding under our term-loan credit facility, which we refer to as the “Term Facility.” The Term Facility has a maturity date of July 31, 2019. Borrowings under the Term Facility bear interest, at our election, at either an adjusted LIBOR rate plus an applicable margin of 5.50% per annum or the alternate base rate (as defined in the Term Facility) plus an applicable margin of 4.50% per annum. Interest is generally payable quarterly for alternate base rate loans and, for LIBOR loans at the interest periods selected by us. We are required to repay principal at the rate of $0.4 million per quarter commencing December 31, 2013 and continuing until the maturity date when the remaining balance is due. At September 30, 2014, the weighted average interest rate on our outstanding Term Facility borrowings was 6.5%.

The Term Facility contains customary covenants that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of our assets. The Term Facility also contains covenants that require (i) that we maintain a ratio of Total Funded Debt (as defined in the Term Facility) to EBITDA (as defined in the Term Facility), calculated over a period of four consecutive fiscal quarters, of not greater than 4.5 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2014; 4.0 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2015; and 3.5 to 1.0 for the last day of each of the quarters thereafter, and (ii) the entry into swap agreements with respect to the assets acquired in the EP Energy and Arkoma acquisitions. As of September 30, 2014, we were in compliance with these covenants. The events which constitute events of default are also customary for credit facilities of this nature, including payment defaults, breaches of representations, warranties or covenants, defaults in the payment of other indebtedness over a specified threshold, insolvency and change of control.

Our obligations under the Term Facility are secured by first priority security interests in substantially all of our assets, including all of the ownership interests in our material subsidiaries and our ownership interests in ARP. Additionally, our obligations under the Term Facility are guaranteed by our wholly owned subsidiaries and may be guaranteed by future subsidiaries. The Term Facility is subject to an intercreditor agreement, which provides for certain rights and procedures, between the lenders under the Term Facility and Atlas Energy’s credit facility, with respect to enforcement of rights, collateral and application of payment proceeds.

Atlas Resource Partners

On September 24, 2014, in connection with its Eagle Ford Acquisition (see Note 17—Subsequent Events), ARP entered into a fourth amendment to its revolving credit agreement with Wells Fargo Bank, National

 

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Association, as administrative agent, and the lenders party thereto (as so amended, the “ARP Credit Agreement”). The ARP Credit Agreement provides for a senior secured revolving credit facility with a syndicate of banks with a current borrowing base of $825.0 million and a maximum facility amount of $1.5 billion scheduled to mature in July 2018. The fourth amendment amends the ARP Credit Agreement to permit the guarantee by ARP of certain deferred purchase price obligations and contingent indemnity obligations in connection with the Eagle Ford Acquisition, and, with certain constraints, to permit ARP and its subsidiaries to enter into certain derivative instruments related to the producing wells acquired in the Eagle Ford Acquisition. At September 30, 2014, ARP had $660.0 million outstanding under its revolving credit facility.

ARP’s borrowing base under the revolving credit facility is scheduled for semi-annual redeterminations on May 1 and November 1 of each year. Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which $4.4 million was outstanding at September 30, 2014. ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries, and any of its non-guarantor subsidiaries are minor. Borrowings under the revolving credit facility bear interest, at ARP’s election, at either an adjusted LIBOR rate plus an applicable margin between 1.50% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.50% and 1.75% per annum. ARP is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.375% if less than 50% of the borrowing base is utilized and 0.5% if 50% or more of the borrowing base is utilized, which is included within interest expense on our consolidated statements of operations.

The ARP Credit Agreement contains customary covenants that limit ARP’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions, including a sale of all or substantially all of its assets. ARP was in compliance with these covenants as of September 30, 2014. The ARP Credit Agreement also requires ARP to maintain a ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to EBITDA (as defined in the ARP Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than 4.50 to 1.0 as of the last day of the quarters ended through December 31, 2014, 4.25 to 1.0 as of the last day of the quarter ending March 31, 2015, and 4.00 to 1.0 as of the last day of fiscal quarters ending thereafter and a ratio of current assets (as defined in the ARP Credit Agreement) to current liabilities (as defined in the ARP Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

Atlas Resource Partners Secured Hedge Facility

At September 30, 2014, ARP had a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under ARP’s revolving credit facility, ARP is required to utilize this secured hedge facility for future commodity risk management activity for its equity production volumes within the participating Drilling Partnerships. ARP, as general partner of the Drilling Partnerships, administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility and guarantees their obligations under it. Before executing any hedge transaction, a participating Drilling Partnership is required to, among other things, provide mortgages on its oil and gas properties and first priority security interests in substantially all of its assets to the collateral agent for the benefit of the counterparties. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions, including a sale of all or substantially all of its assets.

 

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In addition, it will be an event of default under ARP’s revolving credit facility if ARP, as general partner of the Drilling Partnerships, breaches an obligation governed by the secured hedge facility and the effect of such breach is to cause amounts owing under swap agreements governed by the secured hedge facility to become immediately due and payable.

Atlas Resource Partners Senior Notes

At September 30, 2014, ARP had $374.5 million outstanding of its 7.75% senior unsecured notes due 2021 (“7.75% ARP Senior Notes”), inclusive of an additional $100.0 million of such notes in a private placement transaction on June 2, 2014 at an offering price of 99.5% of par value, yielding net proceeds of approximately $97.4 million. The net proceeds were used to partially fund the Rangely Acquisition. ARP issued $275.0 million of its 7.75% ARP Senior Notes in a private placement transaction at par on January 23, 2013. The 7.75% ARP Senior Notes were presented net of a $0.5 million unamortized discount as of September 30, 2014. Interest is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable for up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price as defined in the governing indenture, plus accrued and unpaid interest and additional interest, if any. On and after January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019.

ARP entered into registration rights agreements with respect to the $100.0 million 7.75% ARP Senior Notes issued in June 2014. Under the registration rights agreements, ARP will cause to be filed with the SEC registration statements with respect to an offer to exchange the 7.75% ARP Senior Notes for substantially identical notes that are registered under the Securities Act. ARP will use reasonable best efforts to cause such exchange offer registration statement to become effective under the Securities Act. In addition, ARP will use reasonable best efforts to cause an exchange offer to be consummated not later than 270 days after the issuance of the 7.75% ARP Senior Notes. Under some circumstances, in lieu of, or in addition to, a registered exchange offer, ARP has agreed to file a shelf registration statement with respect to the 7.75% ARP Senior Notes. ARP is required to pay additional interest if it fails to comply with its obligations to register the 7.75% ARP Senior Notes within the specified time periods.

At September 30, 2014, ARP had $248.5 million outstanding of its 9.25% senior unsecured notes due 2021 (“9.25% ARP Senior Notes”). The net proceeds were used to partially fund the EP Energy Acquisition. The 9.25% ARP Senior Notes were presented net of a $1.5 million unamortized discount as of September 30, 2014. Interest on the 9.25% Senior Notes is payable semi-annually on February 15 and August 15. At any time on or after August 15, 2017, ARP may redeem some or all of the 9.25% ARP Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 102.313%, and on or after August 15, 2019, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 100.0%. In addition, at any time prior to August 15, 2016, ARP may redeem up to 35% of the 9.25% ARP Senior Notes with the proceeds received from certain equity offerings at a redemption price of 109.250%. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 9.25% ARP Senior Notes.

In connection with the issuance of the 9.25% ARP Senior Notes, ARP entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by July 30, 2014. On March 28, 2014, the registration statement relating to the exchange offer for the 9.25% ARP Senior Notes was declared effective, and the exchange offer was completed on April 29, 2014.

 

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The 9.25% ARP Senior Notes and 7.75% ARP Senior Notes are guaranteed by certain of ARP’s material subsidiaries. The guarantees under the 9.25% ARP Senior Notes and 7.75% ARP Senior Notes are full and unconditional and joint and several, and any of ARP’s subsidiaries, other than the subsidiary guarantors, are minor. There are no restrictions on ARP’s ability to obtain cash or any other distributions of funds from the guarantor subsidiaries.

The indentures governing the 9.25% ARP Senior Notes and 7.75% ARP Senior Notes contain covenants, including limitations on ARP’s ability to incur certain liens; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. ARP was in compliance with these covenants as of September 30, 2014.

Contractual Obligations and Commercial Commitments

The following tables summarize our and ARP’s contractual obligations at December 31, 2013 (in thousands):

 

						Payments Due By Period
		Total				Less than 1 Year				1 – 3 Years				4 – 5 Years				After 5 Years
Contractual cash obligations:
New Atlas total debt		$	149,625			$	1,500			$	4,500			$	3,000			$	140,625
ARP total debt			944,000				—				—				419,000				525,000
New Atlas interest on total debt			64,027				9,726				29,177				19,451				5,673
ARP interest on total debt			372,246				54,445				108,890				104,695				104,216
ARP operating leases			18,790				3,903				5,685				4,062				5,140
Total contractual cash obligations		$	1,548,688			$	69,574			$	148,252			$	550,208			$	780,654
						Amount of Commitment Expiration Per Period
		Total				Less than 1 Year				1 – 3 Years				4 – 5 Years				After 5 Years
Other commercial commitments:
ARP standby letters of credit		$	3,562			$	3,562			$	—			$	—			$	—
ARP other commercial commitments(1)			27,840				13,104				12,985				1,388				363
Development Subsidiary commercial commitments(2)			2,049				2,049				—				—				—
Total commercial commitments		$	33,451			$	18,715			$	12,985			$	1,388			$	363

 

(1)

ARP’s other commercial commitments include ARP’s share of drilling and completion commitments and ARP’s throughput contracts, including firm transportation obligations for natural gas as a result of ARP’s EP Energy Acquisition. See “Business—Contractual Revenue Arrangements” for a description of ARP’s firm transportation obligations.

(2)	Development Subsidiary commercial commitments include Development Subsidiary’s share of drilling and completion commitments.

Issuance of Units

We recognize gains on ARP’s equity transactions as credits to equity on our combined consolidated balance sheets rather than as income on our combined consolidated statements of operations. These gains represent our portion of the excess net offering price per unit of each of ARP’s common units over the book carrying amount per unit.

 

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Equity Offerings

In August 2014, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of the several banks named therein (the “Agents”). Pursuant to the equity distribution agreement, ARP may sell from time to time through the Agents common units representing limited partner interests of ARP having an aggregate offering price of up to $100.0 million. Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act, including sales made directly on the New York Stock Exchange, the existing trading market for the common units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP will pay each of the Agents a commission, which in each case shall not be more than 2.0% of the gross sales price of common units sold through such Agent. Under the terms of the equity distribution agreement, ARP may also sell common units from time to time to any Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to an Agent as principal would be pursuant to the terms of a separate terms agreement between ARP and such Agent. As of September 30, 2014, no units have been sold under this program.

In May 2014, in connection with the closing of the Rangely Acquisition, ARP issued 15,525,000 of its common limited partner units (including 2,025,000 units pursuant to an over-allotment option) in a public offering at a price of $19.90 per unit, yielding net proceeds of approximately $297.5 million. The units were registered under the Securities Act, pursuant to a shelf registration statement on Form S-3, which was automatically effective on the filing date of February 3, 2014.

In March 2014, ARP issued 6,325,000 of its common limited partner units (including 825,000 units pursuant to an over-allotment option) in a public offering at a price of $21.18 per unit, yielding net proceeds of approximately $129.1 million. The units were registered under the Securities Act, pursuant to a shelf registration statement on Form S-3, which was automatically effective on the filing date of February 3, 2014.

In July 2013, in connection with ARP’s EP Energy Acquisition, ARP issued 3,749,986 newly created Class C convertible preferred units to us, at a negotiated price per unit of $23.10, for proceeds of $86.6 million. The Class C preferred units were issued with 562,497 warrants to purchase ARP common units at an exercise price of $23.10 at our option beginning on October 29, 2013. The warrants will expire on July 31, 2016. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act.

Upon issuance of the Class C preferred units and warrants on July 31, 2013, ARP entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class C preferred units and upon exercise of the warrants. ARP agreed to use commercially reasonable efforts to file such registration statement within 90 days of the conversion of the Class C preferred units into common units or the exercise of the warrants.

In June 2013, in connection with the EP Energy Acquisition, ARP sold an aggregate of 14,950,000 of its common limited partner units (including 1,950,000 units pursuant to an over-allotment option) in a public offering at a price of $21.75 per unit, yielding net proceeds of approximately $313.1 million. ARP utilized the net proceeds from the sale to repay the outstanding balance under its revolving credit facility.

In May 2013, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of several banks. Pursuant to the equity distribution agreement, ARP could sell, from time to time through the agents, common units having an aggregate offering price of up to $25.0 million. During the year ended December 31, 2013, ARP issued 309,174 common limited partner units under the equity distribution program for net proceeds of $6.9 million, net of $0.4 million in commissions paid. ARP utilized the net proceeds from the sale to repay borrowings outstanding under its revolving credit facility. ARP terminated its equity distribution agreement effective December 27, 2013.

In November 2012 and December 2012, in connection with entering into a purchase agreement to acquire certain producing wells and net acreage from DTE, ARP sold an aggregate of 7,898,210 of its common limited partner units in a public offering at a price of $23.01 per unit, yielding net proceeds of approximately $174.5

 

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million. ARP utilized the net proceeds from the sale to repay a portion of the outstanding balance under its revolving credit facility and $2.2 million under its then-existing term loan credit facility.

In July 2012, ARP completed the acquisition of certain proved reserves and associated assets in the Barnett Shale from Titan in exchange for 3.8 million of ARP’s common units and 3.8 million newly-created ARP convertible Class B preferred units (which have an estimated collective value of $193.2 million, based upon the closing price of ARP’s publicly traded common units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments. The Class B preferred units are voluntarily convertible to common units on a one-for-one basis within three years of the acquisition closing date at a strike price of $26.03 plus all unpaid preferred distributions per unit, and will be mandatorily converted to common units on the third anniversary of the issuance. While outstanding, the preferred units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. On September 19, 2012, ARP filed a registration statement with the SEC in satisfaction of the registration requirements of the registration rights agreement, and the registration statement was declared effective by the SEC on October 2, 2012.

In April 2012, ARP completed the acquisition of certain oil and gas assets from Carrizo. To partially fund the acquisition, ARP sold 6.0 million of its common units in a private placement at a negotiated purchase price per unit of $20.00, for net proceeds of $119.5 million, of which $5.0 million was purchased by certain of our executives. The common units issued by ARP were subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement stipulated that ARP would (a) file a registration statement with the SEC by October 30, 2012 and (b) cause the registration statement to be declared effective by the SEC by December 31, 2012. On July 11, 2012, ARP filed a registration statement with the SEC for the common units subject to the registration rights agreement in satisfaction of the registration requirements of the registration rights agreement and on August 28, 2012, the registration statement was declared effective by the SEC.

In connection with the issuance of ARP’s unit offerings during the nine months ended September 30, 2014 and the years ended December 31, 2013 and 2012, we recorded gains of $40.7 million, $27.3 million and $66.6 million, respectively, within equity and a corresponding decrease in non-controlling interests on our combined consolidated balance sheets and combined consolidated statement of equity.

ARP Common Unit Distribution

In February 2012, the board of directors of Atlas Energy’s general partner approved the distribution of approximately 5.24 million ARP common units, which were distributed on March 13, 2012 to Atlas Energy unitholders using a ratio of 0.1021 ARP limited partner units for each of our common units owned on the record date of February 28, 2012.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a publicly traded partnership, we will be required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal controls over financial reporting. Though we will be required to disclose changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal controls over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a publicly traded partnership, we will need to implement additional internal controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

 

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Further, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal controls over financial reporting until the year following our first annual report required to be filed with the SEC. If it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed or operating. Our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future.

We have no history operating as a publicly traded company. As a public company with listed equity securities, we will need to comply with new laws, regulations and requirements, including certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will require a significant amount of time from our board of directors and management and will significantly increase our legal and financial compliance costs and make such compliance more time-consuming and costly. We will need to:

 

•

institute a more comprehensive compliance function;

 

•

design, establish, evaluate and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;

 

•

comply with rules promulgated by the New York Stock Exchange;

 

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prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

 

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establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;

 

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involve and retain to a greater degree outside counsel and accountants in the above-listed activities; and

 

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establish an investor relations function.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point in time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include revenue and expense accruals, depletion, depreciation and amortization, asset impairment, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired.

The critical accounting policies and estimates we have identified are discussed below.

Depreciation and Impairment of Long-Lived Assets and Goodwill

Long-Lived Assets. The cost of property, plant and equipment, less estimated salvage value, is generally depreciated on a straight-line basis over the estimated useful lives of the assets. Useful lives are based on historical experience and are adjusted when changes in planned use, technological advances or other factors indicate that a different life would be more appropriate. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively.

 

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Long-lived assets, other than goodwill and intangibles with infinite lives, generally consist of natural gas and oil properties and pipeline, processing and compression facilities and are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. A long-lived asset, other than goodwill and intangibles with infinite lives, is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. The undiscounted net cash flows expected to be generated by the asset are based upon our estimates that rely on various assumptions, including natural gas and oil prices, and production and operating expenses. Any significant variance in these assumptions could materially affect the estimated net cash flows expected to be generated by the asset. Declines in natural gas prices may result in impairment charges in future periods.

There were no impairments of proved or unproved gas and oil properties recorded for the nine months ended September 30, 2014 and 2013. During the year ended December 31, 2013, ARP recognized $38.0 million of asset impairments related to gas and oil properties within property, plant and equipment, net on our combined consolidated balance sheet primarily for its shallow natural gas wells in the New Albany Shale and unproved acreage in the Chattanooga Shale and the New Albany Shale. During the year ended December 31, 2012, ARP recognized $9.5 million of asset impairments related to gas and oil properties within property, plant and equipment, net on our combined consolidated balance sheet for shallow natural gas wells in the Antrim Shale and the Niobrara Shale. During the year ended December 31, 2011, ARP recognized $7.0 million of asset impairment related to gas and oil properties within property, plant and equipment, net on our combined consolidated balance sheet for shallow natural gas wells in the Niobrara Shale. These impairments related to the carrying amount of these gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2013, 2012 and 2011 and ARP’s intention not to drill on certain expiring unproved acreage. The estimate of fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. Additional factors impacting the economic viability of long-lived assets are discussed under the section “Forward-Looking Statements” beginning on page 66.

Goodwill and Intangibles with Infinite Lives. Goodwill and intangibles with infinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment loss should be recognized if the carrying value of an entity’s reporting units exceeds its estimated fair value.

There were no goodwill impairments recognized by ARP during the nine months ended September 30, 2014 and 2013 and the years ended December 31, 2013, 2012 or 2011.

Fair Value of Financial Instruments

We and our subsidiaries have established a hierarchy to measure our financial instruments at fair value, which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

 

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Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

We use a fair value methodology to value the assets and liabilities for our and our subsidiaries’ outstanding derivative contracts and our rabbi trust assets. Our and ARP’s commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. Investments held in our rabbi trust are publicly traded equity and debt securities and are therefore defined as Level 1 fair value measurements.

Liabilities that are required to be measured at fair value on a nonrecurring basis include our asset retirement obligations that are defined as Level 3. Estimates of the fair value of asset retirement obligations are based on discounted cash flows using numerous estimates, assumptions, and judgments regarding the cost, timing of settlement, our credit-adjusted risk-free rate and inflation rates.

During the nine months ended September 30, 2014, ARP completed the Rangely Acquisition and the GeoMet Acquisition. During the year ended December 31, 2013, we completed the Arkoma Acquisition and ARP completed the EP Energy Acquisition. During the year ended December 31, 2012, ARP completed the acquisitions of certain oil and gas assets from Carrizo, certain proved reserves and associated assets from Titan, Equal and DTE. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under our and ARP’s existing methodology for recognizing an estimated liability for the plugging and abandonment of our and its gas and oil wells. These inputs require significant judgments and estimates by our and ARP’s management at the time of the valuation and are subject to change.

Reserve Estimates

Estimates of proved natural gas, oil and natural gas liquids reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas, oil and natural gas liquids prices, drilling and operating expenses, capital expenditures and availability of funds. The accuracy of these reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. As discussed in “Summary Reserve Data” beginning on page 29, we and ARP engaged Wright & Company, Inc., an independent third-party reserve engineer, to prepare a report of our and ARP’s proved reserves.

Any significant variance in the assumptions utilized in the calculation of reserve estimates could materially affect the estimated quantity of reserves. As a result, estimates of proved natural gas, oil and natural gas liquids reserves are inherently imprecise. Actual future production, natural gas, oil and natural gas liquids prices, revenues, development expenditures, operating expenses and quantities of recoverable natural gas, oil and natural gas liquids reserves may vary substantially from our estimates or estimates contained in the reserve reports and may affect our and ARP’s ability to pay amounts due under our and ARP’s credit facilities or cause a reduction in our or ARP’s credit facilities. In addition, proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing natural gas, oil and natural gas liquids prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control. Reserves and their relation to estimated future net cash flows impact the calculation of impairment and depletion of oil and gas properties. Adjustments to quarterly depletion rates, which are based upon a units of production method, are made concurrently with changes to reserve estimates. Generally, an increase or decrease in reserves without a corresponding change in capitalized costs will have a corresponding inverse impact to depletion expense.

 

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Asset Retirement Obligations

We and our subsidiaries estimate the cost of future dismantlement, restoration, reclamation and abandonment of our operating assets.

We and ARP recognize an estimated liability for the plugging and abandonment of gas and oil wells and related facilities. We and ARP also recognize a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. We and ARP also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Since there are many variables in estimating asset retirement obligations, we and ARP attempt to limit the impact of management’s judgment on certain of these variables by developing a standard cost estimate based on historical costs and industry quotes updated annually. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. Neither we nor ARP have any assets legally restricted for purposes of settling asset retirement obligations. Except for gas and oil properties, there are no other material retirement obligations associated with our and ARP’s tangible long-lived assets.

Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our and our subsidiaries’ potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and commodity prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we and our subsidiaries view and manage our ongoing market risk exposures. All of the market risk-sensitive instruments were entered into for purposes other than trading.

General

All of our and our subsidiaries’ assets and liabilities are denominated in U.S. dollars, and as a result, we do not have exposure to currency exchange risks.

We and our subsidiaries are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We and our subsidiaries manage these risks through regular operating and financing activities and periodic use of derivative financial instruments such as forward contracts and interest rate cap and swap agreements. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on September 30, 2014. Only the potential impact of hypothetical assumptions was analyzed. The analysis does not consider other possible effects that could impact our and our subsidiaries’ business.

Current market conditions elevate our and ARP’s concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us and ARP, if any. The counterparties related to our and ARP’s commodity derivative contracts are banking institutions or their affiliates, who also participate in ARP’s revolving credit facilities. The creditworthiness of us and ARP’s counterparties is constantly monitored, and we and ARP currently believe them to be financially viable. Our and ARP’s subsidiaries are not aware of any inability on the part of their counterparties to perform under their contracts and believe our and ARP’s exposure to non-performance is remote.

 

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Interest Rate Risk. As of September 30, 2014, we had $148.5 million of outstanding borrowings under our Term Facility and ARP had $660.0 million of outstanding borrowings under its revolving credit facility. Holding all other variables constant, a hypothetical 100 basis-point or 1% change in variable interest rates would change our consolidated interest expense for the twelve-month period ending September 30, 2014 by $8.1 million, excluding the effect of non-controlling interests.

Commodity Price Risk. Our and ARP’s market risk exposures to commodities are due to the fluctuations in the commodity prices and the impact those price movements have on our and our subsidiaries’ financial results. To limit the exposure to changing commodity prices, we and our subsidiaries use financial derivative instruments, including financial swap and option instruments, to hedge portions of future production. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under these swap agreements, we and our subsidiaries receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, but not the obligation, to purchase or sell commodities at a fixed price for the relevant period.

Holding all other variables constant, including the effect of commodity derivatives, a 10% change in average commodity prices would result in a change to our consolidated operating income for the twelve-month period ending September 30, 2015 of approximately $6.8 million, net of non-controlling interests.

Realized pricing of natural gas, oil, and natural gas liquids production is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas, oil and natural gas liquids production. Pricing for natural gas, oil and natural gas liquids production has been volatile and unpredictable for many years. To limit our and our subsidiaries’ exposure to changing natural gas, oil and natural gas liquids prices, we enter into natural gas and oil swap, put option and costless collar option contracts. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter (“OTC”) futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. OTC contracts are generally financial contracts which are settled with financial payments or receipts and generally do not require delivery of physical hydrocarbons. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. Natural gas liquids fixed price swaps are priced based on a WTI crude oil index, while other natural gas liquids contracts are based on an OPIS Mt. Belvieu index. These contracts have qualified and been designated as cash flow hedges and been recorded at their fair values.

As of September 30, 2014, we had the following commodity derivatives:

Natural Gas—Fixed Price Swaps

 

Production Period Ending December 31,		Volume				Average Fixed Price
		(MMBtu)(1)				(per MMBtu)(1)
2014			690,000			$	4.177
2015			2,280,000			$	4.302
2016			1,440,000			$	4.433
2017			1,200,000			$	4.590
2018			420,000			$	4.797

 

(1)	“MMBtu” represents million British Thermal Units.

 

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As of September 30, 2014, ARP had the following commodity derivatives:

Natural Gas—Fixed Price Swaps

 

Production Period Ending December 31,		Volume				Average Fixed Price
		(MMBtu)(1)				(per MMBtu)(1)
2014			15,038,200			$	4.152
2015			51,924,500			$	4.239
2016			45,746,300			$	4.311
2017			24,840,000			$	4.532
2018			9,360,000			$	4.619

Natural Gas—Costless Collars

 

Production Period Ending December 31,		Option Type		Volume				Average Floor and Cap
				(MMBtu)(1)				(per MMBtu)(1)
2014		Puts purchased			960,000			$	4.221
2014		Calls sold			960,000			$	5.120
2015		Puts purchased			3,480,000			$	4.234
2015		Calls sold			3,480,000			$	5.129

Natural Gas—Put Options—Drilling Partnerships

 

Production Period Ending December 31,		Option Type		Volume				Average Fixed Price
				(MMBtu)(1)				(per MMBtu)(1)
2014		Puts purchased			450,000			$	3.800
2015		Puts purchased			1,440,000			$	4.000
2016		Puts purchased			1,440,000			$	4.150

Natural Gas—WAHA Basis Swaps

 

Production Period Ending December 31,		Volume				Average Fixed Price
		(MMBtu)(1)				(per MMBtu)(1)
2014			2,700,000			$	(0.110	)
2015			3,000,000			$	(0.068	)

Natural Gas—NGPL Basis Swaps

 

Production Period Ending December 31,		Volume				Average Fixed Price
		(MMBtu)(1)				(per MMBtu)(1)
2014			2,250,000			$	(0.108	)

Natural Gas Liquids—Natural Gasoline Fixed Price Swaps

 

Production Period Ending December 31,		Volume				Average Fixed Price
		(Bbl)(1)				(per Bbl)(1)
2014			1,386,000			$	2.123
2015			5,040,000			$	1.983

 

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Natural Gas Liquids—Ethane Fixed Price Swaps

 

Production Period Ending December 31,		Volume				Average Fixed Price
		(Gal)(1)				(per Gal)(1)
2014			630,000			$	0.303

Natural Gas Liquids—Propane Fixed Price Swaps

 

Production Period Ending December 31,		Volume				Average Fixed Price
		(Gal)(1)				(per Gal)(1)
2014			3,087,000			$	1.000
2015			8,064,000			$	1.016

Natural Gas Liquids—Butane Fixed Price Swaps

 

Production Period Ending December 31,		Volume				Average Fixed Price
		(Gal)(1)				(per Gal)(1)
2014			378,000			$	1.308
2015			1,512,000			$	1.248

Natural Gas Liquids—Iso Butane Fixed Price Swaps

 

Production Period Ending December 31,		Volume				Average Fixed Price
		(Gal)(1)				(per Gal)(1)
2014			378,000			$	1.323
2015			1,512,000			$	1.263

Natural Gas Liquids—Crude Oil Fixed Price Swaps

 

Production Period Ending December 31,		Volume				Average Fixed Price
		(Bbl)(1)				(per Bbl)(1)
2016			84,000			$	85.651
2017			60,000			$	83.780

Crude Oil—Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price
		(Bbl)(1)				(per Bbl)(1)
2014			439,500			$	95.090
2015			1,743,000			$	90.645
2016			1,029,000			$	88.650
2017			492,000			$	87.752
2018			360,000			$	88.283

 

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Crude Oil—Costless Collars

 

Production Period Ending December 31,		Option Type		Volume				Average Floor and Cap
				(Bbl)(1)				(per Bbl)(1)
2014		Puts purchased			20,580			$	84.169
2014		Calls sold			20,580			$	113.308
2015		Puts purchased			29,250			$	83.846
2015		Calls sold			29,250			$	110.654

 

(1)	“MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons.

 

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BUSINESS

Overview

We are a Delaware limited liability company formed in October 2011 by Atlas Energy to serve as the general partner of Atlas Resource Partners, which is described below. Following the separation, we will hold Atlas Energy’s assets and businesses other than those not related to its “Atlas Pipeline Partners” segment, including holding the following:

 

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the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in Atlas Resource Partners (which is also referred to as “ARP”), a publicly traded Delaware master limited partnership and an independent developer and producer of natural gas, crude oil and NGLs, with operations in basins across the United States. ARP sponsors and manages tax-advantaged investment partnerships, in which it coinvests, to finance a portion of its natural gas and oil production activities. As of January 1, 2015, we owned 100% of the general partner Class A units and all of the incentive distribution rights in ARP, and Atlas Energy owned an approximate 27.7% limited partner interest (consisting of 20,962,485 common and 3,749,986 preferred limited partner units) in ARP;

 

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Atlas Energy’s general partner and limited partner interests in the Development Subsidiary, a partnership that currently conducts natural gas and oil operations initially in the mid-continent region of the United States. As of January 1, 2015, Atlas Energy owned a 1.7% limited partner interest in the Development Subsidiary and 80.0% of its outstanding general partner Class A units, which are entitled to receive 2.0% of the cash distributed without any obligation to make further capital contributions;

 

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Atlas Energy’s interests in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, its general partner, which incubate new MLPs and invest in existing MLPs. At January 1, 2015, Atlas Energy had an approximate 15.9% general partner interest and 12.0% limited partner interest in Lightfoot; and

 

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direct natural gas development and production assets in the Arkoma Basin, which Atlas Energy acquired in July 2013.

Our goal is to increase the distributions to our unitholders by continuing to grow the net production from our direct natural gas production business as well as the distributions paid to us by the MLPs in which we own interests. Atlas Energy, together with its predecessors and affiliates, has been involved in the energy industry since 1968. The Atlas Energy personnel currently responsible for managing our assets and capital raising will continue to do so and will become our employees upon completion of the separation and distribution.

Overview of ARP

ARP is a publicly traded Delaware master limited partnership and an independent developer and producer of natural gas, crude oil and NGLs, with operations in basins across the United States. ARP is a leading sponsor and manager of tax-advantaged investment partnerships, also referred to as “Drilling Partnerships,” in which ARP co-invests, to finance a portion of its natural gas, crude oil and NGL production activities. We are the general partner of ARP and manage its businesses. As of December 1, 2014, we own 100% of ARP’s general partner Class A units, all of ARP’s incentive distribution rights and approximately 27.7% of ARP’s outstanding limited partner interest.

In February 2012, the board of directors of Atlas Energy’s general partner approved the formation of ARP as a newly created exploration and production master limited partnership and the related transfer of substantially all of Atlas Energy’s natural gas and oil development and production assets at that time and the partnership management business to ARP on March 5, 2012.

ARP’s primary business objective is to generate growing yet stable cash flows through the development and acquisition of mature, long-lived natural gas, oil and NGL properties. As of December 31, 2013, ARP’s

 

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estimated proved reserves were 1.2 Tcfe, including the reserves net to its equity interest in Drilling Partnerships. Of ARP’s estimated proved reserves, approximately 68% were proved developed and approximately 83% were natural gas. For the year ended December 31, 2013, ARP’s average daily net production was approximately 187.7 MMcfe.

Overview of our Development Subsidiary

During the year ended December 31, 2013, Atlas Energy formed a new partnership subsidiary to conduct natural gas and oil operations, initially in the mid-continent region of the United States. Since its formation, the Development Subsidiary has conducted operations in the Marble Falls formation in the Fort Worth Basin, where it has drilled 13 wells, and in the Mississippi Lime area of the Anadarko Basin in Oklahoma, where it has participated in two non-operated wells. At January 1, 2015, the Development Subsidiary had capital contributions of $120.6 million, including $2.0 million from Atlas Energy to acquire its limited partner interest. Our Development Subsidiary also entered into a purchase and sale agreement to acquire interests in oil and gas assets in the Eagle Ford Shale in South Central Atascosa County, Texas, which closed on November 5, 2014. As of December 1, 2014, we own an approximate 80.0% interest in the Development Subsidiary’s general partner and a 1.7% limited partner interest in the Development Subsidiary.

Overview of Lightfoot

Lightfoot is a private investment vehicle that focuses on investing directly in master limited partnership-qualifying businesses and assets. Lightfoot investors include affiliates of, and funds under management by, GE EFS, Atlas Energy, L.P., BlackRock Investment Management, LLC, Magnetar Financial LLC, CorEnergy Infrastructure Trust, Inc. and Triangle Peak Partners Private Equity, LP. As of January 1, 2015, we own an approximate 15.9% interest in Lightfoot’s general partner and a 12.0% interest in Lightfoot’s limited partner.

Lightfoot’s stated strategy is to make investments by partnering with, promoting and supporting strong management teams to build growth-oriented businesses or industry verticals. Lightfoot provides extensive financial and industry relationships and significant master limited partnership experience, which assist in growth via acquisitions and development projects by identifying:

 

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efficient operating platforms with deep industry relationships;

 

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significant expansion opportunities through add-on acquisitions and development projects;

 

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stable cash flows with fee-based income streams, limited commodity exposure and long-term contracts; and

 

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scalable platforms and opportunities with attractive fundamentals and visible future growth.

On November 6, 2013, ARCX, a master limited partnership owned and controlled by Lightfoot Capital Partners, L.P., began trading publicly on the NYSE. ARCX is focused on the terminalling, storage, throughput and transloading of crude oil and petroleum products in the East Coast, Gulf Coast and Midwest regions of the United States. ARCX’s cash flows are primarily fee-based under multi-year contracts. Lightfoot has a significant interest in ARCX through its ownership of a 40.3% limited partner interest, Lightfoot Capital Partners, G.P., the general partner, and all of Lightfoot’s incentive distribution rights. Lightfoot intends to utilize ARCX to facilitate future organic expansions and acquisitions for its energy logistics business.

Overview of Direct Natural Gas and Oil Production

Our consolidated gas and oil production operations consist of various shale plays in the United States, both through ARP and the Development Subsidiary and through assets that we own directly. Our direct natural gas and oil production results from certain coal-bed methane-producing natural gas assets in the Arkoma Basin that Atlas Energy acquired on July 31, 2013 from EP Energy E&P Company, L.P., which we refer to as “EP Energy,”

 

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for $64.5 million, net of purchase price adjustments. We refer to this transaction as the “Arkoma Acquisition.” As a result of the Arkoma Acquisition, we have ownership interests in approximately 600 wells in the Arkoma Basin in eastern Oklahoma with average daily production of 5.1 MMcfe for the year ended December 31, 2013.

Business Strategy

Our goal is to increase the distributions to our unitholders by continuing to grow the net production from our direct natural gas and oil production business as well as the distributions paid to us by the MLPs in which we own interests. The key elements of our business strategy are to:

 

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Increase cash available for distributions to our unitholders. Our primary business objective is to increase the amount of cash distributed to us by ARP, as well as our other subsidiaries, which we can then distribute to our unitholders. We own the general partner interest and IDRs in ARP and generate substantial cash flow from the distributions we receive on these interests.

 

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Actively assist our subsidiaries in executing their business strategies. We are actively engaged in the management of ARP and our other subsidiaries and assist them in identifying, evaluating and pursuing growth strategies, acquisitions and capital-raising opportunities. Our employees manage ARP’s daily activities on ARP. In addition, Jonathan Cohen, our Executive Chairman, is chairman of the board of Lightfoot’s general partner.

 

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Expand operations through strategic acquisitions. We continually evaluate opportunities to expand our and ARP’s operations through acquisitions of developed and undeveloped properties or companies that can increase our cash available for distribution. We will continue to seek strategic opportunities in our and ARP’s current areas of operation, as well as other regions of the United States. In the first half of 2014, ARP acquired certain coal-bed methane producing natural gas assets in West Virginia and Virginia and low-decline oil and NGL assets in the Rangeley field in northwest Colorado. In September 2014, our Development Subsidiary and ARP entered into a purchase and sale agreement to acquire interests in oil and natural gas assets in the Eagle Ford Shale in South Central Atascosa County, Texas.

 

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Expand our natural gas and oil production. We and ARP generate a significant portion of our respective revenue and net cash flow from natural gas and oil production. We believe ARP’s program of sponsoring investment partnerships to exploit its acreage opportunities provides it with enhanced economic returns, which we participate in through our ownership of ARP’s IDRs and general partner interest. We intend for ARP to continue to finance the majority of its drilling and production activities through these investment partnerships. In addition, the Development Subsidiary has completed 13 wells in the Marble Falls play and participated in two non-operated wells in the Mississippi Lime play, and we operate select assets in the Arkoma Basin.

 

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Expand ARP’s fee-based revenue through its sponsorship of Drilling Partnerships. ARP generates substantial revenue and cash flow from fees paid by the Drilling Partnerships to ARP for acting as the managing general partner. As ARP continues to sponsor Drilling Partnerships, we expect that ARP’s fee revenues from its drilling and operating agreements with its Drilling Partnerships will increase and will continue to add stability to its revenue and cash flows.

 

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Continue to maintain control of operations and costs. We believe it is important to be the operator of wells in which we, ARP or ARP’s Drilling Partnerships have an interest because we believe it will allow us and ARP to achieve operating efficiencies and control costs. As operators, we and ARP are better positioned to control the timing and plans for future enhancement and exploitation efforts, costs of enhancing, drilling, completing and producing the well, and marketing negotiations for natural gas, oil and NGL production to maximize both volumes and wellhead price. Through our management of ARP, we were the operator of the vast majority of the properties in which ARP or ARP’s Drilling Partnerships had a working interest as of September 30, 2014.

 

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•

Continue to manage our exposure to commodity price risk. To limit our and ARP’s exposure to changing commodity prices and enhance and stabilize cash flow, we and ARP use financial hedges for a portion of our and ARP’s natural gas and oil production. We and ARP principally use fixed price swaps and collars as the mechanism for the financial hedging of commodity prices.

Competitive Strengths

We believe our and ARP’s competitive strengths favorably position us to execute our business strategy and to maintain and grow our distributions to unitholders. Our and ARP’s competitive strengths are:

 

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We and ARP have a high quality, long-lived reserve base. Our and ARP’s natural gas and oil properties are located principally in the Barnett Shale, the Mississippi Lime, the Raton, Black Warrior, Fort Worth, Arkoma and Appalachian basins and the Rangely field, and are characterized by long-lived reserves, generally favorable pricing for our and ARP’s production and readily available transportation.

 

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We have significant experience in making accretive acquisitions. Our management team has extensive experience in consummating accretive acquisitions. We believe we will be able to generate acquisition opportunities of both producing and non-producing properties through our management’s extensive industry relationships. We intend to use these relationships and experience to find, evaluate and execute on acquisition opportunities.

 

•

We have significant engineering, geologic and management experience. Atlas Energy’s technical team of geologists and engineers has extensive industry experience. We believe that we have been one of the most active drillers in ARP’s core operating areas and, as a result, that we have accumulated extensive geological and geographical knowledge about the area. We have also added geologists and engineers to our technical staff who have significant experience in other productive basins within the continental United States, which enables us to evaluate and, as evidenced by the EP Energy acquisition, expand our core operating areas.

 

•

ARP is one of the leading sponsors of tax-advantaged Drilling Partnerships. ARP and its predecessors have sponsored limited and general partnerships to raise funds from investors to finance development drilling activities since 1968, and we believe that ARP is one of the leading sponsors of such Drilling Partnerships in the country. We believe that ARP’s lengthy association with many of the broker-dealers that act as placement agents for Drilling Partnerships provide ARP with a competitive advantage over entities with similar operations. We also believe that ARP’s sponsorship of Drilling Partnerships has allowed ARP to generate attractive returns on drilling, operating and production activities.

 

•

Fee-based revenues from ARP’s Drilling Partnerships and our and ARP’s substantially hedged production provide protection from commodity price volatility. ARP’s Drilling Partnerships provide ARP with stable, fee-based revenues that diminish the influence of commodity price fluctuations on cash flows. Because ARP’s Drilling Partnerships reimburse ARP on a cost-plus basis for drilling capital expenses, ARP is partially protected against increases in drilling costs. ARP’s fees for managing Drilling Partnerships accounted for approximately 16% of ARP’s segment margin for the year ended December 31, 2013. As of September 30, 2014, we and ARP had approximately 157.4 Bcfe, 4.1 Mmbbl and 0.7 Mmbbl of hedge positions, respectively, on our and ARP’s natural gas, crude oil and NGL production for 2014 through 2018.

 

•

ARP’s partnership management business can improve the economic rates of return associated with natural gas and oil production activities. A well drilled, net to ARP’s equity interest, in ARP’s partnership management business will provide ARP with an enhanced rate of return. For each well drilled in a partnership, ARP receives an upfront fee on the investors’ well construction and completion costs and a fixed administration and oversight fee, which enhances ARP’s overall rate of return. ARP also receives monthly per well fees from the partnership for the life of each individual well, which also increases the rate of return.

 

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Cash Distributions from ARP and Lightfoot

As of January 1, 2015, our equity interests in ARP and our other subsidiaries and investees consisted of:

 

		Incentive Distribution Rights				General Partner Interest				Limited Partner Interests
Our interests in ARP			100	%(1)			100	%(2)			20,962,485 3,749,986 562,497			Common Units(3)  Class C Preferred Units(4) Warrants for Class C Preferred Units(5)
Our interests in the Development Subsidiary			—				80.0	%(6)			1.7% limited partner interest
Our interests in Lightfoot			—				15.9	%			12.0% limited partner interest
Lightfoot’s interests in ARCX			100	%(7)			100	%(8)			40.3% limited partner interest

 

(1)	The incentive distribution rights, or “IDRs,” entitle us to receive increasing percentages, up to a maximum of 48%, of any cash distributed by ARP as it reaches certain target distribution levels in excess of $0.46 per ARP common unit in any quarter.

(2)	Consists of 1,819,113 general partner Class A units, which are entitled to receive 2% of the cash distributed by ARP without any obligation to make further capital contributions to ARP.

(3)	Represents an approximate 23.5% limited partner interest.

(4)

Represents an approximate 4.2% limited partner interest. The Class C preferred units pay cash distributions in an amount equal to the greater of (a) $0.51 per unit and (b) the distributions payable on each common unit at each declared quarterly distribution date. Class C preferred units are convertible, at the option of the holder, on a one-for-one basis, in whole or in part, at any time before July 31, 2016 and are mandatorily convertible on July 31, 2016.

(5)	Upon issuance of the Class C preferred units, Atlas Energy, as purchaser of the Class C preferred units, received 562,497 warrants to purchase ARP common units at an exercise price of $23.10 per unit, subject to adjustments provided therein. The warrants will expire on July 31, 2016.

(6)	The general partner interest is entitled to receive 2% of the cash distributed by the Development Subsidiary without any obligation to make further capital contributions.

(7)

Lightfoot owns 100% of Arc Logistics GP LLC, the general partner of ARCX, which owns all of the ARCX IDRs. The ARCX IDRs entitle ARCX’s general partner to receive increasing percentages, up to a maximum of 50%, of any cash distributed by ARCX as it reaches certain target distribution levels in excess of $0.4456 per ARCX common unit in any quarter.

(8)	The general partner interest in ARCX is a non-economic interest and does not entitle its holder to receive cash distributions.

The ARP IDRs entitle us, as the indirect holder of those rights, to receive the following percentages of cash distributed by ARP as the following target cash distribution levels are reached:

 

•

13.0% of all cash distributed in any quarter after each ARP common unit has received $0.46 for that quarter;

 

•

23.0% of all cash distributed in any quarter after each ARP common unit has received $0.50 for that quarter; and

 

•

48.0% of all cash distributed in any quarter after each ARP common unit has received $0.60 for that quarter.

In addition, our ownership of ARP’s general partner Class A units entitles us to receive 2% of the cash distributed by ARP without any obligation to make further capital contributions to ARP, and our ownership of approximately 27.7% of ARP’s limited partner ownership interest entitles us to receive distributions pro rata with ARP’s other limited partners.

 

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The following are distributions declared and/or paid by ARP subsequent to December 31, 2013. Our board of directors adopted a monthly distribution policy for ARP effective for the month of January 2014 and later:

 

Payment		Record Date		Payment Date		Rate
Q4 2013		February 10, 2014		February 14, 2014		$	0.5800
January 2014		March 7, 2014		March 17, 2014			0.1933
February 2014		April 7, 2014		April 14, 2014			0.1933
March 2014		May 7, 2014		May 15, 2014			0.1933
April 2014		June 5, 2014		June 13, 2014			0.1933
May 2014		July 7, 2014		July 15, 2014			0.1933
June 2014		August 6, 2014		August 14, 2014			0.1966
July 2014		September 4, 2014		September 12, 2014			0.1966
August 2014		October 7, 2014		October 15, 2014			0.1966
September 2014		November 10, 2014		November 14, 2014			0.1966
October 2014		December 5, 2014		December 15, 2014			0.1966
November 2014		January 6, 2015		January 16, 2015			0.1966

Following the separation, New Atlas will own 80.0% of the Development Subsidiary’s general partner, which is entitled to 2.0% of the cash distributed to the Development Subsidiary, and 15.9% of Lightfoot’s general partner, which owns ARCX’s IDRs and is entitled to distributions, up to a maximum of 50%, of any cash distributed by ARCX as it reaches certain target distribution levels in excess of $0.4456 per ARCX common unit in any quarter. New Atlas will also own 1.9% of the Development Subsidiary’s limited partner interests and 12.0% of Lightfoot’s limited partnership interests, which will be entitled to a pro rata share of distributions made by the Development Subsidiary and Lightfoot (and therefore ARCX), respectively.

Geographic and Geologic Overview

Through December 31, 2014, the majority of our and ARP’s production positions were in the following areas:

Barnett Shale/Marble Falls. The Barnett Shale and Marble Falls play are located east of the Bend Arch and west of the Quachita Thrust in the Fort Worth Basin of northern Texas. The Barnett Shale is a Mississippian-age shale formation located at depths between 5,000 and 8,000 feet and ranges in thickness from 100 and 600 feet. The Marble Falls play is a Pennsylvanian-age formation located above the Barnett Shale and beneath the Atoka at depths of approximately 5,500 feet and ranges in thickness from 50 and 400 feet. As of September 30, 2014, we and ARP had an interest in approximately 688 Barnett Shale and Marble Falls wells, and our Development Subsidiary had drilled 13 wells. As of September 30, 2014, we and ARP had more than 115,000 net acres prospective for the Barnett Shale/Marble Falls play.

Appalachian Basin. The Appalachian Basin includes all or parts of: Alabama, Georgia, Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia. It is the most mature natural gas, crude oil and NGL producing region in the United States, having established the first oil production in 1860. ARP’s development and production activities in the Appalachian Basin principally include the Marcellus Shale, Utica-Point Pleasant Shale, Clinton Sand and other conventional formations primarily in Pennsylvania and Ohio.

The Marcellus Shale is a black, organic rich shale formation located at depths between 4,000 and 8,500 feet and ranges in thickness from 15 to 400 feet. As of September 30, 2014, ARP had an interest in approximately 272 Marcellus Shale wells, consisting of 229 vertical wells and 43 horizontal wells. As of September 30, 2014, ARP had an interest in eight horizontal Marcellus Shale wells in Northeastern Pennsylvania, all of which were developed through Drilling Partnerships. Also as of September 30, 2014, approximately 2,314 prospective Marcellus Shale acres remained undeveloped in Lycoming County, Pennsylvania. ARP’s drilling activity in certain portions of the Appalachian Basin located in southwestern Pennsylvania, West Virginia and New York were limited until February 17, 2014 by the terms of the non-competition agreements between certain of Atlas Energy’s officers and directors and Chevron Corporation.

 

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The Utica-Point Pleasant Shale is an Ordovician-age shale that covers a large portion of Ohio, Pennsylvania, New York and West Virginia and lies several thousand feet below the Devonian-age Marcellus Shale. The Utica-Point Pleasant is an organic rich system comprised of two related shales. The richest concentration of organic material is present within the Point Pleasant member of the Lower Utica formation; it is, therefore, the primary objective section of this shale play. From central Ohio, the Utica-Point Pleasant play has a gentle basin center dip towards its deepest point in central Pennsylvania. In general, as the present day depth increases from West to East, so does the progression of hydrocarbon maturity along the following, ordered hydrocarbon phase windows: Immature-Oil-Condensate-Rich Gas-Dry Gas windows. As of September 30, 2014, ARP had drilled and completed eight horizontal Utica-Point Pleasant wells, all of which have been placed into production. As of September 30, 2014, ARP had approximately 1,006 net undeveloped acres prospective for the Utica Shale in Trumbull and Stark Counties in Ohio. ARP also currently has an interest in approximately 2,100 wells in Ohio and operates three field offices that ARP intends to use for future Utica Shale development.

Coal-Bed Methane. Our and ARP’s coal-bed methane developments are diversified across four well-known coal-bed methane producing areas: the Raton, Black Warrior, Arkoma and Central Appalachian basins. As of September 30, 2014, we and ARP had more than 510,000 net undeveloped acres prospective for coal-bed methane. Also as of September 30, 2014, we and ARP operated 2,817 wells and had an interest in another 1,213 wells, all of which produce gas generated from coal.

The Raton asset straddles the New Mexico-Colorado border, along the eastern edge of the Sangre de Cristo Mountains. The production derives from two coal-bearing intervals, the Raton (Tertiary-Upper Cretaceous Age) and Vermajo (Cretaceous Age) formations. The combined net coal thickness ranges between 18 and 65 feet, with depths between 750 and 2,200 feet. As of September 30, 2014, ARP operated 972 wells at the Raton asset.

The Black Warrior coal-bed methane asset is located in central Alabama and geologically related with the frontal thrusts associated with the Appalachian Mountains. The three Pennsylvanian-age coal intervals (Pratt, Mary Lee and Black Creek, listed in increasing stratigraphic depth and age) possess combined net coal thicknesses ranging from 16 to 24 feet, at depths of 500 to 2,400 feet. As of September 30, 2014, ARP operated 869 wells and had an interest in an additional 707 wells at the Black Warrior asset.

The Arkoma coal-bed methane asset is located in southeastern Oklahoma. The Middle Pennsylvanian (Desmoinesian) high volatile- to low volatile-bituminous coals in the Arkoma Basin are less than 10 feet thick with gas content values up to 560 cubic feet per ton. As of September 30, 2014, we operated 565 wells and had an interest in an additional 29 wells in the Arkoma asset.

The Central Appalachian coal-bed methane asset is located in Virginia and West Virginia. The Central Appalachian Basin is a mountainous region where coal mining is prevalent. We operate vertical wells in the Pond Creek and Lasher fields located in southern West Virginia and southwestern Virginia and pinnate horizontal wells in central and northern West Virginia. As of September 30, 2014, we operated 411 wells and had an interest in an additional 58 wells in Virginia and West Virginia.

Rangely. The Rangely Oil Field, located in northwestern Colorado, is one of the oldest and largest oil fields in the Rocky Mountain region. ARP has an approximate 25% non-operating net working interest in the assets and Chevron Corporation is the current owner/operator of the Rangely Weber Sand Unit. The Weber Formation is Permian to Pennsylvanian in age (245-315 million years ago), and typically consists of fine-grained, cross-bedded calcareous sandstones. Average thickness of the unit is 1,200 feet, although the gross reservoir thickness averages 700 feet, and the net production interval within the formation varies from approximately 50 to 400 feet.

Mississippi Lime/Hunton. The Mississippi Lime and Hunton formations are located in the Anadarko Shelf in northern Oklahoma. The Mississippi Lime formation is an expansive carbonate hydrocarbon system and is located at depths between 4,000 and 7,000 feet between the Pennsylvanian-age Morrow formation and the Devonian-age world-class source rock Woodford Shale formation. The Mississippi Lime formation can reach

 

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600 feet in gross thickness, with a targeted porosity zone between 50 and 100 feet thickness. The Hunton formation is a limestone formation located at a depth of approximately 7,500 feet, and ranges in thickness from 150 and 300 feet. As of September 30, 2014, ARP had an interest in approximately 35 Hunton wells. As of September 30, 2014, ARP had drilled 43 Mississippi Lime horizontal wells, of which 39 were completed and producing. As of September 30, 2014, ARP has identified an additional 136 horizontal Mississippi Lime locations across ARP’s over 25,000 net acre leaseholds.

Eagle Ford. The Eagle Ford Shale is an Upper Cretaceous-age formation that is prospective for horizontal drilling in some 20 counties across South Texas. Target vertical depths range from 4,000 to some 11,000+ feet with thickness from 40 to over 400 feet. The Eagle Ford formation is considered to be the primary source rock for many conventional oil and gas fields including the prolific East Texas Oil Field, one of the largest oil fields in the contiguous United States. In November 2014, ARP acquired 22 producing wells and 19 undeveloped locations in the Eagle Ford Shale. In connection with the acquisition, our Development Subsidiary purchased eight wells that have been drilled but not completed and 53 undeveloped drilling locations.

Gas and Oil Acquisitions

We and ARP seek to create substantial value by executing our respective strategies of acquiring properties with stable, long-life production, relatively predictable decline curves and lower risk development opportunities. Overall, we and ARP have acquired significant net proved reserves and production through the following transactions:

 

•

Carrizo Barnett Shale Acquisition—On April 30, 2012, ARP acquired 277 Bcfe of proved reserves, including undeveloped drilling locations, in the core of the Barnett Shale from Carrizo Oil & Gas, Inc. for approximately $187.0 million. The assets included 198 gross producing wells generating approximately 31 MMcfed of production at the date of acquisition on over 12,000 net acres, all of which are held by production.

 

•

Titan Barnett Shale Acquisition—On July 26, 2012, ARP acquired Titan Operating, L.L.C., which owned approximately 250 Bcfe of proved reserves and associated assets in the Barnett Shale on approximately 16,000 net acres, which are 90% held by production, for approximately $208.6 million. The assets are located in close proximity to the assets acquired from Carrizo in the Barnett Shale. Net production from these assets at the date of acquisition was approximately 24 MMcfed, including approximately 370 Bpd of NGLs. ARP believes there are over 300 potential undeveloped drilling locations on the acquired acreage.

 

•

Equal Mississippi Lime Acquisition—On April 4, 2012, ARP entered into an agreement with Equal Energy, Ltd., which we refer to as “Equal,” to acquire a 50% interest in Equal’s approximately 14,500 net undeveloped acres in the core of the oil and liquids rich Mississippi Lime play in northwestern Oklahoma for approximately $18.0 million. On September 24, 2012, ARP acquired Equal’s remaining 50% interest in approximately 8,500 net undeveloped acres included in the joint venture, approximately 8 MMcfed of net production in the region at the date of acquisition and substantial salt water disposal infrastructure for $41.3 million. The transaction increased ARP’s position in the Mississippi Lime play to 19,800 net acres in Alfalfa, Grant and Garfield counties in Oklahoma.

 

•

DTE Fort Worth Basin Acquisition—On December 20, 2012, ARP acquired 210 Bcfe of proved reserves in the Fort Worth Basin from DTE Energy Company for $257.4 million. The assets include 261 gross producing wells generating approximately 23 MMcfed of production at the date of acquisition on over 88,000 net acres, approximately 40% of which are held by production and approximately 33% are in continuous development. The acreage position includes approximately 75,000 net acres prospective for the oil and NGL-rich Marble Falls play, in which there are over 700 identified vertical drilling locations. ARP spudded approximately 70 vertical wells during 2013 and plans to continue its development during 2014. ARP believes that there are further potential development opportunities through vertical down-spacing and horizontal drilling in the Marble Falls formation. The assets acquired from DTE are in close proximity to ARP’s other assets in the Barnett Shale.

 

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•

EP Energy Raton Basin, Black Warrior Basin and County Line Acquisition—On July 31, 2013, ARP completed the acquisition of certain assets from EP Energy for approximately $709.6 million in net cash. We refer to this transaction as the “EP Energy Acquisition.” Pursuant to the purchase and sale agreement, ARP acquired interests in approximately 3,000 producing wells generating net production of approximately 119 MMcfed on the date of acquisition from EP Energy on approximately 700,000 net acres. ARP believes there are approximately 1,600 potential undeveloped drilling locations on the acreage acquired. The assets acquired included coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming.

 

•

EP Arkoma Acquisition—On July 31, 2013, Atlas Energy completed the acquisition of certain assets from EP Energy for approximately $64.5 million, net of purchase price adjustments. We refer to this transaction as the “Arkoma Acquisition.” The assets acquired included coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma.

 

•

GeoMet Acquisition—On May 12, 2014, ARP completed the acquisition of certain assets from GeoMet, Inc. for approximately $99.3 million in cash, net of purchase price adjustments, with an effective date of January 1, 2014. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia. The assets include, as of January 1, 2014: approximately 70 Bcfe of proved reserves in West Virginia and Virginia, all of which are natural gas and proved developed; current net production of approximately 22 MMcfed from over 400 active wells for the year ended December 31, 2013; lease operating costs of approximately $1.20/mcf; production and ad valorem taxes of approximately 10%; and transportation and gathering of approximately $0.40/mcf.

 

•

Rangely Acquisition—On June 30, 2014, ARP completed the acquisition of a 25% non-operated net working interest in oil and NGL producing assets, representing approximately 47 Mmboe of oil equivalent reserves for approximately $407.8 million in cash with an effective date of April 1, 2014. The assets are located in the Rangely field in northwest Colorado. The acquired assets are expected to provide ARP with a stable, high margin cash flow stream with a low-decline profile (average 3-4% annual decline rate over the past 15 years). The asset position is a tertiary oil recovery project using CO2 flood activity, and the production mix is predominantly oil at 90%, with the remainder coming from NGLs. Chevron Corporation will continue as operator of the assets.

 

•

Eagle Ford Acquisition—In November 2014, our Development Subsidiary and ARP completed the acquisition of interests in oil and natural gas assets in the Eagle Ford Shale in South Central Atascosa County, Texas, including 4,000 operated gross acres and net reserves of 12 Mmboe as of July 1, 2014. The purchase price was $339.0 million, of which $199.0 million was paid at closing and the balance will be paid during the twelve months following closing, subject to certain purchase price adjustments. The acquisition closed on November 5, 2014, with an effective date of July 1, 2014.

Gas and Oil Production

Our consolidated gas and oil production operations consist of various shale plays in the United States, both through ARP and through assets that we own directly. Our direct gas and oil production results from certain coal-bed methane producing natural gas assets in the Arkoma Basin we acquired on July 31, 2013 from EP Energy and wells drilled in the Marble Falls play by our Development Subsidiary. As of January 1, 2015, we own a 1.7% limited partner interest in the Development Subsidiary and 80.0% of its outstanding general partner Class A units, which are entitled to receive 2.0% of the cash distributed without any obligation to make further capital contributions

ARP has focused its natural gas, oil and NGL production operations in various shale plays throughout the United States, and its production includes direct interest wells and ownership interests in wells drilled through Drilling Partnerships. When ARP drills through a Drilling Partnership, it receives an interest in each Drilling Partnership proportionate to the value of ARP’s coinvestment in it and the value of the acreage ARP contributes to it, typically 30% of the overall capitalization of a particular partnership.

 

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Production Volumes

The following table presents our and ARP’s total net gas, oil and NGL production volumes and production per day during the nine months ended September 30, 2014 and 2013 and the years ended December 31, 2013, 2012 and 2011:

 

		Nine Months Ended September 30,								Year Ended December 31,
		2014				2013				2013				2012				2011
Production per day:(1)(2)
New Atlas:
Natural gas (Mcfd)			11,560				2,780				5,085				—				—
Oil (Bpd)			—				—				—				—				—
NGLs (Bpd)			—				—				—				—				—
Total (Mcfed)			11,560				2,780				5,085				—				—
Development Subsidiary:
Natural gas (Mcfd)			656				—				21				—				—
Oil (Bpd)			121				—				7				—				—
NGLs (Bpd)			85				—				3				—				—
Total (Mcfed)			1,887				—				79				—				—
Atlas Resource:
Natural gas (Mcfd)			225,943				134,945				158,886				69,408				31,403
Oil (Bpd)			2,761				1,301				1,329				330				307
NGLs (Bpd)			3,722				3,441				3,473				974				444
Total (Mcfed)			264,843				163,397				187,701				77,232				35,912
Total production per day:
Natural gas (Mcfd)			238,158				137,725				163,992				69,408				31,403
Oil (Bpd)			2,882				1,301				1,336				330				307
NGLs (Bpd)			3,807				3,441				3,476				974				444
Total (Mcfed)			278,290				166,178				192,866				77,232				35,912

 

(1)

Production quantities consist of the sum of (i) the proportionate share of production from wells in which we and ARP have a direct interest, based on the proportionate net revenue interest in such wells, and (ii) ARP’s proportionate share of production from wells owned by the Drilling Partnerships in which it has an interest, based on ARP’s equity interest in each such Drilling Partnership and based on each Drilling Partnership’s proportionate net revenue interest in these wells.

(2)

“MMcf” represents million cubic feet; “MMcfe” represents million cubic feet equivalents; “Mcfd” represents thousand cubic feet per day; “Mcfed” represents thousand cubic feet equivalents per day; and “Bbls” and “Bpd” represent barrels and barrels per day. Barrels are converted to Mcfe using the ratio of approximately 6 Mcf to one barrel.

 

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Our and ARP’s production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised 83% of our consolidated proved reserves on an energy equivalent basis at December 31, 2013. The following table presents our and ARP’s production revenues and average sales prices for natural gas and oil production for the nine months ended September 30, 2014 and 2013 and the years ended December 31, 2013, 2012 and 2011, along with average production costs, taxes and transportation and compression costs in each of the reported periods:

 

		Nine Months Ended September 30,								Year Ended December 31,
		2014				2013				2013				2012				2011
Production revenues (in thousands):
New Atlas:
Natural gas revenue		$	12,197			$	2,700			$	6,821			$	—			$	—
Oil revenue			—				—				—				—				—
NGLs revenue			—				—				—				—				—
Total revenues		$	12,197			$	2,700			$	6,821			$	—			$	—
Development Subsidiary:
Natural gas revenue		$	756			$	—			$	28			$	—			$	—
Oil revenue			3,081				—				241				—				—
NGLs revenue			726				—				33				—				—
Total revenues		$	4,563			$	—			$	302			$	—			$	—
Atlas Resource Partners:
Natural gas revenue		$	227,036			$	114,789			$	186,229			$	70,151			$	49,096
Oil revenue			67,626				32,394				44,160				11,351				10,057
NGLs revenue			31,034				26,307				36,394				11,399				7,826
Total revenues		$	325,696			$	173,490			$	266,783			$	92,901			$	66,979
Total production revenues:
Natural gas revenue		$	239,989			$	117,489			$	193,078			$	70,151			$	49,096
Oil revenue			70,707				32,394				44,401				11,351				10,057
NGLs revenue			31,760				26,307				36,427				11,399				7,826
Total revenues		$	342,456			$	176,190			$	273,906			$	92,901			$	66,979
Average sales price:
New Atlas:
Natural gas (per Mcf):(1)
Total realized price, after hedge		$	3.86			$	3.56			$	3.68			$	—			$	—
Total realized price, before hedge		$	4.11			$	3.35			$	3.41			$	—			$	—
Oil (per Bbl):(1)
Total realized price, after hedge		$	—			$	—			$	—			$	—			$	—
Total realized price, before hedge		$	—			$	—			$	—			$	—			$	—
NGLs (per Bbl):(1)
Total realized price, after hedge		$	—			$	—			$	—			$	—			$	—
Total realized price, before hedge		$	—			$	—			$	—			$	—			$	—
Development Subsidiary:
Natural gas (per Mcf):(1)
Total realized price, after hedge(2)		$	4.22			$	—			$	3.63			$	—			$	—
Total realized price, before hedge(2)		$	4.22			$	—			$	3.63			$	—			$	—
Oil (per Bbl):(1)
Total realized price, after hedge		$	93.52			$	—			$	93.16			$	—			$	—
Total realized price, before hedge		$	93.52			$	—			$	93.16			$	—			$	—

 

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		Nine Months Ended September 30,								Year Ended December 31,
		2014				2013				2013				2012				2011
NGLs (per Bbl):(1)
Total realized price, after hedge		$	31.45			$	—			$	34.88			$	—			$	—
Total realized price, before hedge		$	31.45			$	—			$	34.88			$	—			$	—
Atlas Resource Partners:
Natural gas (per Mcf):(1)
Total realized price, after hedge(2)		$	3.79			$	3.39			$	3.47			$	3.29			$	4.98
Total realized price, before hedge(2)		$	4.07			$	3.19			$	3.25			$	2.60			$	4.53
Oil (per Bbl):(1)
Total realized price, after hedge		$	89.71			$	91.19			$	91.01			$	94.02			$	89.70
Total realized price, before hedge		$	93.45			$	96.50			$	95.88			$	91.32			$	89.07
NGLs (per Bbl):(1)
Total realized price, after hedge		$	30.54			$	28.01			$	28.71			$	31.97			$	48.26
Total realized price, before hedge		$	32.16			$	28.52			$	29.43			$	31.97			$	48.26
Total:
Natural gas (per Mcf):(1)
Total realized price, after hedge(2)		$	3.79			$	3.39			$	3.48			$	3.29			$	4.98
Total realized price, before hedge(2)		$	4.08			$	3.20			$	3.25			$	2.60			$	4.53
Oil (per Bbl):(1)
Total realized price, after hedge		$	89.87			$	91.19			$	91.02			$	94.02			$	89.70
Total realized price, before hedge		$	93.46			$	96.50			$	95.86			$	91.32			$	89.07
NGLs (per Bbl):(1)
Total realized price, after hedge		$	30.56			$	28.02			$	28.71			$	31.97			$	48.26
Total realized price, before hedge		$	32.14			$	28.52			$	29.43			$	31.97			$	48.26
Production costs (per Mcfe):(1)
New Atlas Direct:
Lease operating expenses		$	0.86			$	0.77			$	0.79			$	—			$	—
Production taxes		$	0.26			$	0.21			$	0.21				—				—
Transportation and compression		$	0.33			$	0.56			$	0.54				—				—
		$	1.45			$	1.54			$	1.54			$	—			$	—
Development Subsidiary:
Lease operating expenses		$	2.51			$	—			$	—			$	—			$	—
Production taxes		$	0.50				—				—				—				—
Transportation and compression		$	—				—				—				—				—
		$	3.01			$	—			$	—			$	—			$	—
Atlas Resource Partners:
Lease operating expenses(3)		$	1.27			$	1.12			$	1.09			$	0.82			$	1.09
Production taxes		$	0.27			$	0.17			$	0.18			$	0.12			$	0.10
Transportation and compression		$	0.26			$	0.22			$	0.24			$	0.24			$	0.43
		$	1.80			$	1.51			$	1.50			$	1.19			$	1.61
Total production costs:
Lease operating expenses(3)		$	1.26			$	1.11			$	1.08			$	0.82			$	1.09
Production taxes		$	1.27			$	0.17			$	0.18			$	0.12			$	0.10
Transportation and compression		$	0.26			$	0.22			$	0.25			$	0.24			$	0.43
		$	1.80			$	1.51			$	1.50			$	1.19			$	1.61

 

(1)	“Mcf” represents thousand cubic feet; “Mcfe” represents thousand cubic feet equivalents; and “Bbl” represents barrels.

 

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(2)

Excludes the impact of subordination of ARP’s production revenue to investor partners within its Drilling Partnerships for the nine months ended September 30, 2014 and 2013, and the years ended December 31, 2013, 2012 and 2011. Including the effect of this subordination, the average realized gas sales price was $3.68 per Mcf ($3.96 per Mcf before the effects of financial hedging) and $3.12 per Mcf ($2.92 per Mcf before the effects of financial hedging) for the nine months ended September 30, 2014 and 2013, respectively, and $3.23 per Mcf ($3.00 per Mcf before the effects of financial hedging), $2.76 per Mcf ($2.08 per Mcf before the effects of financial hedging) and $4.28 per Mcf ($3.83 per Mcf before the effects of financial hedging) for the years ended December 31, 2013, 2012 and 2011, respectively.

(3)

Excludes the effects of ARP’s proportionate share of lease operating expenses associated with subordination of its production revenue to investor partners within its Drilling Partnerships for the nine months ended September 30, 2014 and 2013, and for the years ended December 31, 2013, 2012 and 2011. Including the effects of these costs, total lease operating expenses per Mcfe were $1.25 per Mcfe ($1.78 per Mcfe for total production costs) and $1.04 per Mcfe ($1.43 per Mcfe for total production costs) for the nine months ended September 30, 2014 and 2013, and $1.00 per Mcfe ($1.42 per Mcfe for total production costs), $0.58 per Mcfe ($0.94 per Mcfe for total production costs) and $0.80 per Mcfe ($1.41 per Mcfe for total production costs) for the years ended December 31, 2013, 2012 and 2011, respectively.

Drilling Activity

The number of wells we and ARP drill will vary depending on, among other things, the amount of money we have available and the money raised by ARP through Drilling Partnerships, the cost of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. The following table sets forth information with respect to the number of wells we and ARP drilled, both gross and for our and ARP’s interest, during the periods indicated.

 

		Nine Months Ended September 30,								Years Ended December 31,
		2014				2013				2013				2012				2011
New Atlas Direct:
Gross wells drilled			—				—				—				—				—
Our share of gross wells drilled			—				—				—				—				—
Gross wells turned in line			—				—				—				—				—
Net wells turned in line			—				—				—				—				—
Development Subsidiary:
Gross wells drilled			11				—				2				—				—
Our share of gross wells drilled(1)			11				—				2				—				—
Gross wells turned in line			10				—				2				—				—
Net wells turned in line(1)			10				—				2				—				—
		Nine Months Ended September 30,								Years Ended December 31,
		2014				2013				2013				2012				2011
Atlas Resource Partners:
ARP gross wells drilled			98				75				103				105				160
ARP’s share of gross wells drilled(2)			52				49				66				42				31
ARP gross wells turned in line			90				83				117				154				99
ARP net wells turned in line(2)			53				59				80				43				28

 

(1)	Includes our Development Subsidiary’s percentage interest in the wells in which it has a direct ownership interest.

(2)	Includes (i) ARP’s percentage interest in the wells in which it has a direct ownership interest and (ii) ARP’s percentage interest in the wells based on its percentage ownership in its Drilling Partnerships.

 

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Neither we nor ARP operate any of the rigs or related equipment used in our and its drilling operations, relying instead on specialized subcontractors or joint venture partners for all drilling and completion work. This enables us and ARP to streamline operations and conserve capital for investments in new wells, infrastructure and property acquisitions, while generally retaining control over all geological, drilling, engineering and operating decisions. We and ARP perform regular inspection, testing and monitoring functions on each of our Drilling Partnerships and its operated wells.

Natural Gas and Oil Leases

The typical oil and gas lease agreement provides for the payment of a percentage of the proceeds, known as a royalty, to the mineral owner(s) for all natural gas, oil and other hydrocarbons produced from any well(s) drilled on the leased premises. In the Appalachian Basin and much of the United States, this amount, historically has ranged between 1/8th (12.5%) and 1/6th (16.66%) of the hydrocarbons produced, resulting in a net revenue interest to us of between 87.5% and 83.33%. With the discovery of the Marcellus and Utica shales in the Appalachian Basin in the last few years, and the resultant competition for undeveloped acreage, it has become very common for landowners to demand royalty rates up to 20% or higher, resulting in a net revenue interest of 80% or less. In Oklahoma (Mississippi Lime play) and Texas (Barnett Shale and Marble Falls plays), both states where we have acquired substantial acreage positions, royalties are commonly in the 15-20% range, resulting in net revenue interests to us in the 80-85% range.

In the Texas Barnett Shale, Oklahoma Mississippi Lime and Appalachian Basin Marcellus and Utica plays, where horizontal wells are generally drilled on much larger drilling units (sometimes approaching 1,000 acres), the mineral and/or surface rights are generally acquired from multiple parties. In the case of “urban” drilling areas in the Barnett Shale, there may be as many as 3,500 royalty owners within a single drilling unit.

Because the acquisition of hydrocarbon leases in highly desirable basins is an extremely competitive process, and involves certain geological and business risks to identify prospective areas, leases are frequently held by other oil and gas operators. In order to access the rights to drill on those leases held by others, we may elect to farm-in lease rights and/or purchase assignments of leases from competitor operators. Typically, the assignor of such leases will reserve an overriding royalty interest (over and above the existing mineral owner royalty), that can range from 2-3% up to as high as 7 or 8%, and sometimes contain options to convert the overriding royalty interests to working interests at payout of a well. Areas where farm-ins are utilized can result in additional reductions in our net revenue interests, depending upon their terms and how much of a particular drilling unit the farm-in acreage encompasses.

There will be occasions where competitors owning leasehold interests in areas where we want to drill will not farm-out or sell their leases, but will instead join us as working interest partners, paying their proportionate share of all drilling and operating costs in a well. However, it is generally our goal to obtain 100% of the working interest in any and all new wells that we operate.

The following table sets forth information about our and ARP’s developed and undeveloped natural gas and oil acreage as of September 30, 2014. The information in this table includes ARP’s proportionate interest in acreage owned by Drilling Partnerships.

 

		Developed acreage(1)								Undeveloped acreage(2)
New Atlas:		Gross(3)				Net(4)				Gross(3)				Net(4)
Oklahoma			101,936				73,408				66,910				28,029
Arkansas			1,016				559				368				334
Texas			1,405				1,398				856				810
Total			104,357				75,365				68,134				29,173

 

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		Developed acreage(1)								Undeveloped acreage(2)
Atlas Resource Partners:		Gross(3)				Net(4)				Gross(3)				Net(4)
Pennsylvania			154,445				74,819				2,345				2,314
West Virginia			148,789				82,552				26				23
New Mexico			126,246				126,246				447,713				447,713
Ohio(5)			110,354				99,812				100,164				97,032
Texas			77,062				67,086				61,896				51,619
Alabama			56,200				55,253				41,143				37,595
Indiana			31,920				24,398				63,608				55,817
Wyoming			29,737				5,677				830				156
Colorado			44,124				29,158				20,278				20,278
Tennessee			20,119				8,409				46,424				46,196
Oklahoma			20,975				17,327				10,603				8,522
New York			13,254				12,122				20,957				18,936
Virginia			6,489				6,040				—				—
Other			1,290				207				3,014				2,829
Total			841,004				609,106				819,001				789,030

 

(1)	Developed acres are acres spaced or assigned to productive wells.

(2)	Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves.

(3)	A gross acre is an acre in which we or ARP own a working interest. The number of gross acres is the total number of acres in which we or ARP own a working interest.

(4)	Net acres is the sum of the fractional working interests owned in gross acres. For example, a 50% working interest in an acre is one gross acre but is 0.5 net acres.

(5)	Includes ARP’s Utica Shale natural gas and oil rights on approximately 1,006 net acres under new leases taken in Ohio that remain undeveloped.

The leases for our and ARP’s developed acreage generally have terms that extend for the life of the wells, while the leases on our and ARP’s undeveloped acreage have terms that vary from less than one year to five years. There are no concessions for undeveloped acreage as of September 30, 2014. As of September 30, 2014, none of the leases covering our approximately 29,173 net undeveloped acres, or 0.0%, are scheduled to expire on or before December 31, 2014, while leases covering approximately 8,418 of ARP’s 789,030 net undeveloped acres, or 1.1%, are scheduled to expire on or before December 31, 2014. An additional 4.7% and 0.7% of ARP’s net undeveloped acres are scheduled to expire in each of the years 2015 and 2016, respectively.

We believe that we and ARP hold good and indefeasible title to our and its producing properties, in accordance with standards generally accepted in the natural gas industry, subject to exceptions stated in the opinions of counsel employed by us and ARP in the various areas in which we conduct our activities. We do not believe that these exceptions detract substantially from our or ARP’s use of any property. As is customary in the natural gas industry, we and ARP conduct only a perfunctory title examination at the time we or ARP acquire a property. Before commencing drilling operations, we and ARP conduct an extensive title examination and perform curative work on defects that are deemed significant. We, ARP or our predecessors have obtained title examinations for substantially all of our and ARP’s managed producing properties. No single property represents a material portion of our or ARP’s holdings.

Our and ARP’s properties are subject to royalty, overriding royalty and other outstanding interests customary in the industry. These properties are also subject to burdens such as liens incident to operating agreements, taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. We do not believe that any of these burdens will materially interfere with our or ARP’s use of our or its properties.

 

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Natural Gas and Oil Reserves

The following tables summarize information regarding our and ARP’s estimated proved natural gas and oil reserves as of December 31, 2013. Proved reserves are the estimated quantities of crude oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The estimated reserves include reserves attributable to our and ARP’s direct ownership interests in oil and gas properties as well as the reserves attributable to ARP’s percentage interests in the oil and gas properties owned by Drilling Partnerships in which ARP owns partnership interests. All of the reserves are located in the United States. We and ARP base these estimated proved natural gas, oil and NGL reserves and future net revenues of natural gas, oil and NGL reserves upon reports prepared by Wright & Company, Inc., an independent third-party engineer. We and ARP have adjusted these estimates to reflect the settlement of asset retirement obligations on gas and oil properties. Summaries of the reserve reports related to our and ARP’s estimated proved reserves at December 31, 2013 are included as exhibits to this information statement. In accordance with SEC guidelines, we and ARP make the standardized measure estimates of future net cash flows from proved reserves using natural gas, oil and NGL sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. Our and ARP’s estimates of proved reserves are calculated on the basis of the unweighted adjusted average of the first-day-of-the-month price for each month during the years ended December 31, 2013 and 2012, and are listed below as of the dates indicated:

 

		December 31,
Unadjusted Prices(1)		2013				2012
Natural gas (per Mcf)		$	3.67			$	2.76
Oil (per Bbl)		$	96.78			$	94.71
NGLs (per Bbl)		$	30.10			$	33.91
Average Realized Prices, Before Hedge(1)(2)
Natural gas (per Mcf)		$	3.25			$	2.53
Oil (per Bbl)		$	95.86			$	92.26
NGLs (per Bbl)		$	29.43			$	31.97

 

(1)	“Mcf” represents thousand cubic feet; and “Bbl” represents barrels.

(2)

Excludes the impact of subordination of ARP’s production revenue to investor partners within its Drilling Partnerships for years ended December 31, 2013 and 2012. Including the effect of this subordination, the average realized gas sales price was $3.00 per Mcf before the effects of financial hedging and $2.08 per Mcf before the effects of financial hedging for years ended December 31, 2013 and 2012, respectively.

Reserve estimates are imprecise and may change as additional information becomes available. Estimates of natural gas, oil and NGL reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas, oil and NGLs that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

The preparation of our and ARP’s natural gas, oil and NGL reserve estimates were completed in accordance with prescribed internal control procedures by reserve engineers. For the periods presented, Wright & Company, Inc., was retained to prepare a report of proved reserves. The reserve information includes natural gas and oil reserves which are all located in the United States. The independent reserves engineer’s evaluation was based on more than 37 years of experience in the estimation and evaluation of petroleum reserves, specified economic parameters, operating conditions and government regulations. Our and ARP’s internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management

 

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review. The preparation of reserve estimates was overseen by our and ARP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 15 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our and ARP’s senior engineering staff and management, with final approval by the Chief Operating Officer and President.

Results of drilling, testing and production subsequent to the date of the estimate may justify revision of these estimates. Future prices received from the sale of natural gas, oil and NGLs may be different from those estimated by Wright & Company, Inc. in preparing its reports. The amounts and timing of future operating and development costs may also differ from those used. Due to these factors, the reserves set forth in the following tables ultimately may not be produced and the proved undeveloped reserves may not be developed within the periods anticipated. Our and ARP’s estimated standardized measure values may not be representative of the current or future fair market value of proved natural gas and oil properties. Standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas, oil and NGL prices or for the escalation of expenses and capital costs. The meaningfulness of these estimates depends upon the accuracy of the assumptions upon which they were based.

We and ARP evaluate natural gas reserves at constant temperature and pressure. A change in either of these factors can affect the measurement of natural gas reserves. We and ARP deduct operating costs, development costs and production-related and ad valorem taxes in arriving at the estimated future cash flows. We and ARP base the estimates on operating methods and conditions prevailing as of the dates indicated:

 

		Proved Reserves at December 31,
		2013				2012
Proved reserves:
Natural gas reserves (MMcf):(1)
Proved developed reserves			766,872				338,655
Proved undeveloped reserves(3)			236,907				235,119
Total proved reserves of natural gas			1,003,779				573,774
Oil reserves (MBbl):(1)
Proved developed reserves			3,459				3,400
Proved undeveloped reserves(3)			11,530				5,469
Total proved reserves of oil			14,989				8,869
NGL reserves (MBbl):
Proved developed reserves			7,676				7,885
Proved undeveloped reserves(3)			11,281				8,177
Total proved reserves of NGL			18,957				16,062
Total proved reserves (MMcfe)(1)			1,207,455				723,359
Standardized measure of discounted future cash flows (in thousands)(4)		$	1,079,291			$	623,676

 

(1)	“MMcf” represents million cubic feet; “MMcfe” represents million cubic feet equivalents; and “MBbl” represents thousand barrels. Oil and NGLs are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. Mcf is defined as one thousand cubic feet.

(2)	At December 31, 2013, there were no proved undeveloped reserves related to our oil and gas properties.

(3)

ARP’s ownership in these reserves is subject to reduction as it generally makes capital contributions, which includes leasehold acreage associated with ARP’s proved undeveloped reserves, to its Drilling Partnerships in exchange for an equity interest in these partnerships, which is approximately 30%, which effectively will reduce ARP’s ownership interest in these reserves from 100% to its respective ownership interest as ARP makes these contributions.

 

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(4)

Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses, such as general and administrative expenses, interest and income tax expenses, or to depletion, depreciation and amortization. The future cash flows are discounted using an annual discount rate of 10%. Standardized measure does not give effect to commodity derivative contracts. Because we and ARP are limited partnerships, no provision for federal or state income taxes has been included in the December 31, 2013 and 2012 calculations of standardized measure, which is, therefore, the same as the PV-10 value. Standardized measure for the years ended December 31, 2013 and 2012 includes approximately $2.0 and $3.8 Million related to the present value of future cash flows from plugging and abandonment of wells, including the estimated salvage value. These amounts were not included in the summary reserve reports that appear in Exhibits 99.2 and 99.3 in the registration statement of which this information statement forms a part.

Proved developed reserves are those reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserve estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells on which a relatively major expenditure is required for recompletion.

Proved Undeveloped Reserve, or “PUD”

PUD Locations. As of December 31, 2013, there were no PUD locations related to our natural gas and oil reserves and ARP had 598 PUD locations totaling approximately 373,773 Bcfe of natural gas, oil and NGLs. These PUDS are based on the definition of PUDs in accordance with the SEC’s rules allowing the use of techniques that have been proven effective through documented evidence, such as actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.

Historically, the primary focus of ARP’s drilling operations has been in the Appalachian Basin. Subsequent to our acquisition in the Arkoma Basin and ARP’s acquisitions in the Barnett Shale and Marble Falls play, the Mississippi Lime play, and the Raton Basin, the Black Warrior Basin and the County Line area of Wyoming during the years ended December 31, 2013 and 2012, we and ARP will continue to integrate those areas and increase our and ARP’s proved reserves through organic leasing, as well as drilling on our and ARP’s existing undeveloped acreage.

Our and ARP’s organic growth will focus on expanding acreage positions in our and ARP’s target areas, including our operations in the Arkoma Basin and ARP’s operations in the Marcellus Shale, Utica Shale, Barnett Shale and Marble Falls play, the Mississippi Lime play and the Raton Basin, the Black Warrior Basin and the County Line area of Wyoming. Through our and ARP’s previous drilling in these regions, as well as geologic analyses of these areas, we and ARP are expecting these expansion locations to have a significant impact on our and ARP’s proved reserves.

Changes in PUDs. Changes in PUDs that occurred during the year ended December 31, 2013 were due to ARP’s:

 

•

addition of approximately 158.6 Bcfe due to ARP’s drilling activity in the Marcellus Shale, Utica Shale, Mississippi Lime and Marble Falls play; and

 

•

addition of approximately 34.6 Bcfe due to ARP’s acquisition of acreage in the Raton and Black Warrior Basins; partially offset by

 

•

negative revisions of approximately 77.5 Bcfe in PUDs primarily due to the reduction of ARP’s five- year drilling plans in the Barnett Shale and pricing scenario revisions.

 

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Development Costs. We did not incur any costs related to the development of PUDs and no reserves were converted from PUDs to proved developed reserves during the year ended December 31, 2013. ARP’s costs incurred related to the development of PUDs were approximately $103.3 million, $79.4 million and $15.8 million for the years ended December 31, 2013, 2012 and 2011, respectively. During the years ended December 31, 2013, 2012 and 2011, approximately 58.4 Bcfe, 30.6 Bcfe and 9.6 Bcfe of ARP’s reserves, respectively, were converted from PUDs to proved developed reserves. Of the 30.6 Bcfe of ARP reserves converted from PUDs to proved developed reserves during the year ended December 31, 2012, 29.8 Bcfe is related to PUDs acquired and developed during the year. See “Business—Gas and Oil Acquisitions” beginning on page 162 for further information. As of December 31, 2013, there were no PUDs that had remained undeveloped for five years or more for us or ARP.

Productive Wells

The following table sets forth information regarding productive natural gas and oil wells in which we and ARP have a working interest as of December 31, 2013. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we and ARP have an interest, directly or through ARP’s ownership interests in Drilling Partnerships, and net wells are the sum of our and ARP’s fractional working interests in gross wells, based on the percentage interest ARP owns in the Drilling Partnership that owns the well:

 

		Number of productive wells(1)(2)
New Atlas		Gross				Net
Barnett Shale/Marble Falls:
Gas wells			2				2
Oil wells			—				—
Total			2				2
Coal-bed Methane:(3)
Gas wells			584				451
Oil wells			—				—
Total			584				451
Total:
Gas wells			586				452
Oil wells			—				—
Total			586				452

 

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		Number of productive wells(1)(2)
Atlas Resource Partners		Gross				Net
Appalachia:
Gas wells			7,681				3,767
Oil wells			495				355
Total			8,176				4,122
Coal-bed Methane:(3)
Gas wells			2,955				2,172
Oil wells			—				—
Total			2,955				2,172
Barnett Shale/Marble Falls:
Gas wells			569				470
Oil wells			52				35
Total			621				505
Mississippi Lime/Hunton:
Gas wells			66				47
Oil wells			—				—
Total			66				47
Other operating areas:(4)
Gas wells			782				240
Oil wells			2				1
Total			784				241
Total:
Gas wells			12,053				6,696
Oil wells			549				391
Total			12,602				7,087

 

(1)

There were no exploratory or dry wells drilled by us during the years ended December 31, 2013, 2012 and 2011. There were no exploratory wells drilled by ARP during the years ended December 31, 2013, 2012 and 2011; there were no gross or net dry wells within ARP’s operating areas during the year ended December 31, 2013. During the year ended December 31, 2012, there were eight gross (three net) ARP dry wells drilled in the Niobrara Shale. During the year ended December 31, 2011, there were 14 gross (five net) ARP dry wells drilled in the Niobrara Shale.

(2)	Includes ARP’s proportionate interest in wells owned by 86 Drilling Partnerships for which it serves as managing general partner and various joint ventures. This does not include royalty or overriding interests in 610 ARP wells and 14 of our wells.

(3)	Our coal-bed methane includes our production in the Arkoma Basin in eastern Oklahoma. Coal-bed methane for ARP includes its production located in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming.

(4)	Other operating areas include ARP’s production located in the Chattanooga, New Albany Shale and the Niobrara Shale.

 

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Commodity Risk Management

We and ARP seek to provide greater stability in our and ARP’s cash flows through the use of financial hedges for our natural gas, oil and NGLs production. The financial hedges may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures and options contracts with qualified counterparties. Financial hedges are contracts between us or ARP and counterparties and do not require physical delivery of hydrocarbons. Financial hedges allow us and ARP to mitigate hydrocarbon price risk, and cash is settled to the extent there is a price difference between the hedge price and the actual NYMEX settlement price. Settlement typically occurs on a monthly basis, at the time in the future dictated within the hedge contract. Financial hedges executed in accordance with our and ARP’s secured credit facilities do not require cash margin and are secured by our and ARP’s natural gas and oil properties. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, we and ARP have a management committee to assure that all financial trading is done in compliance with our and ARP’s hedging policies and procedures. We and ARP do not intend to contract for positions that we and ARP cannot offset with actual production.

Contractual Revenue Arrangements

Natural Gas and Oil Production

Natural Gas. We and ARP market the majority of our natural gas production to gas marketers directly or to third party plant operators who process and market the gas. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The production area and pricing indices for the majority of our and ARP’s production areas are as follows:

 

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Appalachian Basin—Dominion South Point, Tennessee Gas Pipeline, Transco Leidy Line, Columbia Appalachia, NYMEX, Transco Zone 5;

 

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Mississippi Lime—Southern Star;

 

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Barnett Shale and Marble Falls—primarily Waha, with smaller amounts sold into a variety of north Texas outlets;

 

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Raton—ANR, Panhandle and NGPL;

 

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Black Warrior Basin—Southern Natural;

 

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Arkoma—Enable Gas; and

 

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Other regions—primarily the Texas Gas Zone SL spot market (New Albany Shale) and the Cheyenne Hub spot market (Niobrara).

We and ARP attempt to sell the majority of natural gas produced at monthly, fixed index prices and a smaller portion at index daily prices.

Crude Oil. Crude oil produced from our and ARP’s wells flows directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting for an oil company. The crude oil is typically sold at the prevailing spot market price for each region, less appropriate trucking/pipeline charges. We and ARP do not have delivery commitments for fixed and determinable quantities of crude oil in any future periods under existing contracts or agreements.

Natural Gas Liquids. NGLs are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas to meet pipeline specifications for transport or sale to end users or marketers operating on the receiving pipeline. The resulting plant residue natural gas is sold as described above and the NGLs are generally priced and sold using the Mont Belvieu (TX) or Conway (KS) regional processing indices. The cost to process and fractionate the NGLs from the gas stream is typically either a volumetric fee for the gas and liquids processed or a percentage retention by the processing and fractionation facility. We and ARP do not have delivery commitments for fixed and determinable quantities of NGLs in any future periods under existing contracts or agreements.

 

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For the year ended December 31, 2013, Enterprise Products Operating LLC, Chevron and Empire Pipeline Corporation accounted for approximately 19%, 11% and 10% of ARP’s total natural gas, oil and NGL production revenues, respectively, with no other single customer accounting for more than 10% for this period.

Drilling Partnerships

Certain energy activities are conducted by ARP through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by ARP is deployed to drill and complete wells included within the partnership. As ARP deploys Drilling Partnership investor capital, it recognizes certain management fees it is entitled to receive, including well construction and completion revenue and a portion of administration and oversight revenue. At each period end, if ARP has Drilling Partnership investor capital that has not yet been deployed, it will recognize a current liability titled “Liabilities Associated with Drilling Contracts” on New Atlas’s combined consolidated balance sheets. After the Drilling Partnership well is completed and turned in line, ARP is entitled to receive additional operating and management fees, which are included within well services and administration and oversight revenue, respectively, on a monthly basis while the well is operating. In addition to the management fees it is entitled to receive for services provided, ARP is also entitled to its pro-rata share of Drilling Partnership gas and oil production revenue, which generally approximates 30%. ARP recognizes its Drilling Partnership management fees in the following manner:

 

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Well construction and completion. For each well that is drilled by a Drilling Partnership, ARP receives a 15% mark-up on those costs incurred to drill and complete wells included within the partnership. Such fees are earned, in accordance with the partnership agreement, and recognized as the services are performed, typically between 60 and 270 days, using the percentage of completion method.

 

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Administration and oversight. For each well drilled by a Drilling Partnership, ARP receives a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which is earned, in accordance with the partnership agreement and recognized at the initiation of the well. Additionally, the Drilling Partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. The well administrative fee is earned on a monthly basis as the services are performed.

 

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Well services. Each Drilling Partnership pays ARP a monthly per well operating fee, currently $100 to $2,000, depending on the type of well, for the life of the well. Such fees are earned on a monthly basis as the services are performed.

While its historical structure has varied, ARP has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically 10% per year determined on a cumulative basis and inclusive of estimated individual tax benefits, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. ARP periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, ARP recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which ARP has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, ARP will recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized.

 

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Competition

The energy industry is intensely competitive in all of its aspects. We and ARP operate in a highly competitive environment for acquiring properties and other energy companies, attracting capital for ARP’s Drilling Partnerships, contracting for drilling equipment and securing trained personnel. We and ARP also compete with the exploration and production divisions of public utility companies for mineral property acquisitions. Competition is intense for the acquisition of leases considered favorable for the development of hydrocarbons in commercial quantities. Our and ARP’s competitors may be able to pay more for hydrocarbon properties and to evaluate, bid for and purchase a greater number of properties than our and ARP’s financial or personnel resources permit. Furthermore, competition arises not only from numerous domestic and foreign sources of hydrocarbons but also from other industries that supply alternative sources of energy. Product availability and price are the principal means of competition in selling natural gas, crude oil, and NGLs.

Many of our and ARP’s competitors possess greater financial and other resources which may enable them to identify and acquire desirable properties and market their hydrocarbon production more effectively than we do. Moreover, ARP also competes with a number of other companies that offer interests in Drilling Partnerships. As a result, competition for investment capital to fund Drilling Partnerships is intense.

Market

The availability of a ready market for natural gas and oil, and the price obtained, depends upon numerous factors beyond our control, as described in “Risk Factors—Risks Relating to Our Business.” Product availability and price are the principal means of competition in selling oil and natural gas. During the nine months ended September 30, 2014 and fiscal 2013, 2012 and 2011, we did not experience problems in selling our natural gas and oil, although prices have varied significantly during those periods.

Seasonal Nature of Business

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. In addition, seasonal weather conditions and lease stipulations can limit our and ARP’s drilling and producing activities and other operations in certain areas. These seasonal anomalies may pose challenges for meeting well construction objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations. ARP has in the past drilled a greater number of wells during the winter months because it typically received the majority of funds from Drilling Partnerships during the fourth calendar quarter.

Environmental Matters and Regulation

Our and ARP’s operations relating to drilling and waste disposal are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As operators within the complex natural gas and oil industry, we and ARP must comply with laws and regulations at the federal, state and local levels. These laws and regulations can restrict or affect our and ARP’s business activities in many ways, such as by:

 

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restricting the way waste disposal is handled;

 

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limiting or prohibiting drilling, construction and operating activities in sensitive areas such as wetlands, coastal regions, non-attainment areas, tribal lands or areas inhabited by endangered species;

 

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requiring the acquisition of various permits before the commencement of drilling;

 

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requiring the installation of expensive pollution control equipment and water treatment facilities;

 

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restricting the types, quantities and concentration of various substances that can be released into the environment in connection with drilling, completion and production activities;

 

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requiring remedial measures to reduce, mitigate and/or respond to releases of pollutants or hazardous substances from existing and former operations, such as pit closure and plugging of abandoned wells;

 

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enjoining some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations;

 

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imposing substantial liabilities for pollution resulting from operations; and

 

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with respect to operations affecting federal lands or leases, requiring preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where pollutants or wastes have been disposed or otherwise released. Neighboring landowners and other third parties can file claims for personal injury or property damage allegedly caused by noise and/or the release of pollutants or wastes into the environment. These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently enact new, and revise existing, environmental laws and regulations, and any new laws or changes to existing laws that result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs.

We believe that our and ARP’s operations are in substantial compliance with applicable environmental laws and regulations, and compliance with existing federal, state and local environmental laws and regulations will not have a material adverse effect on our business, financial position or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, we cannot assure future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs.

Environmental laws and regulations that could have a material impact on our and ARP’s operations include the following:

National Environmental Policy Act. Natural gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act, or “NEPA.” NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly affect the environment. In the course of such evaluations, an agency will typically require an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that will be made available for public review and comment. All of our and ARP’s proposed exploration and production activities on federal lands, if any, require governmental permits, many of which are subject to the requirements of NEPA. This process has the potential to delay the development of natural gas and oil projects.

Waste Handling. The Solid Waste Disposal Act, including RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. Under the auspices of the U.S. EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own more stringent requirements. Drilling fluids,

 

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produced waters, and most of the other wastes associated with the exploration, development and production of crude oil and natural gas constitute “solid wastes,” which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be regulated as solid waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.

We believe that our and ARP’s operations are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that they hold all necessary and up-to-date permits, registrations and other authorizations to the extent that they are required under such laws and regulations. Although we and our subsidiaries do not believe the current costs of managing wastes to be significant, any more stringent regulation of natural gas and oil exploitation and production wastes could increase the costs to manage and dispose of such wastes.

CERCLA. CERCLA, also known as the “Superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on persons who are considered under the statute to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

Our and ARP’s operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. Although we and ARP both believe that we utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us or ARP or on or under other locations, including off-site locations, where such substances have been taken for disposal. There may be evidence that petroleum spills or releases have occurred at some of the properties owned or leased by us or ARP. However, none of these spills or releases appears to be material to our financial condition and we believe all of them have been or will be appropriately remediated. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was not under our or ARP’s control. These properties, and the substances disposed or released on them, may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes (including waste disposed of by prior owners or operators), remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills), or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, into navigable waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state. These permits may require pretreatment of produced waters before discharge. Compliance with such permits and requirements may be costly. Further, much of ARP’s natural gas extraction activity utilizes a process called hydraulic fracturing, which results in water discharges that must be treated and disposed of in accordance with applicable regulatory requirements.

On April 21, 2014, the U.S. Army Corps of Engineers and USEPA proposed a rule that would define ‘Waters of the United States,’ i.e., the scope of waters protected under the Clean Water Act, in light of several U.S. Supreme Court opinions (U.S. v. Riverside Bayview, Rapanos v. United States, and Solid Waste Agency of

 

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Northern Cook County v. U.S. Army Corps of Engineers). The U.S. Army Corps of Engineers and USEPA have stated that the proposed rule would enhance protection for nationwide public health and aquatic resources, and increase Clean Water Act program predictability and consistency. The public comment period has been extended twice, and will conclude on November 14, 2014. As drafted, this proposed rule may increase the costs of compliance and result in additional permitting requirements for some of our or ARP’s existing or future facilities.

The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The Clean Water Act also requires specified facilities to maintain and implement spill prevention, control and countermeasure plans and to take measures to minimize the risks of petroleum spills. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for failure to obtain or non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe that our and ARP’s operations are in substantial compliance with the requirements of the Clean Water Act.

Air Emissions. Our and ARP’s operations are subject to the federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including drilling sites, processing plants, certain storage vessels and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require obtaining pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. These laws and regulations also apply to entities that use natural gas as fuel, and may increase the costs of customer compliance to the point where demand for natural gas is affected. Various air quality regulations are periodically reviewed by the EPA and are amended as deemed necessary. The EPA may also issue new regulations based on changing environmental concerns.

In 2012, specific federal regulations applicable to the natural gas industry were finalized under the New Source Performance Standards, or “NSPS,” program along with National Emissions Standards for Hazardous Air Pollutants. These new regulations impose additional emissions control requirements and practices on our operations. Some of our or ARP’s new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new emission limitations. These regulations may increase the costs of compliance for some facilities. Our or ARP’s failure to comply with these requirements could subject us or ARP to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We believe that our and ARP’s operations are in substantial compliance with the requirements of the Clean Air Act.

While we and ARP will likely be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions, we and ARP believe that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than other similarly situated companies.

OSHA and Other Regulations. We and ARP are subject to the requirements of the federal Occupational Safety and Health Act, or “OSHA,” and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our or ARP’s operations. We and ARP believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Greenhouse Gas Regulation and Climate Change. To date, legislative and regulatory initiatives relating to greenhouse gas emissions have not had a material impact on our or ARP’s businesses. However, Congress has been actively considering climate change legislation. More directly, the EPA has begun regulating greenhouse

 

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gas emissions under the federal Clean Air Act. In response to the Supreme Court’s decision in Massachusetts v. EPA, 549 U.S. 497 (2007) (holding that greenhouse gases are air pollutants covered by the Clean Air Act), the EPA made a final determination that greenhouse gases endangered public health and welfare, 74 Fed. Reg. 66,496 (December 15, 2009). This finding led to the regulation of greenhouse gases under the Clean Air Act. Currently, the EPA has promulgated two rules that will affect our and ARP’s businesses.

First, the EPA promulgated the so-called “Tailoring Rule” which established emission thresholds for greenhouse gases under the Clean Air Act permitting programs, 75 Fed. Reg. 31,514 (June 3, 2010). Both the federal preconstruction review program, known as “PSD,” and the operating permit program are now implicated by emissions of greenhouse gases. These programs, as modified by the Tailoring Rule, could require some new facilities to obtain a PSD permit depending on the size of the new facilities. In addition, existing facilities as well as new facilities that exceed the emissions thresholds could be required to obtain the requisite operating permits.

On June 23, 2014, the United States Supreme Court ruled on challenges to the Tailoring Rule in the case of Utility Air Regulatory Group v. EPA, 134 S. Ct. 2427 (2014). The Court limited the applicability of the PSD program and Tailoring Rule to only new sources or modifications that would trigger PSD for another criteria pollutant such that projects cannot trigger PSD based solely on greenhouse gas emissions. However, if PSD is triggered for another pollutant, greenhouse gases could be subject to a control technology review process. The Court’s decision also means that sources cannot trigger a federal operating permit requirement based solely on greenhouse gas emissions. Overall, the impact of the Tailoring Rule after the Court’s decision is that it is unlikely to have much, if any, impact on our and ARP’s operations.

Second, the EPA finalized its Mandatory Reporting of Greenhouse Gases rule in 2009, 74 Fed. Reg. 56,260 (October 30, 2009). Subsequent revisions, additions and clarification rules were promulgated, including a rule specifically addressing the natural gas industry. These rules require certain industry sectors that emit greenhouse gases above a specified threshold to report greenhouse gas emissions to the EPA on an annual basis. The natural gas industry is covered by the rule and requires annual greenhouse gas emissions to be reported by March 31 of each year for the emissions during the preceding calendar year. This rule imposes additional obligations on us and ARP to determine whether the greenhouse gas reporting applies and if so, to calculate and report greenhouse gas emissions.

There are also ongoing legislative and regulatory efforts to encourage the use of cleaner energy technologies. While natural gas is a fossil fuel, it is considered to be more benign, from a greenhouse gas standpoint, than other carbon-based fuels, such as coal or oil. Thus, future regulatory developments could have a positive impact on our business to the extent that they either decrease the demand for other carbon-based fuels or position natural gas as a favored fuel.

In addition to domestic regulatory developments, the United States is a participant in multi-national discussions intended to deal with the greenhouse gas issue on a global basis. To date, those discussions have not resulted in the imposition of any specific regulatory system, but such talks are continuing and may result in treaties or other multi-national agreements that could have an impact on our and ARP’s businesses.

Finally, the scientific community continues to engage in a healthy debate as to the impact of greenhouse gas emissions on planetary conditions. For example, such emissions may be responsible for increasing global temperatures, and/or enhancing the frequency and severity of storms, flooding and other similar adverse weather conditions. We do not believe that these conditions are having any material current adverse impact on our or ARP’s businesses, and we are unable to predict at this time, what, if any, long-term impact such climate effects would have.

Energy Policy Act. Much of our and ARP’s natural gas extraction activity utilizes a process called hydraulic fracturing. The Energy Policy Act of 2005 amended the definition of “underground injection” in the Federal Safe Drinking Water Act of 1974, or “SDWA.” This amendment effectively excluded hydraulic fracturing for oil, gas

 

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or geothermal activities from the SDWA permitting requirements, except when “diesel fuels” are used in the hydraulic fracturing operations. Recently, this subject has received much regulatory and legislative attention at both the federal and state level and we anticipate that the permitting and compliance requirements applicable to hydraulic fracturing activity are likely to become more stringent and could have a material adverse impact on ARP’s business and operations. For instance, the U.S. EPA published a draft “Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels” on May 10, 2012 for public comment through August 23, 2012. In that draft guidance, the EPA asserts SDWA permitting authority over hydraulic fracturing activities that employ the injection of diesel fuel. The EPA submitted its draft guidance to the White House Office of Management and Budget in September 2013. In February 2014, the EPA released its revised final guidance document on SDWA underground injection control permitting for hydraulic fracturing using diesel fuels, along with responses to selected substantive public comments on the EPA’s previous draft guidance, a fact sheet and a memorandum to the EPA’s regional offices regarding implementation of the guidance. The process for implementing the EPA’s final guidance document may vary across states depending on the regulatory authority responsible for implementing the SDWA UIC program in each state.

The U.S. Senate and House of Representatives considered legislative bills in the 111th and 112th Sessions of Congress that, if enacted, would have repealed the SDWA permitting exemption for hydraulic fracturing activities. Titled the “Fracturing Responsibility and Awareness of Chemicals Act,” or “Frac Act,” the legislative bills as proposed could have potentially led to significant oversight of hydraulic fracturing activities by federal and state agencies. In 2013, the Frac Act was re-introduced in the 113th Session of Congress. If enacted into law, the legislation as proposed could potentially result in significant regulatory oversight, which may include additional permitting, monitoring, recording and recordkeeping requirements for us and ARP.

We and ARP believe our operations are in substantial compliance with existing SDWA requirements. However, future compliance with the SDWA could result in additional requirements and costs due to the possibility that new or amended laws, regulations or policies could be implemented or enacted in the future.

Hydrogen Sulfide. Exposure to gas containing high levels of hydrogen sulfide, referred to as sour gas, is harmful to humans and can result in death. ARP conducts its natural gas extraction activities in certain formations where hydrogen sulfide may be, or is known to be, present. ARP employs numerous safety precautions at its operations to ensure the safety of its employees. There are various federal and state environmental and safety requirements for handling sour gas, and ARP is in substantial compliance with all such requirements.

Drilling and Production. State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we or ARP can produce from our or its wells or limit the number of wells or the locations at which we or ARP can drill. Moreover, each state generally imposes a production or severance tax or impact fee with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

State Regulation and Taxation of Drilling. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Pennsylvania has imposed an impact fee on wells drilled into an unconventional formation, which includes the Marcellus Shale. The impact fee, which changes from year to year, is based on the average annual price of natural gas as determined by the NYMEX price, as reported by the Wall Street Journal for the last trading day of each calendar month. For example, based upon natural gas prices for 2013, the impact fee for qualifying unconventional horizontal wells spudded during 2013 was $50,000 per well, while the impact

 

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fee for unconventional vertical wells was $10,000 per well. The payment structure for the impact fee makes the fee due the year after an unconventional well is spudded, and the fee will continue for 15 years for an unconventional horizontal well and 10 years for an unconventional vertical well. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum limits on daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our and ARP’s wells, the type of wells that may be drilled in the future in proximity to existing wells and to limit the number of wells or locations from which we and ARP can drill. Texas imposes a 7.5% tax on the market value of natural gas sold, 4.6% on the market value of condensate and a fee of $0.000667 per Mcf of gas produced and $.00625 per barrel of crude. New Mexico imposes a severance tax of up to 3.75% of the value of oil and gas produced, a conservation tax equal to 0.19% of the oil and gas sold, and a school emergency tax of up to 3.15% for oil and 4% for gas. Alabama imposes a production tax of up to 2% on oil or gas and a privilege tax of up to 8% on oil or gas. Oklahoma imposes a gross production tax of 7% per Bbl of oil, 7% per Mcf of natural gas and a petroleum excise tax of $0.095 on the gross production of oil and gas.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon our unitholders.

Oil Spills and Hydraulic Fracturing. The Oil Pollution Act of 1990, as amended (“OPA”), contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters. While we and ARP believe we have been in compliance with OPA, noncompliance could result in varying civil and criminal penalties and liabilities.

A number of federal agencies, including the EPA and the Department of Interior, are currently evaluating a variety of environmental issues related to hydraulic fracturing. For example, EPA is conducting a study that evaluates any potential effects of hydraulic fracturing on drinking water and ground water. EPA released a progress report on this study on December 21, 2012 that did not present any conclusions, but notes that results will be released in draft form in late 2014 for review by the public and the EPA Science Advisory Board. The Department of Interior’s Bureau of Land Management published a revised proposed rule to regulate hydraulic fracturing on federal and Indian lands on May 24, 2013. The comment period closed on August 23, 2013 and the revised proposed rule drew more than 175,000 comments. A revised rule was reportedly sent to the White House Office of Management and Budget review in August 2014, and a final rule is expected to be issued in 2014 or 2015.

In addition, state and local conservancy districts and river basin commissions have all previously exercised their various regulatory powers to curtail and, in some cases, place moratoriums on hydraulic fracturing. State regulations include express inclusion of hydraulic fracturing into existing regulations covering other aspects of exploration and production and specifically may include, but not be limited to, the following:

 

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requirement that logs and pressure test results are included in disclosures to state authorities;

 

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disclosure of hydraulic fracturing fluids and chemicals, and the ratios of same used in operations;

 

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specific disposal regimens for hydraulic fracturing fluids;

 

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replacement/remediation of contaminated water assets; and

 

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minimum depth of hydraulic fracturing.

 

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Local regulations, which may be preempted by state and federal regulations, have included, but have not been limited to, the following, which may extend to all operations including those beyond hydraulic fracturing:

 

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noise control ordinances;

 

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traffic control ordinances;

 

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limitations on the hours of operations; and

 

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mandatory reporting of accidents, spills and pressure test failures.

Other Regulation of the Natural Gas and Oil Industry. The natural gas and oil industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the natural gas and oil industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in their industries with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. Our and ARP’s operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the potential costs to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Employees

New Atlas expects to employ approximately 675 persons as of the distribution date. Some of our officers may spend a substantial amount of time managing the business and affairs of ARP, our Development Subsidiary and their affiliates other than us and may face a conflict regarding the allocation of their time between our business and affairs and their other business interests.

Legal Proceedings

We are party to various routine legal proceedings arising in the ordinary course of our business. We do not believe that any of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations.

Since the announcement on October 13, 2014 of the Atlas Merger and the APL Merger, Atlas Energy, APL and the other parties to the mergers have been named as defendants in putative stockholder class action complaints challenging the transactions. Although New Atlas has not been named as a defendant in these complaints, certain of our expected officers have been named as defendants, and the litigation could delay or impede the consummation of the separation and distribution.

As of February 9, 2015, we are aware that Atlas Energy, Atlas Energy’s general partner, Targa Resources, Trident GP Merger Sub LLC (a subsidiary of Targa Resources created in connection with the Atlas Merger), and the members of the Atlas Energy board, including Edward E. Cohen and Jonathan Z. Cohen, New Atlas’s expected Chief Executive Officer and Executive Chairman, have been named as defendants in two putative stockholder class action complaint challenging the Atlas Merger filed in the Court of Common Pleas for Allegheny County, Pennsylvania. These cases are captioned: Rick Kane v. Atlas Energy, L.P., et al., Case No. GD-14-019658 (Pa. Ct. Comm. Pls. Oct. 22, 2013) and Jeffrey Ayers v. Atlas Energy, L.P., et al., Case No. GD-14-020255 (Pa. Ct. Comm. Pls. Nov. 3, 2014) (the “ATLS Lawsuits”). The ATLS Lawsuits were consolidated as In re Atlas Energy, L.P. Unitholder Litigation, Case No. GD-14-019658, in the Court of

 

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Common Pleas for Allegheny County, Pennsylvania (the “Consolidated ATLS Lawsuit”), although the Kane litigation has since been voluntarily dismissed. We are also aware that APL, APL’s general partner, Atlas Energy, Targa Resources, Targa Resources Partners, Targa Resource Partners’ general partner, Trident MLP Merger Sub LLC (a subsidiary of Targa Resources Partners created in connection with the APL Merger), and the members of the APL board, including Edward E. Cohen and Jonathan Z. Cohen, New Atlas’s expected Chief Executive Officer and Executive Chairman, have been named as defendants in five putative stockholder class action complaints challenging the APL Merger, four filed in the Court of Common Pleas for Allegheny County, Pennsylvania and one filed in the District Court of Tulsa County, Oklahoma. These cases are captioned: Michael Envin v. Atlas Pipeline Partners, L.P., et al., Case No. GD-14-019245 (Pa. Ct. Comm. Pls. Oct. 17, 2013), Greenthal Living Trust U/A 01/26/88 v. Atlas Pipeline Partners, L.P., et al., Case No. GD-14-020108 (Pa. Ct. Comm. Pls. Oct. 31, 2014), Mike Welborn v. Atlas Pipeline Partners, L.P., et al., Case No. GD-14-020729 (Pa. Ct. Comm. Pls. Nov. 10, 2014), Irving Feldbaum v. Atlas Pipeline Partners, L.P., et al., Case No. GD-14-22208 (Pa. Ct. Comm. Pls. Dec. 5, 2014) and William B. Federman Family Wealth Preservation Trust v. Atlas Pipeline Partners, L.P., et al., Case No. CJ-2014-04087 (Okla. D. Ct. Oct. 28, 2014) (the “APL Lawsuits” and, together with the ATLS Lawsuits, the “Lawsuits”). The Evnin, Greenthal, Welborn and Feldbaum APL Lawsuits have been consolidated as In re Atlas Pipeline Partners, L.P. Unitholder Litigation, Case No. GD-14-019245, in the Court of Common Pleas for Allegheny County, Pennsylvania (the “Consolidated APL Lawsuit”) and the Federman Lawsuit has subsequently been voluntarily dismissed.

The lawsuits generally allege that the individual defendants breached their fiduciary duties and/or contractual obligations by, among other things, failing to obtain sufficient value for the Atlas Energy and APL unitholders in, respectively, each of the Atlas Energy Merger and the APL Merger, agreeing to certain terms in each of the merger agreements that allegedly restrict the defendants’ ability to obtain a more favorable offer, favoring their self-interests over the interests of ATLS and APL unitholders, and omitting material information from the Proxy Statements. The lawsuits further allege that those breaches were aided and abetted by some combination of Atlas Energy, APL, Targa Resources, Targa Resources Partners, or various affiliates of those entities named above. The plaintiffs seek, among other things, injunctive relief, unspecified compensatory and/or rescissory damages, attorney’s fees, other expenses, and costs.

Additionally, on January 28, 2015, a putative stockholder class action and derivative lawsuit, captioned Inspired Investors v. Perkins et. al., Case No. 2015-04961, was filed purportedly on behalf of Targa Resources Corp. shareholders in the District Court of Harris County, Texas. The lawsuit names Atlas Energy and the individual members of the board of directors of Targa Resources Corp. as defendants and Targa Resources Corp. as a nominal defendant. The lawsuit generally alleges that the individual defendants breached their fiduciary duties by, among other things, omitting purportedly material information from the registration statement on Form S-4 that Targa Resources Corp. initially filed with the SEC on November 20, 2014 and most recently amended on January 22, 2015. The lawsuit seeks, among other things, injunctive relief and unspecified recissory damages, attorney’s fees, interest, and costs.

 

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MANAGEMENT

Executive Officers Following the Separation

The following table sets forth information as of February 9, 2015 regarding the individuals who are expected to serve as executive officers of New Atlas following the distribution. New Atlas’s executive officers are currently officers and employees of Atlas Energy and/or ARP. These individuals will not continue to be employed by Atlas Energy following the distribution, but the New Atlas executive officers who are currently officers and employees of ARP are expected to continue in such roles.

 

Name		Age		Position(s)
Edward E. Cohen		76		Chief Executive Officer, President and Director
Jonathan Z. Cohen		44		Executive Chairman of the Board
Sean P. McGrath		43		Chief Financial Officer
Daniel C. Herz		38		Senior Vice President, Corporate Development & Strategy
Matthew A. Jones		53		Senior Vice President, New Atlas and President, ARP
Freddie M. Kotek		59		Senior Vice President, Investment Partnership
Lisa Washington		47		Vice President, Chief Legal Officer and Secretary
Jeffrey M. Slotterback		32		Chief Accounting Officer

Edward E. Cohen. Mr. Cohen will be the Chief Executive Officer and President of New Atlas. He is currently the Chief Executive Officer and President of Atlas Energy and has served in those roles since February 2011. Mr. Cohen was the Chairman of the board of Atlas Energy’s general partner from its formation in January 2006 until February 2011. Mr. Cohen served as the Chief Executive Officer of Atlas Energy’s general partner from its formation in January 2006 until February 2009. Mr. Cohen has served on the executive committee of Atlas Energy’s General Partner since 2006. Mr. Cohen also was the Chairman of the Board and Chief Executive Officer of Atlas Energy, Inc. (formerly known as Atlas America, Inc.) from its organization in 2000 until the consummation of the Chevron Merger in February 2011 and also served as its President from September 2000 to October 2009. Mr. Cohen has been the Executive Chairman of the managing board of Atlas Pipeline Partners GP, LLC, which we refer to as “Atlas Pipeline GP,” since its formation in 1999. Mr. Cohen was the Chief Executive Officer of Atlas Pipeline GP from 1999 to January 2009. Mr. Cohen has served as Chairman of the Board and Chief Executive Officer of New Atlas since February 2012. Mr. Cohen has also been the Chairman and Chief Executive Officer of our Development Subsidiary since April 2013. Mr. Cohen was the Chairman of the Board and Chief Executive Officer of Atlas Energy Resources, LLC and its manager, Atlas Energy Management, Inc. from their formation in June 2006 until the consummation of the Chevron Merger in February 2011. In addition, Mr. Cohen has been Chairman of the Board of Directors of Resource America, Inc. (a publicly traded specialized asset management company) since 1990 and was its Chief Executive Officer from 1988 until 2004, and President from 2000 until 2003; Chairman of the Board of Resource Capital Corp. (a publicly traded real estate investment trust) since its formation in September 2005 until November 2009 and currently serves on its board; and Chairman of the Board of Brandywine Construction & Management, Inc. (a property management company) since 1994. Mr. Cohen is the father of Jonathan Z. Cohen. Mr. Cohen has been active in the energy business for over 30 years.

Jonathan Z. Cohen. Mr. Cohen will serve as the Executive Chairman of New Atlas. He has served as the Executive Chairman of the board of Atlas Energy’s general partner since January 2012. Before that, he served as Chairman of the board of Atlas Energy’s general partner from February 2011 until January 2012 and as Vice Chairman of the board from Atlas Energy’s formation in January 2006 until February 2011. Mr. Cohen has served as Chairman of the executive committee of Atlas Energy’s general partner since 2006. Mr. Cohen was the Vice Chairman of the board of Atlas Energy, Inc. from its incorporation in September 2000 until the consummation of the Chevron Merger in February 2011. Mr. Cohen has been the Executive Vice Chairman of the managing board of Atlas Pipeline GP since its formation in 1999, and Vice Chairman of the managing board of New Atlas since February 2012, both of which, until the consummation of the separation, are wholly owned subsidiaries of Atlas Energy. Mr. Cohen is the founder and Chairman of the board of Lightfoot Capital Partners GP, LLC. Mr. Cohen has also been the Executive Vice Chairman of the Board of our Development Subsidiary

 

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since April 2013. Mr. Cohen was the Vice Chairman of the board of Atlas Energy Resources, LLC and its manager, Atlas Energy Management, Inc., from their formation in June 2006 until the consummation of the Chevron Merger. Mr. Cohen has been a senior officer of Resource America, Inc. (a publicly traded specialized asset management company) since 1998, serving as the Chief Executive Officer since 2004, President since 2003 and a director since 2002. Mr. Cohen has been Chief Executive Officer, President and a director of Resource Capital Corp. since its formation in 2005. Mr. Cohen is a son of Edward E. Cohen. Mr. Cohen has been active in the energy business for approximately 20 years.

Sean P. McGrath. Mr. McGrath will be named Chief Financial Officer of New Atlas. He has been Atlas Energy’s Chief Financial Officer since February 2011. Before that he was the Chief Accounting Officer of Atlas Energy, Inc. and the Chief Accounting Officer of Atlas Energy Resources, LLC from December 2008 until February 2011. Mr. McGrath has served as the Chief Financial Officer of New Atlas since February 2012, as the Chief Financial Officer of our Development Subsidiary since April 2013, as the Chief Accounting Officer of Atlas Energy’s general partner from January 2006 until November 2009, and as the Chief Accounting Officer of Atlas Pipeline GP from May 2005 until November 2009. Mr. McGrath was the Controller of Sunoco Logistics Partners L.P. (a publicly traded partnership that transports, terminals and stores refined products and crude oil) from 2002 to 2005. Mr. McGrath is a Certified Public Accountant.

Daniel C. Herz. Mr. Herz will be named Senior Vice President of Corporate Development & Strategy of New Atlas. He has served as Senior Vice President of Corporate Development and Strategy of Atlas Energy’s general partner since February 2011. Before that, he was Senior Vice President of Corporate Development of Atlas Energy, Inc. and Atlas Energy Resources, LLC from August 2007 until February 2011. Mr. Herz has served as Senior Vice President of Corporate Development and Strategy of New Atlas since March 2012 and as the President and a director of our Development Subsidiary since April 2013. Mr. Herz has been Senior Vice President of Corporate Development of Atlas Pipeline Partners GP, LLC since August 2007. Before that, Mr. Herz was Vice President of Corporate Development of Atlas Energy, Inc. and Atlas Pipeline Partners GP, LLC from December 2004 and of Atlas Energy’s general partner from January 2006. Prior to joining Atlas Energy, Inc. and Atlas Pipeline Partners GP, LLC, Mr. Herz was an investment banker with Banc of America Securities from 1999 to 2003.

Matthew A. Jones. Mr. Jones will be named Senior Vice President of New Atlas and President of ARP. He has been Senior Vice President of Atlas Energy’s general partner and President of Atlas Energy’s exploration and production division since February 2011, and served as Chief Operating Officer of Atlas Energy’s exploration and production division from February 2011 until October 2013. Before that, he was the Chief Financial Officer of Atlas Energy, Inc. from March 2005 and an Executive Vice President from October 2009 until February 2011. Mr. Jones has been the President and a director of New Atlas since March 2012 and its Chief Operating Officer from March 2012 until October 2013, and was the Chief Financial Officer of Atlas Energy Resources, LLC and Atlas Energy Management, Inc. from their formation in June 2006 until the consummation of the Chevron Merger in February 2011. Mr. Jones served as the Chief Financial Officer of Atlas Energy’s general partner from January 2006 until September 2009 and as a member of the Board from February 2006 until February 2011. Mr. Jones was the Chief Financial Officer of Atlas Pipeline GP from March 2005 to September 2009. From 1996 to 2005, Mr. Jones worked in the Investment Banking Group at Friedman Billings Ramsey, concluding as Managing Director. Mr. Jones worked in Friedman Billings Ramsey’s Energy Investment Banking Group from 1999 to 2005. Mr. Jones is a Chartered Financial Analyst.

Freddie M. Kotek. Mr. Kotek will be named Senior Vice President of New Atlas’s Investment Partnership Division. He has been the Senior Vice President of the Investment Partnership Division of Atlas Energy’s general partner since February 2011. Before that, he was the Executive Vice President of Atlas Energy, Inc. from February 2004 until February 2011 and served as a director from September 2001 until February 2004. Mr. Kotek has been Senior Vice President of New Atlas since March 2012, the Executive Vice President and a director of our Development Subsidiary since April 2013, and Chairman of Atlas Resources, LLC since September 2001. He has also served as Chief Executive Officer and President of Atlas Resources since

 

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January 2002. Mr. Kotek served as Atlas Energy, Inc.’s Chief Financial Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice President of Resource America from 1995 until May 2004 and President of Resource Leasing, Inc. (a wholly owned subsidiary of Resource America) from 1995 until May 2004.

Lisa Washington. Ms. Washington will be named Vice President, Chief Legal Officer and Corporate Secretary of New Atlas. She has been Vice President, Chief Legal Officer and Secretary of Atlas Energy’s general partner since February 2011. Ms. Washington has been the Chief Legal Officer and Secretary of New Atlas since February 2012 and a Senior Vice President since October 2013 and has been the Chief Legal Officer and Secretary of our Development Subsidiary since April 2013. Ms. Washington served as Chief Legal Officer and Secretary of Atlas Energy’s general partner from January 2006 to October 2009 and as a Senior Vice President of Atlas Energy’s general partner from October 2008 to October 2009. Ms. Washington served as Chief Legal Officer and Secretary of Atlas Pipeline GP from November 2005 to October 2009, as Senior Vice President from October 2008 to October 2009 and as Vice President from November 2005 until October 2008. Ms. Washington served as Chief Legal Officer and Secretary of Atlas Energy, Inc. from November 2005 until February 2011, as Senior Vice President from October 2008 until February 2011 and as Vice President from November 2005 until October 2008. Ms. Washington served as Chief Legal Officer and Secretary of Atlas Energy Resources, LLC from 2006 until February 2011, as Senior Vice President from July 2008 until February 2011 and as Vice President from 2006 until July 2008. From 1999 to 2005, Ms. Washington was an attorney in the business department of the law firm of Blank Rome LLP.

Jeffrey M. Slotterback. Mr. Slotterback will be named Chief Accounting Officer of New Atlas. He has been Atlas Energy’s Chief Accounting Officer since March 2011. Mr. Slotterback has also been the Chief Accounting Officer of New Atlas since March 2012 and the Chief Accounting Officer of our Development Subsidiary since April 2013. Mr. Slotterback served as the Manager of Financial Reporting for Atlas Energy, Inc. from July 2009 until February 2011 and then served as the Manager of Financial Reporting for Atlas Energy’s general partner from February 2011 until March 2011. Mr. Slotterback served as Manager of Financial Reporting for both Atlas Energy’s general partner and Atlas Pipeline GP from May 2007 until July 2009. Mr. Slotterback was a Senior Auditor at Deloitte and Touche, LLP from 2004 until 2007, where he focused on energy and health care clients. Mr. Slotterback is a Certified Public Accountant.

 

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DIRECTORS

Board of Directors Following the Separation

The following table sets forth information as of February 9, 2015 with respect to those persons who are expected to serve on our board of directors following the separation. Our limited liability company agreement will provide that an annual meeting of the unitholders for the election of directors to the board of directors and other matters that the board of directors submits to a vote of the unitholders will be held at such date and time as may be fixed from time to time by our board of directors. At each annual meeting, the unitholders entitled to vote will vote as a single class for the election of directors to the board, and will elect, by a plurality of the votes cast at such meeting, persons to serve on the board of directors who are nominated in accordance with the provisions of the limited liability company agreement.

 

Name		Age				Position(s)
Jonathan Z. Cohen			44			Executive Chairman of the Board
Edward E. Cohen			76			Chief Executive Officer, President and Director
Mark C. Biderman			69			Director
DeAnn Craig			63			Director
Dennis A. Holtz			74			Director
Walter C. Jones			52			Director
Jeffrey F. Kupfer			47			Director
Ellen F. Warren			58			Director

Jonathan Z. Cohen. Mr. Cohen’s extensive knowledge of New Atlas’s business resulting from his long service with Atlas Energy and its predecessors, as well as his strong financial and industry experience, will allow him to contribute valuable perspectives on many issues facing New Atlas. Mr. Cohen’s service on our board of directors will create an important link between management and the rest of the board of directors and will provide New Atlas with decisive and effective leadership. Mr. Cohen’s involvement with public and private entities of varying size, complexity and focus, and raising debt and equity for such entities, provides him with extensive experience and contacts that will be valuable to New Atlas. Additionally, among the reasons for his appointment as a director, Mr. Cohen’s financial, business, operational and energy experience, as well as the experience that he has accumulated through his activities as a financier and investor, will add strategic vision to the board of directors to assist with our growth, operations and development. Mr. Cohen will be able to draw upon these diverse experiences to provide guidance and leadership with respect to exploration and production operations, capital markets and corporate finance transactions and corporate governance issues.

Edward E. Cohen. Mr. Cohen’s strong financial and energy industry experience, along with his deep knowledge of our company resulting from his long tenure with Atlas Energy and its predecessors, will enable Mr. Cohen to provide valuable perspectives on many issues facing New Atlas. Mr. Cohen’s service on the board of directors will create an important link between management and the board and will provide New Atlas with decisive and effective leadership. Mr. Cohen’s extensive experience in founding, operating and managing public and private companies of varying size and complexity will enable him to provide valuable expertise to New Atlas. Additionally, among the reasons for his appointment as a director, Mr. Cohen will bring to the board of directors the vast experience that he has accumulated through his activities as a financier, investor and operator in various parts of the country. These diverse experiences will enable Mr. Cohen to bring unique perspectives to the board of directors, particularly with respect to business management, financial markets and financing transactions and corporate governance issues.

Mark C. Biderman. Mr. Biderman has served as a director of Atlas Energy’s general partner since February 2011. Before that, he was a director of Atlas Energy, Inc. from July 2009 until February 2011. Mr. Biderman was Vice Chair of National Financial Partners Corp. (a publicly-traded financial services company) from September 2008 to December 2008. Before that, from November 1999 to September 2008, he was National Financial’s Executive Vice President and Chief Financial Officer. From May 1987 to October 1999, he served as Managing

 

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Director and Head of the Financial Institutions Group at CIBC World Markets Group (an investment banking firm) and its predecessor, Oppenheimer & Co., Inc. Mr. Biderman has served as a director and chair of the audit committee of Full Circle Capital Corporation (a publicly-traded investment company), as well as a member of its corporate governance and nominating committee, since August 2010. Mr. Biderman serves as a director, and chair of the compensation committee of Apollo Commercial Real Estate Finance, Inc. (a publicly-traded commercial real estate finance company) as well as a member of its audit committee, since November 2010. He has also served as a director and chair of the audit committee and as a member of the nominating and corporate governance committee of Apollo Residential Mortgage, Inc. (a publicly-traded residential real estate finance company) since July 2011. Mr. Biderman is a Chartered Financial Analyst. Mr. Biderman will bring over 40 years’ of business and financial experience to our board of directors, including his service as a chief financial officer for over eight years. Mr. Biderman will also bring more than nine years of collective service on various boards of directors as well as his service on the audit committees of four other companies, including Atlas Energy’s general partner. In addition, the board of directors will benefit from his business acumen and valuable financial experience.

Dolly Ann (“DeAnn”) Craig. Dr. Craig has served as a director of ARP’s general partner since March 2012. Dr. Craig served as a consultant to Atlas Energy from April 2011 to January 2012. Dr. Craig is an Adjunct Professor in the Petroleum Engineering Department of the Colorado School of Mines since January 2009 and serves as a member of the Colorado Oil and Gas Conservation Commission since March 2009. Dr. Craig was the Senior Vice President – Asset Assessment with CNX Gas Corporation from September 2007 until February 2009. Previously, she served as President of Phillips Petroleum Resources, a Canadian subsidiary of Phillips Petroleum, and Manager of Worldwide Drilling and Production of Phillips Petroleum from July 1992 to October 1996. Dr. Craig has been a director for Samson Oil & Gas Limited since July 2011 and is the chairperson of its audit committee as well as a member of its compensation committee. Dr. Craig serves as chair of the environmental, health and safety committee of ARP’s general partner. Dr. Craig is a Registered Professional Engineer in the State of Colorado. Dr. Craig is a Past-President of the Society of Petroleum Engineers (SPE) and currently serves as the Treasurer for the Society of Petroleum Engineers’ Foundation. She is also a Past-President of the American Institute of Mining, Metallurgical, and Petroleum Engineers (AIME). Dr. Craig will bring to our board of directors a strong technical and operational background and practical expertise in issues relating to exploration and production activities. Dr. Craig’s experience, particularly her background in petroleum engineering, and her knowledge of the company resulting from her work as a consultant, will benefit the board of directors. In addition, Dr. Craig will provide leadership to the board of directors with respect to energy policy issues, owing to her experience as a member of the Colorado Oil and Gas Conservation Commission.

Dennis A Holtz. Mr. Holtz has served as a director of Atlas Energy’s general partner since February 2011. Before that, he was a director of Atlas Energy, Inc. from February 2004 to February 2011. Mr. Holtz maintained a corporate and real estate law practice in Philadelphia and New Jersey from 1988 until his retirement in January 2008. During that period, Mr. Holtz was counsel for or corporate secretary of numerous private and public business entities, and this extensive experience with corporate governance issues was the reason he was chosen as chair of New Atlas’s nominating and governance committee. As a licensed attorney with approximately 50 years of business experience, Mr. Holtz will offer a unique and invaluable perspective into corporate governance matters. Additionally, Mr. Holtz has extensive knowledge of the energy industry, having served as a director of former affiliated companies of New Atlas for nine years.

Walter C. Jones. Mr. Jones has served as a director of Atlas Energy’s general partner since October 2013. From April 2010 to October 2013, Mr. Jones served as the U.S. Executive Director and Chief-of-Mission to the African Development Bank in Tunis, Tunisia, having been nominated for the position by President Barack Obama in 2009 and confirmed by the U.S. Senate in 2010. In that position, he represented the United States on the African Development Bank’s Board of Directors, and served as chair of the bank’s audit committee and vice-chair of both the ethics and development effectiveness committees. From June 2005 until May 2007, Mr. Jones served as the Head of Private Equity and General Counsel at GRAVITAS Capital Advisors, LLC (an independent advisory firm). From May 1994 to May 2005, and then again from September 2007 until April 2010,

 

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Mr. Jones was at the Overseas Private Investment Corporation, where he served as Manager for Asia, Africa, the Middle East, Latin America and the Caribbean, as well as a Senior Investment Officer in the Finance Department. Prior to that, Mr. Jones was an International Consultant at the Washington, D.C. firm of Neill & Co. Mr. Jones began his career at the law firm of Sidley & Austin where he was a transactions attorney specializing in leveraged buyouts. Mr. Jones is a seasoned energy company director, having previously served as a director and chair of the audit committee of Atlas Energy Resources, LLC from December 2006 until September 2009 and a director of Atlas Energy, Inc. from September 2009 until March 2010. Mr. Jones’ combination of private and public sector experience, as well as his international work, has afforded him a unique combination of management and leadership experience. Our board of directors will also benefit from his investment and transaction expertise as well as his valuable financial experience.

Jeffrey F. Kupfer. Mr. Kupfer has served as a director of Atlas Energy’s general partner since March 2014. Mr. Kupfer is currently the Bernard Schwartz Fellow with the Asia Society, a non-profit, non-partisan global institution. He is also an Adjunct Professor of Policy and Management at Carnegie Mellon University’s H. John Heinz III College. From February 2011 to January 2014, Mr. Kupfer served as a senior advisor for policy and government affairs at Chevron and from September 2009 to February 2011, Mr. Kupfer served as a Senior Vice President at Atlas Energy, Inc. Before that, Mr. Kupfer held a number of high level positions in the U.S. Department of Energy. From March 2008 to January 2009, he was the Acting Deputy Secretary and Chief Operating Officer and from October 2006 to March 2008, he was the Chief of Staff. Mr. Kupfer also worked in the White House as a Special Assistant to the President for Economic Policy in 2006, as the Executive Director of the President’s Panel on Federal Tax Reform in 2005, and as Deputy Chief of Staff at the U.S. Treasury Department from 2001 to 2005. Mr. Kupfer will bring to the board of directors extensive experience in the energy industry, as well his perspective as a former senior official in the U.S. government, which New Atlas views as complementary to the industry perspective of other members of the board of directors.

Ellen F. Warren. Ms. Warren has served as a director of Atlas Energy’s general partner since February 2011. Before that, she was a director of Atlas Energy, Inc. from September 2009 until February 2011. She is founder and President of OutSource Communications, a marketing communications firm that services corporate and nonprofit clients. Prior to founding OutSource Communications in August 2005, she was President of Levy Warren Marketing Media, a public relations and marketing firm she co-founded in March 1998. She was previously Vice President of Marketing/Communications for Jefferson Bank (a Philadelphia-based financial institution) from September 1992 to February 1998, and President of Diversified Advertising, Inc. (an advertising and marketing firm) from December 1984 to September 1992, where she provided marketing services to various industries, including the energy industry. Ms. Warren is a seasoned energy company director, having also served as an independent member of the board of Atlas Energy Resources, LLC from December 2006 until September 2009, where she chaired a special committee, and later on the board of Atlas Energy, Inc., and she will bring this extensive experience to our board of directors. As a member of the National Association of Corporate Directors, Ms. Warren will also offer expertise in corporate governance matters. Ms. Warren has extensive public relations, corporate communications and marketing experience, having founded and led various marketing communications firms and will be uniquely positioned to provide leadership to the board of directors in public relations and communications matters. Ms. Warren will also bring valuable management, communication, community involvement and leadership skills to the board of directors.

Composition of the Board of Directors

Upon completion of the distribution, the board of directors will be divided into three classes, comprised of three, three and two directors, respectively. The directors designated as Class I directors will have terms expiring at the first annual meeting of unitholders following the distribution, which we expect will be held in 2016. The directors designated as Class II directors will have terms expiring at the following year’s annual meeting of unitholders, which we expect will be held in 2017, and the directors designated as Class III directors will have terms expiring at the following year’s annual meeting of unitholders, which we expect will be held in 2018. We expect that Class I directors will be comprised of Mark C. Biderman and DeAnn Craig; Class II directors will be

 

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comprised of Edward E. Cohen, Walter C. Jones and Jeffrey F. Kupfer; and Class III directors will be comprised of Jonathan Z. Cohen, Dennis A. Holtz and Ellen F. Warren. Commencing with the first annual meeting of unitholders following the separation, directors for each class will be elected at the annual meeting of unitholders held in the year in which the term for that class expires and thereafter will serve for a term of three years. At any meeting of unitholders for the election of directors at which a quorum is present, the election will be determined by a plurality of the votes cast by the unitholders entitled to vote in the election. A properly submitted proxy to “Withhold Authority” with respect to the election of one or more directors will not be voted with respect to the director or directors indicated, although it will be counted for purposes of determining whether there is a quorum.

Director Independence

A majority of the board of directors will be comprised of directors who are “independent” as defined by the rules of the NYSE and any standards of independence to be adopted by the board. We will seek to have all directors other than Edward E. Cohen and Jonathan Z. Cohen qualify as “independent” under these standards. The board of directors is expected to establish categorical standards to assist it in making its determination of director independence. We expect these standards will provide that no director qualifies as “independent” unless the board of directors affirmatively determines that the director has no material relationship with us or our subsidiaries (either directly or as a member, partner, shareholder or officer of an organization that has a relationship with us or any of our subsidiaries). In making this determination, the board of directors will (i) adhere to all of the specific tests for independence included in the NYSE listing standards, and (ii) consider all other facts and circumstances it deems necessary or advisable and any standards of independence as may be established by the board from time to time, including the following standards:

 

•

a director is not independent if the director is, or has been within the last three years, an employee of New Atlas or its subsidiaries, or if an immediate family member is, or has been within the last three years, an executive officer of New Atlas or its subsidiaries;

 

•

a director is not independent if the director has received, or has an immediate family member who has received, during any 12-month period within the last three years, more than $120,000 in direct compensation from New Atlas or its subsidiaries, other than director and committee fees and pension or other forms of deferred compensation for prior service (provided such compensation is not contingent in any way on continued service), and other than amounts received by an immediate family member for service as an employee (other than an executive officer);

 

•

a director is not independent if (A) the director or an immediate family member is a current partner of a firm that is New Atlas’s internal or external auditor; (B) the director is a current employee of such a firm; (C) the director has an immediate family member who is a current employee of such a firm and personally works on New Atlas’s or its subsidiaries’ audit; or (D) the director or an immediate family member was within the last three years a partner or employee of such a firm and personally worked on New Atlas or its subsidiaries’ audit within that time;

 

•

a director is not independent if the director or an immediate family member is, or has been within the last three years, employed as an executive officer of another company where any of the present executive officers of New Atlas or its subsidiaries at the same time serves or served on that company’s compensation committee;

 

•

a director is not independent if the director is a current employee, or if an immediate family member is a current executive officer, of a company that has made payments to, or received payments from, New Atlas or its subsidiaries for property or services in an amount that, in any of the last three fiscal years, exceeds the greater of $1 million or two percent of such other company’s consolidated gross revenues; and

 

•

a director is not independent if the director is an executive officer of a charitable organization that received charitable contributions (other than matching contributions) from New Atlas and its subsidiaries in the preceding fiscal year that are in excess of the greater of $1 million or two percent of such charitable organization’s consolidated gross revenues.

 

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The board of directors will assess on a regular basis, and at least annually, the independence of directors and, based on the recommendation of the Nominating and Corporate Governance Committee, will make a determination as to which members are independent. References to “New Atlas,” “we” or “us” above include any subsidiary in a consolidated group with us. The terms “immediate family member” and “executive officer” above are expected to have the same meanings specified for such terms in the NYSE listing standards.

Committees of the Board of Directors

The independent board members will comprise all of the members of the board’s committees: the audit committee, the compensation committee, the nominating and governance committee, the investment committee and the conflicts committee.

Audit Committee. Messrs. Biderman, Jones and Kupfer are expected to be the members of the Audit Committee, with Mr. Biderman acting as the chairman. The principal functions of the Audit Committee will be to assist the board in monitoring the integrity of our and ARP’s financial statements, our and ARP’s independent auditor’s qualifications and independence, the performance of our and ARP’s independent auditors and our and ARP’s compliance with legal and regulatory requirements. The Audit Committee will review the scope and effectiveness of audits by our and ARP’s independent accountants, is responsible for the engagement of independent accountants and reviews the adequacy of our and ARP’s internal controls. The board of directors is expected to determine that at least one member of the Audit Committee is an “audit committee financial expert” for purposes of the rules of the SEC. In addition, the board is expected to determine that at least one member of the Audit Committee has accounting or related financial management expertise and that each member is financially literate as required by NYSE rules. In addition, we expect that the board of directors will determine that each of the members of the Audit Committee will be independent, as defined by the rules of the NYSE, Section 10A(m)(3) of the Exchange Act, and any independence standards to be adopted by the board.

Compensation Committee. Ms. Warren and Mr. Holtz are expected to be the members of the Compensation Committee, with Ms. Warren acting as the chairperson. The principal functions of the Compensation Committee will be to assist the board of directors in carrying out its responsibilities with respect to compensation. The Compensation Committee will evaluate the compensation paid or payable to the chief executive officer and our other named executive officers. The Compensation Committee will review compensation paid or payable under employee qualified benefit plans, employee stock option and restricted stock option plans, under individual employment agreements, and executive compensation and bonus programs. The Compensation Committee, together with senior management, also reviews compensation programs and benefits plans affecting our employees generally (in addition to those applicable to our executive officers), to determine that our compensation policies and practices do not create risks that are reasonably likely to have a material adverse effect on the company. The Compensation Committee will have the sole authority, under its charter, to select, retain and/or terminate independent compensation advisors. The board of directors is expected to determine that each member of the Compensation Committee will be independent, as defined by the rules of the NYSE and in accordance with any independence standards to be adopted by the board. In addition, we expect that the members of the Compensation Committee will qualify as “non-employee directors” for purposes of Rule 16b-3 under the Exchange Act.

Nominating and Governance Committee. Ms. Warren and Messrs. Holtz and Kupfer are expected to be the members of the Nominating and Governance Committee, with Mr. Holtz acting as the chairman. The board of directors is expected to determine that each of the members of the Nominating and Governance Committee will be independent, as defined by the rules of the NYSE and in accordance with any independence standards to be adopted by the board. The principal functions of the Nominating and Governance Committee will be to recommend persons to be selected by the board as nominees for election as directors, recommend persons to be elected to fill any vacancies on the board, consider and recommend to the board qualifications for the office of director and policies concerning the term of office of directors and the composition of the board and consider and recommend to the board other actions relating to corporate governance.

 

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Investment Committee. Messrs. Biderman, Jones and Kupfer are expected to be the members of the Investment Committee, with Mr. Jones acting as the chairman. The board of directors is expected to determine that each of the members of the Investment Committee will be independent, as defined by the rules of the NYSE and in accordance with any independence standards to be adopted by the board. The principal functions of the Investment Committee will be to assist the board in reviewing management investment practices, policies, strategies, transactions and performance, as well as evaluating and monitoring existing and proposed investments.

ARP Conflicts Committee. The ARP Conflicts Committee will review specific matters that the board of directors believes may involve conflicts of interest between us, on the one hand, and ARP and its limited partners, on the other hand. The ARP Conflicts Committee will determine if the conflict of interest has been resolved in accordance with our limited liability company agreement and ARP’s limited partnership agreement. Any matters approved by the ARP Conflicts Committee will be conclusively deemed to be fair and reasonable to ARP, approved by all of ARP’s unitholders and not a breach by ARP’s general partner of any duties it may owe to ARP or ARP’s unitholders. Members of the ARP Conflicts Committee must not be an officer or employee of us and must not be an officer, director or employee of any of our affiliates, must not own any ownership interest in us or ARP other than ARP’s common units and other awards granted to such director under ARP’s equity compensation plans, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors.

Environmental, Health and Safety Committee. Dr. Craig and Messrs. Holtz and Kupfer are expected to be the members of the Environmental, Health and Safety Committee, with Dr. Craig acting as the chairman. The board of directors is expected to determine that each of the members of the Environmental, Health and Safety Committee will be independent, as defined by the rules of the NYSE and in accordance with any independence standards to be adopted by the board. The Environmental, Health and Safety Committee will assist the board of directors in determining whether we and ARP have appropriate policies and management systems in place with respect to environment, health and safety and related matters. The committee will monitor the adequacy of our and ARP’s policies and management for addressing environmental, health and safety matters consistent with prudent exploration and production industry practices. The Environmental, Health and Safety Committee will monitor and review compliance with applicable environmental, health and safety laws, rules and regulations. The committee will also review actions taken by our and ARP’s management with respect to deficiencies identified or improvements recommended.

The board of directors is expected to adopt a written charter for each of the Audit Committee, the Compensation Committee, the Nominating and Governance Committee and the Environmental, Health and Safety Committee. These charters will be posted on our website in connection with the separation.

Compensation Committee Interlocks and Insider Participation

During the company’s year ended December 31, 2013, we were not an independent entity, and did not have a compensation committee or any other committee serving a similar function. Decisions as to the compensation of those who currently serve as our executive officers were made by Atlas Energy, as described in the section of this information statement captioned “Compensation Discussion and Analysis.”

Corporate Governance

Board Leadership; Executive Sessions of the Board

Jonathan Z. Cohen will serve as the Executive Chairman of the board and Edward E. Cohen will serve as our Chief Executive Officer and President. We believe that the most effective leadership structure at the present time is to have separate Executive Chairman of the board and Chief Executive Officer positions because this allows the board to benefit from having two strong voices bringing separate views and perspectives to meetings. We expect the Chief Executive Officer and the Executive Chairman of the board to be in regular contact and to serve together with Matthew A. Jones, who will serve as a Senior Vice President, as our executive committee.

 

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As set forth in our governance guidelines and in accordance with NYSE listing standards, the non-management members of our board of directors will meet in executive session regularly without management. The managing board member who presides at these meetings will rotate each meeting. The purpose of these executive sessions will be to promote open and candid discussion among the non-management board members.

Governance Guidelines

The board of directors is expected to adopt a set of Governance Guidelines in connection with the separation to assist it in guiding our governance practices. These practices will be regularly reevaluated by the Nominating and Governance Committee in light of changing circumstances in order to continue serving our best interests and the best interests of our unitholders.

Role in Risk Oversight

The board’s role in risk oversight will recognize the multifaceted nature of risk management. We expect our board to administer its risk oversight function through our Audit Committee and Environmental, Health and Safety Committee. The Audit Committee will monitor material enterprise risks and, in order to assist in its oversight function, will create an enterprise risk management committee consisting of senior officers from our various divisions that are responsible for day-to-day risk oversight. The Audit Committee will meet with the members of the enterprise risk management committee as needed to discuss our risk management framework and related areas. The Audit Committee will also review with counsel legal compliance and legal matters that could have a significant impact on our financial statements. Our Audit Committee will oversee our internal audit function and will be responsible for monitoring the integrity and ensuring the transparency of our financial reporting processes and systems of internal controls regarding finance, accounting and regulatory compliance. These risk oversight functions will be incorporated in the Audit Committee’s regular reports to the board of directors. The Environmental, Health and Safety Committee will assist in determining whether appropriate policies and management systems are in place with respect to environment, health and safety and related matters and will monitor and review compliance with applicable environmental, health and safety laws, rules and regulations. The Environmental, Health and Safety Committee will review actions taken by management with respect to deficiencies identified or improvements recommended.

We expect our full board to regularly engage in discussions of the most significant risks that we face and how these risks are being managed. Our senior executives will provide the board and its committees with regular updates about our strategies and objectives, and the risks inherent with them, at board and committee meetings and in regular reports. Board and committee meetings will also provide a venue for directors to discuss issues of concern with management. The board and committees will be able to call special meetings when necessary to address specific issues or matters that should be addressed before the next regularly scheduled meeting. Our directors will have access to our management at all levels to discuss any matters of interest, including those related to risk. Those members of management most knowledgeable of the issues will attend board meetings to provide additional insight into items being discussed, including risk exposures.

Director Nomination Process

The Nominating and Governance Committee will be responsible for reviewing with our board of directors the appropriate skills and characteristics required of board members in the context of the makeup of the board of directors and developing criteria for identifying and evaluating board candidates.

The Nominating and Governance Committee will identify director nominees by first evaluating the current members of the board willing to continue in service. Current members with skills and experience that are relevant to our business and who are willing to continue in service will be considered for renomination, balancing the value of continuity of service by existing members of the board with that of obtaining a new perspective. If any member of the board does not wish to continue in service, or if the Nominating and Governance Committee or the board decides not to nominate a member for reelection, or if we decide to expand the size of the board, the

 

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Nominating and Governance Committee will identify the desired skills and experience of a new nominee consistent with the Nominating and Governance Committee’s criteria for board service. Current members of the board and management will be polled for their recommendations. Research may also be performed or third parties retained to identify qualified individuals. From time to time, we may engage an executive search firm to assist the committee in identifying individuals qualified to be board members. The Nominating and Governance Committee will consider diversity as an element in identifying director nominees.

The Nominating and Governance Committee will evaluate independent director candidates based upon a number of criteria, including:

 

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commitment to promoting the long-term interests of our unitholders and independence from any particular constituency;

 

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professional and personal reputations that are consistent with our values;

 

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broad general business experience and acumen, which may include experience in management, finance, marketing and accounting;

 

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a high level of personal and professional integrity;

 

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adequate time to devote attention to the board;

 

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such other attributes, including independence, relevant in constituting a board that also satisfy the requirements imposed by the SEC and the NYSE; and

 

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board balance in light of our current and anticipated needs and the attributes of the other directors and executives.

The specific criteria that the Nominating and Governance Committee will use to identify a nominee to serve as a member of the board of directors will depend on the qualities being sought. The committee may reevaluate the relevant criteria for board membership from time to time in response to changing business factors or regulatory requirements. The full board of directors will be responsible for selecting candidates for election as directors based on the recommendation of the Nominating and Governance Committee.

Our limited liability company agreement will contain provisions that address the process by which a unitholder may nominate an individual to stand for election to the board of directors. We expect that the board of directors will adopt a policy concerning the evaluation of unitholder recommendations of board candidates by the Nominating and Governance Committee.

Communicating with the Board of Directors

Our Governance Guidelines will include procedures by which unitholders and other interested parties who would like to communicate their concerns to one or more members of our board of directors, a board committee or the independent non-management directors as a group may do so by writing to them at Atlas Energy Group, LLC, Park Place Corporate Center One, 1000 Commerce Drive, 4^th Floor, Pittsburgh, Pennsylvania 15275, c/o Chair, Audit Committee. All concerns received will be appropriately forwarded and, if deemed appropriate by the chair of the Audit Committee, may be accompanied by a report summarizing such concerns.

Code of Business Conduct and Ethics

In connection with the separation, we will adopt a Code of Business Conduct and Ethics, which we refer to as the “Code of Conduct,” that requires all our business activities to be conducted in compliance with laws, regulations, and ethical principles and values. All of our directors, officers and employees will be required to read, understand and abide by the requirements of the Code of Conduct. The Code of Conduct will be accessible on our website. Any waiver of the Code of Conduct for directors or executive officers may be made only by our board of directors. We will disclose any amendment to, or waiver from, a provision of the Code of Conduct for

 

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the principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, on our website within four business days following the date of the amendment or waiver. In addition, we will disclose any waiver from the Code of Conduct for the other executive officers and for directors on our website.

Procedures for Treatment of Complaints Regarding Accounting, Internal Accounting Controls and Auditing Matters

In accordance with the Sarbanes-Oxley Act of 2002, we expect that the Audit Committee will adopt procedures for the receipt, retention and treatment of complaints regarding accounting, internal accounting controls, and auditing matters and to allow for the confidential, anonymous submission by employees and others of concerns regarding questionable accounting or auditing matters.

 

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COMPENSATION DISCUSSION AND ANALYSIS

As discussed above, we are currently part of Atlas Energy and not an independent company, and our compensation committee has not yet been formed. This Compensation Discussion and Analysis describes the historical compensation practices of Atlas Energy and attempts to outline certain aspects of our anticipated compensation structure for our senior executive officers following the separation. While we have discussed its anticipated programs and policies with the Compensation Committee of Atlas Energy GP’s board of directors (the “Atlas Energy Compensation Committee”), they remain subject to the review and approval of New Atlas’s own compensation committee (the “New Atlas Compensation Committee”).

The employees who are expected to be appointed to serve as our Chief Executive Officer and President, Chief Financial Officer, Executive Chairman of the Board, Senior Vice President of Corporate Development and Strategy, and Senior Vice President and President of ARP are identified below, and each of such individuals is currently an executive officer of Atlas Energy. The historical decisions relating to their compensation as executive officers of Atlas Energy in 2014 and prior years have been made by the Atlas Energy Compensation Committee. Following the separation, the compensation of our executive officers will be determined by the New Atlas Compensation Committee consistent with the compensation and benefit plans, programs and policies adopted by us.

For purposes of the following Compensation Discussion and Analysis and executive compensation disclosures, the individuals listed below are collectively referred to as our or Atlas Energy’s “Named Executive Officers” or “NEOs.” They are our Chief Executive Officer and President, Chief Financial Officer, Executive Chairman of the Board, Senior Vice President of Corporate Development and Strategy, and Senior Vice President and President of ARP. Their compensation is disclosed in the tables following this discussion and analysis.

 

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Edward E. Cohen, Chief Executive Officer and President

 

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Sean P. McGrath, Chief Financial Officer

 

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Jonathan Z. Cohen, Executive Chairman of the Board

 

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Daniel C. Herz, Senior Vice President, Corporate Development and Strategy

 

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Matthew A. Jones, Senior Vice President and President of ARP

Initially, our compensation policies will be substantially the same as those employed by Atlas Energy. The New Atlas Compensation Committee will review these policies and practices and, it is expected, will make adjustments to support our strategies and to remain market competitive. The following sections of this Compensation Discussion and Analysis describe Atlas Energy’s compensation philosophy, policies and practices as they applied to the Named Executive Officers identified above during 2014.

Compensation Objectives

Historically

Atlas Energy believes that its compensation program must support its business strategy, be competitive, and provide both significant rewards for outstanding performance and clear financial consequences for underperformance. Atlas Energy also believes that a significant portion of the NEOs’ compensation should be “at risk” in the form of annual and long-term incentive awards that are paid, if at all, based on individual and company accomplishments.

Going Forward

As noted above, since the New Atlas Compensation Committee has not yet been formed, our policies and executive compensation philosophy will be developed and established by the New Atlas Compensation Committee.

 

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Governance of Executive Compensation

Compensation Committee

Historically

The Atlas Energy Compensation Committee is responsible for designing Atlas Energy’s compensation objectives and methodology, and evaluating the compensation to be paid to Atlas Energy’s NEOs. The Atlas Energy Compensation Committee is also responsible for administering Atlas Energy’s clawback policy, stock ownership guidelines and employee benefit plans, including incentive plans.

Atlas Energy’s NEOs and other employees who perform services for ARP and APL may receive bonus and equity awards from ARP and/or APL. ARP has delegated compensation decisions to the Compensation Committee because ARP does not have its own compensation committee and does not directly employ its officers. Therefore, the Atlas Energy Compensation Committee determines awards to be made by ARP to Atlas Energy’s NEOs, as well as determining the compensation to be paid to NEOs of ARP. Since April 2012, APL has had its own compensation committee that determines compensation for its NEOs. APL’s compensation committee provides its determinations to the Atlas Energy Compensation Committee, and the Atlas Energy Compensation Committee retains the right to accept, reject, or modify the determinations with respect to the NEOs who serve both companies.

During 2014, the Atlas Energy Compensation Committee was comprised solely of independent directors, consisting of Ms. Warren and Messrs. Arrendell and Holtz, with Ms. Warren acting as the chair.

Going Forward

As noted above, since the New Atlas Compensation Committee has not yet been formed, but we anticipate that its responsibilities will be identical to those of the Atlas Energy Compensation Committee and that it will be comprised solely of independent directors. We also anticipate that our NEOs may receive bonuses and equity awards from ARP following the separation, but they will no longer receive any such awards from APL.

Chief Executive Officer

Historically

The Atlas Energy Chief Executive Officer makes recommendations to the Atlas Energy Compensation Committee regarding the salary, bonus and incentive compensation component of each of the other NEO’s total compensation. The Atlas Energy Chief Executive Officer provides the Atlas Energy Compensation Committee with key elements of Atlas Energy’s and the other NEOs’ performance during the year. The Atlas Energy Chief Executive Officer, at the Atlas Energy Compensation Committee’s request, may attend committee meetings solely to provide insight into Atlas Energy’s and the other NEOs’ performance, as well as the performance of other comparable companies in the same industry.

Going Forward

As noted above, since the New Atlas Compensation Committee has not yet been formed, the role of our Chief Executive Officer in making recommendations to the New Atlas Compensation Committee will be developed and established by the New Atlas Compensation Committee following the separation.

Independent Compensation Consultant

Historically

For 2014, the Atlas Energy Compensation Committee engaged Mercer (US) Inc. (referred to as “Mercer”), an independent compensation consulting firm, to provide information and objective advice regarding executive

 

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compensation. All of the decisions with respect to Atlas Energy’s NEOs’ compensation, however, are made by the Atlas Energy Compensation Committee or, in the case of awards from APL, the APL compensation committee, which communicates the APL award information to the Atlas Energy Compensation Committee.

Mercer worked with Atlas Energy senior management to develop a peer group in 2012 that reflected, as close as possible, Atlas Energy’s business mix, structure and size. The peer group is comprised of 14 oil and gas companies with the majority having revenues ranging from 1/2 to 2 times Atlas Energy’s revenues, which are near the median. The 2014 peer group is the same as the peer group used in 2013. The members of the peer group are:

 

Ticker		Company Name		2013 Revenues ($ millions)
NGLS		TARGA RESOURCES CORP		$	6,556
PXD		PIONEER NATURAL RESOURCES CO		$	3,490
SWN		SOUTHWESTERN ENERGY CO		$	3,371
WLL		WHITING PETROLEUM CORP		$	2,696
LINE		LINN ENERGY LLC		$	2,320
SD		SANDRIDGE ENERGY INC		$	1,983
MMP		MAGELLAN MIDSTREAM PRTNRS LP		$	1,898
EQT		EQT CORP		$	1,862
RRC		RANGE RESOURCES CORP		$	1,772
COG		CABOT OIL & GAS CORP		$	1,746
MWE		MARKWEST ENERGY PARTNERS LP		$	1,662
EROC		EAGLE ROCK ENERGY PARTNRS LP		$	1,195
CRZO		CARRIZO OIL & GAS INC		$	520
EVEP		EV ENERGY PARTNERS LP		$	315

 

Summary Statistics (n= 14)
75th Percentile:		$	2,602
Median		$	1,880
25th Percentile:		$	1,683
ATLAS ENERGY		$	2,584

Source: Standard & Poor’s Compustat Database

Mercer’s analysis also included its compensation survey data for the oil and gas industry. Mercer’s analysis included:

 

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A market competitive assessment against the peer group and survey data evaluating base salaries, total cash compensation and total direct compensation (representing the annualized long-term incentive award value plus total cash compensation), as well as pay mix. Mercer found that:

 

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base salaries were competitive (defined as within 15% of a market benchmark) with the 90th percentile of the peer group and the median of the survey, except for Mr. Jones’, which was competitive with the median of both groups, Mr. Herz’s, which was competitive with the 75th percentile of the survey, and Mr. McGrath’s, which was competitive with the median and 75th percentile of the peer group and below the competitive range of the 25th percentile of the survey;

 

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total cash compensation was competitive with the 75th percentile of the peer group and the median of the survey, except for Mr. E. Cohen’s, which was competitive with between the 50th and the 75th percentile of the peer group, Mr. J. Cohen’s, which was competitive with the 90th percentile of the peer group, Mr. Jones’, which was competitive with the 75th percentile of the survey, and Mr. Herz’s, which was competitive with the 90th percentile of the peer group and the survey;

 

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total direct compensation was at or above the 90th percentile of the peer group and the survey, except for Mr. McGrath’s, which was competitive with the 75th percentile of the peer group and the survey; and

 

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in the aggregate, Atlas Energy places more emphasis on long-term incentives than the peer group or the survey, reinforcing alignment with unitholders.

 

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A pay for performance assessment that tests the alignment between the actual compensation awarded and total shareholder return for the 3-year and 1-year periods ending December 2013 against the peer group. Mercer found that:

 

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Atlas Energy’s total shareholder return was generally aligned with its peers for both periods;

 

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on a three-year basis, Atlas Energy’s total direct compensation was aligned with total shareholder return; and

 

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on a one-year basis, Atlas Energy’s total cash compensation was aligned with total shareholder return.

 

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A run rate and dilution assessment that reviewed potential economic dilution and economic run rate against the peer group. Mercer found that Atlas Energy’s three-year average economic run rate (including ARP and APL) was between the 75th and 90th percentiles of the peer group but that potential economic dilution falls just below the median of the peer group as vesting of past awards has moderated total market overhang relative to the prior year.

A critical criterion in the Atlas Energy Compensation Committee’s selection of Mercer to provide executive and director compensation consulting services was the fact that Mercer does not provide any other services to Atlas Energy or its affiliated companies. In addition to reaffirming this on an annual basis, Atlas Energy also conducts a search of its accounts payable system to confirm that no Mercer affiliates are providing services outside of the compensation consulting services. As discussed in “Directors—Corporate Governance—Code of Business Conduct and Ethics” and “Certain Relationships and Related Party Transactions,” Atlas Energy has a Code of Business Conduct and Ethics as well as a related party transaction policy which governs potential conflicts of interest. Atlas Energy directors and officers are also required to complete questionnaires on an annual basis which allows Atlas Energy to review whether there are any potential conflicts as a result of personal or business relationships. There are no business or personal relationships between the consultants from Mercer who work with Atlas Energy and its directors and executive officers other than the compensation consulting described herein.

Going Forward

Following the separation, the New Atlas Compensation Committee will need to select compensation consultants and other advisors and may initially choose to use the same consultants and advisors as those used by the Atlas Energy Compensation Committee. The New Atlas Compensation Committee will also work with the selected compensation consultant to develop a peer group that reflects, as closely as possible, the business mix, structure, and size of New Atlas.

Timing of Compensation Decision Process

Historically

The Atlas Energy Compensation Committee makes its determination on compensation amounts shortly after the close of Atlas Energy’s fiscal year. In the case of base salaries, the committee recommends the amounts to be paid for the new fiscal year. In the case of annual bonus and long-term incentive compensation, the committee determines the amount of awards based on the most recently concluded fiscal year.

Atlas Energy typically pays cash awards and issues equity awards in February of each year, although the Atlas Energy Compensation Committee has the discretion to recommend salary adjustments and the issuance of

 

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equity awards at other times during the fiscal year. In addition, Atlas Energy’s NEOs and other employees who perform services for APL may receive annual bonus and long-term incentive compensation awarded by APL’s compensation committee.

Going Forward

Following the separation, the New Atlas Compensation Committee will need to determine the process by which it makes compensation decisions, and may initially choose to use the process as that used by the Atlas Energy Compensation Committee.

Elements of Atlas Energy’s Compensation Program

Historically

Base Salary

Base salary is intended to provide fixed compensation to the NEOs for their performance of core duties that contribute to Atlas Energy’s success. Base salaries are not intended to compensate individuals for their extraordinary performance or for above average company performance.

Annual Incentives

Annual incentives are intended to tie a significant portion of each of the NEO’s compensation to Atlas Energy’s annual performance and/or that of Atlas Energy’s subsidiaries or divisions for which the officer is responsible. Generally, the higher the level of responsibility of the executive within Atlas Energy, the greater is the incentive component of that executive’s target total cash compensation. The Atlas Energy Compensation Committee may recommend awards of performance-based bonuses and discretionary bonuses.

Performance-Based Bonuses

Atlas Energy has an Annual Incentive Plan for Senior Executives, which it refers to as the Atlas Energy Senior Executive Plan, to award bonuses for achievement of predetermined performance objectives during a 12-month performance period, generally its fiscal year. During 2014, each of the NEOs other than Mr. Herz, participated in the Atlas Energy Senior Executive Plan. Awards under the Atlas Energy Senior Executive Plan may be paid in cash or in a combination of cash and time-vesting equity. Making all equity awards vest over time adds an additional performance-based component to the bonuses.

 

During 2014, the Atlas Energy Compensation Committee approved 2014 bonus awards to be paid from a bonus pool for all NEOs other than Mr. Herz, who has not historically been an Atlas Energy NEO. The theoretical bonus pool is equal to a maximum of 10% of the distributable cash flow of Atlas Energy’s entire enterprise, but actual amounts awarded have been much less. One of two goals for 2014 had to be met before any bonuses would be paid:

 

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at least 80% of the average distributable cash flow allocable to Atlas Energy for the past three years; and

 

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at least 80% of the average production volumes (which for ARP means production volumes and for APL means gathered volumes) for the past three years.

 

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The goals are set early in the year, but actual awards are ultimately determined by the Atlas Energy Compensation Committee’s year-end evaluation that also evaluates other factors as set forth below. While the Atlas Energy Compensation Committee has the discretion to make awards even if one of the goals is not met, it does not anticipate doing so absent exceptionally rare circumstances justifying the payment of a bonus.

In the event that distributable cash flow includes any capital transaction gains in excess of $50 million, then only 10% of that excess is included in the bonus pool. Distributable cash flow means the sum of (i) cash available for distribution by us, including the distributable cash flow of any of its subsidiaries (regardless of whether such cash is actually distributed), plus (ii) to the extent not otherwise included in distributable cash flow, any realized gain on the sale of securities, including securities of a subsidiary, less (iii) to the extent not otherwise included in distributable cash flow, any loss on the sale of securities, including securities of a subsidiary. A return of Atlas Energy’s capital investment in a subsidiary was not intended to be included and, accordingly, if distributable cash flow included proceeds from the sale of all or substantially all of the assets of a subsidiary, the amount of such proceeds to be included in distributable cash flow would be reduced by Atlas Energy’s basis in the subsidiary.

The maximum award, expressed as a percentage of Atlas Energy’s estimated 2014 distributable cash flow, for each participant was as follows: Mr. E. Cohen, 3.40% ($15,600,000); Mr. J. Cohen, 3.00% ($13,700,000); Mr. Jones, 1.60% ($7,300,000); and Mr. McGrath, 0.80% ($3,700,000). While the final maximum bonus pool amount was $45.8 million, actual awards made to the NEOs totaled $5.35 million, or approximately 12% of the maximum bonus pool.

Pursuant to the terms of the Atlas Energy Senior Executive Plan, the Atlas Energy Compensation Committee has discretion to recommend reductions, but not increases, in maximum awards under the Atlas Energy Senior Executive Plan. In making its decisions, the Atlas Energy Compensation Committee considers factors including, growth of reserves, growth in production, processing and intake of natural gas, total market and distribution return to unitholders, and health and safety performance.

Discretionary Bonuses

In exceptional circumstances, discretionary bonuses may be awarded to recognize individual and group performance without regard to limitations otherwise in effect.

Long-Term Incentives

Atlas Energy believes that its long-term success depends upon aligning its executives’ and unitholders’ interests. To support this objective, Atlas Energy provides its executives with various means to become significant equity holders, including awards under the Atlas Energy 2006 Long-Term Incentive Plan (the “Atlas Energy 2006 Plan”) and the Atlas Energy 2010 Long-Term Incentive Plan (the “Atlas Energy 2010 Plan”), which we refer to as the Atlas Energy Plans. Under the Atlas Energy Plans, the Atlas Energy Compensation Committee may recommend grants of equity awards in the form of options and/or phantom units. Generally, the unit options and phantom units vest over a three- or four-year period.

Atlas Energy’s NEOs are eligible to receive awards under ARP’s 2012 Long-Term Incentive Plan, which we refer to as the ARP Plan. Atlas Energy’s NEOs are also eligible to receive awards under APL’s 2004 Long-Term Incentive Plan and its 2010 Long-Term Incentive Plan, which we refer to as the APL Plans; however, awards under the APL Plans are determined by the APL compensation committee and the amount of the APL awards are communicated to the Atlas Energy Compensation Committee.

Going Forward

After the separation, the New Atlas Compensation Committee will adopt and develop practices and procedures with respect to compensation decisions relating to base salary, annual incentives, and long-term incentives within the framework of the compensation plans adopted by us, which initially will be substantially

 

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similar to Atlas Energy’s compensation plans. Additional information about the New Atlas Senior Executive Plan and New Atlas 2014 Long-Term Incentive Plan is set forth in the sections of this information statement captioned “—New Atlas Senior Executive Plan” and “—New Atlas 2014 Long-Term Incentive Plan,” respectively.

The New Atlas Compensation Committee will develop a process for establishing financial and non-financial performance goals that will be structured around our business goals and will provide appropriate incentives to our executive officers following the separation. We expect that the target levels for the annual incentive and long-term incentive compensation opportunities of our Named Executive Officers following the separation will be set based on each Named Executive Officer’s post-separation level of responsibility and competitive market rates.

In addition, in connection with the separation, outstanding Atlas Energy and APL equity awards held by our employees generally, including our Named Executive Officers, will be treated as follows:

 

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Each option to purchase Atlas Energy common units will be converted into an adjusted Atlas Energy option and a New Atlas option. The exercise price and number of units subject to each option will be adjusted in order to preserve the aggregate intrinsic value of the original Atlas Energy option as measured immediately before and immediately after the separation, subject to rounding.

 

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Holders of Atlas Energy phantom unit awards, including Atlas Energy non-employee directors, will retain those awards and also will receive a New Atlas phantom unit award covering a number of New Atlas common units that that reflects the distribution to Atlas Energy unitholders, determined by applying the distribution ratio to Atlas Energy phantom unit awards as though they were actual Atlas Energy common units.

 

•

Immediately following the separation and distribution, all New Atlas options and phantom unit awards will be cancelled and settled for the implied value of a New Atlas common unit less, in the case of New Atlas options, the applicable exercise price. All New Atlas options and phantom unit awards will be settled in cash, subject to a specified aggregate cap on the amount of cash that may be distributed in respect of all New Atlas equity awards held by employees and non-employee directors. If the cap is exceeded, then any amounts payable to holders of New Atlas equity awards in excess of the cap will be settled in New Atlas common units.

 

•

The adjusted Atlas Energy equity awards will be cancelled and converted or settled as provided in the Atlas merger agreement.

 

•

APL equity awards will be cancelled and converted or settled as provided in the APL merger agreement.

ARP equity awards will not be adjusted in connection with the separation and will remain outstanding in accordance with their respective terms.

Additional Information Concerning Executive Compensation

Historically

Deferred Compensation

All Atlas Energy employees may participate in the Atlas Energy 401(k) plan, which is a qualified defined contribution plan designed to help participating employees accumulate funds for retirement. In July 2011, Atlas Energy established the Atlas Energy Executive Excess 401(k) Plan (the “Atlas Energy Deferred Compensation Plan”), a nonqualified deferred compensation plan that is designed to permit individuals who exceed certain income thresholds and who may be subject to compensation and/or contribution limitations under Atlas Energy’s 401(k) plan to defer an additional portion of their compensation. The purpose of the Atlas Energy Deferred Compensation Plan is to provide participants with an incentive for a long-term career with Atlas Energy by providing them with an appropriate level of replacement income upon retirement. Under the Atlas Energy

 

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Deferred Compensation Plan, a participant may contribute to an account an amount up to 10% of annual cash compensation (which means a participant’s salary and non-performance-based bonus) and up to 100% of all performance-based bonuses. Atlas Energy is obligated to make matching contributions on a dollar-for-dollar basis of the amount deferred by the participant subject to a maximum matching contribution equal to 50% of the participant’s base salary for any calendar year. Atlas Energy does not pay above-market or preferential earnings on deferred compensation. Participation in the Atlas Energy Deferred Compensation Plan is available pursuant to the terms of an individual’s employment agreement or at the designation of the Atlas Energy Compensation Committee. During 2014, Messrs. E. Cohen and J. Cohen were the only participants in the Atlas Energy Deferred Compensation Plan. For further details, please see “2014 Nonqualified Deferred Compensation” table.

Post-Termination Compensation

Atlas Energy’s NEOs received substantial cash amounts from Chevron in connection with the Chevron Merger, both as a result of the termination payments due under their employment agreements and their equity holdings. The Atlas Energy Compensation Committee believed that the amounts thus realized left Atlas Energy’s NEOs without adequate financial incentives to continue employment with us, which the Atlas Energy Compensation Committee did not believe was in Atlas Energy’s interest as it moved forward with significant new operations. In order to encourage these executives to remain with Atlas Energy on a long-term basis, it entered into employment agreements with Messrs. E. Cohen, J. Cohen, Jones and Herz that, among other things, provide compensation upon termination of their employment by reason of death or disability, by Atlas Energy without cause or by each of them for good reason. See “Executive Compensation—Employment Agreements and Potential Payments Upon Termination or Change of Control.”

The Atlas Energy Compensation Committee considered the following in entering into these agreements:

 

•

“Double trigger” severance payments—Change in control severance benefits (base salary and bonus payments) to each NEO are paid pursuant to a “double-trigger,” which means that to receive such benefits employment must terminate both: (1) as a result of a qualifying termination of employment, where his position with Atlas Energy changes substantially and is essentially an involuntary termination, and (2) after a change in control.

 

•

Benefit multiple—The compensation committee determined the benefit multiple, that is, the cash severance amount based on each executive’s salary and bonus, after consideration of comparable market practices provided to the committee by Mercer.

Clawback Policy

In February 2014, the Atlas Energy Compensation Committee established a Clawback Policy pursuant to which NEOs and other key executive officers will be required to return incentive compensation paid to them if the financial results upon which the awards were based are restated due to the fraud or intentional illegal conduct of the executive officer.

The Clawback Policy does not authorize the Atlas Energy Compensation Committee to seek recovery to the extent it determines that to do so would be unreasonable or that it would be better for Atlas Energy not to do so. The Atlas Energy Compensation Committee will determine in its discretion if it will seek to recover applicable compensation, taking into account the following considerations as it deems appropriate:

 

•

whether the amount of any bonus or equity compensation paid or awarded during the covered time period, based on the achievement of specific performance targets, would have been reduced based on the restated financial results;

 

•

the likelihood of success of recouping the compensation under governing law relative to the cost and effort involved;

 

•

whether the assertion of the claim may prejudice Atlas Energy’s interests, including in any related proceeding or investigation;

 

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•

the passage of time since the occurrence of the misconduct; and

 

•

any pending legal action related to the misconduct.

Atlas Energy believes its Clawback Policy is sufficiently broad to reduce the potential risk that an executive officer would intentionally misstate results in order to benefit under an incentive program and provides a right of recovery in the event that an executive officer takes actions that, in hindsight, should not have been rewarded.

This Clawback Policy applies in addition to the clawback provisions of awards under the Atlas Energy Plans, which provide that the Atlas Energy Compensation Committee has the express right to cancel an option or phantom unit grant, and to demand the return of any vested units, if the recipient has disclosed confidential information or trade secrets or engaged in any activity in competition with Atlas Energy’s business or the business of any of its subsidiaries or, in the case of the Atlas Energy 2006 Plan awards, is convicted of a felony or a crime of moral turpitude with respect to Atlas Energy or engages in fraud or embezzlement with respect to Atlas Energy.

Stock Ownership Guidelines for NEOs

In February 2014, the Atlas Energy Compensation Committee established unit ownership guidelines for Atlas Energy’s NEOs pursuant to which these executives are expected to hold a minimum number of Atlas Energy’s common units equal to a specified multiple of their annual base salaries, as follows:

 

Position		Required ownership multiple
Chief Executive Officer		Five (5) times annual base salary
Executive Chair and Executive Vice Chair		Four (4) times annual base salary
Chief Financial Officer		Three (3) times annual base salary
Executive Vice Presidents		Three (3) times annual base salary
Senior Vice Presidents		Two (2) times annual base salary

Equity interests that count toward the satisfaction of the ownership guidelines include common units held directly or indirectly by the executive, including common units purchased on the open market or acquired upon the exercise of a stock option and common units remaining or received upon the settlement of restricted stock, restricted stock units, and phantom units, and vested units allocated to the executive’s account under any qualified plan. Common units of APL and ARP will also satisfy the ownership guidelines so long as at least 50% of an executive’s holdings are Atlas Energy common units. Executives have five years from the date of the commencement of the guidelines or the date the executive is designated a covered executive by the Atlas Energy Compensation Committee, whichever is later, to attain these ownership levels. If an executive officer does not meet the applicable guideline by the end of the five-year period, the executive officer is required to hold any net shares resulting from any future vesting of restricted or phantom units or exercise of stock options until the guideline is met. These guidelines reinforce the importance of aligning the interests of Atlas Energy’s executive officers with the interests of its unitholders and encourage its executive officers to consider the long-term perspective when managing Atlas Energy.

Additionally, Atlas Energy has instituted stock ownership guidelines for its non-employee directors. For information regarding these guidelines, see the section entitled “Director Compensation.”

No Hedging of Company Stock

All of Atlas Energy’s employees are prohibited from hedging their company stock.

No Tax Gross-Ups

Atlas Energy does not provide tax reimbursements to its NEOs.

 

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Perquisites

At the discretion of the Atlas Energy Compensation Committee, Atlas Energy provides perquisites to its NEOs. In 2014, these benefits provided to the NEOs were limited to providing automobile allowances or automobile-related expenses to Messrs. E. Cohen, Jones and Herz.

Consulting Agreement with Mr. J. Cohen

In connection with the formation of the Lightfoot entities in 2007, Atlas Energy, Inc. entered into an agreement with Mr. J. Cohen to provide compensation to him in recognition of his role in negotiating and structuring its investment and his continued service as chairman of Lightfoot GP. Atlas Energy acquired Atlas Energy, Inc.’s direct and indirect ownership interests in the Lightfoot entities as part of the assets and liabilities it acquired from Atlas Energy, Inc. in February 2011. Under the agreement, Mr. J. Cohen receives an amount equal to 10% of the distributions that Atlas Energy receives from the Lightfoot entities, excluding amounts that constitute a return of capital.

Going Forward

After the separation, the New Atlas Compensation Committee will adopt and develop practices and procedures with respect to compensation decisions relating to deferred compensation, post-termination compensation, clawbacks, stock ownership guidelines, hedging, tax gross-ups and perquisites within the framework of the compensation plans adopted by us, which initially will be substantially similar to Atlas Energy’s compensation plans.

Determination of 2014 Compensation Amounts

Historically

Following its review of Mercer’s analyses, in the fall of 2014, the Atlas Energy Compensation Committee began to prepare for the executive compensation process by discussing the schedule for upcoming meetings and reviewing a proposed calendar. The Atlas Energy Compensation Committee held meetings in October to review and discuss the compensation philosophy. In January 2015, the Atlas Energy Compensation Committee consulted with Mercer, with Atlas Energy’s Chief Executive Officer participating, to evaluate Atlas Energy’s performance and to approve annual payouts to NEOs, as well as long-term incentive grants to senior employees.

Say on Pay

At Atlas Energy’s 2014 annual meeting, unitholders were asked to vote on a non-binding resolution approving the compensation of Atlas Energy’s NEOs as disclosed in the proxy statement. Atlas Energy’s unitholders approved compensation of the NEOs with approximately 97% of the votes cast in favor of the “Say on Pay” proposal. Additionally, consistent with the vote of the unitholders at the 2012 annual meeting, the Board decided to conduct an advisory vote on the compensation of the NEOs every year until the next required vote on the frequency of the unitholder vote on executive compensation. While these unitholder votes are advisory and non-binding, the Atlas Energy Compensation Committee has interpreted the results as strongly supportive of the compensation paid to the NEOs and therefore decided to maintain similar compensation practices for 2014. In addition, the annual review by the unitholders provides the Atlas Energy Compensation Committee with a current perspective on the compensation awarded to the NEOs.

Base Salary

As described above, Mercer’s market competitive assessment found that the base salaries of the NEOs were competitive with the 90th percentile of the peer group and the median of the survey, except for Mr. Jones’, which was competitive with the median of both groups, Mr. Herz’s, which was competitive with the 75th percentile of

 

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the survey, and Mr. McGrath’s, which was competitive with the median and 75th percentile of the peer group and below the competitive range of the 25th percentile of the survey. Taking that analysis into consideration, the Atlas Energy Compensation Committee determined that the current base salaries for Messrs. E. Cohen, J. Cohen, McGrath, Herz and Jones were appropriate for 2015.

Annual and Transaction Incentives

After the end of the 2014 fiscal year, the Atlas Energy Compensation Committee considered incentive awards pursuant to the Senior Executive Plan based on the year’s performance. In determining the actual amounts to be paid to the NEOs (other than Mr. Herz), the Atlas Energy Compensation Committee considered both individual and company performance. The Atlas Energy Chief Executive Officer made recommendations of incentive award amounts based upon Atlas Energy’s performance as well as the performance of its subsidiaries; however, the Atlas Energy Compensation Committee had the discretion to approve, reject or modify the recommendations. The Atlas Energy Compensation Committee noted that the total unitholder return, including cash distributions, was –29% during 2014, which was consistent with the peer group median. The Atlas Energy Compensation Committee also took into consideration that the 2014 return followed positive returns of 61% and 39% for 2012 and 2013, respectively, which were substantially higher than the peer companies’ average, and that the peer group’s average return had been far inferior to Atlas Energy’s return over that two year period. Atlas Energy’s return during the three year period spanning 2012 through 2014 was approximately 55%, compared to the median peer return of approximately 8% for the same period. The distributable cash flow was approximately double the performance goal set by the Atlas Energy Senior Executive Plan. Atlas Energy’s E&P operations achieved a record high average production rate of approximately 285 million cubic feet equivalents of natural gas and oil in late 2014, approximately 10% higher than peak average daily production in 2013. Atlas Energy also increased its net production margin per million cubic feet equivalents by over 40% as a result of organic development and acquisitions, namely from the Rangely field (Colorado) and Eagle Ford (Texas) oil producing properties acquired during 2014. Net proved reserves increased by over 40% to almost 1.7 Tcfe.

The Atlas Energy Compensation Committee confirmed that Atlas Energy had achieved not one, but both, of the threshold performance standards permitting bonus payments under the Atlas Energy Senior Executive Plan. The committee determined that the three-year average of distributable cash flow allocable to Atlas Energy was $124.7 million, which was one and a half times the pre-determined minimum threshold of 80% of three-year average distributable cash flow of $82.6 million. The committee also determined that the production volume for 2014 was 1,893 MMcfed, which was two times 80% of the average production volume for the past three years of 908 MMcfed. The Atlas Energy Compensation Committee reviewed the calculations of the maximum 2014 bonus pool, which was 10% of the adjusted distributable cash flow of $458 million. Although the Atlas Energy Compensation Committee recognized the NEOs continued strong performance, it took into account the current challenging state of the industry and the year’s negative return to Atlas Energy unitholders and decided to sharply reduce bonus payments from those paid in the prior year and make awards that were, on average, 68% less than the total amount of the 2013 awards, far below the maximum level for any of the NEOs.

 

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At this time, in view of evolving corporate governance standards, the Atlas Energy Compensation Committee decided to continue to implement a compensation strategy that is weighted toward providing variable compensation (bonus and equity awards) versus fixed salaries. This was consistent with the approach the Atlas Energy Compensation Committee took in 2013, a year in which, according to Mercer’s analysis, salary accounted for approximately 8% of the compensation of Atlas Energy’s Chief Executive Officer, as compared to 12% for the peer group median, and approximately 10% of the compensation of the other NEOs, as compared to 17% for the peer group median. The following table shows the maximum amounts that could have been awarded under the Atlas Energy Senior Executive Plan and the breakdown of the cash awards actually granted:

 

Named Executive Officer		Maximum percentage of bonus pool (10%)				Maximum potential awards				Actual awards
Edward E. Cohen			3.40	%		$	15,600,000			$	2,000,000
Jonathan Z. Cohen			3.00	%		$	13,700,000			$	2,000,000
Matthew A. Jones			1.60	%		$	7,300,000			$	750,000
Sean P. McGrath			0.80	%		$	3,700,000			$	600,000

As noted above, Mr. Herz did not participate in the Atlas Energy Senior Executive Plan during 2014. Based on a holistic evaluation of Atlas Energy’s and his individual performance, the Atlas Energy Compensation Committee determined that Mr. Herz should be awarded a cash bonus of $750,000 for 2014. The Atlas Energy Compensation Committee did not award any other discretionary bonuses for 2014 (although the company did pay substantial bonuses independently of the committee process to other, non-NEO, employees).

APL also awarded Messrs. Cohen each a cash bonus of $1 million and awarded Mr. Herz a cash bonus of $400,000 in recognition of the strategic direction and insight they have provided with respect to APL’s executive management, financing activities and growth opportunities.

Long-Term Incentives

In June 2014, the APL compensation committee provided retention bonuses for a number of executives, including several of the NEOs as follows: Mr. E. Cohen—20,000 phantom units; Mr. J. Cohen—20,000 phantom units; and Mr. Herz—15,000 phantom units. The awards were to vest 25% on each anniversary of the grant but, as described under “—Elements of Atlas Energy’s Compensation Program—Going Forward,” will as a result of the separation be cancelled and converted into a right to receive the APL merger consideration. The APL compensation committee determined that competition for experienced personnel, particularly from private equity firms, had substantially increased and that the awards were necessary to assure the continued services of APL personnel.

To address the significant competition for capable energy executives, in June 2014, the ATLS compensation committee made continuity awards of ATLS phantom units (with DERs) to a number of executives, including to the NEOs as follows: 240,000 phantom units to each of Messrs. E. Cohen and J. Cohen; 47,000 phantom units to Mr. McGrath; 60,000 phantom units to Mr. Jones and 75,000 phantom units to Mr. Herz. The awards were to vest 25% on each anniversary of the grant but, as described under “—Elements of Atlas Energy’s Compensation Program—Going Forward,” will as a result of the separation be cancelled and converted into a right to receive the merger consideration and New Atlas phantom units.

Going Forward

After the separation, the New Atlas Compensation Committee will adopt and develop practices and procedures with respect to compensation decisions relating to base salary, annual incentives, and long-term incentives within the framework of the compensation plans adopted by us, which at least initially will be substantially similar to Atlas Energy’s compensation plans. In addition, the New Atlas Compensation Committee will need to evaluate the relevance of peer data and determine the appropriate peer group, if any, for us following the separation.

 

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EXECUTIVE COMPENSATION

Historical Compensation of Named Executive Officers

The Named Executive Officers listed above were employed by Atlas Energy prior to the separation; therefore, the information provided for the fiscal years 2014, 2013 and 2012 below reflects compensation earned at Atlas Energy and the design and objectives of the Atlas Energy executive compensation programs in place prior to the separation. Each of these Named Executive Officers is currently, and was as of December 31, 2014, an executive officer of Atlas Energy. Accordingly, the compensation decisions regarding the Named Executive Officers were made by the Atlas Energy Compensation Committee or by the Atlas Energy Chief Executive Officer. Executive compensation decisions following the separation will be made by the New Atlas Compensation Committee. All references in the following tables to options or phantom units relate to awards granted by Atlas Energy, APL or ARP.

The amounts and forms of compensation reported below are not necessarily indicative of the compensation that our executive officers will receive following the separation, which could be higher or lower, because historical compensation was determined by Atlas Energy’s Compensation Committee based in part on Atlas Energy’s performance and because future compensation levels at our company will be determined based on the compensation policies, programs and procedures to be established by the New Atlas Compensation Committee for those individuals who will be employed by us following the separation.

SUMMARY COMPENSATION TABLE

 

Name and principal position		Year				Salary ($)				Bonus ($)				Unit awards ($)(1)				Option awards ($)(2)				Non-equity incentive plan compensation ($)				All other compensation ($)				Total ($)
Edward E. Cohen			2014				1,000,000				—				17,812,798				—				2,000,000				4,178,447	(3)			24,991,245
Chief Executive Officer and President			2013				1,000,000				—				3,775,488				—				1,200,000				1,611,182				7,586,670
			2012				896,154				—				7,198,500				2,135,000				2,750,000				2,066,013				15,045,667
Sean P. McGrath			2014				400,000				—				3,411,694				—				600,000				236,718	(4)			4,648,412
Chief Financial Officer			2013				350,000				—				499,973				—				600,000				159,851				1,609,824
			2012				250,000				—				1,233,500				305,000				550,000				173,962				2,512,462
Jonathan Z. Cohen			2014				700,000				—				17,312,821				—				2,000,000				3,766,497	(5)			23,779,318
Executive Chairman of the Board			2013				700,000				—				3,575,468				—				1,200,000				1,481,840				6,957,308
			2012				630,769				—				7,198,500				2,135,000				2,700,000				1,981,760				14,646,029
Daniel C. Herz			2014				392,308				750,000				5,844,469				—				—				1,042,524	(6)			8,029,301
Senior Vice President, Corporate Development and Strategy			2013				341,923				750,000				1,487,723				—				—				469,533				3,049,179
			2012				280,000				280,000				2,321,560				610,000				—				658,053				4,669,613
Matthew A. Jones			2014				400,000				—				4,945,806				—				750,000				593,093	(7)			6,688,899
Senior Vice President and President of E&P Division			2013				400,000				—				1,099,995				—				750,000				480,892				2,730,887
			2012				358,462				—				2,467,000				1,372,500				1,650,000				254,033				6,101,995

 

(1)

Unit awards include bonus payments attributable to 2013 performance and continuity grants as discussed in “Compensation Discussion and Analysis—Determination of 2014 Compensation Amounts—Historically—Long-Term Incentives.” For fiscal year 2014, the amounts reflect the grant date fair value of the phantom units under the Atlas Energy Plans and the APL Plans. The grant date fair value was determined in accordance with FASB ASC Topic 718 and is based on the market value on the grant date of Atlas Energy units (February 2014 and June 2014) and APL units (February 2014 and June 2014 for Messrs. E. Cohen, J. Cohen, and Herz). ATLS awards granted in 2014 were largely continuity grants. See “Compensation Discussion & Analysis—Determination of 2014 Compensation Amounts—Historically—Long-Term Incentives.” Such continuity grants are not awarded annually (the last such grants had been made in fiscal year 2011). ATLS and APL grants in fiscal year 2013 were awarded as part of the bonus process. For fiscal year 2013, the amounts reflect the grant date fair value of the phantom units under the Atlas Energy Plans and the APL Plans. For fiscal year 2012, the amounts reflect the grant date fair value of the phantom units under the APL Plans and the ARP Plan.

 

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(2)

The amounts in this column reflect the grant date fair value of options awarded under the ARP Plan calculated in accordance with FASB ASC Topic 718. See Note 15 of New Atlas Operations and Subsidiaries Unaudited Pro Forma Condensed Combined Financial Statements section of this information statement beginning on F-56 for further discussion regarding assumptions made in fair value valuation.

(3)

Comprised of (i) payments on DERs of $974,168 with respect to the phantom units awarded under the Atlas Energy Plans, (ii) payments on DERs of $233,209 with respect to the phantom units awarded under the ARP Plan, (iii) payments on DERs of $370,525 with respect to the phantom units awarded under the APL Plans, (iv) a cash bonus of $1,000,000 from APL, (v) a matching contribution of $500,000 under the Atlas Energy Deferred Compensation Plan, (vi) distribution of $1,097,721 under the Atlas Energy Deferred Compensation Plan and (vii) tax, title and insurance premiums for Mr. E. Cohen’s automobile.

(4)	Comprised of (i) payments on DERs of $158,982 with respect to the phantom units awarded under the Atlas Energy Plans and (ii) payments on DERs of $77,736 with respect to the phantom units awarded under the ARP Plan.

(5)

Comprised of (i) payments on DERs of $865,653 with respect to the phantom units awarded under the Atlas Energy Plans, (ii) payments on DERs of $233,209 with respect to the phantom units awarded under the ARP Plan, (iii) payments on DERs of $370,525 with respect to the phantom units awarded under the APL Plans, (iv) a cash bonus of $1,000,000 from APL, (v) a matching contribution of $350,000 under the Atlas Energy Deferred Compensation Plan, (vi) distribution of $784,086 under the Atlas Energy Deferred Compensation Plan and (vii) $163,024 paid under the agreement relating to Lightfoot.

(6)

Comprised of (i) payments on DERs of $397,910 with respect to the phantom units awarded under the Atlas Energy Plans, (ii) payments on DERs of $108,831 with respect to the phantom units awarded under the ARP Plan, (iii) payments on DERs of $126,183 with respect to the phantom units awarded under the APL Plans, (iv) a cash bonus of $400,000 from APL and (v) an automobile allowance.

(7)	Comprised of (i) payments on DERs of $428,210 with respect to the phantom units awarded under the Atlas Energy Plans; (ii) payments on DERs of $155,473 with respect to the phantom units awarded under the ARP Plan; and (iii) an automobile allowance.

2014 GRANTS OF PLAN-BASED AWARDS

 

		Estimated possible payments under non-equity incentive plan awards(1)												Grant date				All other stock awards: Number of units				All other option awards: Number of securities underlying options				Exercise or base price of option awards ($/Unit)				Grant date fair value of unit and option awards ($)(5)
Name		Threshold ($)				Target ($)				Maximum ($)
Edward E. Cohen			N/A				N/A				15,600,000				2/18/14				109,589	(2)			—				—				4,799,998
															2/18/14				50,000	(3)							—				1,550,000
															6/26/14				240,000	(4)							—				10,783,200
															6/28/14				20,000	(3)							—				679,600
Sean P. McGrath			N/A				N/A				3,700,000				2/18/14				29,680	(2)			—				—				1,299,984
															6/26/14				47,000	(4)			—				—				2,111,710
Jonathan Z. Cohen			N/A				N/A				13,700,000				2/18/14				98,174	(2)			—				—				4,300,021
															2/18/14				50,000	(3)											1,550,000
															6/26/14				240,000	(4)							—				10,783,200
															6/28/14				20,000	(3)							—				679,600
Daniel C. Herz			N/A				N/A				N/A				2/18/14				34,247	(2)			—				—				1,500,019
															2/18/14				15,000	(3)											465,000
															6/26/14				75,000	(4)											3,369,750
															6/28/14				15,000	(3)											509,700
Matthew A. Jones			N/A				N/A				7,300,000				2/18/14				51,370	(2)			—				—				2,250,006
															6/26/14				60,000	(4)			—				—				2,695,800

 

(1)

Represents performance-based bonuses under the Atlas Energy Senior Executive Plan that may be paid in cash and/or equity. As discussed under “Compensation Discussion and Analysis—Elements of Atlas Energy’s Compensation Program—Annual Incentives” and “—Performance-Based Bonuses,” the Atlas Energy Compensation Committee set performance goals based on the distributable cash flow and average production volumes, and established maximum awards, but not minimum or target amounts, for each eligible NEO.

(2)	Represents phantom units granted under the Atlas Energy 2006 Plan.

(3)	Represents phantom units granted under the APL 2010 Plan.

 

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(4)	Represents phantom units granted under the Atlas Energy 2010 Plan.

(5)	The grant date fair value was calculated in accordance with FASB ASC Topic 718.

Employment Agreements and Potential Payments Upon Termination or Change of Control

Atlas Energy has employment agreements with its NEOs that provide for severance compensation to be paid if their employment is terminated under certain conditions.

Terms Used

“Good reason” is defined in the following employment agreements as:

 

•

a material reduction in base salary;

 

•

a demotion from his position;

 

•

a material reduction in duties, it being deemed such a material reduction if Atlas Energy ceases to be a public company unless it becomes a subsidiary of a public company, and

 

•

in the case of Mr. E. Cohen, becomes the chief executive officer of the public parent immediately following the applicable transaction;

 

•

in the case of Mr. J. Cohen, becomes an executive officer of the public parent with responsibilities substantially equivalent to his previous position immediately following the applicable transaction;

 

•

in the case of Messrs. Jones and Herz, the CEO or the Chairman of Atlas Energy’s general partner’s board is not its CEO or the CEO of the acquiring entity;

 

•

the executive is required to relocate to a location more than 35 miles from the executive’s previous location;

 

•

in the case of Mr. E. Cohen and Mr. J. Cohen, ceasing to be elected to the board; or

 

•

any material breach of the agreement.

“Cause” is defined in Mr. E. Cohen’s and Mr. J. Cohen’s employment agreements as:

 

•

the executive is convicted of a felony, or any crime involving fraud or embezzlement;

 

•

the executive intentionally and continually fails to perform his reasonably assigned duties (other than as a result of disability), which failure is materially and demonstrably detrimental to Atlas Energy and has continued for 30 days after written notice signed by a majority of the independent directors of the General Partner; or

 

•

the executive is determined, through arbitration, to have materially breached the restrictive covenants in the agreement.

“Cause” is defined in Messrs. Jones’s and Herz’s employment agreements as:

 

•

the executive has committed any demonstrable and material fraud;

 

•

illegal or gross misconduct that is willful and results in damage to Atlas Energy’s business or reputation;

 

•

the executive is convicted of a felony, or any crime involving fraud or embezzlement;

 

•

failure to substantially perform his duties (other than as a result of disability) after written demand and a reasonable opportunity to cure; or

 

•

failure to follow reasonable written instructions which are consistent with his duties.

 

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Edward E. Cohen

Effective May 16, 2011, Atlas Energy entered into an employment agreement with Mr. Cohen to secure his service as President and Chief Executive Officer of the Atlas Energy General Partner. The agreement has a term of three years, which automatically renews daily unless terminated before the expiration of the term pursuant to the termination provisions of the agreement.

The agreement provides for an initial annual base salary of $700,000, which may be increased at the discretion of the board of directors of Atlas Energy’s general partner. Mr. Cohen is entitled to participate in any short-term and long-term incentive programs and health and welfare plans and receive perquisites and reimbursement of business expenses, in each case as provided by Atlas Energy for its senior level executives generally. Mr. Cohen participates in the Atlas Energy Deferred Compensation Plan, under which he may elect to defer up to 10% of his total annual cash compensation, which Atlas Energy must match on a dollar-for-dollar basis up to 50% of his annual base salary. See the “2014 Nonqualified Deferred Compensation” table. During the term of the agreement, Atlas Energy must maintain a term life insurance policy on Mr. Cohen’s life that provides a death benefit of $3 million, which can be assumed by Mr. Cohen upon a termination of employment.

The agreement provides the following benefits in the event of a termination of employment:

 

•

Upon termination of employment due to death, all equity awards held by Mr. Cohen accelerate and vest in full upon the later of the termination of employment or six months after the date of grant of the awards (“Acceleration of Equity Vesting”), and Mr. Cohen’s estate is entitled to receive, in addition to payment of all accrued and unpaid amounts of base salary, vacation, business expenses and other benefits (“Accrued Obligations”), a pro rata bonus for the year of termination, based on the actual bonus that would have been earned had the termination of employment not occurred, determined and paid consistent with past practice (the “Pro Rata Bonus”).

 

•

Atlas Energy may terminate Mr. Cohen’s employment if he has been unable to perform the material duties of his employment for 180 days in any 12-month period because of physical or mental injury or illness, but it is required to pay his base salary until it acts to terminate his employment. Upon termination of employment due to disability, Mr. Cohen will receive the Accrued Obligations, all amounts payable under Atlas Energy’s long-term disability plans, three years’ continuation of group term life and health insurance benefits (or, alternatively, Atlas Energy may elect to pay executive cash in lieu of such coverage in an amount equal to three years’ healthcare coverage at COBRA rates and the premiums it would have paid during the three-year period for such life insurance) (such coverage, the “Continued Benefits”), Acceleration of Equity Vesting and the Pro Rata Bonus.

 

•

Upon termination of employment by Atlas Energy without cause or by Mr. Cohen for good reason, Mr. Cohen will be entitled to either (i) if he does not execute and not revoke a release of claims against us, payment of the Accrued Obligations, or (ii) in addition to payment of the Accrued Obligations, if he executes and does not revoke a release of claims against us, (A) a lump sum cash payment in an amount equal to three times his average compensation (which is defined as the sum of (1) his annualized base salary in effect immediately before the termination of employment plus (2) the average of the bonuses earned for the three years preceding the year in which the termination occurs), (B) Continued Benefits for three years, (C) the Pro Rata Bonus, and (D) Acceleration of Equity Vesting.

 

•

Upon a termination by Atlas Energy for cause or by Mr. Cohen without good reason, he is entitled to receive payment of the Accrued Obligations.

In connection with a change of control, any “excess parachute payments” (within the meaning of Section 280G of the Internal Revenue Code) otherwise payable to Mr. Cohen will be reduced such that the total payments to the executive which are subject to Internal Revenue Code Section 280G are no greater than the Section 280G “safe harbor amount” if he would be in a better after-tax position as a result of such reduction.

 

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The following table provides an estimate of the value of the benefits to Mr. Cohen if a termination event had occurred as of December 31, 2014.

 

Reason for termination		Lump sum severance payment				Benefits(1)				Accelerated vesting of unit awards and option awards(2)
Death		$	3,000,000	(3)		$	—			$	30,706,209
Disability			—				57,003				30,706,209
Termination by Atlas Energy without cause or by Mr. Cohen for good reason			25,073,486	(4)			57,003				30,706,209

 

(1)	Dental and medical benefits were calculated using 2014 COBRA rates.

(2)

Represents the value of unexercisable option and unvested unit awards disclosed in the “2014 Outstanding Equity Awards at Fiscal Year-End” table. The payments relating to option awards are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of the applicable units on December 31, 2014. The payments relating to unit awards are calculated by multiplying the number of accelerated units by the closing price of the applicable unit on December 31, 2014.

(3)	Represents life insurance policy proceeds.

(4)

Represents three times (a) Mr. Cohen’s base salary plus (b) the average of his bonuses for the three years preceding the year in which the termination occurs. The value of unit awards is based on the fair market value of the underlying stock at the grant date. The value of options is based on Black-Scholes option pricing at grant date.

Jonathan Z. Cohen

Effective May 16, 2011, Atlas Energy entered into an employment agreement with Mr. Cohen to secure his service as Chairman of the Board. The agreement has a term of three years, which automatically renews daily unless terminated before the expiration of the term pursuant to the termination provisions of the agreement.

The agreement provides for an initial annual base salary of $500,000, which may be increased at the discretion of the board of directors of Atlas Energy’s general partner. Mr. Cohen is entitled to participate in any short-term and long-term incentive programs and health and welfare plans of the company and receive perquisites and reimbursement of business expenses, in each case as provided by Atlas Energy for its senior level executives generally. Mr. Cohen participates in the Atlas Energy Deferred Compensation Plan, under which he may elect to defer up to 10% of his total annual cash compensation, which Atlas Energy must match on a dollar-for-dollar basis up to 50% of his annual base salary. See the “2014 Nonqualified Deferred Compensation” table. During the term of the agreement, Atlas Energy must maintain a term life insurance policy on Mr. Cohen’s life that provides a death benefit of $2 million, which can be assumed by Mr. Cohen upon a termination of employment.

The agreement provides the same benefits in the event of a termination of employment as described above in Mr. E. Cohen’s employment agreement summary.

In connection with a change of control, any “excess parachute payments” (within the meaning of Section 280G of the Internal Revenue Code) otherwise payable to Mr. Cohen will be reduced such that the total payments to the executive which are subject to Internal Revenue Code Section 280G are no greater than the Section 280G “safe harbor amount” if he would be in a better after-tax position as a result of such reduction.

 

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The following table provides an estimate of the value of the benefits to Mr. Cohen if a termination event had occurred as of December 31, 2014.

 

Reason for termination		Lump sum severance payment				Benefits(1)				Accelerated vesting of unit awards and option awards(2)
Death		$	2,000,000	(3)		$	—			$	27,223,652
Disability			—				83,526				27,223,652
Termination by Atlas Energy without cause or by Mr. Cohen for good reason			22,923,489	(4)			83,526				27,223,652

 

(1)	Dental and medical benefits were calculated using 2014 COBRA rates.

(2)

Represents the value of unexercisable option and unvested unit awards disclosed in the “2014 Outstanding Equity Awards at Fiscal Year-End” table. The payments relating to option awards are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of the applicable units on December 31, 2014. The payments relating to unit awards are calculated by multiplying the number of accelerated units by the closing price of the applicable unit on December 31, 2014.

(3)	Represents life insurance policy proceeds.

(4)

Represents three times (a) Mr. Cohen’s base salary plus (b) the average of his bonuses for the three years preceding the year in which the termination occurs. The value of unit awards is based on the fair market value of the underlying stock at the grant date. The value of options is based on Black-Scholes option pricing at grant date.

 

Daniel

C. Herz

In November 2011, Atlas Energy entered into an employment agreement with Daniel C. Herz. Under the agreement, Mr. Herz has the title of Senior Vice President—Corporate Development and Strategy. The agreement has an effective date of November 4, 2011 and has an initial term of two years, which automatically renews daily after the first anniversary of the agreement for one-year terms.

The agreement provides for an initial annual base salary of $280,000. Mr. Herz is entitled to participate in any of Atlas Energy’s short-term and long-term incentive programs and health and welfare plans and receive perquisites and reimbursement of business expenses, in each case as provided by Atlas Energy for senior executives generally.

The agreement provides the following benefits in the event of a termination of employment:

 

•

Upon a termination by Atlas Energy for cause or by Mr. Herz without good reason, he is entitled to receive payment of accrued but unpaid base salary and (to the extent required to be paid under company policy) amounts of accrued but unpaid vacation, in each case through the date of termination (together, the “Accrued Obligations”).

 

•

Upon a termination of employment due to death or disability (defined as Mr. Herz being physically or mentally disabled for 180 days in the aggregate or 90 consecutive days during any 365-day period and the determination by Atlas Energy’s general partner’s board of directors, in good faith based upon medical evidence, that he is unable to perform his duties), all equity awards held by Mr. Herz accelerate and vest in full upon such termination (“Acceleration of Equity Vesting”), and Mr. Herz or his estate is entitled to receive in one cash payment, in addition to payment of all Accrued Obligations and any accrued but unpaid bonus earned for any year before the date of termination, a pro-rata amount in respect of the bonus granted to the executive for the fiscal year in which the termination occurs in an amount equal to the bonus earned by Mr. Herz for the prior fiscal year multiplied by a fraction, the numerator of which is the number of days in the fiscal year in which the termination occurs through the

 

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date of termination, and the denominator of which is the total number of days in such fiscal year (the “Pro-Rata Bonus”). In addition, his family is entitled to company-paid health insurance for the one-year period after his death.

 

•

Upon a termination of employment by Atlas Energy without cause (which, for purposes of the “Acceleration of Equity Vesting” includes a non-renewal of the agreement) or by the executive for good reason, Mr. Herz will be entitled to either: if Mr. Herz does not timely execute (or revokes) a release of claims against Atlas Energy, payment in one cash payment of the Accrued Obligations, any accrued but unpaid bonus and the Pro-Rata Bonus; or in addition to payment in one cash payment of the Accrued Obligations, any accrued but unpaid bonus and the Pro-Rata Bonus, if Mr. Herz timely executes and does not revoke a release of claims against Atlas Energy: a lump-sum cash severance payment in an amount equal to two years of his average compensation (which is the sum of his then-current base salary and the average of the cash bonuses earned for the three calendar years preceding the year in which the termination occurs); healthcare continuation at active employee rates for two years (or, where such coverage would have a negative tax effect to Atlas Energy’s healthcare plan or Mr. Herz, Atlas Energy may elect to pay Mr. Herz cash in lieu of such coverage at COBRA rates); and Acceleration of Equity Vesting.

In connection with a change of control, any “excess parachute payments” (within the meaning of Section 280G of the Internal Revenue Code) otherwise payable to Mr. Herz will be reduced such that the total payments to the executive which are subject to Section 280G of the Internal Revenue Code are no greater than the Section 280G “safe harbor amount” if Mr. Herz would be in a better after-tax position as a result of such reduction.

The following table provides an estimate of the value of the benefits to Mr. Herz if a termination event had occurred as of December 31, 2014.

 

Reason for termination		Lump sum severance payment				Benefits(1)				Accelerated vesting of unit awards and option awards(2)
Death		$	—			$	19,829			$	11,169,789
Disability			—				19,829				11,169,789
Termination by Atlas Energy without cause or by Mr. Herz for good reason			2,766,667	(3)			39,657				11,169,789

 

(1)	Dental and medical benefits were calculated using 2014 active employee rates.

(2)

Represents the value of unexercisable option and unvested unit awards disclosed in the “2014 Outstanding Equity Awards at Fiscal Year-End Table.” The payments relating to option awards are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of the applicable units on December 31, 2014. The payments relating to awards are calculated by multiplying the number of accelerated units by the closing price of the applicable unit on December 31, 2014.

(3)	Represents two times (a) Mr. Herz’s base salary plus (b) the average of his cash bonuses for the three years preceding the year of termination.

Matthew A. Jones

In November 2011, Atlas Energy entered into an employment agreement with Matthew A. Jones. Mr. Jones has the title of Senior Vice President and President of the Exploration and Production Division. The agreement has an effective date of November 4, 2011 and has an initial term of two years, which automatically renews daily after the first anniversary of the agreement for one year terms.

The agreement provides for an initial annual base salary of $280,000. Mr. Jones is entitled to participate in any of Atlas Energy’s short-term and long-term incentive programs and health and welfare plans and receive perquisites and reimbursement of business expenses, in each case as provided by Atlas Energy for its senior executives generally.

 

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The agreement provides the following benefits in the event of a termination of employment:

 

•

Upon a termination by Atlas Energy for cause or by Mr. Jones without good reason, he is entitled to receive payment of accrued but unpaid base salary and (to the extent required to be paid under company policy) amounts of accrued but unpaid vacation, in each case through the date of termination (together, the “Accrued Obligations”).

 

•

Upon a termination of employment due to death or disability (defined as Mr. Jones being physically or mentally disabled for 180 days in the aggregate or 90 consecutive days during any 365-day period and the determination by Atlas Energy’s general partner’s board of directors, in good faith based upon medical evidence, that he is unable to perform his duties), all equity awards held by Mr. Jones accelerate and vest in full upon such termination (“Acceleration of Equity Vesting”), and Mr. Jones or his estate is entitled to receive in one cash payment, in addition to payment of all Accrued Obligations and any accrued but unpaid bonus earned for any year before the date of termination, a pro rata amount in respect of the bonus granted to the executive for the fiscal year in which the termination occurs in an amount equal to the bonus earned by Mr. Jones for the prior fiscal year multiplied by a fraction, the numerator of which is the number of days in the fiscal year in which the termination occurs through the date of termination, and the denominator of which is the total number of days in such fiscal year (the “Pro Rata Bonus”). In addition, his family is entitled to company-paid health insurance for the one-year period after his death.

 

•

Upon a termination of employment by Atlas Energy without cause (which, for purposes of the “Acceleration of Equity Vesting” includes a non-renewal of the agreement) or by the executive for good reason, Mr. Jones will be entitled to either:

 

•

if Mr. Jones does not timely execute (or revokes) a release of claims against us, payment in one cash payment of the Accrued Obligations, any accrued but unpaid bonus and the Pro Rata Bonus; or

 

•

in addition to payment in one cash payment of the Accrued Obligations, any accrued but unpaid bonus and the Pro Rata Bonus, if Mr. Jones timely executes and does not revoke a release of claims against us:

 

•

a lump sum cash severance payment in an amount equal to two times his average compensation (which is the sum of his then-current base salary and the average of the cash bonuses earned for the three calendar years preceding the year in which the termination occurs);

 

•

healthcare continuation at active employee rates for two years (or, where such coverage would have a negative tax effect to Atlas Energy’s healthcare plan or Mr. Jones, Atlas Energy may elect to pay Mr. Jones cash in lieu of such coverage at COBRA rates); and

 

•

Acceleration of Equity Vesting.

In connection with a change of control, any “excess parachute payments” (within the meaning of Section 280G of the Internal Revenue Code) otherwise payable to Mr. Jones will be reduced such that the total payments to the executive which are subject to Section 280G are no greater than the Section 280G “safe harbor amount” if Mr. Jones would be in a better after-tax position as a result of such reduction.

 

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The following table provides an estimate of the value of the benefits to Mr. Jones if a termination event had occurred as of December 31, 2014:

 

Reason for termination		Lump sum severance payment				Benefits(1)				Accelerated vesting of unit awards and option awards(2)
Death		$	—			$	17,783			$	10,163,078
Disability			—				17,783				10,163,078
Termination by Atlas Energy without cause or by Mr. Jones for good reason			3,233,333	(3)		$	35,565				10,163,078

 

(1)	Dental and medical benefits were calculated using 2014 active employee rates.

(2)

Represents the value of unexercisable option and unvested unit awards disclosed in the “2014 Outstanding Equity Awards at Fiscal Year-End” table. The payments relating to option awards are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of the applicable units on December 31, 2014. The payments relating to unit awards are calculated by multiplying the number of accelerated units by the closing price of the applicable unit on December 31, 2014.

(3)	Represents two times (a) Mr. Jones’s base salary plus (b) the average of his cash bonuses for the

three years preceding the year of termination.

Long-Term Incentive Plans

Atlas Energy 2006 Plan

The Atlas Energy 2006 Plan provides equity incentive awards to officers, employees and board members of the General Partner and its affiliates, consultants and joint-venture partners who perform services for Atlas Energy. The Atlas Energy 2006 Plan is administered by the Atlas Energy Compensation Committee. The committee may grant awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units, which was adjusted to an aggregate of 2,261,516 common limited partner units in connection with the ARP Distribution described below.

Partnership Phantom Units. A phantom unit entitles a participant to receive a common unit upon vesting of the phantom unit. Non-employee directors may receive an annual grant of phantom units having a fair market value of $125,000, which upon vesting entitles the grantee to receive the equivalent number of common units or the cash equivalent to the fair market value of the units. The phantom units granted to employees under the Atlas Energy 2006 Plan generally vest over a three- or four-year period and phantom grants to non-employee directors generally vest over a four-year period, 25% per year. In tandem with phantom unit grants, the committee may grant a DER. The committee determines the vesting period for phantom units.

Partnership Unit Options. A unit option entitles a participant to receive a common unit upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of a common unit as determined by the committee on the date of grant of the option. The committee determines the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Generally, unit options granted under the Atlas Energy 2006 Plan will vest over a three- or four-year period from the date of grant.

 

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Change of Control

 

Individual		Triggering event		Acceleration
Eligible employees		Change of Control (as defined in the Atlas Energy 2006 Plan), and   Termination of employment without “cause” as defined in grant agreement or upon any other type of termination specified in the applicable award agreement(s), following a change of control		Unvested awards immediately vest in full and in the case of options, become exercisable for the one-year period following the date of termination (but not later than the end of the original term of the option)
Independent directors		Change of Control (as defined in the Atlas Energy 2006 Plan)		Unvested awards immediately vest in full

Atlas Energy 2010 Plan

The Atlas Energy 2010 Plan provides equity incentive awards to officers, employees and board members of the General Partner and its affiliates, consultants and joint-venture partners who perform services for Atlas Energy. The Atlas Energy 2010 Plan is administered by the Atlas Energy Compensation Committee, which may grant awards of either phantom units, unit options or restricted units for an aggregate of 5,300,000 common limited partner units, which was adjusted to an aggregate of 5,763,781 common limited partner units in connection with the ARP Distribution described below.

Partnership Phantom Units. A phantom unit entitles a participant to receive a common unit upon vesting of the phantom unit. Non-employee directors may receive an annual grant of phantom units having a market value of $125,000, which, upon vesting, entitle the grantee to receive the equivalent number of common units or the cash equivalent to the fair market value of the units. The phantom units granted to employees under the Atlas Energy 2010 Plan generally vest over a three- or four-year period and phantom grants to non-employee directors generally vest over a four-year period, 25% per year. In tandem with phantom unit grants, the committee may grant a participant the right, which is referred to as a DER, to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions made on an Atlas Energy common unit during the period the phantom unit is outstanding. The committee determines the vesting period for phantom units.

Partnership Unit Options. A unit option entitles a participant to receive a common unit upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of a common unit as determined by the committee on the date of grant of the option. The committee determines the vesting and exercise period for unit options and generally, the unit options granted under the Atlas Energy 2010 Plan will vest over a three- or four-year period from the date of grant.

Partnership Restricted Units. A restricted unit is a common unit issued that entitles a participant to receive it upon vesting of the restricted unit. Prior to or upon grant of an award of restricted units, the committee will condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals or both.

 

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Change of Control

 

Individual		Triggering event		Acceleration
Eligible employees		Change of Control (as defined in the Atlas Energy 2010 Plan), and   Termination of employment without “cause” as defined in grant agreement or upon any other type of termination specified in the applicable award agreement(s), following a change of control		Unvested awards immediately vest in full and in the case of options, become exercisable for the one-year period following the date of termination (but not later than the end of the original term of the option)
Independent directors		Change of Control (as defined in the Atlas Energy 2010 Plan)		Unvested awards immediately vest in full

Adjustments to Awards under the Atlas Energy Plans

On March 13, 2012, Atlas Energy distributed approximately 5.24 million ARP common units to Atlas Energy unitholders, which common units represented an approximately 19.6% limited partner interest in ARP (the “ARP Distribution”). The Atlas Energy Compensation Committee determined that the ARP Distribution qualified as the type of event necessitating an adjustment to the outstanding options and phantom units issued pursuant to the Atlas Energy Plans. Accordingly, on March 13, 2012, the exercise price and the number of options outstanding were adjusted in order to maintain the aggregate pre-adjustment difference between the market value of the units subject to the option and the option exercise price. The number of phantom units outstanding was also adjusted to maintain the awards’ pre-adjustment values. All other terms of the awards remained unchanged.

APL Plans

The APL 2004 Long-Term Incentive Plan (the “2004 APL Plan”) and the 2010 Long-Term Incentive Plan, which was modified in April 2011 (the “2010 APL Plan” and, collectively with the 2004 APL Plan, the “APL Plans”), provide incentive awards to officers, employees and non-employee managers of Atlas Pipeline GP and officers and employees of its affiliates, consultants and joint venture partners who perform services for APL or in furtherance of its business. The APL Plans are administered by APL’s compensation committee (the “APL Committee”). Under the APL Plans, the APL Committee may make awards of either phantom units or options covering an aggregate of 435,000 common units under the 2004 APL Plan and 3,000,000 common units under the 2010 APL Plan.

APL Phantom Units. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit. In addition, the APL Committee may grant a participant the right, which is referred to as a DER, to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions made on an APL common unit during the period the phantom unit is outstanding.

APL Unit Options. An option entitles the grantee to purchase APL common units at an exercise price determined by the APL Committee, which may be less than, equal to or more than the fair market value of APL common units on the date of grant. The compensation committee will also have discretion to determine how the exercise price may be paid.

Except for phantom units awarded to non-employee managers of Atlas Pipeline GP, the APL Committee will determine the vesting period for phantom units and the exercise period for options. Phantom units awarded to non-employee managers will generally vest over a 4-year period at the rate of 25% per year. Both types of awards will automatically vest upon a change of control, as defined in the APL Plans.

 

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ARP Plan

The ARP 2012 Long-Term Incentive Plan (the “ARP Plan”) provides equity incentive awards to officers, employees and managing board members of Atlas Energy Group and employees of its affiliates, consultants and joint venture partners who perform services for ARP. The ARP Plan is administered by the Atlas Energy Compensation Committee, which may grant awards of either phantom units, unit options or restricted units for an aggregate of 2,900,000 common limited partner units.

ARP Phantom Units. A phantom unit entitles a participant to receive a common unit upon vesting of the phantom unit. The phantom units vest over four years. In tandem with phantom unit grants, the committee may grant a DER. The committee determines the vesting period for phantom units.

ARP Unit Options. A unit option entitles a participant to receive a common unit upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of a common unit as determined by the committee on the date of grant of the option. The committee determines the vesting and exercise period for unit options.

ARP Restricted Units. A restricted unit is a common unit issued that entitles a participant to receive it upon vesting of the restricted unit. Prior to or upon grant of an award of restricted units, the committee can condition the vesting or transferability of the restricted units upon conditions that it may determine such as the attainment of performance goals.

Change of Control

 

Individual		Triggering event		Acceleration
Eligible employees		Change of Control (as defined in the ARP Plan), and   Termination of employment without “cause” as defined in grant agreement or upon any other type of termination specified in the applicable award agreement(s), following a change of control		Unvested awards immediately vest in full and in the case of options, become exercisable for the one-year period following the date of termination (but not later than the end of the original term of the option)
Independent directors		Change of Control (as defined in the ARP Plan)		Unvested awards immediately vest in full

 

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2014 OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END

In accordance with SEC rules, the table below discloses vesting dates for the outstanding equity awards. However, these awards will as a result of the separation be cancelled and converted or settled as provided in the merger agreements as described under “Compensation Discussion and Analysis—Elements of Atlas Energy’s Compensation Program—Going Forward.”

 

		Option awards																Unit awards
Name		Exercisable				Unexercisable				Option exercise price ($)				Option expiration date				Number of units that have not vested(#)				Market value of units that have not vested($)
Edward E. Cohen			543,825	(1)			—				20.75				11/10/2016				—				—
			190,338	(1)			571,017	(2)			20.44				3/25/2021				244,722	(3)			7,623,090
			—				—				N/A				N/A				50,000	(4)			1,363,000
			175,000	(5)			175,000	(6)			24.67				5/15/2022				75,000	(7)			802,500
			—				—				N/A				N/A				31,521	(8)			981,879
			—				—				N/A				N/A				37,500	(9)			1,022,250
			—				—				N/A				N/A				109,589	(10)			3,413,697
			—				—				N/A				N/A				50,000	(11)			1,363,000
			—				—				N/A				N/A				240,000	(12)			7,476,000
			—				—				N/A				N/A				20,000	(13)			545,200
Sean P. McGrath			16,314	(1)			—				20.75				11/10/2016				—				—
			9,516	(1)			28,551	(2)			20.44				3/25/2021				24,472	(3)			762,303
			25,000	(5)			25,000	(14)			24.67				5/15/2022				25,000	(15)			267,500
			—				—				N/A				N/A				8,756	(16)			272,749
			—				—				N/A				N/A				29,680	(17)			924,532
			—				—				N/A				N/A				47,000	(18)			1,464,050
Jonathan Z. Cohen			217,530	(1)			—				20.75				11/10/2016				—				—
			135,956	(1)			407,869	(2)			20.44				3/25/2021				203,934	(3)			6,352,544
			—				—				N/A				N/A				50,000	(4)			1,363,000
			175,000	(5)			175,000	(6)			24.67				5/15/2022				75,000	(7)			802,500
			—				—				N/A				N/A				28,018	(19)			872,761
			—				—				N/A				N/A				37,500	(9)			1,022,250
			—				—				N/A				N/A				98,174	(20)			3,058,120
			—				—				N/A				N/A				50,000	(11)			1,363,000
			—				—				N/A				N/A				240,000	(12)			7,476,000
			—				—				N/A				N/A				20,000	(13)			545,200
Daniel C. Herz			32,629	(1)			—				20.75				11/10/2016				—				—
			54,382	(1)			163,148	(2)			20.44				3/25/2021				122,361	(3)			3,811,545
			—				—				N/A				N/A				8,500	(26)			231,710
			50,000	(5)			50,000	(27)			24.67				5/15/2022				35,000	(28)			374,500
			—				—				N/A				N/A				8,756	(16)			272,749
			—				—				N/A				N/A				18,750	(29)			511,125
			—				—				N/A				N/A				34,247	(30)			1,066,794
			—				—				N/A				N/A				15,000	(31)			408,900
			—				—				N/A				N/A				75,000	(32)			2,336,250
			—				—				N/A				N/A				15,000	(33)			408,900
Matthew A. Jones			108,765	(1)			—				20.75				11/10/2016				—				—
			54,382	(1)			163,148	(2)			20.44				3/25/2021				122,261	(3)			3,811,545
			112,500	(5)			112,500	(21)			24.67				5/15/2022				50,000	(22)			535,000
			—				—				N/A				N/A				19,263	(23)			600,042
			—				—				N/A				N/A				51,370	(24)			1,600,176
			—				—				N/A				N/A				60,000	(25)			1,869,000

 

(1)	Represents options to purchase Atlas Energy units.

(2)	Represents options to purchase Atlas Energy units, which vest on 3/25/2015.

(3)	Represents Atlas Energy phantom units, which vest on 3/25/2015.

(4)	Represents APL phantom units, which vest as follows: 4/26/2015—25,000 and 4/26/2016—25,000.

 

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(5)	Represents options to purchase Atlas Energy units.

(6)	Represents options to purchase ARP units, which vest as follows: 5/15/2015—87,500 and 5/15/2016—87,500.

(7)	Represents ARP phantom units, which vest as follows: 5/15/2015—37,500 and 5/15/2016—37,500.

(8)	Represents Atlas Energy phantom units, which vest as follows: 2/4/2015—15,760 and 2/4/2016—15,761.

(9)	Represents APL phantom units, which vest as follows: 7/10/2015—12,500, 7/10/2016—12,500 and 7/10/2017—12,500.

(10)	Represents Atlas Energy phantom units, which vest as follows: 2/18/2015—54,794 and 2/18/2016—54,795.

(11)	Represents APL phantom units, which vest as follows: 2/18/2015—16,500, 2/18/2016—16,500, and 2/18/2017—17,000.

(12)	Represents Atlas Energy phantom units, which vest as follows: 6/26/2015—60,000, 6/26/2016—60,000, 6/26/2017—60,000, and 6/26/2018—60,000.

(13)	Represents APL phantom units, which vest as follows: 6/28/2015—5,000, 6/28/2016—5,000, 6/28/2017—5,000, and 6/28/2018—5,000.

(14)	Represents options to purchase ARP units, which vest as follows: 5/15/2015—12,500 and 5/15/2016—12,500.

(15)	Represents ARP phantom units, which vest as follows: 5/15/2015—12,500 and 5/15/2016—12,500.

(16)	Represents Atlas Energy phantom units, which vest as follows: 2/4/2015—4,377 and 2/4/2016—4,379.

(17)	Represents Atlas Energy phantom units, which vest as follows: 2/18/2015—14,840 and 2/18/2016—14,840.

(18)	Represents Atlas Energy phantom units, which vest as follows: 6/26/2015—11,750, 6/26/2016—11,750, 6/26/2017—11,750, and 6/26/2018—11,750.

(19)	Represents Atlas Energy phantom units, which vest as follows: 2/4/2015—14,009 and 2/4/2016—14,009.

(20)	Represents Atlas Energy phantom units, which vest as follows: 2/18/2015—49,087 and 2/18/2016—49,087.

(21)	Represents options to purchase ARP units, which vest as follows: 5/15/2015—56,250 and 5/15/2016—56,250.

(22)	Represents ARP phantom units, which vest as follows: 5/15/2015—25,000 and 5/15/2016—25,000.

(23)	Represents Atlas Energy phantom units, which vest as follows: 2/4/2015—9,631 and 2/4/2016—9,632.

(24)	Represents Atlas Energy phantom units, which vest as follows: 2/18/2015—25,685 and 2/18/2016—25,685.

(25)	Represents Atlas Energy phantom units, which vest as follows: 6/26/2015—15,000, 6/26/2016—15,000, 6/26/2017—15,000, and 6/26/2018—15,000.

(26)	Represents APL phantom units, which vest as follows: 4/26/2015—4,250 and 4/26/2016—4,250.

(27)	Represents options to purchase ARP units, which vest as follows: 5/15/2015—25,000 and 5/15/2016—25,000.

(28)	Represents ARP phantom units, which vest as follows: 5/15/2015—17,500 and 5/15/2016—17,500.

(29)	Represents APL phantom units, which vest as follows: 7/10/2015—6,250, 7/10/2016—6,250, and 7/10/2017—6,250.

(30)	Represents Atlas Energy phantom units, which vest as follows: 2/18/2015—17,123 and 2/18/2016—17,124.

(31)	Represents APL phantom units, which vest as follows: 2/18/2015—4,950, 2/18/2016—4,950, and 2/18/2017—5,100.

(32)	Represents Atlas Energy phantom units, which vest as follows: 6/26/2015—18,750, 6/26/2016—18,750, 6/26/2017 —18,750, and 6/26/2018—18,750.

(33)	Represents APL phantom units, which vest as follows: 6/28/2015—3,750, 6/28/2016—3,750, 6/28/2017—3,750, and 6/28/2018—3,750.

 

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2014 OPTION EXERCISES AND UNITS VESTED TABLE

 

		Option awards								Unit awards
Name		Number of units acquired on exercise				Value realized on exercise ($)				Number of units acquired on vesting				Value realized on vesting ($)
Edward E. Cohen			—				—				172,333				6,231,524
Sean P. McGrath			—				—				25,034	(1)			800,102	(1)
Jonathan Z. Cohen			—				—				156,987	(2)			5,541,387	(2)
Daniel C. Herz			—				—				73,163	(3)			2,660,479	(3)
Matthew A. Jones			—				—				75,417				2,704,477

 

(1)	Includes 5,924 ARP units with a value of $114,866 and 5,941 Atlas Energy units with a value of $264,359 that were withheld to cover taxes.

(2)	Includes 15,265 ARP units with a value of $295,988 and 15,266 APL units with a value of $492,380 that were withheld to cover taxes.

(3)	Includes 812 ARP units with a value of $157,292, 20,934 Atlas Energy units with a value of $915,818, and 2,897 APL units with a value of $98,150 that were withheld to cover taxes.

2014 NONQUALIFIED DEFERRED COMPENSATION

 

Name		Executive contributions In the last FY ($)				Registrant contributions in the last FY ($)				Aggregate earnings in the last FY ($)				Aggregate Withdrawals/ Distributions ($)				Aggregate balance at last FYE ($)
Edward E. Cohen			500,000	(1)			500,000	(3)			75,108				1,097,721	(5)			2,172,829
Jonathan Z. Cohen			350,000	(2)			350,000	(4)			53,317				784,086	(5)			1,537,403

 

(1)	This amount is included within the Summary Compensation Table for 2014 reflecting $100,000 in the salary column and $400,000 in the non-equity incentive plan compensation column.

(2)	This amount is included within the Summary Compensation Table for 2014 reflecting $70,000 in the salary column and $280,000 in the non-equity incentive plan compensation column.

(3)	This amount is included within the Summary Compensation Table for 2014 reflecting Atlas Energy’s $500,000 matching contribution in the all other compensation column.

(4)	This amount is included within the Summary Compensation Table for 2014 reflecting Atlas Energy’s $350,000 matching contribution in the all other compensation column.

(5)	Messrs. E. and J. Cohen each elected a deferral period of three years after the amount deferred would otherwise have been earned. This amount is included within the Summary Compensation Table for 2014 in the all other compensation column.

Effective July 1, 2011, Atlas Energy established the Atlas Energy Deferred Compensation Plan, an unfunded nonqualified deferred compensation plan for certain highly compensated employees. The Atlas Energy Deferred Compensation Plan provides Messrs. E. Cohen and J. Cohen, the plan’s current participants, with the opportunity to defer, annually, the receipt of a portion of their compensation, and to permit them to designate investment indices for the purpose of crediting earnings and losses on any amounts deferred under the Atlas Energy Deferred Compensation Plan. Messrs. E. Cohen and J. Cohen may defer up to 10% of their total annual cash compensation (which means base salary and non-performance-based bonus) and up to 100% of all performance-based bonuses, and Atlas Energy is obligated to match such deferrals on a dollar-for-dollar basis (i.e., 100% of the deferral) up to a total of 50% of their base salary for any calendar year. The account is invested in a mutual fund and cash balances are invested daily in a money market account. Atlas Energy established a “rabbi” trust to serve as the funding vehicle for the Atlas Energy Deferred Compensation Plan and Atlas Energy will, not later than the last day of the first month of each calendar quarter, make contributions to the trust in the amount of the compensation deferred, along with the corresponding match, during the preceding calendar quarter. Notwithstanding the establishment of the rabbi trust, the obligation to pay the amounts due under the

 

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Atlas Energy Deferred Compensation Plan constitutes a general, unsecured obligation, payable out of Atlas Energy’s general assets, and Messrs. E. Cohen and J. Cohen do not have any rights to any specific asset of the company.

The Atlas Energy Deferred Compensation Plan has the following additional provisions:

 

•

At the time the participant makes his deferral election with respect to any year, he must specify the date or dates (but not more than two) on which distributions will start, which date may be upon termination of employment or a date that is at least three years after the year in which the amount deferred would otherwise have been earned. A participant may subsequently defer a specified payment date for a minimum of an additional five years from the previously elected payment date. If the participant fails to make an election, all amounts will be distributable upon the termination of employment.

 

•

Distributions will be made earlier in the event of death, disability or a termination of employment due to a change of control.

 

•

If the participant elects to receive all or a portion of his distribution upon the termination of employment, it will be paid in a lump sum. Otherwise, the participant may elect to receive a lump sum payment or equal installments over not more than 10 years.

 

•

A participant may request a distribution of all or part of his account in the event of an unforeseen financial emergency. An unforeseen financial emergency is a severe financial hardship due to an unforeseeable emergency resulting from a sudden and unexpected illness or accident of the participant, or a sudden and unexpected illness or accident of a dependent, or loss of the participant’s property due to casualty, or other similar and extraordinary unforeseeable circumstances arising as a result of events beyond the control of the participant. An unforeseen financial emergency is not deemed to exist to the extent it is or may be relieved through reimbursement or compensation by insurance or otherwise; by borrowing from commercial sources on reasonable commercial terms to the extent that this borrowing would not itself cause a severe financial hardship; by cessation of deferrals under the plan; or by liquidation of the participant’s other assets (including assets of the participant’s spouse and minor children that are reasonably available to the participant) to the extent that this liquidation would not itself cause severe financial hardship.

New Atlas Senior Executive Plan

It is expected that, prior to the completion of the separation, the New Atlas board of directors will adopt, subject to the approval of Atlas Energy in its capacity as New Atlas’s sole unitholder, the Atlas Energy Group, LLC Annual Incentive Plan for Senior Executives, which we refer to as the “New Atlas Senior Executive Plan.” The following is a summary of the New Atlas Senior Executive Plan. This summary is subject to, and qualified in its entirety by reference to, the New Atlas Senior Executive Plan, which is attached as Exhibit 10.8 to the registration statement of which this information statement is a part.

Purpose

The New Atlas Senior Executive Plan provides a means for awarding annual bonuses to New Atlas’s senior executive employees and senior executive employees of New Atlas’s subsidiaries based on the achievement of performance goals over a designated performance period. The performance period is New Atlas’s fiscal year or any other period of up to 12 months. The objectives of the Senior Executive Plan are:

 

•

to enhance our ability to attract, reward and retain senior executive employees;

 

•

to strengthen employee commitment to our success; and

 

•

to align employee interests with those of New Atlas’s unitholders by providing compensation that varies based on New Atlas’s success.

 

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Administration

The New Atlas Senior Executive Plan will be administered and interpreted by the compensation committee of the New Atlas board of directors. The compensation committee has the authority to establish rules and regulations relating to the New Atlas Senior Executive Plan, to interpret the New Atlas Senior Executive Plan and those rules and regulations, to select participants, to determine each participant’s maximum award and award amount, to approve all awards, to decide the facts in any case arising under the New Atlas Senior Executive Plan, to make all other determinations, including factual determinations, and to take all other actions necessary or appropriate for the proper administration of the New Atlas Senior Executive Plan, including the delegation of its authority or power, where appropriate.

Eligibility and Participation

Senior executive employees of New Atlas and its subsidiaries are eligible to participate in the New Atlas Senior Executive Plan. The compensation committee will select the senior executive employees who will participate in the New Atlas Senior Executive Plan for each performance period.

Establishment of Performance Goals

As soon as practicable following the beginning of a performance period, the compensation committee will determine the employees who will be participants for the performance period, the performance goals, and each participant’s maximum award for the performance period. The performance goals may provide for differing amounts to be paid based on differing thresholds of performance.

Performance Objectives

The performance goals will be based on performance objectives selected by the compensation committee for each performance period. The compensation committee may consider factors including, but not limited to, performance relative to an appropriate group designated by the compensation committee, total market return and distributions paid to unitholders, and factors related to the operation of the business, including growth of reserves, growth in production, processing and intake of natural gas, health and safety performance, environmental compliance, and risk management. The aforementioned performance criteria may be considered either individually or in any combination, applied to New Atlas as a whole, to a subsidiary, to a business unit of New Atlas or any subsidiary, to an affiliate of New Atlas or any subsidiary, or to any individual, measured either annually or cumulatively over a period of time. To the extent applicable, the compensation committee, in determining whether and to what extent a performance goal has been achieved, shall use the information set forth in New Atlas’s audited financial statements and other objectively determinable information. The performance goals established by the compensation committee may be (but need not be) different each performance period, and different performance goals may be applicable to different participants.

Calculation of Awards

A participant will earn an award for a performance period based on the level of achievement of the performance goals established by the compensation committee for that performance period. The compensation committee may reduce or increase an award for any performance period based on its assessment of personal performance or other factors.

Payment of Awards

The compensation committee will certify and announce the awards that will be paid to each participant as soon as practicable following the final determination of New Atlas’s financial results for the relevant performance period. Payment of the awards certified by the compensation committee will be made as soon as practicable following the close of the performance period, but in any event within 2.5 months after the close of the performance period. Awards shall be paid in cash, in equity, or in a combination thereof. Any common or phantom units may be issued under a long-term incentive plan of New Atlas or of its subsidiaries.

 

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Limitations on Payment of Awards

Generally, a participant must be employed on the last day of a performance period to receive payment of an award under the New Atlas Senior Executive Plan. If a participant’s employment terminates before the end of the performance period, however, the compensation committee may determine that the participant will remain eligible to receive a prorated portion of any award that would have been earned for the performance period, in such circumstances as the compensation committee deems appropriate. If a participant is on an authorized leave of absence during the performance period, the participant may be eligible to receive a prorated portion of any award that would have been earned, as determined by the compensation committee.

Change in Control

Unless the compensation committee determines otherwise, if a “change in control” (as defined in the New Atlas Senior Executive Plan) of New Atlas occurs before the end of a performance period, each participant will receive an award for the performance period based on performance measured as of the date of the change in control.

Amendment and Termination of Plan

The compensation committee has the authority to amend, modify, or terminate the New Atlas Senior Executive Plan at any time. In the case of a termination of the plan, each participant may receive all or a portion of the award that would otherwise have been earned for the then-current performance period had the New Atlas Senior Executive Plan not been terminated, as determined by the committee.

New Atlas 2015 Long-Term Incentive Plan

It is expected that, prior to the completion of the separation, the New Atlas board of directors will adopt, subject to the approval of Atlas Energy in its capacity as New Atlas’s sole unitholder, the Atlas Energy Group, LLC 2015 Long-Term Incentive Plan, which we refer to as the “New Atlas LTIP,” and which will become effective upon the consummation of the distribution.

The following is a brief description of the principal features of the New Atlas LTIP. This summary is subject to, and qualified in its entirety by reference to, the New Atlas LTIP, which is attached as Exhibit 10.5 to the registration statement of which this information statement is a part.

Purpose

The New Atlas LTIP is intended to promote the interests of New Atlas by providing to officers, employees, and directors of New Atlas, employees of its affiliates, consultants, and joint venture partners who perform services for New Atlas incentive awards for superior performance that are based on New Atlas common units. The New Atlas LTIP is intended to enhance the ability of New Atlas and its affiliates to attract and retain the services of individuals who are essential for the growth and profitability of New Atlas, and to encourage them to devote their best efforts to the business of New Atlas and advancing the interests of New Atlas.

Administration

Grants made under the New Atlas LTIP will be determined by the New Atlas board of directors or a committee of the New Atlas board of directors, or the board (or a committee of the board) of an affiliate of New Atlas that is appointed by the New Atlas board of directors to administer the New Atlas LTIP. We refer to the New Atlas board of directors, the board of an affiliate, or any respective committee thereof that administers the New Atlas LTIP as the “committee.”

Subject to the provisions of the New Atlas LTIP, the committee is authorized to administer and interpret the New Atlas LTIP, to make factual determinations, and to adopt or amend its rules, regulations, agreements, and

 

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instruments for implementing the New Atlas LTIP. The committee will also have the full power and authority to determine the recipients of grants under the New Atlas LTIP as well as the terms and provisions of restrictions relating to grants.

Subject to any applicable law, the committee, in its sole discretion, may delegate any or all of its powers and duties under the New Atlas LTIP, including the power to award grants under the New Atlas LTIP, to the Chief Executive Officer of New Atlas, subject to such limitations as the committee may impose, if any. However, the Chief Executive Officer may not make awards to, or take any action with respect to any grant previously awarded to, himself or a person who is subject to Rule 16b-3 under the Exchange Act.

Eligibility

Persons eligible to receive grants under the New Atlas LTIP are (a) officers and employees of New Atlas, its affiliates, consultants, or joint venture partners who perform services for New Atlas or an affiliate or in furtherance of New Atlas’s business (we refer to each such officer and employee as an “eligible employee”) and (b) non-employee directors of New Atlas.

Unit Reserve; Adjustments

Awards in respect of up to 5.25 million New Atlas common units (approximately 20% of the fully diluted issued and outstanding number of New Atlas common units on a pro forma basis after giving effect to the distribution) may be issued under the New Atlas LTIP. This amount is subject to adjustment as provided in the New Atlas LTIP for events such as distributions (in New Atlas common units or other securities or property, including cash), unit splits (including reverse splits), recapitalizations, mergers, consolidations, reorganizations, reclassifications, and other extraordinary events affecting the outstanding New Atlas common units such that an adjustment is necessary in order to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under the New Atlas LTIP. New Atlas common units issued under the New Atlas LTIP may consist of New Atlas common units newly issued by New Atlas, New Atlas common units acquired in the open market or from any affiliate of New Atlas, or any other person, or any combination of the foregoing. If any award granted under the New Atlas LTIP is forfeited or otherwise terminates or is cancelled or paid without the delivery of New Atlas common units, then the New Atlas common units covered by the award will (to the extent of the forfeiture, termination, or cancellation, as the case may be) again be New Atlas common units available for grants of awards under the New Atlas LTIP. New Atlas common units surrendered in payment of the exercise price of an option, and New Atlas common units withheld or surrendered for payment of taxes, will not be available for re-issuance under the New Atlas LTIP.

Awards

Awards granted under the New Atlas LTIP may consist of options to purchase New Atlas common units, phantom units, and restricted units. All grants are subject to such terms and conditions as the committee deems appropriate, including but not limited to vesting conditions.

Option. An option is the right to purchase a New Atlas common unit in the future at a predetermined price (which we refer to as the “exercise price”). The exercise price of each option is determined by the committee and may be equal to or greater than the fair market value of a New Atlas common unit on the date the option is granted. The committee will determine the vesting and exercise restrictions applicable to an award of options, if any, and the method or methods by which payment of the exercise price may be made, which may include, without limitation, cash, check acceptable to the New Atlas board of directors, a tender of New Atlas common units having a fair market value equal to the exercise price, a “cashless” broker-assisted exercise, a recourse note in a form acceptable to the New Atlas board of directors and that does not violate the Sarbanes-Oxley Act of 2002, a “net exercise” that permits New Atlas to withhold a number of New Atlas common units that otherwise would be issued to the holder of the option pursuant to the exercise of the option having a fair market value equal to the exercise price, or any combination of the methods described above.

 

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Phantom Units. Phantom units represent rights to receive New Atlas common units, an amount of cash or other securities or property based on the value of a New Atlas common unit, or a combination of New Atlas common units and cash or other securities or property. Phantom units are subject to terms and conditions determined by the committee, which may include vesting restrictions. In addition, the committee may grant distribution equivalent rights in connection with a grant of phantom units. Distribution equivalent rights represent the right to receive an amount in cash, securities, or other property equal to, and at the same time as, the cash distributions or other distributions of securities or other property made by New Atlas with respect to New Atlas common units during the period that the underlying phantom unit is outstanding. Distribution equivalents may (a) be paid currently by New Atlas or may be deferred and, if deferred, may accrue interest, (b) accrue as a cash obligation or may convert into additional phantom units for the holder of the underlying phantom units, (c) be payable based on the achievement of specific goals, and (d) be payable in cash or New Atlas common units or in a combination of cash and New Atlas common units, in each case as determined by the committee.

Restricted Units. Restricted units are actual New Atlas common units issued to a participant that are subject to vesting restrictions and evidenced in such manner as the committee may deem appropriate, including book-entry registration or issuance of one or more unit certificates. Prior to or upon the grant of an award of restricted units, the committee will condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals, or both. Unless otherwise determined by the committee, a holder of restricted units will have certain rights of holders of New Atlas common units in general, including the right to vote the restricted units. During the period during which the restricted units are subject to vesting restrictions, however, the holder will not be permitted to sell, assign, transfer, pledge, or otherwise encumber the restricted units. As determined by the committee, cash dividends on restricted units may be automatically deferred or reinvested in additional restricted units and held subject to the vesting of the underlying restricted units, and dividends payable in New Atlas common units may be paid in the form of restricted units of the same class as the restricted units with respect to which the dividend is paid and may be subject to vesting of the underlying restricted units.

Change in Control

Upon a “change in control” (as defined in the New Atlas LTIP), all unvested awards granted under the New Atlas LTIP held by directors will immediately vest in full. In the case of awards granted under the New Atlas LTIP held by eligible employees, upon the eligible employee’s termination of employment without “cause” (as defined in the New Atlas LTIP) or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), in any case following a change in control, any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. In connection with a change in control, the committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which New Atlas (or any affiliate) and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason):

 

•

cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity);

 

•

accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to the New Atlas common units that otherwise would have been unvested so that participants (as holders of awards granted under the New Atlas LTIP) may participate in the transaction;

 

•

provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards);

 

•

terminate all or some awards upon the consummation of the change-in-control transaction, but only if the committee provides for full vesting of awards immediately prior to the consummation of such transaction; and

 

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•

make such other modifications, adjustments, or amendments to outstanding awards or the New Atlas LTIP as the committee deems necessary or appropriate.

No Assignment

Except as otherwise determined by the committee, no award granted under the New Atlas LTIP will be assignable or transferable except by will or the laws of descent and distribution. When a participant dies, the personal representative or other person entitled to succeed to the rights of the participant may exercise the participant’s rights under his or her awards.

Withholding

All awards granted under the New Atlas LTIP will be subject to applicable federal (including FICA), state, and local tax withholding requirements. If New Atlas so permits, New Atlas common units may be withheld to satisfy tax withholding obligations with respect to awards paid in New Atlas common units, at the time such awards become subject to employment taxes and tax withholding, as applicable, up to an amount that does not exceed the minimum required withholding for federal (including FICA), state, and local tax liabilities. New Atlas may require forfeiture of any award for which the participant does not timely pay the applicable withholding taxes.

Amendment and Termination

Subject to the limitations described below, the committee may amend, alter, suspend, discontinue, or terminate the New Atlas LTIP at any time without the consent of participants, except that the committee may not amend the New Atlas LTIP without approval of the unitholders if such approval is required in order to comply with applicable stock exchange requirements. New Atlas may waive any conditions or rights under, amend any terms of, or alter any award previously granted under the New Atlas LTIP; however, no change to any award previously granted under the New Atlas LTIP may materially reduce the benefit to a participant, unless the participant has consented or such change is explicitly allowed in the New Atlas LTIP or the applicable award agreements. The committee may not reprice options, nor may the New Atlas LTIP be amended to permit option repricing, unless the unitholders approve such repricing or amendment.

Plan Term

The New Atlas LTIP will continue until the date terminated by the New Atlas board of directors or the date upon which New Atlas common units are no longer available for the grant of awards, whichever occurs first.

U.S. Federal Income Tax Consequences

The following is a general description of the U.S. federal income tax consequences of options, phantom units, and restricted unit awards granted under the New Atlas LTIP. It provides only a general description of the application of federal income tax laws with respect to grants under the New Atlas LTIP. This discussion is intended for the information of New Atlas unitholders and not as tax guidance to participants in the New Atlas LTIP. The summary does not address the effects of other federal taxes or taxes imposed under state, local, or foreign tax laws and does not purport to be complete.

Options. Options granted under the New Atlas LTIP are not eligible for treatment as “incentive stock options” under the Internal Revenue Code. Therefore, all options granted under the New Atlas LTIP will be nonqualified options. A grantee of options will not recognize income at the time of grant. Upon exercise of an option, the grantee will recognize ordinary compensation income equal to the amount, if any, by which the fair market value (as determined on the date of exercise of the option) of the New Atlas common units issuable with respect to the option exceeds the exercise price of the option. Since New Atlas is currently not a taxable entity for federal income tax purposes, the amount of taxable compensation to the participant will be treated as deductions

 

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allocated among the partners of New Atlas in accordance with New Atlas’s limited liability company agreement. The grantee’s holding period for the New Atlas common units acquired pursuant to the exercise of an option for purposes of determining eligibility for capital gains treatment upon the disposition of the New Atlas common units begins on the option exercise date.

Phantom Units; Restricted Units. The recipient of a phantom unit or restricted unit award will not recognize income at the time of the grant of his or her award. Rather, the participant will have taxable compensation in an amount equal to the fair market value of the New Atlas common units or, in the case of phantom units, the New Atlas common units or other securities or property (as the case may be), actually received by the participant in connection with the vesting of the award, and New Atlas will receive a deduction equal to such amount. Upon the sale of New Atlas common units, a participant generally will have gain or loss (which may consist of both ordinary and capital gain and loss elements depending upon New Atlas’s taxable income and loss during the period in which the New Atlas common units were held). Since New Atlas is currently not a taxable entity for federal income tax purposes, the amount of taxable compensation to the participant will be treated as deductions allocated among the partners of New Atlas in accordance with New Atlas’s limited liability company agreement.

 

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DESCRIPTION OF MATERIAL INDEBTEDNESS

New Atlas intends to enter into certain financing arrangements prior to or concurrent with the separation.

 

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SECURITY OWNERSHIP OF MANAGEMENT, DIRECTORS AND PRINCIPAL UNITHOLDERS

Before the separation and distribution, all of our outstanding common units, representing a 100% limited liability company interest, will be owned beneficially and of record by Atlas Energy. After the distribution, Atlas Energy will not retain ownership of any common units, and will therefore have no limited liability company interest in New Atlas.

The following table provides information with respect to the expected beneficial ownership of our common units, immediately following the completion of the separation and distribution, by (1) each person who is known by us who will beneficially own more than 5% of our common units, (2) each expected member of the board of directors, (3) each executive officer named in the Summary Compensation Table, and (4) all of the executive officers and members of the board of directors. We based the number of units shown below on each person’s beneficial ownership of Atlas Energy common units as of February 4, 2015, assuming that the Atlas Merger and the distribution were both consummated as of such date. Except as otherwise noted in the footnotes below, each person or entity identified below has sole voting and investment power with respect to such securities. Following the distribution, we will have an aggregate of 26.0 million common units outstanding.

 

Beneficial Owner		Beneficial Ownership of Common Units				Percent of Common Units
Directors and Officers(1)
Mark C. Biderman			9,555				*
Edward E. Cohen			737,807	(2)			2.8	%
Jonathan Z. Cohen			695,180	(3)			2.7	%
DeAnn Craig			2,199				*
Daniel C. Herz			8,419				*
Dennis A. Holtz			6,949				*
Matthew A. Jones			41,234				*
Walter C. Jones			323				*
Freddie M. Kotek			51,435	(4)			*
Jeffrey F. Kupfer			3,213				*
Sean P. McGrath			8,536				*
Jeffrey M. Slotterback			1,101				*
Lisa Washington			4,377				*
Ellen F. Warren			2,343				*
All Executive Officers and Directors as a Group (14 persons)			968,874	(5)			3.6	%
Owners of More Than 5% of Outstanding Common Units
Leon G. Cooperman			3,705,499	(6)			14.3	%
ING Groep N.V./ING Capital Markets LLC			1,744,840	(7)			6.7	%
Tourbillon Capital Partners LP			1,305,500	(8)			5.0	%

 

*	Less than 1%.

(1)	The business address for each director and executive officer is Park Place Corporate Center One, 1000 Commerce Drive, 4th Floor, Pittsburgh, PA 15275-1011.

(2)

Includes (i) 13,125 common units held in an individual retirement account of Mr. E. Cohen’s spouse, (ii) 570,163 common units held by a charitable foundation of which Mr. E. Cohen, his spouse and their children serve as co-trustees; and (iii) 33,636 common units held in trust for the benefit of Mr. E. Cohen’s spouse and/or children. Mr. E. Cohen disclaims beneficial ownership of the above referenced common units. 603,800 of these common units are also included in the common units referred to in footnote 3 below.

(3)

Includes (i) 33,636 common units held in a trust of which Mr. J. Cohen is a co-trustee and co-beneficiary and (ii) 570,163 common units held by a charitable foundation of which Mr. J. Cohen, his parents and his sibling serve as co-trustees. These common units are also included in the common units referred to in footnote 2 above. Mr. J. Cohen disclaims beneficial ownership of the above referenced common units.

(4)	Includes (i) 8,163 common units held by spouse, (ii) 28,564 common units held by his children’s trust, (iii) 965 common units held by his children and (iv) 3,229 common units held by his mother-in-law.

(5)	This number has been adjusted to exclude 33,636 common units and 570,163 common units which were included in both Mr. E. Cohen’s beneficial ownership amount and Mr. J. Cohen’s beneficial ownership amount.

(6)	This information is based on a Form 4 filed with the SEC on February 5, 2015. The address of Mr. Cooperman is 11431 W. Palmetto Park Road, Boca Raton, FL 33428.

(7)

This information is based on a Schedule 13G/A filed with the SEC on February 14, 2014. The address for ING Groep N.V. is Bijlmerplein 888, 1102 MG, Amsterdam-Zuidoost, Postbus 1800, 1000 BV Amsterdam, The Netherlands and the address for ING Capital Markets LLC is 1013 Centre Road, Wilmington, New Castle, DE 19805.

(8)	This information is based on a Schedule 13G filed with the SEC on May 7, 2014.

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Our Relationship with Atlas Energy

Immediately following the separation and distribution, Atlas Energy will no longer own any of our outstanding common units and will therefore no longer have any limited liability company interest in us.

Our Board of Directors has adopted a cash distribution policy, pursuant to our limited liability company agreement, which requires that we distribute all of our available cash quarterly to our unitholders within 50 days following the end of each calendar quarter in accordance with their respective percentage interests. Under our limited liability company agreement, available cash will be defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of cash reserves established by our board of directors, in its sole discretion to provide for the proper conduct of our business or to provide for future distributions. Some of the expected non-independent directors of our board of directors also serve as directors of Atlas Energy’s general partner.

We will enter into the agreements described in this section with Atlas Energy to facilitate an orderly transition and govern the relationship between the companies after completion of the distribution and the Atlas Merger. Following the Atlas Merger, Atlas Energy will be a subsidiary of Targa Resources. The following descriptions include a summary of material terms of such agreements but are qualified in their entirety by reference to the agreements, which are filed as exhibits to New Atlas’s registration statement on Form 10 of which this information statement is a part. We urge all unitholders to read these agreements carefully.

Separation and Distribution Agreement

Subject to the terms and conditions set forth in the Atlas merger agreement, Atlas Energy has agreed that it will, pursuant to a separation and distribution agreement substantially in the form attached to the Atlas merger agreement, transfer its assets and liabilities other than those related to its “Atlas Pipeline Partners” segment to New Atlas and, immediately prior to the Atlas Merger, effect a pro rata distribution to the Atlas Energy unitholders of New Atlas common units representing a 100% interest in New Atlas. The separation and distribution agreement sets forth our agreements with Atlas Energy regarding the principal actions to be taken in connection with these transactions and other agreements that will govern aspects of our relationship with Atlas Energy following the distribution. Following the Atlas Merger, Atlas Energy will be a subsidiary of Targa Resources.

Prior to the separation and distribution, our assets and businesses, other than the general partner interest and incentive distribution rights in ARP, will be held by Atlas Energy or one or more of its subsidiaries. In connection with the separation and distribution, we will enter into an agreement with Atlas Energy, pursuant to which Atlas Energy will agree to transfer to us certain assets and liabilities comprising the remainder of our businesses and to distribute approximately 26.0 million of our common units, representing a 100% limited liability company interest in us, to the Atlas Energy unitholders in a pro rata distribution.

Transfer of Assets and Assumption of Liabilities

The separation and distribution agreement will identify assets to be transferred, liabilities to be assumed and contracts to be assigned to us as part of our separation from Atlas Energy and will describe when and how these transfers, assumptions and assignments will occur. In particular, the separation and distribution agreement will generally provide that Atlas Energy will transfer to us or one of our subsidiaries substantially all of its businesses to the extent they are not related to its “Atlas Pipeline Partners” segment, which we refer to as the “Retained Business.” Following the transfer, we will own, directly or indirectly:

 

•

the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in Atlas Resource Partners;

 

•

Atlas Energy’s equity in the limited and general partner in the Development Subsidiary;

 

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•

Atlas Energy’s equity in the limited and general partner in Lightfoot;

 

•

natural gas development and production assets in the Arkoma Basin, which Atlas Energy acquired in July 2013;

 

•

all contracts, other than contracts (and portions thereof) that are exclusively related to the Retained Business;

 

•

the ATLAS name and trademark;

 

•

all equipment, information, technology, software, intellectual property, information, permits and insurance policies, other than equipment, information, technology, software, intellectual property and permits that are primarily related to the Retained Business;

 

•

all rights to third-party indemnification and all other claims, other than rights to indemnification and claims to the extent attributable to the Retained Business;

 

•

oil and gas interests underneath certain rights-of-way in Ohio;

 

•

insurance proceeds received or receivable by Atlas Energy to the extent in connection with damage to the transferred assets or with Assumed Liabilities (as defined below);

 

•

tax refunds or credits attributable to the transferred assets or business or to the Assumed Liabilities;

 

•

leases for real property located in New York, New York, Philadelphia, Pennsylvania and Pittsburgh, Pennsylvania; and

 

•

all cash held by Atlas Energy or its wholly owned subsidiaries, other than $5 million that will be retained by Atlas Energy.

We will also assume and be responsible for all liabilities and obligations of Atlas Energy, other than Retained Liabilities (as defined below). The liabilities that New Atlas will be responsible for, which we refer to as “Assumed Liabilities,” include:

 

•

liabilities arising out of actions, inactions, events, omissions, conditions, facts or circumstances occurring or existing prior to the completion of the separation, to the extent related to the transferred assets, transferred businesses or transferred employees;

 

•

liabilities and obligations expressly allocated to us or one of our subsidiaries pursuant to the terms of the separation and distribution agreement, the Atlas merger agreement or certain other agreements entered into in connection with the separation;

 

•

subject to Targa Resources’ and, after the closing of the Atlas Merger, Atlas Energy’s compliance with the terms of the Atlas merger agreement, (1) liabilities in respect of severance, change in control, termination, retention, incentive or similar amounts or benefits payable by Atlas Energy or its subsidiaries to employees who will transfer to New Atlas as a result of the Atlas merger agreement and (2) liabilities arising under or in connection with Atlas Energy’s and APL’s equity plans;

 

•

liabilities for claims made by third parties against us, Atlas Energy or our or its subsidiaries or affiliates to the extent relating to, arising out of, or resulting from such assets or businesses;

 

•

claims or actions by past or present directors and officers of Atlas Energy (other than employees who will remain with Atlas Energy) against Atlas Energy or its general partner, other than certain indemnification claims under the Atlas merger agreement;

 

•

liabilities of Atlas Energy (1) in respect of stockholder litigation, to the extent such litigation arises solely from the separation and distribution, and (2) for administering stockholder or other third-party litigation relating to the Atlas merger agreement between the signing of the agreement and the closing of the Atlas Merger; and

 

•

transaction fees and expenses payable to third-party advisors as a result of the Atlas merger agreement or the consummation of the Atlas Merger or the distribution.

 

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Atlas Energy will retain the following assets, which will not be transferred to us in the separation:

 

•

all of the equity in the general partner of Atlas Energy;

 

•

all of the equity in the general partner of Atlas Pipeline Partners and Atlas Energy’s common units in Atlas Pipeline Partners;

 

•

all contracts (and portions thereof) that are exclusively related to the Retained Business;

 

•

all equipment, information, technology, software, intellectual property, information, permits and insurance policies that are primarily related to the Retained Business;

 

•

$5 million in cash;

 

•

all rights to third-party indemnification and all other claims to the extent attributable to the Retained Business;

 

•

insurance proceeds received or receivable by Atlas Energy to the extent in connection with damage to the retained assets or with Retained Liabilities (as defined below);

 

•

tax refunds or credits attributable to the Retained Business, the assets retained by Atlas Energy or the Retained Liabilities; and

 

•

all other assets primarily related to the Retained Business.

Atlas Energy will also remain responsible for certain liabilities and obligations related to these assets, which we refer to as the “Retained Liabilities,” including:

 

•

liabilities arising out of actions, inactions, events, omissions, conditions, facts, or circumstances occurring or existing prior to the completion of the separation, to the extent related to such assets and businesses;

 

•

liabilities and obligations expressly allocated to Atlas Energy or one of its subsidiaries pursuant to the terms of the separation and distribution agreement, the Atlas merger agreement or certain other agreements entered into in connection with the separation;

 

•

liabilities under APL’s existing credit agreements and APL’s outstanding senior notes;

 

•

liabilities of Atlas Energy to comply with the Atlas merger agreement after the closing of the Atlas Merger;

 

•

liabilities of Atlas Energy for stockholder litigation (other than any such liabilities that are included in the Assumed Liabilities), including liabilities in connection with settling such litigation; and

 

•

liabilities for claims made by third parties against us, Atlas Energy or our or its subsidiaries or affiliates to the extent relating to, arising out of, or resulting from such assets or businesses.

In general, neither we nor Atlas Energy will make any representations or warranties regarding the assets, businesses or liabilities transferred or assumed, any consents or approvals that may be required in connection with such transfers or assumptions, the value or freedom from any lien or other security interest of any assets transferred, the absence of any defenses relating to any claim of either us or Atlas Energy, or the legal sufficiency of any conveyance documents. Except as expressly set forth in the contribution and assumption agreement or in any ancillary agreement, all assets will be transferred on an “as is,” “where is” basis.

Information in this information statement with respect to the assets and liabilities of the parties following the distribution is presented based on the allocation of such assets and liabilities pursuant to the separation and distribution agreement, unless the context otherwise requires. The separation and distribution agreement provides that, in the event that the transfer or assignment of certain assets and liabilities to us or Atlas Energy, as applicable, does not occur prior to the separation, then until such assets or liabilities are able to be transferred or

 

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assigned, we or Atlas Energy, as applicable, will hold such assets on behalf and for the benefit of the other party and will pay, perform, and discharge such liabilities, for which the other party will reimburse us or Atlas Energy, as applicable, for all commercially reasonable payments made in connection with the performance and discharge of such liabilities.

Assignment of Obligations

We and Atlas Energy will be required to use commercially reasonable efforts to obtain consents, approvals and amendments required to novate or assign the liabilities that are to be transferred pursuant to the separation and distribution agreement. If either party is unable to obtain required consents, approvals or amendments, the prospective assignor will act as agent or subcontractor for the prospective assignee and perform the assignee’s obligations, and the assignee will pay and remit to the assignor all money, rights and other consideration received by the assignee in respect of such performance.

Cash Transfers

The separation and distribution agreement will provide that, in connection with the transfer of assets and assumption of liabilities described above, and prior to the distribution, New Atlas will enter into one or more financing arrangements pursuant to which it will borrow at least $150.0 million and transfer $150.0 million to Atlas Energy as a cash distribution. Atlas Energy will use this cash distribution as well as a payment due from Targa Resources under the Atlas merger agreement to repay certain of Atlas Energy’s outstanding indebtedness at or prior to the effective time of the distribution. New Atlas will be responsible for any shortfall if the sum of the cash distribution and Targa Resources payment is less than the amount required to repay such indebtedness in full.

The Distribution

The separation and distribution agreement will also govern the rights and obligations of the parties regarding the proposed distribution of our common units to the Atlas Energy unitholders. Pursuant to the separation and distribution agreement, Atlas Energy will cause its agent to distribute one of our common units for every two common units of Atlas Energy held by such person as of the record date. Based on the number of outstanding Atlas Energy common units outstanding on the record date, we expect that approximately 26.0 million of our common units, representing 100% limited liability company interest, will be distributed in the distribution.

Conditions to the Distribution

The separation and distribution agreement provides that the distribution is subject to the satisfaction (or waiver by Atlas Energy, subject to the restrictions described below) of certain conditions. These conditions are described in the section entitled “The Separation and Distribution—Conditions to the Distribution” beginning on page 74. Neither Atlas Energy nor New Atlas will be permitted to amend, waive, supplement or modify any provision of the separation and distribution agreement, or make any determination as to the satisfaction or waiver of the conditions to the distribution, in a manner that is materially adverse to Atlas Energy, Targa Resources or their affiliates or that would prevent or materially impede consummation of the Atlas Merger without first obtaining Targa Resources’ consent.

Termination

The separation and distribution agreement will terminate without further action before the distribution upon termination of the Atlas merger agreement. Subject to the terms and conditions of the Atlas merger agreement, the separation and distribution agreement will not be terminable prior to the distribution without the mutual consent of Atlas Energy and Targa Resources.

 

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Indemnification

We will indemnify Atlas Energy and its affiliates (other than us and our subsidiaries) and their directors, officers and employees against liabilities relating to, arising out of or resulting from:

 

•

the Assumed Liabilities;

 

•

our failure, or the failure of any other person, to pay, perform or otherwise promptly discharge any of the Assumed Liabilities, in accordance with their respective terms, whether prior to, at or after the distribution;

 

•

except to the extent relating to a Retained Liability, any guarantee, indemnification or contribution obligation for our benefit by Atlas Energy that survives the distribution;

 

•

any breach by us of the separation and distribution agreement or any of the ancillary agreements; and

 

•

any untrue statement or alleged untrue statement or omission or alleged omission of a material fact in the registration statement of which this information statement forms a part, or in this information statement (as amended or supplemented).

Atlas Energy will indemnify us and our subsidiaries, directors, officers and employees against liabilities relating to, arising out of or resulting from:

 

•

the Retained Liabilities;

 

•

the failure of Atlas Energy or any other person to pay, perform, or otherwise promptly discharge any of the Retained Liabilities, in accordance with their respective terms whether prior to, at, or after the distribution;

 

•

except to the extent relating to an Assumed Liability, any guarantee, indemnification or contribution obligation for the benefit of Atlas Energy by us that survives the distribution; and

 

•

any breach by Atlas Energy of the separation and distribution agreement or any of the ancillary agreements.

The separation and distribution agreement will also specify procedures with respect to claims subject to indemnification and related matters.

Intellectual Property

Following the distribution, New Atlas will own the Atlas name and trademark and will license the Atlas name and trademark on a worldwide, royalty-free, non-exclusive basis for use in the Retained Business. The license will generally expire 180 days following the distribution, except that it will continue for twelve months after the distribution for pipeline markers and other equipment held by Atlas Energy.

Non-Solicitation

For twelve months after the distribution, both Atlas Energy and we will not, and will not permit its or our affiliates to, directly or indirectly, solicit for employment any employee of the other party or its affiliates, subject to certain customary exceptions.

Further Assurances

Atlas Energy and we will agree to use reasonable best efforts to take all actions reasonably necessary, proper or advisable to consummate and make effective the transactions contemplated by the separation and distribution agreement and any other agreement executed in connection therewith. Atlas Energy and we will also cooperate as and to the extent reasonably requested by the other party in connection with certain tax-related matters.

 

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Dispute Resolution

The separation and distribution agreement contains provisions that govern, except as otherwise provided in any ancillary agreement, the resolution of disputes, controversies or claims that may arise between us and Atlas Energy related to the separation or distribution. These provisions contemplate that efforts will be made to resolve disputes, controversies and claims by escalation of the matter to executives of us and Atlas Energy. If such efforts are not successful, either we or Atlas Energy may submit the dispute, controversy or claim to nonbinding mediation or, if such nonbinding mediation is not successful, binding alternative dispute resolution, subject to the provisions of the separation and distribution agreement.

Amendments

Neither Atlas Energy nor New Atlas will be permitted to amend, waive, supplement or modify any provision of the separation and distribution agreement, or make any determination as to the satisfaction or waiver of the conditions to the distribution, in a manner that is materially adverse to Atlas Energy, Targa Resources or their affiliates or that would prevent or materially impede consummation of the Atlas Merger without first obtaining Targa Resources’ consent.

Expenses

Except as expressly set forth in the separation and distribution agreement, the Atlas merger agreement or in any ancillary agreement, all costs and expenses incurred in connection with the separation and distribution incurred prior to the distribution date, including costs and expenses relating to legal and tax counsel, financial advisors and accounting advisory work related to the separation and distribution, will be paid by New Atlas. After the distribution date, each party will bear its own costs and expenses incurred after such date.

Other Matters

Other matters governed by the separation and distribution agreement include access to financial and other information, confidentiality, access to and provision of records and treatment of outstanding guarantees and similar credit support.

Employee Matters Agreement

Prior to the separation and distribution, Atlas Energy and New Atlas will enter into an employee matters agreement, substantially in the form attached to the form of separation and distribution agreement, to allocate liabilities and responsibilities relating to employment matters, employee compensation and benefits plans and programs, and other related matters. The employee matters agreement will govern certain compensation and employee benefit obligations with respect to the current and former employees and non-employee directors of each company.

Unless otherwise specified, Atlas Energy will be responsible for liabilities associated with employees who will be employed by Atlas Energy following the separation and distribution and former employees whose last employment was with the Retained Business, whom we collectively refer to as the “Atlas Energy allocated employees,” and New Atlas will be responsible for liabilities associated with employees who will be employed by New Atlas following the separation and distribution and former employees whose last employment was with the New Atlas businesses, whom we collectively refer to as the “New Atlas allocated employees.”

Transfer of Employees

The employee matters agreement will provide that, prior to the separation and distribution, all New Atlas allocated employees will be transferred to New Atlas to the extent not already employed by New Atlas or its subsidiaries. Subject to certain exceptions, the transfer of New Atlas allocated employees to New Atlas will not constitute a separation from service for purposes of any applicable laws or severance programs.

 

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Employee Benefits

The employee matters agreement will provide that, upon or prior to the separation and distribution, New Atlas will assume the benefit plans sponsored or maintained by Atlas Energy, including a 401(k) plan, a nonqualified deferred compensation plan, and health and welfare benefit plans, and maintain these plans for the benefit of New Atlas allocated employees following the separation and distribution. Effective as of the consummation of the separation and distribution, Atlas Energy allocated employees will generally cease to participate in the benefit plans assumed by New Atlas.

In general, New Atlas will credit each New Atlas allocated employee with his or her service with Atlas Energy prior to the separation and distribution for all purposes under the New Atlas benefit plans to the same extent such service was recognized by Atlas Energy for similar purposes and so long as such crediting does not result in a duplication of benefits.

Equity Compensation Awards

The employee matters agreement will provide for the conversion of the outstanding awards granted under Atlas Energy’s equity compensation plans into adjusted awards relating to common units of Atlas Energy and New Atlas, and the subsequent cancellation and settlement of all New Atlas awards issued in connection with the adjustment.

Each option to purchase Atlas Energy common units will be converted into an adjusted Atlas Energy option and a New Atlas option. The exercise price and number of units subject to each option will be adjusted in order to preserve the aggregate intrinsic value of the original Atlas Energy option as measured immediately before and immediately after the separation, subject to rounding.

Holders of Atlas Energy phantom unit awards, including Atlas Energy non-employee directors, will retain those awards and also will receive a New Atlas phantom unit award covering a number of New Atlas common units that reflects the distribution to Atlas Energy unitholders, determined by applying the distribution ratio to Atlas Energy phantom unit awards as though they were actual Atlas Energy common units.

Immediately following the separation and distribution, all New Atlas options and phantom unit awards will be cancelled and settled for the implied value of a New Atlas common unit less, in the case of New Atlas options, the applicable exercise price. The New Atlas options and phantom unit awards will be settled in cash, subject to a specified aggregate cap on the amount of cash that may be distributed in respect of all New Atlas equity awards held by employees and non-employee directors. If the cap is exceeded, then any amounts payable to holders of New Atlas equity awards in excess of the cap will be settled in New Atlas common units. If the cap is not exceeded, then any excess available cash will be distributed to the holders of New Atlas phantom unit awards on a pro rata basis.

The adjusted Atlas Energy equity awards will be cancelled and converted or settled as provided in the Atlas merger agreement.

The separation and distribution agreement and the employee matters agreement will be filed as an exhibit to the registration statement of which this document forms a part, and the summary sets forth the terms of the agreement that we believe are material. These summaries are qualified in their entireties by reference to the full text of the applicable agreements, which are incorporated by reference into this information statement. The terms of the agreements described above that will be in effect following the separation have not yet been finalized; changes to these agreements, some of which may be material, may be made prior to our separation from Atlas Energy.

Relationship with Resource America

Edward E. Cohen, our expected Chief Executive Officer and President, serves as Chairman of Resource America, Inc., the former parent of AEI, and is a greater than 10% shareholder, and Jonathan Z. Cohen, our

 

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expected Executive Chairman, serves as Chief Executive Officer and President of Resource America and is a greater than 10% shareholder. We sublease office space from Resource America and reimburse it for certain shared services.

Transactions with ARP

ARP does not employ any persons to manage or operate its businesses. Instead, as ARP’s general partner, we provide employees and incur expenses related to managing ARP’s operations. ARP reimburses us for expenses we incur in managing its operations and also reimburses us for compensation and benefits related to our employees who perform services for ARP upon an estimate of the time spent by such persons on activities for ARP. For the year ended December 31, 2013, ARP reimbursed $5.0 million for expenses, compensation and benefits.

In July 2013, in connection with ARP’s acquisition of Raton Basin assets from EP Energy, L.P., Atlas Energy purchased $86.6 million of ARP’s newly created Class C convertible preferred units at a negotiated price per unit of $23.10, which was the face value of the units. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act. The Class C preferred units pay cash distributions in an amount equal to the greater of (i) $0.51 per unit and (ii) the distributions payable on each common unit at each declared quarterly distribution date. The initial Class C preferred distribution was paid for the quarter ending September 30, 2013. The Class C preferred units have no voting rights, except as set forth in the certificate of designation for the Class C preferred units, which provides, among other things, that the affirmative vote of 75% of the Class C Preferred Units is required to repeal the certificate of designation. Holders of the Class C preferred units have the right to convert the Class C preferred units on a one-for-one basis, in whole or in part, into common units at any time before July 31, 2016. Unless previously converted, all Class C preferred units will convert into common units on July 31, 2016. Upon issuance of the Class C preferred units, we received 562,497 warrants to purchase ARP’s common units at an exercise price equal to the face value of the Class C preferred units. The warrants were exercisable beginning October 29, 2013 into an equal number of our common units at an exercise price of $23.10 per unit, subject to adjustments provided therein. The warrants will expire on July 31, 2016.

Upon issuance of the Class C preferred units and warrants on July 31, 2013, Atlas Energy and ARP entered into a registration rights agreement pursuant to which ARP agreed to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class C preferred units and upon exercise of the warrants. ARP agreed to use commercially reasonable efforts to file such registration statement within 90 days of the conversion of the Class C preferred units into common units or the exercise of the warrants.

Indemnification of Directors and Officers

Under our limited liability company agreement, in most circumstances, we will indemnify any director or, officer, manager, managing member, tax matters partner, employee, agent or trustee of our company or any of our affiliates and any person who is or was serving at our request as a manager, managing member, officer, director, tax matter partner, employee, agent, fiduciary or trustee of another person, to the fullest extent permitted by law, from and against all losses, claims or damages arising out of or incurred in connection with our business. See “Our Limited Liability Company Agreement—Indemnification.”

Procedures for Approval of Related Person Transactions

The board of directors is expected to adopt a written policy designed to minimize potential conflicts of interest in connection with New Atlas transactions with related persons. This policy will define a “related person” to include: (i) any executive officer, director or director nominee; (ii) any person known to be a beneficial owner of 5% or more of our common units; (iii) an immediate family member of any person included in clauses (i) and (ii) (which, by definition, includes a person’s spouse, parents, and parents in law, step parents, children, children in law and step children, siblings and brothers and sisters in law and anyone residing in that

 

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person’s home); and (iv) any firm, corporation or other entity in which any person included in clauses (i) through (iii) above is employed as an executive officer, is a director, partner, principal or occupies a similar position or in which that person owns a 5% or more beneficial interest. The policy will define a “related person transaction” as a transaction, arrangement or relationship between us and a related party that is anticipated to exceed $120,000 in any calendar year and provide that each related person transaction must be approved, in advance, by the disinterested members of the board of directors. If approval in advance is not feasible, the related person transaction must be ratified by the disinterested directors. In approving a related person transaction, the disinterested directors will take into account, in addition to such other factors as they deem appropriate, the extent of the related person’s interest in the transaction and whether the transaction is no less favorable to us than terms generally available to an unaffiliated third party under similar circumstances.

The following related person transactions are expected to be pre-approved under the policy: (i) employment of an executive officer to perform services on our behalf (or on behalf of one of our subsidiaries) if (a) the compensation is required to be reported in our annual proxy statement or (b) the executive officer is not an immediate family member of an executive officer, director, director nominee or person known to be a beneficial owner of 5% or more of our common units and such compensation was approved, or recommended to the board of directors for approval by the Compensation Committee; (ii) compensation paid to directors for serving on the board of directors or any committee thereof or reimbursement of expenses in connection with such services, if the compensation is required to be reported in our annual proxy statement; (iii) transactions where the related person’s interest arises solely as a holder of our common units and all holders of our common units received the same benefit on a pro rata basis (e.g., dividends), or transactions available to all employees generally; (iv) a transaction at another company where the related person is only an employee (and not an executive officer), director or beneficial owner of less than 10% of such company’s shares and the aggregate amount involved does not exceed the greater of $1.0 million or 2% of that company’s total annual revenues; and (v) any charitable contribution, grant or endowment by us to a charitable organization, foundation or university at which the related person’s only relationship is an employee (other than an executive officer) or director or similar capacity, if the aggregate amount involved does not exceed the lesser of $200,000 or 2% of the charitable organization’s total annual receipts, expenditures or assets.

 

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CONFLICTS OF INTEREST AND DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, including us and the general partner of our new Development Subsidiary, on the one hand, and ARP or our Development Subsidiary and their respective limited partners, on the other hand. Our directors and officers and the directors and officers of the Development Subsidiary’s general partners have duties to manage ARP and the Development Subsidiary in a manner they believe is beneficial to us, the owner of the general partner interest in each entity. At the same time, these directors and officers have a duty to manage each of ARP and the Development Subsidiary in a manner they believe is beneficial to such partnership. Our board of directors and the board of directors of our Development Subsidiary’s general partner, or ARP’s or our Development Subsidiary’s conflicts committees, will resolve any such conflict and have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

Whenever a conflict arises between us, on the one hand, and any affiliated entities, on the other hand, the board of directors will resolve that conflict. Our limited liability company agreement contains provisions that eliminate any and all fiduciary duties under applicable law and replaces them with contractual standards as set forth therein. Our limited liability company agreement also restricts the remedies available to unitholders for actions taken that, without such elimination of any fiduciary duties, might constitute breaches of fiduciary duty by our directors or officers or their affiliates under applicable law.

It will be presumed that, in making decisions and taking, or declining to take, actions, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any unitholder or the company, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. The existence of all conflicts of interest described in this information statement, including from the transactions described in this information statement, and any actions of our directors and officers taken in connection with such conflicts of interest, will be deemed approved by all of our unitholders pursuant to our limited liability company agreement. Unless the resolution of a conflict is specifically provided for in our limited liability company agreement, our board of directors may consider any factor it determines in good faith to consider when resolving a conflict. When our limited liability company agreement requires someone to act in good faith, it requires that person to believe that he is not acting adversely to the interests of the company.

Conflicts of interest could arise in the situations described below, among others.

Our affiliates and ARP may in certain circumstances compete with us or with each other, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses, which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.

Neither our limited liability company agreement nor the partnership agreement of ARP prohibits ARP or our affiliates from owning assets or engaging in businesses that compete directly or indirectly with us, our affiliates or ARP. In addition, ARP and its affiliates may acquire, develop or dispose of additional assets related to the production and development of oil, natural gas and NGLs or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. As a result, competition among these entities could adversely affect ARP’s or our results of operations and cash available for paying required debt service on our credit facilities or making distributions.

Pursuant to the terms of our limited liability company agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to our directors or executive officers or any of their affiliates. Some of these executive officers and directors also serve as officers of ARP. No such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any unitholder for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues

 

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or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Therefore, ARP and its affiliates may compete with us for investment opportunities and may own an interest in entities that compete with us on an operations basis.

Our limited liability company agreement eliminates our directors’ and officers’ fiduciary duties to holders of our common units and restricts the remedies available to holders of our common units for actions taken by our directors and officers.

Our limited liability company agreement contains provisions that eliminate any fiduciary standards to which our directors, officers and their affiliates could otherwise be held by state fiduciary duty laws. Instead, our directors and officers are accountable to us and our unitholders pursuant to the contractual standards set forth in our limited liability company agreement. Our limited liability company agreement reduces the standards to which our directors and officers would otherwise be held by state fiduciary duty law and contains provisions restricting the remedies available to unitholders for actions taken by our directors, officers or their affiliates. For example, it provides that:

 

•

whenever our board of directors or officers make a determination or take, or decline to take, any other action in such capacity, our directors and officers are required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard (including fiduciary standards) imposed by Delaware law or any other law, rule or regulation or at equity;

 

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our directors and officers will not have any liability to us or our unitholders for decisions made in their capacity as a director or officer so long as they acted in good faith, meaning they believed that the decision was not adverse to our interests;

 

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our directors and officers will not be liable for monetary damages to us or our unitholders for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

 

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in making decisions and taking, or declining to take, actions, the board of directors is presumed to have acted in good faith, and in any proceeding brought by or on behalf of any unitholder or the company, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

No Fiduciary Duties

The Delaware Act provides that Delaware limited liability companies may, in their limited liability company agreements, restrict, expand or eliminate any fiduciary duties owed by directors and officers to members and the company. Our limited liability company agreement has eliminated any default fiduciary standards owed to the company or its members. Instead, our directors and officers are accountable to us and our unitholders pursuant to the contractual standards set forth in our limited liability company agreement, which requires that, when our directors and officers are acting in such capacity, as opposed to in their individual capacity, they must act in “good faith,” meaning that they believed that the decision was not adverse to our interests.

We have adopted these standards to allow affiliates of our directors and officers, including ARP, to engage in transactions with us that could otherwise be prohibited by state law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our board of directors has a duty to manage us in good faith and a duty to manage ARP and our other affiliates in a manner beneficial to the unitholders of ARP and such other subsidiaries. Without these modifications, our directors’ and officers’ ability to make decisions involving conflicts of interest could be restricted. These modifications also enable our directors and officers to take into

 

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consideration all parties involved in the proposed action. Further, these modifications also strengthen our ability to attract and retain experienced and capable directors. However, these modifications disadvantage the common unitholders because they restrict the rights and remedies that would otherwise be available to unitholders for actions that, without such modifications, might constitute breaches of fiduciary duty, as described below, and permit our directors and officers to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of:

 

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the default fiduciary duties under the Delaware Act; and

 

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the standards contained in our limited liability company agreement that replace the default fiduciary duties.

 

State law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a limited liability company agreement providing otherwise, would generally require a manager of a Delaware limited liability company to act for the company in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a limited liability company agreement providing otherwise, would generally prohibit the manager of a Delaware limited liability company from taking any action or engaging in any transaction where a conflict of interest is present.

 

The Delaware Act generally provides that a limited liability company member may institute legal action on behalf of the company to recover damages from a third party where the company (through its managers) has refused to institute the action or where an effort to cause the company to do so is not likely to succeed. These actions include actions against a manager for breach of its fiduciary duties or of the limited liability company agreement. In addition, the statutory or case law of some jurisdictions may permit a member to institute legal action on behalf of itself and all other similarly situated member to recover damages from a manager for violations of its fiduciary duties to the members.

 

Limited liability company agreement modified standards

Our limited liability company agreement has eliminated any default fiduciary standards owed to the company or its members. Instead, our directors and officers are accountable to us and our unitholders pursuant to the contractual standards set forth in our limited liability company agreement, which requires that, when the directors or officers are acting in their capacity as our officers or directors, as opposed to in their individual capacity, they must act in “good faith,” meaning that they believed that the decision was not adverse to our interests. These contractual standards reduce the obligations to which our directors or officers would otherwise be held.

 

In addition to the other more specific provisions limiting the obligations of our directors and officers, our limited liability company agreement further provides that our directors and officers will not be liable for monetary damages to us or our unitholders for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction

 

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determining that such directors or officers acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that such person’s conduct was unlawful.

 

In making decisions or taking, or declining to take, actions, including the resolution of conflicts of interest, it will be presumed that the board of directors acted in good faith, and in any proceeding brought by or on behalf of any unitholder or the company, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our directors and officers would otherwise be held.

 

Our limited liability company agreement generally provides that the existence of all conflicts of interest disclosed in this information statement, and any actions of our directors and officers taken in connection with such conflicts of interest, have been approved by all of our unitholders pursuant to our limited liability company agreement.

By accepting or purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our limited liability company agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of limited liability company agreements. The failure of a unitholder or transferee to sign a limited liability company agreement does not render our limited liability company agreement unenforceable against that person.

Under our limited liability company agreement, we must indemnify our directors, officers, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by such persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We also must provide this indemnification for criminal proceedings unless such persons acted with knowledge that their conduct was unlawful. Thus, such persons could be indemnified for their negligent and grossly negligent acts if they meet the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. See “Our Limited Liability Company Agreement—Indemnification” beginning on page 258.

 

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DESCRIPTION OF OUR COMMON UNITS

Common Units

The common units are a class of limited liability company interests in us. The holders of common units are entitled to participate in company distributions and exercise the rights or privileges available to a holder of common units as outlined in our limited liability company agreement. For a description of the rights and preferences of holders of common units in partnership distributions, see this section and “Cash Distribution Policy.” For a description of the rights and privileges of the holders of our common units under our limited liability company agreement, including voting rights, see “Our Limited Liability Company Agreement.”

Transfer Agent and Registrar

Duties. Broadridge will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units, except for the following that must be paid by unitholders:

 

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surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

 

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special charges for services requested by a common unitholder; and

 

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other similar fees or charges.

There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal. The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of such resignation or removal, we may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our limited liability company agreement, each transferee of common units shall be admitted as a member with respect to the common units transferred when such transfer and admission is reflected in our books and records. Each transferee:

 

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represents that the transferee has the capacity, power and authority to become bound by our limited liability company agreement;

 

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automatically becomes bound by the terms and conditions of, and is deemed to have executed, our limited liability company agreement; and

 

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gives the consents and waivers contained in our limited liability company agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and the distribution.

A transferee will become a member of our company for the transferred common units automatically upon the recording of the transfer on our books and records. Our company will cause any transfers to be recorded on our books and records from time to time as necessary to accurately reflect the transfers.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

 

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Common units are securities and are transferable according to the laws governing transfers of securities.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

 

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OUR LIMITED LIABILITY COMPANY AGREEMENT

The following is a summary of the material provisions of our limited liability company agreement that will be in effect as of the distribution. The form of our limited liability company agreement is attached as Annex A to this information statement. We will provide holders of our common units with a copy of our limited liability company agreement upon request at no charge.

We summarize the following provisions of our limited liability company agreement elsewhere in this information statement:

 

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with regard to distributions of available cash, see “Cash Distribution Policy” beginning on page 76;

 

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with regard to the duties of our board of directors and officers, see “Conflicts of Interest and Duties” beginning on page 243;

 

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with regard to the transfer of common units, see “Description of Our Common Units—Transfer of Common Units” beginning on page 247; and

 

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with regard to allocations of taxable income and taxable loss, see “Certain U.S. Federal Income Tax Matters” beginning on page 260.

Organization and Duration

Our partnership was formed in October 2011 and will have a perpetual existence unless terminated pursuant to the terms of our limited liability company agreement.

Purpose

Our purpose under our limited liability company agreement is to engage in any business activity that lawfully may be conducted by a limited liability company organized under Delaware law; provided, that our company shall not engage in any business activity that the board of directors determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes.

We have agreed in the limited partnership agreement of ARP, however, to certain restrictions on our business activities so long as we are the general partner of ARP. The ARP limited partnership agreement that will be in effect as of the closing of the distribution will provide that, for so long as we are the general partner of ARP, we agree that our sole business will be to act as a general partner of ARP and any other partnership or limited liability company of which ARP is, directly or indirectly, a partner or member and to undertake activities that are ancillary or related thereto. It will also provide that, for so long as we are the general partner of ARP, we will not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (1) our performance as general partner of ARP or its subsidiaries or as described in or contemplated by the Form 10 registration statement filed by ARP, (2) the acquiring, owning or disposing of debt securities or equity interests in ARP or any of its subsidiaries or (3) the guarantee of, and mortgage, pledge, or encumbrance of any or all of its assets in connection with, any indebtedness of any of our affiliates. This restriction shall not apply to any person other than us, and we may hold or dispose any interest that we acquire or obtain from any affiliate or certain other unrestricted Person (as defined in the ARP limited partnership agreement), and perform activities in connection therewith. The ARP limited partnership agreement, and the amendments to such limited partnership agreement that will be in effect prior to the date of the distribution, are filed as exhibits to our registration statement on Form 10, of which this information statement is a part.

Although we and our subsidiaries may engage in activities other than the production of natural gas and oil and making investments in other master limited partnerships, our board of directors has no current plans to do so and may decline to do so free of any duty or obligation whatsoever to us or our unitholders, including any duty to

 

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act in good faith or in the best interests of us or our unitholders. We are authorized in general to perform all acts that may be necessary or appropriate to carry out our purposes and to conduct our business.

Cash Distributions

Our limited liability company agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities. For a description of these cash distribution provisions, please read “Cash Distribution Policy.”

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “Our Limited Liability Company Agreement—Limited Liability” beginning on page 251.

Voting Rights

The following is a summary of the unitholder vote required for the matters specified below.

The holders of a majority of the common units represented in person or by proxy shall constitute a quorum at a meeting of such common unitholders, unless any such action requires approval by holders of a greater percentage of such units in which case the quorum shall be such greater percentage. Our unitholders following the distribution will be entitled to elect the members of our board of directors.

The following is a summary of the vote requirements specified for certain matters under our limited liability company agreement:

 

Election of the directors to our board of directors		Plurality of votes cast by our unitholders. See “Our Limited Liability Company Agreement—Meetings; Voting” beginning on page 256.
Issuance of additional company securities		No approval right, subject to existing NYSE listing rules. See “Our Limited Liability Company Agreement—Issuance of Additional Securities” beginning on page 252.
Amendment of our limited liability company agreement		Certain amendments may be made by our board of directors without the approval of the common unitholders. Other amendments generally require the approval of a majority of our outstanding voting units. See “Our Limited Liability Company Agreement—Amendment of Our Limited Liability Company Agreement” beginning on page 253.
Merger of our company or the sale of all or substantially all of our assets		Majority of our outstanding voting units in certain circumstances. See “Our Limited Liability Company Agreement—Merger, Consolidation, Conversion, Sale or Other Disposition of Our Assets” beginning on page 255.
Dissolution of our company		Majority of our outstanding voting units. See “Our Limited Liability Company Agreement—Termination and Dissolution” beginning on page 256.
Continuation of our company upon dissolution		Majority of our outstanding voting units. See “Our Limited Liability Company Agreement—Termination and Dissolution” beginning on page 256.

 

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Applicable Law; Forum, Venue and Jurisdiction

Our limited liability company agreement is governed by Delaware law. Our limited liability company agreement requires that, unless we (through the approval of our board of directors) consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware shall be the sole and exclusive forum for any claims, suits, actions or proceedings:

 

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arising out of or relating in any way to our limited liability company agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our limited liability company agreement or the duties, obligations or liabilities among unitholders or of unitholders to us, or the rights or powers of, or restrictions on, the unitholders or us);

 

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brought in a derivative manner on our behalf;

 

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asserting a claim of breach of a fiduciary duty owed by any of our directors, officers or other employees to us or the unitholders;

 

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asserting a claim arising pursuant to any provision of the Delaware Act; or

 

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asserting a claim governed by the internal affairs doctrine;

regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. However, if and only if the Court of Chancery of the State of Delaware dismisses any such claims, suits, actions or proceedings for lack of subject matter jurisdiction, such claims, suits, actions or proceedings may be brought in another state or federal court sitting in the State of Delaware. By acquiring or purchasing a common unit, a unitholder is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware in connection with any such claims, suits, actions or proceedings.

Limited Liability

Assuming that a unitholder does not participate in the control of our business within the meaning of the Delaware Act and otherwise acts in conformity with the provisions of our limited liability company agreement, each unitholders’ liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. Under the Delaware Act, a limited liability company cannot make a distribution to a member if, after the distribution, all liabilities of the limited liability company, other than liabilities to members on account of their limited liability company interests and liabilities for which the recourse of creditors is limited to specific property of the company, would exceed the fair value of the assets of the limited liability company. For the purpose of determining the fair value of the assets of a limited liability company, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited liability company only to the extent that the fair value of that property exceeds the nonrecourse liability. Moreover, under the Delaware Act, a limited liability company may also not make a distribution to a member upon the winding up of the limited liability company before liabilities of the limited liability company to creditors have been satisfied by payment or the making of reasonable provision for payment thereof. The Delaware Act provides that a member who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act will be liable to the limited liability company for the amount of the distribution for three years. Under the Delaware Act, an assignee who becomes a member is liable for the obligations of his assignor to make contributions to the company, except such person is not obligated for liabilities unknown to him at the time he became a member and that could not be ascertained from our limited liability company agreement.

We and ARP currently conduct business in Arkansas, Colorado, Indiana, Michigan, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas and West Virginia. Limitations on the liability of

 

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members for the obligations of a limited liability company have not been clearly established in many jurisdictions. We will operate in a manner that we consider reasonable and necessary or appropriate to preserve the limited liability of the unitholders.

Issuance of Additional Securities

Our limited liability company agreement authorizes us to issue an unlimited number of additional company securities for the consideration and on the terms and conditions determined by our board of directors without the approval of our unitholders subject to certain limitations under existing NYSE listing rules.

It is possible that we will fund acquisitions through the issuance of additional common units or other company securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other company securities may dilute the value of the interests of the then-existing holders of common units in our net assets. The holders of common units will not have preemptive rights to acquire additional common units or other company securities.

In accordance with Delaware law and the provisions of our limited liability company agreement, we may also issue additional company securities that, as determined by our board of directors, may have special voting rights to which the common units are not entitled. In addition, our limited liability company agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to our common units.

Election of Members of the Board of Directors

Our limited liability company agreement provides that the board of directors will be divided into three classes. Upon completion of the distribution, the board of directors will be divided into three classes, comprised of three, three and two directors, respectively. The directors designated as Class I directors will have terms expiring at the first annual meeting of unitholders following the distribution, which we expect will be held in 2016. The directors designated as Class II directors will have terms expiring at the following year’s annual meeting of unitholders, which we expect will be held in 2017, and the directors designated as Class III directors will have terms expiring at the following year’s annual meeting of unitholders, which we expect will be held in 2018. Commencing with the first annual meeting of unitholders following the separation, directors for each class will be elected at the annual meeting of unitholders held in the year in which the term for that class expires and thereafter will serve for a term of three years. At any meeting of unitholders for the election of directors at which a quorum is present, the election will be determined by a plurality of the votes cast by the unitholders entitled to vote in the election. A properly submitted proxy to “Withhold Authority” with respect to the election of one or more directors will not be voted with respect to the director or directors indicated, although it will be counted for purposes of determining whether there is a quorum.

Removal of Members of the Board of Directors

Directors may be removed only for cause and only upon a vote of the remaining directors then in office.

Anti-Takeover Effects of Various Provisions of Our Limited Liability Company Agreement

Provisions of our limited liability company agreement could make it more difficult to acquire us by means of a tender offer, a proxy contest or otherwise, or to remove incumbent officers and directors. These provisions, summarized below, are expected to discourage certain types of coercive takeover practices and takeover bids that our board of directors may consider inadequate and to encourage persons seeking to acquire control of us to first negotiate with the board of directors. We believe that the benefits of increased protection of our ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging takeover or acquisition proposals because, among other things, negotiation of these proposals could result in an improvement of their terms.

 

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Classified Board. Our limited liability company agreement provides that the board of directors will be divided into three classes. Under the classified board provisions, it would take at least two elections of directors for any individual or group to gain control of our board. Accordingly, these provisions could discourage a third party from initiating a proxy contest, making a tender offer or otherwise attempting to gain control of us.

Removal of Directors. Our limited liability company agreement provides that directors may be removed only for cause and only upon a vote of the remaining directors then in office.

Amendments to Limited Liability Company Agreement. Our limited liability company agreement will provide that the affirmative vote of the holders of at least 80% of the outstanding units is required to amend provisions relating to the number, term and removal of our directors, the filling of board vacancies, the conduct of annual meetings of unitholders, calling of special meetings of unitholders, advance notice of unitholder proposals and unitholder action by written consent.

Size of Board and Vacancies. Our limited liability company agreement provides that the number of directors on the board of directors will be fixed exclusively by the board of directors. Any vacancies created in the board of directors resulting from any increase in the authorized number of directors or the death, resignation, retirement, disqualification, removal from office or other cause will be filled by a majority of the board of directors then in office. Any director appointed to fill a vacancy on the board of directors will be appointed for a term expiring at the next election of the class for which such director has been appointed, and until his or her successor has been elected and qualified.

Special Unitholder Meetings. Our limited liability company agreement provides that only our board of directors may call special meetings of unitholders.

Unitholder Action by Written Consent. Our limited liability company agreement expressly provides that our unitholders may act by written consent only when authorized to do so by the board of directors. If action by written consent is not specifically authorized by our board of directors, unitholder action must take place at the annual meeting or a special meeting of unitholders.

Requirements for Advance Notification of Unitholder Nominations and Proposals. Our limited liability company agreement establishes advance notice procedures with respect to unitholder proposals and nomination of candidates for election as directors other than nominations made by or at the direction of the board of directors or a committee of the board of directors.

No Cumulative Voting. Our limited liability company agreement does not give unitholders the right to cumulate votes in the election of directors.

Issuances of Additional Securities. The authority that our board of directors possesses to issue an unlimited number of additional company securities (subject to certain limitations under existing NYSE listing rules) could potentially be used to discourage attempts by third parties to obtain control of our company through a merger, tender offer, proxy contest or otherwise by making such attempts more difficult or more costly. Our board of directors may be able to issue partnership securities with voting rights or conversion rights that, if exercised, could adversely affect the voting power of the holders of our common units.

Amendment of Our Limited Liability Company Agreement

General. Amendments to our limited liability company agreement may be proposed only by our board of directors. However, our board of directors will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or our unitholders, including any duty to act in good faith or in the best interests of us or our unitholders. To adopt a proposed amendment, other than the amendments discussed under “Our Limited Liability Company Agreement—Amendment of Our Limited Liability Company Agreement—No Unitholder Approval” beginning on page 254, our board of directors is

 

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required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the unitholders to consider and vote upon the proposed amendment.

Prohibited Amendments. No amendment may be made that would enlarge the obligations of any unitholder without its consent, unless approved by at least a majority of the type or class of limited liability company interests so affected.

The provision of our limited liability company agreement preventing the amendments having the effects described above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class.

No Unitholder Approval. Our board of directors may generally make amendments to our limited liability company agreement without the approval of any unitholder to reflect:

 

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a change in our name, the location of our principal place of business, our registered agent or registered office;

 

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the admission, substitution, withdrawal or removal of members in accordance with our limited liability company agreement;

 

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a change that our board of directors determines to be necessary or appropriate for us to qualify us or continue our qualification as a limited liability company or other entity in which the unitholders have limited liability under the laws of any state or to ensure that we will not be taxed as a corporation or otherwise taxed as an entity for U.S. federal income tax purposes;

 

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a change in our fiscal year or taxable year and related changes;

 

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an amendment that is necessary, in the opinion of our counsel, to prevent us or our directors, officers, agents or trustees from in any manner being subject to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or “ERISA,” whether or not substantially similar to plan asset regulations currently applied or proposed;

 

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an amendment that our board of directors determines to be necessary or appropriate for the authorization or issuance of additional company partnership securities or options, warrants, rights or appreciation rights relating to any company securities;

 

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an amendment expressly permitted in our limited liability company agreement to be made by our board of directors acting alone;

 

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any amendment effected, necessitated or contemplated by a merger agreement or plan of conversion that has been approved under the terms of our limited liability company agreement;

 

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any amendment that our board of directors determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our limited liability company agreement;

 

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any amendment effected, necessitated or contemplated by any amendment to the limited partnership or limited liability company agreement of any of our subsidiaries that requires the equityholders of such subsidiary to provide a statement, certification or other evidence to the subsidiary regarding whether such equityholder is subject to U.S. federal income taxation on the income generated by such subsidiary or regarding such equityholders’ nationality or citizenship;

 

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conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance;

 

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•

any amendment necessary to require our unitholders to provide a statement, certification or other evidence to us regarding whether such unitholder is subject to U.S. federal income taxation on the income generated by us or regarding such unitholder’s nationality or citizenship and to provide for the ability of our board of directors to redeem the units of any unitholder who fails to provide such statement, certification or other evidence; and

 

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any other amendment substantially similar to any of the matters described above.

In addition, our board of directors may amend our limited liability company agreement, without the approval of the unitholders, if our board determines that those amendments:

 

•

do not adversely affect the unitholders in any material respect;

 

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are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

 

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are necessary or appropriate to facilitate the trading of limited liability company interests or to comply with any rule, regulation, guideline or requirement of any securities exchange or interdealer quotation system on which the limited liability company interests are or will be listed for trading;

 

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are necessary or appropriate for any action taken by our board of directors relating to splits or combinations of units or to implement the tax-related provisions of our limited liability company agreement; or

 

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are required to effect the intent expressed in this information statement or the intent of the provisions of our limited liability company agreement or are otherwise contemplated by our limited liability company agreement.

Unitholder Approval. For amendments of the type not requiring unitholder approval, our board of directors will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to our unitholders or result in our being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes. No other amendments to our limited liability company agreement will become effective without the approval of holders of at least 90% of the outstanding common units if our board of directors determines that such amendment will affect the limited liability of any unitholder under Delaware law.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Except as provided under “Our Limited Liability Company Agreement—Anti-Takeover Effects of Various Provisions of Our Limited Liability Company Agreement” or to change the vote required to approve an amendment to our limited liability company agreement, any other amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of unitholders whose aggregate outstanding common units constitute not less than the voting requirement sought to be reduced. Any amendment that would change the vote required to approve an amendment to our limited liability company agreement must be approved by holders of at least 90% of the outstanding common units.

Merger, Consolidation, Conversion, Sale or Other Disposition of Our Assets

A merger, consolidation or conversion of us requires the prior approval of our board of directors. However, our board of directors will have no duty or obligation to approve any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the unitholders, including any duty to act in good faith or any other standard imposed by our limited liability company agreement, the Delaware Act or applicable law.

 

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In addition, our limited liability company agreement generally prohibits our board of directors, without the prior approval by a majority of our outstanding voting units, from causing us to sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions. Our board of directors may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without the approval of a majority of our outstanding voting units. Our board of directors may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our board of directors may consummate any merger, consolidation or conversion without the prior approval of our unitholders if we are the surviving entity in the transaction, our board of directors has received an opinion of counsel regarding limited liability and tax matters, the transaction will not result in an amendment to our limited liability company agreement (other than an amendment that the board of directors could adopt without the consent of the unitholders), each of our units will be an identical unit of our company following the transaction and the number of company securities to be issued does not exceed 20% of our outstanding company securities immediately prior to the transaction.

If the conditions specified in our limited liability company agreement are satisfied, our board of directors may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity if the purpose of that conversion, merger or conveyance is to effect a change in our legal form into another limited liability entity, our board of directors has received an opinion of counsel regarding limited liability and tax matters and our board of directors determines that the governing instruments of the new entity provide the unitholders with substantially the same rights and obligations as contained in our limited liability company agreement. The unitholders are not entitled to dissenters’ rights of appraisal under our limited liability company agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited liability company until dissolved under our limited liability company agreement. We will dissolve upon:

 

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the election of our board of directors to dissolve us, if approved by a majority of our outstanding voting units; or

 

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the entry of a decree of judicial dissolution of our company.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited liability company, the liquidator authorized to wind up our affairs will, acting with all of the powers of our board of directors that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “Cash Distribution Policy.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our members.

Meetings; Voting

Unitholders who are record holders of common units on a record date will be entitled to notice of, and to vote at, meetings of our unitholders and to act upon matters for which approvals may be solicited. Our limited liability company agreement provides that an annual meeting of the unitholders for the election of directors to the board of directors and other matters that the board of directors submits to a vote of the unitholders will be held at such date and time as may be fixed from time to time by our board of directors. At each annual meeting, the unitholders entitled to vote will vote as a single class for the election of directors to the board, and will elect, by a plurality of the votes cast at such meeting, persons to serve on the board of directors who are nominated in accordance with the provisions of our limited liability company agreement.

 

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Any action that is required or permitted to be taken by the common unitholders must be taken at a meeting of the common unitholders, unless our board of directors specifically authorizes action by written consent. If so authorized, action may be taken without a meeting if consents in writing describing the action so taken are signed by holders of the number of common units necessary to authorize or take that action at a meeting. Meetings of the common unitholders may be called only by our board of directors. Unitholders may not call special unitholder meetings. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding common units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the common units, in which case the quorum will be the greater percentage.

Each record holder will have a vote in accordance with its percentage interest, although additional limited liability company interests having different voting rights could be issued. See “Our Limited Liability Company Agreement—Issuance of Additional Securities” beginning on page 252. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner.

Any notice, demand, request report, or proxy material required or permitted to be given or made to record holders of common units under our limited liability company agreement will be delivered to the record holder by us or by the transfer agent.

Status as Member

By transfer of any common units in accordance with our limited liability company agreement, each transferee of common units shall be admitted as a member with respect to the common units transferred when such transfer and admission is reflected in our books and records. Except as described above under “Our Limited Liability Company Agreement—Limited Liability” beginning on page 251, the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Citizen Assignees; Redemption

If we or any of our subsidiaries are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our board of directors, create a substantial risk of cancellation or forfeiture of any property that we or such subsidiary have an interest in because of the nationality, citizenship or other related status of any unitholder, we may redeem the units held by the unitholder at their current market price. In order to avoid any cancellation or forfeiture, our board of directors may require any unitholder or transferee to furnish information about his nationality, citizenship or related status. If a unitholder fails to furnish this information within 30 days after a request for the information, or our board of directors determines after receipt of the information that the unitholder is not an eligible citizen, then the unitholder may be treated as a non-citizen assignee. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

In addition, in such circumstance, we will have the right to acquire all (but not less than all) of the units held by such unitholder or non-citizen assignee. The purchase price for such units will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for such purchase, and such purchase price will be paid (in the sole discretion of our board of directors) either in cash or by delivery of a promissory note. Any such promissory note will bear interest at the rate of 5% annually and will be payable in three equal annual installments of principal and accrued interest, commencing one year after the purchase date.

Non-Taxpaying Holders; Redemption

If our board of directors, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our unitholders, has, or is reasonably likely to have, a

 

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material adverse effect on the maximum applicable rate that can be charged to customers by our subsidiaries, then our board of directors may adopt such amendments to our limited liability company agreement as it determines necessary or advisable to:

 

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obtain proof of the U.S. federal income tax status of our unitholders (and their owners, to the extent relevant); and

 

•

permit us to redeem the units at their current market price held by any person whose tax status has or is reasonably likely to have a material adverse effect on our ability to operate our assets or generate revenues from such assets or who fails to comply with the procedures instituted by our board of directors to obtain proof of the U.S. federal income tax status.

A non-taxpaying assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

Indemnification

Under our limited liability company agreement, in most circumstances, we will indemnify the following persons, by reason of their status as such, to the fullest extent permitted by law, from and against all losses, claims or damages arising out of or incurred in connection with our business:

 

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any person who is or was a member, partner, officer, tax matters partner, employee, agent, director, fiduciary or trustee of our company or our subsidiaries, or any affiliate of our company or our subsidiaries;

 

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any person who is or was serving at the request of our company or our board of directors as an officer, director, tax matters partner, employee, member, partner, agent, fiduciary or trustee of another person; and

 

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any person whom the board of directors designates as an indemnitee for purposes of our limited liability company agreement.

Our indemnification obligation arises only if the indemnified person did not act in bad faith or engage in fraud, willful misconduct or, in the case of a criminal matter, knowledge of the indemnified person’s unlawful conduct.

Any indemnification under these provisions will be only out of our assets. Our limited liability company agreement permits us to purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our limited liability company agreement.

Books and Reports

We are required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For financial and tax reporting purposes, our fiscal year end is December 31.

We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent registered public accounting firm. Except for our fourth quarter, we also furnish or make available summary financial information within 90 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website that we maintain.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this

 

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summary information to our unitholders will depend on the cooperation of our unitholders in supplying us with specific information. Every unitholder will receive information to assist it in determining its federal and state tax liability and filing its federal and state income tax returns, regardless of whether it supplies us with information.

Right to Inspect Our Books and Records

Our limited liability company agreement provides that a unitholder can, for a purpose reasonably related to its interest as a unitholder, upon reasonable written demand stating the purpose of such demand and at his own expense, obtain:

 

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a current list of the name and last known address of each unitholder;

 

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a copy of our tax returns;

 

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information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each unitholder and the date on which each became a unitholder;

 

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copies of our limited liability company agreement, the certificate of formation and related amendments and powers of attorney under which they have been executed; and

 

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information regarding the status of our business and financial condition.

We may, and intend to, keep confidential from our unitholders trade secrets or other information the disclosure of which we believe is not in our best interests or which we are required by law or by agreements with third parties to keep confidential.

 

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CERTAIN U.S. FEDERAL INCOME TAX MATTERS

Overview

The following is a summary of certain U.S. federal income tax consequences to U.S. holders (as defined below) relating to the distribution of our common units by Atlas Energy and the ownership and disposition of our common units. This summary is based on the Internal Revenue Code of 1986, as amended, or the “Code,” the U.S. Treasury regulations promulgated thereunder, and interpretations of the Code and the U.S. Treasury regulations by the courts and the Internal Revenue Service, or “IRS,” in effect as of the date hereof, all of which are subject to change, possibly with retroactive effect. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to New Atlas.

This summary addresses the material U.S. federal income tax consequences only to an individual citizen or resident of the United States who is a beneficial owner for U.S. federal income tax purposes of (i) our common units and (ii) solely with respect to the discussion under the heading “Certain U.S. Federal Income Tax Matters—Tax Consequences of the Distribution of Our Common Units by Atlas Energy,” common units of Atlas Energy (a “U.S. holder”). In addition, this summary is limited to U.S. holders who receive our common units in the distribution in their capacity as partners of Atlas Energy, and who hold such units and their common units of Atlas Energy as a capital asset for U.S. federal income tax purposes. In addition, this summary does not discuss all the tax considerations that may be relevant to unitholders in light of their particular circumstances, nor does it address the consequences to unitholders subject to special treatment under the U.S. federal income tax laws (including, for example, unitholders other than U.S. holders, insurance companies, dealers or brokers in securities or currencies, tax-exempt organizations, banks, financial institutions, mutual funds, real estate investment trusts, individual retirement accounts, pass-through entities and investors in such entities, unitholders who have a functional currency other than the U.S. dollar, unitholders who hold their units as a hedge or as part of a hedging, straddle, conversion, synthetic security, integrated investment or other risk-reduction transaction, unitholders who are subject to alternative minimum tax, unitholders who acquired their units as compensation or otherwise in connection with compensation arrangements, unitholders who hold (directly, indirectly or constructively) units representing 5% or more of our capital or profit or the capital or profit of Atlas Energy, or unitholders who acquired their units of Atlas Energy in exchange for a contribution of property described in Section 704(c) of the Code).

Furthermore, this summary does not address any U.S. federal taxes other than U.S. federal income tax, and does not discuss any state, local or foreign tax consequences. Nor does this summary discuss any tax consequences of the Medicare tax on certain investment income pursuant to the recently enacted Health Care and Education Reconciliation Act of 2010. Each unitholder is urged to consult its tax advisor regarding the U.S. federal, state, local and foreign tax considerations of the distribution and the ownership and disposition of our common units.

No ruling has been or will be requested from the IRS regarding any matter affecting us or unitholders. Accordingly, the U.S. federal income tax consequences described in this summary may be contested by the IRS and sustained by a court. Any contest of this sort with the IRS may materially and adversely affect the market for our common units and the prices at which our common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders. Furthermore, the tax treatment of the distribution, our operations, and an investment in us may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

This summary of U.S. federal income tax consequences is for general information purposes. This summary does not purport to address all U.S. federal income tax consequences that may be relevant to unitholders in light of their particular circumstances, nor does it address any state, local or foreign tax

 

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consequences. Unitholders are urged to consult their own advisors concerning the U.S. federal, state, local and foreign tax consequences to them of the distribution and of the ownership and disposition of our common units.

Partnership Status

In general, a partnership is a pass-through entity and incurs no U.S. federal income tax liability. Instead, each partner of a partnership is required to take into account such partner’s share of items of income, gain, loss and deduction of the partnership in computing such partner’s U.S. federal income tax liability, regardless of whether cash distributions are made to such partner by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner’s adjusted basis in such partner’s partnership interest.

Section 7704 of the Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations for U.S. federal income tax purposes. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage, processing and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income.

Based on estimates of our current gross income, we believe that at least 90% of such income constitutes qualifying income, and thus, we believe that we will be classified as a partnership for U.S. federal income tax purposes under the Qualifying Income Exception to Section 7704 of the Code. Similarly, based on estimates of the current gross income of Atlas Energy, we and Atlas Energy believe that at least 90% of such income of Atlas Energy constitutes qualifying income, and thus, we and Atlas Energy believe that Atlas Energy will be classified as a partnership for U.S. federal income tax purposes on the date of the distribution under the Qualifying Income Exception to Section 7704 of the Code. In addition, Atlas Energy files U.S. federal income tax returns on the basis that it should be classified as a partnership for U.S. federal income tax purposes. However, the portion of our or Atlas Energy’s income that is qualifying income may change from time to time, and no assurance can be given that at least 90% of our or Atlas Energy’s current or future gross income will constitute qualifying income.

No ruling has been or will be sought from the IRS, nor has the IRS made any determination as to our or Atlas Energy’s status for U.S. federal income tax purposes or whether our or Atlas Energy’s operations generate qualifying income under Section 7704 of the Code. The IRS could assert that we or Atlas Energy should be treated as a corporation for U.S. federal income tax purposes, either as a result of a failure to meet the Qualifying Income Exception or otherwise. If we or Atlas Energy fail to meet the Qualifying Income Exception under Section 7704 of the Code, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we or Atlas Energy, as applicable, will be treated as if we or Atlas Energy, as applicable, had transferred all of our assets or Atlas Energy’s assets, as applicable, subject to liabilities, to a newly formed corporation on the first day of the year in which we or Atlas Energy, as applicable, fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us or Atlas Energy, as applicable. This contribution and liquidation should be tax-free to unitholders and us or Atlas Energy, as applicable, so long as we or Atlas Energy, as applicable, at that time, do not have liabilities in excess of the tax basis of our assets or Atlas Energy’s assets, as applicable. Thereafter, we or Atlas Energy, as applicable, would be treated as a corporation for U.S. federal income tax purposes.

If Atlas Energy were taxable as a corporation for U.S. federal income tax purposes on the date of the distribution, either as a result of a failure to meet the Qualifying Income Exception or otherwise, materially adverse consequences could result to Atlas Energy and unitholders of Atlas Energy who receive our common units in the distribution. If Atlas Energy were taxable as a corporation for U.S. federal income tax purposes on

 

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the date of the distribution, Atlas Energy would be subject to tax on gain, if any, that it would have recognized if it had sold the common units received by unitholders of Atlas Energy in the distribution in a taxable sale for their fair market value. In addition, in such case, each unitholder of Atlas Energy who receives our common units in the distribution would be treated as if the unitholder had received a distribution equal to the fair market value of our common units that were distributed to the unitholder, which generally would be treated as either taxable dividend income to the unitholder, to the extent of Atlas Energy’s current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in such unitholder’s units of Atlas Energy, or taxable capital gain, after the unitholder’s tax basis in such unitholder’s units of Atlas Energy is reduced to zero. Accordingly, taxation of Atlas Energy as a corporation on the date of the distribution could result in materially adverse tax consequences to Atlas Energy and unitholders of Atlas Energy who receive our common units in the distribution.

If we were taxable as a corporation for U.S. federal income tax purposes in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, the unitholders will be subject to special tax rules and materially adverse consequences could result to unitholders and us. If we were a taxable corporation for U.S. federal income tax purposes, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates, currently at a maximum rate of 35%. In addition, in such case, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in such unitholders’ common units in us, or taxable capital gain, after the unitholder’s tax basis in such unitholder’s common units in us is reduced to zero. Accordingly, taxation of us as a corporation could result in materially adverse tax consequences, as well as a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of our units.

The discussion below assumes that we and Atlas Energy will each be classified as a partnership for U.S. federal income tax purposes.

Tax Consequences of the Distribution of Our Common Units by Atlas Energy

Recognition of Gain

While not free from doubt due to the absence of controlling legal authority, we believe that the distribution of our common units by Atlas Energy to a U.S. holder of common units of Atlas Energy generally should not be taxable to such U.S. holder for U.S. federal income tax purposes, except to the extent that the aggregate amount of money distributed (including cash received in lieu of fractional units) or deemed distributed to such U.S. holder (as discussed below) exceeds such U.S. holder’s tax basis in such U.S. holder’s common units of Atlas Energy immediately before the distribution. In general, any money distributed or deemed distributed (as described below) to such U.S. holder in excess of such U.S. holder’s tax basis should be considered to be gain from the sale or exchange of such U.S. holder’s common units of Atlas Energy, taxable in accordance with the rules described below under “Certain U.S. Federal Income Tax Matters—Tax Consequences of Disposition of Our Common Units.” No loss shall be recognized for U.S. federal income tax purposes by a U.S. holder on such distribution.

For purposes of determining whether gain is recognized by a U.S. holder on such distribution of our common units, the distribution of a “marketable security” generally is treated as a distribution of money equal to the fair market value of such marketable security on the date of the distribution. In general, a “marketable security” includes a financial instrument (including stock or other equity interest) which is, as of the date of the distribution, “actively traded” for U.S. federal income tax purposes. The amount treated as money upon a distribution of a “marketable security” is reduced (but not below zero) by the excess, if any, of the distributee U.S. holder’s proportionate share of (i) net gain, if any, that would be recognized if all of Atlas Energy’s marketable securities would have been sold immediately before the distribution by Atlas Energy for fair market value, over (ii) net gain, if any, that would be recognized if all of Atlas Energy’s marketable securities would

 

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have been sold immediately after the distribution by Atlas Energy for that same fair market value, in each case with certain adjustments pursuant to U.S. Treasury Regulations (including taking into account the U.S. holder’s basis adjustment in such marketable securities by reason of an election under Section 754 of the Code). Because we have been authorized to list our common units on the NYSE, subject to official notice of distribution, we and Atlas Energy believe and intend to take the position that our common units distributed by Atlas Energy in the distribution are “actively traded” on the date of the distribution and thus qualify as “marketable securities.” Therefore, subject to the reduction described above, we believe our common units distributed by Atlas Energy should be treated as money for purposes of determining whether the U.S. holder recognizes gain for U.S. federal income tax purposes on the distribution of our common units by Atlas Energy in the distribution.

Any reduction in the U.S. holder’s share of liabilities of Atlas Energy for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” generally will be treated as a deemed distribution of money to such U.S. holder for U.S. federal income tax purposes. For purposes of determining a U.S. holder’s share of liabilities of Atlas Energy, U.S. Treasury regulations provide that an upper-tier partnership’s share of the liabilities of a lower-tier partnership (other than any liability of the lower-tier partnership that is owed to the upper-tier partnership) generally should be treated as a liability of the upper-tier partnership. Furthermore, U.S. Treasury Regulations provide that if, as a result of a single transaction, a partner incurs both an increase in the partner’s share of the partnership liabilities and a decrease in the partner’s share of the partnership liabilities, only the net decrease is treated as a distribution from the partnership and only the net increase is treated as a contribution of money to the partnership. While not free from doubt due to the absence of controlling legal authority, we believe that under these U.S. Treasury regulations the increase and decrease, if any, in the U.S. holder’s liabilities of Atlas Energy and us solely by reason of the pro rata distribution by Atlas Energy of our common units in the distribution should be netted to equal zero so that there will be no deemed contribution or distribution of money by a U.S. holder with respect to such increase or decrease of liabilities solely by reason of the distribution.

To the extent the distribution causes the “at risk” amount of a U.S. holder of common units in Atlas Energy to be less than zero at the end of any taxable year, such U.S. holder must recapture any losses deducted in previous years. Unitholders are urged to consult their own tax advisors with respect to the “at risk” rules in their particular circumstances and read the summary under the heading entitled “Certain U.S. Federal Income Tax Matters—Tax Consequences of Ownership of Our Common Units—Limitations on Deductibility of Losses.”

Atlas Energy expects to provide unitholders with information regarding the amount deemed to be treated as money upon the distribution of our common units.

Basis and Holding Period

A U.S. holder’s initial basis in our common units received by such U.S. holder in the distribution generally will be equal to Atlas Energy’s adjusted basis in such common units immediately before the distribution. However, such U.S. holder’s initial basis in such common units shall not exceed the adjusted basis of such U.S. holder’s interest in Atlas Energy common units, reduced by any money distributed in the same transaction. In addition, such U.S. holder’s initial basis in such common units shall be increased by the amount of any gain such U.S. holder recognizes on the distribution of “marketable securities” as described above. Furthermore, if such U.S. holder acquired any part of such U.S. holder’s interest in Atlas Energy in a transfer as to which an election under Section 754 of the Code was in effect, then Atlas Energy’s adjusted basis in our common units distributed to such U.S. holder generally should take into account such U.S. holder’s special basis adjustment, if any, in such common units.

A U.S. holder’s adjusted basis in such U.S. holder’s interest in Atlas Energy generally will be reduced (but not below zero) by the amount of money distributed by Atlas Energy to such U.S. holder and such U.S. holder’s initial basis in our common units distributed by Atlas Energy to such U.S. holder in the distribution, determined as if no gain were recognized by the U.S. holder as a result of our common units being treated as “marketable securities” as described above.

 

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A U.S. holder’s holding period for our common units distributed by Atlas Energy to such U.S. holder in the distribution generally will include Atlas Energy’s holding period for those common units.

Atlas Energy expects to provide unitholders with information regarding its adjusted basis and holding period in our common units distributed by Atlas Energy to its unitholders in the distribution.

The rules governing the U.S. federal income tax consequences of the distribution of our common units by Atlas Energy in the distribution are complex. Unitholders are urged to consult their own tax advisors regarding the application of these rules and the U.S. federal income tax consequences of the distribution to them in their particular circumstances.

Tax Consequences of Ownership of Our Common Units

Partner Status for U.S. Federal Income Tax Purposes

Unitholders who have been admitted as members of New Atlas will be treated as partners of New Atlas for U.S. federal income tax purposes. Also, assignees who have executed and delivered transfer applications, and are awaiting admission as members, and unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of us for U.S. federal income tax purposes.

There is no direct authority addressing assignees of units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications. Furthermore, a purchaser or other transferee of units who does not execute and deliver a transfer application may not receive some U.S. federal income tax information or reports furnished to record holders of units unless the units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those units. In addition, a beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes, as discussed further under the section entitled “Certain U.S. Federal Income Tax Matters—Tax Consequences of Ownership of Our Common Units—Treatment of Short Sales”.

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for U.S. federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for U.S. federal income tax purposes would therefore appear to be fully taxable as ordinary income. Unitholders are urged to consult their own tax advisors with respect to their status as partners in us for U.S. federal income tax purposes.

This summary assumes that holders of our common units are partners for U.S. federal income tax consequences. Further, the references to “unitholder” and “U.S. holder” in this summary are to persons who are treated as partners for U.S. federal income tax purposes.

Flow-Through of Taxable Income

In general, we are a pass-through entity and will incur no U.S. federal income tax liability. Instead, each unitholder will be required to take into account and report on such unitholder’s income tax return such unitholder’s share of our items of income, gain, loss and deduction in computing such unitholder’s U.S. federal income tax liability, regardless of whether we make corresponding cash distributions to such unitholder. Consequently, we may allocate income to a unitholder even if such unitholder has not received a cash distribution. Each unitholder will be required to include in income such unitholder’s allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

 

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Distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder for U.S. federal income tax purposes, except to the extent that any money (and certain “marketable securities”) distributed by us to such unitholder exceeds such unitholder’s adjusted basis in our common units immediately before the distribution. Our distributions of money in excess of a unitholder’s adjusted basis generally will be considered to be gain from the sale or exchange of our common units, taxable in accordance with the rules described under “Certain U.S. Federal Income Tax Matters—Tax Consequences of Disposition of Our Common Units”. Any reduction in a unitholder’s share of our liabilities for which no unitholder bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, such unitholder must recapture any losses deducted in previous years. See “Certain U.S. Federal Income Tax Matters—Tax Consequences of Ownership of Our Common Units—Limitations on Deductibility of Losses”.

A decrease in a unitholder’s percentage interest in New Atlas because of our issuance of additional common units will decrease such unitholder’s share of our “non-recourse liabilities,” and thus will result in a corresponding deemed distribution of money. A non-pro rata distribution of money or other property may result in ordinary income to a unitholder, regardless of such unitholder’s adjusted basis in our common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in the Code, and collectively, “Section 751 Assets.” To that extent, the unitholder generally will be treated as having distributed such unitholder’s proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s adjusted basis for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

We estimate that a U.S. Holder who receives our common units in the distribution and holds such common units from the distribution date through the record date for distributions for the period ending December 31, 2015, will be allocated an amount of U.S. federal taxable income for that period that will be 20% or less of the cash distributed with respect to that period. We anticipate that after the taxable year ending December 31, 2015, the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution of on all units and other assumptions with respect to capital expenditures, cash flow and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual ratio of taxable income could be higher or lower than our estimate, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a unitholder who receives our common units in the distribution will be greater than 20% with respect to the period described above if:

 

•

gross income from operations exceeds the amount required to make the minimum quarterly distribution on all units, yet we only distribute the minimum quarterly distribution on all its units; or

 

•

we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this distribution or to acquire property that is not eligible for depreciation or amortization for U.S. federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this distribution.

 

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Basis of Our Common Units

A unitholder’s initial adjusted basis for our common units received in the distribution by Atlas Energy generally will be determined as described under the heading “Certain U.S. Federal Income Tax Matters—Tax Consequences of the Distribution of Our Common Units by Atlas Energy—Basis and Holding Period”. That basis will be (i) increased by such unitholder’s share of our income and by any increases in such unitholder’s share of our nonrecourse liabilities, and (ii) decreased, but not below zero, by distributions from us, by such unitholder’s share of our losses, by any decreases in such unitholder’s share of our nonrecourse liabilities and by such unitholder’s share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have a share, generally based on such unitholder’s share of profits, of our nonrecourse liabilities. Please read “Certain U.S. Federal Income Tax Matters—Tax Consequences of Disposition of Our Common Units—Recognition of Gain or Loss”.

Limitations on Deductibility of Losses

The deduction by a unitholder of such unitholder’s share of our losses will be limited to such unitholder’s adjusted basis in our common units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than such unitholder’s adjusted basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause such unitholder’s “at risk” amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that such unitholder’s adjusted basis or “at risk” amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a common unit by such unitholder, any gain recognized by the unitholder can be offset by losses that were previously suspended by the “at risk” limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the “at risk” or basis limitations is no longer utilizable.

In general, a unitholder will be “at risk” to the extent of the unitholder’s adjusted basis in our common units, excluding any portion of that basis attributable to the unitholder’s share of our nonrecourse liabilities, reduced by any amount of money the unitholder borrows to acquire or hold the unitholder’s common units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the common units for repayment. A unitholder’s “at risk” amount will increase or decrease as the unitholder’s adjusted basis of our common units increases or decreases, other than basis increases or decreases attributable to increases or decreases in such unitholder’s share of our nonrecourse liabilities.

In addition to the basis and the “at risk” limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely held corporations and personal service corporations can deduct losses from passive activities, which are generally corporate or partnership activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. As a general rule, the passive loss limitations are applied separately with respect to each publicly traded partnership. However, the application of the passive loss limitations to tiered publicly traded partnerships is uncertain. We will take the position that any passive losses we generate that are reasonably allocable to our investment in other partnerships will only be available to offset our passive income generated in the future that is reasonably allocable to our investment in those other partnerships and will not be available to offset income from other passive activities or investments, including other investments in private businesses or investments we may make in other publicly traded partnerships. Moreover, because the passive loss limitations are applied separately with respect to each publicly traded partnership, any passive losses we generate will not be available to offset a unitholder’s income from other passive activities or investments, including the unitholder’s investments in other publicly traded partnerships or salary or active business income. Further, a unitholder’s share of our net income may be offset by any suspended passive losses from the unitholder’s investment in us, but may not be offset by our current or carryover losses from other passive activities, including those attributable to other publicly traded

 

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partnerships. Passive losses that are not deductible because they exceed a unitholder’s share of income generate may be deducted in full when the unitholder’s disposes of the unitholder’s entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss limitations are applied after other applicable limitations on deductions, including the “at risk” rules and the basis limitation.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

 

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interest on indebtedness properly allocable to property held for investment;

 

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our interest expense attributed to portfolio income; and

 

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the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections

If we are required or elect under applicable law to pay any U.S. federal, state, or local or foreign income tax on behalf of any unitholder or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend the limited liability company agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the limited liability company agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual partner, in which event the partner would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated to the unitholders in accordance with their percentage interests in us. If we have a net loss for the entire year, that loss will be allocated to the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts.

Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of our assets at the time of any future offerings of our common stock or certain other transactions, referred to in this discussion as “Contributed Property.” The effect of these allocations, referred to as “Section 704(c) Allocations,” acquiring our common units in such offering or other transactions will be essentially the same as if the tax basis of our assets were equal to their fair market value at such time. However, in connection with providing this benefit to any future unitholders, similar allocations will be made to all holders of partnership interests immediately prior to such other transactions, including U.S.

 

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holders who receive our common stock in this distribution, to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction.

In the event we issue additional units or engage in certain other transactions, “Reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to all persons who are holders of units immediately prior to such issuance or other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or other transactions.

In addition, items of recapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Furthermore, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in such amount and manner as are needed to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Code to eliminate the difference between a unitholder’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for U.S. federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a unitholder’s share of an item will be determined on the basis of the unitholder’s interest in us, which will be determined by taking into account all the facts and circumstances, including:

 

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the unitholder’s relative contributions to us;

 

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the interests of all of the unitholders in profits and losses;

 

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the interest of all of the unitholders in cash flow and other non-liquidating distributions; and

 

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the rights of all of the unitholders to distributions of capital upon liquidation.

Treatment of Short Sales

A unitholder whose common units are loaned to a “short seller” to cover a short sale of our common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

 

•

any of our income, gain, loss or deduction with respect to those common units would not be reportable by the unitholder;

 

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any cash distributions received by the unitholder as to those units would be fully taxable; and

 

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all of these distributions would appear to be ordinary income.

The U.S. federal income tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units is uncertain. Therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. See also “Certain U.S. Federal Income Tax Matters—Tax Consequences of Disposition of Our Common Units—Recognition of Gain or Loss”.

 

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Section 754 Election

We will make the election permitted by Section 754 of the Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Code to reflect such unitholder’s purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) the unitholder’s share of our tax basis in our assets (“common basis”) and (2) the unitholder’s Section 743(b) adjustment to that basis.

U.S. Treasury regulations under Section 743 of the Code require, if the remedial allocation method is adopted (which we will adopt), a portion of the Section 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under U.S. Treasury Regulations Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Code, rather than cost recovery deductions under Section 168 of the Code, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our limited liability company agreement, the board of directors is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these U.S. Treasury regulations. See “Certain U.S. Federal Income Tax Matters—Tax Consequences of Disposition of Our Common Units—Uniformity of Common Units”.

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 of the Code but is arguably inconsistent with U.S. Treasury Regulations Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the U.S. Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. See “Certain U.S. Federal Income Tax Matters—Tax Consequences of Disposition of Our Common Units—Uniformity of Common Units.”

A Section 754 election is advantageous if the transferee’s tax basis in the transferee’s common units is higher than the common units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and the transferee’s share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in the transferee’s common units is lower than those common units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built in loss immediately after the transfer or if we distribute property and have a substantial basis reduction. Generally, a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets.

 

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We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceeds the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than the purchaser would have been allocated had the election not been revoked.

Tax Consequences of Our Operations

Accounting Method and Taxable Year

Our initial taxable year will end on December 31, 2015. Our taxable year may change after December 31, 2015, depending upon a number of factors. Each unitholder will be required to include in income such unitholder’s share of our income, gain, loss and deduction for our taxable year ending within or with such unitholder’s taxable year. For example, a unitholder who uses the calendar year will be required to include in such unitholder’s income for 2015 such unitholder’s share of our income, gain, loss and deduction for our taxable year ending December 31, 2015. In addition, a unitholder who has a different taxable year than our taxable year and who disposes of all of such unitholder’s units following the close of our taxable year but before the close of such unitholder’s taxable year must include his share of our income, gain, loss and deduction in income for such unitholder’s taxable year, with the result that such unitholder will be required to include in income for such unitholder’s taxable year such unitholder’s share of more than one year of our income, gain, loss and deduction. See “Certain U.S. Federal Income Tax Matters—Tax Consequences of Disposition of Our Common Units—Allocations Between Transferors and Transferees”.

Depletion Deductions

Subject to the limitations on deductibility of losses discussed above (see “Certain U.S. Federal Income Tax Matters—Tax Consequences of Ownership of Our Common Units—Limitations on Deductibility of Losses”), unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our oil and natural gas interests. Although the Code requires each unitholder to compute the unitholder’s own depletion allowance and maintain records of the unitholder’s share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our unitholders with information relating to this computation for U.S. federal income tax purposes. Each unitholder, however, remains responsible for calculating its own depletion allowance and maintaining records of the unitholder’s share of the adjusted tax basis of the underlying property for depletion and other purposes. Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative contracts or the operation of a major refinery.

Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the unitholder from the property for each taxable year, computed without the depletion allowance. A unitholder who qualifies as an independent producer may deduct percentage depletion only to the extent the unitholder’s average net daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and natural gas production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a unitholder’s total taxable income from all sources for the year, computed without the depletion

 

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allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.

Unitholders who do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the unitholder’s share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet, or Mcf, of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the unitholder’s share of the total adjusted tax basis in the property.

All or a portion of any gain recognized by a unitholder as a result of either the disposition by us of some or all of our oil and natural gas interests or the disposition by the unitholder of some or all of the unitholder’s units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the tax basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and U.S. Treasury regulations relating to the availability and calculation of depletion deductions by the unitholders. Further, because depletion is required to be computed separately by each unitholder and not by us, no assurance can be given with respect to the availability or extent of percentage depletion deductions to the unitholders for any taxable year. Moreover, the availability of percentage depletion may be reduced or eliminated if recently proposed (or similar) tax legislation is enacted. We encourage each unitholder to consult the unitholder’s own tax advisor to determine whether percentage depletion would be available to the unitholder.

Deductions for Intangible Drilling and Development Costs

We will elect to currently deduct intangible drilling and development costs, or “IDCs.” IDCs generally include our expenses for wages, fuel, repairs, hauling, supplies and other items that are incidental to, and necessary for, the drilling and preparation of wells for the production of oil, natural gas, or geothermal energy. The option to currently deduct IDCs applies only to those items that do not have a salvage value.

Although we will elect to currently deduct IDCs, each unitholder will have the option of either currently deducting IDCs or capitalizing all or part of the IDCs and amortizing them on a straight-line basis over a 60-month period, beginning with the taxable month in which the expenditure is made. If a unitholder makes the election to amortize the IDCs over a 60-month period, no IDC preference amount in respect of those IDCs will result for alternative minimum tax purposes.

Integrated oil companies must capitalize 30% of all their IDCs (other than IDCs paid or incurred with respect to oil and natural gas wells located outside of the United States) and amortize these IDCs over 60 months beginning in the month in which those costs are paid or incurred. If the taxpayer ceases to be an integrated oil company, it must continue to amortize those costs as long as it continues to own the property to which the IDCs relate. An “integrated oil company” is a taxpayer that has economic interests in oil or natural gas properties and also carries on substantial retailing or refining operations. An oil or natural gas producer is deemed to be a substantial retailer or refiner if it is subject to the rules disqualifying retailers and refiners from taking percentage depletion. To qualify as an “independent producer” that is not subject to these IDC deduction limits, a unitholder, either directly or indirectly through certain related parties, may not be involved in the refining of more than 75,000 barrels of oil (or the equivalent amount of natural gas) on average for any day during the taxable year or in the retail marketing of oil and natural gas products exceeding $5 million per year in the aggregate.

 

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IDCs previously deducted that are allocable to property (directly or through ownership of an interest in a partnership) and that would have been included in the adjusted tax basis of the property had the IDC deduction not been taken are recaptured to the extent of any gain realized upon the disposition of the property or upon the disposition by a unitholder of interests in us. Recapture is generally determined at the unitholder level. Where only a portion of the recapture property is sold, any IDCs related to the entire property are recaptured to the extent of the gain realized on the portion of the property sold. In the case of a disposition of an undivided interest in a property, a proportionate amount of the IDCs with respect to the property is treated as allocable to the transferred undivided interest to the extent of any gain recognized. See “Certain U.S. Federal Income Tax Matters—Tax Consequences of Disposition of Our Common Units—Recognition of Gain or Loss”. The election to currently deduct IDCs may be restricted or eliminated if recently proposed (or similar) tax legislation is enacted. Each prospective unitholder is encouraged to consult his tax advisor regarding any deduction or amortization of IDCs, as well as any recapture.

Deduction for U.S. Production Activities

Subject to the limitations on the deductibility of losses discussed above (see “Certain U.S. Federal Income Tax Matters—Tax Consequences of Ownership of Our Common Units—Limitations on Deductibility of Losses”) and the limitation discussed below, unitholders will be entitled to a deduction, herein referred to as the “Section 199 deduction,” equal to 6% of our qualified production activities income that is allocated to such unitholder, but not to exceed 50% of such unitholder’s IRS Form W-2 wages for the taxable year allocable to domestic production gross receipts.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine the unitholder’s Section 199 deduction, each unitholder will aggregate the unitholder’s share of the qualified production activities income allocated to the unitholder from us with the unitholder’s qualified production activities income from other sources. Each unitholder must take into account the unitholder’s distributive share of the expenses allocated to the unitholder from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are taken into account only if and to the extent the unitholder’s share of losses and deductions from all of our activities is not disallowed by the tax basis rules, the at-risk rules or the passive activity loss rules. See “Certain U.S. Federal Income Tax Matters—Tax Consequences of Ownership of Our Common Units—Limitations on Deductibility of Losses”.

The amount of a unitholder’s Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder’s allocable share of our wages that are deducted in arriving at qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders, and thus a unitholder’s ability to claim the Section 199 deduction may be limited.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRS Form W-2 wages, or how such items are allocated by us to unitholders. Further, because the Section 199 deduction is required to be computed separately by each unitholder, no assurance can be given as to the availability or extent of the Section 199 deduction to the unitholders. Moreover,

 

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the availability of Section 199 deductions may be reduced or eliminated if recently proposed (or similar) tax legislation is enacted. Each prospective unitholder is encouraged to consult his tax advisor to determine whether the Section 199 deduction would be available to the unitholder.

Lease Acquisition Costs

The cost of acquiring oil and natural gas leases or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. See “Certain U.S. Federal Income Tax Matters—Tax Consequences of Our Operations—Depletion Deductions”.

Geophysical Costs

The costs of geophysical exploration incurred in connection with the exploration and development of oil and natural gas properties in the United States are deducted ratably over a 24-month period beginning on the date that such expense is paid or incurred.

Operating and Administrative Costs

Amounts paid for operating a producing well are deductible as ordinary business expenses, as are administrative costs to the extent they constitute ordinary and necessary business expenses that are reasonable in amount.

Initial Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The tax basis of our assets we own at the time of this distribution will be greater to the extent such assets have been recently acquired. The U.S. federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to the distribution will be borne by our existing Unitholders and Unitholders who receive our common units in the distribution. See “Certain U.S. Federal Income Tax Matters—Tax Consequences of Ownership of our Common Units—Allocation of Income, Gain, Loss and Deduction”.

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own or will likely be required to recapture some or all of those deductions as ordinary income upon a sale of such unitholder’s interest in us. Please read “Certain U.S. Federal Income Tax Matters—Tax Consequences of Ownership of our Common Units—Allocation of Income, Gain, Loss and Deduction” and “Certain U.S. Federal Income Tax Matters—Tax Consequences of Disposition of our Common Units—Recognition of Gain or Loss”.

Valuation and Tax Basis of Our Properties

The U.S. federal income tax consequences of the ownership and disposition of common units will depend in part on our estimates of the relative fair market values, and the initial tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the

 

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relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Tax Consequences of Disposition of Our Common Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of our common units equal to the difference between the amount realized and the unitholder’s tax basis for the common units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by such unitholder plus such unitholder’s share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a common unit held for more than one year will generally be taxable as capital gain or loss. However, a portion of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of common units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income in the case of individuals.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in such partner’s entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. U.S. Treasury regulations under Section 1223 of the Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the U.S. Treasury regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult such unitholder’s tax advisor as to the possible consequences of this ruling and application of the U.S. Treasury regulations.

 

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Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

 

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a short sale;

 

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an offsetting notional principal contract; or

 

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a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this summary as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing U.S. Treasury regulations. Recently, however, the Department of the Treasury and the IRS issued proposed U.S. Treasury regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed U.S. Treasury regulations do not specifically authorize the use of the proration method we have adopted. Existing publicly traded partnerships are entitled to rely on those proposed U.S. Treasury regulations; however, they are not binding on the IRS and are subject to change until the final U.S. Treasury regulations are issued. If our method of allocating income and deductions between transferee and transferor unitholders is not allowed under the U.S. Treasury regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future U.S. Treasury regulations.

A unitholder who disposes of common units prior to the record date set for a cash distribution for any quarter will be allocated items of our income, gain, loss and deductions attributable to the month of sale but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his units other than through a broker generally is required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is generally required to notify us in writing of that purchase within 30 days after the purchase, unless a broker or nominee will satisfy such requirement. We are

 

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required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker.

Constructive Termination

We will be considered to have been terminated for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Common Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of U.S. federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of U.S. Treasury regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “Certain U.S. Federal Income Tax Matters—Tax Consequences of Ownership of Our Common Units—Section 754 Election”.

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Code, even though that position may be inconsistent with U.S. Treasury regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “Certain U.S. Federal Income Tax Matters—Tax Consequences of Ownership of Our Common Units—Section 754 Election”. To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the U.S. Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “Certain U.S. Federal Income Tax Matters—Tax Consequences of Disposition of Our Common Units—Recognition of Gain or Loss”.

 

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Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including an IRS Schedule K-1, which describes the unitholder’s share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to the requirements of the Code, the U.S. Treasury regulations or administrative interpretations of the IRS. Nor can we assure unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the common units.

The IRS may audit our U.S. federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of the unitholder’s own return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to his returns.

Partnerships generally are treated as separate entities for purposes of U.S. federal income tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our limited liability company agreement provides for the board of directors to designate a Tax Matters Partner, and we expect the initial tax matters partner to be a subsidiary of ours.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate in that action.

A unitholder must file a statement with the IRS identifying the treatment of any item on the unitholder’s U.S. federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

 

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the name, address and taxpayer identification number of the beneficial owner and the nominee;

 

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a statement regarding whether the beneficial owner is: (a) a person that is not a U.S. person; (b) a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or (c) a tax-exempt entity;

 

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the amount and description of units held, acquired or transferred for the beneficial owner; and

 

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specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

 

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Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

 

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for which there is, or was, “substantial authority”; or

 

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as to which there is a reasonable basis and the relevant facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the relevant facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the adjusted tax basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted tax basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Section 482 of the Code is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net transfer price adjustment under Section 482 for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S corporation or a personal holding company). The penalty is increased to 40% in the event of a gross valuation misstatement. We do not anticipate making any valuation misstatements.

Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly our unitholders and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single tax year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our U.S. federal income tax information return (and possibly our unitholders’ tax return) would be audited by the IRS. Please read “Certain U.S. Federal Income Tax Matters—Administrative Matters—Information Returns and Audit Procedures”.

 

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Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, our unitholders may be subject to the following provisions of the American Jobs Creation Act of 2004:

 

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accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described in “Certain U.S. Federal Income Tax Matters—Administrative Matters—Accuracy-Related Penalties”;

 

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for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

 

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in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

 

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WHERE YOU CAN FIND MORE INFORMATION

We have filed a registration statement on Form 10 with the SEC with respect to our common units that Atlas Energy unitholders will receive in the distribution. This information statement is a part of that registration statement and, as allowed by SEC rules, does not include all of the information you can find in the registration statement or the exhibits to the registration statement. For additional information relating to New Atlas and the distribution, reference is made to the registration statement and the exhibits to the registration statement. Statements contained in this information statement as to the contents of any contract or document referred to are not necessarily complete and in each instance, if the contract or document is filed as an exhibit to the registration statement, we refer you to the copy of the contract or other document filed as an exhibit to the registration statement. Each such statement is qualified in all respects by reference to the applicable document.

After the distribution, we will file annual, quarterly and special reports, proxy statements and other information with the SEC. We intend to furnish our unitholders with annual reports containing consolidated financial statements audited by an independent registered public accounting firm. The registration statement is, and any of these future filings with the SEC will be, available to the public over the Internet on the SEC’s website at www.sec.gov. You may read and copy any filed document at the SEC’s public reference rooms at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information about the public reference rooms.

Following the distribution, we will maintain an Internet site at www.atlasenergy.com. Our website and the information contained on that site, or connected to that site, are not incorporated into this information statement or the registration statement on Form 10.

 

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GLOSSARY OF TERMS

As commonly used in the oil and gas industry and as used in this information statement, the following terms have the following meanings:

Bbl. One stock tank barrel or 42 United States gallons liquid volume.

Bcf. One billion cubic feet.

Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl oil, condensate or natural gas liquids.

Btu. One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Developed acres. Acres spaced or assigned to productive wells.

Development well. A well drilled within a proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dth. One dekatherm, equivalent to one million British thermal units.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well as those items are defined in this section.

Extension well. A well drilled to extend the limits of a known reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

MBbl. One thousand barrels of oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.

Mcfd. One thousand cubic feet per day.

MMBl. One million barrels of oil or other liquid hydrocarbons.

MMBtu. One million British thermal units.

MMcf. One million cubic feet.

 

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MMcfe. One million cubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.

MMcfed. One MMcfe per day.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NGL. Natural gas liquids, which are the hydrocarbon liquids contained within gas.

NYMEX. The New York Mercantile Exchange.

Oil. Crude oil, condensate and natural gas liquids.

PV-10. Present value of future net revenues. See the definition of “standardized measure.”

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved reserves. Proved oil and gas reserves are those quantities of oil and gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves or PUDs. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for undeveloped reserves cannot be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

 

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Reservoir. A porous and permeable underground formation containing a natural accumulation of economically productive oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation and injection for in-situ combustion.

Standardized measure. Standardized measure, or standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities, is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses, debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.

Unproved reserves. Lease acreage on which wells have not been drilled and where it is either probable or possible that the acreage contains reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

 

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INDEX TO FINANCIAL STATEMENTS

ATLAS ENERGY GROUP, LLC

INDEX TO COMBINED CONSOLIDATED FINANCIAL STATEMENTS

 

		PAGE
NEW ATLAS OPERATIONS AND SUBSIDIARIES UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS
Introduction			F-2
Unaudited Pro Forma Condensed Combined Balance Sheet as of September 30, 2014			F-4
Unaudited Pro Forma Condensed Combined Statement of Operations for the nine months ended September 30, 2014			F-5
Unaudited Pro Forma Condensed Combined Statement of Operations for the nine months ended September 30, 2013			F-6
Unaudited Pro Forma Condensed Combined Statement of Operations for the year ended December 31, 2013			F-7
Notes to Unaudited Pro Forma Condensed Combined Financial Statements			F-8
NEW ATLAS OPERATIONS AND SUBSIDIARIES COMBINED CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm			F-12
Combined Consolidated Balance Sheets as of December 31, 2013 and 2012			F-13
Combined Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011			F-14
Combined Consolidated Statements of Comprehensive Income (Loss) for the years ended December  31, 2013, 2012 and 2011			F-15
Combined Consolidated Statements of Equity for the years ended December 31, 2013, 2012 and 2011			F-16
Combined Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011			F-17
Notes to Combined Consolidated Financial Statements			F-18
NEW ATLAS OPERATIONS AND SUBSIDIARIES COMBINED CONSOLIDATED UNAUDITED INTERIM FINANCIAL STATEMENTS
Combined Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013			F-66
Combined Consolidated Statements of Operations for the nine months ended September 30, 2014 and 2013			F-67
Combined Consolidated Statements of Comprehensive Income (Loss) for the nine months ended September 30, 2014 and 2013			F-68
Combined Consolidated Statement of Equity for the nine months ended September 30, 2014			F-69
Combined Consolidated Statements of Cash Flows for the nine months ended September 30, 2014 and 2013			F-70
Notes to Combined Consolidated Financial Statements			F-71

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NEW ATLAS OPERATIONS AND SUBSIDIARIES

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

The following unaudited pro forma condensed combined financial statements of Atlas Energy Group, LLC reflect the historical combined financial statements of “New Atlas Operations and subsidiaries” (the “Predecessor”) included elsewhere in this information statement, and were adjusted on a pro forma basis to give effect to the following transactions:

 

•

Atlas Resource Partners, L.P.’s (NYSE: ARP; “ARP”) July 2013 acquisition of assets from EP Energy E&P Company, L.P. (the “EP Energy Acquisition”) for cash consideration of $709.6 million partially funded with ARP’s issuance of (A) 14.95 million of its common limited partner units, (B) 3.75 million of its Class C convertible preferred units, and (C) $250.0 million of its 9.25% Senior Notes;

 

•

ARP’s May 2014 issuance of 6.3 million of its common limited partner units;

 

•

ARP’s June 2014 acquisition of a 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado for cash consideration of approximately $407.8 million partially funded with ARP’s issuance of (A) 15.50 million of its common limited partner units and (B) $100.0 million of its 7.75% Senior Notes;

 

•

the contribution by Atlas Energy, L.P. to us of the assets and liabilities that comprise our business;

 

•

the issuance of our $155.0 term-loan credit facility to replace the $147.4 million of Atlas Energy’s term-loan credit facility allocated to us;

 

•

the issuance of 26.0 million of our common units, which will all be distributed to holders of Atlas Energy common units. This number of common units is based upon the number of Atlas Energy common units expected to be outstanding on February 25, 2015 and a distribution ratio of one common unit of New Atlas for every two common units of Atlas Energy; and

 

•

the impact of a separation agreement between us and Atlas Energy and the provisions contained therein.

The unaudited pro forma condensed combined statements of operations for the nine months ended September 30, 2014 and 2013 and for the year ended December 31, 2013 reflect our results as if the separation and related transactions described above had occurred as of January 1, 2014, January 1, 2013 and January 1, 2013, respectively. The unaudited pro forma condensed combined balance sheet as of September 30, 2014 reflects our results as if the separation and related transactions described above had occurred as of such date.

The unaudited pro forma condensed combined financial statements have been prepared on the basis that we will be treated as a partnership for federal income tax purposes. The unaudited pro forma condensed combined financial statements should be read in conjunction with our “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 113 and our Predecessor’s audited and unaudited interim combined consolidated financial statements and corresponding notes beginning on page F-13.

The unaudited pro forma condensed combined financial statements included in this information statement do not necessarily reflect what our financial position and results of operations would have been if we had operated as an independent, publicly traded company during the periods shown. In addition, they are not necessarily indicative of our future results of operations or financial condition. The assumptions and estimates used and pro forma adjustments derived from such assumptions are based on currently available information, and we believe such assumptions are reasonable under the circumstances.

The unaudited pro forma condensed combined financial statements do not include certain non-recurring separation costs that we expect to incur in connection with the separation. Excluded are one-time expenditures

 

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estimated at $1.0 million to $1.5 million related to one-time transaction-related costs, excluding advisory fees. We expect to fund these costs through cash from operations, cash on hand and, if necessary, cash available from the senior secured revolving credit facility we anticipate entering into simultaneously with the closing of the transactions described above. Due to the scope and complexity of these activities, the amount of these costs could increase or decrease materially and the timing of incurrence could change.

 

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NEW ATLAS OPERATIONS AND SUBSIDIARIES

UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET

AS OF SEPTEMBER 30, 2014

(in thousands)

 

		New Atlas Historical				Pro Forma Adjustments				New Atlas Pro Forma
ASSETS
Current assets:
Cash and equivalents		$	56,755			$	146,600	(a)		$	54,855
							(148,500	)(b)
Accounts receivable			103,160				—				103,160
Advances to affiliates			5,473				—				5,473
Current portion of derivative asset			21,634				—				21,634
Subscriptions receivable			62,840				—				62,840
Prepaid expenses and other			25,128				—				25,128
Total current assets			274,990				(1,900	)			273,090
Property, plant and equipment cost			3,571,957				—				3,571,957
Accumulated depreciation, depletion and amortization			(843,307	)			—				(843,307	)
Property, plant and equipment, net			2,728,650				—				2,728,650
Intangible assets, net			759				—				759
Goodwill			31,784				—				31,784
Long-term derivative asset			32,096				—				32,096
Other assets, net			84,997				8,400	(a)			87,583
							(5,814	)(b)
Total other long-term assets			149,636				2,586				152,222
Total assets		$	3,153,276			$	686			$	3,153,962
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt		$	1,500			$	1,500	(a)		$	1,500
							(1,500	)(b)
Accounts payable			119,643				—				119,643
Current portion of derivative liability			1,792				—				1,792
Accrued interest			10,867				—				10,867
Accrued well drilling and completion costs			100,721				—				100,721
Accrued liabilities			47,740				—				47,740
Total current liabilities			282,263				—				282,263
Long-term debt			1,430,022				153,500	(a)			1,436,522
							(147,000	)(b)
Asset retirement obligations and other			110,336				—				110,336
Commitments and contingencies
Equity:
Equity			336,532				(336,532	)(c)			—
Members’ equity			—				336,532	(c)			330,718
							(5,814	)(b)
Accumulated other comprehensive income			15,744				—				15,744
			352,276				(5,814	)			346,462
Non-controlling interests			978,379				—				978,379
Total equity			1,330,655				(5,814	)			1,324,841
Total liabilities and equity		$	3,153,276			$	686			$	3,153,962

See accompanying notes to unaudited pro forma condensed combined financial statements.

 

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NEW ATLAS OPERATIONS AND SUBSIDIARIES

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2014

(in thousands)

 

		Historical New Atlas Standalone				Historical Merit (1/1/14- 6/30/14)				Acquisitions Adjustments				As Adjusted				Transaction Adjustments				Combined Pro Forma New Atlas
Revenues:
Gas and oil production		$	342,456			$	46,001			$	—			$	388,457			$	—			$	388,457
Well construction and completion			126,917				—				—				126,917				—				126,917
Gathering and processing			11,287				—				—				11,287				—				11,287
Administration and oversight			12,072				—				—				12,072				—				12,072
Well services			18,441				—				—				18,441				—				18,441
Other, net			1,167				—				—				1,167				—				1,167
Total revenues			512,340				46,001				—				558,341				—				558,341
Costs and expenses:
Gas and oil production			134,590				15,394				—				149,984				—				149,984
Well construction and completion			110,363				—				—				110,363				—				110,363
Gathering and processing			11,900				—				—				11,900				—				11,900
Well services			7,525				—				—				7,525				—				7,525
General and administrative			63,487				—				(12,765	)(d)			50,722				—				50,722
Depreciation, depletion and amortization			177,513				—				8,836	(e)			186,387				—				186,387
											38	(f)							—
Total costs and expenses			505,378				15,394				(3,891	)			516,881				—				516,881
Operating income			6,962				30,607				3,891				41,460				—				41,460
Interest expense			(51,474	)			—				(1,407	)(g)			(57,726	)			(4,229	)(l)			(61,955	)
											(3,906	)(h)
											(798	)(i)
											(141	)(j)
Loss on asset sales and disposal			(1,683	)			—				—				(1,683	)			—				(1,683	)
Net income (loss)			(46,195	)			30,607				(2,361	)			(17,949	)			(4,229	)			(22,178	)
Loss (income) attributable to non-controlling interests			33,828				—				(20,464	)(k)			13,364				—				13,364
Net income (loss) attributable to owner		$	(12,367	)		$	30,607			$	(22,825	)		$	(4,585	)		$	(4,229	)		$	(8,814	)
Net loss attributable to common units:
Basic and Diluted		$	—																			$	(0.34	)
Weighted average common units outstanding:
Basic and Diluted			—																				26,250	(m)

See accompanying notes to unaudited pro forma condensed combined financial statements.

 

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NEW ATLAS OPERATIONS AND SUBSIDIARIES

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2013

(in thousands)

 

		Historical New Atlas Standalone				Historical EP Energy (1/1/13- 7/31/13)				Historical Merit (1/1/13- 9/30/13)				Acquisitions Adjustments				As Adjusted				Transaction Adjustments				Combined Pro Forma New Atlas
Revenues:
Gas and oil production		$	176,190			$	90,626			$	67,933			$	—			$	334,749			$	—			$	334,749
Well construction and completion			92,293				—				—				—				92,293				—				92,293
Gathering and processing			11,639				—				—				—				11,639				—				11,639
Administration and oversight			8,923				—				—				—				8,923				—				8,923
Well services			14,703				—				—				—				14,703				—				14,703
Other, net			(14,459	)			—				—				14,480				21				—				21
Total revenues			289,289				90,626				67,933				14,480				462,328				—				462,328
Costs and expenses:
Gas and oil production			64,837				41,630				23,416				—				129,883				—				129,883
Well construction and completion			80,255				—				—				—				80,255				—				80,255
Gathering and processing			13,767				—				—				—				13,767				—				13,767
Well services			7,009				—				—				—				7,009				—				7,009
General and administrative			73,037				—				—				(25,897	)(d)			47,140				—				47,140
Depreciation, depletion and amortization			86,392				17,742				—				13,036	(e)			117,227				—				117,227
															57	(f)
Total costs and expenses			325,297				59,372				23,416				(12,804	)			395,281				—				395,281
Operating income (loss)			(36,008	)			31,254				44,517				27,284				67,047				—				67,047
Interest expense			(24,704	)			—				—				(6,344	)(g)			(50,384	)			(10,115	)(l)			(60,499	)
															(1,303	)(n)
															(5,860	)(h)
															(1,197	)(i)
															(211	)(j)
															(13,619	)(o)
															(401	)(p)
															3,255	(q)
Loss on asset sales and disposal			(2,035	)			—				—				—				(2,035	)			—				(2,035	)
Net income (loss)			(62,747	)			31,254				44,517				1,604				14,628				(10,115	)			4,513
Loss (income) attributable to non-controlling interests			31,484				—				—				(56,211	)(k)			(24,727	)			—				(24,727	)
Net income (loss) attributable to owner		$	(31,263	)		$	31,254			$	44,517			$	(54,607	)		$	(10,099	)		$	(10,115	)		$	(20,214	)
Net loss attributable to common units:
Basic and Diluted		$	—																							$	(0.77	)
Weighted average common units outstanding:
Basic and Diluted			—																								26,250	(m)

See accompanying notes to unaudited pro forma condensed combined financial statements.

 

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NEW ATLAS OPERATIONS AND SUBSIDIARIES

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2013

(in thousands)

 

		Historical New Atlas Standalone				Historical EP Energy (1/1/13- 7/31/13)				Historical Merit (1/1/13- 12/31/13)(s)				Acquisitions Adjustments				As Adjusted				Transaction Adjustments				Combined Pro Forma New Atlas
Revenues:
Gas and oil production		$	273,906			$	90,626			$	91,575			$	—			$	456,107			$	—			$	456,107
Well construction and completion			167,883				—				—				—				167,883				—				167,883
Gathering and processing			15,676				—				—				—				15,676				—				15,676
Administration and oversight			12,277				—				—				—				12,277				—				12,277
Well services			19,492				—				—				—				19,492				—				19,492
Other, net			(14,135	)			—				—				14,480	(r)			345				—				345
Total revenues			475,099				90,626				91,575				14,480				671,780				—				671,780
Costs and expenses:
Gas and oil production			100,178				41,630				32,069				—				173,877				—				173,877
Well construction and completion			145,985				—				—				—				145,985				—				145,985
Gathering and processing			18,012				—				—				—				18,012				—				18,012
Well services			9,515				—				—				—				9,515				—				9,515
General and administrative			89,957				—				—				(29,923	)(d)			60,034				—				60,034
Depreciation, depletion and amortization			139,916				17,742				—				17,381	(e)			175,115				—				175,115
															76	(f)
Asset impairment			38,014				—				—				—				38,014				—				38,014
Total costs and expenses			541,577				59,372				32,069				(12,466	)			620,552				—				620,552
Operating income (loss)			(66,478	)			31,254				59,506				26,946				51,228								51,228
Interest expense			(39,712	)			—				—				(6,854	)(g)			(68,322	)			(11,512	)(l)			(79,834	)
															(1,303	)(n)
															(7,813	)(h)
															(1,596	)(i)
															(280	)(j)
															(13,619	)(o)
															(401	)(p)
															3,255	(q)
Loss on asset sales and disposal			(987	)			—				—				—				(987	)			—				(987	)
Net income (loss)			(107,177	)			31,254				59,506				(1,664	)			(18,081	)			(11,512	)			(29,593	)
Loss (income) attributable to non-controlling interests			58,389				—				—				(61,385	)(k)			(2,996	)			—				(2,996	)
Net income (loss) attributable to owner		$	(48,788	)		$	31,254			$	59,506			$	(63,049	)		$	(21,077	)		$	(11,512	)		$	(32,589	)
Net loss attributable to common units:
Basic and Diluted		$	—																							$	(1.24	)
Weighted average common units outstanding:
Basic and Diluted			—																								26,250	(m)

See accompanying notes to unaudited pro forma condensed combined financial statements.

 

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NEW ATLAS OPERATIONS AND SUBSIDIARIES

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

 

(a)

To reflect the issuance of New Atlas’s $155.0 million term-loan credit facility, which we anticipate entering into simultaneously with the closing of the separation and related transactions. The estimated fees and expenses will be recognized as deferred financing costs within other assets, net on the unaudited pro forma condensed combined balance sheet and amortized over the anticipated term of the senior secured credit facility, which is assumed to be six years.

 

(b)

To reflect the repayment of the portion of the Atlas Energy term loan credit facility allocated to New Atlas, including the current portion, with the proceeds from the New Atlas $155.0 million term loan credit facility discussed in (a), and to write-off the unamortized deferred financing costs related to the Atlas Energy term loan credit facility.

 

(c)

To reflect the contribution by Atlas Energy of assets and liabilities defined as “New Atlas” to Atlas Energy Group, LLC. The contribution of assets was recorded at historical cost because it is considered to be a reorganization of entities under common control. To reflect the impact of the contribution within equity/members’ equity on the unaudited pro forma condensed combined balance sheet, the historical equity of New Atlas was eliminated and reallocated to Atlas Energy Group, LLC members’ equity.

 

(d)

To reflect the adjustment to general and administrative expense related to ARP’s acquisition-related costs incurred in connection with its consummated acquisitions.

 

(e)

To reflect incremental depreciation, depletion and amortization expense related to the acquisition of oil and gas assets in the Rangely Acquisition.

 

(f)

To reflect incremental accretion expense related to $1.3 million of asset retirement obligations on oil and natural gas properties acquired in the Rangely Acquisition.

 

(g)

To reflect the adjustment to interest expense related to ARP’s pro forma borrowings under its revolving credit facility as of September 30, 2014, inclusive of amounts used to partially fund its consummated acquisitions, based on the interest rate of 2.2%.

 

(h)

To reflect the adjustment to interest expense from ARP’s additional $100.0 million issuance of 7.75% senior notes, which were issued on June 2, 2014 at an offering price of 99.5% of par value, and the related amortization of the debt discount associated with the 7.75% senior notes.

 

(i)

To reflect the amortization of ARP’s pro forma deferred financing costs, inclusive of amounts incurred in the amendments to ARP’s revolving credit facility to allow for its consummated acquisitions, over the duration of the ARP credit facility.

 

(j)

To reflect the amortization of deferred financing costs related to ARP’s additional $100.0 million issuance of 7.75% senior notes over the duration of the senior notes.

 

(k)

To reflect the adjustment of non-controlling interests in the net income (loss) of ARP as a result of the pro forma statement of operations adjustments previously noted. The allocation of ARP net income (loss) to non-controlling interests is based upon the general partner’s and limited partners’ relative ownership interests, as well as required minimum distributions to preferred limited partners.

 

(l)

To reflect the adjustment to interest expense and the amortization of deferred financing costs associated with the repayment of the portion of the Atlas Energy term-loan credit facility allocated to New Atlas and the issuance of New Atlas’s $155.0 million term-loan credit facility, which we anticipate entering into simultaneously with the closing of the separation and related transactions.

 

(m)

To reflect the New Atlas outstanding common units upon completion of the separation and related transactions.

 

(n)

To reflect the adjustment to interest expense from ARP’s $275.0 million issuance of 7.75% senior notes, which were issued on January 23, 2013 at par value.

 

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(o)

To reflect the adjustment to interest expense from ARP’s $250.0 million issuance of 9.25% senior notes, which were issued on July 30, 2013 at an offering price of 99.297% of par value, and the related amortization of the debt discount associated with the 9.25% senior notes.

 

(p)

To reflect the amortization of deferred financing costs related to ARP’s additional $250.0 million issuance of 9.25% senior notes over the duration of the senior notes.

 

(q)

To reflect the adjustment to interest expense for the accelerated amortization of deferred financing costs associated with the retirement of ARP’s term loan facility and a portion of the outstanding indebtedness under ARP’s revolving credit facility with a portion of the proceeds from the issuance of the 7.75% ARP Senior Notes.

 

(r)

To reflect the adjustment to other, net related to ARP’s acquisition-related costs incurred when ARP entered into contracts which provided the option to enter into swap contracts for future production periods (“swaptions”) for production volumes acquired in the EP Energy Acquisition.

 

(s)

The following tables set forth certain unaudited pro forma information concerning ARP’s proved oil, natural gas and natural gas liquids reserves for the year ended December 31, 2013, giving effect to the Rangely Acquisition as if it had occurred on January 1, 2013. There are numerous uncertainties inherent in estimating the quantities of proved reserves and projecting future rates of production and timing of development costs. The following reserve data represent estimates only and should not be construed as being precise:

Proved Gas and Oil Reserve Quantities

The estimates of proved oil and gas reserves as of December 31, 2013 were prepared for Merit Energy utilizing year-end estimates of reserve quantities provided by third-party independent petroleum engineering consultants. The estimated proved net recoverable reserves presented below include only those quantities that were expected to be commercially recoverable at the SEC-applicable prices and costs for each year under the then existing regulatory practices and with conventional equipment and operating methods. Proved developed reserves represent only those reserves estimated to be recovered through existing wells. Proved undeveloped reserves include those reserves that may be recovered from new wells on undrilled acreage or from existing wells on which a relatively major expenditure for recompletion or secondary recovery operation is required. All of the Rangely proved reserves set forth herein are located in Colorado. The estimate of reserves and the standardized measure of discounted future net cash flows shown below reflect Merit Energy’s development plan rather than ARP’s development plan for those properties. New Atlas and ARP’s pro forma net proved gas and oil reserves and changes in net proved gas and oil reserves attributable to the Rangely Acquisition are summarized below:

 

		Historical				Rangely Acquisition Natural Gas (Mcf)				Pro Forma
Balance, January 1, 2013			573,774,257				—				573,774,257
Extensions, discoveries and other additions(1)			90,098,219				—				90,098,219
Sales of reserves in-place			(2,755,155	)			—				(2,755,155	)
Purchase of reserves in-place(2)			493,481,302				—				493,481,302
Transfers to limited partnerships(3)			(2,485,210	)			—				(2,485,210	)
Revisions(4)			(88,484,468	)			—				(88,484,468	)
Production			(59,849,442	)			—				(59,849,442	)
Balance, December 31, 2013			1,003,779,503				—				1,003,779,503
Proved developed reserves at:
January 1, 2013			338,655,324				—				338,655,324
December 31, 2013			766,872,394				—				766,872,394
Proved undeveloped reserves at:
January 1, 2013			235,118,932				—				235,118,932
December 31, 2013			236,907,109				—				236,907,109

 

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		Historical				Rangely Acquisition Oil (Bbl)				Pro Forma
Balance, January 1, 2013			8,868,836				19,831,680				28,700,516
Extensions, discoveries and other additions(1)			8,255,531				—				8,255,531
Sales of reserves in-place			—				—				—
Purchase of reserves in-place(2)			1,964				—				1,964
Transfers to limited partnerships(3)			(239,910	)			—				(239,910	)
Revisions(4)			(1,412,371	)			25,584				(1,386,787	)
Production			(485,226	)			(930,748	)			(1,415,974	)
Balance, December 31, 2013			14,988,824				18,926,516				33,915,340
Proved developed reserves at:
January 1, 2013			3,400,447				18,164,413				21,564,860
December 31, 2013			3,459,260				17,480,779				20,940,039
Proved undeveloped reserves at:
January 1, 2013			5,468,389				1,667,267				7,135,656
December 31, 2013			11,529,564				1,445,737				12,975,301

 

		Historical				Rangely Acquisition Natural Gas Liquids (Bbl)				Pro Forma
Balance, January 1, 2013			16,061,897				1,352,990				17,414,887
Extensions, discoveries and other additions(1)			8,197,272				—				8,197,272
Sales of reserves in-place			(4,625	)			—				(4,625	)
Purchase of reserves in-place(2)			55,187				—				55,187
Transfers to limited partnerships(3)			(258,381	)			—				(258,381	)
Revisions(4)			(3,826,744	)			30,524				(3,796,220	)
Production			(1,267,590	)			(101,642	)			(1,369,232	)
Balance, December 31, 2013			18,957,016				1,281,872				20,238,888
Proved developed reserves at:
January 1, 2013			7,884,778				1,352,990				9,237,768
December 31, 2013			7,676,389				1,281,872				8,958,261
Proved undeveloped reserves at:
January 1, 2013			8,177,120				—				8,177,120
December 31, 2013			11,280,627				—				11,280,627

 

(1)	Principally includes increases of proved reserves due to the results of ARP’s drilling activity.

(2)	Represents the reserves purchased through acquisition during the period.

(3)	Represents the limited partner’s portion of ARP’s reserves transferred to its Drilling Partnerships.

(4)	Represents a downward revision primarily due to a reduction of ARP’s five year drilling plans in the Barnett Shale and pricing scenario revisions.

 

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Standardized Measure

New Atlas’s and ARP’s pro forma standardized measure of discounted future net cash flows before income taxes related to the proved gas and oil reserves of the Rangely Acquisition is as follows (in thousands):

 

		For the Year Ended December 31, 2013
		Historical				Rangely Acquisition				Pro Forma
Future cash inflows		$	5,268,148			$	1,798,238			$	7,066,386
Future production costs			(2,397,997	)			(784,622	)			(3,182,619	)
Future development costs			(752,369	)			(83,848	)			(836,217	)
Future net cash flows			2,117,782				929,768				3,047,550
Less 10% annual discount for estimated timing of cash flows			(1,038,491	)			(558,029	)			(1,596,520	)
Standardized measure of discounted future net cash flows		$	1,079,291			$	371,739			$	1,451,030

FASB requirements for gas and oil reserve estimation and disclosure require that reserve estimates and future cash flows be based on the average market prices for sales of gas and oil on the first calendar day of each month during the year. The average prices used for 2013 under these rules were $3.67 per Mmbtu of natural gas and $96.78 per barrel of oil.

Changes in Standardized Measure

New Atlas and ARP pro forma changes in the standardized measure of discounted future net cash flows before income taxes related to the proved gas and oil reserves of the Rangely Acquisition are as follows:

 

		Year Ended December 31, 2013
		Historical				Rangely Acquisition				Pro Forma
Balance, beginning of year		$	623,676			$	372,338			$	996,014
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs			(171,409	)			(59,506	)			(230,915	)
Net changes in prices and production costs			85,191				(803	)			84,388
Revisions of previous quantity estimates			(1,881	)			1,125				(756	)
Development costs incurred			27,245				17,306				44,551
Changes in future development costs			(21,579	)			(6,500	)			(28,079	)
Transfers to limited partnerships			(53,392	)			—				(53,392	)
Extensions, discoveries, and improved recovery less related costs			143,338				—				143,338
Purchases of reserves in-place			516,985				—				516,985
Sales of reserves in-place			(2,053	)			—				(2,053	)
Accretion of discount			62,368				37,234				99,602
Estimated settlement of asset retirement obligations			(18,858	)			—				(18,858	)
Estimated proceeds on disposals of well equipment			17,052				—				17,052
Changes in production rates (timing) and other			(127,392	)			10,545				(116,847	)
Outstanding, end of year		$	1,079,291			$	371,739			$	1,451,030

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholder

Atlas Energy Group, LLC

We have audited the accompanying combined consolidated balance sheets of Atlas Energy Group, LLC (a Delaware limited liability company and a wholly owned subsidiary of Atlas Energy, L.P.) and subsidiaries and affiliates as defined in Note 1 (collectively “New Atlas Operations and subsidiaries”) as of December 31, 2013 and 2012, and the related combined consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of New Atlas Operations and subsidiaries’ management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of New Atlas Operations and subsidiaries’ internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of New Atlas Operations and subsidiaries’ internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the combined consolidated financial statements referred to above present fairly, in all material respects, the financial position of New Atlas Operations and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

November 5, 2014

 

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NEW ATLAS OPERATIONS AND SUBSIDIARIES

COMBINED CONSOLIDATED BALANCE SHEETS

(in thousands)

 

		December 31,
		2013				2012
ASSETS
Current assets:
Cash and cash equivalents		$	10,625			$	23,270
Accounts receivable			60,167				38,723
Advances to affiliates			2,912				5,500
Current portion of derivative asset			1,891				12,274
Subscriptions receivable			47,692				55,357
Prepaid expenses and other			10,181				9,138
Total current assets			133,468				144,262
Property, plant and equipment, net			2,186,683				1,302,228
Intangible assets, net			963				1,320
Goodwill			31,784				31,784
Long-term derivative asset			28,598				8,898
Long-term derivative receivable from Drilling Partnerships			863				—
Other assets, net			73,511				38,160
Total assets		$	2,455,870			$	1,526,652
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt		$	1,500			$	—
Accounts payable			70,228				59,720
Liabilities associated with drilling contracts			49,377				67,293
Current portion of derivative liability			6,386				—
Current portion of derivative payable to Drilling Partnerships			2,676				11,293
Accrued interest			20,649				1,155
Accrued well drilling and completion costs			40,899				47,637
Accrued liabilities			34,097				43,452
Total current liabilities			225,812				230,550
Long-term debt, less current portion			1,090,459				357,050
Long-term derivative liability			67				888
Long-term derivative payable to Drilling Partnerships			—				2,429
Asset retirement obligations and other			95,536				66,931
Commitments and contingencies
Equity:
Owner’s equity			357,378				366,066
Accumulated other comprehensive income			10,338				9,699
			367,716				375,765
Non-controlling interests			676,280				493,039
Total equity			1,043,996				868,804
Total liabilities and equity		$	2,455,870			$	1,526,652

See accompanying notes to combined consolidated financial statements.

 

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NEW ATLAS OPERATIONS AND SUBSIDIARIES

COMBINED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

 

		Years Ended December 31,
		2013				2012				2011
Revenues:
Gas and oil production		$	273,906			$	92,901			$	66,979
Well construction and completion			167,883				131,496				135,283
Gathering and processing			15,676				16,267				17,746
Administration and oversight			12,277				11,810				7,741
Well services			19,492				20,041				19,803
Other, net			(14,135	)			(3,346	)			16,527
Total revenues			475,099				269,169				264,079
Costs and expenses:
Gas and oil production			100,178				26,624				17,100
Well construction and completion			145,985				114,079				115,630
Gathering and processing			18,012				19,491				20,842
Well services			9,515				9,280				8,738
General and administrative			89,957				75,475				27,688
Chevron transaction expense			—				7,670				—
Depreciation, depletion and amortization			139,916				52,582				31,938
Asset impairment			38,014				9,507				6,995
Total costs and expenses			541,577				314,708				228,931
Operating income (loss)			(66,478	)			(45,539	)			35,148
Gain (loss) on asset sales and disposal			(987	)			(6,980	)			90
Interest expense			(39,712	)			(4,548	)			(4,244	)
Net income (loss)			(107,177	)			(57,067	)			30,994
Loss attributable to non-controlling interests			58,389				17,184				—
Net income (loss) attributable to owner		$	(48,788	)		$	(39,883	)		$	30,994

See accompanying notes to combined consolidated financial statements.

 

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NEW ATLAS OPERATIONS AND SUBSIDIARIES

COMBINED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

 

		Years Ended December 31,
		2013				2012				2011
Net income (loss)		$	(107,177	)		$	(57,067	)		$	30,994
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges			15,828				10,921				35,156
Less: reclassification adjustment for realized gains of cash flow hedges in net income (loss)			(10,216	)			(19,281	)			(10,542	)
Total other comprehensive income (loss)			5,612				(8,360	)			24,614
Comprehensive income (loss)			(101,565	)			(65,427	)			55,608
Comprehensive loss attributable to non-controlling interests			53,416				5,314				—
Comprehensive income (loss) attributable to owner		$	(48,149	)		$	(60,113	)		$	55,608

See accompanying notes to combined consolidated financial statements.

 

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NEW ATLAS OPERATIONS AND SUBSIDIARIES

COMBINED CONSOLIDATED STATEMENT OF EQUITY

(in thousands, except unit data)

 

		Owners’ Equity				Accumulated Other Comprehensive Income/(Loss)				Non-Controlling Interest				Total Equity
Balance at January 1, 2011		$	395,479			$	5,315			$	—			$	400,794
Net investment from Atlas Energy			28,946				—				—				28,946
Other comprehensive income			—				24,614				—				24,614
Net income			30,994				—				—				30,994
Balance at December 31, 2011		$	455,419			$	29,929			$	—			$	485,348
Distribution of Atlas Resource Partners, L.P. units			(84,892	)			—				84,892				—
Distributions to non-controlling interests			—				—				(13,283	)			(13,283	)
Unissued common units under incentive plan			—				—				10,797				10,797
Non-controlling interests’ capital contribution			—				—				483,277				483,277
Net distribution to Atlas Energy			(31,177	)			—				—				(31,177	)
Distribution equivalent rights paid on unissued units under incentive plans			—				—				(731	)			(731	)
Gain on sale of subsidiary unit issuances			66,599				—				(66,599	)			—
Other comprehensive income (loss)			—				(20,230	)			11,870				(8,360	)
Net loss			(39,883	)			—				(17,184	)			(57,067	)
Balance at December 31, 2012		$	366,066			$	9,699			$	493,039			$	868,804
Distributions to non-controlling interests			—				—				(73,129	)			(73,129	)
Unissued common units under incentive plan			—				—				12,630				12,630
Non-controlling interests’ capital contribution			—				—				326,421				326,421
Net investment from Atlas Energy			12,774				—				—				12,774
Distribution equivalent rights paid on unissued units under incentive plans			—				—				(1,939	)			(1,939	)
Gain on sale of subsidiary unit issuances			27,326								(27,326	)			—
Other comprehensive income			—				639				4,973				5,612
Net loss			(48,788	)			—				(58,389	)			(107,177	)
Balance at December 31, 2013		$	357,378			$	10,338			$	676,280			$	1,043,996

See accompanying notes to combined consolidated financial statements.

 

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NEW ATLAS OPERATIONS AND SUBSIDIARIES

COMBINED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

 

		Years Ended December 31,
		2013				2012				2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	(107,177	)		$	(57,067	)		$	30,994
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			139,916				52,582				31,938
Asset impairment			38,014				9,507				6,995
Amortization of deferred financing costs			10,263				1,963				391
Non-cash compensation expense			12,680				10,797				—
(Gain) loss on asset sales and disposal			987				6,980				(90	)
Distributions paid to non-controlling interests			(75,068	)			(14,014	)			—
Equity income in unconsolidated companies			(2,594	)			(1,540	)			(16,557	)
Distributions received from unconsolidated companies			1,022				931				16,195
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other			(22,283	)			(62,663	)			(1,803	)
Accounts payable and accrued liabilities			8,081				66,048				15,347
Net cash provided by operating activities			3,841				13,524				83,410
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures			(267,480	)			(127,226	)			(47,324	)
Net cash paid for acquisitions			(780,857	)			(709,832	)			—
Other			(5,187	)			(767	)			(10,660	)
Net cash used in investing activities			(1,053,524	)			(837,825	)			(57,984	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facilities			1,107,625				672,724				—
Repayments under credit facilities			(896,050	)			(315,674	)			—
Net proceeds from issuance of subsidiary long-term debt			510,396				—				—
Net proceeds from subsidiary equity offerings			326,421				483,277				—
Net investment from (distributions to) Atlas Energy			12,774				(31,177	)			28,946
Deferred financing costs, distribution equivalent rights and other			(24,128	)			(16,287	)			336
Net cash provided by financing activities			1,037,038				792,863				29,282
Net change in cash and cash equivalents			(12,645	)			(31,438	)			54,708
Cash and cash equivalents, beginning of year			23,270				54,708				—
Cash and cash equivalents, end of year		$	10,625			$	23,270			$	54,708

See accompanying notes to combined consolidated financial statements.

 

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NEW ATLAS OPERATIONS AND SUBSIDIARIES

NOTES TO COMBINED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—BASIS OF PRESENTATION

Atlas Energy Group, LLC is a Delaware limited liability company and a wholly owned subsidiary of Atlas Energy, L.P. (the “Company” or “Atlas Energy”). Atlas Energy ( NYSE: ATLS), a publicly traded Delaware master-limited partnership, intends to transfer to Atlas Energy Group, LLC Atlas Energy’s interests not related to its Atlas Pipeline Partners (“APL”) interests. Collectively, Atlas Energy Group, LLC, the entities and assets referenced below, along with the allocated entity-level activity of Atlas Energy, are considered to be “New Atlas” (see Note 2). In connection with the transfer of Atlas Energy’s interests to New Atlas, Atlas Energy intends to distribute 100% of New Atlas’s common units to common unitholders of Atlas Energy. Following the distribution of New Atlas’s common units and the transfer of assets from Atlas Energy, New Atlas’s operations will be its interests in the following:

 

•

ARP, a publicly traded Delaware master limited partnership (NYSE: ARP) and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”), with operations in basins across the United States. ARP sponsors and manages tax-advantaged investment partnerships (“Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas and oil production activities. At December 31, 2013, Atlas Energy owned 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 36.9% limited partner interest (20,962,485 common and 3,749,986 preferred limited partner units) in ARP;

 

•

Atlas Energy Development Subsidiary (“Development Subsidiary”), a subsidiary partnership formed in 2013 that conducts natural gas and oil operations initially in the mid-continent region of the United States, currently in the Marble Falls formation in the Fort Worth Basin and Mississippi Lime area of the Anadarko basin in Oklahoma. At December 31, 2013, Atlas Energy owned an 18.3% limited partner interest in the Development Subsidiary and 83.1% of its outstanding general partner Class A units, which are entitled to receive 2.0% of the cash distributed without any obligation to make further capital contributions;

 

•

Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and Lightfoot Capital Partners GP, LLC (“Lightfoot GP”), the general partner of Lightfoot L.P. (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. At December 31, 2013, Atlas Energy had an approximate 16.0% general partner interest and 12.0% limited partner interest in Lightfoot; and

 

•

coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma, which were acquired by Atlas Energy in July 2013.

In February 2012, the Board of Directors approved the formation of ARP as a newly created exploration and production master limited partnership and the related transfer of substantially all of Atlas Energy’s exploration and production assets to ARP on March 5, 2012. The Board also approved the distribution of approximately 5.24 million ARP common units to Atlas Energy’s unitholders, which were distributed on March 13, 2012 using a ratio of 0.1021 ARP limited partner units for each of Atlas Energy’s common units owned on the record date of February 28, 2012.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Combination

The combined consolidated balance sheets at December 31, 2013 and 2012 and the related combined consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011 were derived from the separate records maintained by Atlas Energy and may not necessarily be indicative of the conditions that would have existed or the results of operations if New Atlas had been operated as an unaffiliated entity. Because

 

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a direct ownership relationship did not exist among all the various entities comprising New Atlas, Atlas Energy’s net investment in New Atlas is shown as equity in the combined consolidated financial statements. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the combined consolidated balance sheets and related combined consolidated statements of operations. Such estimates included allocations made from the historical accounting records of Atlas Energy, based on management’s best estimates, in order to derive the financial statements of New Atlas. Actual balances and results could be different from those estimates. Transactions between New Atlas and other Atlas Energy operations have been identified in the combined consolidated financial statements as transactions between affiliates.

New Atlas combines the financial statements of ARP and the Development Subsidiary into its combined consolidated financial statements rather than present its ownership interest as equity investments, as New Atlas will control these entities through its general partnership interests therein. As such, the non-controlling interests in ARP and the Development Subsidiary are reflected as (income) loss attributable to non-controlling interests in its combined consolidated statements of operations and as a component of equity on its combined consolidated balance sheets. All material intercompany transactions have been eliminated.

During the year ended December 31, 2013, the Development Subsidiary issued $6.4 million of its common limited partner units, which was included within non-controlling interests on New Atlas’s combined consolidated balance sheets.

On February 17, 2011, Atlas Energy acquired certain producing natural gas and oil properties, the partnership management business, and other assets (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of its general partner (see Note 3). Management of Atlas Energy determined that the acquisition of the Transferred Business constituted a transaction between entities under common control. In comparison to the acquisition method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable assets and liabilities of the Transferred Business based upon their fair values with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to equity on New Atlas’s combined consolidated balance sheets. Also, in comparison to the acquisition method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in New Atlas’s combined consolidated financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect to the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, New Atlas reflected the impact of the acquisition of the Transferred Business on its combined consolidated financial statements in the following manner:

 

•

Recognized the assets acquired and liabilities assumed from the Transferred Business at their historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to equity;

 

•

Retrospectively adjusted its combined consolidated financial statements for any date prior to February 17, 2011, the date of acquisition, to reflect its results on a combined consolidated basis with the results of the Transferred Business as of or at the beginning of the respective period; and

 

•

Adjusted the presentation of New Atlas’s combined consolidated statements of operations for the year ended December 31, 2011 to reflect the results of operations attributable to the Transferred Business prior to the date of acquisition as a reduction of net income to determine income attributable to common limited partners. However, the Transferred Business’s historical financial statements prior to the date of acquisition do not reflect general and administrative expenses and interest expense. The Transferred Business was not managed by AEI as a separate business segment and did not have

 

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identifiable labor and other ancillary costs. The general and administrative and interest expenses of AEI prior to the date of acquisition, including the exploration and production business segment, related primarily to business activities associated with the business sold to Chevron Corporation in February 2011 and not activities related to the Transferred Business.

In accordance with established practice in the oil and gas industry, New Atlas’s combined consolidated financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the Drilling Partnerships in which ARP has an interest. Such interests generally approximate 30%. New Atlas’s combined consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of ARP’s Drilling Partnerships. Rather, ARP calculates these items specific to its own economics as further explained under the heading “Property, Plant and Equipment” elsewhere within this note.

In connection with ARP’s acquisition of certain proved reserves and associated assets from Titan Operating, L.L.C. in July 2012 (see Note 4), ARP issued 3.8 million ARP common units and 3.8 million newly created convertible Class B ARP preferred units (see Note 13). While outstanding, the preferred units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. At December 31, 2013 and 2012, ARP recorded $96.5 million and $96.2 million, respectively, related to the Class B preferred units within non-controlling interests on New Atlas’s combined consolidated statements of equity.

Use of Estimates

The preparation of New Atlas’s combined consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of New Atlas’s combined consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. New Atlas’s combined consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired and liabilities assumed. Such estimates included estimated allocations made from the historical accounting records of: 1) Atlas Energy in order to derive the historical financial statements of New Atlas, and 2) AEI in order to derive the historical financial statements of the Transferred Business prior to February 17, 2011, the date of acquisition. Actual results could differ from those estimates.

Cash Equivalents

New Atlas considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments.

Receivables

Accounts receivable on the combined consolidated balance sheets consist primarily of the trade accounts receivable associated with New Atlas. In evaluating the realizability of its accounts receivable, management performs ongoing credit evaluations of customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of customers’ credit information. New Atlas extends credit on sales on an unsecured basis to many of its customers. At December 31, 2013 and 2012, New Atlas had recorded no allowance for uncollectible accounts receivable on its combined consolidated balance sheets.

Inventory

New Atlas had $4.6 million and $5.3 million of inventory at December 31, 2013 and 2012, respectively, which were included within prepaid expenses and other current assets on its combined consolidated balance

 

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sheets. New Atlas values inventories at the lower of cost or market. New Atlas’s inventories, which consist primarily of ARP’s materials, pipes, supplies and other inventories, were principally determined using the average cost method.

Subscriptions Receivable

ARP receives contributions from limited partner investors of its Drilling Partnerships, which are used to fund well drilling activities within the programs. Limited partner investors in the Drilling Partnerships execute an investment agreement with Anthem Securities, Inc. (“Anthem”), a registered broker dealer and wholly owned subsidiary of ARP, through third-party broker dealers, which are then delivered to Anthem with the contribution remitted to Anthem at a later date. Limited partner investor contributions are non-refundable upon the execution of an investment agreement. ARP recognizes the contributions associated with executed investment agreements but for which contributions have not yet been received at the respective balance sheet date as subscriptions receivable.

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements which generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in New Atlas’s results of operations.

New Atlas follows the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. “Mcf” is defined as one thousand cubic feet.

New Atlas’s and ARP’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include ARP’s costs of property interests in proportionately consolidated Drilling Partnerships, joint venture wells, wells drilled solely by ARP for its interests, properties purchased and working interests with other outside operators.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to New Atlas’s combined consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within New Atlas’s combined consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in New Atlas’s combined consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

 

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Impairment of Long-Lived Assets

New Atlas reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on New Atlas’s and ARP’s plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. New Atlas estimates prices based upon current contracts in place, adjusted for basis differentials and market-related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, ARP’s reserve estimates for its investment in the Drilling Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include ARP’s actual capital contributions and a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

ARP’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to ARP their proportionate share of these expenses plus a profit margin. These assumptions could result in ARP’s calculation of depletion and impairment being different than its proportionate share of the Drilling Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. New Atlas and ARP cannot predict what reserve revisions may be required in future periods.

ARP’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Drilling Partnerships, which ARP sponsors and owns an interest in but does not control. ARP’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which ARP may be unable to recover due to the Drilling Partnerships’ legal structure. ARP may have to pay additional consideration in the future as a Drilling Partnership’s wells become uneconomic to the Drilling Partnership under the terms of the Drilling Partnership’s drilling and operating agreement in order to recover these excess reserves, in addition to ARP becoming responsible for paying associated future operating, development and plugging costs of the well interests acquired, and to acquire any additional residual interests in the wells held by the Drilling Partnership’s limited partners. The acquisition of any such uneconomic well interest from the Drilling Partnership by ARP is governed under the Drilling Partnership’s limited partner agreement. In general, ARP will seek consent from the Drilling Partnership’s limited partners to acquire the well interests from the Drilling Partnership based upon ARP’s determination of fair market value.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions

 

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indicate that New Atlas will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. During the year ended December 31, 2013, ARP recognized $13.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on New Atlas’s combined consolidated balance sheet primarily for its unproved acreage in the Chattanooga and New Albany shales. There were no impairments of unproved gas and oil properties recorded on New Atlas’s combined consolidated statements of operations for the years ended December 31, 2012 and 2011.

Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2013, ARP recognized $24.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on New Atlas’s combined consolidated balance sheet for ARP’s shallow natural gas wells in the New Albany Shale. During the year ended December 31, 2012, New Atlas recognized $9.5 million of asset impairments related to ARP’s gas and oil properties within property, plant and equipment, net on its combined consolidated balance sheet for its shallow natural gas wells in the Antrim and Niobrara shales. During the year ended December 31, 2011, New Atlas recognized $7.0 million of asset impairment related to ARP’s gas and oil properties within property, plant and equipment, net on its combined consolidated balance sheet for its shallow natural gas wells in the Niobrara Shale.

These impairments related to the carrying amounts of these gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2013, 2012 and 2011 and ARP’s intention not to drill on certain expiring unproved acreage. The estimate of the fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

Capitalized Interest

ARP capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP were 6.0% and 3.5% for the years ended December 31, 2013 and 2012, respectively. The amounts of interest capitalized by ARP were $14.2 million and $2.1 million for the years ended December 31, 2013 and 2012, respectively. There was no interest capitalized by ARP during the year ended December 31, 2011.

Intangible Assets

ARP has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. ARP amortizes contracts acquired on a declining balance method over their respective estimated useful lives.

The following table reflects the components of intangible assets being amortized at December 31, 2013 and 2012 (in thousands):

 

		December 31,								Estimated Useful Lives In Years
		2013				2012
Gross Carrying Amount		$	14,344			$	14,344				13
Accumulated Amortization			(13,381	)			(13,024	)
Net Carrying Amount		$	963			$	1,320

Amortization expense on intangible assets was $0.4 million, $0.2 million and $0.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. Aggregate estimated annual amortization expense for all

 

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of the contracts described above for the next five years ending December 31 is as follows: 2014—$0.3 million; 2015—$0.2 million; 2016—$0.1 million; 2017—$0.1 million; and 2018—$0.1 million.

Goodwill

At December 31, 2013 and 2012, New Atlas had $31.8 million of goodwill recorded in connection with ARP’s prior consummated acquisitions. No changes in the carrying amount of goodwill were recorded for the years ended December 31, 2013, 2012 and 2011.

ARP tests goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units. ARP’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets and the available market data of the respective industry group. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including ARP’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, ARP also considers the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ARP’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in ARP’s industry to determine whether those valuations appear reasonable in management’s judgment. ARP’s management will continue to evaluate goodwill at least annually or when impairment indicators arise. During the years ended December 31, 2013, 2012 and 2011, no impairment indicators arose, and no goodwill impairments were recognized for ARP by New Atlas.

Derivative Instruments

New Atlas enters into certain financial contracts to manage their exposure to movement in commodity prices and interest rates (see Note 9). The derivative instruments recorded in the combined consolidated balance sheets were measured as either an asset or liability at fair value. Changes in the fair value of derivative instruments are recognized currently in New Atlas’s combined consolidated statements of operations unless specific hedge accounting criteria are met.

Asset Retirement Obligations

New Atlas recognizes an estimated liability for the plugging and abandonment of gas and oil wells and related facilities (see Note 7). New Atlas also recognizes a liability for future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. New Atlas also considers the estimated salvage value in the calculation of depreciation, depletion and amortization.

Income Taxes

ARP, Development Subsidiary, Lightfoot and the respective subsidiaries thereof are not subject to U.S. federal and most state income taxes. The partners of these entities are liable for income tax in regard to their distributive share of the entities’ taxable income. Such taxable income may vary substantially from net income

 

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(loss) reported in the accompanying combined consolidated financial statements. Certain corporate subsidiaries of ARP are subject to federal and state income tax. The federal and state income taxes related to New Atlas and these corporate subsidiaries were immaterial to the combined consolidated financial statements as of December 31, 2013 and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for these corporate subsidiaries in the accompanying combined consolidated financial statements.

Each of the entities which comprise New Atlas evaluate tax positions taken or expected to be taken in the course of preparing their respective tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. New Atlas’s management does not believe it has any tax positions taken within its combined consolidated financial statements that would not meet this threshold. New Atlas’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. New Atlas has not recognized any potential interest or penalties in its combined consolidated financial statements for the years ended December 31, 2013, 2012 and 2011.

The entities comprising New Atlas file Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the entities comprising New Atlas are no longer subject to income tax examinations by major tax authorities for years prior to 2010 and are not currently being examined by any jurisdiction and are not aware of any potential examinations as of December 31, 2013.

General and Administrative Expenses

For the years ended December 31, 2013, 2012 and 2011, Atlas Energy has allocated $8.2 million, $6.4 million and $0.2 million, respectively, of its historical general and administrative expenses to New Atlas according to the amounts associated with the management of New Atlas’s operations. New Atlas has reviewed Atlas Energy’s general and administrative expense allocation methodology and believes the methodology is reasonable and reflects the approximate general and administrative costs of the management of its operations.

Interest Expense

For the years ended December 31, 2013, 2012 and 2011, Atlas Energy has allocated $5.4 million, $0.4 million and $4.2 million, respectively, of its historical interest expense to New Atlas according to the amounts associated with the financing of New Atlas’s operations. New Atlas has reviewed Atlas Energy’s interest expense allocation methodology and believes the methodology is reasonable and reflects the approximate interest expense associated with the management of its operations.

Stock-Based Compensation

ARP recognizes all share-based payments to employees, including grants of employee stock options, in the combined consolidated financial statements based on their fair values (see Note 15).

Environmental Matters

New Atlas is subject to various federal, state and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of New Atlas’s operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. New Atlas maintains insurance which may cover in whole or in part certain environmental expenditures. New Atlas had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, 2013 and 2011. During the

 

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year ended December 31, 2012, one of ARP’s subsidiaries entered into two agreements with the United States Environmental Protection Agency (the “EPA”) to settle alleged violations in connection with a fire that occurred at a natural gas well and associated well pad site in Washington County, Pennsylvania in 2010. The EPA alleged non-compliance with the Clean Air Act, including with respect to the storage and handling of the natural gas condensate, as well as non-compliance with the Emergency Planning and Community Right-to-Know Act of 1986. The subsidiary agreed to a civil penalty of $84,506 under a consent agreement and agreed to upgrade its facility pursuant to an administrative settlement agreement.

Concentration of Credit Risk

Financial instruments, which potentially subject New Atlas to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. New Atlas places its temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. At December 31, 2013 and 2012, New Atlas had $23.9 million and $37.1 million, respectively, in deposits at various banks, of which $21.9 million and $35.1 million, respectively, were over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date. Cash on deposit at various banks may differ from the balance of cash and cash equivalents at period end due to certain reconciling items, including any outstanding checks as of period end.

New Atlas sells natural gas, oil, NGLs and condensate under contract to various purchasers in the normal course of business. For the year ended December 31, 2013, ARP had three customers that individually accounted for approximately 19%, 11% and 10%, respectively, of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2012, ARP had two customers that individually accounted for approximately 43% and 11%, respectively, of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2011, ARP had three customers that individually accounted for approximately 17%, 14% and 10% respectively, of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity.

Revenue Recognition

Natural gas and oil production. New Atlas and ARP’s gas and oil production operations generally sell natural gas, crude oil and NGLs at prevailing market prices. Typically, sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which New Atlas has an interest with other producers, are recognized on the basis of the entity’s percentage ownership of the working interest and/or overriding royalty.

ARP’s Drilling Partnerships. Certain energy activities are conducted by ARP through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by ARP is deployed to drill and complete wells included within the partnership. As ARP deploys Drilling Partnership investor capital, it recognizes certain management fees it is entitled to receive, including well construction and completion revenue and a portion of administration and oversight revenue. At each period end, if ARP has Drilling Partnership investor capital that has not yet been deployed, it will recognize a current liability titled “Liabilities Associated with Drilling Contracts” on New Atlas’s combined consolidated balance sheets. After the Drilling Partnership well is completed and turned in line, ARP is entitled to receive additional operating and management fees, which are included within well services and administration and oversight revenue, respectively, on a monthly basis while the well is operating. In addition to the management fees it is

 

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entitled to receive for services provided, ARP is also entitled to its pro-rata share of Drilling Partnership gas and oil production revenue, which generally approximate 30%. ARP recognizes its Drilling Partnership management fees in the following manner:

 

•

Well construction and completion. For each well that is drilled by a Drilling Partnership, ARP receives a 15% mark-up on those costs incurred to drill and complete wells included within the partnership. Such fees are earned, in accordance with the partnership agreement, and recognized as the services are performed, typically between 60 and 270 days, using the percentage of completion method.

 

•

Administration and oversight. For each well drilled by a Drilling Partnership, ARP receives a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which is earned, in accordance with the partnership agreement, and recognized at the initiation of the well. Additionally, the Drilling Partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. The well administrative fee is earned on a monthly basis as the services are performed.

 

•

Well services. Each Drilling Partnership pays ARP a monthly per well operating fee, currently $100 to $2,000, depending on the type of well, for the life of the well. Such fees are earned on a monthly basis as the services are performed.

While its historical structure has varied, ARP has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically 10% per year determined on a cumulative basis and inclusive of estimated individual tax benefits, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. ARP periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, ARP recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which ARP has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, ARP will recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized.

ARP’s gathering and processing revenue. Gathering and processing revenue includes gathering fees ARP charges to the Drilling Partnership wells for ARP’s processing plants in the New Albany and the Chattanooga shales. Generally, ARP charges a gathering fee to the Drilling Partnership wells equivalent to the fees ARP remits. In Appalachia, a majority of the Drilling Partnership wells are subject to a gathering agreement, whereby ARP remits a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, ARP charges the Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%.

New Atlas and ARP’s gas and oil production operations accrue unbilled revenue due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” for further description). New Atlas had unbilled revenues at December 31, 2013 and 2012 of $56.9 million and $33.4 million, respectively, which were included in accounts receivable within its combined consolidated balance sheets.

 

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Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on New Atlas’s combined consolidated financial statements, and for all periods presented, only include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges (see Note 9). New Atlas does not have any other type of transaction which would be included within other comprehensive income (loss).

Recently Adopted Accounting Standards

In February 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. New Atlas adopted the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures.

Recently Issued Accounting Standards

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early adoption is permitted. New Atlas will adopt the requirements of Update 2014-15 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In June 2014, the FASB issued ASU 2014-12, Compensation—Stock Compensation (Topic 718) (“Update 2014-12”). The amendments in Update 2014-12 require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to

 

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reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in Update 2014-12 are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. New Atlas will adopt the requirements of Update 2014-12 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles—Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. New Atlas will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2017, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

NOTE 3—ACQUISITION FROM ATLAS ENERGY, INC.

On February 17, 2011, Atlas Energy acquired the Transferred Business from AEI, including the following exploration and production assets that were transferred to ARP on March 5, 2012:

 

•

AEI’s investment management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which ARP funds a portion of its natural gas and oil well drilling;

 

•

proved reserves located in the Appalachian Basin, the Niobrara formation in Colorado, the New Albany Shale of west central Indiana, the Antrim Shale of northern Michigan and the Chattanooga Shale of northeastern Tennessee; and

 

•

certain producing natural gas and oil properties, upon which ARP is the developer and producer.

In addition to the exploration and production assets, the Transferred Business also included all of the ownership interests in Atlas Energy GP, LLC, Atlas Energy’s general partner, and a direct and indirect ownership interest in Lightfoot.

For the assets acquired and liabilities assumed, Atlas Energy issued approximately 23.4 million of its common limited partner units and paid $30.0 million in cash consideration. Based on Atlas Energy’s February 17, 2011 common unit closing price of $15.92, the common units issued to AEI were valued at approximately $372.2 million. Concurrent with Atlas Energy’s acquisition of the Transferred Business, AEI was sold to Chevron Corporation (NYSE: CVX) (“Chevron”). In connection with the transaction, Atlas Energy received $118.7 million with respect to a contractual cash transaction adjustment from AEI related to certain exploration and production liabilities assumed by Atlas Energy. Including the cash transaction adjustment, the

 

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net book value of the Transferred Business was approximately $522.9 million. Certain amounts included within the contractual cash transaction adjustment were subject to a reconciliation period with Chevron following the consummation of the transaction. Liabilities related to the cash transaction adjustment were assumed by ARP on March 5, 2012, as certain amounts included within the contractual cash transaction adjustment remained in dispute between the parties. During the year ended December 31, 2012, ARP recognized a $7.7 million charge on New Atlas’s combined consolidated statement of operations regarding its reconciliation process with Chevron, which was settled in October 2012.

Concurrent with Atlas Energy’s acquisition of the Transferred Business on February 17, 2011, including assets and liabilities transferred to ARP on March 5, 2012, AEI completed its merger with Chevron, whereby AEI became a wholly owned subsidiary of Chevron.

Management of Atlas Energy determined that the acquisition of the Transferred Business constituted a transaction between entities under common control. As such, Atlas Energy recognized the assets acquired and liabilities assumed at historical carrying value at the date of acquisition, with the difference between the purchase price and the net book value of the assets recognized as an adjustment to equity on New Atlas’s combined consolidated balance sheet. Atlas Energy recognized a non-cash decrease of $261.0 million in equity on New Atlas’s combined consolidated balance sheet based on the excess net book value above the value of the consideration paid to AEI. The following table presents the historical carrying value of the assets acquired and liabilities assumed by Atlas Energy, including the effect of cash transaction adjustments, as of February 17, 2011 (in thousands):

 

Cash		$	153,350
Accounts receivable			18,090
Accounts receivable—affiliate			45,682
Prepaid expenses and other			6,955
Total current assets			224,077
Property, plant and equipment, net			516,625
Goodwill			31,784
Intangible assets, net			2,107
Other assets, net			20,416
Total long-term assets			570,932
Total assets acquired		$	795,009
Accounts payable		$	59,202
Net liabilities associated with drilling contracts			47,929
Accrued well completion costs			39,552
Current portion of derivative payable to Drilling Partnerships			25,659
Accrued liabilities			25,283
Total current liabilities			197,625
Long-term derivative payable to Drilling Partnerships			31,719
Asset retirement obligations			42,791
Total long-term liabilities			74,510
Total liabilities assumed		$	272,135
Historical carrying value of net assets acquired		$	522,874

New Atlas reflected the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which the Transferred Business was acquired and retrospectively adjusted its prior year financial statements to furnish comparative information (see Note 2).

 

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NOTE 4—ACQUISITIONS

ARP’s EP Energy Acquisition

On July 31, 2013, ARP completed an acquisition of assets from EP Energy E&P Company, L.P. (“EP Energy”) for approximately $709.6 million in cash, net of purchase price adjustments (the “EP Energy Acquisition”). ARP funded the purchase price through borrowings under its revolving credit facility, the issuance of its 9.25% senior notes due 2021 (“9.25% ARP Senior Notes”) (see Note 8), and the issuance of 14,950,000 ARP common limited partner units and 3,749,986 newly created ARP Class C convertible preferred units (see Note 13). The assets acquired by ARP in the EP Energy Acquisition included coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming. The EP Energy Acquisition had an effective date of May 1, 2013. The accompanying combined consolidated financial statements reflect the operating results of the acquired business commencing July 31, 2013 with the transaction closing.

ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 10). In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $12.1 million of transaction fees which were included within non-controlling interests for the year ended December 31, 2013 on New Atlas’s combined consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. As of December 31, 2013, the accounting for the business combination was based upon preliminary data that remained subject to adjustment and could further change as ARP continued to evaluate the facts and circumstances that existed as of the acquisition date. During the six months ended June 30, 2014, the purchase price allocation was finalized with no material change.

The following table presents the values assigned to the assets acquired and liabilities assumed in the EP Energy Acquisition, based on their estimated fair values at the date of the acquisition (in thousands):

 

Assets:
Property, plant and equipment		$	728,925
Liabilities:
Accounts payable			2,562
Asset retirement obligation			16,728
Total liabilities assumed			19,290
Net assets acquired		$	709,635

Revenues and net loss of $66.1 million and $5.2 million, respectively, have been included in New Atlas’s combined consolidated statements of operations related to the EP Energy Acquisition for the year ended December 31, 2013.

ARP’s DTE Acquisition

On December 20, 2012, ARP completed the acquisition of DTE Gas Resources, L.L.C. from DTE Energy Company (NYSE: DTE; “DTE”) for $257.4 million (the “DTE Acquisition”). In connection with entering into a purchase agreement related to the DTE Acquisition, ARP issued approximately 7.9 million of its common limited partner units through a public offering in November 2012 for $174.5 million, which was used to partially repay amounts outstanding under its revolving credit facility prior to closing (see Note 13). The cash paid at closing was funded through $179.8 million of borrowings under ARP’s revolving credit facility and $77.6 million through borrowings under ARP’s then-existing term loan credit facility (see Note 8).

ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values

 

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(see Note 10). In conjunction with the issuance of common units associated with the acquisition, ARP recorded $0.2 million of transaction fees which were included within non-controlling interests for the year ended December 31, 2012 on New Atlas’s combined consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred.

The following table presents the values assigned to the assets acquired and liabilities assumed in the DTE Acquisition, based on their estimated fair values at the date of the acquisition (in thousands):

 

Assets:
Accounts receivable		$	10,721
Prepaid expenses and other			2,100
Total current assets			12,821
Property, plant and equipment			263,194
Other assets, net			273
Total assets acquired		$	276,288
Liabilities:
Accounts payable		$	7,760
Accrued liabilities			2,910
Total current liabilities			10,670
Asset retirement obligation and other			8,169
Total liabilities assumed			18,839
Net assets acquired		$	257,449

ARP’s Titan Acquisition

On July 25, 2012, ARP completed the acquisition of Titan Operating, L.L.C. (“Titan”) in exchange for 3.8 million common units and 3.8 million newly created convertible Class B preferred units (which had an estimated collective value of $193.2 million, based upon the closing price of ARP’s publicly traded units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments (see Note 13). The cash paid at closing was funded through borrowings under ARP’s credit facility. The common units and preferred units were issued and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”) (see Note 13). ARP’s acquisition of Titan in exchange for 3.8 million ARP common units and 3.8 million newly created convertible ARP Class B preferred units represented a non-cash transaction during the year ended December 31, 2012.

ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 10). In conjunction with its issuance of common and preferred limited partner units associated with the acquisition, ARP recorded $3.5 million of transaction fees, which were included within non-controlling interests for the year ended December 31, 2012 on New Atlas’s combined consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred.

 

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The following table presents the values assigned to the assets acquired and liabilities assumed in the acquisition of Titan, based on their estimated fair values at the date of the acquisition (in thousands):

 

Assets:
Cash and cash equivalents		$	372
Accounts receivable			5,253
Prepaid expenses and other			131
Total current assets			5,756
Property, plant and equipment			208,491
Other assets, net			2,344
Total assets acquired		$	216,591
Liabilities:
Accounts payable		$	676
Revenue distribution payable			3,091
Accrued liabilities			1,816
Total current liabilities			5,583
Asset retirement obligation and other			2,418
Total liabilities assumed			8,001
Net assets acquired		$	208,590

ARP’s Carrizo Acquisition

On April 30, 2012, ARP completed the acquisition of certain oil and natural gas assets from Carrizo Oil and Gas, Inc. (NASDAQ: CRZO; “Carrizo”) for approximately $187.0 million in cash (the “Carrizo Acquisition”). The purchase price was funded through borrowings under ARP’s credit facility and $119.5 million of net proceeds from the sale of 6.0 million of its common units at a negotiated purchase price per unit of $20.00, of which $5.0 million was purchased by certain executives of Atlas Energy. The common units were issued in a private transaction exempt from registration under Section 4(2) of the Securities Act (see Note 13).

ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 10). In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $1.2 million of transaction fees which were included within non-controlling interests for the year ended December 31, 2012 on New Atlas’s combined consolidated balance sheet. All other costs associated with ARP’s acquisition of assets were expensed as incurred.

The following table presents the values assigned to the assets acquired and liabilities assumed in the Carrizo Acquisition, based on their estimated fair values at the date of the acquisition (in thousands):

 

Assets:
Property, plant and equipment		$	190,946
Liabilities:
Asset retirement obligation			3,903
Net assets acquired		$	187,043

 

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Pro Forma Financial Information

The following data presents pro forma revenues and net income (loss) for New Atlas as if the EP Energy, DTE, Titan, and Carrizo acquisitions, including the related borrowings under the respective revolving credit facilities, net proceeds from the issuance of debt and issuances of common and preferred units had occurred on January 1, 2012. For the year ended December 31, 2013, New Atlas has also included the pro forma effect of the Rangely Acquisition and its related financings (see Note 17). Pro forma financial information related to the Rangely Acquisition for the year ended December 31, 2012 was not available. New Atlas prepared these pro forma unaudited financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the EP Energy, DTE, Titan and Carrizo acquisitions and related offerings, borrowings, and issuances had occurred on January 1, 2012 or the results that will be attained in future periods (in thousands, except per unit data; unaudited):

 

		Years Ended December 31,
		2013				2012
Total revenues and other		$	671,780			$	469,023
Net loss			(18,081	)			(127,898	)
Net loss attributable to owner			(21,077	)			(62,410	)

Other Acquisitions

In April 2012, ARP acquired a 50% interest in approximately 14,500 net undeveloped acres in the oil and NGL area of the Mississippi Lime play in northwestern Oklahoma for $18.0 million from subsidiaries of Equal Energy, Ltd. (“Equal”) (NYSE: EQU; TSX: EQU). The transaction was funded through borrowings under ARP’s revolving credit facility. Concurrent with the purchase of acreage, ARP and Equal entered into a participation and development agreement for future drilling in the Mississippi Lime play. ARP served as the drilling and completion operator, while Equal undertook production operations, including water disposal. In September 2012, ARP acquired Equal’s remaining 50% interest in the undeveloped acres, as well as approximately 8 MMcfed of net production in the Mississippi Lime region and salt water disposal infrastructure for $41.3 million. Both transactions were funded through borrowings under ARP’s revolving credit facility. As a result of ARP’s acquisition of Equal’s remaining interest in the undeveloped acres, the existing joint venture agreement between ARP and Equal in the Mississippi Lime position was terminated and all infrastructure associated with the assets, principally the salt water disposal system, is operated by ARP.

In July 2013, Atlas Energy completed the acquisition of certain natural gas and oil producing assets in the Arkoma Basin from EP Energy for approximately $64.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). The Arkoma Acquisition was funded with a portion of the proceeds from the issuance of Atlas Energy’s term loan facility (see Note 8). The Arkoma Acquisition had an effective date of May 1, 2013.

In September 2013, ARP completed the acquisition of certain assets from Norwood Natural Resources (“Norwood”) for $5.4 million (the “Norwood Acquisition”). The assets acquired included Norwood’s non-operating working interest in certain producing wells in the Barnett Shale. The Norwood Acquisition had an effective date of June 1, 2013.

 

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NOTE 5—PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment at the dates indicated (in thousands):

 

		December 31,								Estimated Useful Lives in Years
		2013				2012
Natural gas and oil properties:
Proved properties:
Leasehold interests		$	322,217			$	244,476
Pre-development costs			4,367				1,935
Wells and related equipment			2,231,213				1,222,475
Total proved properties			2,557,797				1,468,886
Unproved properties			211,851				292,053
Support equipment			23,258				13,110
Total natural gas and oil properties			2,792,906				1,774,049
Pipelines, processing and compression facilities			43,120				33,092			2–40
Rights of way			830				784			20–40
Land, buildings and improvements			9,462				8,283			3–40
Other			15,321				9,762			3–10
			2,861,639				1,825,970
Less—accumulated depreciation, depletion and amortization			(674,956	)			(523,742	)
		$	2,186,683			$	1,302,228

During the year ended December 31, 2013, New Atlas recognized $1.0 million of loss on asset sales and disposal primarily pertaining to ARP’s loss on the sale of its Antrim assets. During the year ended December 31, 2012, New Atlas recognized a $7.0 million loss on asset sales and disposal pertaining to ARP’s decision to terminate a farm-out agreement with a third party for well drilling in the South Knox area of the New Albany Shale that was originally entered into in 2010. The farm-out agreement contained certain well drilling targets for ARP to maintain ownership of the South Knox processing plant, which ARP’s management decided in 2012 to not achieve due to the then current natural gas price environment. As a result, ARP forfeited its interest in the processing plant and related properties and recorded a loss related to the net book values of those assets during the year ended December 31, 2012.

During the year ended December 31, 2013, ARP recognized $38.0 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on New Atlas’s combined consolidated balance sheet primarily for its shallow natural gas wells in the New Albany Shale and unproved acreage in the Chattanooga and New Albany shales. During the year ended December 31, 2012, ARP recognized $9.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on New Atlas’s combined consolidated balance sheet for ARP’s shallow natural gas wells in the Antrim and Niobrara shales. During the year ended December 31, 2011, ARP recognized $7.0 million of asset impairment related to its gas and oil properties within property, plant and equipment, net on New Atlas’s combined consolidated balance sheet for ARP’s shallow natural gas wells in the Niobrara Shale.

These impairments related to the carrying amounts of gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2013, 2012 and 2011 and ARP’s intention not to drill on certain expiring unproved acreage. The estimate of fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

During the years ended December 31, 2013, 2012 and 2011, the Company recognized $11.4 million, $11.0 million, and $3.3 million of non-cash property, plant and equipment additions, respectively, which were excluded

 

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within the changes in accounts payable and accrued liabilities on New Atlas’s combined consolidated statement of cash flows for such years.

NOTE 6—OTHER ASSETS

The following is a summary of other assets at the dates indicated (in thousands):

 

		December 31,
		2013				2012
Deferred financing costs, net of accumulated amortization of $12,731 and $2,469 at December 31, 2013 and 2012, respectively		$	41,686			$	14,883
Investment in Lightfoot			21,454				19,882
Rabbi Trust			3,705				1,740
Security deposits			264				293
ARP notes receivable			3,978				—
Other			2,424				1,362
		$	73,511			$	38,160

Deferred financing costs. Deferred financing costs are recorded at cost and amortized over the terms of the respective debt agreements (see Note 8). Amortization expense of New Atlas’s deferred financing costs was $7.0 million, $2.0 million and $0.4 million for the years ended December 31, 2013, 2012 and 2011, respectively, which was recorded within interest expense on New Atlas’s combined consolidated statements of operations. During the year ended December 31, 2011, New Atlas recognized an additional $3.1 million of accelerated amortization of its deferred financing costs associated with the retirement of its $70.0 million credit facility, which was recorded within interest expense on New Atlas’s combined consolidated statement of operations. There was no accelerated amortization of deferred financing costs for New Atlas during the years ended December 31, 2013 and 2012.

During the year ended December 31, 2013, ARP recognized an additional $3.2 million for accelerated amortization of deferred financing costs associated with the retirement of a portion of its then-existing term loan facility and a portion of the outstanding indebtedness under its revolving credit facility with a portion of the proceeds from its issuance of senior unsecured notes due 2021 (“7.75% ARP Senior Notes”) (see Note 8). There was no accelerated amortization of deferred financing costs for ARP during the years ended December 31, 2012 and 2011.

ARP notes receivable. At December 31, 2013, ARP had notes receivable with certain investors of its Drilling Partnerships, which were included within other assets on New Atlas’s combined consolidated balance sheet. The notes have a maturity date of March 31, 2022, and a 2.25% per annum interest rate. The maturity date of the notes can be extended to March 31, 2027, subject to certain closing conditions, including an extension fee of 1.0% of the outstanding principal balance. For the year ended December 31, 2013, $0.1 million of interest income was recognized within other, net on New Atlas’s combined consolidated statement of operations. There was no interest income recognized for the years ended December 31, 2012 and 2011. At December 31, 2013, ARP recorded no allowance for credit losses within New Atlas’s combined consolidated balance sheet based upon payment history and ongoing credit evaluations associated with the ARP notes receivable.

Investment in Lightfoot. At December 31, 2013, New Atlas included in other assets an approximate 12% interest in Lightfoot L.P. and an approximate 16% interest in Lightfoot G.P., the general partner of Lightfoot L.P., an entity for which Jonathan Cohen, Executive Chairman of the General Partner’s board of directors, is the Chairman of the Board. Lightfoot L.P. focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt. New Atlas accounts for its investment in Lightfoot under the equity method of accounting. During the years ended December 31, 2013, 2012 and 2011,

 

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New Atlas recognized equity income of approximately $2.6 million, $1.5 million and $16.6 million, respectively, within other, net on New Atlas’s combined consolidated statements of operations. During the year ended December 31, 2011, New Atlas recognized a gain associated with its equity ownership interest in Lightfoot of $15.0 million pertaining to its share of Lightfoot L.P.’s gain recognized on the sale of International Resource Partners L.P. (“IRP”), its metallurgical and steam coal business, in March 2011. During the years ended December 31, 2013, 2012 and 2011, New Atlas received net cash distributions of approximately $1.0 million, $0.9 million and $16.2 million, respectively. The net cash distributions received in 2011 included $14.2 million, representing its share of the cash distribution made to investors by Lightfoot L.P. with proceeds from the IRP sale.

On November 6, 2013, Arc Logistics Partners, L.P. (“ARCX”), an MLP, owned and controlled by Lightfoot, which is involved in terminalling, storage, throughput and transloading of crude oil and petroleum products, began trading publicly on the NYSE under the ticker symbol “ARCX”.

NOTE 7—ASSET RETIREMENT OBLIGATIONS

New Atlas and ARP recognized an estimated liability for the plugging and abandonment of their respective gas and oil wells and related facilities. New Atlas and ARP also recognized a liability for their respective future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. New Atlas and ARP also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability for asset retirement obligations was based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. New Atlas and ARP have no assets legally restricted for purposes of settling asset retirement obligations. Except for New Atlas and ARP’s gas and oil properties, there were no other material retirement obligations associated with tangible long-lived assets.

ARP proportionately consolidates its ownership interest of the asset retirement obligations of its Drilling Partnerships. At December 31, 2013, the Drilling Partnerships had $59.7 million of aggregate asset retirement obligation liabilities recognized on their combined balance sheets allocable to the limited partners, exclusive of ARP’s proportional interest in such liabilities. Under the terms of the respective partnership agreements, ARP maintains the right to retain a portion or all of the distributions to the limited partners of its Drilling Partnerships to cover the limited partners’ share of the plugging and abandonment costs up to a specified amount per month. During the year ended December 31, 2013, ARP withheld approximately $0.3 million of limited partner distributions related to the asset retirement obligations of certain Drilling Partnerships. No amounts were withheld during the years ended December 31, 2012 and 2011. ARP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within each Drilling Partnership near the end of their useful life. On a partnership-by-partnership basis, ARP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors, including commodity price trends, the natural decline in the production of the wells, and current and future costs. Generally, ARP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon ARP’s decision to retain all future distributions to the limited partners of its Drilling Partnerships, ARP will assume the related asset retirement obligations of the limited partners.

 

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A reconciliation of New Atlas and ARP’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):

 

		Years Ended December 31
		2013				2012				2011
Asset retirement obligations, beginning of year		$	64,794			$	45,779			$	42,673
Liabilities incurred			23,129				16,568				713
Liabilities settled			(1,188	)			(546	)			(209	)
Accretion expense			4,479				2,993				2,602
Asset retirement obligations, end of year		$	91,214			$	64,794			$	45,779

The above accretion expense was included in depreciation, depletion and amortization in New Atlas’s combined consolidated statements of operations and the asset retirement obligation liabilities were included within asset retirement obligations and other in New Atlas’s combined consolidated balance sheets. During the year ended December 31, 2013, New Atlas incurred $1.3 million of future plugging and abandonment costs related to the Arkoma Acquisition, which Atlas Energy consummated during the period. During the year ended December 31, 2013, ARP incurred $16.7 million of future plugging and abandonment costs related to the EP Energy Acquisition it consummated during the period. During the year ended December 31, 2012, ARP incurred $15.6 million of future plugging and abandonment costs related to acquisitions it consummated during the period.

NOTE 8—DEBT

Total debt consists of the following at the dates indicated (in thousands):

 

		December 31,
		2013				2012
Term loan facility		$	149,625			$	—
Revolving credit facility			—				5,625
ARP revolving credit facility			419,000				276,000
ARP term loan credit facility			—				75,425
ARP 7.75% Senior Notes—due 2021			275,000				—
ARP 9.25% Senior Notes—due 2021			248,334				—
Total debt			1,091,959				357,050
Less current maturities			(1,500	)			—
Total long-term debt		$	1,090,459			$	357,050

Term Loan Facility

In July 2013, Atlas Energy entered into a $240.0 million secured term loan credit facility (“Term Facility”). At December 31, 2013, $149.6 million of the Term Facility was attributable to New Atlas. The Term Facility has a maturity date of July 31, 2019. Borrowings under the Term Facility bear interest, at Atlas Energy’s election at either an adjusted LIBOR rate plus an applicable margin of 5.50% per annum or the alternate base rate (as defined in the Term Facility) (“ABR”) plus an applicable margin of 4.50% per annum. Interest is generally payable quarterly for ABR loans and, for LIBOR loans at the interest periods selected by Atlas Energy. Atlas Energy is required to repay principal at the rate of $0.4 million per quarter commencing December 31, 2013 and continuing until the maturity date when the remaining balance is due. At December 31, 2013, the weighted average interest rate on its outstanding Term Facility borrowings was 6.5%.

The Term Facility contains customary covenants that limit Atlas Energy’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from

 

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the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of Atlas Energy’s assets. The Term Facility also contains covenants that require (i) Atlas Energy to maintain a ratio of Total Funded Debt (as defined in the Term Facility) to EBITDA (as defined in the Term Facility), calculated over a period of four consecutive fiscal quarters, of not greater than 4.5 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2014; 4.0 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2015; and 3.5 to 1.0 for the last day of each of the quarters thereafter, and (ii) the entry into swap agreements with respect to the assets acquired in the EP Energy and Arkoma acquisitions (see Note 4). At December 31, 2013, Atlas Energy was in compliance with these covenants. The events which constitute events of default are also customary for credit facilities of this nature, including payment defaults, breaches of representations, warranties or covenants, defaults in the payment of other indebtedness over a specified threshold, insolvency and change of control. Based on the definition in Atlas Energy’s Term Facility, New Atlas’s ratio of Total Funded Debt to EBITDA was 2.4 to 1.0.

Atlas Energy’s obligations under the Term Facility are secured by first priority security interests in substantially all of its assets, including all of its ownership interests in its material subsidiaries and its ownership interests in ARP. Additionally, Atlas Energy’s obligations under its Term Facility are guaranteed by its wholly owned subsidiaries and may be guaranteed by future subsidiaries. The Term Facility is subject to an intercreditor agreement, which provides for certain rights and procedures, between the lenders under the Term Facility and Atlas Energy’s credit facility, with respect to enforcement of rights, collateral and application of payment proceeds.

At December 31, 2013, New Atlas has not guaranteed any of ARP’s debt obligations.

ARP’s Credit Facility

On July 31, 2013, in connection with the EP Energy Acquisition (see Note 4), ARP entered into a Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (“ARP Credit Agreement”), which amended and restated ARP’s existing revolving credit facility. The ARP Credit Agreement provides for a senior unsecured revolving credit facility with a syndicate of banks scheduled to mature in July 2018. ARP’s borrowing base is scheduled for redeterminations on May 1 and November 1 of each year. On December 6, 2013, ARP entered into the First Amendment to the Credit Agreement (“ARP Amendment”). The ARP Amendment redetermined the borrowing base to $735.0 million and amended the ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to EBITDA (as defined in the ARP Credit Agreement) (actual or annualized, as applicable). The ARP Credit Agreement has a maximum facility amount of $1.5 billion. At December 31, 2013, $419.0 million was outstanding under the credit facility. Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which $3.6 million was outstanding at December 31, 2013. ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. Borrowings under the credit facility bear interest, at ARP’s election, at either an adjusted LIBOR rate plus an applicable margin between 1.75% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal Funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.75% and 1.75% per annum. ARP is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.5% per annum if 50% or more of the borrowing base is utilized and 0.375% per annum if less than 50% of the borrowing base is utilized, which is included within interest expense on New Atlas’s combined consolidated statements of operations. At December 31, 2013, the weighted average interest rate on outstanding borrowings under the credit facility was 2.4%.

The ARP Credit Agreement contains customary covenants that limit ARP’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset

 

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dispositions, including a sale of all or substantially all of its assets. ARP was in compliance with these covenants as of December 31, 2013. The ARP Credit Agreement also requires ARP to maintain a ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to four quarters of EBITDA (as defined in the ARP Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than 4.50 to 1.0 as of the last day of the quarters ended December 31, 2013, March 31, 2014 and June 30, 2014, 4.25 to 1.0 as of the last day of the quarter ended September 30, 2014 and 4.0 to 1.0 as of the last day of fiscal quarters ending thereafter and a ratio of current assets (as defined in the ARP Credit Agreement) to current liabilities (as defined in the ARP Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. Based on the definitions contained in ARP’s credit agreement, at December 31, 2013, ARP’s ratio of current assets to current liabilities was 1.9 to 1.0 and its ratio of Total Funded Debt to EBITDA was 4.0 to 1.0.

ARP Senior Notes

On December 31, 2013, ARP had $275.0 million principal outstanding of 7.75% senior notes due 2021 (“7.75% ARP Senior Notes”) and $250.0 million principal outstanding of 9.25% Senior Notes due 2021 (“9.25% ARP Senior Notes”). On July 30, 2013, ARP issued $250.0 million of its 9.25% ARP Senior Notes in a private placement transaction at an offering price of 99.297% of par value, yielding net proceeds of approximately $242.8 million, net of underwriting fees and other offering costs of $5.5 million. The net proceeds were used to partially fund the EP Energy Acquisition (see Note 4). The 9.25% ARP Senior Notes were presented net of a $1.7 million unamortized discount as of December 31, 2013. Interest on the 9.25% ARP Senior Notes accrued from July 30, 2013, and is payable semi-annually on February 15 and August 15, with the first interest payment date on February 15, 2014. At any time on or after August 15, 2017, ARP may redeem some or all of the 9.25% ARP Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 100.0%. In addition, at any time prior to August 15, 2016, ARP may redeem up to 35% of the 9.25% ARP Senior Notes with the proceeds received from certain equity offerings at a redemption price of 109.25%. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 9.25% ARP Senior Notes.

In connection with the issuance of the 9.25% ARP Senior Notes, ARP entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission (the “SEC”) to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by July 30, 2014. Under certain circumstances, in lieu of, or in addition to, a registered exchange offer, ARP has agreed to file a shelf registration statement with respect to the 9.25% ARP Senior Notes. If ARP fails to comply with its obligations to register the 9.25% ARP Senior Notes within the specified time periods, the 9.25% ARP Senior Notes will be subject to additional interest, up to 1% per annum, until such time that the exchange offer is consummated or the shelf registration statement is declared effective, as applicable.

On January 23, 2013, ARP issued $275.0 million of its 7.75% ARP Senior Notes in a private placement transaction at par. ARP used the net proceeds of approximately $267.6 million to repay all of the indebtedness and accrued interest outstanding under its then-existing term loan credit facility and a portion of the amounts outstanding under its revolving credit facility. In connection with the retirement of ARP’s term loan credit facility and the reduction in its revolving credit facility borrowing base, ARP accelerated $3.2 million of amortization expense related to deferred financing costs during the year ended December 31, 2013 (see Note 6). Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price as defined in the governing indenture, plus accrued and unpaid interest

 

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and additional interest, if any. On and after January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019. On July 1, 2013, ARP filed a registration statement relating to the exchange offer for the 7.75% ARP Senior Notes and the exchange offer was completed on January 2, 2014.

The 9.25% ARP Senior Notes and 7.75% ARP Senior Notes are guaranteed by certain of ARP’s material subsidiaries. The guarantees under the 9.25% ARP Senior Notes and 7.75% ARP Senior Notes are full and unconditional and joint and several, and any subsidiaries of ARP, other than the subsidiary guarantors, are minor. There are no restrictions on ARP’s ability to obtain cash or any other distributions of funds from the guarantor subsidiaries.

The indentures governing the 9.25% ARP Senior Notes and 7.75% ARP Senior Notes contain covenants, including limitations of ARP’s ability to incur certain liens, incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of ARP’s assets. ARP was in compliance with these covenants as of December 31, 2013.

The aggregate amount of New Atlas’s and ARP’s future debt maturities are as follows (in thousands):

 

Years Ended December 31:
2014		$	1,500
2015			1,500
2016			1,500
2017			1,500
2018			420,500
Thereafter			667,125
Total principle maturities			1,093,625
Unamortized discounts			(1,666	)
Total debt		$	1,091,959

Cash payments for interest by New Atlas were $22.3 million, $3.1 million and $2.4 million for the years ended December 31, 2013, 2012 and 2011, respectively.

NOTE 9—DERIVATIVE INSTRUMENTS

New Atlas and ARP use a number of different derivative instruments, principally swaps, collars, and options, in connection with their commodity and interest rate price risk management activities. New Atlas and ARP enter into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold or interest payments on the underlying debt instrument are due. Under commodity-based swap agreements, New Atlas and ARP receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.

New Atlas and ARP formally document all relationships between hedging instruments and the items being hedged, including their risk management objective and strategy for undertaking the hedging transactions. This

 

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includes matching the commodity and interest derivative contracts to the forecasted transactions. New Atlas and ARP assess, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, New Atlas and ARP will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which are determined by management through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in New Atlas combined consolidated statements of operations. For derivatives qualifying as hedges, New Atlas and ARP recognize the effective portion of changes in fair value of derivative instruments in equity as accumulated other comprehensive income (loss) and reclassify the portion relating to the New Atlas and ARP’s commodity derivatives to gas and oil production revenues and the portion relating to interest rate derivatives to interest expense within New Atlas’s combined consolidated statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, changes in fair value are recognized within gain (loss) on mark-to-market derivatives in New Atlas’s combined consolidated statements of operations as they occur.

New Atlas and ARP enter into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on New Atlas’s combined consolidated balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on New Atlas’s combined consolidated balance sheets as the initial value of the options.

New Atlas and ARP enter into commodity future option and collar contracts to achieve more predictable cash flows by hedging their exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. Natural gas liquids fixed price swaps are priced based on a WTI crude oil index, while other natural gas liquids contracts are based on an OPIS Mt. Belvieu index.

Derivatives are recorded on New Atlas’s combined consolidated balance sheets as assets or liabilities at fair value. New Atlas reflected net derivative assets on its combined consolidated balance sheets of $24.0 million and $20.3 million at December 31, 2013 and 2012, respectively. Of the $10.3 million of net gain in accumulated other comprehensive income within equity on New Atlas’s combined consolidated balance sheet related to derivatives at December 31, 2013, if the fair values of the instruments remain at current market values, New Atlas will reclassify $1.6 million of losses to gas and oil production revenue on its combined consolidated statement of operations over the next twelve month period as these contracts expire. Aggregate gains of $11.9 million of gas and oil production revenues will be reclassified to New Atlas’s combined consolidated statements of operations in later periods as the remaining contracts expire. Actual amounts that will be reclassified will vary as a result of future commodity price changes. Approximately $3.9 million of derivative gains were reclassified from other comprehensive income related to derivative instruments entered into during the year ended December 31, 2013, respectively.

 

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The following table summarizes New Atlas and ARP’s gains or losses recognized in New Atlas’s combined consolidated statements of operations for effective derivative instruments, excluding the effect of non-controlling interest, for the periods indicated (in thousands):

 

		Years Ended December 31,
		2013				2012				2011
Gain reclassified from accumulated other comprehensive income:
Gas and oil production revenue		$	(10,216	)		$	(19,281	)		$	(10,542	)
Total		$	(10,216	)		$	(19,281	)		$	(10,542	)

New Atlas

The following table summarizes the gross fair values of New Atlas’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on New Atlas’s combined consolidated balance sheets as of the dates indicated (in thousands):

 

		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Combined Consolidated Balance Sheets				Net Amount of Assets Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Assets
As of December 31, 2013
Current portion of derivative assets		$	24			$	(23	)		$	1
Long-term portion of derivative assets			1,547				(33	)			1,514
Current portion of derivative liabilities			63				(63	)			—
Total derivative assets		$	1,634			$	(119	)		$	1,515
As of December 31, 2012
Current portion of derivative assets		$	—			$	—			$	—
Long-term portion of derivative assets			—				—				—
Current portion of derivative liabilities			—				—				—
Long-term portion of derivative liabilities			—				—				—
Total derivative assets		$	—			$	—			$	—

 

		Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Combined Consolidated Balance Sheets				Net Amount of Liabilities Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Liabilities
As of December 31, 2013
Current portion of derivative assets		$	(23	)		$	23			$	—
Long-term portion of derivative assets			(33	)			33				—
Current portion of derivative liabilities			(96	)			63				(33	)
Total derivative liabilities		$	(152	)		$	119			$	(33	)
As of December 31, 2012
Current portion of derivative assets		$	—			$	—			$	—
Long-term portion of derivative assets			—				—				—
Current portion of derivative liabilities			—				—				—
Long-term portion of derivative liabilities			—				—				—
Total derivative liabilities		$	—			$	—			$	—

 

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During the year ended December 31, 2013, New Atlas recorded gains of $0.5 million on settled derivative contracts within its combined consolidated statements of operations. These gains were included within gas and oil production revenue in New Atlas’s combined consolidated statement of operations. No gains or losses were recorded on settled derivative contracts within New Atlas’s combined consolidated statements of operations for the years ended December 31, 2012 and 2011 as New Atlas had no derivative contracts in those years. As the underlying prices and terms in New Atlas’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the year ended December 31, 2013 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

In connection with the Arkoma Acquisition, New Atlas entered into contracts which provided the option to enter into swap contracts for future production periods (“swaptions”) up through September 30, 2013 for production volumes related to the Arkoma assets acquired from EP Energy (see Note 4). In connection with the swaption contacts, New Atlas paid premiums of $2.3 million which represented their fair value on the date the transactions were initiated, were initially recorded as a derivative asset on New Atlas’s combined consolidated balance sheet and were fully amortized as of September 30, 2013. Swaption contract premiums paid are amortized over the period from initiation of the contract through termination date. For the year ended December 31, 2013, New Atlas recognized approximately $2.3 million of amortization expense in other, net on New Atlas’s combined consolidated statement of operations related to the swaption contracts.

At December 31, 2013, New Atlas had the following commodity derivatives:

Natural Gas Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Asset/(Liability)
		(MMBtu)(1)				(per MMBtu)(1)				(in thousands)(2)
2014			2,760,000			$	4.177			$	(32	)
2015			2,280,000			$	4.302				355
2016			1,440,000			$	4.433				430
2017			1,200,000			$	4.590				504
2018			420,000			$	4.797				225
New Atlas’s net asset										$	1,482

 

(1)	“MMBtu” represents million British Thermal Units.

(2)	Fair value based on forward NYMEX natural gas prices, as applicable.

 

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Atlas Resource Partners

The following table summarizes the gross fair values of ARP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on New Atlas’s combined consolidated balance sheets as of the dates indicated (in thousands):

 

		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Combined Consolidated Balance Sheets				Net Amount of Assets Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Assets
As of December 31, 2013
Current portion of derivative assets		$	2,664			$	(773	)		$	1,891
Long-term portion of derivative assets			31,146				(4,062	)			27,084
Current portion of derivative liabilities			4,341				(4,341	)			—
Long-term portion of derivative liabilities			122				(122	)			—
Total derivative assets		$	38,273			$	(9,298	)		$	28,975
As of December 31, 2012
Current portion of derivative assets		$	14,248			$	(1,974	)		$	12,274
Long-term portion of derivative assets			14,724				(5,826	)			8,898
Long-term portion of derivative liabilities			800				(800	)			—
Total derivative assets		$	29,772			$	(8,600	)		$	21,172

 

		Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Combined Consolidated Balance Sheets				Net Amount of Liabilities Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Liabilities
As of December 31, 2013
Current portion of derivative assets		$	(773	)		$	773			$	—
Long-term portion of derivative assets			(4,062	)			4,062				—
Current portion of derivative liabilities			(10,694	)			4,341				(6,353	)
Long-term portion of derivative liabilities			(189	)			122				(67	)
Total derivative liabilities		$	(15,718	)		$	9,298			$	(6,420	)
As of December 31, 2012
Current portion of derivative assets		$	(1,974	)		$	1,974			$	—
Long-term portion of derivative assets			(5,826	)			5,826				—
Long-term portion of derivative liabilities			(1,688	)			800				(888	)
Total derivative liabilities		$	(9,488	)		$	8,600			$	(888	)

In June 2012, ARP received approximately $3.9 million in net proceeds from the early termination of natural gas and oil derivative positions for production periods from 2015 through 2016. In conjunction with the early termination of these derivatives, ARP entered into new derivative positions at prevailing prices at the time of the transaction. The net proceeds from the early termination of these derivatives were used to reduce indebtedness under ARP’s credit facility (see Note 8). The gain recognized upon the early termination of these derivative positions will continue to be reported in accumulated other comprehensive income (loss) and will be reclassified into New Atlas’s combined consolidated statements of operations in the same periods in which the hedged production revenues would have been recognized in earnings.

 

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In connection with the EP Energy Acquisition, ARP entered into swaption contracts up through September 30, 2013 for production volumes related to assets ARP acquired from EP Energy (see Note 4). In connection with the swaption contracts, ARP paid premiums of $14.5 million which represented their fair value on the date the transactions were initiated, were initially recorded as derivative assets on New Atlas’s combined consolidated balance sheet and were fully amortized as of September 30, 2013. Swaption contract premiums paid are amortized over the period from initiation of the contract through the termination date. For the year ended December 31, 2013, ARP recognized $14.5 million of amortization expense in other, net on New Atlas’s combined consolidated statement of operations related to the swaption contracts.

In connection with the Carrizo Acquisition, ARP entered into swaption contracts up through May 31, 2012 for production volumes related to wells acquired from Carrizo (see Note 4). In connection with the swaption contracts, ARP paid premiums of $4.6 million, which represented their fair value on the date the transactions were initiated, were initially recorded as derivative assets on New Atlas’s combined consolidated balance sheet and were fully amortized as of September 30, 2012. For the year ended December 31, 2012, ARP recorded $4.6 million of amortization expense in other, net on New Atlas’s combined consolidated statement of operations related to the swaption contracts.

ARP recognized gains of $9.7 million, $19.3 million and $10.5 million for the years ended December 31, 2013, 2012 and 2011, respectively, on settled contracts covering commodity production. These gains were included within gas and oil production revenue in New Atlas’s combined consolidated statements of operations. As the underlying prices and terms in ARP’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the years ended December 31, 2013, 2012 and 2011 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

At December 31, 2013, ARP had the following commodity derivatives:

Natural Gas Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Asset/(Liability)
		(MMBtu)(1)				(per MMBtu)(1)				(in thousands)(2)
2014			60,153,000			$	4.152			$	(2,238	)
2015			51,474,500			$	4.236				4,639
2016			45,746,300			$	4.311				8,183
2017			24,840,000			$	4.532				9,053
2018			3,960,000			$	4.716				1,819
										$	21,456

Natural Gas Costless Collars

 

Production Period Ending December 31,		Option Type		Volumes				Average Floor and Cap				Fair Value Asset/(Liability)
				(MMBtu)(1)				(per MMBtu)(1)				(in thousands)(2)
2014		Puts purchased			3,840,000			$	4.221			$	1,322
2014		Calls sold			3,840,000			$	5.120				(363	)
2015		Puts purchased			3,480,000			$	4.234				1,747
2015		Calls sold			3,480,000			$	5.129				(639	)
												$	2,067

 

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Natural Gas Put Options—Drilling Partnerships

 

Production Period Ending December 31,		Option Type		Volumes				Average Fixed Price				Fair Value Asset
				(MMBtu)(1)				(per MMBtu)(1)				(in thousands)(2)
2014		Puts purchased			1,800,000			$	3.800			$	222
2015		Puts purchased			1,440,000			$	4.000				486
2016		Puts purchased			1,440,000			$	4.150				667
												$	1,375

Natural Gas Liquids Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Asset/(Liability)
		(Bbl)(1)				(per Bbl)(1)				(in thousands)(3)
2014			105,000			$	91.571			$	(417	)
2015			96,000			$	88.550				44
2016			84,000			$	85.651				183
2017			60,000			$	83.780				186
										$	(4	)

Natural Gas Liquids Ethane Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Asset
		(Gal)(1)				(per Gal)(1)				(in thousands)(4)
2014			2,520,000			$	0.303			$	67
										$	67

Natural Gas Liquids Propane Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Liability
		(Gal)(1)				(per Gal)(1)				(in thousands)(5)
2014			12,348,000			$	0.996			$	(1,409	)
2015			8,064,000			$	1.016				(144	)
										$	(1,553	)

Natural Gas Liquids Butane Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Liability
		(Gal)(1)				(per Gal)(1)				(in thousands)(6)
2014			1,512,000			$	1.308			$	(27	)
2015			1,512,000			$	1.248				(70	)
										$	(97	)

 

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Natural Gas Liquids Iso Butane Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Liability
		(Gal)(1)				(per Gal)(1)				(in thousands)(7)
2014			1,512,000			$	1.323			$	(7	)
2015			1,512,000			$	1.263				(99	)
										$	(106	)

Crude Oil Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Asset/(Liability)
		(Bbl)(1)				(per Bbl)(1)				(in thousands)(3)
2014			552,000			$	92.668			$	(1,657	)
2015			567,000			$	88.144				51
2016			225,000			$	85.523				463
2017			132,000			$	83.305				348
										$	(795	)

Crude Oil Costless Collars

 

Production Period Ending December 31,		Option Type		Volumes				Average Floor and Cap				Fair Value Asset/(Liability)
				(Bbl)(1)				(per Bbl)(1)				(in thousands)(3)
2014		Puts purchased			41,160			$	84.169			$	79
2014		Calls sold			41,160			$	113.308				(36	)
2015		Puts purchased			29,250			$	83.846				158
2015		Calls sold			29,250			$	110.654				(56	)
												$	145
ARP’s net asset												$	22,555

 

(1)	“MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons.

(2)	Fair value based on forward NYMEX natural gas prices, as applicable.

(3)	Fair value based on forward WTI crude oil prices, as applicable.

(4)	Fair value based on forward Mt. Belvieu ethane prices, as applicable.

(5)	Fair value based on forward Mt. Belvieu propane prices, as applicable.

(6)	Fair value based on forward Mt. Belvieu butane prices, as applicable.

(7)	Fair value based on forward Mt. Belvieu iso butane prices, as applicable.

At December 31, 2013, ARP had net cash proceeds of $3.5 million related to ARP’s hedging positions monetized on behalf of the Drilling Partnerships’ limited partners, which were included within cash and cash equivalents on New Atlas’s combined consolidated balance sheet. ARP will allocate the monetization net proceeds to the Drilling Partnerships’ limited partners based on their natural gas and oil production generated over the period of the original derivative contracts. New Atlas reflected the remaining hedge monetization proceeds within current and long-term portion of derivative payable to Drilling Partnerships on its combined consolidated balance sheets as of December 31, 2013 and 2012.

In June 2012, ARP entered into natural gas put option contracts which related to future natural gas production of the Drilling Partnerships. Therefore, a portion of any unrealized derivative gain or loss is allocable

 

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to the limited partners of the Drilling Partnerships based on their share of estimated gas production related to the derivatives not yet settled. At December 31, 2013, net unrealized derivative assets of $1.4 million were payable to the limited partners in the Drilling Partnerships related to these natural gas put option contracts.

At December 31, 2013, ARP had a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under its revolving credit facility (see Note 8), ARP is required to utilize this secured hedge facility for future commodity risk management activity for its equity production volumes within the participating Drilling Partnerships. Each participating Drilling Partnership’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets and by a guarantee of the general partner of the Drilling Partnership. ARP, as general partner of the Drilling Partnerships, administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnerships’ ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets.

NOTE 10—FAIR VALUE OF FINANCIAL INSTRUMENTS

New Atlas has established a hierarchy to measure their financial instruments at fair value which requires them to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect New Atlas own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

New Atlas and ARP use a market approach fair value methodology to value the assets and liabilities for their outstanding derivative contracts (see Note 9) and New Atlas’s rabbi trust assets (see Note 15). New Atlas and ARP manage and report derivative assets and liabilities on the basis of their exposure to market risks and credit risks by counterparty. New Atlas and ARP’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument. Investments held in New Atlas’s rabbi trust are publicly traded equity and debt securities and are therefore defined as Level 1 fair value measurements.

 

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Information for New Atlas and ARP’s assets and liabilities measured at fair value at December 31, 2013 and 2012 was as follows (in thousands):

 

		Level 1				Level 2				Level 3				Total
As of December 31, 2013
Assets, gross
Rabbi trust		$	3,705			$	—			$	—			$	3,705
Commodity swaps			—				1,634				—				1,634
ARP Commodity swaps			—				33,594				—				33,594
ARP Commodity puts			—				1,374				—				1,374
ARP Commodity options			—				3,305				—				3,305
Total assets, gross			3,705				39,907				—				43,612
Liabilities, gross
Commodity swaps			—				(152	)			—				(152	)
ARP Commodity swaps			—				(14,624	)			—				(14,624	)
ARP Commodity options			—				(1,094	)			—				(1,094	)
Total derivative liabilities, gross			—				(15,870	)			—				(15,870	)
Total assets, fair value, net		$	3,705			$	24,037			$	—			$	27,742
As of December 31, 2012
Assets, gross
Rabbi trust		$	1,739			$	—			$	—			$	1,739
ARP Commodity swaps			—				15,859				—				15,859
ARP Commodity puts			—				2,991				—				2,991
ARP Commodity options			—				10,923				—				10,923
Total assets, gross			1,739				29,773				—				31,512
Liabilities, gross
ARP Commodity swaps			—				(6,813	)			—				(6,813	)
ARP Commodity puts			—				—				—				—
ARP Commodity options			—				(2,676	)			—				(2,676	)
Total liabilities, gross			—				(9,489	)			—				(9,489	)
Total assets, fair value, net		$	1,739			$	20,284			$	—			$	22,023

Other Financial Instruments

The estimated fair values of New Atlas and ARP’s other financial instruments have been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that New Atlas and ARP could realize upon the sale or refinancing of such financial instruments.

New Atlas and ARP’s other current assets and liabilities on its combined consolidated balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1. The estimated fair values of New Atlas and ARP’s debt at December 31, 2013 and 2012, which consist principally of ARP’s senior notes and borrowings under New Atlas’s, and ARP’s term loan and revolving credit facilities, were $1,088.3 million and $357.1 million, respectively, compared with the carrying amounts of $1,092.0 million and $357.1 million, respectively. The carrying values of outstanding borrowings under the respective revolving and term loan credit facilities, which bear interest at variable interest rates, approximated their estimated fair values. The estimated fair values of the ARP senior notes were based upon the market approach and calculated using the yields of the ARP senior notes as provided by financial institutions and thus were categorized as Level 3 values.

 

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Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

New Atlas and ARP estimate the fair value of their respective asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of New Atlas and ARP and estimated inflation rates (see Note 7).

Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the years ended December 31, 2013 and 2012 was as follows (in thousands):

 

		Years Ended December 31,
		2013								2012
		Level 3				Total				Level 3				Total
Asset retirement obligations		$	23,129			$	23,129			$	16,568			$	16,568
Total		$	23,129			$	23,129			$	16,568			$	16,568

Management estimates the fair value of New Atlas and ARP’s long-lived assets in connection with reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances. For the years ended December 31, 2013, 2012, and 2011, ARP recognized $38.0 million, $9.5 million and $7.0 million, respectively, of impairment of long-lived assets which were defined as a Level 3 fair value measurements (see Note 2—Impairment of Long-Lived Assets).

During the year ended December 31, 2013, Atlas Energy completed the Arkoma Acquisition and ARP completed the EP Energy Acquisition. During the year ended December 31, 2012, ARP completed the acquisitions of certain oil and gas assets from Carrizo, and certain proved reserves and associated assets from the Titan, Equal and DTE acquisitions (see Note 4). The fair value measurements of assets acquired and liabilities assumed for each of these acquisitions are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The estimates of fair value of the EP Energy Acquisition and the Arkoma Acquisition as of their acquisition date, which are reflected in New Atlas’s combined consolidated balance sheet as of December 31, 2013, were finalized during the six months ended June 30, 2014. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under New Atlas’s and ARP’s existing methodology for recognizing an estimated liability for the plugging and abandonment of their gas and oil wells (see Note 7). These inputs require significant judgments and estimates by New Atlas’s and ARP’s management at the time of the valuation and are subject to change.

NOTE 11—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Relationship with Drilling Partnerships. ARP conducts certain activities through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. ARP serves as general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the general partner, ARP is liable for the Drilling Partnerships’ liabilities and can be liable to limited partners of the Drilling Partnerships if it breaches its responsibilities with respect to the operations of the Drilling Partnerships. ARP is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Drilling Partnership’s revenue and costs and expenses according to the respective partnership agreements.

Relationship between ARP and APL. Atlas Energy also maintains a general partner ownership interest in Atlas Pipeline Partners, L.P. (“APL”), a publicly traded Delaware master limited partnership (NYSE: APL) and midstream energy service provider engaged in the gathering, processing and treating of natural gas in the mid-

 

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continent and southwestern regions of the United States and gas gathering services in the Appalachian Basin in the northwest region of the United States. In the Chattanooga Shale, a portion of the natural gas produced by New Atlas is gathered and processed by APL. For the years ended December 31, 2013, 2012 and 2011, $0.3 million, $0.4 million and $0.3 million, respectively, of gathering fees paid by ARP to APL were included in the combined consolidated statements of operations.

In addition, in Lycoming County, Pennsylvania, APL agreed to provide assistance in the design and construction management services for ARP with respect to a pipeline. ARP reimbursed approximately $1.8 million to APL as of December 31, 2013.

Relationship with Resource America, Inc. In connection with the issuance of the Term Facility, CVC Credit Partners, LLC (“CVC”), which is a joint-venture between Resource America, Inc. and an unrelated third party private equity firm, was allocated an aggregate of $12.5 million of the Term Facility. Atlas Energy’s Chief Executive Officer and President is Chairman of the board of directors of Resource America, Inc., and Atlas Energy’s Executive Chairman of the General Partner’s board of directors is Chief Executive Officer and President and Resource America, Inc.

NOTE 12—COMMITMENTS AND CONTINGENCIES

General Commitments

Atlas Energy and its subsidiaries lease office space and equipment under leases with varying expiration dates. Rental expense related to New Atlas and ARP was $13.1 million, $4.1 million and $1.9 million for the years ended December 31, 2013, 2012 and 2011, respectively. Future minimum rental commitments for the next five years are as follows (in thousands):

 

Years Ended December 31,
2014		$	3,903
2015			3,064
2016			2,621
2017			2,470
2018			1,592
Thereafter			5,140
		$	18,790

ARP is the managing general partner of the Drilling Partnerships and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. ARP has structured certain Drilling Partnerships to allow limited partners to have the right to present their interests for purchase. Generally for Drilling Partnerships with this structure, ARP is not obligated to purchase more than 5% to 10% of the units in any calendar year, no units may be purchased during the first five years after closing for the Drilling Partnership, and ARP may immediately suspend the presentment structure for a Drilling Partnership by giving notice to the limited partners that it does not have adequate liquidity for redemptions. In accordance with the Drilling Partnership agreement, the purchase price for limited partner interests would generally be based upon a percentage of the present value of future cash flows allocable to the interest, discounted at 10%, as of the date of presentment, subject to estimated changes by ARP to reflect current well performance, commodity prices and production costs, among other items. Based on its historical experience, as of December 31, 2013, the management of ARP believes that any such estimated liability for redemptions of limited partner interests in Drilling Partnerships which allow such transactions would not be material.

While its historical structure has varied, ARP has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors

 

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until they have received specified returns, typically 10% per year determined on a cumulative basis and inclusive of estimated individual tax benefits, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. ARP periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, ARP recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which ARP has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, ARP will recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized. For the years ended December 31, 2013, 2012 and 2011, $9.6 million, $6.3 million and $4.0 million, respectively, of ARP’s gas and oil production revenues, net of corresponding production costs, from certain Drilling Partnerships were subordinated, which reduced gas and oil production revenues and expenses.

Atlas Energy is party to employment agreements with certain executives that provide compensation and certain other benefits. The agreements also provide for severance payments under certain circumstances.

In connection with ARP’s EP Energy Acquisition (see Note 4), ARP acquired certain long-term annual firm transportation obligations. Estimated fixed and determinable portions of ARP’s firm transportation obligations as of December 31, 2013 were as follows: 2014—$8.8 million; 2015—$8.6 million; 2016—$2.1 million; and 2017 to 2018—none.

As of December 31, 2013, New Atlas is committed to expend approximately $13.9 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

Legal Proceedings

The operations of New Atlas are party to various routine legal proceedings arising out of the ordinary course of its business. Management of New Atlas believes that none of these actions, individually or in the aggregate, will have a material adverse effect on New Atlas’s financial condition or results of operations.

NOTE 13—ISSUANCES OF UNITS

New Atlas recognizes gains on ARP’s equity transactions as credits to equity on its combined consolidated balance sheets rather than as income on its combined consolidated statements of operations. These gains represent New Atlas’s portion of the excess net offering price per unit of each of ARP’s common units over the book carrying amount per unit.

Atlas Resource Partners

Equity Offerings

In July 2013, in connection with the closing of the EP Energy Acquisition (see Note 4), ARP issued 3,749,986 newly created Class C convertible preferred units to New Atlas at a negotiated price per unit of $23.10, for proceeds of $86.6 million. The Class C preferred units were issued with 562,497 warrants to purchase ARP common units at an exercise price of $23.10 at New Atlas’s option beginning on October 29, 2013. The warrants will expire on July 31, 2016. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act.

 

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Upon issuance of the Class C preferred units and warrants on July 31, 2013, ARP entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class C preferred units and upon exercise of the warrants. ARP agreed to use commercially reasonable efforts to file such registration statement within 90 days of the conversion of the Class C preferred units into common units or the exercise of the warrants.

In June 2013, in connection with the EP Energy Acquisition (see Note 4), ARP sold an aggregate of 14,950,000 of its common limited partner units (including 1,950,000 units pursuant to an over-allotment option) in a public offering at a price of $21.75 per unit, yielding net proceeds of approximately $313.1 million. ARP utilized the net proceeds from the sale to repay the outstanding balance under its revolving credit facility (see Note 8).

In May 2013, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of several banks. Pursuant to the equity distribution agreement, ARP could sell, from time to time through the agents, common units having an aggregate offering price of up to $25.0 million. Sales of common limited partner units, if any, could be made in negotiated transactions or transactions that were deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act, including sales made directly on the NYSE, the existing trading market for the common limited partner units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP paid each of the agents a commission, which in each case was not more than 2.0% of the gross sales price of common limited partner units sold through such agent. During the year ended December 31, 2013, ARP issued 309,174 common limited partner units under the equity distribution program for net proceeds of $6.9 million, net of $0.4 million in commissions paid. ARP utilized the net proceeds from the sale to repay borrowings outstanding under its revolving credit facility. ARP terminated its equity distribution agreement effective December 27, 2013.

In November and December 2012, in connection with entering into a purchase agreement to acquire certain producing wells and net acreage from DTE, ARP sold an aggregate of 7,898,210 of its common limited partner units in a public offering at a price of $23.01 per unit, yielding net proceeds of approximately $174.5 million. ARP utilized the net proceeds from the sale to repay a portion of the outstanding balance under its revolving credit facility and $2.2 million under its then-existing term loan credit facility.

In July 2012, ARP completed the acquisition of certain proved reserves and associated assets in the Barnett Shale from Titan in exchange for 3.8 million ARP common units and 3.8 million newly created convertible ARP Class B preferred units (which have an estimated collective value of $193.2 million, based upon the closing price of ARP’s publicly traded common units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments (see Note 4). The Class B preferred units are voluntarily convertible to common units on a one-for-one basis within three years of the acquisition closing date at a strike price of $26.03 plus all unpaid preferred distributions per unit, and will be mandatorily converted to common units on the third anniversary of the issuance. While outstanding, the preferred units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution.

ARP entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC by January 25, 2013 to register the resale of the ARP common units issued on the acquisition closing date and those issuable upon conversion of the Class B preferred units. ARP agreed to use its commercially reasonable efforts to have the registration statement declared effective by March 31, 2013, and to cause the registration statement to be continuously effective until the earlier of (i) the date as of which all such common units registered thereunder are sold by the holders and (ii) one year after the date of effectiveness. On September 19, 2012, ARP filed a registration statement with the SEC in satisfaction of the registration requirements of the registration rights agreement, and the registration statement was declared effective by the SEC on October 2, 2012.

In April 2012, ARP completed the acquisition of certain oil and gas assets from Carrizo (see Note 4). To partially fund the acquisition, ARP sold 6.0 million of its common units in a private placement at a negotiated

 

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purchase price per unit of $20.00, for net proceeds of $119.5 million, of which $5.0 million was purchased by certain executives of Atlas Energy. The common units issued by ARP are subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement stipulated that ARP would (a) file a registration statement with the SEC by October 30, 2012 and (b) cause the registration statement to be declared effective by the SEC by December 31, 2012. On July 11, 2012, ARP filed a registration statement with the SEC for the common units subject to the registration rights agreement in satisfaction of one of the requirements of the registration rights agreement noted previously. On August 28, 2012, the registration statement was declared effective by the SEC.

In connection with the issuance of ARP’s common and preferred units during the years ended December 31, 2013 and 2012, New Atlas recorded gains of $27.3 million and $66.6 million within equity and a corresponding decrease in non-controlling interests on its combined consolidated balance sheets and combined consolidated statement of equity.

ARP Common Unit Distribution

In February 2012, the board of directors of Atlas Energy’s general partner approved the distribution of approximately 5.24 million of ARP’s common limited partner units which were distributed on March 13, 2012 to Atlas Energy’s unitholders using a ratio of 0.1021 ARP common limited partner units for each of Atlas Energy’s common units owned on the record date of February 28, 2012.

NOTE 14—CASH DISTRIBUTIONS

ARP Cash Distributions. ARP has a cash distribution policy under which it distributes, within 45 days following the end of each calendar quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders and general partner. If ARP’s common unit distributions in any quarter exceed specified target levels, New Atlas will receive between 13% and 48% of such distributions in excess of the specified target levels.

Distributions declared by ARP from its formation through December 31, 2013 were as follows (in thousands, except per unit amounts):

 

Date Cash Distribution Paid		For Quarter Ended		Cash Distribution per Common Limited Partner Unit				Total Cash Distribution to Common Limited Partners				Total Cash Distribution to Preferred Limited Partners				Total Cash Distribution to the General Partner
May 15, 2012		March 31, 2012		$	0.12	(1)		$	3,144			$	—			$	64
August 14, 2012		June 30, 2012		$	0.40			$	12,891			$	—			$	263
November 14, 2012		September 30, 2012		$	0.43			$	15,510			$	1,652			$	350
February 14, 2013		December 31, 2012		$	0.48			$	21,107			$	1,841			$	618
May 15, 2013		March 31, 2013		$	0.51			$	22,428			$	1,957			$	946
August 14, 2013		June 30, 2013		$	0.54			$	32,097			$	2,072			$	1,884
November 14, 2013		September 30, 2013		$	0.56			$	33,291			$	4,248			$	2,443

 

(1)	Represents a pro-rated cash distribution of $0.40 per common limited partner unit for the period from March 5, 2012, the date Atlas Energy’s exploration and production assets were transferred to ARP, to March 31, 2012.

On January 29, 2014, ARP declared a cash distribution of $0.58 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2013. The $41.8 million distribution, including $2.9 million and $4.4 million to New Atlas, as general partner, and preferred limited

 

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partners, respectively, was paid on February 14, 2014 to unitholders of record at the close of business on February 10, 2014.

NOTE 15—BENEFIT PLANS

New Atlas Rabbi Trust

In 2011, Atlas Energy established an excess 401(k) plan relating to certain executives. In connection with the plan, Atlas Energy established a “rabbi” trust for the contributed amounts. At December 31, 2013 and 2012, New Atlas reflected $3.7 million and $1.7 million, respectively, related to the value of the rabbi trust within other assets, net on its combined consolidated balance sheets, and recorded corresponding liabilities of $3.7 million and $1.7 million as of those same dates with asset retirement obligations and other on its combined consolidated balance sheets.

ARP Long-Term Incentive Plan

ARP has a 2012 Long-Term Incentive Plan effective March 2012 (the “ARP LTIP”). Awards of options to purchase units, restricted units and phantom units may be granted to officers, employees and directors of ARP’s general partner under the ARP LTIP, and such awards may be subject to vesting terms and conditions in the discretion of the administrator of the ARP LTIP. Up to 2,900,0000 common units of ARP, subject to adjustment as provided for under the ARP LTIP, may be issued pursuant to awards granted under the ARP LTIP. The ARP LTIP is administered by the Compensation Committee of the board (the “ARP LTIP Committee”). At December 31, 2013, ARP had 2,322,483 phantom units, restricted units and unit options outstanding under the ARP LTIP, with 352,586 phantom units, restricted units and unit options available for grant.

In the case of awards held by eligible employees, following a “change in control”, as defined in the ARP LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the ARP LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full.

In connection with a change in control, the ARP LTIP Committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which New Atlas, as general partner, (or any affiliate) and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason):

 

•

cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity);

 

•

accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to ARP’s common units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction;

 

•

provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards);

 

•

terminate all or some awards upon the consummation of the change-in-control transaction, but only if the ARP LTIP Committee provides for full vesting of awards immediately prior to the consummation of such transaction; and

 

•

make such other modifications, adjustments or amendments to outstanding awards or the new equity plan as the ARP LTIP Committee deems necessary or appropriate.

 

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ARP Phantom Units. Phantom units granted under the ARP LTIP generally will vest 25% of the original granted amount on each of the four anniversaries of the date of grant. Of the phantom units outstanding under the ARP LTIP at December 31, 2013, 278,795 units will vest within the following twelve months. All phantom units outstanding under the ARP LTIP at December 31, 2013 include DERs. During the years ended December 31, 2013 and 2012, ARP paid $1.9 million and $0.7 million, respectively, with respect to the 2012 ARP LTIP’s DERs. No amounts were paid during the year ended December 31, 2011. These amounts were recorded as reductions of equity on New Atlas’s combined consolidated balance sheets.

The following table sets forth the ARP LTIP phantom unit activity for the periods indicated:

 

		Years Ended December 31,
		2013								2012								2011
		Number of Units				Weighted Average Grant Date Fair Value				Number of Units				Weighted Average Grant Date Fair Value				Number of Units				Weighted Average Grant Date Fair Value
Outstanding, beginning of year			948,476			$	24.76				—			$	—				—			$	—
Granted			145,813				21.87				949,476				24.76				—				—
Vested(1)			(215,981	)			24.73				—				—				—				—
Forfeited			(38,500	)			23.96				(1,000	)			24.67				—				—
Outstanding, end of year(2)(3)			839,808			$	24.31				948,476			$	24.76				—			$	—
Non-cash compensation expense recognized (in thousands)						$	9,166							$	7,630							$	—

 

(1)	The intrinsic value of phantom unit awards vested during the year ended December 31, 2013 was $6.1 million. No phantom unit awards vested during the years ended December 31, 2012 and 2011.

(2)	The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2013 was $17.2 million.

(3)

There was approximately $81,000 and $31,000 recognized as liabilities on New Atlas’s combined consolidated balance sheets at December 31, 2013 and December 31, 2012, respectively, representing 16,084 and 3,476 units, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units were $22.15 and $28.75 at December 31, 2013 and 2012, respectively.

At December 31, 2013, ARP had approximately $8.9 million in unrecognized compensation expense related to unvested phantom units outstanding under the ARP LTIP based upon the fair value of the awards.

ARP Unit Options. The exercise price of the unit option may be equal to or more than the fair market value of ARP’s common unit on the date of grant of the option. Unit option awards expire 10 years from the date of grant. Unit options granted under the ARP LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. There were 370,750 unit options outstanding under the ARP LTIP at December 31, 2013 that will vest within the following twelve months. No cash was received from the exercise of options for the years ended December 31, 2013, 2012 and 2011.

 

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The following table sets forth the ARP LTIP unit option activity for the periods indicated:

 

		Years Ended December 31,
		2013								2012								2011
		Number of Unit Options				Weighted Average Exercise Price				Number of Unit Options				Weighted Average Exercise Price				Number of Unit Options				Weighted Average Exercise Price
Outstanding, beginning of year			1,515,500			$	24.68				—			$	—				—			$	—
Granted			5,000				21.56				1,517,500				24.68				—				—
Exercised(1)			—				—				—				—				—				—
Forfeited			(37,825	)			24.80				(2,000	)			24.67				—				—
Outstanding, end of year(2)(3)			1,482,675			$	24.66				1,515,500			$	24.68				—			$	—
Options exercisable, end of year(4)			370,700			$	24.67				—			$	—				—			$	—
Non-cash compensation expense recognized (in thousands)						$	3,514							$	3,198							$	—

 

(1)	No options were exercised during the years ended December 31, 2013, 2012 and 2011.

(2)	The weighted average remaining contractual life for outstanding options at December 31, 2013 was 8.4 years.

(3)	The aggregate intrinsic value of options outstanding at December 31, 2013 was approximately $1,000.

(4)	The weighted average remaining contractual life for exercisable options at December 31, 2013 was 8.4 years. There were no aggregate intrinsic values of options exercisable at December 31, 2013, 2012 and 2011.

At December 31, 2013, ARP had approximately $2.8 million in unrecognized compensation expense related to unvested unit options outstanding under the ARP LTIP based upon the fair value of the awards. ARP used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted.

The following weighted average assumptions were used for the periods indicated:

 

		Years Ended December 31,
		2013				2012				2011
Expected dividend yield			8.0	%			5.9	%			—	%
Expected unit price volatility			35.5	%			47.0	%			—	%
Risk-free interest rate			1.4	%			1.0	%			—	%
Expected term (in years)			6.31				6.25				—
Fair value of unit options granted		$	2.95			$	6.10			$	—

 

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NOTE 16—OPERATING SEGMENT INFORMATION

New Atlas’s operations include three reportable operating segments: ARP, New Atlas, and corporate and other. These operating segments reflect the way New Atlas manages its operations and makes business decisions. ARP consists of ARP’s operations. New Atlas includes the operations of the Arkoma assets and the Development Subsidiary (see Note 1). Corporate and other includes New Atlas’s equity investment in Lightfoot (see Note 1), as well as its general and administrative and interest expenses. Operating segment data for the periods indicated were as follows (in thousands):

 

		Years Ended December 31,
		2013				2012				2011
Atlas Resource:
Revenues		$	467,655			$	267,629			$	247,522
Operating costs and expenses			(348,812	)			(246,267	)			(189,846	)
Depreciation, depletion and amortization expense			(136,763	)			(52,582	)			(31,938	)
Asset impairment			(38,014	)			(9,507	)			(6,995	)
Gain (loss) on asset sales and disposal			(987	)			(6,980	)			87
Interest expense			(34,324	)			(4,195	)			—
Segment income (loss)		$	(91,245	)		$	(51,902	)		$	18,830
New Atlas:
Revenues		$	7,123			$	—			$	—
Operating costs and expenses			(2,941	)			—				—
Depreciation, depletion and amortization expense			(3,153	)			—				—
Segment income		$	1,029			$	—			$	—
Corporate and other:
Revenues		$	321			$	1,540			$	16,557
General and administrative			(11,894	)			(6,352	)			(152	)
Gain on asset sales and disposal			—				—				3
Interest expense			(5,388	)			(353	)			(4,244	)
Segment income (loss)		$	(16,961	)		$	(5,165	)		$	12,164
Reconciliation of segment income (loss) to net income (loss):
Segment income (loss):
Atlas Resource		$	(91,245	)		$	(51,902	)		$	18,830
New Atlas			1,029				—				—
Corporate and other			(16,961	)			(5,165	)			12,164
Net income (loss)		$	(107,177	)		$	(57,067	)		$	30,994
Reconciliation of segment revenues to total revenues:
Segment revenues:
Atlas Resource		$	467,655			$	267,629			$	247,522
New Atlas			7,123				—				—
Corporate and other			321				1,540				16,557
Total revenues		$	475,099			$	269,169			$	264,079
Capital expenditures:
Atlas Resource		$	263,537			$	127,226			$	47,324
New Atlas			3,943				—				—
Corporate and other			—				—				—
Total capital expenditures		$	267,480			$	127,226			$	47,324

 

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		December 31,
		2013				2012
Balance sheet:
Goodwill:
Atlas Resource		$	31,784			$	31,784
New Atlas			—				—
Corporate and other			—				—
		$	31,784			$	31,784
Total assets:
Atlas Resource		$	2,343,800			$	1,498,952
New Atlas			76,004				—
Corporate and other			36,066				27,700
		$	2,455,870			$	1,526,652

NOTE 17—SUBSEQUENT EVENTS

Eagle Ford Asset Acquisition. On September 24, 2014, ARP and the Development Subsidiary entered into a definitive agreement to acquire producing oil and natural gas liquid interests in the Eagle Ford Shale in Atascosa County, Texas (the “Eagle Ford Acquisition”) for approximately $340.0 million, subject to customary closing adjustments. Of the $340.0 million purchase price, $200.0 million will be paid at closing and the balance paid during the twelve months following closing, subject to certain purchase price adjustments. The transaction is expected to close during the fourth quarter 2014 and has an effective date of July 1, 2014.

In connection with the transaction, on October 2, 2014, ARP issued 3,200,000 8.625% Class D cumulative redeemable perpetual preferred units at a public offering price of $25.00 per Class D Unit. ARP will pay cumulative distributions in cash on the Units on a quarterly basis at a rate of $2.15625 per unit, or 8.625% of the liquidation preference, per year.

Also in connection with the transaction, on October 14, 2014, ARP issued $75.0 million of its 9.25% Senior Notes in a private placement transaction under Rule 144A and Regulation S of the Securities Act at an offering price of 100.5%, yielding net proceeds of approximately $73.6 million. In connection with the issuance, ARP also entered into a registration rights agreement. Under the agreement, ARP agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated in July 2015. Under certain circumstances, in lieu of, or in addition to, a registered offer, ARP agreed to file a shelf registration statement with respect to the issuance. If ARP fails to comply with its obligations to register the notes within the specified time periods, ARP will be subject to additional interest, up to 1% per annum, until such time that the exchange offer is consummated or the shelf registration is declared effective, as applicable.

ARP Equity Distribution Agreement. In August 2014, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of the several banks named therein (the “Agents”). Pursuant to the equity distribution agreement, ARP may sell from time to time through the Agents common units representing limited partner interests of ARP having an aggregate offering price of up to $100.0 million. Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act, including sales made directly on the New York Stock Exchange, the existing trading market for the common units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP will pay each of the Agents a commission, which in each case shall not be more than 2.0% of the gross sales price of common units sold through such Agent. Under the terms of the Distribution Agreement, ARP may also sell common units from time to time to any Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of

 

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common units to an Agent as principal would be pursuant to the terms of a separate terms agreement between ARP and such Agent.

Rangely Acquisition. On June 30, 2014, ARP completed an acquisition of a 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado for approximately $407.8 million in cash, net of purchase price adjustments (the “Rangely Acquisition”). The purchase price was funded through borrowings under our revolving credit facility, the issuance of an additional $100.0 million of ARP’s 7.75% senior notes due 2021 and the issuance of 15,525,000 common limited partner units. The Rangely Acquisition had an effective date of April 1, 2014. Our combined consolidated financial statements will reflect the operating results of the acquired business commencing June 30, 2014. Due to the recent date of the acquisition, the subsequent accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as New Atlas continues to evaluate the facts and circumstances that existed as of the acquisition date.

GeoMet Acquisition. On May 12, 2014, ARP completed the acquisition of assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $107.0 million in cash with an effective date of January 1, 2014. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia. Due to the recent date of the acquisition, the subsequent accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as New Atlas continues to evaluate the facts and circumstances that existed as of the acquisition date.

Issuance of Common Units. In May 2014, in connection with the closing of the Rangely Acquisition, ARP issued 15,525,000 of its common limited partner units (including 2,025,000 units pursuant to an over-allotment option) in a public offering at a price of $19.90 per unit, yielding net proceeds of approximately $297.5 million. The units were registered under the Securities Act, pursuant to a shelf registration statement on Form S-3, which was automatically effective on the filing date of February 3, 2014. In March 2014, ARP issued 6,325,000 of its common limited partner units (including 825,000 units pursuant to an over-allotment option) in a public offering at a price of $21.18 per unit, yielding net proceeds of approximately $129.1 million. The units were registered under the Securities Act, pursuant to a shelf registration statement on Form S-3, which was automatically effective on the filing date of February 3, 2014.

NOTE 18—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil, Gas and NGL Reserve Information. The preparation of New Atlas’s and ARP’s natural gas, oil and NGL reserve estimates were completed in accordance with New Atlas’s and ARP’s prescribed internal control procedures by New Atlas’s and ARP’s reserve engineers. The accompanying reserve information included below was derived from the reserve reports prepared for Atlas Energy’s and ARP’s annual reports on Form 10-K for the year ended December 31, 2013. For the periods presented, Wright and Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves. The reserve information includes natural gas, oil and NGL reserves which are all located throughout the United States. The independent reserves engineer’s evaluation was based on more than 37 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. New Atlas and ARP’s internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by New Atlas and ARP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 15 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by Atlas Energy’s senior engineering staff and management, with final approval by the Chief Operating Officer and President.

The reserve disclosures that follow reflect New Atlas’s and ARP’s estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of royalty interests, of natural gas, crude oil and NGLs owned at year end and changes in proved reserves during the last three years. Proved oil, gas and NGL reserves

 

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are those quantities of oil, gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved developed reserves are those reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for undeveloped reserves cannot be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. The proved reserves quantities and future net cash flows as of December 31, 2013, 2012 and 2011 were estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, 2013, 2012 and 2011, including adjustments related to regional price differentials and energy content.

There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of oil and gas reserves included within New Atlas and ARP or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors, for their effects have not been proved.

Reserve quantity information and a reconciliation of changes in proved reserve quantities included within New Atlas and ARP are as follows (unaudited):

 

		Gas (Mcf)				Oil (Bbls)(1)				NGLs (Bbls)(1)
Balance, January 1, 2011			176,065,003				1,832,535				—
Extensions, discoveries and other additions(2)			9,966,952				8,217				—
Sales of reserves in-place			(990	)			—				—
Purchase of reserves in-place			586,662				2,216				—
Transfers to limited partnerships			(6,042,432	)			—				—
Revisions(3)			(11,436,615	)			77,661				—
Production			(11,462,149	)			(274,330	)			—
Balance, December 31, 2011			157,676,431				1,646,299				—
Extensions, discoveries and other additions(2)			6,756,817				10,688				—
Sales of reserves in-place			—				—				—
Purchase of reserves in-place			462,504,519				7,485,998				16,212,356
Transfers to limited partnerships			—				—				—
Revisions(4)			(27,760,192	)			(153,413	)			206,091
Production			(25,403,318	)			(120,736	)			(356,550	)
Balance, December 31, 2012(5)			573,774,257				8,868,836				16,061,897

 

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		Gas (Mcf)				Oil (Bbls)(1)				NGLs (Bbls)(1)
Extensions, discoveries and other additions(2)			90,098,219				8,255,531				8,197,272
Sales of reserves in-place			(2,755,155	)			—				(4,625	)
Purchase of reserves in-place			493,481,302				1,964				55,187
Transfers to limited partnerships			(2,485,210	)			(239,910	)			(258,381	)
Revisions(6)			(88,484,468	)			(1,412,371	)			(3,826,744	)
Production			(59,849,442	)			(485,226	)			(1,267,590	)
Balance, December 31, 2013			1,003,779,503				14,988,824				18,957,016
Proved developed reserves at(5):
January 1, 2011			137,393,017				1,832,535				—
December 31, 2011			138,403,225				1,638,083				—
December 31, 2012			338,655,324				3,400,447				7,884,778
December 31, 2013			766,872,394				3,459,260				7,676,389
Proved undeveloped reserves at:
January 1, 2011			38,671,986				—				—
December 31, 2011			19,273,206				8,216				—
December 31, 2012			235,118,932				5,468,389				8,177,120
December 31, 2013			236,907,109				11,529,564				11,280,627

 

(1)	Oil includes NGL information for the year ended December 31, 2011, which was less than 500 MBbls.

(2)	Principally includes increases of proved reserves due to the addition of Marcellus wells.

(3)	Represents a downward revision of proved undeveloped reserves in the New Albany Shale due to the reduction of certain drilling plans related to ARP’s shallow natural gas wells, as well as a downward revision and related impairment charge related to ARP’s shallow natural gas wells in Colorado.

(4)	Represents a downward revision and related impairment charge related to ARP’s shallow natural gas wells in Michigan and Colorado due to declines in the average 1st day of the month price for the year ended December 31, 2012 as compared with the year ended December 31, 2011.

(5)	Prior to the Arkoma Acquisition on July 31, 2013, New Atlas had no oil and gas reserves. At December 31, 2013, there were no proved undeveloped reserves related to New Atlas’s oil and gas assets.

(6)	Represents a downward revision primarily due to a reduction of ARP’s five year drilling plans in the Barnett Shale and pricing scenario revisions.

Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities of New Atlas and ARP during the periods indicated were as follows (in thousands):

 

		Years Ended December 31,
		2013				2012
Natural gas and oil properties:
Proved properties		$	2,557,797			$	1,468,886
Unproved properties			211,851				292,053
Support equipment			23,258				13,110
			2,792,906				1,774,049
Accumulated depreciation, depletion and amortization			(649,635	)			(504,625	)
Net capitalized costs		$	2,143,271			$	1,269,424

 

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Results of Operations from Oil and Gas Producing Activities. The results of operations related to New Atlas’s and ARP’s oil and gas producing activities during the periods indicated were as follows (in thousands):

 

		Years Ended December 31,
		2013				2012				2011
Revenues		$	273,906			$	92,901			$	66,979
Production costs			(100,178	)			(26,624	)			(17,100	)
Depreciation, depletion and amortization			(132,860	)			(47,000	)			(27,430	)
Asset impairment(1)			(38,014	)			(9,507	)			(6,995	)
		$	2,854			$	9,770			$	15,454

 

(1)

During the year ended December 31, 2013, ARP recognized $38.0 million of impairment primarily related to its shallow natural gas wells in the New Albany shale and unproved acreage in the Chattanooga and New Albany shales. During the year ended December 31, 2012, ARP recognized $9.5 million of impairment related to its shallow natural gas wells in the Antrim and Niobrara shales. During the year ended December 31, 2011, ARP recognized $7.0 million of impairment related to its shallow natural gas wells in the Niobrara Shale.

Costs Incurred in Oil and Gas Producing Activities. The costs incurred by New Atlas and ARP in their oil and gas activities during the periods indicated are as follows (in thousands):

 

		Years Ended December 31,
		2013				2012				2011
Property acquisition costs:
Proved properties		$	863,421			$	528,684			$	9,199
Unproved properties			895				213,638				323
Exploration costs(1)			1,053				1,026				1,156
Development costs			214,383				83,538				29,809
Total costs incurred in oil & gas producing activities		$	1,079,752			$	826,886			$	40,487

 

(1)	There were no exploratory wells drilled during the years ended December 31, 2013, 2012 and 2011.

 

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Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to New Atlas’s and ARP’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2013, 2012 and 2011, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (in thousands):

 

		Years Ended December 31,
		2013				2012				2011
Future cash inflows		$	5,268,148			$	2,930,514			$	949,286
Future production costs			(2,397,997	)			(1,185,084	)			(425,493	)
Future development costs			(752,369	)			(441,423	)			(27,266	)
Future net cash flows			2,117,782				1,304,007				496,527
Less 10% annual discount for estimated timing of cash flows			(1,038,491	)			(680,331	)			(276,668	)
Standardized measure of discounted future net cash flows		$	1,079,291			$	623,676			$	219,859

Changes in Standardized Discounted Future Cash Flows. The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil, gas and NGL reserves (in thousands), including amounts related to asset retirement obligations. Since New Atlas and ARP allocate taxable income to their owner, no recognition has been given to income taxes:

 

		Years Ended December 31,
		2013				2012				2011
Balance, beginning of year		$	623,676			$	219,859			$	236,630
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs			(171,409	)			(54,969	)			(46,304	)
Net changes in prices and production costs			85,191				(87	)			(34	)
Revisions of previous quantity estimates			(1,881	)			(6,378	)			757
Development costs incurred			27,245				575				1,842
Changes in future development costs			(21,579	)			—				(3,591	)
Transfers to limited partnerships			(53,392	)			—				(8,022	)
Extensions, discoveries, and improved recovery less related costs			143,338				64				14,923
Purchases of reserves in-place			516,985				510,467				736
Sales of reserves in-place			(2,053	)			—				(1	)
Accretion of discount			62,368				21,986				23,663
Estimated settlement of asset retirement obligations			(18,858	)			(2,823	)			(3,105	)
Estimated proceeds on disposals of well equipment			17,052				3,806				3,363
Changes in production rates (timing) and other			(127,392	)			(68,824	)			(998	)
Outstanding, end of year		$	1,079,291			$	623,676			$	219,859

 

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NEW ATLAS OPERATIONS AND SUBSIDIARIES

COMBINED CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

 

		September 30, 2014				December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents		$	56,755			$	10,625
Accounts receivable			103,160				60,167
Advances to affiliates			5,473				2,912
Current portion of derivative asset			21,634				1,891
Subscriptions receivable			62,840				47,692
Prepaid expenses and other			25,128				10,181
Total current assets			274,990				133,468
Property, plant and equipment, net			2,728,650				2,186,683
Intangible assets, net			759				963
Goodwill			31,784				31,784
Long-term derivative asset			32,096				28,598
Other assets, net			84,997				74,374
		$	3,153,276			$	2,455,870
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt		$	1,500			$	1,500
Accounts payable			119,643				70,228
Liabilities associated with drilling contracts			—				49,377
Current portion of derivative liability			1,792				6,386
Current portion of derivative payable to Drilling Partnerships			383				2,676
Accrued interest			10,867				20,649
Accrued well drilling and completion costs			100,721				40,899
Accrued liabilities			47,357				34,097
Total current liabilities			282,263				225,812
Long-term debt, less current portion			1,430,022				1,090,459
Long-term derivative liability			—				67
Asset retirement obligations and other			110,336				95,536
Commitments and contingencies
Equity:
Owner’s equity			336,532				357,378
Accumulated other comprehensive income			15,744				10,338
			352,276				367,716
Non-controlling interests			978,379				676,280
Total equity			1,330,655				1,043,996
		$	3,153,276			$	2,455,870

See accompanying notes to combined consolidated financial statements.

 

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NEW ATLAS OPERATIONS AND SUBSIDIARIES

COMBINED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

 

		Nine Months Ended September 30,
		2014				2013
Revenues:
Gas and oil production		$	342,456			$	176,190
Well construction and completion			126,917				92,293
Gathering and processing			11,287				11,639
Administration and oversight			12,072				8,923
Well services			18,441				14,703
Other, net			1,167				(14,459	)
Total revenues			512,340				289,289
Costs and expenses:
Gas and oil production			134,590				64,837
Well construction and completion			110,363				80,255
Gathering and processing			11,900				13,767
Well services			7,525				7,009
General and administrative			63,487				73,037
Depreciation, depletion and amortization			177,513				86,392
Total costs and expenses			505,378				325,297
Operating income (loss)			6,962				(36,008	)
Loss on asset sales and disposal			(1,683	)			(2,035	)
Interest expense			(51,474	)			(24,704	)
Net loss			(46,195	)			(62,747	)
Loss attributable to non-controlling interests			33,828				31,484
Net loss attributable to owner		$	(12,367	)		$	(31,263	)

See accompanying notes to combined consolidated financial statements.

 

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NEW ATLAS OPERATIONS AND SUBSIDIARIES

COMBINED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)

 

		Nine Months Ended September 30,
		2014				2013
Net loss		$	(46,195	)		$	(62,747	)
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges			5,268				35,875
Less: reclassification adjustment for realized (gains) losses of cash flow hedges in net loss			22,703				(4,579	)
Total other comprehensive income (loss)			27,971				31,296
Comprehensive loss			(18,224	)			(31,451	)
Comprehensive loss attributable to non-controlling interests			11,263				10,430
Comprehensive loss attributable to owners		$	(6,961	)		$	(21,021	)

See accompanying notes to combined consolidated financial statements.

 

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NEW ATLAS OPERATIONS AND SUBSIDIARIES

COMBINED CONSOLIDATED STATEMENT OF EQUITY

(in thousands, except unit data)

(Unaudited)

 

		Owners’ Equity				Accumulated Other Comprehensive Income/(Loss)				Non- Controlling Interest				Total Equity
Balance January 1, 2014		$	357,378			$	10,338			$	676,280			$	1,043,996
Distributions to non-controlling interests			—				—				(103,582	)			(103,582	)
Net issued and unissued units under incentive plans			—				—				5,579				5,579
Net distribution to Atlas Energy			(52,904	)			—				—				(52,904	)
Distribution equivalent rights paid on unissued units under incentive plans			—				—				(1,696	)			(1,696	)
Distributions payable by Atlas Resource Partners, L.P.			—				—				(12,665	)			(12,665	)
Gain on sale of subsidiary unit issuances			44,425				—				(44,425	)			—
Non-controlling interests’ capital contributions			—				—				470,151				470,151
Other comprehensive income			—				5,406				22,565				27,971
Net loss			(12,367	)			—				(33,828	)			(46,195	)
Balance at September 30, 2014		$	336,532			$	15,744			$	978,379			$	1,330,655

See accompanying notes to combined consolidated financial statements.

 

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NEW ATLAS OPERATIONS AND SUBSIDIARIES

COMBINED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

 

		Nine Months Ended September 30,
		2014				2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss		$	(46,195	)		$	(62,747	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization			177,513				86,392
Amortization of deferred financing costs			7,039				9,024
Non-cash compensation expense			6,343				10,209
Loss on asset sales and disposal			1,683				2,035
Distributions paid to non-controlling interests			(105,278	)			(50,890	)
Equity income in unconsolidated companies			(833	)			(2,417	)
Distributions received from unconsolidated companies			1,244				729
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other			(73,588	)			9,960
Accounts payable and accrued liabilities			5,489				(80,754	)
Net cash used in operating activities			(26,583	)			(78,459	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures			(162,726	)			(205,827	)
Net cash paid for acquisitions			(507,093	)			(777,096	)
Other			(2,060	)			(7,356	)
Net cash used in investing activities			(671,879	)			(990,279	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facilities			1,034,000				917,625
Repayments under credit facilities			(794,125	)			(699,675	)
Net proceeds from issuance of subsidiary long-term debt			97,386				510,518
Net proceeds from subsidiary equity offerings			470,151				320,092
Net investment from (distributions to) Atlas Energy			(52,904	)			21,790
Deferred financing costs, distribution equivalent rights and other			(9,916	)			(23,313	)
Net cash provided by financing activities			744,592				1,047,037
Net change in cash and cash equivalents			46,130				(21,701	)
Cash and cash equivalents, beginning of year			10,625				23,270
Cash and cash equivalents, end of period		$	56,755			$	1,569

See accompanying notes to combined consolidated financial statements.

 

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NEW ATLAS OPERATIONS AND SUBSIDIARIES

NOTES TO COMBINED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2014

(Unaudited)

NOTE 1—BASIS OF PRESENTATION

Atlas Energy Group, LLC is a Delaware limited liability company and a wholly owned subsidiary of Atlas Energy, L.P. (“the Company” or “Atlas Energy”). Atlas Energy ( NYSE: ATLS), a publicly traded Delaware master-limited partnership, intends to transfer to Atlas Energy Group, LLC Atlas Energy’s interests not related to its Atlas Pipeline Partners (“APL”) interests. Collectively, Atlas Energy Group, LLC, the entities and assets referenced below, along with the allocated entity-level activity of Atlas Energy, are considered to be “New Atlas” (see Note 2). In connection with the transfer of Atlas Energy’s interests to New Atlas, Atlas Energy intends to distribute 100% of New Atlas’s common units to common unitholders of Atlas Energy. Following the distribution of the New Atlas’s common units and the transfer of assets from Atlas Energy, New Atlas’s operations will be its interests in the following:

 

•

ARP, a publicly traded Delaware master limited partnership (NYSE: ARP) and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”), with operations in basins across the United States. ARP sponsors and manages tax-advantaged investment partnerships (“Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas and oil production activities. At September 30, 2014, Atlas Energy owned 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 27.7% limited partner interest (20,962,485 common and 3,749,986 Class C preferred limited partner units) in ARP;

 

•

Atlas Energy Development Subsidiary (“Development Subsidiary”), a subsidiary partnership formed in 2013 that conducts natural gas and oil operations initially in the mid-continent region of the United States, currently in the Marble Falls formation in the Fort Worth Basin and Mississippi Lime area of the Anadarko basin in Oklahoma. At September 30, 2014, Atlas Energy owned a 3.1% limited partner interest in the Development Subsidiary and 80.0% of its outstanding general partner Class A units, which are entitled to receive 2.0% of the cash distributed without any obligation to make further capital contributions;

 

•

Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and Lightfoot Capital Partners GP, LLC (“Lightfoot GP”), the general partner of Lightfoot L.P. (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. At September 30, 2014, Atlas Energy had an approximate 15.9% general partner interest and 12.0% limited partner interest in Lightfoot; and

 

•

coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma, which were acquired by Atlas Energy in July 2013.

In February 2012, the Board approved the formation of ARP as a newly created exploration and production master limited partnership and the related transfer of substantially all of Atlas Energy’s exploration and production assets to ARP on March 5, 2012. The Board also approved the distribution of approximately 5.24 million ARP common units to Atlas Energy’s unitholders, which were distributed on March 13, 2012 using a ratio of 0.1021 ARP limited partner units for each of Atlas Energy’s common units owned on the record date of February 28, 2012.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Combination

The combined consolidated balance sheets at September 30, 2014 and December 31, 2013 and the related combined consolidated statements of operations for the nine months ended September 30, 2014 and 2013 were derived from the separate records maintained by Atlas Energy and may not necessarily be indicative of the

 

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conditions that would have existed or the results of operations if New Atlas had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various entities comprising New Atlas, Atlas Energy’s net investment in New Atlas is shown as equity in the combined consolidated financial statements. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the combined consolidated balance sheets and related combined consolidated statements of operations. Such estimates included allocations made from the historical accounting records of Atlas Energy, based on management’s best estimates, in order to derive the financial statements of New Atlas. Actual balances and results could be different from those estimates. Transactions between New Atlas and other Atlas Energy operations have been identified in the combined consolidated financial statements as transactions between affiliates.

New Atlas combines the financial statements of ARP and the Development Subsidiary into its combined consolidated financial statements rather than present its ownership interest as equity investments, as New Atlas will control these entities through its general partnership interests therein. As such, the non-controlling interests in ARP and the Development Subsidiary are reflected as (income) loss attributable to non-controlling interests in its combined consolidated statements of operations and as a component of equity on its combined consolidated balance sheets. All material intercompany transactions have been eliminated.

In connection with ARP’s acquisition of certain proved reserves and associated assets from Titan Operating, L.L.C. in July 2012, ARP issued 3.8 million ARP common units and 3.8 million newly created convertible Class B ARP preferred units. While outstanding, the preferred units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. At September 30, 2014 and 2013, ARP recorded $95.1 million and $96.5 million, respectively, related to the Class B preferred units within non-controlling interests on New Atlas’s combined consolidated statements of equity.

In accordance with established practice in the oil and gas industry, New Atlas’s combined consolidated financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the Drilling Partnerships in which ARP has an interest. Such interests generally approximate 30%. New Atlas’s combined consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of ARP’s Drilling Partnerships. Rather, ARP calculates these items specific to its own economics as further explained under the heading “Property, Plant and Equipment” elsewhere within this note.

During the nine months ended September 30, 2014, the Development Subsidiary issued $53.0 million of its common limited partner units, which was included within non-controlling interests on New Atlas’s combined consolidated balance sheets. During the nine months ended September 30, 2014, the Development Subsidiary paid $0.6 million to unitholders, which was included within distributions paid to non-controlling interests on New Atlas’s combined consolidated statement of cash flows. For the nine months ended September 30, 2014, in connection with the issuance of the Development Subsidiary’s common units, New Atlas recorded gains of $3.8 million within equity and a corresponding decrease in non-controlling interests on its combined consolidated balance sheets and combined consolidated statement of equity.

All adjustments, in the opinion of management, necessary for a fair statement of the results of operations for the interim periods presented have been made, and all such adjustments are of a normal, recurring nature.

Use of Estimates

The preparation of New Atlas’s combined consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of New Atlas’s combined consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. New Atlas’s combined consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value

 

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of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired and liabilities assumed. Such estimates included estimated allocations made from the historical accounting records of Atlas Energy in order to derive the historical financial statements of New Atlas. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the nine months ended September 30, 2014 and 2013 represent actual results in all material respects (see “Revenue Recognition”).

Receivables

Accounts receivable on the combined consolidated balance sheets consist primarily of the trade accounts receivable associated with New Atlas. In evaluating the realizability of its accounts receivable, management performs ongoing credit evaluations of customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of customers’ credit information. New Atlas extends credit on sales on an unsecured basis to many of its customers. At September 30, 2014 and December 31, 2013, New Atlas had recorded no allowance for uncollectible accounts receivable on its combined consolidated balance sheets.

Inventory

New Atlas had $8.9 million and $4.6 million of inventory at September 30, 2014 and December 31, 2013, respectively, which were included within prepaid expenses and other current assets on its combined consolidated balance sheets. New Atlas values inventories at the lower of cost or market. New Atlas inventories, which consist primarily of ARP’s materials, pipes, supplies and other inventories, were principally determined using the average cost method.

Subscriptions Receivable

ARP receives contributions from limited partner investors of its Drilling Partnerships, which are used to fund well drilling activities within the programs. Limited partner investors in the Drilling Partnerships execute an investment agreement with Anthem Securities, Inc. (“Anthem”), a registered broker-dealer and wholly owned subsidiary of ARP, through third-party broker dealers, which are then delivered to Anthem with the contribution remitted to Anthem at a later date. Limited partner investor contributions are non-refundable upon the execution of an investment agreement. ARP recognizes the contributions associated with executed investment agreements but for which contributions have not yet been received at the respective balance sheet date as subscriptions receivable.

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements which generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is based on cost, less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in New Atlas’s results of operations.

 

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New Atlas follows the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. “Mcf” is defined as one thousand cubic feet.

New Atlas’s and ARP’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include ARP’s costs of property interests in proportionately consolidated Drilling Partnerships, joint venture wells, wells drilled solely by ARP for its interests, properties purchased and working interests with other outside operators.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is recognized to New Atlas’s combined consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within New Atlas’s combined consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in New Atlas’s combined consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

Impairment of Long-Lived Assets

New Atlas reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on New Atlas’s plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. New Atlas estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, ARP’s reserve estimates for its investment in the Drilling Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include ARP’s actual capital contributions and a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

 

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ARP’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to ARP their proportionate share of these expenses plus a profit margin. These assumptions could result in ARP’s calculation of depletion and impairment being different than its proportionate share of the Drilling Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. New Atlas and ARP cannot predict what reserve revisions may be required in future periods.

ARP’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Drilling Partnerships, which ARP sponsors and owns an interest in but does not control. ARP’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which ARP may be unable to recover due to the Drilling Partnerships’ legal structure. ARP may have to pay additional consideration in the future as a Drilling Partnership’s wells become uneconomic to the Drilling Partnership under the terms of the Drilling Partnership’s drilling and operating agreement in order to recover these excess reserves, in addition to ARP becoming responsible for paying associated future operating, development and plugging costs of the well interests acquired, and to acquire any additional residual interests in the wells held by the Drilling Partnership’s limited partners. The acquisition of any such uneconomic well interest from the Drilling Partnership by ARP is governed under the Drilling Partnership’s limited partner agreement. In general, ARP will seek consent from the Drilling Partnership’s limited partners to acquire the well interests from the Drilling Partnership based upon ARP’s determination of fair market value.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate that New Atlas will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. During the year ended December 31, 2013, ARP recognized $13.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on New Atlas’s combined consolidated balance sheet, primarily for its unproved acreage in the Chattanooga and New Albany Shales. There were no impairments of unproved gas and oil properties recorded by New Atlas for the nine months ended September 30, 2014 and 2013.

Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2013, ARP recognized $24.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on New Atlas’s combined consolidated balance sheet for ARP’s shallow natural gas wells in the New Albany Shale. There were no impairments of proved gas and oil properties recorded by New Atlas for the nine months ended September 30, 2014 and 2013.

The impairments of proved and unproved properties during the year ended December 31, 2013 related to the carrying amounts of these gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2013 and ARP’s intention not to drill on certain expiring unproved acreage. The estimate of the fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

Capitalized Interest

ARP capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP was 5.7% and 6.1% for the nine months ended September 30, 2014 and 2013, respectively. The aggregate amount of interest capitalized by ARP was $9.4 million and $10.5 million for the nine months ended September 30, 2014 and 2013, respectively.

 

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Intangible Assets

ARP has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. ARP amortizes contracts acquired on a declining balance method over their respective estimated useful lives.

The following table reflects the components of intangible assets being amortized at September 30, 2014 and December 31, 2013 (in thousands):

 

		September 30, 2014				December 31, 2013				Estimated Useful Lives In Years
Gross Carrying Amount		$	14,344			$	14,344				13
Accumulated Amortization			(13,585	)			(13,381	)
Net Carrying Amount		$	759			$	963

Amortization expense on intangible assets was $0.2 million and $0.3 million for the nine months ended September 30, 2014 and 2013, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2014—$0.3 million; 2015—$0.2 million; 2016—$0.1 million, 2017—$0.1 million and 2018—$0.1 million.

Goodwill

At September 30, 2014 and December 31, 2013, New Atlas had $31.8 million of goodwill recorded in connection with ARP’s prior consummated acquisitions. No changes in the carrying amount of goodwill were recorded for the nine months ended September 30, 2014 and 2013.

ARP tests goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units. ARP’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets and the available market data of the respective industry group. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including ARP’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, ARP also considers the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ARP’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in ARP’s industry to determine whether those valuations appear reasonable in management’s judgment. ARP’s management will continue to evaluate goodwill at least annually or when impairment indicators arise. During the nine months ended September 30, 2014 and 2013, no impairment indicators arose, and no goodwill impairments were recognized for ARP by New Atlas.

Asset Retirement Obligations

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current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. New Atlas also considers the estimated salvage value in the calculation of depreciation, depletion and amortization.

Income Taxes

ARP, Development Subsidiary, Lightfoot and the respective subsidiaries thereof are not subject to U.S. federal and most state income taxes. The partners of these entities are liable for income tax in regard to their distributive share of the entities taxable income. Such taxable income may vary substantially from net income (loss) reported in the accompanying combined consolidated financial statements. Certain corporate subsidiaries of ARP are subject to federal and state income tax. The federal and state income taxes related to New Atlas and these corporate subsidiaries were immaterial to the combined consolidated financial statements as of September 30, 2014 and are recorded in pre-tax income on a current basis only. Accordingly, no federal and state deferred income tax has been provided for these corporate subsidiaries in the accompanying combined consolidated financial statements.

Each of the entities which comprise New Atlas evaluate tax positions taken or expected to be taken in the course of preparing their respective tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. New Atlas’s management does not believe it has taken any tax positions within its combined consolidated financial statements that would not meet this threshold. New Atlas’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. New Atlas has not recognized any potential interest or penalties in its combined consolidated financial statements for the nine months ended September 30, 2014 and 2013.

The entities comprising New Atlas file Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the entities comprising New Atlas are no longer subject to income tax examinations by major tax authorities for years prior to 2011 and are not currently being examined by any jurisdiction and are not aware of any potential examinations as of September 30, 2014.

General and Administrative Expenses

For the nine months ended September 30, 2014 and 2013, Atlas Energy has allocated $5.8 million and $5.9 million, respectively, of its historical general and administrative expenses to New Atlas according to the amounts associated with the management of New Atlas’s operations. New Atlas has reviewed Atlas Energy’s general and administrative expense allocation methodology and believes the methodology is reasonable and reflects the approximate general and administrative costs of the management of its operations.

Interest Expense

For the nine months ended September 30, 2014 and 2013, Atlas Energy has allocated $8.4 million and $2.6 million, respectively, of its historical interest expense to New Atlas according to the amounts associated with the financing of New Atlas’s operations. New Atlas has reviewed Atlas Energy’s interest expense allocation methodology and believes the methodology is reasonable and reflects the approximate interest expense associated with the management of its operations.

Revenue Recognition

Natural gas and oil production. New Atlas’s and ARP’s gas and oil production operations generally sell natural gas, crude oil and NGLs at prevailing market prices. Typically, sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized

 

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when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibilities of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which New Atlas has an interest with other producers, are recognized on the basis of the entity’s percentage ownership of the working interest and/or overriding royalty.

ARP’s Drilling Partnerships. Certain energy activities are conducted by ARP through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by ARP is deployed to drill and complete wells included within the partnership. As ARP deploys Drilling Partnership investor capital, it recognizes certain management fees it is entitled to receive, including well construction and completion revenue and a portion of administration and oversight revenue. At each period end, if ARP has Drilling Partnership investor capital that has not yet been deployed, it will recognize a current liability titled “Liabilities Associated with Drilling Contracts” on New Atlas’s combined consolidated balance sheets. After the Drilling Partnership well is completed and turned in line, ARP is entitled to receive additional operating and management fees, which are included within well services and administration and oversight revenue, respectively, on a monthly basis while the well is operating. In addition to the management fees it is entitled to receive for services provided, ARP is also entitled to its pro-rata share of Drilling Partnership gas and oil production revenue, which generally approximate 30%. ARP recognizes its Drilling Partnership management fees in the following manner:

 

•

Well construction and completion. For each well that is drilled by a Drilling Partnership, ARP receives a 15% mark-up on those costs incurred to drill and complete wells included within the partnership. Such fees are earned, in accordance with the partnership agreement, and recognized as the services are performed, typically between 60 and 270 days, using the percentage of completion method.

 

•

Administration and oversight. For each well drilled by a Drilling Partnership, ARP receives a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which is earned, in accordance with the partnership agreement, and recognized at the initiation of the well. Additionally, the Drilling Partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. The well administrative fee is earned on a monthly basis as the services are performed.

 

•

Well services. Each Drilling Partnership pays ARP a monthly per well operating fee, currently $100 to $2,000, depending on the type of well, for the life of the well. Such fees are earned on a monthly basis as the services are performed.

While its historical structure has varied, ARP has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically 10% per year determined on a cumulative basis and inclusive of estimated individual tax benefits, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. ARP periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, ARP recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which ARP has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, ARP will recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized.

 

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ARP’s gathering and processing revenue. Gathering and processing revenue includes gathering fees ARP charges to the Drilling Partnership wells for ARP’s processing plants in the New Albany and the Chattanooga Shales. Generally, ARP charges a gathering fee to the Drilling Partnership wells equivalent to the fees ARP remits. In Appalachia, a majority of the Drilling Partnership wells are subject to a gathering agreement, whereby ARP remits a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, ARP charges the Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on New Atlas’s combined consolidated financial statements, and for all periods presented, only include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges (see Note 8). New Atlas does not have any other type of transaction which would be included within other comprehensive income (loss).

Recently Adopted Accounting Standards

In February 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. New Atlas adopted the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures.

Recently Issued Accounting Standards

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early adoption is permitted. New Atlas will adopt the requirements of Update 2014-15 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In June 2014, the FASB issued ASU 2014-12, Compensation—Stock Compensation (Topic 718) (“Update 2014-12”). The amendments in Update 2014-12 require that a performance target that affects vesting and that

 

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could be achieved after the requisite service period be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in Update 2014-12 are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. New Atlas will adopt the requirements of Update 2014-12 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles—Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. New Atlas will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2017, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

NOTE 3—ACQUISITIONS

ARP’s Rangely Acquisition

On June 30, 2014, ARP completed an acquisition of a 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado for approximately $407.8 million in cash, net of purchase price adjustments (the “Rangely Acquisition”). The purchase price was funded through borrowings under ARP’s revolving credit facility, the issuance of an additional $100.0 million of ARP’s 7.75% senior notes due 2021 (“7.75% ARP Senior Notes”) (see Note 7) and the issuance of 15,525,000 of ARP’s common limited partner units (see Note 12). The Rangely Acquisition had an effective date of April 1, 2014. New Atlas’s combined consolidated financial statements reflected the operating results of the acquired business commencing June 30, 2014 with the transaction closing.

ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 9). In conjunction with the issuance of ARP’s common limited partner units associated with the

 

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acquisition, ARP recorded $11.6 million of transaction fees which were included within non-controlling interests at September 30, 2014 on New Atlas’s combined consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as ARP continues to evaluate the facts and circumstances that existed as of the acquisition date.

The following table presents the preliminary values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands):

 

Assets:
Prepaid expenses and other			4,041
Property, plant and equipment			405,065
Other assets, net			2,944
Total current assets		$	412,050
Liabilities:
Accrued liabilities			2,936
Asset retirement obligation			1,305
Total liabilities assumed			4,241
Net assets acquired		$	407,809

ARP’s EP Energy Acquisition

On July 31, 2013, ARP completed the acquisition of assets from EP Energy E&P Company, L.P. (“EP Energy”) for approximately $709.6 million in cash, net of purchase price adjustments (the “EP Energy Acquisition”). ARP funded the purchase price through borrowings under its revolving credit facility, the issuance of its 9.25% senior notes due 2021 (“9.25% ARP Senior Notes”) (see Note 7), and the issuance of 14,950,000 ARP common limited partner units and 3,749,986 newly created ARP Class C convertible preferred units (see Note 12). The assets acquired by ARP in the EP Energy Acquisition included coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming. The EP Energy Acquisition had an effective date of May 1, 2013. New Atlas’s combined consolidated financial statements reflected the operating results of the acquired business commencing July 31, 2013 with the transaction closing.

ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 9). In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $12.1 million of transaction fees which were included within non-controlling interests for the year ended December 31, 2013 on New Atlas’s combined consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred.

 

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The following table presents the values assigned to the assets acquired and liabilities assumed in the acquisition, based on their fair values at the date of the acquisition (in thousands):

 

Assets:
Prepaid expenses and other		$	5,268
Property, plant and equipment			723,842
Total current assets		$	729,110
Liabilities:
Accounts payable			2,747
Asset retirement obligation			16,728
Total liabilities assumed			19,475
Net assets acquired		$	709,635

Pro Forma Financial Information

The following data presents pro forma revenues and net income (loss) for New Atlas as if the Rangely and EP Energy acquisitions, including the related borrowings under the revolving credit facility, net proceeds from the issuance of debt and issuances of common and preferred limited partner units had occurred on January 1, 2013. New Atlas prepared these pro forma unaudited financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the Rangely and EP Energy acquisitions and related offerings, borrowings, and issuances had occurred on January 1, 2013 or the results that will be attained in future periods (in thousands, except per unit data; unaudited):

 

		Nine Months Ended September 30,
		2014				2013
Total revenues and other		$	558,341			$	462,328
Net income (loss)			(17,949	)			14,628
Net loss attributable to owner			(4,585	)			(10,099	)

Other Acquisitions

On May 12, 2014, ARP completed the acquisition of certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $99.3 million in cash, net of purchase price adjustments (the “GeoMet Acquisition”), with an effective date of January 1, 2014. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia.

In September 2013, ARP completed the acquisition of certain assets from Norwood Natural Resources (“Norwood”) for $5.4 million (the “Norwood Acquisition”). The assets acquired included Norwood’s non-operating working interest in certain producing wells in the Barnett Shale. The Norwood Acquisition had an effective date of June 1, 2013.

In July 2013, Atlas Energy completed the acquisition of certain natural gas and oil producing assets in the Arkoma Basin from EP Energy for approximately $64.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). The Arkoma Acquisition was funded with a portion of the proceeds from the issuance of Atlas Energy’s term loan facility (see Note 7). The Arkoma Acquisition had an effective date of May 1, 2013.

 

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NOTE 4—PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment at the dates indicated (in thousands):

 

		September 30, 2014				December 31, 2013				Estimated Useful Lives in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests		$	404,328			$	322,217
Pre-development costs			6,247				4,367
Wells and related equipment			2,840,144				2,231,213
Total proved properties			3,250,719				2,557,797
Unproved properties			215,021				211,851
Support equipment			34,970				23,258
Total natural gas and oil properties			3,500,710				2,792,906
Pipelines, processing and compression facilities			43,804				43,120				2–40
Rights of way			830				830				20–40
Land, buildings and improvements			9,072				9,462				3–40
Other			17,541				15,321				3–10
			3,571,957				2,861,639
Less—accumulated depreciation, depletion and amortization			(843,307	)			(674,956	)
		$	2,728,650			$	2,186,683

During the nine months ended September 30, 2014, New Atlas recognized $1.7 million of loss on asset sales and disposal, primarily related to ARP’s loss on the sale of producing wells in the Niobrara Shale in connection with the settlement of a third party farm-out agreement. During the nine months ended September 30, 2013, New Atlas recognized $2.0 million of loss on asset sales and disposal, pertaining to ARP’s decision not to drill wells on leasehold property that expired in such periods in Indiana and Tennessee.

During the year ended December 31, 2013, ARP recognized $38.0 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on New Atlas’s combined consolidated balance sheet primarily for its shallow natural gas wells in the New Albany Shale and unproved acreage in the Chattanooga and New Albany Shales. These impairments related to the carrying amounts of gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2013, and ARP’s intention not to drill on certain expiring unproved acreage. The estimate of fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

During the nine months ended September 30 2014 and 2013, New Atlas recognized $42.6 million and $23.9 million, respectively, of non-cash property, plant and equipment additions, which were included within the changes in accounts payable and accrued liabilities on New Atlas’s combined consolidated statements of cash flows.

 

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NOTE 5—OTHER ASSETS

The following is a summary of other assets at the dates indicated (in thousands):

 

		September 30, 2014				December 31, 2013
Deferred financing costs, net of accumulated amortization of $19,771 and $12,731 at September 30, 2014 and December 31, 2013, respectively		$	46,249			$	41,686
Investment in Lightfoot			21,225				21,454
Rabbi Trust			5,600				3,705
Security deposits			265				264
ARP notes receivable			3,754				3,978
Long-term derivative asset receivable from Drilling Partnerships			622				863
Other			7,282				2,424
		$	84,997			$	74,374

Deferred financing costs. Deferred financing costs are recorded at cost and amortized over the terms of the respective debt agreements (see Note 7). Amortization expense of New Atlas’s deferred financing costs was $7.0 million and $9.0 million for the nine months ended September 30, 2014 and 2013, respectively, which was recorded within interest expense on New Atlas’s combined consolidated statements of operations. During the nine months ended September 30, 2014, ARP recognized $8.4 million of deferred financing costs relating to the amendment to its revolving credit facility in connection with the Rangely Acquisition (see Note 7). During the nine months ended September 30, 2013, ARP recognized $3.2 million for accelerated amortization of deferred financing costs associated with the retirement of a portion of its then-existing term loan facility and a portion of the outstanding indebtedness under its revolving credit facility with a portion of the proceeds from its issuance of the 7.75% ARP Senior Notes (see Note 7).

ARP notes receivable. At September 30, 2014 and December 31, 2013, ARP had notes receivable with certain investors of its Drilling Partnerships, which were included within other assets, net on New Atlas’s combined consolidated balance sheets. The notes have a maturity date of March 31, 2022, and a 2.25% per annum interest rate. The maturity date of the notes can be extended to March 31, 2027, subject to certain closing conditions, including an extension fee of 1.0% of the outstanding principal balance. For the nine months ended September 30, 2014, $68,000 of interest income was recognized within other, net on New Atlas’s combined consolidated statement of operations. For the nine months ended September 30, 2013, approximately $50,000 of interest income was recognized within other, net on New Atlas’s combined consolidated statements of operations. At September 30, 2014 and December 31, 2013, ARP recorded no allowance for credit losses within New Atlas’s combined consolidated balance sheets based upon payment history and ongoing credit evaluations associated with the ARP notes receivable.

Investment in Lightfoot. At September 30, 2014, New Atlas owned an approximate 12.0% interest in Lightfoot L.P. and an approximate 15.9% interest in Lightfoot G.P., the general partner of Lightfoot L.P., an entity for which Jonathan Cohen, Executive Chairman of the General Partner’s board of directors, is the Chairman of the Board. Lightfoot L.P. focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt. New Atlas accounts for its investment in Lightfoot under the equity method of accounting. During the nine months ended September 30, 2014 and 2013, New Atlas recognized equity income of approximately $0.8 million and $2.4 million, respectively, within other, net on New Atlas’s combined consolidated statements of operations. During the nine months ended September 30, 2014 and 2013, New Atlas received net cash distributions of $1.2 million and $0.7 million, respectively.

On November 6, 2013, Arc Logistics Partners, L.P. (“ARCX”), an MLP, owned and controlled by Lightfoot, which is involved in terminalling, storage, throughput and transloading of crude oil and petroleum products, began trading publicly on the NYSE under the ticker symbol “ARCX”.

 

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NOTE 6—ASSET RETIREMENT OBLIGATIONS

New Atlas and ARP recognized an estimated liability for the plugging and abandonment of their respective gas and oil wells and related facilities. New Atlas and ARP also recognized a liability for their respective future asset retirement obligations where a reasonable estimate of the fair value of that liability could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. New Atlas and ARP also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability for asset retirement obligations was based on historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. New Atlas and ARP have no assets legally restricted for purposes of settling asset retirement obligations. Except for New Atlas and ARP’s gas and oil properties, New Atlas and ARP determined that there were no other material retirement obligations associated with tangible long-lived assets.

ARP proportionately consolidates its ownership interest of the asset retirement obligations of its Drilling Partnerships. At September 30, 2014, the Drilling Partnerships had $56.0 million of aggregate asset retirement obligation liabilities recognized on their combined balance sheets allocable to the limited partners, exclusive of ARP’s proportional interest in such liabilities. Under the terms of the respective partnership agreements, ARP maintains the right to retain a portion or all of the distributions to the limited partners of its Drilling Partnerships to cover the limited partners’ share of the plugging and abandonment costs up to a specified amount per month. As of September 30, 2014, ARP withheld approximately $1.3 million of limited partner distributions related to the asset retirement obligations of certain Drilling Partnerships. ARP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within each Drilling Partnership near the end of their useful life. On a partnership-by-partnership basis, ARP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors including commodity price trends, the natural decline in the production of the wells, and current and future costs. Generally, ARP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon ARP’s decision to retain all future distributions to the limited partners of its Drilling Partnerships, ARP will assume the related asset retirement obligations of the limited partners.

A reconciliation of New Atlas’s and ARP’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):

 

		Nine Months Ended September 30,
		2014				2013
Asset retirement obligations, beginning of period		$	91,214			$	64,794
Liabilities incurred			8,283				18,550
Liabilities settled			(820	)			(381	)
Accretion expense			4,314				3,270
Asset retirement obligations, end of period		$	102,991			$	86,233

The above accretion expense was included in depreciation, depletion and amortization in New Atlas’s combined consolidated statements of operations and the asset retirement obligation liabilities were included within asset retirement obligations and other long-term liabilities in New Atlas’s combined consolidated balance sheets. During the nine months ended September 30, 2014, ARP incurred $6.6 million of future plugging and abandonment liabilities within purchase accounting for the Rangely and GeoMet acquisitions it consummated

 

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during the period (see Note 3). During the year ended December 31, 2013, New Atlas incurred $1.3 million of future plugging and abandonment costs related to the Arkoma Acquisition Atlas Energy consummated during the period. During the year ended December 31, 2013, ARP incurred $16.7 million of future plugging and abandonment liabilities within purchase accounting for the EP Energy Acquisition it consummated during the period.

NOTE 7—DEBT

Total debt consists of the following at the dates indicated (in thousands):

 

		September 30, 2014				December 31, 2013
Term loan facility		$	148,500			$	149,625
ARP revolving credit facility			660,000				419,000
ARP 7.75% Senior Notes—due 2021			374,525				275,000
ARP 9.25% Senior Notes—due 2021			248,497				248,334
Total debt			1,431,522				1,091,959
Less current maturities			(1,500	)			(1,500	)
Total long-term debt		$	1,430,022			$	1,090,459

Term Loan Facility.

In July 2013, Atlas Energy entered into a $240.0 million secured term loan credit facility (“Term Facility”). At September 30, 2014 and December 31, 2013, $148.5 million and $149.6 million, respectively, of the Term Facility was attributable to New Atlas. The Term Facility has a maturity date of July 31, 2019. Borrowings under the Term Facility bear interest at Atlas Energy’s election at either an adjusted LIBOR rate plus an applicable margin of 5.50% per annum or the alternate base rate (as defined in the Term Facility) (“ABR”) plus an applicable margin of 4.50% per annum. Interest is generally payable quarterly for ABR loans and, for LIBOR loans at the interest periods selected by Atlas Energy. Atlas Energy is required to repay principal at the rate of $0.4 million per quarter commencing December 31, 2013 and continuing until the maturity date when the remaining balance is due. At September 30, 2014, the weighted average interest rate on outstanding borrowings under the Term Facility was 6.5%.

The Term Facility contains customary covenants that limit Atlas Energy’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of Atlas Energy’s assets. The Term Facility also contains covenants that require Atlas Energy to maintain a ratio of Total Funded Debt (as defined in the Term Facility) to EBITDA (as defined in the Term Facility), calculated over a period of four consecutive fiscal quarters, of not greater than 4.5 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2014; 4.0 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2015; and 3.5 to 1.0 for the last day of each of the quarters thereafter. At September 30, 2014, Atlas Energy was in compliance with these covenants. The events which constitute events of default are also customary for credit facilities of this nature, including payment defaults, breaches of representations, warranties or covenants, defaults in the payment of other indebtedness over a specified threshold, insolvency and change of control. Based on the definition in Atlas Energy’s Term Facility, New Atlas’s ratio of Total Funded Debt to EBITDA was 1.9 to 1.0.

Atlas Energy’s obligations under the Term Facility are secured by first priority security interests in substantially all of its assets, including all of its ownership interests in its material subsidiaries and its ownership interests in APL and ARP. Additionally, Atlas Energy’s obligations under its Term Facility are guaranteed by its

 

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material wholly owned subsidiaries and may be guaranteed by future subsidiaries. The Term Facility is subject to an intercreditor agreement, which provides for certain rights and procedures, between the lenders under the Term Facility and Atlas Energy’s credit facility, with respect to enforcement of rights, collateral and application of payment proceeds.

At September 30, 2014, New Atlas has not guaranteed any of ARP’s debt obligations.

ARP’s Credit Facility

On September 24, 2014, in connection with its Eagle Ford acquisition (see Note 16), ARP entered into a fourth amendment to its revolving credit agreement with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (as so amended, the “ARP Credit Agreement”). The ARP Credit Agreement provides for a senior secured revolving credit facility with a syndicate of banks with a current borrowing base of $825.0 million and a maximum facility amount of $1.5 billion scheduled to mature in July 2018. The fourth amendment amends the ARP Credit Agreement to permit the guarantee by ARP of certain deferred purchase price obligations and contingent indemnity obligations in connection with the Eagle Ford acquisition, and, with certain constraints, to permit ARP and its subsidiaries to enter into certain derivative instruments related to the producing wells acquired in the Eagle Ford acquisition.

ARP’s borrowing base under the revolving credit facility is scheduled for semi-annual redeterminations on May 1 and November 1 of each year. Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which $4.4 million was outstanding at September 30, 2014. ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. Borrowings under the revolving credit facility bear interest, at ARP’s election, at either an adjusted LIBOR rate plus an applicable margin between 1.50% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal Funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.50% and 1.75% per annum. ARP is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.375% if less than 50% of the borrowing base is utilized and 0.5% if 50% or more of the borrowing base is utilized, which is included within interest expense on New Atlas’s combined consolidated statements of operations. At September 30, 2014, the weighted average interest rate on outstanding borrowings under the revolving credit facility was 2.5%.

The ARP Credit Agreement contains customary covenants that limit ARP’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. ARP was in compliance with these covenants as of September 30, 2014. The ARP Credit Agreement also requires ARP to maintain a ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to four quarters of EBITDA (as defined in the ARP Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than 4.50 to 1.0 as of the last day of the quarters ended through December 31, 2014, 4.25 to 1.0 as of the last day of the quarter ended March 31, 2015 and 4.00 to 1.0 as of the last day of fiscal quarters ending thereafter, and a ratio of current assets (as defined in the ARP Credit Agreement) to current liabilities (as defined in the ARP Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. Based on the definitions contained in ARP’s Credit Agreement, at September 30, 2014, ARP’s ratio of current assets to current liabilities was 1.2 to 1.0, and its ratio of Total Funded Debt to EBITDA was 4.0 to 1.0.

ARP Senior Notes

At September 30, 2014, ARP had $374.5 million outstanding of its 7.75% senior unsecured notes due 2021 (“7.75% ARP Senior Notes”), inclusive of an additional $100.0 million of such notes issued in a private

 

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placement transaction on June 2, 2014 at an offering price of 99.5% of par value, yielding net proceeds of approximately $97.4 million. The net proceeds were used to partially fund the Rangely Acquisition (see Note 3). ARP issued $275.0 million of its 7.75% ARP Senior Notes in a private placement transaction at par on January 23, 2013. The 7.75% ARP Senior Notes were presented net of a $0.5 million unamortized discount as of September 30, 2014. Interest is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable for up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price as defined in the governing indenture, plus accrued and unpaid interest and additional interest, if any. On and after January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019.

ARP entered into registration rights agreements with respect to the $100.0 million 7.75% ARP Senior Notes issued in June 2014. Under the registration rights agreements, ARP will cause to be filed with the SEC registration statements with respect to offers to exchange the 7.75% ARP Senior Notes for substantially identical notes that are registered under the Securities Act. ARP will use reasonable best efforts to cause such exchange offer registration statements to become effective under the Securities Act. In addition, ARP will use reasonable best efforts to cause an exchange offer to be consummated not later than 270 days after the issuance of the 7.75% ARP Senior Notes. Under some circumstances, in lieu of, or in addition to, a registered exchange offer, ARP has agreed to file a shelf registration statement with respect to the 7.75% ARP Senior Notes. ARP is required to pay additional interest if it fails to comply with its obligations to register the 7.75% ARP Senior Notes within the specified time periods.

At September 30, 2014, ARP had $248.5 million outstanding of its 9.25% senior unsecured notes due 2021 (“9.25% ARP Senior Notes”). The net proceeds were used to partially fund the EP Energy Acquisition (see Note 3). The 9.25% ARP Senior Notes were presented net of a $1.5 million unamortized discount as of September 30, 2014. Interest on the 9.25% ARP Senior Notes is payable semi-annually on February 15 and August 15. At any time on or after August 15, 2017, ARP may redeem some or all of the 9.25% ARP Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 100.0%. In addition, at any time prior to August 15, 2016, ARP may redeem up to 35% of the 9.25% ARP Senior Notes with the proceeds received from certain equity offerings at a redemption price of 109.25%. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 9.25% ARP Senior Notes.

In connection with the issuance of the 9.25% ARP Senior Notes, ARP entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by July 30, 2014. On March 28, 2014, the registration statement relating to the exchange offer for the 9.25% ARP Senior Notes was declared effective, and the exchange offer was completed on April 29, 2014.

The 9.25% ARP Senior Notes and 7.75% ARP Senior Notes are guaranteed by certain of ARP’s material subsidiaries. The guarantees under the 9.25% ARP Senior Notes and 7.75% ARP Senior Notes are full and unconditional and joint and several, and any subsidiaries of ARP, other than the subsidiary guarantors, are minor. There are no restrictions on ARP’s ability to obtain cash or any other distributions of funds from the guarantor subsidiaries.

The indentures governing the 9.25% ARP Senior Notes and 7.75% ARP Senior Notes contain covenants, including limitations on ARP’s ability to incur certain liens; incur additional indebtedness; declare or pay

 

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distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of ARP’s assets. ARP was in compliance with these covenants as of September 30, 2014.

Total cash payments for interest by New Atlas were $62.5 million and $17.2 million for the nine months ended September 30, 2014 and 2013, respectively.

NOTE 8—DERIVATIVE INSTRUMENTS

New Atlas and ARP use a number of different derivative instruments, principally swaps, collars, and options, in connection with their commodity and interest rate price risk management activities. New Atlas and ARP enter into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold or interest payments on the underlying debt instrument are due. Under commodity-based swap agreements, New Atlas and ARP receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. To manage the risk of regional commodity price differences, New Atlas and ARP occasionally enter into basis swaps. Basis swaps are contractual arrangements that guarantee a price differential for a commodity from a specified delivery point price and the comparable national exchange price. For natural gas basis swaps, which have negative differentials to NYMEX, New Atlas and ARP receive or pay a payment from or to the counterparty if the price differential to NYMEX is greater or less than the stated terms of the contract. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.

New Atlas and ARP apply the principles of hedge accounting for derivatives qualifying as hedges. Accordingly, New Atlas and ARP formally document all relationships between hedging instruments and the items being hedged, including their risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity and interest derivative contracts to the forecasted transactions. New Atlas and ARP assess, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, New Atlas and ARP will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which are determined by management through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in New Atlas’s combined consolidated statements of operations. For derivatives qualifying as hedges, New Atlas and ARP recognize the effective portion of changes in fair value of derivative instruments in equity as accumulated other comprehensive income (loss) and reclassify the portion relating to New Atlas’s and ARP’s commodity derivatives within gas and oil production revenues and the portion relating to interest rate derivatives to interest expense within New Atlas’s combined consolidated statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, changes in fair value are recognized within gain (loss) on mark-to-market derivatives in New Atlas’s combined consolidated statements of operations as they occur.

New Atlas and ARP enter into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on New Atlas’s combined consolidated balance sheets as assets or liabilities at fair value

 

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on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on New Atlas’s combined consolidated balance sheets as the initial value of the options.

New Atlas and ARP enter into commodity future option and collar contracts to achieve more predictable cash flows by hedging their exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. Natural gas liquids fixed price swaps are priced based on a WTI crude oil index, while other natural gas liquids contracts are based on an OPIS Mt. Belvieu index.

Derivatives are recorded on New Atlas’s combined consolidated balance sheets as assets or liabilities at fair value. New Atlas reflected net derivative assets on its combined consolidated balance sheets of $51.9 million and $24.0 million at September 30, 2014 and December 31, 2013, respectively. Of the $15.7 million of net gains in accumulated other comprehensive income (loss) within equity on the New Atlas’s combined consolidated balance sheet related to derivatives at September 30, 2014, if the fair values of the instruments remain at current market values, New Atlas will reclassify $6.0 million of gains to gas and oil production revenue on its combined consolidated statement of operations over the next twelve month period as these contracts expire. Aggregate gains of $9.7 million of gas and oil production revenues will be reclassified to New Atlas’s combined consolidated statements of operations in later periods as the remaining contracts expire. Actual amounts that will be reclassified will vary as a result of future commodity price changes. Approximately $0.8 million of derivative gains were reclassified from other comprehensive income related to derivative instruments entered into during the nine months ended September 30, 2014. Approximately $0.9 million of derivative gains were reclassified from other comprehensive income related to derivative instruments entered into during the nine months ended September 30, 2013.

The following table summarizes New Atlas’s and ARP’s gains or losses recognized in New Atlas’s combined consolidated statements of operations for effective derivative instruments, excluding the effect of non-controlling interest, for the periods indicated (in thousands):

 

		Nine Months Ended September 30,
		2014				2013
(Gain) loss reclassified from accumulated other comprehensive income (loss):
Gas and oil production revenue		$	22,703			$	(4,579	)
Total		$	22,703			$	(4,579	)

 

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New Atlas

The following table summarizes the gross fair values of the New Atlas’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on New Atlas’s combined consolidated balance sheets as of the dates indicated (in thousands):

 

		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Combined Consolidated Balance Sheets				Net Amount of Assets Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Assets
As of September 30, 2014
Long-term portion of derivative assets		$	591			$	(7	)		$	584
Current portion of derivative liabilities			1,270				—				1,270
Total derivative assets		$	1,861			$	(7	)		$	1,854
As of December 31, 2013
Current portion of derivative assets		$	24			$	(23	)		$	1
Long-term portion of derivative assets			1,547				(33	)			1,514
Current portion of derivative liabilities			63				(63	)			—
Total derivative assets		$	1,634			$	(119	)		$	1,515

 

		Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Combined Consolidated Balance Sheets				Net Amount of Liabilities Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Liabilities
As of September 30, 2014
Long-term portion of derivative assets		$	(7	)		$	7			$	—
Total derivative liabilities		$	(7	)		$	7			$	—
As of December 31, 2013
Current portion of derivative assets		$	(23	)		$	23			$	—
Long-term portion of derivative assets			(33	)			33				—
Current portion of derivative liabilities			(96	)			63				(33	)
Total derivative liabilities		$	(152	)		$	119			$	(33	)

During the nine months ended September 30, 2014, New Atlas recorded losses of $0.8 million on settled derivative contracts within its combined consolidated statements of operations. During the nine months ended September 30, 2013, New Atlas recorded gains of $0.2 million on settled derivative contracts within its combined consolidated statements of operations. These losses were included within gas and oil production revenue in New Atlas’s combined consolidated statement of operations. As the underlying prices and terms in New Atlas’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the nine months ended September 30, 2014 and 2013 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

In connection with the Arkoma Acquisition in July 2013, New Atlas entered into contracts which provided the option to enter into swap contracts for future production periods (“swaptions”) up through September 30, 2013 for production volumes related to the Arkoma assets acquired from EP Energy (see Note 3). In connection with the swaption contacts, New Atlas paid premiums of $2.3 million which represented their fair value on the

 

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date the transactions were initiated, and were initially recorded as a derivative asset on New Atlas’s combined consolidated balance sheet and were fully amortized into other, net on New Atlas’s combined consolidated statement of operations as of September 30, 2013.

At September 30, 2014, New Atlas had the following commodity derivatives:

Natural Gas—Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Asset
		(MMBtu)(1)				(per MMBtu)(1)				(in thousands)(2)
2014			690,000			$	4.177			$	55
2015			2,280,000			$	4.302				683
2016			1,440,000			$	4.433				501
2017			1,200,000			$	4.590				432
2018			420,000			$	4.797				183
New Atlas’s net asset										$	1,854

 

(1)	“MMBtu” represents million British Thermal Units.

(2)	Fair value based on forward NYMEX natural gas prices, as applicable.

Atlas Resource Partners

The following table summarizes the gross fair values of ARP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on New Atlas’s combined consolidated balance sheets as of the dates indicated (in thousands):

 

		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Combined Consolidated Balance Sheets				Net Amount of Assets Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Assets
As of September 30, 2014
Current portion of derivative assets		$	23,604			$	(2,554	)		$	21,050
Long-term portion of derivative assets			31,950				(1,124	)			30,826
Total derivative assets		$	55,554			$	(3,678	)		$	51,876
As of December 31, 2013
Current portion of derivative assets		$	2,664			$	(773	)		$	1,891
Long-term portion of derivative assets			31,146				(4,062	)			27,084
Current portion of derivative liabilities			4,341				(4,341	)			—
Long-term portion of derivative liabilities			122				(122	)			—
Total derivative assets		$	38,273			$	(9,298	)		$	28,975

 

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		Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Combined Consolidated Balance Sheets				Net Amount of Liabilities Presented in the Combined Consolidated Balance Sheets
Offsetting Derivative Liabilities
As of September 30, 2014
Current portion of derivative assets		$	(2,554	)		$	2,554			$	—
Long-term portion of derivative assets			(1,124	)			1,124				—
Current portion of derivative liabilities			(1,792	)			—				(1,792	)
Total derivative liabilities		$	(5,470	)		$	3,678			$	(1,792	)
As of December 31, 2013
Current portion of derivative assets		$	(773	)		$	773			$	—
Long-term portion of derivative assets			(4,062	)			4,062				—
Current portion of derivative liabilities			(10,694	)			4,341				(6,353	)
Long-term portion of derivative liabilities			(189	)			122				(67	)
Total derivative liabilities		$	(15,718	)		$	9,298			$	(6,420	)

In June 2013, ARP entered into contracts which provided the option to enter into swaptions up through September 30, 2013 for production volumes related to assets acquired from EP Energy (see Note 3). In connection with these swaption contracts, ARP paid premiums of $14.5 million, which represented their fair value on the date the transactions were initiated and were initially recorded as a derivative asset on New Atlas’s combined consolidated balance sheet. Swaption contract premiums paid are amortized over the period from initiation of the contract through their termination date. For the nine months ended September 30, 2013, ARP recognized approximately $14.5 million of amortization expense in other, net on New Atlas’s combined consolidated statement of operations related to the swaption contracts.

ARP recognized losses of $21.9 million and gains of $4.4 million for the nine months ended September 30, 2014 and 2013, respectively on settled contracts covering commodity production. These gains and losses were included within gas and oil production revenue in New Atlas’s combined consolidated statements of operations. As the underlying prices and terms in ARP’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the nine months ended September 30, 2014 and 2013, respectively for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

At September 30, 2014, ARP had the following commodity derivatives:

Natural Gas—Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Asset
		(MMBtu)(1)				(per MMBtu)(1)				(in thousands)(2)
2014			15,038,200			$	4.152			$	804
2015			51,924,500			$	4.239				12,192
2016			45,746,300			$	4.311				10,462
2017			24,840,000			$	4.532				7,552
2018			9,360,000			$	4.619				2,590
										$	33,600

 

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Natural Gas—Costless Collars

 

Production Period Ending December 31,		Option Type		Volumes				Average Floor and Cap				Fair Value Asset/(Liability)
				(MMBtu)(1)				(per MMBtu)(1)				(in thousands)(2)
2014		Puts purchased			960,000			$	4.221			$	279
2014		Calls sold			960,000			$	5.120				(23	)
2015		Puts purchased			3,480,000			$	4.234				1,948
2015		Calls sold			3,480,000			$	5.129				(452	)
												$	1,752

Natural Gas—Put Options—Drilling Partnerships

 

Production Period Ending December 31,		Option Type		Volumes				Average Fixed Price				Fair Value Asset
				(MMBtu)(1)				(per MMBtu)(1)				(in thousands)(2)
2014		Puts purchased			450,000			$	3.800			$	17
2015		Puts purchased			1,440,000			$	4.000				550
2016		Puts purchased			1,440,000			$	4.150				738
												$	1,305

Natural Gas—WAHA Basis Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Asset/(Liability)
		(MMBtu)(1)				(per MMBtu)(1)				(in thousands)(8)
2014			2,700,000			$	(0.110	)		$	3
2015			3,000,000			$	(0.068	)			(31	)
										$	(28	)

Natural Gas—NGPL Basis Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Asset
		(MMBtu)(1)				(per MMBtu)(1)				(in thousands)(9)
2014			2,250,000			$	(0.108	)		$	1
										$	1

Natural Gas Liquids—Natural Gasoline Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Asset
		(Gal)(1)				(per Gal)(1)				(in thousands)(10)
2014			1,386,000			$	2.123			$	238
2015			5,040,000			$	1.983				570
										$	808

Natural Gas Liquids—Ethane Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Asset
		(Gal)(1)				(per Gal)(1)				(in thousands)(4)
2014			630,000			$	0.303			$	37
										$	37

 

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Natural Gas Liquids—Propane Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Liability
		(Gal)(1)				(per Gal)(1)				(in thousands)(5)
2014			3,087,000			$	1.000			$	(144	)
2015			8,064,000			$	1.016				(76	)
										$	(220	)

Natural Gas Liquids—Butane Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Asset
		(Gal)(1)				(per Gal)(1)				(in thousands)(6)
2014			378,000			$	1.308			$	34
2015			1,512,000			$	1.248				98
										$	132

Natural Gas Liquids—Iso Butane Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Asset
		(Gal)(1)				(per Gal)(1)				(in thousands)(7)
2014			378,000			$	1.323			$	32
2015			1,512,000			$	1.263				91
										$	123

Natural Gas Liquids—Crude Oil Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Liability
		(Bbl)(1)				(per Bbl)(1)				(in thousands)(3)
2016			84,000			$	85.651			$	(24	)
2017			60,000			$	83.780				(58	)
										$	(82	)

Crude Oil—Fixed Price Swaps

 

Production Period Ending December 31,		Volumes				Average Fixed Price				Fair Value Asset
		(Bbl)(1)				(per Bbl)(1)				(in thousands)(3)
2014			439,500			$	95.090			$	2,144
2015			1,743,000			$	90.645				4,977
2016			1,029,000			$	88.650				2,731
2017			492,000			$	87.752				1,409
2018			360,000			$	88.283				1,302
										$	12,563

 

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Crude Oil—Costless Collars

 

Production Period Ending December 31,		Option Type		Volumes				Average Floor and Cap				Fair Value Asset/(Liability)
				(Bbl)(1)				(per Bbl)(1)				(in thousands)(3)
2014		Puts purchased			10,290			$	84.169			$	15
2014		Calls sold			10,290			$	113.308				(1	)
2015		Puts purchased			29,250			$	83.846				110
2015		Calls sold			29,250			$	110.654				(31	)
												$	93
ARP’s net asset												$	50,084

 

(1)	“MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons.

(2)	Fair value based on forward NYMEX natural gas prices, as applicable.

(3)	Fair value based on forward WTI crude oil prices, as applicable.

(4)	Fair value based on forward Mt. Belvieu ethane prices, as applicable.

(5)	Fair value based on forward Mt. Belvieu propane prices, as applicable.

(6)	Fair value based on forward Mt. Belvieu butane prices, as applicable.

(7)	Fair value based on forward Mt. Belvieu iso butane prices, as applicable.

(8)	Fair value based on forward WAHA natural gas prices, as applicable.

(9)	Fair value based on forward NGPL natural gas prices, as applicable.

(10)	Fair value based on forward Mt. Belvieu natural gasoline prices, as applicable.

At September 30, 2014, ARP had net cash proceeds of $0.8 million related to hedging positions monetized on behalf of the Drilling Partnerships’ limited partners, which were included within cash and cash equivalents on New Atlas’s combined consolidated balance sheet. ARP will allocate the monetization net proceeds to the Drilling Partnerships’ limited partners based on their natural gas and oil production generated over the period of the original derivative contracts.

In June 2012, ARP entered into natural gas put option contracts which related to future natural gas production of the Drilling Partnerships. Therefore, a portion of any unrealized derivative gain or loss is allocable to the limited partners of the Drilling Partnerships based on their share of estimated gas production related to the derivatives not yet settled. At September 30, 2014, net unrealized derivative assets of $1.3 million were payable to the limited partners in the Drilling Partnerships related to these natural gas put option contracts.

At September 30, 2014, ARP had a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under its revolving credit facility (see Note 7), ARP is required to utilize this secured hedge facility for future commodity risk management activity for its equity production volumes within the participating Drilling Partnerships. Each participating Drilling Partnership’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets and by a guarantee of the general partner of the Drilling Partnership. ARP, as general partner of the Drilling Partnerships, administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnerships’ ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets.

 

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The fair value of the derivatives included in New Atlas’s combined consolidated balance sheets for the periods indicated was as follows (in thousands):

 

		September 30, 2014				December 31, 2013
Current portion of derivative asset		$	21,634			$	1,891
Long-term derivative asset			32,096				28,598
Current portion of derivative liability			(1,792	)			(6,386	)
Long-term derivative liability			—				(67	)
Total net asset (liability)		$	51,938			$	24,036

NOTE 9—FAIR VALUE OF FINANCIAL INSTRUMENTS

New Atlas has established a hierarchy to measure their financial instruments at fair value, which requires them to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources, whereas, unobservable inputs reflect New Atlas’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

New Atlas and ARP use a market approach fair value methodology to value the assets and liabilities for their outstanding derivative contracts (see Note 8) and investments held in New Atlas’s rabbi trust (see Note 14). New Atlas and ARP manage and report derivative assets and liabilities on the basis of their exposure to market risks and credit risks by counterparty. New Atlas and ARP commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument. Investments held within New Atlas’s rabbi trust are publicly traded equity and debt securities which are Level 1 fair value measurements.

 

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Information for the New Atlas and ARP’s assets and liabilities measured at fair value at September 30, 2014 and December 31, 2013 was as follows (in thousands):

 

		Level 1				Level 2				Level 3				Total
As of September 30, 2014
Assets, gross
Rabbi Trust		$	5,600			$	—			$	—			$	5,600
Commodity swaps			—				1,861				—				1,861
ARP Commodity swaps			—				51,734				—				51,734
ARP Commodity basis swaps			—				163				—				163
ARP Commodity puts			—				1,305				—				1,305
ARP Commodity options			—				2,352				—				2,352
Total assets, gross			5,600				57,415				—				63,015
Liabilities, gross
Commodity swaps		$	—			$	(7	)		$	—			$	(7	)
ARP Commodity swaps			—				(4,773	)			—				(4,773	)
ARP Commodity basis swaps			—				(190	)			—				(190	)
ARP Commodity options			—				(507	)			—				(507	)
Total liabilities, gross			—				(5,477	)			—				(5,477	)
Total assets, fair value, net		$	5,600			$	51,938			$	—			$	57,538
As of December 31, 2013
Assets, gross
Rabbi Trust		$	3,705			$	—			$	—			$	3,705
Commodity swaps			—				1,634				—				1,634
ARP Commodity swaps			—				33,594				—				33,594
ARP Commodity puts			—				1,374				—				1,374
ARP Commodity options			—				3,305				—				3,305
Total assets, gross			3,705				39,907				—				43,612
Liabilities, gross
Commodity swaps			—				(152	)			—				(152	)
ARP Commodity swaps			—				(14,624	)			—				(14,624	)
ARP Commodity options			—				(1,094	)			—				(1,094	)
Total liabilities, gross			—				(15,870	)			—				(15,870	)
Total assets, fair value, net		$	3,705			$	24,037			$	—			$	27,742

Other Financial Instruments

The estimated fair value of New Atlas and ARP’s other financial instruments has been determined based upon their assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that New Atlas and ARP could realize upon the sale or refinancing of such financial instruments.

New Atlas and ARP’s other current assets and liabilities on the combined consolidated balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1. The estimated fair values of New Atlas and ARP’s debt at September 30, 2014 and December 31, 2013, which consist principally of ARP’s senior notes and borrowings under New Atlas’s and ARP’s revolving and term loan credit facilities, were $1,447.6 million and $1,088.3 million, respectively, compared with the carrying amounts of $1,431.5 million and $1,092.0

 

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million, respectively. The carrying values of outstanding borrowings under the respective revolving and term loan credit facilities, which bear interest at variable interest rates, approximated their estimated fair values. The estimated fair values of the ARP senior notes were based upon the market approach and calculated using the yields of the ARP senior notes as provided by financial institutions and thus were categorized as Level 3 values.

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

New Atlas and ARP estimate the fair value of their respective asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of New Atlas and ARP and estimated inflation rates (see Note 6).

Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the nine months ended September 30, 2014 and 2013 was as follows (in thousands):

 

		Nine Months Ended September 30,
		2014								2013
		Level 3				Total				Level 3				Total
Asset retirement obligations		$	8,283			$	8,283			$	18,550			$	18,550
Total		$	8,283			$	8,283			$	18,550			$	18,550

New Atlas and ARP estimate the fair values of their long-lived assets in connection with reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances. For the year ended December 31, 2013, ARP recognized $38.0 million of impairment of long-lived assets which were defined as Level 3 fair value measurements (see Note 2—Impairment of Long-Lived Assets). No impairments were recognized during the nine months ended September 30, 2014 and 2013.

During the nine months ended September 30, 2014, ARP completed the Rangely Acquisition and the GeoMet acquisition (see Note 3). During the year ended December 31, 2013, Atlas Energy completed the Arkoma Acquisition and ARP completed the EP Energy Acquisition. The fair value measurements of assets acquired and liabilities assumed for each of these acquisitions are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The estimated fair values of the assets acquired and liabilities assumed in the Rangely and GeoMet acquisitions as of the acquisition dates, which are reflected in New Atlas’s combined consolidated balance sheet as of September 30, 2014, are subject to change as the final valuations for these transactions have not yet been completed, and such changes may be material. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under New Atlas and ARP’s existing methodology for recognizing an estimated liability for the plugging and abandonment of its gas and oil wells (see Note 6). These inputs require significant judgments and estimates by New Atlas and ARP’s management at the time of the valuations and are subject to change.

NOTE 10—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Relationship with Drilling Partnerships. ARP conducts certain activities through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. ARP serves as general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the general partner, ARP is liable for the Drilling Partnerships’ liabilities and can be liable to limited partners of the Drilling Partnerships if it breaches its responsibilities with respect to the operations of the Drilling Partnerships.

 

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ARP is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Drilling Partnerships’ revenues and costs and expenses according to the respective partnership agreements.

Relationship between ARP and APL. Atlas Energy also maintains a general partner ownership interest in Atlas Pipeline Partners, L.P. (“APL”), a publicly traded Delaware master limited partnership (NYSE: APL) and midstream energy service provider engaged in the gathering, processing and treating of natural gas in the mid-continent and southwestern regions of the United States and gas gathering services in the Appalachian Basin in the northwest region of the United States. In the Chattanooga Shale, a portion of the natural gas produced by ARP is gathered and processed by APL. For each of the nine month periods ended September 30, 2014 and 2013, $0.2 million of gathering fees paid by ARP to APL were included in the combined consolidated statement of operations.

Relationship with Resource America, Inc. In connection with the issuance of the Term Facility, CVC Credit Partners, LLC (“CVC”), which is a joint venture between Resource America, Inc. and an unrelated third party private equity firm, was allocated an aggregate of $12.5 million of the Term Facility. Atlas Energy’s Chief Executive Officer and President is Chairman of the board of directors of Resource America, Inc., and Atlas Energy’s Executive Chairman of the General Partner’s board of directors is Chief Executive Officer and President of Resource America, Inc.

NOTE 11—COMMITMENTS AND CONTINGENCIES

General Commitments

ARP is the managing general partner of the Drilling Partnerships and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. ARP has structured certain Drilling Partnerships to allow limited partners to have the right to present their interests for purchase. Generally for Drilling Partnerships with this structure, ARP is not obligated to purchase more than 5% to 10% of the units in any calendar year, no units may be purchased during the first five years after closing for the Drilling Partnership, and ARP may immediately suspend the presentment structure for a Drilling Partnership by giving notice to the limited partners that it does not have adequate liquidity for redemptions. In accordance with the Drilling Partnership agreement, the purchase price for limited partner interests would generally be based upon a percentage of the present value of future cash flows allocable to the interest, discounted at 10%, as of the date of presentment, subject to estimated changes by ARP to reflect current well performance, commodity prices and production costs, among other items. Based on its historical experience, as of September 30, 2014, the management of ARP believes that any such estimated liability for redemptions of limited partner interests in Drilling Partnerships which allow such transactions would not be material.

While its historical structure has varied, ARP has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically 10% per year determined on a cumulative basis and inclusive of estimated individual tax benefits, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. ARP periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, ARP recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which ARP has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, ARP will recognize an

 

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estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized. For the nine months ended September 30, 2014 and 2013, $4.7 million and $6.5 million, respectively, of ARP’s gas and oil production revenues, net of corresponding production costs, from certain Drilling Partnerships were subordinated, which reduced gas and oil production revenues and expenses.

Atlas Energy is party to employment agreements with certain executives that provide compensation and certain other benefits. The agreements also provide for severance payments under certain circumstances.

In connection with ARP’s EP Energy Acquisition (see Note 3), ARP acquired certain long-term annual firm transportation obligations. Estimated fixed and determinable portions of ARP’s firm transportation obligations as of September 30, 2014 were as follows: 2014—$2.1 million; 2015—$8.6 million; 2016—$2.1 million; and 2017 to 2018—none.

As of September 30, 2014, New Atlas is committed to expend approximately $65.4 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

Legal Proceedings

Atlas Energy is involved in class action lawsuits arising from events subsequent to September 30, 2014 (see Note 16).

The operations of New Atlas are party to various routine legal proceedings arising out of the ordinary course of its business. Management of New Atlas believes that none of these actions, individually or in the aggregate, will have a material adverse effect on New Atlas’s financial condition or results of operations.

NOTE 12—ISSUANCES OF UNITS

New Atlas recognizes gains on ARP’s and the Development Subsidiary’s equity transactions as credits to equity on its combined consolidated balance sheets rather than as income on its combined consolidated statements of operations. These gains represent New Atlas’s portion of the excess net offering price per unit of each of ARP’s and the Development Subsidiary’s common units over the book carrying amount per unit (see Note 2).

Atlas Resource Partners

Equity Offerings

In August 2014, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of the several banks named therein (the “Agents”). Pursuant to the equity distribution agreement, ARP may sell from time to time through the Agents common units representing limited partner interests of ARP having an aggregate offering price of up to $100.0 million. Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act, including sales made directly on the New York Stock Exchange, the existing trading market for the common units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP will pay each of the Agents a commission, which in each case shall not be more than 2.0% of the gross sales price of common units sold through such Agent. Under the terms of the equity distribution agreement, ARP may also sell common units from time to time to any Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to an Agent as principal would be pursuant to the terms of a separate terms agreement between ARP and such Agent. As of September 30, 2014, no units have been sold under this program.

 

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In May 2014, in connection with the closing of the Rangely Acquisition (see Note 3), ARP issued 15,525,000 of its common limited partner units (including 2,025,000 units pursuant to an over-allotment option) in a public offering at a price of $19.90 per unit, yielding net proceeds of approximately $297.5 million. The units were registered under the Securities Act, pursuant to a shelf registration statement on Form S-3, which was automatically effective on the filing date of February 3, 2014.

In March 2014, ARP issued 6,325,000 of its common limited partner units (including 825,000 units pursuant to an over-allotment option) in a public offering at a price of $21.18 per unit, yielding net proceeds of approximately $129.1 million. The units were registered under the Securities Act, pursuant to a shelf registration statement on Form S-3, which was automatically effective on the filing date of February 3, 2014.

In July 2013, in connection with the closing of the EP Energy Acquisition (see Note 3), ARP issued 3,749,986 newly created Class C convertible preferred units to New Atlas at a negotiated price per unit of $23.10, for proceeds of $86.6 million. The Class C preferred units were issued with 562,497 warrants to purchase ARP common units at an exercise price of $23.10 at New Atlas’s option beginning on October 29, 2013. The warrants will expire on July 31, 2016. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act.

Upon issuance of the Class C preferred units and warrants on July 31, 2013, ARP entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class C preferred units and upon exercise of the warrants. ARP agreed to use commercially reasonable efforts to file such registration statement within 90 days of the conversion of the Class C preferred units into common units or the exercise of the warrants.

In June 2013, in connection with the EP Energy Acquisition (see Note 3), ARP sold an aggregate of 14,950,000 of its common limited partner units (including 1,950,000 units pursuant to an over-allotment option) in a public offering at a price of $21.75 per unit, yielding net proceeds of approximately $313.1 million. ARP utilized the net proceeds from the sale to repay the outstanding balance under its revolving credit facility (see Note 7).

In May 2013, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of several banks. Pursuant to the equity distribution agreement, ARP could sell, from time to time through the agents, common units having an aggregate offering price of up to $25.0 million. During the year ended December 31, 2013, ARP issued 309,174 common limited partner units under the equity distribution program for net proceeds of $6.9 million, net of $0.4 million in commissions paid. ARP utilized the net proceeds from the sale to repay borrowings outstanding under its revolving credit facility. ARP terminated the equity distribution agreement effective December 27, 2013.

For the nine months ended September 30, 2014, in connection with the issuance of ARP’s common units, New Atlas recorded gains of $40.7 million within equity and a corresponding decrease in non-controlling interests on its combined consolidated balance sheet and combined consolidated statement of equity. At December 31, 2013, in connection with the issuance of ARP’s common units, New Atlas recorded gains of $27.3 million within equity and a corresponding decrease in non-controlling interests on its combined consolidated balance sheet and combined consolidated statement of equity.

NOTE 13—CASH DISTRIBUTIONS

ARP Cash Distributions. In January 2014, ARP’s board of directors approved the modification of its cash distribution payment practice to a monthly cash distribution program beginning for the month of January 2014, whereby it would distribute all of its available cash (as defined in the partnership agreement) for that month to its unitholders within 45 days from the month end. Prior to that, ARP paid quarterly cash distributions within 45 days from the end of each calendar quarter. If ARP’s common unit distributions in any quarter exceed specified target levels, New Atlas will receive between 13% and 48% of such distributions in excess of the specified target levels.

 

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Distributions declared by ARP for the period from January 1, 2013 through September 30, 2014 were as follows (in thousands, except per unit amounts):

 

Date Cash Distribution Paid		For Quarter/ Month Ended		Cash Distribution per Common Limited Partner Unit				Total Cash Distribution to Common Limited Partners				Total Cash Distribution to Preferred Limited Partners				Total Cash Distribution to the General Partner
May 15, 2013		March 31, 2013		$	0.5100			$	22,428			$	1,957			$	946
August 14, 2013		June 30, 2013		$	0.5400			$	32,097			$	2,072			$	1,884
November 14, 2013		September 30, 2013		$	0.5600			$	33,291			$	4,248			$	2,443
February 14, 2014		December 31, 2013		$	0.5800			$	34,489			$	4,400			$	2,891
March 17, 2014		January 31, 2014		$	0.1933			$	12,718			$	1,467			$	1,055
April 14, 2014		February 28, 2014		$	0.1933			$	12,719			$	1,466			$	1,055
May 15, 2014		March 31, 2014		$	0.1933			$	12,719			$	1,466			$	1,054
June 13, 2014		April 30, 2014		$	0.1933			$	15,752			$	1,466			$	1,279
July 15, 2014		May 31, 2014		$	0.1933			$	15,752			$	1,466			$	1,279
August 14, 2014		June 30, 2014		$	0.1966			$	16,029			$	1,492			$	1,377
September 12, 2014		July 31, 2014		$	0.1966			$	16,028			$	1,493			$	1,378
October 15, 2014		August 31, 2014		$	0.1966			$	16,032			$	1,491			$	1,378

On October 29, 2014, ARP declared its monthly distribution of $0.1966 per common unit for the month of September 2014. The $18.9 million distribution, including $1.4 million and $1.5 million to the general partner and preferred limited partners, respectively, was paid on November 14, 2014 to holders of record as of November 10, 2014.

On November 24, 2014, ARP declared its monthly distribution of $0.1966 per common unit for the month of October 2014. The $18.9 million distribution, including $1.4 million and $1.5 million to the general partner and preferred limited partners, respectively, will be paid on December 15, 2014 to holders of record as of December 5, 2014.

NOTE 14—BENEFIT PLANS

New Atlas Rabbi Trust

In 2011, Atlas Energy established an excess 401(k) plan relating to certain executives. In connection with the plan, Atlas Energy established a “rabbi” trust for the contributed amounts. At September 30, 2014 and December 31, 2013, New Atlas reflected $5.6 million and $3.7 million, respectively, related to the value of the rabbi trust within other assets, net on its combined consolidated balance sheets, and recorded corresponding liabilities of $5.6 million and $3.7 million as of these same dates within asset retirement obligations and other on its combined consolidated balance sheets.

ARP Long-Term Incentive Plan

ARP’s 2012 Long-Term Incentive Plan (the “ARP LTIP”), effective March 2012, provides incentive awards to officers, employees and directors as well as employees of the general partner and its affiliates, consultants and joint venture partners who perform services for ARP. The ARP LTIP is administered by the board of the general partner, a committee of the board or the board (or committee of the board) of an affiliate (the “ARP LTIP Committee”). Under ARP’s 2012 LTIP, the ARP LTIP Committee may grant awards of phantom units, restricted units, or unit options for an aggregate of 2,900,000 common limited partner units of ARP. At September 30, 2014, ARP had 2,258,110 phantom units, restricted units and restricted options outstanding under the ARP LTIP, with 148,663 phantom units, restricted units and unit options available for grant. Share-based payments to non-employee directors, which have a cash settlement option, are recognized within liabilities in the financial statements based upon their current fair market value.

 

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In the case of awards held by eligible employees, following a “change in control”, as defined in the ARP LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the ARP LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full.

In connection with a change in control, the ARP LTIP Committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which the Partnership, as general partner (or any affiliate), and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason):

 

•

cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity);

 

•

accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to ARP’s common units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction;

 

•

provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards);

 

•

terminate all or some awards upon the consummation of the change-in-control transaction, but only if the ARP LTIP Committee provides for full vesting of awards immediately prior to the consummation of such transaction; and

 

•

make such other modifications, adjustments or amendments to outstanding awards or the new equity plan as the ARP LTIP Committee deems necessary or appropriate.

ARP Phantom Units. Phantom units granted under the ARP LTIP generally will vest 25% of the original granted amount on each of the four anniversaries of the date of grant. Of the phantom units outstanding under the ARP LTIP at September 30, 2014, 314,775 units will vest within the following twelve months. All phantom units outstanding under the ARP LTIP at September 30, 2014 include DERs. During the nine months ended September 30, 2014 and 2013, ARP paid $1.5 million with respect to the ARP LTIP’s DERs. These amounts were recorded as reductions of partners’ capital on the Partnership’s consolidated balance sheets.

The following table sets forth the ARP LTIP phantom unit activity for the periods indicated:

 

		Nine Months Ended September 30,
		2014								2013
		Number of Units				Weighted Average Grant Date Fair Value				Number of Units				Weighted Average Grant Date Fair Value
Outstanding, beginning of year			839,808			$	24.31				948,476			$	24.76
Granted			236,423				20.28				128,981				22.07
Vested and issued(1)			(262,671	)			24.51				(204,582	)			24.70
Forfeited			(18,750	)			23.00				(22,875	)			24.23
Outstanding, end of period(2)(3)			794,810			$	23.07				850,000			$	24.38
Vested and not yet issued(4)			5,412			$	25.25				7,749			$	25.51
Non-cash compensation expense recognized (in thousands)						$	4,968							$	7,329

 

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(1)	The intrinsic value of phantom unit awards vested and issued during the nine months ended September 30, 2014 and 2013 was and $5.7 million and $5.0 million, respectively.

(2)	The aggregate intrinsic value for phantom unit awards outstanding at September 30, 2014 was $15.5 million.

(3)

There was $0.2 million and $0.1 million recognized as liabilities on the Partnership’s consolidated balance sheets representing 29,035 and 16,084 units for the periods ending September 30, 2014 and December 31, 2013, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair value for these units was $21.09 and $22.15 for the periods ending September 30, 2014 and December 31, 2013, respectively. There was approximately $40,000 recognized as liabilities on the Partnership’s consolidated balance sheet at September 30, 2013, representing 7,939 units due to the option of the participants to settle in cash instead of units. The weighted average grant date fair value for these units was $25.19 as of September 30, 2013.

(4)	The intrinsic values of phantom unit awards vested, but not yet issued at September 30, 2014 and 2013 were $0.1 million and $0.2 million, respectively.

At September 30, 2014, ARP had approximately $8.3 million in unrecognized compensation expense related to unvested phantom units outstanding under the ARP LTIP based upon the fair value of the awards.

ARP Unit Options. The exercise price of each ARP unit option is determined by the ARP LTIP Committee and may be equal to or greater than the fair market value of ARP’s common unit on the date of grant of the option. The ARP LTIP Committee will determine the vesting and exercise restrictions applicable to an ARP award of options, if any, and the method by which the exercise price may be paid by the participant. Unit option awards expire 10 years from the date of grant. Unit options granted under the ARP LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. There were 362,888 unit options outstanding under the ARP LTIP at September 30, 2014 that will vest within the following twelve months. No cash was received from the exercise of options for the nine month periods ended September 30, 2014 and 2013.

The following table sets forth the ARP LTIP unit option activity for the periods indicated:

 

		Nine Months Ended September 30,
		2014								2013
		Number of Units				Weighted Average Exercise Price				Number of Units				Weighted Average Exercise Price
Outstanding, beginning of year			1,482,675			$	24.66				1,515,500			$	24.68
Granted			—				—				2,500				22.88
Exercised (1)			—				—				—				—
Forfeited			(19,375	)			24.48				(29,500	)			24.74
Outstanding, end of period(2)(3)			1,463,300			$	24.66				1,488,500			$	24.67
Options exercisable, end of period(4)			732,025			$	24.67				371,375			$	24.67
Non-cash compensation expense recognized (in thousands)						$	1,374							$	2,880

 

(1)	No options were exercised during the nine months ended September 30, 2014 and 2013, respectively.

(2)	The weighted average remaining contractual life for outstanding options at September 30, 2014 was 7.6 years.

(3)	There was no aggregate intrinsic value of options outstanding at September 30, 2014 and 2013.

(4)	The weighted average remaining contractual lives for exercisable options at September 30, 2014 and 2013 were 7.6 years and 8.6 years, respectively. There were no aggregate intrinsic values of options exercisable at September 30, 2014 and 2013.

 

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At September 30, 2014, ARP had approximately $1.4 million in unrecognized compensation expense related to unvested unit options outstanding under the ARP LTIP based upon the fair value of the awards. ARP used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted.

The following weighted average assumptions were used for the periods indicated:

 

		Nine Months Ended September 30,
		2014				2013
Expected dividend yield			—	%			6.7	%
Expected unit price volatility			—	%			35.8	%
Risk-free interest rate			—	%			1.1	%
Expected term (in years)			—				6.35
Fair value of unit options granted		$	—			$	3.63

 

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NOTE 15—OPERATING SEGMENT INFORMATION

New Atlas’s operations include three reportable operating segments: ARP, New Atlas, and corporate and other. These operating segments reflect the way New Atlas manages its operations and makes business decisions. ARP consists of ARP’s operations. New Atlas includes the operations of the Arkoma assets and the Development Subsidiary (see Note 1). Corporate and other includes New Atlas’s equity investment in Lightfoot (see Note 1), as well as its general and administrative and interest expenses. Operating segment data for the periods indicated were as follows (in thousands):

 

		Nine Months Ended September 30,
		2014				2013
Atlas Resource:
Revenues		$	494,756			$	286,459
Operating costs and expenses			(309,159	)			(228,468	)
Depreciation, depletion and amortization expense			(171,090	)			(85,061	)
Loss on asset sales and disposal			(1,686	)			(2,035	)
Interest expense			(43,028	)			(22,145	)
Segment loss		$	(30,207	)		$	(51,250	)
New Atlas:
Revenues		$	16,760			$	2,700
Operating costs and expenses			(6,113	)			(1,167	)
Depreciation, depletion and amortization expense			(6,423	)			(1,331	)
Segment income		$	4,224			$	202
Corporate and other:
Revenues		$	824			$	130
General and administrative			(12,593	)			(9,270	)
Gain on asset sales and disposal			3				—
Interest expense			(8,446	)			(2,559	)
Segment loss		$	(20,212	)		$	(11,699	)
Reconciliation of segment income (loss) to net income (loss):
Segment income (loss):
Atlas Resource		$	(30,207	)		$	(51,250	)
New Atlas			4,224				202
Corporate and other			(20,212	)			(11,699	)
Net loss		$	(46,195	)		$	(62,747	)
Reconciliation of segment revenues to total revenues:
Segment revenues:
Atlas Resource		$	494,756			$	286,459
New Atlas			16,760				2,700
Corporate and other			824				130
Total revenues		$	512,340			$	289,289
Capital expenditures:
Atlas Resource		$	150,485			$	203,996
New Atlas			12,241				1,831
Corporate and other			—				—
Total capital expenditures		$	162,726			$	205,827

 

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		September 30, 2014				December 31, 2013
Balance sheet:
Goodwill:
Atlas Resource		$	31,784			$	31,784
New Atlas			—				—
Corporate and other			—				—
		$	31,784			$	31,784
Total assets:
Atlas Resource		$	2,986,402			$	2,343,800
New Atlas			126,955				76,004
Corporate and other			39,919				36,066
		$	3,153,276			$	2,455,870

NOTE 16—SUBSEQUENT EVENTS

Eagle Ford Shale Asset Acquisition. In November 2014, ARP and the Development Subsidiary completed an acquisition of oil and natural gas liquid interests in the Eagle Ford Shale in Atascosa County, Texas (the “Eagle Ford Acquisition”). Approximately $199.0 million was paid in cash by ARP and the Development Subsidiary at closing, and approximately $140.0 million will be paid over the four quarters following closing. ARP will pay approximately $24.0 million of the deferred portion of the purchase price in three quarterly installments beginning March 31, 2015. The Development Subsidiary will pay approximately $116.0 million of the deferred portion purchase price in four quarterly installments following closing. ARP may pay up to $20.0 million of its deferred portion of the purchase price by issuing ARP’s Class D cumulative redeemable perpetual preferred units at a price of $25.00 per unit. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as ARP and the Development Subsidiary continue to evaluate the facts and circumstances that existed as of the acquisition date.

In connection with the closing of the Eagle Ford Acquisition, the borrowing base under ARP’s revolving credit facility was increased to $900.0 million.

Merger with Targa Resources Corp. On October 13, 2014, Atlas Energy entered into a definitive merger agreement with Targa Resources Corp. (“TRC”; NYSE: TRGP) (the “Merger Agreement”), pursuant to which TRC agreed to acquire Atlas Energy through a newly formed, wholly owned subsidiary of TRC (the “Merger”). Upon completion of the Merger, holders of Atlas Energy’s common units will have the right to receive, for each Atlas Energy common unit, (i) 0.1809 TRC shares, and (ii) $9.12 in cash.

Concurrently with the execution of the Merger Agreement, APL entered into a definitive merger agreement (the “APL Merger Agreement”) with Atlas Energy, TRC, and Targa Resources Partners LP (“TRP”; NYSE: NGLS), pursuant to which TRP agreed to acquire APL through a newly formed, wholly owned subsidiary of TRP (the “APL Merger”). Upon completion of the APL Merger, holders of APL’s common units will have the right to receive (i) 0.5846 TRP common units and (ii) $1.26 in cash for each APL common unit.

Concurrent with the execution of the Merger Agreement and the APL Merger Agreement, Atlas Energy agreed to (i) transfer its assets and liabilities, other than those related to APL, to New Atlas, which is currently a wholly owned subsidiary of Atlas Energy and (ii) immediately prior to the Merger, effect a pro rata distribution to Atlas Energy’s unitholders of common units of New Atlas representing a 100% interest in such entity (the “Spin-Off”). New Atlas’s assets, assuming the Spin-Off had been completed as of September 30, 2014, consist of:

 

•

100% of the general partner Class A units, all of the incentive distribution rights, as well as an approximate 27.7% limited partner interest (20,962,485 common and 3,749,986 preferred limited partner units) in ARP;

 

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•

80% of the general partner Class A units, all of the incentive distribution rights, as well as a 3.1% limited partner interest, in the Development Subsidiary;

 

•

15.9% of the general partner interest and a 12% limited partner interest in Lightfoot, which has a 40% limited partner interest in ARCX; and,

 

•

Atlas Energy’s direct natural gas development and production assets in the Arkoma Basin, which it acquired in July 2013.

The closing of the Merger is subject to approval by holders of a majority of Atlas Energy’s common units, approval by a majority of the holders of TRC common stock voting at a special meeting held to approve the issuance of TRC shares in the Merger and other closing conditions, including the closing of the APL Merger and the Spin-Off. Completion of each of the APL Merger and the Spin-Off are also conditioned on the parties standing ready to complete the Merger.

Following the announcement on October 13, 2014 of the Merger, Atlas Energy, the General Partner, TRC, Trident GP Merger Sub LLC and the members of the General Partner’s board have been named as defendants in two putative unitholder class action lawsuits challenging the Merger. In addition, Atlas Energy, APL, Atlas Pipeline Partners GP LLC (“APL GP”), TRC, TRP, Targa Resources GP LLC, Trident MLP Merger Sub LLC and the members of the managing board of APL GP have been named as defendants in five putative unitholder class action lawsuits challenging the APL Merger.

The lawsuits filed generally allege that the individual defendants breached their fiduciary duties and/or contractual obligations by, among other things, failing to obtain sufficient value, in the case of the Merger, for Atlas Energy’s unitholders and, in the case of the APL Merger, for APL’s unitholders. The lawsuits also allege that the defendants omitted material information in the preliminary proxy statement/prospectuses filed by Atlas Energy and APL in connection with these mergers. in the Merger. The plaintiffs seek, among other things, injunctive relief, unspecified compensatory and/or rescissory damages, attorney’s fees, other expenses and costs. At this time, Atlas Energy cannot reasonably estimate the range of possible loss as a result of the lawsuit.

In addition, in January 2015, Atlas Energy, the individual members of the board of directors of Targa Resources and Targa Resources were named as defendants in a putative shareholder class action and derivative lawsuit alleging that the individual defendants breached their fiduciary duties by, among other things, omitting purportedly material information from the Proxy Statement/Prospectus filed by Targa Resources with the SEC. The plaintiffs seek, among other things, injunctive relief and unspecified rescissory damages, attorney’s fees, interest, and costs.

Atlas Resource

Distribution. On October 29, 2014, ARP declared a monthly distribution of $0.1966 per common unit for the month of September 2014. The $18.9 million distribution, including $1.4 million and $1.5 million to the general partner and preferred limited partners, respectively, was paid on November 14, 2014 to holders of record as of November 10, 2014.

On November 24, 2014, ARP declared its monthly distribution of $0.1966 per common unit for the month of October 2014. The $18.9 million distribution, including $1.4 million and $1.5 million to the general partner and preferred limited partners, respectively, will be paid on December 15, 2014 to holders of record as of December 5, 2014.

Issuance of Preferred Units. In connection with the Eagle Ford Acquisition, on October 2, 2014, ARP issued 3,200,000 8.625% ARP Class D cumulative redeemable perpetual preferred units at a public offering price of $25.00 per Class D Unit. ARP will pay cumulative distributions in cash on the units on a quarterly basis at a rate of $2.15625 per unit, or 8.625% of the liquidation preference, per year.

 

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9.25% ARP Senior Notes. Also in connection with the Eagle Ford Acquisition, on October 14, 2014, ARP issued an additional $75.0 million of its 9.25% ARP Senior Notes in a private transaction under Rule 144A and Regulation S of the Securities Act at an offering price of 100.5%, yielding net proceeds of approximately $73.6 million. In connection with the issuance, ARP also entered into a registration rights agreement. Under the registration rights agreement, ARP agreed to (i) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (ii) cause the exchange offer to be consummated no later than 270 days after the issuance of the 9.25% ARP Senior Notes. Under certain circumstances, in lieu of, or in addition to, a registered exchange offer, ARP agreed to file a shelf registration statement with respect to the issuance. If ARP fails to comply with its obligations to register the notes within the specified time periods, ARP will be subject to additional interest, up to 1% per annum, until such time that the exchange offer is consummated or the shelf registration is declared effective, as applicable.

 

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Annex A

 

 

THIRD AMENDED AND RESTATED

LIMITED LIABILITY COMPANY AGREEMENT

OF

ATLAS ENERGY GROUP, LLC

 

 

 

 

 

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TABLE OF CONTENTS

 

				Page
ARTICLE I DEFINITIONS					A-5
Section 1.1.		Definitions			A-5
Section 1.2.		Construction			A-15
ARTICLE II ORGANIZATION					A-16
Section 2.1.		Formation			A-16
Section 2.2.		Name			A-16
Section 2.3.		Registered Office; Registered Agent; Principal Office; Other Offices			A-16
Section 2.4.		Purpose and Business			A-16
Section 2.5.		Powers			A-17
Section 2.6.		Term			A-17
Section 2.7.		Title to Company Assets			A-17
ARTICLE III RIGHTS OF MEMBERS					A-17
Section 3.1.		Limitation of Liability			A-17
Section 3.2.		Management of Business			A-17
Section 3.3.		Outside Activities of Members			A-17
Section 3.4.		Rights of Members			A-18
ARTICLE IV CERTIFICATES; RECORD HOLDERS; TRANSFER OF COMPANY INTERESTS; REDEMPTION OF COMPANY INTERESTS					A-18
Section 4.1.		Certificates			A-18
Section 4.2.		Mutilated, Destroyed, Lost or Stolen Certificates			A-19
Section 4.3.		Record Holders			A-19
Section 4.4.		Transfer Generally			A-19
Section 4.5.		Registration and Transfer of Company Interests			A-20
Section 4.6.		Restrictions on Transfers			A-21
Section 4.7.		Eligibility Certificates; Ineligible Holders			A-22
Section 4.8.		Redemption of Company Interests of Ineligible Holders			A-23
ARTICLE V CAPITAL CONTRIBUTIONS AND ISSUANCE OF COMPANY INTERESTS					A-24
Section 5.1.		Organizational Contributions			A-24
Section 5.2.		Additional Capital Contributions			A-24
Section 5.3.		Interest and Withdrawal			A-24
Section 5.4.		Capital Accounts			A-24
Section 5.5.		Issuances of Additional Company Interests			A-27
Section 5.6.		No Preemptive Right			A-27
Section 5.7.		Splits and Combinations			A-27
Section 5.8.		Fully Paid and Non-Assessable Nature of Company Interests			A-28
ARTICLE VI ALLOCATIONS AND DISTRIBUTIONS					A-28
Section 6.1.		Allocations for Capital Account Purposes			A-28
Section 6.2.		Allocations for Tax Purposes			A-31
Section 6.3.		Requirement of Distributions; Distributions to Record Holders			A-34
ARTICLE VII MANAGEMENT AND OPERATION OF BUSINESS					A-34
Section 7.1.		Management			A-34
Section 7.2.		Duties			A-38
Section 7.3.		Certificate of Formation			A-38

 

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				Page
Section 7.4.		Restrictions on the Board of Directors’ Authority			A-38
Section 7.5.		Officers			A-39
Section 7.6.		Outside Activities			A-41
Section 7.7.		Loans or Contributions from the Company or Group Members			A-42
Section 7.8.		Indemnification			A-42
Section 7.9.		Liability of Indemnitees			A-43
Section 7.10.		Standards of Conduct and Modification of Duties			A-44
Section 7.11.		Other Matters Concerning the Board of Directors and Officers			A-44
Section 7.12.		Purchase or Sale of Company Interests			A-45
Section 7.13.		Reliance by Third Parties			A-45
ARTICLE VIII BOOKS, RECORDS, ACCOUNTING AND REPORTS					A-45
Section 8.1.		Records and Accounting			A-45
Section 8.2.		Fiscal Year			A-45
Section 8.3.		Reports			A-46
ARTICLE IX TAX MATTERS					A-46
Section 9.1.		Tax Returns and Information			A-46
Section 9.2.		Tax Elections			A-46
Section 9.3.		Tax Controversies			A-47
Section 9.4.		Withholding			A-47
ARTICLE X ADMISSION AND WITHDRAWAL OF MEMBERS					A-47
Section 10.1.		Admission of Members			A-47
Section 10.2.		Withdrawal of Members			A-48
ARTICLE XI DISSOLUTION AND LIQUIDATION					A-48
Section 11.1.		Dissolution			A-48
Section 11.2.		Liquidator			A-48
Section 11.3.		Liquidation			A-48
Section 11.4.		Cancellation of Certificate of Formation			A-49
Section 11.5.		Return of Contributions			A-49
Section 11.6.		Waiver of Partition			A-49
Section 11.7.		Capital Account Restoration			A-49
ARTICLE XII AMENDMENT OF COMPANY AGREEMENT; MEETINGS; RECORD DATE					A-49
Section 12.1.		Amendments to be Adopted Solely by the Board of Directors			A-49
Section 12.2.		Amendment Procedures			A-51
Section 12.3.		Amendment Requirements			A-51
Section 12.4.		Unitholder Meetings			A-52
Section 12.5.		Notice of a Meeting			A-56
Section 12.6.		Record Date			A-56
Section 12.7.		Adjournment			A-56
Section 12.8.		Waiver of Notice; Approval of Meeting			A-56
Section 12.9.		Quorum and Voting			A-56
Section 12.10.		Conduct of a Meeting			A-57
Section 12.11.		Action Without a Meeting			A-57
Section 12.12.		Voting and Other Rights			A-57
Section 12.13.		Submission of Questionnaire, Representation and Agreement			A-58
ARTICLE XIII MERGER, CONSOLIDATION OR CONVERSION					A-58
Section 13.1.		Authority			A-58
Section 13.2.		Procedure for Merger, Consolidation or Conversion			A-58

 

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				Page
Section 13.3.		Approval by Members			A-59
Section 13.4.		Certificate and Effect of Merger or Conversion			A-60
Section 13.5.		Amendment of Company Agreement			A-61
ARTICLE XIV GENERAL PROVISIONS					A-61
Section 14.1.		Addresses and Notices; Written Communications			A-61
Section 14.2.		Further Action			A-62
Section 14.3.		Binding Effect			A-62
Section 14.4.		Integration			A-62
Section 14.5.		Creditors			A-62
Section 14.6.		Waiver			A-62
Section 14.7.		Third-Party Beneficiaries			A-62
Section 14.8.		Counterparts			A-63
Section 14.9.		Applicable Law; Forum; Venue and Jurisdiction			A-63
Section 14.10.		Invalidity of Provisions			A-64
Section 14.11.		Consent of Members			A-64
Section 14.12.		Facsimile and PDF Signatures			A-64

 

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THIRD AMENDED AND RESTATED

LIMITED LIABILITY COMPANY AGREEMENT

OF

ATLAS ENERGY GROUP, LLC

THIS THIRD AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT OF ATLAS ENERGY GROUP, LLC, dated as of                     , is executed and agreed to by Atlas Energy, L.P., a Delaware limited partnership (the “Initial Member”), as the sole member of the Company as of the date hereof, together with any other Persons who become Members in the Company or parties hereto as provided herein.

WITNESSETH:

WHEREAS, the Company was formed as a Delaware limited liability company on October 13, 2011;

WHEREAS, the Initial Member, as the sole member of the Company, executed the Second Amended and Restated Limited Liability Company Agreement of the Company, dated as of October 24, 2013, which it further amended on November 3, 2014 (as amended, the “Existing Limited Liability Company Agreement”), which superseded the Amended and Restated Limited Liability Company Agreement of the Company, dated as of February 13, 2012, which superseded the Limited Liability Company Agreement of the Company, dated as of October 13, 2011 (the “Original Limited Liability Company Agreement”).

WHEREAS, on                     , the Initial Member has declared a distribution of 100% of the limited liability company interests in the Company to the holders of common units of Atlas Energy, L.P. as of record as of the close of business on                      (the “Distribution”); and

WHEREAS, prior to the consummation of the Distribution, the Initial Member desires to amend and restate the Existing Limited Liability Company Agreement in its entirety in the manner set forth in this Agreement.

NOW, THEREFORE, in consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I

DEFINITIONS

Section 1.1. Definitions.

The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

“Additional Book Basis” means the portion of any remaining Carrying Value of an Adjusted Property that is attributable to positive adjustments made to such Carrying Value as a result of Book-Up Events. For purposes of determining the extent that Carrying Value constitutes Additional Book Basis:

(a) Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event.

 

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(b) If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis; provided that the amount treated as Additional Book Basis as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceeds the remaining Additional Book Basis attributable to all of the Company’s Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (b) to such Book-Down Event).

“Additional Book Basis Derivative Items” means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Company’s Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the “Excess Additional Book Basis”), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period.

“Additional Member” means a Person admitted to the Company as a Member pursuant to Section 4.5(d) and who is shown as such on the books and records of the Company.

“Adjusted Capital Account” means the Capital Account maintained for each Member as of the end of each taxable year of the Company, (a) increased by any amounts that such Member is obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all adjustments that, as of the end of such taxable year, reasonably are expected to be made to such Member’s Capital Account under Treasury Regulation Section 1.704-1(b)(2)(iv)(k) for depletion allowances with respect to oil and gas properties of the Company, (ii) the amount of all losses and deductions that, as of the end of such taxable year, reasonably are expected to be allocated to such Member in subsequent years pursuant to Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii), and (iii) the amount of all distributions that, as of the end of such taxable year, reasonably are expected to be made to such Member in subsequent years in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Member’s Capital Account that are reasonably expected to occur during (or prior to) the year in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section 6.1(d)(i) or 6.1(d)(ii)). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Member in respect of a Common Unit or any other Company Interest shall be the amount that such Adjusted Capital Account would be if such Common Unit or other Company Interest were the only interest in the Company held by a Member from and after the date on which such Common Unit or other Company Interest was first issued.

“Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Section 5.4(d)(i) or 5.4(d)(ii).

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

“Aggregate Remaining Net Positive Adjustments” means, as of the end of any taxable period, the sum of the Remaining Net Positive Adjustments of all the Members.

 

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“Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including a Curative Allocation (if appropriate to the context in which the term “Agreed Allocation” is used).

“Agreed Value” of any Contributed Property means the fair market value of such property or other consideration at the time of contribution and in the case of an Adjusted Property, the fair market value of such Adjusted Property on the date of the revaluation event as described in Section 5.4(d), in both cases as determined by the Board of Directors. The Board of Directors shall use such method as it determines to be appropriate to allocate the aggregate Agreed Value of Contributed Properties contributed to the Company in a single or integrated transaction among each separate property on a basis proportional to the fair market value of each Contributed Property.

“Agreement” means this Third Amended and Restated Limited Liability Company Agreement of Atlas Energy Group, LLC, as it may be amended, supplemented or restated from time to time.

“Associate” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer, manager, member, general partner or managing member or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

“Available Cash” means, with respect to any Distribution Period ending prior to the Liquidation Date,

(a) the sum of all cash and cash equivalents (including amounts available for working capital purposes under a credit facility, commercial paper facility or other similar financing arrangement) of the Company on hand on the date of determination of Available Cash with respect to such Distribution Period, less

(b) the amount of any cash reserves established by the Board of Directors for the Company Group to (i) provide for the proper conduct of the business of the Company (including reserves for working capital, operating expenses, future capital expenditures, potential acquisitions and for anticipated future credit needs of the Company Group), (ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a party or by which it is bound or its assets are subject, (iii) permit any member of the Non-MLP Group to make capital contributions to any member of an MLP Group to maintain its then current interest in such member of an MLP Group upon the issuance of additional securities by such member of an MLP Group or (iv) provide funds for distributions under Section 6.3 in respect of any one or more of the Distribution Periods in the next calendar year; provided, however, that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of such Distribution Period but on or before the date of determination of Available Cash with respect to such Distribution Period shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Distribution Period if the Board of Directors so determines.

Notwithstanding the foregoing, “Available Cash” with respect to the Distribution Period in which the Liquidation Date occurs and any subsequent Distribution Period shall equal zero.

“Board of Directors” has the meaning assigned to such term in Section 7.1.

“Book Basis Derivative Items” means any item of income, deduction, gain or loss included in the determination of Net Income or Net Loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, depletion, or gain or loss with respect to an Adjusted Property).

 

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“Book-Down Event” means an event that triggers a negative adjustment to the Capital Accounts of the Member pursuant to Section 5.4(d).

“Book-Tax Disparity” means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for U.S. federal income tax purposes as of such date. A Member’s share of the Company’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Member’s Capital Account balance as maintained pursuant to Section 5.4 and the hypothetical balance of such Member’s Capital Account computed as if it had been maintained strictly in accordance with U.S. federal income tax accounting principles.

“Book-Up Event” means an event that triggers a positive adjustment to the Capital Accounts of the Members pursuant to Section 5.4(d).

“Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the Commonwealth of Pennsylvania shall not be regarded as a Business Day.

“Capital Account” means the capital account maintained for a Member pursuant to Section 5.4. The “Capital Account” of a Member in respect of a Common Unit or any other Company Interest shall be the amount that such Capital Account would be if such Common Unit or other Company Interest were the only interest in the Company held by a Member from and after the date on which such Common Unit or other Company Interest was first issued.

“Capital Contribution” means any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Member contributes to the Company pursuant to this Agreement or the Separation Agreement or that is contributed or deemed contributed to the Company on behalf of a Member (including, in the case of an underwritten offering of Company Interests, the amount of any underwriting discounts or commissions).

“Carrying Value” means (a) with respect to a Contributed Property or Adjusted Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, Simulated Depletion, amortization and cost recovery deductions charged to the Members’ Capital Accounts in respect of such property, and (b) with respect to any other Company property, the adjusted basis of such property for U.S. federal income tax purposes, all as of the time of determination. The Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.4(d)(i) and 5.4(d)(ii) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Company properties, as deemed appropriate by the Board of Directors.

“Certificate” means a certificate in such form (including in global form if permitted by applicable rules and regulations) as may be adopted by the Board of Directors, issued by the Company evidencing ownership of one or more Common Units or a certificate, in such form as may be adopted by the Board of Directors, issued by the Company evidencing ownership of one or more other Company Interests.

“Certificate of Formation” means the Certificate of Formation of the Company filed with the Secretary of State of the State of Delaware as referenced in Section 2.1, as such Certificate of Formation may be amended, supplemented or restated from time to time.

“Citizenship Eligibility Trigger” has the meaning assigned to such term in Section 4.7(a)(ii).

“Closing Date” means                     .

“Code” means the Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

 

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“Commission” means the U.S. Securities and Exchange Commission.

“Common Unit” means a Company Interest representing a fractional part of the Company Interests of all Members, and having the rights and obligations specified with respect to Common Units in this Agreement.

“Company” means Atlas Energy Group, LLC, a Delaware limited liability company, and any successors thereto.

“Company Group” means the Company and its Subsidiaries treated as a single consolidated entity.

“Company Interest” means the ownership interest of a Member in the Company, which may be evidenced by Common Units or other equity interests in the Company or a combination thereof or interest therein, and includes any and all benefits to which such Member is entitled as provided in this Agreement, together with all obligations of such Member to comply with the terms and provisions of this Agreement, and which shall exclude options, warrants, rights and appreciation rights relating to an equity interest in the Company.

“Company Minimum Gain” means that amount determined in accordance with the principles of Treasury Regulation Section 1.704-2(b)(2) and 1.704-2(d).

“Contributed Property” means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Company (or deemed contributed to a new partnership on termination of the Company pursuant to Section 708 of the Code). Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.4(d), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

“Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(ix).

“Current Market Price” as of any date of any class of Company Interests listed or admitted to trading on any National Securities Exchange means the average of the daily closing prices per limited liability company interest of such class for the 20 consecutive trading days immediately prior to such date. For the purposes of this definition, “closing price” for any day means the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, in either case as reported in the principal consolidated transaction reporting system with respect to securities listed or admitted for trading on the principal National Securities Exchange on which such Company Interests of such class are listed or admitted to trading or, if such Company Interests of such class are not listed or admitted to trading on any National Securities Exchange, the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by the Nasdaq National Market or any other system then in use, or, if on any such day such Company Interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Company Interests of such class selected by the Board of Directors, or if on any such day no market maker is making a market in such Company Interests of such class, the fair value of such Company Interests on such day as determined by the Board of Directors. For the purposes of this definition, “trading day” means a day on which the principal National Securities Exchange on which such Company Interests of any class are listed or admitted to trading is open for the transaction of business or, if Company Interests of a class are not listed or admitted to trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

“Delaware Act” means the Delaware Limited Liability Company Act, 6 Del. C. Section 18-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

“Derivative Instrument” has the meaning assigned to such term in Section 12.4(d)(i).

 

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“Directors” shall mean the members of the Board of Directors.

“Distribution Period” means any period of time (including Month, Quarter or other period of time) selected by the Board of Directors with respect to which distributions of Available Cash shall be made by the Company.

“Economic Risk of Loss” has the meaning set forth in Treasury Regulation Section 1.752-2(a).

“Eligibility Certificate” has the meaning assigned to such term in Section 4.7(b).

“Eligible Holder” means a Member whose (a) U.S. federal income tax status would not, in the determination of the Board of Directors, have the material adverse effect described in Section 4.7(a)(i) or (b) nationality, citizenship or other related status would not, in the determination of the Board of Directors, create a substantial risk of cancellation or forfeiture as described in Section 4.7(a)(ii).

“Exchange Act” means the U.S. Securities Exchange Act of 1934, as amended, supplemented or restated from time to time and any successor to such statute.

“Gross Liability Value” means, with respect to any Liability of the Company described in Treasury Regulation Section 1.752-7(b)(3)(i), the amount of cash that a willing assignor would pay to a willing assignee to assume such Liability in an arm’s length transaction.

“Group” means a Person that, with or through any of its Affiliates or Associates, has any contract, agreement, arrangement, understanding or relationship for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power or disposing of any Company Interests with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Company Interests.

“Group Member” means a member of the Company Group.

“Indemnitee” means (a) any Person who is or was a manager, managing member, officer, director, employee, agent, tax matters partner, fiduciary or trustee of any Group Member or any Affiliate of any Group Member, (b) any Group Member or any Affiliate of any Group Member, (c) any Person who is or was serving at the request of the Company as a manager, managing member, officer, director, employee, agent, tax matters partner, fiduciary or trustee of another Person; provided that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services and (d) any Person that the Board of Directors designates as an “Indemnitee” for purposes of this Agreement.

“Ineligible Holder” has the meaning assigned to such term in Section 4.7(c).

“Initial Common Units” means the Common Units distributed in the Initial Distribution.

“Initial Distribution” means the initial distribution by Atlas Energy, L.P. of Common Units to the unitholders of Atlas Energy, L.P., as described in the Registration Statement.

“Initial Member” means Atlas Energy, L.P., in its capacity as the sole member of the Company pursuant to the Existing Agreement.

“Liability” means any liability or obligation of any nature, whether accrued, contingent or otherwise.

“Liquidation Date” means the date on which dissolution of the Company occurs.

 

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“Liquidator” means one or more Persons selected by the Board of Directors to perform the functions described in Section 11.2 as liquidating trustee of the Company within the meaning of the Delaware Act.

“Member” means, unless the context otherwise requires, a holder of Common Units, except to the extent otherwise provided herein, and each Additional Member, in each case, in such Person’s capacity as a member of the Company.

“Member Nonrecourse Debt” has the meaning of the term “partner nonrecourse debt” as set forth in Treasury Regulation Section 1.704-2(b)(4).

“Member Nonrecourse Debt Minimum Gain” has the meaning of the term “partner nonrecourse debt minimum gain” as set forth in Treasury Regulation Section 1.704-2(i)(2).

“Member Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(i)(1) and 1.704-2(i)(2), are attributable to a Member Nonrecourse Debt.

“Merger Agreement” has the meaning assigned to such term in Section 13.1.

“MLP Group” means any MLP and any Subsidiary of such MLP, treated as a single consolidated entity.

“MLP” means any limited partnership or limited liability company that is not a wholly owned Subsidiary of the Company where the general partner or managing member of such limited partnership or limited liability company is the Company or a Subsidiary of the Company. As of the date hereof, Atlas Resource Partners, L.P., a Delaware limited partnership, is an MLP.

“Month” means, unless the context requires otherwise, a calendar month or, with respect to the first calendar month of the Company that includes the Closing Date, the portion of such calendar month after the Closing Date.

“National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Exchange Act (or any successor to such Section) and any other securities exchange (whether or not registered with the Commission under Section 6(a) (or successor to such Section) of the Exchange Act) that the Board of Directors shall designate as a National Securities Exchange for purposes of this Agreement.

“Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any Liabilities either assumed by the Company upon such contribution or to which such property is subject when contributed, and (b) in the case of any property distributed to a Member by the Company, the Company’s Carrying Value of such property (as adjusted pursuant to Section 5.4(d)(ii)) at the time such property is distributed, reduced by any Liability either assumed by such Member upon such distribution or to which such property is subject at the time of distribution, in either case, as determined and required by the Treasury Regulations promulgated under Section 704(b) of the Code.

“Net Income” means, for any taxable period, the excess, if any, of the Company’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Company’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Income shall be determined in accordance with Section 5.4(b) and shall include Simulated Gain but shall not include any items specially allocated under Section 6.1(d) or Section 6.1(e); provided that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d) were not in this Agreement.

 

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“Net Loss” means, for any taxable period, the excess, if any, of the Company’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Company’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.4(b) and shall include Simulated Gain but shall not include any items specially allocated under Section 6.1(d) or Section 6.1(e); provided that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d) were not in this Agreement.

“Net Positive Adjustments” means, with respect to any Member, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Member pursuant to Book-Up Events and Book-Down Events.

“Net Termination Gain” means, for any taxable period, the sum, if positive, of all items of income, gain, loss or deduction recognized by the Company after the Liquidation Date. The items included in the determination of Net Termination Gain shall be determined in accordance with Section 5.4(b) and shall include Simulated Gain but shall not include any items of income, gain or loss specially allocated under Section 6.1(d) or Section 6.1(e).

“Net Termination Loss” means, for any taxable period, the sum, if negative, of all items of income, gain, loss or deduction recognized by the Company after the Liquidation Date. The items included in the determination of Net Termination Loss shall be determined in accordance with Section 5.4(b) and shall include Simulated Gain but shall not include any items of income, gain or loss specially allocated under Section 6.1(d) or Section 6.1(e).

“Non-MLP Group” means any member of the Company Group, other than any member of any MLP Group.

“Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Members pursuant to Sections 6.2(c)(iii), 6.2(d)(i)(A), 6.2(d)(ii)(A) and 6.2(d)(iii) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

“Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(b)(1) and 1.704-2(c), are attributable to a Nonrecourse Liability.

“Nonrecourse Liability” has the meaning set forth in Treasury Regulation Section 1.704-2(b)(3).

“Officers” has the meaning assigned to such term in Section 7.5(a).

“Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to the Company or any of its Affiliates) in a form acceptable to the Board of Directors.

“Outstanding” means, with respect to Company Interests, all Company Interests that are issued by the Company and reflected as outstanding on the Company’s books and records as of the date of determination; provided, however, that if at any time any Person or Group beneficially owns 20% or more of the Outstanding Voting Units of any class, all Units owned by such Person or Group shall not be voted (and shall not be entitled to be voted) on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Members to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement; provided, further, that the foregoing limitation shall not apply to any Person or Group who acquired 20% or more of the Outstanding Units of any class with the prior approval of the Board of Directors.

 

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“Per Unit Capital Amount” means, as of any date of determination, the Capital Account, stated on a per Unit basis, underlying any Company Interest held by a Person.

“Percentage Interest” means, as of any date of determination, (a) as to any Unitholder holding Units, the product obtained by multiplying (i) 100% less the percentage applicable to clause (b) below by (ii) the quotient obtained by dividing (A) the number of Units held by such Unitholder by (B) the total number of all Outstanding Units, and (b) as to the holders of additional Company Interests issued by the Company in accordance with Section 5.5, the percentage established as a part of such issuance. Unless the context otherwise requires, references to the Percentage Interest of any holder of more than one class or series of Company Interests shall mean the aggregate Percentage Interest attributable to all such Company Interests.

“Person” means an individual or a corporation, firm, limited liability company, partnership, limited partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

“Plan of Conversion” has the meaning assigned to such term in Section 13.1.

“Pro Rata” means (a) when used with respect to Company Interests or any class or classes thereof, apportioned equally among all designated Company Interests in accordance with their relative Percentage Interests, and (b) when used with respect to Members or Record Holders, apportioned among all Members or Record Holders in accordance with their relative Percentage Interests.

“Quarter” means, unless the context requires otherwise, a fiscal quarter of the Company, or, with respect to the fiscal quarter of the Company that includes the Closing Date, the portion of such fiscal quarter after the Closing Date.

“Rate Eligibility Trigger” has the meaning assigned to such term in Section 4.7(a)(i).

“Recapture Income” means any gain recognized by the Company (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Company, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

“Record Date” means the date established by the Board of Directors or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Members or entitled to vote by ballot or give approval of Company action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Members or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

“Record Holder” means (a) with respect to Company Interests of any class for which a Transfer Agent has been appointed, the Person in whose name a Company Interest of such class is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day or (b) with respect to other classes of Company Interests, the Person in whose name any such other Company Interest is registered on the books that the Board of Directors has caused to be kept as of the opening of business on such Business Day.

“Redeemable Interests” means any Company Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.8.

“Registration Statement” means the Registration Statement on Form 10 (File No. 001-            ), as it has been or as it may be amended or supplemented from time to time, filed by the Company with the Commission to register the Common Units under the Exchange Act.

 

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“Remaining Net Positive Adjustments” means as of the end of any taxable period, with respect to the Unitholders, the excess of (a) the Net Positive Adjustments of the Unitholders, as of the end of such period over (b) the sum of those Members’ Share of Additional Book Basis Derivative Items for each prior taxable period.

“Required Allocations” means (a) any limitation imposed on any allocation of Net Losses or Net Termination Losses under Section 6.1(b) or 6.1(c)(ii) and (b) any allocation of an item of income, gain, loss, deduction, Simulated Depletion or Simulated Loss pursuant to Section 6.1(d)(i), 6.1(d)(ii), 6.1(d)(iv), 6.1(d)(v), 6.1(d)(vi), 6.1(d)(vii), 6.1(d)(ix) or 6.1(e).

“Residual Gain” or “Residual Loss” means any item of gain or loss, or Simulated Gain or Simulated Loss, as the case may be, of the Company recognized for U.S. federal income tax purposes resulting from a sale, exchange or other disposition of a Contributed Property or Adjusted Property, to the extent such item of gain or loss or Simulated Gain or Simulated Loss is not allocated pursuant to Section 6.2(d)(i)(A) or 6.2(d)(ii)(A), respectively, to eliminate Book-Tax Disparities.

“Securities Act” means the U.S. Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.

“Separation Agreement” means the Separation and Distribution Agreement, dated as of                     , by and among the Initial Member, the Company and the general partner of the Initial Member.

“Share of Additional Book Basis Derivative Items” means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, with respect to the Unitholders, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such taxable period bears to the Aggregate Remaining Net Positive Adjustments as of that time.

“Short Interest” has the meaning assigned to such term in Section 12.4(d)(i).

“Simulated Basis” means the Carrying Value of any oil and gas property (as defined in Section 614 of the Code).

“Simulated Depletion” means, with respect to an oil and gas property (as defined in Section 614 of the Code), a depletion allowance computed in accordance with U.S. federal income tax principles (as if the Simulated Basis of the property was its adjusted tax basis) and in the manner specified in Treasury Regulation Section 1.704-1(b)(2)(iv)(k)(2). For purposes of computing Simulated Depletion with respect to any property, the Simulated Basis of such property shall be deemed to be the Carrying Value of such property, and in no event shall such allowance for Simulated Depletion, in the aggregate, exceed such Simulated Basis.

“Simulated Gain” means the excess, if any, of the amount realized from the sale or other disposition of an oil or gas property over the Carrying Value of such property.

“Simulated Loss” means the excess, if any, of the Carrying Value of an oil or gas property over the amount realized from the sale or other disposition of such property.

“Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) or limited liability company in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership or member of such limited liability company, but

 

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only if more than 50% of the partnership interests of such partnership or membership interests of such limited liability company (considering all of the partnership interests or membership interests as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, or (c) any other Person (other than a corporation, a partnership or limited liability company) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

“Surviving Business Entity” has the meaning assigned to such term in Section 13.2(b)(ii).

“transfer” has the meaning assigned to such term in Section 4.4(a).

“Transfer Agent” means such bank, trust company or other Person as shall be appointed from time to time by the Company to act as registrar and transfer agent for any class of Company Interests.

“Unit” means a Company Interest that is designated as a “Unit” and shall include Common Units.

“Unitholders” means the holders of Units.

“Unrealized Gain” attributable to any item of Company property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.4(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.4(d) as of such date).

“Unrealized Loss” attributable to any item of Company property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.4(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.4(d)).

“Unrestricted Person” means (a) each Indemnitee, (b) each Member, (c) each Person who is or was a member, partner, director, officer, employee or agent of any Group Member or any Affiliate of any Group Member and (d) any Person the Board of Directors designates as an “Unrestricted Person” for purposes of this Agreement.

“U.S. GAAP” means U.S. generally accepted accounting principles, as in effect from time to time, consistently applied.

“Voting Commitment” has the meaning assigned to such term in Section 12.13.

“Voting Units” means all Units that are granted the right under this Agreement or under the Delaware Act to vote with respect to the relevant matter; provided that any Units owned, directly or indirectly, by the Company do not constitute Voting Units.

Section 1.2. Construction.

Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; (c) the terms “include,” “includes” or “including” or words of like import shall be deemed to be followed by the words “without limitation”; and (d) the terms “hereof,” “herein” or “hereunder” refer to this Agreement as a whole and not to any particular provision of this Agreement. The table of contents and headings contained in this Agreement are for reference purposes only, and shall not affect in any way the meaning or interpretation of this Agreement.

 

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ARTICLE II

ORGANIZATION

Section 2.1. Formation.

The Company was formed on October 13, 2011 as “Atlas Resource Partners GP, LLC” pursuant to the Certificate of Formation as filed with the Secretary of State of the State of Delaware pursuant to the provisions of the Delaware Act and by the entering into of the Original Limited Liability Company Agreement. The Certificate of Formation was amended on November 3, 2014 to change the name of the Company to “Atlas Energy Group, LLC”. This Agreement hereby amends and restates the Existing Limited Liability Company Agreement in its entirety, and this Agreement shall become effective on the date hereof. Except as expressly provided to the contrary in this Agreement, the rights, duties, liabilities and obligations of the Members and the administration, dissolution and termination of the Company shall be governed by the Delaware Act. All Company Interests shall constitute personal property of the owner thereof for all purposes.

Section 2.2. Name.

The name of the Company shall be “Atlas Energy Group, LLC”. The Company’s business may be conducted under any other name or names as determined by the Board of Directors. The words “Limited Liability Company,” “LLC,” “L.L.C.” or similar words or letters shall be included in the Company’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The Board of Directors may change the name of the Company at any time and from time to time and shall notify the Members of such change in the next regular communication to the Members.

Section 2.3. Registered Office; Registered Agent; Principal Office; Other Offices.

Unless and until changed by the Board of Directors, the registered office of the Company in the State of Delaware shall be located at 2711 Centerville Road, Wilmington, Delaware 19808, and the registered agent for service of process on the Company in the State of Delaware at such registered office shall be The Corporation Trust Company. The principal office of the Company shall be located at Park Place Corporate Center One, 1000 Commerce Drive, Suite 400, Pittsburgh, PA 15275 or such other place as the Board of Directors may from time to time designate by notice to the Members (which notice may be satisfied by indicating such other place in a public filing with the Commission). The Company may maintain offices at such other place or places within or outside the State of Delaware as the Board of Directors determines to be necessary or appropriate.

Section 2.4. Purpose and Business.

The purpose and nature of the business to be conducted by the Company shall be to (a) engage directly in, or enter into or form, hold and dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the Board of Directors, in its sole discretion, and that lawfully may be conducted by a limited liability company organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Company pursuant to the agreements relating to such business activity; and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the Company shall not engage, directly or indirectly, in any business activity that the Board of Directors determines would cause the Company to be treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes. To the fullest extent permitted by law, the Board of Directors shall have no duty or obligation to propose or approve, and may, in its sole discretion, decline to propose or approve, the conduct by the Company of any business, free of any duty or obligation whatsoever to the Company or any Member and, in declining to so propose or approve, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

 

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Section 2.5. Powers.

The Company shall be empowered to do any and all acts and things necessary, appropriate, proper, advisable, incidental to or convenient for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Company.

Section 2.6. Term.

The term of the Company commenced upon the filing of the Certificate of Formation in accordance with the Delaware Act and shall continue in existence until the dissolution of the Company in accordance with the provisions of Article XI. The existence of the Company as a separate legal entity shall continue until the cancellation of the Certificate of Formation as provided in the Delaware Act.

Section 2.7. Title to Company Assets.

Title to Company assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Company as an entity, and no Member, individually or collectively, shall have any ownership interest in such Company assets or any portion thereof. Title to any or all of the Company assets may be held in the name of the Company, one or more of its Affiliates or one or more nominees, as the Board of Directors may determine. The Company hereby declares and warrants that any Company assets for which record title is held in the name of the Company or one or more of its Affiliates or one or more nominees shall be held by the Company or such Affiliate or nominee for the use and benefit of the Company in accordance with the provisions of this Agreement; provided, however, that the Board of Directors shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the Board of Directors determines that the expense and difficulty of conveyancing makes transfer of record title to the Company impracticable) to be vested in the Company or one or more of the Company’s designated Affiliates as soon as reasonably practicable. All Company assets shall be recorded as the property of the Company in its books and records, irrespective of the name in which record title to such Company assets is held.

ARTICLE III

RIGHTS OF MEMBERS

Section 3.1. Limitation of Liability.

As provided in Section 18-303 of the Delaware Act, the debts, obligations and liabilities of the Company, whether arising in contract, tort or otherwise, shall be solely the debts, obligations and liabilities of the Company. The Members shall have no liability under this Agreement, or for any such debt, obligation or liability of the Company, in their capacity as a Member, except as expressly provided in this Agreement or the Delaware Act.

Section 3.2. Management of Business.

No Member, in its capacity as such, shall participate in the operation or management of the Company’s business, transact any business in the Company’s name or have the power to sign documents for or otherwise bind the Company by reason of being a Member.

Section 3.3. Outside Activities of Members.

Any Member shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Company, including business interests and activities in direct competition with the Company Group. Neither the Company nor any of the other Members shall have any rights by virtue of this Agreement in any business ventures of any Member.

 

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Section 3.4. Rights of Members.

(a) In addition to other rights provided by this Agreement or by applicable law, and except as limited by Section 3.4(b), each Member shall have the right, for a purpose reasonably related, as determined by the Board of Directors, to such Member’s interest as a Member in the Company, upon reasonable written demand stating the purpose of such demand and at such Member’s own expense:

(i) to obtain true and full information regarding the status of the business and financial condition of the Company; provided, however, that the requirements of this Section 3.4(a)(i) shall be satisfied by furnishing to a Membr upon its demand pursuant to this Section 3.4(a)(i) either (A) the Company’s most recent filings with the Commission on Form 10-K and any subsequent filings on Form 10-Q and 8-K or (B) if the Company is no longer subject to the reporting requirements of the Exchange Act, the information specified in, and meeting the requirements of, Rule 144A(d)(4) under the Securities Act;

(ii) promptly after its becoming available, to obtain a copy of the Company’s federal, state and local income tax returns for each year;

(iii) to obtain a current list of the name and last known business, residence or mailing address of each Member;

(iv) to obtain a copy of this Agreement and the Certificate of Formation and all amendments thereto, together with a copy of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Formation and all amendments thereto have been executed;

(v) to obtain true and full information regarding the amount of cash and a description and statement of the Net Agreed Value of any other Capital Contribution by each Member and that each Member has agreed to contribute in the future, and the date on which each became a Member; and

(vi) to obtain such other information regarding the affairs of the Company as is just and reasonable.

(b) Notwithstanding any other provision of this Agreement, the Board of Directors may keep confidential from the Members, for such period of time as the Board of Directors determines, (i) any information that the Board of Directors reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the Board of Directors believes (A) is not in the best interests of the Company or the Company Group, (B) could damage the Company or the Company Group or their respective businesses or (C) that any Group Member is required by law or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Company the primary purpose of which is to circumvent the obligations set forth in this Section 3.4).

ARTICLE IV

CERTIFICATES; RECORD HOLDERS; TRANSFER OF COMPANY INTERESTS;

REDEMPTION OF COMPANY INTERESTS

Section 4.1. Certificates.

Notwithstanding anything to the contrary in this Agreement, unless the Board of Directors shall determine otherwise in respect of some or all of any or all classes of Company Interests, Company Interests shall not be evidenced by physical certificates. Certificates that may be issued, if any, shall be executed on behalf of the Company by the Chairman of the Board, Chief Executive Officer, President, Chief Financial Officer or any Executive Vice President or Vice President and the Secretary, any Assistant Secretary or other authorized officer or director of the Company. If a Transfer Agent has been appointed for a class of Company Interests, no Certificate, if any, for such class of Company Interests shall be valid for any purpose until it has been countersigned by the Transfer Agent for such class of Company Interests; provided, however, that if the Board of

 

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Directors elects to cause the Company to issue Company Interests of such class in global form, the Certificate, if any, shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Company Interests have been duly registered in accordance with the directions of the Company.

Section 4.2. Mutilated, Destroyed, Lost or Stolen Certificates.

(a) To the extent any Company Interest is represented by a Certificate, if any mutilated Certificate is surrendered to the Transfer Agent, the appropriate officers of the Company shall execute, and the Transfer Agent shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Company Interests as the Certificate so surrendered.

(b) The appropriate officers of the Company shall execute and deliver, and the Transfer Agent shall countersign a new Certificate in place of any Certificate previously issued if the Record Holder of the Certificate:

(i) makes proof by affidavit, in form and substance satisfactory to the Company, that a previously issued Certificate has been lost, destroyed or stolen;

(ii) requests the issuance of a new Certificate before the Company has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

(iii) if requested by the Company, delivers to the Company a bond, in form and substance satisfactory to the Company, with surety or sureties and with fixed or open penalty as the Company may direct to indemnify the Company and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

(iv) satisfies any other reasonable requirements imposed by the Company.

(c) If a Member fails to notify the Company within a reasonable period of time after such Member has notice of the loss, destruction or theft of a Certificate, and a transfer of the Company Interests represented by the Certificate is registered before the Company, the Company or the Transfer Agent receives such notification, to the fullest extent permitted by law, the Member shall be precluded from making any claim against the Company or the Transfer Agent for such transfer or for a new Certificate.

(d) As a condition to the issuance of any new Certificate under this Section 4.2, the Company may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3. Record Holders.

The Company shall be entitled to recognize the Record Holder as the owner of any Company Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Company Interest on the part of any other Person, regardless of whether the Company shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Company Interests are listed or admitted for trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Company Interests, as between the Company on the one hand, and such other Persons on the other, such representative Person shall be (a) the Record Holder of such Company Interest and (b) bound by this Agreement and shall have the rights and obligations of a Member hereunder as, and to the extent, provided herein.

Section 4.4. Transfer Generally.

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another Person who is or becomes a Member, and includes a sale, assignment, gift, exchange or any other disposition, excluding a pledge, encumbrance, hypothecation or mortgage but including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage.

(b) No Company Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Company Interest not made in accordance with this Article IV shall be null and void.

Section 4.5. Registration and Transfer of Company Interests.

(a) The Company shall keep or cause to be kept on behalf of the Company a register in which, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), the Company will provide for the registration and transfer of Company Interests. The Company shall not recognize transfers of Certificates evidencing Company Interests unless such transfers are effected in the manner described in this Section 4.5.

(b) The Company shall not recognize any transfer of Company Interests evidenced by Certificates until the Certificates evidencing such Company Interests are surrendered for registration of transfer. No charge shall be imposed by the Company for such transfer; provided that, as a condition to the issuance of any new Certificate under this Section 4.5, the Company may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto. Upon surrender of a Certificate for registration of transfer of any Company Interests evidenced by a Certificate, and subject to the provisions of this Section 4.5(b), the appropriate officers of the Company shall execute and deliver, and in the case of Certificates evidencing Company Interests for which a Transfer Agent has been appointed, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Company Interests as was evidenced by the Certificate so surrendered.

(c) Upon the receipt of proper transfer instructions from the registered owner of uncertificated Company Interests, such uncertificated Company Interests shall be cancelled, issuance of new equivalent uncertificated Company Interests or Certificates shall be made to the holder of the Company Interests entitled thereto and the transaction shall be recorded upon the Company’s register.

(d) By acceptance of the transfer of any Company Interests in accordance with this Section 4.5, and except as provided in Section 4.7, each transferee of a Company Interest (including any nominee holder or an agent or representative acquiring such Company Interests for the account of another Person) (i) shall be admitted to the Company as a Member with respect to the Company Interests so transferred to such Person when any such transfer or admission is reflected in the books and records of the Company and such Member becomes the Record Holder of the Company Interests so transferred, (ii) shall become bound, and shall be deemed to have agreed to be bound, by the terms of this Agreement, (iii) represents that the transferee has the capacity, power and authority to enter into this Agreement, and (iv) makes the consents, acknowledgements and waivers contained in this Agreement, all with or without execution of this Agreement by such Person. The transfer of any Company Interests and the admission of any new Member shall not constitute an amendment to this Agreement.

(e) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.6, (iv) with respect to any class or series of Company Interests, the provisions of any statement of designations or amendment to this Agreement establishing such class or series, (v) any contractual provisions binding on any Member and (vi) provisions of applicable law including the Securities Act, Company Interests shall be freely transferable.

 

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Section 4.6. Restrictions on Transfers.

(a) Except as provided in Section 4.6(c), notwithstanding the other provisions of this Article IV, no transfer of any Company Interests shall be made if such transfer would (i) violate the then applicable federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer, (ii) terminate the existence or qualification of the Company under the laws of the jurisdiction of its formation or (iii) cause the Company to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already so treated or taxed).

(b) The Company may impose restrictions on the transfer of Company Interests if it receives an Opinion of Counsel that such restrictions are necessary or advisable to (i) avoid a significant risk of the Company becoming taxable as a corporation or otherwise becoming taxable as an entity for U.S. federal income tax purposes or (ii) preserve the uniformity of the Company Interests (or any class or series thereof). The Company may impose such restrictions by amending this Agreement; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Company Interests on the principal National Securities Exchange on which such class of Company Interests is then listed or admitted for trading must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Company Interests of such class.

(c) Nothing contained in this Article IV or elsewhere in this Agreement shall preclude the settlement of any transactions involving Company Interests entered into through the facilities of any National Securities Exchange on which such Company Interests are listed or admitted for trading.

(d) In the event that any Company Interest is evidenced in certificated form, each such certificate shall bear a conspicuous legend in substantially the following form:

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF ATLAS ENERGY GROUP, LLC THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF ATLAS ENERGY GROUP, LLC UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE ATLAS ENERGY GROUP, LLC TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR U.S. FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). THE BOARD OF DIRECTORS OF ATLAS ENERGY GROUP, LLC, MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY OR ADVISABLE TO AVOID A SIGNIFICANT RISK OF ATLAS ENERGY GROUP, LLC BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR U.S. FEDERAL INCOME TAX PURPOSES OR TO PRESERVE THE UNIFORMITY OF THE COMPANY INTERESTS (OR ANY CLASS OR SERIES THEREOF). THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED FOR TRADING.

 

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Section 4.7. Eligibility Certificates; Ineligible Holders.

(a) If at any time the Board of Directors determines, with the advice of counsel, that:

(i) the Company’s status other than as an association taxable as a corporation for U.S. federal income tax purposes or the failure of the Company otherwise to be subject to an entity-level tax for U.S. federal, state or local income tax purposes, coupled with the tax status (or lack of proof of the U.S. federal income tax status) of one or more Members, has or will reasonably likely have a material adverse effect on the maximum applicable rate that can be charged to customers by Subsidiaries of the Company (a “Rate Eligibility Trigger”); or

(ii) any Group Member is subject to any federal, state or local law or regulation that would create a substantial risk of cancellation or forfeiture of any property in which the Group Member has an interest based on the nationality, citizenship or other related status of a Member (a “Citizenship Eligibility Trigger”);

then, in each of cases (i) and (ii), the Board of Directors may adopt such amendments to this Agreement as it determines to be necessary or advisable to (A) in the case of a Rate Eligibility Trigger, obtain such proof of the U.S. federal income tax status of the Members and, to the extent relevant, their beneficial owners, as the Board of Directors determines to be necessary or advisable to establish those Members whose U.S. federal income tax status does not or would not have a material adverse effect on the maximum applicable rate that can be charged to customers by any Group Member or (B) in the case of a Citizenship Eligibility Trigger, obtain such proof of the nationality, citizenship or other related status of the Member (or, if the Member is a nominee holding for the account of another Person, the nationality, citizenship or other related status of such Person) as the Board of Directors determines to be necessary or advisable to establish those Members whose status as Members does not or would not subject any Group Member to a significant risk of cancellation or forfeiture of any of its properties or interests therein.

(b) Such amendments may include provisions requiring all Members to certify as to their (and their beneficial owners’) status as Eligible Holders upon demand and on a regular basis, as determined by the Board of Directors, and may require transferees of Units to so certify prior to being admitted to the Company as a Member (any such required certificate, an “Eligibility Certificate”).

(c) Such amendments may provide that any Member (and its beneficial owners) who fails to furnish to the Company, within a reasonable period after a request, an Eligibility Certificate and any other information and proof of its (and its beneficial owners’) status as an Eligible Holder, or if upon receipt of such Eligibility Certificate or other requested information the Board of Directors determines that a Member is not an Eligible Holder (such a Member, an “Ineligible Holder”), the Company Interests owned by such Member shall be subject to redemption in accordance with the provisions of Section 4.8. In addition, the Company shall be substituted for any Member that is an Ineligible Holder as the Member in respect of the Ineligible Holder’s Company Interests.

(d) The Company shall, in exercising voting rights in respect of Company Interests held by it on behalf of Ineligible Holders, distribute the votes in the same ratios or for the same candidates for election as Directors as the votes of Members in respect of Company Interests other than those of Ineligible Holders are cast, either for, against or abstaining as to the matter.

(e) Upon dissolution of the Company, an Ineligible Holder shall have no right to receive a distribution in kind pursuant to Section 11.3 but shall be entitled to the cash equivalent thereof, and the Company shall provide cash in exchange for an assignment of the Ineligible Holder’s share of any distribution in kind. Such payment and assignment shall be treated for Company purposes as a purchase by the Company from the Ineligible Holder of its Company Interests (representing the right to receive its share of such distribution in kind).

 

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(f) At any time after a holder can and does certify that it has become an Eligible Holder, an Ineligible Holder may, upon application to the Board of Directors, request that with respect to any Company Interests of such Ineligible Holder not redeemed pursuant to Section 4.8, such Ineligible Holder, upon approval of the Board of Directors, shall no longer constitute an Ineligible Holder, and the Company shall cease to be deemed to be the Member in respect of such Ineligible Holder’s Company Interests.

Section 4.8. Redemption of Company Interests of Ineligible Holders.

(a) If at any time a Member fails to furnish an Eligibility Certificate or any other information requested within the period of time specified in amendments adopted pursuant to Section 4.7, or if upon receipt of such Eligibility Certificate or other information the Board of Directors determines, with the advice of counsel, that a Member is not an Eligible Holder, the Company may, unless the Member establishes to the satisfaction of the Board of Directors that such Member is an Eligible Holder or has transferred its Company Interests to a Person who is an Eligible Holder and who furnishes an Eligibility Certificate to the Board of Directors prior to the date fixed for redemption as provided below, redeem the Company Interests of such Member as follows:

(i) The Board of Directors shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Member, at its last address designated on the records of the Company or the Transfer Agent, as applicable, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon redemption of the Redeemable Interests (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender of the Certificate evidencing the Redeemable Interests) and that on and after the date fixed for redemption no further allocations or distributions to which the Member would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

(ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Company Interests of the class to be so redeemed multiplied by the number of Company Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the Board of Directors, in cash or by delivery of a promissory note of the Company in the principal amount of the redemption price, bearing interest at the rate of 5% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

(iii) The Member or his duly authorized representative shall be entitled to receive the payment for the Redeemable Interests at the place of payment specified in the notice of redemption on the redemption date (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender by or on behalf of the Member at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank).

(iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Company Interests.

(b) The provisions of this Section 4.8 shall also be applicable to Company Interests held by a Member as nominee of a Person determined to be an Ineligible Holder.

(c) Nothing in this Section 4.8 shall prevent the recipient of a notice of redemption from transferring its Company Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the Board of Directors shall withdraw the notice of redemption; provided the transferee of such Company Interest certifies to the satisfaction of the Board of Directors that it is an Eligible Holder. If the transferee fails to make such certification, such redemption shall be effected from the transferee on the original redemption date.

 

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ARTICLE V

CAPITAL CONTRIBUTIONS AND ISSUANCE OF COMPANY INTERESTS

Section 5.1. Organizational Contributions.

In connection with the formation of the Company under the Delaware Act, the Initial Member made an initial Capital Contribution to the Company in the amount of $1,000.00 in exchange for Company Interests representing a Percentage Interest of 100%, and was admitted as a Member of the Company.

Section 5.2. Additional Capital Contributions.

(a) Prior to the Closing Date, the Initial Member contributed to the Company, as a Capital Contribution, cash and ownership interest in the Transferred Assets (as defined in the Separation Agreement) and the Transferred Liabilities (as defined in the Separation Agreement), in exchange for Common Units so that, after such Capital Contribution, the Initial Member held                      Common Units, representing Company Interests with a Percentage Interest of 100%.

(b) No Member will be required by this Agreement to make any additional Capital Contribution to the Company.

Section 5.3. Interest and Withdrawal.

No interest on Capital Contributions shall be paid by the Company. No Member shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon liquidation of the Company may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Member shall have priority over any other Member either as to the return of Capital Contributions or as to profits, losses or distributions. Any such return shall be a compromise to which all Members agree within the meaning of Section 18-502(b) of the Delaware Act.

Section 5.4. Capital Accounts.

(a) The Company shall maintain for each Member (or a beneficial owner of Company Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Company in accordance with Section 6031(c) of the Code or any other method acceptable to the Board of Directors) owning a Company Interest a separate Capital Account with respect to such Company Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv) and the methodology set forth in Treasury Regulation Section 1.704-1(b)(2)(iv)(s). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made to the Company with respect to such Company Interest and (ii) all items of Company income and gain (including Simulated Gain and income and gain exempt from tax) computed in accordance with Section 5.4(b) and allocated with respect to such Company Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Company Interest and (y) all items of Company deduction and loss (including Simulated Depletion and Simulated Loss) computed in accordance with Section 5.4(b) and allocated with respect to such Company Interest pursuant to Section 6.1. In connection with the foregoing, the Board of Directors shall adopt the methodology set forth in the noncompensatory option regulations under Treasury Regulation Sections 1.704-1, 1.721-2 and 1.761-3, unless otherwise required by applicable law.

(b) For purposes of computing the amount of any item of income, gain, loss, deduction, Simulated Depletion, Simulated Gain or Simulated Loss to be allocated pursuant to Article VI and to be reflected in the Members’ Capital Accounts, the determination, recognition and classification of any such item shall be the same

 

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as its determination, recognition and classification for U.S. federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose); provided that:

(i) Solely for purposes of this Section 5.4, the Company shall be treated as owning directly its proportionate share (as determined by the Board of Directors based upon the provisions of the applicable governing, organizational or similar documents) of all property owned by (x) any other Group Member that is classified as a partnership for U.S. federal income tax purposes and (y) any other partnership, limited liability company, unincorporated business or other entity classified as a partnership for U.S. federal income tax purposes of which a Group Member is, directly or indirectly, a partner, member or other equity holder.

(ii) All fees and other expenses incurred by the Company to promote the sale of (or to sell) a Company Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Members pursuant to Section 6.1.

(iii) Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss shall be made without regard to any election under Section 754 of the Code that may be made by the Company and, as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for U.S. federal income tax purposes. To the extent an adjustment to the adjusted tax basis of any Company asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

(iv) Any income, gain, loss, Simulated Gain, Simulated Loss or deduction attributable to the taxable disposition of any Company property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Company’s Carrying Value with respect to such property as of such date.

(v) Any item of income of the Company that is described in Section 705(a)(1)(B) of the Code (with respect to items of income that are exempt from tax) shall be treated as an item of income for the purpose of this Section 5.4(b), and any item of expense of the Company that is described in Section 705(a)(2)(B) of the Code (with respect to expenditures that are not deductible and not chargeable to capital accounts) shall be treated as an item of deduction for the purpose of this Section 5.4(b), in each case without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for U.S. federal income tax purposes.

(vi) In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery, amortization or Simulated Depletion attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Company were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.4(d) to the Carrying Value of any Company property subject to depreciation, cost recovery, amortization or Simulated Depletion, any further deductions for such depreciation, cost recovery, amortization or Simulated Depletion attributable to such property shall be determined (A) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment and (B) using a rate of depreciation, cost recovery or amortization derived from the same method and useful life (or, if applicable, the remaining useful life) as is applied for U.S. federal income tax purposes; provided, however, that, if the asset has a zero adjusted basis for U.S. federal income tax purposes, depreciation, cost recovery or amortization deductions shall be determined using any method that the Board of Directors may adopt.

 

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(vii) The Gross Liability Value of each Liability of the Company described in Treasury Regulation Section 1.752-7(b)(3)(i) shall be adjusted at such times as provided in this Agreement for an adjustment to Carrying Values. The amount of any such adjustment shall be treated for purposes hereof as an item of loss (if the adjustment increases the Carrying Value of such Liability of the Company) or an item of gain (if the adjustment decreases the Carrying Value of such Liability of the Company).

(viii) If the Company’s adjusted basis in a depreciable or cost recovery property is reduced for U.S. federal income tax purposes pursuant to Section 50(c)(1) or (3) of the Code, the amount of such reduction shall, solely for purposes hereof, be deemed to be an additional depreciation or cost recovery deduction in the year such property is placed in service and shall be allocated among the Members pursuant to Section 6.1. Any restoration of such basis pursuant to Section 50(c)(2) of the Code shall, to the extent possible, be allocated in the same manner to the Members to whom such deemed deduction was allocated.

(c) A transferee of a Company Interest shall succeed to a pro rata portion of the Capital Account of the transferor relating to the Company Interest so transferred.

(d) (i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), on an issuance of additional Company Interests for cash or Contributed Property or the issuance of Company Interests as consideration for the provision of services, the Capital Account of all Members and the Carrying Value of each Company property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Company property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property for an amount equal to its fair market value immediately prior to such issuance; provided, however, that in the event of an issuance of Company Interests for a de minimis amount of cash or Contributed Property, or in the event of an issuance of a de minimis amount of Company Interests as consideration for the provision of services, the Board of Directors may determine that such adjustments are unnecessary for the proper administration of the Company. In determining such Unrealized Gain or Unrealized Loss for purposes of maintaining Capital Accounts, the aggregate fair market value of all Company property (including cash or cash equivalents) immediately prior to the issuance of additional Company Interests shall be determined by the Board of Directors using such method of valuation as it may adopt. The Board of Directors shall allocate such aggregate value among the assets of the Company (in such manner as it determines) to arrive at a fair market value for individual properties.

(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Member of any Company property (other than a distribution of cash that is not in redemption or retirement of a Company Interest), the Capital Accounts of all Members and the Carrying Value of all Company property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Company property, as if such Unrealized Gain or Unrealized Loss had been recognized in a sale of such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated among the Members, at such time, pursuant to Section 6.1 in the same manner as any item of gain, loss, Simulated Gain or Simulated Loss actually recognized during such period would have been allocated; provided, however, that in the event of a distribution of a de minimis amount of Company property, the Board of Directors may determine that such adjustments are unnecessary for the proper administration of the Company. In determining such Unrealized Gain or Unrealized Loss for purposes of maintaining Capital Accounts, the aggregate fair market value of all Company assets (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 11.3 or in the case of a deemed distribution, be determined in the same manner as that provided in Section 5.4(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 11.3, be determined and allocated by the Liquidator using such method of valuation as it may adopt.

 

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Section 5.5. Issuances of Additional Company Interests.

(a) The Company may issue additional Company Interests and options, rights, warrants and appreciation rights relating to the Company Interests for any Company purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the Board of Directors shall determine, all without the approval of any Members.

(b) Each additional Company Interest authorized to be issued by the Company pursuant to Section 5.5(a) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of Company Interests), as shall be fixed by the Board of Directors, including (i) the right to share in Company profits and losses or items thereof; (ii) the right to share in Company distributions; (iii) the rights upon dissolution and liquidation of the Company; (iv) whether, and the terms and conditions upon which, the Company may or shall be required to redeem the Company Interest (including sinking fund provisions); (v) whether such Company Interest is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Company Interest will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Company Interest; and (viii) the right, if any, of each such Company Interest to vote on Company matters, including matters relating to the relative designations, preferences, rights, powers and duties of such Company Interest.

(c) The Board of Directors is hereby authorized and directed to take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Company Interests and options, rights, warrants and appreciation rights relating to Company Interests pursuant to this Section 5.5, (ii) the admission of additional Members and (iii) all additional issuances of Company Interests. The Board of Directors shall determine the relative rights, powers and duties of the holders of the Units or other Company Interests being so issued. The Board of Directors shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Company Interests, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Company Interests are listed or admitted for trading.

(d) No fractional Units shall be issued by the Company. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units (but for this Section 5.5(d)), each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).

Section 5.6. No Preemptive Right.

Except as may be provided in a separate agreement executed by the Company, no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Company Interest, whether unissued, held in the treasury or hereafter created.

Section 5.7. Splits and Combinations.

(a) Subject to Section 5.5(d), the Company may make a Pro Rata distribution of Company Interests to all Record Holders or may effect a subdivision or combination of Company Interests so long as, after any such event, each Member shall have the same Percentage Interest in the Company as before such event, and any amounts calculated on a per Unit basis or stated as a number of Units are proportionately adjusted.

(b) Whenever such a distribution, subdivision or combination of Company Interests is declared, the Board of Directors shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a

 

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date not less than 10 days prior to the date of such notice. The Board of Directors also may cause a firm of independent public accountants selected by it to calculate the number of Company Interests to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The Board of Directors shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

(c) Promptly following any such distribution, subdivision or combination, the Company may issue Certificates or uncertificated Company Interests to the Record Holders of Company Interests as of the applicable Record Date representing the new number of Company Interests held by such Record Holders, or the Board of Directors may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Company Interests Outstanding, and a Company Interest is represented by a Certificate, then the Company shall require, as a condition to the delivery to a Record Holder of such new Certificate, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

Section 5.8. Fully Paid and Non-Assessable Nature of Company Interests.

All Company Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Company Interests in the Company, except as such non assessability may be affected by Section 18-607 or 18-804 of the Delaware Act.

ARTICLE VI

ALLOCATIONS AND DISTRIBUTIONS

Section 6.1. Allocations for Capital Account Purposes.

For purposes of maintaining the Capital Accounts and in determining the rights of the Members among themselves, the Company’s items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss (computed in accordance with Section 5.4(b)) shall be allocated among the Members in each taxable year (or portion thereof) as provided herein below.

(a) Net Income. After giving effect to the special allocations set forth in Section 6.1(d), and any allocations to other Company Interests, Net Income for each taxable year and all items of income, gain, loss, deduction and Simulated Gain taken into account in computing Net Income for such taxable year shall be allocated to the Members in accordance with their respective Percentage Interests.

(b) Net Losses. After giving effect to the special allocations set forth in Section 6.1(d), and any allocations to other Company Interests, Net Losses for each taxable period and all items of income, gain, loss, deduction and Simulated Gain taken into account in computing Net Losses for such taxable period shall be allocated to the Members in accordance with their respective Percentage Interests; provided that Net Losses shall not be allocated pursuant to this Section 6.1(b) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account); instead, any such Net Losses shall be allocated to Members with positive Adjusted Capital Account balances in accordance with their Percentage Interests until such positive Adjusted Capital Accounts are reduced to zero.

(c) Net Termination Gains and Losses. After giving effect to the special allocations set forth in Section 6.1(d), all items of income, gain, loss, deduction and Simulated Gain taken into account in computing Net Termination Gain or Net Termination Loss for such taxable period shall be allocated in the same manner as such Net Termination Gain or Net Termination Loss is allocated hereunder. All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided

 

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under this Section 6.1 and after all distributions of Available Cash provided under Section 6.3 have been made; provided, however, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 11.3.

(i) If a Net Termination Gain is recognized (or deemed recognized pursuant to Section 5.4(d)), such Net Termination Gain shall be allocated among the Members in the following manner (and the Capital Accounts of the Members shall be increased by the amount so allocated in each of the following subclauses, in the order listed, before an allocation is made pursuant to the next succeeding subclause):

(A) First, to each Member having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all Members, until each such Member has been allocated Net Termination Gain equal to any such deficit balance in its Capital Account; and

(B) Second, 100% to all Members in accordance with their Percentage Interests;

(ii) If a Net Termination Loss is recognized (or deemed recognized pursuant to Section 5.4(d)), such Net Termination Loss shall be allocated 100% to all Members holding Common Units, Pro Rata, until the Capital Account in respect of each Unit then Outstanding has been reduced to zero.

(d) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:

(i) Company Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Company Minimum Gain during any Company taxable period, each Member shall be allocated items of Company income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(d), each Member’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain or Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to Sections 6.1(d)(v) and 6.1(d)(vi)). This Section 6.1(d)(i) is intended to comply with the Company Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

(ii) Chargeback of Member Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Member Nonrecourse Debt Minimum Gain during any Company taxable period, any Member with a share of Member Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Company income, gain or Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(d), each Member’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain or Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d), other than Section 6.1(d)(i) and other than an allocation pursuant to Sections 6.1(d)(v) and 6.1(d)(vi), with respect to such taxable period. This Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

(iii) Qualified Income Offset. In the event any Member unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Section 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5) or 1.704-1(b)(2)(ii)(d)(6), items of Company income and gain shall be specially allocated to such Member in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in

 

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its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible unless such deficit balance is otherwise eliminated pursuant to Section 6.1(d)(i) or (ii).

(iv) Gross Income Allocations. In the event any Member has a deficit balance in its Capital Account at the end of any Company taxable period in excess of the sum of (A) the amount such Member is required to restore pursuant to the provisions of this Agreement and (B) the amount such Member is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Member shall be specially allocated items of Company gross income, gain and Simulated Gain in the amount of such excess as quickly as possible; provided that an allocation pursuant to this Section 6.1(d)(iv) shall be made only if and to the extent that such Member would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(iv) were not in this Agreement.

(v) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Members in accordance with their respective Percentage Interests. If the Board of Directors determines that the Company’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the Board of Directors is authorized, upon notice to the Members, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

(vi) Member Nonrecourse Deductions. Member Nonrecourse Deductions for any taxable period shall be allocated 100% to the Member that bears the Economic Risk of Loss with respect to the Member Nonrecourse Debt to which such Member Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Member bears the Economic Risk of Loss with respect to a Member Nonrecourse Debt, such Member Nonrecourse Deductions attributable thereto shall be allocated between or among such Members in accordance with the ratios in which they share such Economic Risk of Loss.

(vii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Members agree that Nonrecourse Liabilities of the Company in excess of the sum of (A) the amount of Company Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Member in accordance with their respective Percentage Interests.

(viii) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Company asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain or Simulated Gain (if the adjustment increases the basis of the asset) or loss or Simulated Loss (if the adjustment decreases such basis), and such item of gain or loss, Simulated Gain or Simulated Loss shall be specially allocated to the Members in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

(ix) Curative Allocation.

(A) Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss allocated to each Member pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Member under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1. Notwithstanding the preceding sentence, Required Allocations relating to (1) Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Company Minimum Gain and (2) Member Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Member Nonrecourse Debt Minimum Gain. Allocations pursuant to this Section 6.1(d)(ix)(A) shall only be

 

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made with respect to Required Allocations to the extent the Board of Directors determines that such allocations will otherwise be inconsistent with the economic agreement among the Members. Further, allocations pursuant to this Section 6.1(d)(ix)(A) shall be deferred with respect to allocations pursuant to clauses (1) and (2) hereof to the extent the Board of Directors determines that such allocations are likely to be offset by subsequent Required Allocations.

(B) The Board of Directors shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(d)(ix)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(ix)(A) among the Members in a manner that is likely to minimize such economic distortions.

(x) Corrective Allocations. In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:

(A) In the case of any negative adjustments to the Capital Accounts of the Members resulting from a Book-Down Event or from the recognition of a Net Termination Loss, such negative adjustment (1) shall first be allocated, to the extent of the Aggregate Remaining Net Positive Adjustments, in such a manner, as determined by the Board of Directors, that to the extent possible the aggregate Capital Accounts of the Members will equal the amount that would have been the Capital Account balance of the Members if no prior Book-Up Events had occurred, and (2) any negative adjustment in excess of the Aggregate Remaining Net Positive Adjustments shall be allocated pursuant to Section 6.1(c) hereof.

(B) In making the allocations required under this Section 6.1(d)(x), the Board of Directors may apply whatever conventions or other methodology it determines will satisfy the purpose of this Section 6.1(d)(x).

(e) Simulated Depletion and Simulated Loss.

(i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(k), Simulated Depletion with respect to each oil and gas property shall be allocated among the Unitholders Pro Rata.

(ii) Simulated Loss with respect to the disposition of an oil and gas property shall be allocated among the Members in proportion to their allocable share of total amount realized from such disposition under Section 6.2(c)(i).

Section 6.2. Allocations for Tax Purposes.

(a) Except as otherwise provided herein, for U.S. federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Members in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Section 6.1.

(b) The deduction for depletion with respect to each separate oil and gas property (as defined in Section 614 of the Code) shall be computed for U.S. federal income tax purposes separately by the Members rather than by the Company in accordance with Section 613A(c)(7)(D) of the Code. Except as provided in Section 6.2(c)(iii), for purposes of such computation (before taking into account any adjustments resulting from an election made by the Company under Section 754 of the Code), the adjusted tax basis of each oil and gas property (as defined in Section 614 of the Code) shall be allocated among the Members Pro Rata. Each Member shall separately keep records of his share of the adjusted tax basis in each oil and gas property, allocated as provided above, adjust such share of the adjusted tax basis for any cost or percentage depletion allowable with respect to such property, and use such adjusted tax basis in the computation of its cost depletion or in the computation of his gain or loss on the disposition of such property by the Company.

 

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(c) Except as provided in Section 6.2(c)(iii), for the purposes of the separate computation of gain or loss by each Member on the sale or disposition of each separate oil and gas property (as defined in Section 614 of the Code), the Company’s allocable share of the “amount realized” (as such term is defined in Section 1001(b) of the Code) from such sale or disposition shall be allocated for U.S. federal income tax purposes among the Members as follows:

(i) first, to the extent such amount realized constitutes a recovery of the Simulated Basis of the property, to the Members in the same proportion as the depletable basis of such property was allocated to the Members pursuant to Section 6.2(b) (without regard to any special allocation of basis under Section 6.2(c)(iii)).

(ii) second, the remainder of such amount realized, if any, to the Members so that, to the maximum extent possible, the amount realized allocated to each Member under this Section 6.2(c)(ii) will equal such Member’s share of the Simulated Gain recognized by the Company from such sale or disposition.

(iii) The Members recognize that with respect to Contributed Property and Adjusted Property there will be a difference between the Carrying Value of such property at the time of contribution or revaluation, as the case may be, and the adjusted tax basis of such property at that time. All items of tax depreciation, cost recovery, amortization, adjusted tax basis of depletable properties, amount realized and gain or loss with respect to such Contributed Property and Adjusted Property shall be allocated among the Members to take into account the disparities between the Carrying Values and the adjusted tax basis with respect to such properties in accordance with the principles of Treasury Regulation Section 1.704-3(d).

(d) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property other than an oil and gas property pursuant to Section 6.2(c), items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for U.S. federal income tax purposes among the Members as follows:

(i) (A) In the case of a Contributed Property, such items attributable thereto shall be allocated among the Members in the manner provided under Section 704(c) of the Code that takes into account the variation between the Agreed Value of such property and its adjusted basis at the time of contribution; and (B) any item of Residual Gain or Residual Loss attributable to a Contributed Property shall be allocated among the Members in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

(ii) (A) In the case of an Adjusted Property, such items shall (1) first, be allocated among the Members in a manner consistent with the principles of Section 704(c) of the Code to take into account the Unrealized Gain or Unrealized Loss attributable to such property and the allocations thereof pursuant to Section 5.4(d)(i) or 5.4(d)(ii); and (2) second, in the event such property was originally a Contributed Property, be allocated among the Members in a manner consistent with Section 6.2(d)(i)(A); and (B) any item of Residual Gain or Residual Loss attributable to an Adjusted Property shall be allocated among the Members in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

(iii) The Board of Directors shall apply the principles of Treasury Regulation Section 1.704-3(d) to eliminate Book-Tax Disparities.

(e) For the proper administration of the Company and for the preservation of uniformity of the Company Interests (or any class or classes thereof), the Board of Directors shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations for U.S. federal income tax purposes of income (including gross income) or deductions; and (iii) amend the provisions of this Agreement as appropriate (A) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (B) otherwise to

 

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preserve or achieve uniformity of the Company Interests (or any class or classes thereof). The Board of Directors may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.2(e) only if such conventions, allocations or amendments would not have a material adverse effect on the Members, the holders of any class or classes of Company Interests issued and Outstanding or the Company, and if such allocations are consistent with the principles of Section 704 of the Code.

(f) The Board of Directors may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the Company’s common basis of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-1(a)(6), Treasury Regulation Section 1.197-2(g)(3) or any successor regulations thereto. If the Board of Directors determines that such reporting position cannot reasonably be taken, the Board of Directors may adopt depreciation and amortization conventions under which all purchasers acquiring Company Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Company’s property. If the Board of Directors chooses not to utilize such aggregate method, the Board of Directors may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Company Interests, so long as such conventions would not have a material adverse effect on the Members or the Record Holders of any class or classes of Company Interests.

(g) In accordance with Treasury Regulation Sections 1.1245-1(e) and 1.1250-1(f), any gain allocated to the Members upon the sale or other taxable disposition of any Company asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Members (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

(h) All items of income, gain, loss, deduction and credit recognized by the Company for U.S. federal income tax purposes and allocated to the Members in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code which may be made by the Company; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the Board of Directors) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

(i) Each item of Company income, gain, loss and deduction shall, for U.S. federal income tax purposes, be determined on an annual basis and prorated on a monthly basis and shall be allocated to the Members as of the opening of the National Securities Exchange on which the Company Interests are listed or admitted for trading on the first Business Day of each month; provided, however, that gain or loss on a sale or other disposition of any assets of the Company or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by the Board of Directors in its sole discretion, shall be allocated to the Members as of the opening of the National Securities Exchange on which the Company Interests are listed or admitted for trading on the first Business Day of the month in which such gain or loss is recognized for U.S. federal income tax purposes. The Board of Directors may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

(j) Allocations that would otherwise be made to a Member under the provisions of this Article VI shall instead be made to the beneficial owner of Company Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Company in accordance with Section 6031(c) of the Code or any other method determined by the Board of Directors.

(k) If Capital Account balances are reallocated between the Members in accordance with Section 5.4(d)(i) hereof and Proposed Treasury Regulation Section 1.704-1(b)(2)(iv)(s)(4), beginning with the year of reallocation and continuing until the allocations required are fully taken into account, the Company shall

 

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make corrective allocations (allocations of items of gross income or gain or loss or deduction for federal income tax purposes that do not have a corresponding book allocation) to take into account the Capital Account reallocation, as provided in Proposed Treasury Regulation Section 1.704-1(b)(4)(x).

Section 6.3. Requirement of Distributions; Distributions to Record Holders.

(a) Except as described in Section 6.3(b), within 50 days following the end of each Distribution Period (or if such 50th day is not a Business Day, then the Business Day immediately following such 50th day) commencing with the Distribution Period ending on                     , an amount equal to 100% of Available Cash with respect to such Distribution Period shall, subject to Section 18-607 of the Delaware Act, be distributed in accordance with this Article VI by the Company to the Members in accordance with their respective Percentage Interests as of the Record Date selected by the Board of Directors. All distributions required to be made under this Agreement shall be made subject to Section 18-607 and 18-804 of the Delaware Act.

(b) Notwithstanding Section 6.3(a), in the event of the dissolution and liquidation of the Company, all cash received during or after the Distribution Period in which the Liquidation Date occurs shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 11.3.

(c) The Board of Directors may treat taxes paid by the Company on behalf of, or amounts withheld with respect to, all or less than all of the Members, as a distribution of Available Cash to such Members, as determined by the Board of Directors.

(d) Each distribution in respect of a Company Interest shall be paid by the Company, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Company Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Company’s Liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

ARTICLE VII

MANAGEMENT AND OPERATION OF BUSINESS

Section 7.1. Management.

(a) Except as otherwise expressly provided in this Agreement, the business and affairs of the Company shall be managed by or under the direction of a Board of Directors (the “Board of Directors”). The Directors shall constitute “managers” within the meaning of the Delaware Act. The Board of Directors shall have the power and authority to delegate to one or more other Persons the Board of Director’s rights and power to manage and control the business and affairs, or any portion thereof, of the Company, including to delegate to Officers, agents and employees of the Company and its Subsidiaries or any other Person, except as prohibited by applicable law, and may authorize the Company, any Director, Officer, agent, employee or any other Person to enter into any document on behalf of the Company and perform the obligations of the Company thereunder, except as prohibited by applicable law. No Member, by virtue of its status as such, shall have any management power over the business and affairs of the Company or actual or apparent authority to enter into, execute or deliver contracts on behalf of, or to otherwise bind, the Company. In addition to the powers now or hereafter granted to managers under the Delaware Act or that are granted to the Board of Directors under any other provision of this Agreement, the Board of Directors shall, subject to the other terms of this Agreement, have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Company, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

(i) the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible or exchangeable into Company Interests, and the incurring of any other obligations;

 

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(ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Company;

(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Company or the merger or other combination of the Company with or into another Person;

(iv) the use of the assets of the Company (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of operations, including operations of any Group Member; the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations and the making of capital contributions;

(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the Liability of the Company under contractual arrangements to all or particular assets of the Company);

(vi) the distribution of Company cash;

(vii) the selection, employment, retention and dismissal of employees (including employees having titles such as “president,” “vice president,” “secretary” and “treasurer”) and agents, internal and outside attorneys, accountants, consultants and contractors of Company or any Group Member and the determination of their compensation and other terms of employment or hiring and the creation and operation of employee benefit plans, employee programs and employee practices;

(viii) the maintenance of insurance for the benefit of the Company Group, the Members and the Indemnitees;

(ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other Persons (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time);

(x) the control of any matters affecting the rights and obligations of the Company, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expenses and the settlement of claims and litigation;

(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

(xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Company Interests from, or requesting that trading be suspended on, any such National Securities Exchange;

(xiii) the purchase, sale or other acquisition or disposition of Company Interests, or the issuance of options, rights, warrants, appreciation rights and tracking and phantom interests relating to Company Interests;

(xiv) the undertaking of any action in connection with the Company’s participation in any Group Member;

(xv) the entering into of agreements with any of its Affiliates to render services to a Group Member; and

(xvi) the approval and authorization of any action taken by the Company or a Subsidiary that is the general partner or managing member of another Subsidiary to limit or modify the incentive distribution rights, if any, held by the Company or such general partner or managing member, if the Board of Directors determines that such limitation or modification does not adversely affect the Members (including any particular class of Company Interests as compared to other classes of Company Interests) in any material respect.

 

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(b) Board of Directors.

(i) The number of Directors that shall constitute the whole Board of Directors shall be fixed from time to time exclusively pursuant to a resolution adopted by a majority of the Board of Directors. No decrease in the number of authorized directors constituting the Board of Directors shall shorten the term of any incumbent director.

(ii) The Directors shall be divided, with respect to the time for which they severally hold office, into three classes, as nearly equal in number as is reasonably possible, with the term of office of the first class to expire at the 2016 annual meeting of the Members, the term of office of the second class to expire at the 2017 annual meeting of the Members and the term of office of the third class to expire at the 2018 annual meeting of the Members, with each Director to hold office until his or her successor shall have been duly elected and qualified. At each annual meeting of the Members, commencing with the 2016 annual meeting, (A) Directors elected to succeed those Directors whose terms then expire shall be elected for a term of office to expire at the third succeeding annual meeting of the Members after their election, with each Director to hold office until his or her successor shall have been duly elected and qualified, and (B) if authorized by a resolution of the Board of Directors, Directors may be elected to fill any vacancy on the Board of Directors, regardless of how such vacancy shall have been created.

(iii) Each Director shall hold office for the term for which such Director is elected and thereafter until such Director’s successor shall have been duly elected and qualified, or until such Director’s earlier death, resignation or removal. Any vacancies may be filled, until the next annual meeting, by a majority of the remaining Directors then in office. A Director may be removed only for cause and only upon a vote of the majority of the remaining Directors then in office. Any Director may resign at any time by giving written notice of such Director’s resignation to the Board of Directors. Any such resignation shall take effect at the time the Board receives such notice or at any later effective time specified in such notice. Unless otherwise specified in such notice, the acceptance by the Board of such Director’s resignation shall not be necessary to make such resignation effective.

(iv) Sections 7.1(b)(i), 7.1(b)(ii) and 7.1(b)(iii) may not be amended except upon the prior approval of Members that hold 80% of the Outstanding Voting Units.

(v) Directors need not be Members. The Board of Directors may, from time to time, and by the adoption of resolutions, establish qualifications for Directors.

(vi) The Chairman of the Board, if any, shall be chosen from among the Directors by a vote of the Directors. The Chairman of the Board shall preside, if present, at all meetings of the Board of Directors and the Members and shall perform such additional functions and duties as the Board of Directors may prescribe from time to time. The Directors may also elect a Vice Chairman of the Board to act in the place of the Chairman of the Board upon his or her absence or disability, or in the event that it is impractical for the Chairman of the Board to act personally.

(vii) The Directors shall not be obligated and shall not be expected to devote all of their time or business efforts to the affairs of the Company in their capacity as Directors.

(viii) Regular quarterly meetings of the Board of Directors shall be held at such time and place as shall be designated from time to time by resolution of the Board of Directors. Notice of such regular quarterly meetings shall not be required. A special meeting of the Board of Directors may be called at any time at the request of the Chairman of the Board or a majority of the Directors then in office.

(ix) Oral or written notice of all special meetings of the Board of Directors must be given to all Directors at least twenty-four hours prior to such special meeting, or upon such shorter notice as may be approved by the Directors (or the members of such committee), which approval may be given before or after the relevant meeting to which the notice relates. All notices and other communications to be

 

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given to Directors shall be sufficiently given for all purposes hereunder if (a) in writing and delivered by hand, courier or overnight delivery service or three days after being mailed by certified or registered mail, return receipt requested, with appropriate postage prepaid, or (b) when received in the form of a telegram, as an attachment to an electronic mail message or facsimile, and shall be directed to the address, electronic mail address or facsimile number as such Director (or such member) shall designate by notice to the Company. Neither the business to be transacted at, nor the purpose of, any regular or special meeting of the Board of Directors need be specified in the notice of such meeting. A meeting may be held at any time without notice if all the Directors are present, and any Director may waive the requirement of such notice as to such Director.

(x) Any action required or permitted to be taken at any meeting of the Board of Directors or of any committee thereof may be taken without a meeting if all members of the Board of Directors or committee, as the case may be, consent thereto in writing or by electronic transmission, and the writing or writings or electronic transmission or transmissions are filed with the minutes of proceedings of the Board of Directors or committee. Such filing shall be in paper form if the minutes are maintained in paper form and shall be in electronic form if the minutes are maintained in electronic form.

(xi) Any meeting of the Board of Directors may be held in person or by conference telephone or similar communications equipment by means of which all persons participating in the meeting can hear each other, and such participation in a meeting shall constitute presence in person at such meeting.

(xii) A majority of all Directors, present in person or participating in accordance with Section 7.1(b)(viii), shall constitute a quorum for the transaction of business, but if at any meeting of the Board of Directors there shall be less than a quorum present, a majority of the Directors present may adjourn the meeting without further notice. Except as otherwise provided by the Delaware Act, applicable law or in this Agreement, the act of a majority of Directors present at a meeting at which a quorum is present shall be the act of the Board of Directors. The Directors present at a duly organized meeting may continue to transact business until adjournment, notwithstanding the withdrawal of enough Directors to leave less than a quorum.

(xiii) The Board of Directors may propose and adopt on behalf of the Company employee benefit plans, employee programs and employee practices, or cause the Company to issue Company Interests, or options, rights, warrants, appreciation rights or tracking and phantom interests relating to Company Interests, in connection with or pursuant to any employee benefit plan, employee program or employee practice maintained or sponsored by the Company, any Group Member or any Affiliate thereof, in each case for the benefit of employees of the Company, any Group Member or any Affiliate thereof, or any of them, in respect of services performed, directly or indirectly, for the benefit of any Group Member.

(xiv) The Board of Directors may establish one or more committees of the Board of Directors, which shall consist of one or more Directors, and may delegate any of its responsibilities to such committees, except as prohibited by the Delaware Act or otherwise by applicable law. A majority of any committee, present in person or participating in accordance with Section 7.1(b)(xi), shall constitute a quorum for the transaction of business of such committee. Except as otherwise provided by the Delaware Act, applicable law or in this Agreement, the act of a majority of committee members present at a meeting at which a quorum is present shall be the act of such committee. A majority of any committee may determine its action and fix the time and place of its meetings unless the Board of Directors shall otherwise provide. Notice of meetings shall be given to each member of the committee in the manner provided for in Section 7.1(b)(viii) or 7.1(b)(ix). The Board of Directors shall have the power at any time to fill vacancies in, to change the membership of, or to dissolve any committee.

(xv) Unless otherwise restricted by applicable law, the Board of Directors shall have the authority to fix the compensation of the Directors. The Directors may be paid their expenses, if any, of attendance at each meeting of the Board of Directors and may be paid a fixed sum for attendance at each meeting of the Board of Directors or paid a stated salary or other compensation as Director. No

 

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such payment shall preclude any Director from serving the Company in any other capacity and receiving compensation therefor. Members of special or standing committees may also be paid their expenses, if any, of and allowed compensation for attending committee meetings.

(c) This Agreement shall not be deemed in any way to limit or impair the ability of the Board of Directors to adopt a “poison pill” or unitholder or other similar rights plan with respect to the Company, whether such poison pill or plan contains “dead hand” provisions, “no hand” provisions or other provisions relating to the redemption of the poison pill or plan, in each case as such terms are used under Delaware common law.

(d) Notwithstanding any other provision of this Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Members and each other Person who may acquire an interest in Company Interests or is otherwise bound by this Agreement hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement and the Separation Agreement and the other agreements described in or filed as exhibits to the Registration Statement that are related to the transactions contemplated by the Registration Statement; (ii) agrees that the Board of Directors (on its own or through any Officer of the Company) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Company without any further act, approval or vote of the Members or the other Persons who may acquire an interest in Company Interests or is otherwise bound by this Agreement; and (iii) agrees that the execution, delivery or performance by the Company, any Group Member or any Affiliate of any of them, of this Agreement or any agreement authorized or permitted under this Agreement, shall not constitute a breach by the Board of Directors of any Officer of any duty that the Board of Directors or any Officer may owe the Company or the Members or any other Persons under this Agreement (or any other agreements) or of any duty existing at law, in equity or otherwise.

Section 7.2. Duties.

Except as expressly set forth in this Agreement, neither the Board of Directors nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Company, any Group Member or any Member, and the Members agree that the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the Board of Directors or any other Indemnitee otherwise existing at law or in equity, replace such other duties and liabilities of the Board of Directors or such other Indemnitee. The Members and any other Person who acquires an interest in a Company Interest or any other Person who is bound by this Agreement shall be deemed to have expressly approved this Section 7.2.

Section 7.3. Certificate of Formation.

The Certificate of Formation has been filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The Board of Directors shall use all reasonable efforts to cause to be filed such other certificates or documents that it determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited liability company in the State of Delaware or any other state in which the Company may elect to do business or own property. To the extent the Board of Directors determines such action to be necessary or appropriate, the Board of Directors shall direct the appropriate Officers to file amendments to and restatements of the Certificate of Formation and do all things to maintain the Company as a limited liability company under the laws of the State of Delaware or of any other state in which the Company may elect to do business or own property. Subject to the terms of Section 3.4(a), the Company shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Formation, any qualification document or any amendment thereto to any Member.

Section 7.4. Restrictions on the Board of Directors’ Authority.

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a series of related transactions, to a Person who is not a member of the Company Group, without the approval of the holders of a majority of the Outstanding Voting Units; provided, however, that this provision shall not preclude or limit the Board of Director’s ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Company Group and shall not apply to any forced sale of any or all of the assets of the Company Group pursuant to the foreclosure of, or other realization upon, any such encumbrance.

Section 7.5. Officers.

(a) The Board of Directors shall elect one or more persons to be officers of the Company (“Officers”) to assist in carrying out the Board of Directors’ decisions and the day-to-day activities of the Company. Officers are not “managers” as that term is used in the Delaware Act. Any individuals who are elected as Officers shall serve at the pleasure of the Board of Directors and shall have such titles and the authority and duties specified in this Agreement or otherwise delegated to each of them, respectively, by the Board of Directors from time to time. The salaries or other compensation, if any, of the Officers shall be fixed by the Board of Directors.

(b) The Officers may consist of a Chief Executive Officer, a President, one or more Vice Presidents, a Chief Operating Officer, a Chief Financial Officer, a Chief Legal Officer, a Secretary and such other Officers as the Board of Directors from time to time may deem proper, and the Officers may include an Executive Chairman of the Board and an Executive Vice Chairman of the Board. All Officers elected by the Board of Directors shall each have such powers and duties as generally pertain to their respective offices, subject to the specific provisions of this Section 7.5.

(c) Chief Executive Officer. The Chief Executive Officer, who may be the Chairman (or Vice Chairman) of the Board and/or the President, shall have general and active management authority over the business of the Company and shall see that all orders and resolutions of the Board of Directors are carried into effect. The Chief Executive Officer may sign deeds, mortgages, bonds, contracts or other instruments, except in cases where the signing and execution thereof shall be expressly delegated by the Board of Directors or by this Agreement to some other Officer or agent of the Company, or shall be required by law to be otherwise signed and executed. The Chief Executive Officer shall also perform all duties and have all powers incident to the office of Chief Executive Officer and perform such other duties and may exercise such other powers as may be assigned by this Agreement or prescribed by the Board of Directors from time to time.

(d) President. The President shall, subject to the control of the Board of Directors and the Chief Executive Officer, in general, supervise and control all of the business and affairs of the Company. The President may sign any deeds, mortgages, bonds, contracts or other instruments, except in cases where the signing and execution thereof shall be expressly delegated by the Board of Directors or by this Agreement to some other officer or agent of the Company, or shall be required by law to be otherwise signed and executed. The President shall perform all duties and have all powers incident to the office of President and perform such other duties and may exercise such other powers as may be delegated by the Chief Executive Officer or as may be prescribed by the Board of Directors from time to time.

(e) Vice Presidents. Any Executive Vice President, Senior Vice President and Vice President, in the order of seniority, unless otherwise determined by the Board of Directors, shall, in the absence or disability of the President, perform the duties and exercise the powers of the President. They shall also perform the usual and customary duties and have the powers that pertain to such office and generally assist the President by executing contracts and agreements and exercising such other powers and performing such other duties as are delegated to them by the Chief Executive Officer or President or as may be prescribed by the Board of Directors from time to time.

(f) Chief Financial Officer. The Chief Financial Officer shall perform all duties and have all powers incident to the office of the Chief Financial Officer and in general have overall supervision of the financial operations of the Company. The Chief Financial Officer shall receive and deposit all moneys and other valuables belonging to the Company in the name and to the credit of the Company and shall disburse the same and only in

 

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such manner as the Board of Directors or the appropriate Officer may from time to time determine. The Chief Financial Officer shall render to the Board of Directors, the Chief Executive Officer and the President, whenever any of them request it, an account of all his or her transactions as Chief Financial Officer and of the financial condition of the Company, and shall perform such other duties and may exercise such other powers as may be delegated by the Chief Executive Officer or President or as may be prescribed by the Board from time to time. The Chief Financial Officer shall have the same power as the President and Chief Executive Officer to execute documents on behalf of the Company.

(g) Chief Legal Officer. The Chief Legal Officer shall be the principal legal officer of the Company. The Chief Legal Officer shall have general direction of and supervision over the legal affairs of the Company and shall advise the Board of Directors and the officers of the Company on all legal matters. The Chief Legal Officer shall perform such other duties and may exercise such other powers as may be delegated by the Chief Executive Officer or President or as may be prescribed by the Board from time to time. The Chief Legal Officer shall have the same power as the President and Chief Executive Officer to execute documents on behalf of the Company.

(h) Secretary. The Secretary shall keep or cause to be kept, in one or more books provided for that purpose, the minutes of all meetings of the Board of Directors, the committees of the Board of Directors and the Company and of the Members. The Secretary shall see that all notices are duly given in accordance with the provisions of this Agreement and as required by Applicable Law; shall be custodian of the records and the seal of the Company (if any) and affix and attest the seal (if any) to all documents to be executed on behalf of the Company under its seal; and shall see that the books, reports, statements, certificates and other documents and records required by applicable law to be kept and filed are properly kept and filed; and in general, shall perform all duties and have all powers incident to the office of Secretary and perform such other duties and may exercise such other powers as may be delegated by the Chief Executive Officer or President or as may be prescribed by the Board of Directors from time to time.

(i) Other Officers and Agents. The Board of Directors may from time to time elect such other Officers or appoint such agents as may be necessary or desirable for the conduct of the business of the Company. Such other Officers and agents shall have such duties and shall hold their offices for such terms as shall be provided in this Agreement or as may be prescribed by the Board of Directors, as the case may be from time to time. The Chief Executive Officer may from time to time appoint one or more Assistant Secretaries or other Officers as may be necessary or desirable in the conduct of ministerial affairs of the Company, and such other Officers and agents appointed by the Chief Executive Officers shall have such ministerial duties and hold their offices for such terms as shall be prescribed by the Chief Executive Officer from time to time. The Board of Directors may from time to time delegate the powers or duties of any Officer to any other Officers or agents, notwithstanding any provision of this Section 7.5.

(j) Election and Term of Office. The Officers shall be elected from time to time by the Board of Directors and shall each hold office until such person’s successor shall have been duly elected and qualified or until such person’s death or until he or she shall resign or be removed pursuant to Section 7.5(k) (or, in the case of any Assistant Secretary or other Officer referred to in the third sentence of Section 7.5(i), be elected from time to time by the Board of Directors or the Chief Executive Officer). No Officer shall have any contractual rights against the Company for compensation by virtue of such election beyond the date of the election of such person’s successor, such person’s death, such person’s resignation or such person’s removal, whichever event shall first occur, except as otherwise provided in an employment contract or under an employee deferred compensation plan.

(k) Removal. Any Officer elected, or agent appointed, by the Board of Directors or the Chief Executive Officer may be removed, with or without cause, by the affirmative vote of a majority of the Board of Directors. No Officer shall have any contractual rights against the Company for compensation by virtue of such election beyond the date of the election of such person’s successor, such person’s death, such person’s resignation or such person’s removal, whichever event shall first occur, except as otherwise provided in an employment contract or under an employee deferred compensation plan.

 

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(l) Vacancies. A newly created elected office and a vacancy in any elected office because of death, resignation or removal may be filled by the Board of Directors for the unexpired portion of the term.

(m) Unless otherwise directed by the Board of Directors, the Chief Executive Officer, the President or any Officer of the Company authorized by the Chief Executive Officer shall have the power to vote and otherwise act on behalf of the Company, in person or by proxy, at any meeting of the members of or with respect to any action of equity holders of any other entity in which the Company may hold securities and otherwise to exercise any and all rights and powers which the Company may possess by reason of its ownership of securities in such other entities.

Section 7.6. Outside Activities.

(a) Each Unrestricted Person shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member. No such business interest or activity shall constitute a breach of this Agreement or any duty otherwise existing at law, in equity or otherwise or obligation of any type whatsoever, to the Company, any Group Member, any Member, any Person who acquires an interest in a Company Interest or other person who is bound by this Agreement. None of any Group Member, any Member or any other Person shall have any rights by virtue of this Agreement or the partnership relationship established hereby in any business ventures of any Unrestricted Person.

(b) Notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Unrestricted Person in accordance with the provisions of this Section 7.6 is hereby approved by the Company and all Members, (ii) it shall be deemed not to be a breach by the any Unrestricted Persons of this Agreement or any duty otherwise existing at law, in equity or otherwise or obligation of any type whatsoever, to the Company, any Group Member, any Member, any Person who acquires an interest in a Company Interest or other person who is bound by this Agreement for the Unrestricted Persons to engage in such business interests and activities in preference to or to the exclusion of the Company or any other Group Member and (iii) the Unrestricted Persons shall have no obligation hereunder or as a result of any duty otherwise existing at law, in equity or otherwise or obligation of any type whatsoever, to present business opportunities to the Company or any other Group Member. Notwithstanding anything to the contrary in this Agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Unrestricted Person. No Unrestricted Person who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Company, shall have any duty to communicate or offer such opportunity to the Company, and such Unrestricted Person shall not be liable to the Company, any Group Member, any Member, any Person who acquires an interest in a Company Interest or other person who is bound by this Agreement for breach of this Agreement or any duty otherwise existing at law, in equity or otherwise or obligation of any type whatsoever, by reason of the fact that such Unrestricted Person pursues or acquires for itself, directs such opportunity to another Person or does not communicate such opportunity or information to the Company.

(c) Notwithstanding anything to the contrary in this Agreement, to the extent that any provision of this Agreement purports or is interpreted to have the effect of restricting, modifying or eliminating any duty that might otherwise, as a result of the law of the State of Delaware or any other applicable law, be owed by the Board of Directors to the Company, any Group Member, any Member, any Person who acquires an interest in a Company Interest or other person who is bound by this Agreement, or to constitute a waiver or consent by the Company, any Group Member, any Member, any Person who acquires an interest in a Company Interest or other person who is bound by this Agreement, then in each case such provisions shall be deemed to have been approved by such Persons.

 

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Section 7.7. Loans or Contributions from the Company or Group Members.

(a) The Company may lend or contribute to any Group Member, and any Group Member may borrow from the Company, funds on terms and conditions determined by the Board of Directors.

(b) No borrowing by any Group Member or the approval thereof by the Board of Directors shall be deemed to constitute a breach of any duty hereunder or otherwise existing at law, in equity or otherwise, of the Board of Directors to the Company or the Members by reason of the fact that the purpose or effect of such borrowing is directly or indirectly to enable distributions to the Members.

Section 7.8. Indemnification.

(a) To the fullest extent permitted by law but subject to the limitations expressly provided in this Agreement, all Indemnitees shall be indemnified and held harmless by the Company from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all threatened, pending or completed claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, and whether formal or informal and including appeals, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee and acting (or refraining to act) in such capacity on behalf of or for the benefit of the Company; provided that the Indemnitee shall not be indemnified and held harmless pursuant to this Agreement if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Agreement, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful.

(b) To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.8(a) in appearing at, participating in or defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Company prior to a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.8, the Indemnitee is not entitled to be indemnified upon receipt by the Company of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be ultimately determined that the Indemnitee is not entitled to be indemnified as authorized by this Section 7.8.

(c) The indemnification provided by this Section 7.8 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Company Interests entitled to vote on such matter, as a matter of law, in equity or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity, and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

(d) The Company may purchase and maintain insurance, on behalf of the Indemnitees and such other Persons as the Board of Directors shall determine, against any Liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Company’s activities or such Person’s activities on behalf of the Company, regardless of whether the Company would have the power to indemnify such Person against such Liability under the provisions of this Agreement.

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constitute “fines” within the meaning of Section 7.8(a); and action taken or omitted by it with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Company.

(f) In no event may an Indemnitee subject the Members to personal Liability by reason of the indemnification provisions set forth in this Agreement.

(g) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.8 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies.

(h) The provisions of this Section 7.8 are for the benefit of the Indemnitees and their heirs, successors, assigns, executors and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

(i) No amendment, modification or repeal of this Section 7.8 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Company, nor the obligations of the Company to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.9. Liability of Indemnitees.

(a) Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable for monetary damages to the Company, the Members, any other Persons who acquire an interest in a Company Interest or any other Person who is bound by this Agreement, for losses sustained or liabilities incurred as a result of any act or omission of an Indemnitee unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter in question, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was criminal. The Members any other Person who acquires an interest in a Company Interest and any other Person who is bound by this Agreement, each on their own behalf and on behalf of the Company, waives any and all rights to claim punitive damages or damages based upon the Federal or State income taxes paid or payable by any such Member or other Person.

(b) Subject to its obligations and duties as Board of Directors set forth in Section 7.1(a), the Board of Directors may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the Board of Directors shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the Board of Directors in good faith.

(c) To the extent that, at law or in equity, an Indemnitee has duties and liabilities relating thereto to the Company, the Members, any Person who acquires an interest in a Company Interest or any other Person who is bound by this Agreement, any Indemnitee acting in connection with the Company’s business or affairs shall not be liable, to the fullest extent permitted by law, to the Company, to any Member, to any other Person who acquires an interest in a Company Interest or to any other Person who is bound by this Agreement for its reliance on the provisions of this Agreement.

(d) Any amendment, modification or repeal of this Section 7.9 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the Liability of the Indemnitees under this Section 7.9 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted, and provided such Person became an Indemnitee hereunder prior to such amendment, modification or repeal.

 

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Section 7.10. Standards of Conduct and Modification of Duties.

(a) Whenever the Board of Directors or any committee of the Board of Directors or any Officer, makes a determination or takes or declines to take any other action, whether under this Agreement or any other agreement contemplated hereby or otherwise, then, unless another express standard is provided for in this Agreement, the Board of Directors, such committee or such Officer shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different standards imposed by this Agreement or any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity (including fiduciary standards). A determination, other action or failure to act by the Board of Directors, any committee of the Board of Directors, or any Officer, including in the context of a potential conflict of interest, will be deemed to be in good faith unless the applicable party believed such determination, other action or failure to act was adverse to the interests of the Company. In any proceeding brought by the Company, any Member, any Person who acquires an interest in a Company Interest or any other Person who is bound by this Agreement challenging such action, determination or failure to act, the Person bringing or prosecuting such proceeding shall have the burden of proving that such determination, action or failure to act was not in good faith. Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or equity, the existence of the conflicts of interests described in the Registration Statement and any actions of the Board of Directors or any committee of the Board of Directors or any Officer taken in connection therewith are hereby approved by all Members and shall not constitute a breach of this Agreement or any duty hereunder or existing at law, in equity or otherwise.

(b) The Members, each Person who acquires an interest in a Company Interest and each other Person who is bound by this Agreement hereby authorize the Board of Directors, on behalf of the Company as a partner or member of a Group Member, to take, or approve actions by the board of directors, general partner or managing member of such Group Member, similar to those actions permitted to be taken by the Board of Directors pursuant to this Section 7.10.

(c) Nothing in this Section 7.10 shall be deemed to expand any duties or liabilities of the Board of Directors, its Affiliates or any other Indemnitee to the Company, any Group Member, any Member, any Person who acquires an interest in a Company Interest or other person who is bound by this Agreement for breach of this Agreement, to the extent that those duties or liabilities shall have been limited pursuant to Section 7.2 or 7.6 or this Section 7.10.

Section 7.11. Other Matters Concerning the Board of Directors and Officers.

(a) The Board of Directors, any committee of the Board of Directors and Officers may rely upon, and shall be protected in acting or refraining from acting upon, any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

(b) The Board of Directors, any committee of the Board of Directors and Officers may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the advice or opinion (including an Opinion of Counsel) of such Persons as to matters that the Board of Directors, any committee of the Board of Directors or Officers reasonably believes to be within such Person’s professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such advice or opinion.

(c) The Board of Directors and any committee of the Board of Directors shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its duly authorized Officers, a duly appointed attorney or attorneys-in-fact or the duly authorized officers of any Group Member. Each such attorney shall, to the extent provided by the Board of Directors or any committee of the Board of Directors in the power of attorney, have full power and authority to do and perform each and every act and duty that is permitted or required to be done by the Board of Directors or any committee of the Board of Directors hereunder.

 

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Section 7.12. Purchase or Sale of Company Interests.

The Board of Directors may cause the Company to purchase or otherwise acquire Company Interests. As long as Company Interests are held by the Company, such Company Interests shall not be considered Outstanding for any purpose, except as otherwise provided herein.

Section 7.13. Reliance by Third Parties.

Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Company shall be entitled to assume that the Board of Directors and any Officer authorized by the Board of Directors to act on behalf of and in the name of the Company has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Company and to enter into any authorized contracts on behalf of the Company, and such Person shall be entitled to deal with the Board of Directors or any such Officer as if it were the Company’s sole party in interest, both legally and beneficially. Each of the Members, each other Person who acquires an interest in a Company Interest and each other Person who is bound by this Agreement hereby waives, to the fullest extent permitted by law, any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the Board of Directors or any such Officer in connection with any such dealing. In no event shall any Person dealing with the Board of Directors or any such Officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the Board of Directors or any such officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Company by the Board of Directors or any such Officer or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Company and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Company.

ARTICLE VIII

BOOKS, RECORDS, ACCOUNTING AND REPORTS

Section 8.1. Records and Accounting.

The Board of Directors shall keep or cause to be kept at the principal office of the Company appropriate books and records with respect to the Company’s business, including all books and records necessary to provide to the Members any information required to be provided pursuant to Section 3.4(a). Any books and records maintained by or on behalf of the Company in the regular course of its business, including the record of the Record Holders of Units or other Company Interests, books of account and records of Company proceedings, may be kept on, or be in the form of, computer disks, hard drives, punch cards, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Company shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP. The Company shall not be required to keep books maintained on a cash basis, and the Board of Directors shall be permitted to calculate cash-based measures by making such adjustments to its accrual basis books to account for non-cash items and other adjustments as the Board of Directors determines to be necessary or appropriate.

Section 8.2. Fiscal Year.

The fiscal year of the Company shall be a calendar year ending December 31.

 

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Section 8.3. Reports.

(a) As soon as practicable, but in no event later than 120 days after the close of each fiscal year of the Company, the Board of Directors shall cause to be furnished or made available, by any reasonable means (including posting on or making accessible through the Company’s or the Commission’s website), to each Record Holder of a Company Interest as of a date selected by the Board of Directors, an annual report containing financial statements of the Company for such fiscal year of the Company, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Company equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the Board of Directors.

(b) As soon as practicable, but in no event later than 90 days after the close of each Quarter except the last Quarter of each fiscal year, the Board of Directors shall cause to be furnished or made available, by any reasonable means (including posting on or making accessible through the Company’s or the Commission’s website), to each Record Holder of a Company Interest, as of a date selected by the Board of Directors in its discretion, a report containing unaudited financial statements of the Company and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted for trading, or as the Board of Directors determines to be necessary or appropriate.

ARTICLE IX

TAX MATTERS

Section 9.1. Tax Returns and Information.

The Company shall timely file all returns of the Company that are required for federal, state and local income tax purposes on the basis of the accrual method and the taxable year that it is required by law to adopt, from time to time, as determined by the Board of Directors. In the event the Company is required to use a taxable year other than a year ending on December 31, the Board of Directors shall use reasonable efforts to change the taxable year of the Company to a year ending on December 31. The tax information reasonably required by Record Holders for federal and state income tax reporting purposes with respect to a taxable year shall be furnished to them within 90 days of the close of the calendar year in which the Company’s taxable year ends; provided that, if the 90th day is not a Business Day, then the 90th day shall be deemed to be the next Business Day. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for U.S. federal income tax purposes.

Section 9.2. Tax Elections.

(a) The Company shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the Board of Director’s determination that such revocation is in the best interests of the Members. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the Board of Directors shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Company Interest will be deemed to be the lowest quoted closing price of the Company Interests on any National Securities Exchange on which such Company Interests are listed or admitted for trading during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(g) without regard to the actual price paid by such transferee.

(b) Except as otherwise provided herein, the Board of Directors shall determine whether the Company should make any other elections permitted by the Code.

 

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Section 9.3. Tax Controversies.

Subject to the provisions hereof, the Board of Directors shall designate one Member as the Tax Matters Partner (as defined in the Code). The Tax Matters Partner is authorized and required to represent the Company (at the Company’s expense) in connection with all examinations of the Company’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Company funds for professional services and costs associated therewith. Each Member agrees to cooperate with the Tax Matters Partner and to do or refrain from doing any or all things reasonably required by the Tax Matters Partner to conduct such proceedings.

Section 9.4. Withholding.

Notwithstanding any other provision of this Agreement, the Board of Directors is authorized to take any action that may be required to cause the Company and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law (including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code) or established under any foreign law. To the extent that the Company is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Member (including by reason of Section 1446 of the Code), the Board of Directors may treat the amount withheld as a distribution of cash pursuant to Section 6.3 or 11.3(c) in the amount of such withholding from such Member.

ARTICLE X

ADMISSION AND WITHDRAWAL OF MEMBERS

Section 10.1. Admission of Members.

(a) By acceptance of the transfer of any Company Interests in accordance with Article IV, including the acceptance of any Company Interests in the Initial Distribution, or the acceptance of any Company Interests issued pursuant to Article V or pursuant to a merger, consolidation or conversion pursuant to Article XIII, and except as provided in Section 4.7, each transferee of, or other Person acquiring, a Company Interest (including any nominee holder or an agent or representative acquiring such Company Interests for the account of another Person) (i) shall be admitted to the Company as a Member with respect to the Company Interests so transferred or issued to such Person when any such transfer, issuance or admission is reflected in the books and records of the Company and such Person becomes the Record Holder of the Company Interests so transferred or issued, (ii) shall become bound by and shall be deemed to have agreed to be bound by the terms of, and shall be deemed to have executed, this Agreement, (iii) represents that such Person has the capacity, power and authority to enter into this Agreement, and (iv) makes the consents, acknowledgements and waivers contained in this Agreement, in each case, with or without execution of this Agreement by such Person. The transfer or issuance of any Company Interests and the admission of any new Member shall not constitute an amendment to this Agreement. A Person may become a Member or a Record Holder of a Company Interest without the consent or approval of any of the Members. A Person may not become a Member without acquiring a Company Interest and until such Person is reflected in the books and records of the Company as the Record Holder of such Company Interest. The rights and obligations of a Person who is an Ineligible Holder shall be determined in accordance with Section 4.7.

(b) The name and mailing address of each Member shall be listed on the books and records of the Company maintained for such purpose by the Company or the Transfer Agent. The Company shall update the books and records of the Company from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable). A Company Interest may be represented by a Certificate, as provided in Section 4.1.

(c) Any transfer of a Company Interest shall not entitle the transferee to share in the profits and losses, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a Member pursuant to Section 10.1(a).

 

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Section 10.2. Withdrawal of Members. No Member shall have any right to withdraw from the Company; provided, however, that when a transferee of a Member’s Company Interest becomes a Record Holder of the Company Interest so transferred, such transferring Member shall cease to be a Member with respect to the Company Interest so transferred.

ARTICLE XI

DISSOLUTION AND LIQUIDATION

Section 11.1. Dissolution.

The Company shall not be dissolved by the admission of Additional Members in accordance with the terms of this Agreement. The Company shall dissolve, and its affairs shall be wound up, upon:

(a) an election to dissolve the Company by the Board of Directors that is approved by the holders of a majority of the Outstanding Voting Units; or

(b) the entry of a decree of judicial dissolution of the Company pursuant to the provisions of the Delaware Act.

Section 11.2. Liquidator.

Upon dissolution of the Company, the Board of Directors shall select one or more Persons to act as Liquidator. The Liquidator (if other than the Board of Directors) shall be entitled to receive such compensation for its services as may be approved by holders of a majority of the Outstanding Voting Units. The Liquidator (if other than the Board of Directors) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by the holders of a majority of the Outstanding Voting Units. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of a majority of the Outstanding Voting Units. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article XI, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the Board of Directors under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.4) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Company as provided for herein.

Section 11.3. Liquidation.

The Liquidator shall proceed to dispose of the assets of the Company, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 18-804 of the Delaware Act and the following:

(a) Disposition of Assets. The assets may be disposed of by public or private sale or by distribution in kind to one or more Members on such terms as the Liquidator and such Member or Members may agree; provided that no Member agreement is necessary in respect of any pro rata distribution in kind of freely tradable publicly traded securities pursuant to this sentence. If any property is distributed in kind, the Member receiving the property shall be deemed for purposes of Section 11.3(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Members. The Liquidator may defer liquidation or distribution of the Company’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Company’s assets would be impractical or would

 

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cause undue loss to the Member. The Liquidator may distribute the Company’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Members.

(b) Discharge of Liabilities. Liabilities of the Company include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 11.2) and amounts owed to Members otherwise than in respect of their distribution rights under Article VI. With respect to any Liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

(c) Liquidation Distributions. All property and all cash in excess of that required to discharge liabilities as provided in Section 11.3(b) shall be distributed to the Members in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 11.3(c)) for the taxable year of the Company during which the liquidation of the Company occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable year (or, if later, within 90 days after said date of such occurrence).

Section 11.4. Cancellation of Certificate of Formation.

Upon the completion of the distribution of Company cash and property as provided in Section 11.3 in connection with the liquidation of the Company, the Certificate of Formation and all qualifications of the Company as a foreign limited liability company in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Company shall be taken.

Section 11.5. Return of Contributions.

No member of the Board of Directors or Officer of the Company shall be personally liable for or have any obligation to contribute or loan any monies or property to the Company to enable it to effectuate, the return of the Capital Contributions of the Members or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Company assets.

Section 11.6. Waiver of Partition.

To the maximum extent permitted by law, each Member hereby waives any right to partition of the Company property.

Section 11.7. Capital Account Restoration.

No Member shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Company.

ARTICLE XII

AMENDMENT OF COMPANY AGREEMENT; MEETINGS; RECORD DATE

Section 12.1. Amendments to be Adopted Solely by the Board of Directors.

Each Member agrees that the Board of Directors, without the approval of any Member, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

(a) a change in the name of the Company, the location of the principal place of business of the Company, the registered agent of the Company or the registered office of the Company;

 

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(b) the admission, substitution, withdrawal or removal of Members in accordance with this Agreement;

(c) a change that the Board of Directors determines to be necessary or appropriate to qualify or continue the qualification of the Company as a limited liability company under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for U.S. federal income tax purposes;

(d) a change that the Board of Directors determines (i) does not adversely affect the Members (including any particular class of Company Interests as compared to other classes of Company Interests) in any material respect, (ii) to be necessary or appropriate to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) facilitate the trading of the Company Interests or Units (including the division of any class or classes of Outstanding Company Interests into different classes to facilitate uniformity of tax consequences within such classes of Company Interests) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Company Interests or Units are or will be listed or admitted to trading, (iii) to be necessary or appropriate in connection with action taken by the Board of Directors pursuant to Section 5.7 or to implement the tax-related provisions of this Agreement, or (iv) to be required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

(e) a change in the fiscal year or taxable year of the Company and any other changes that the Board of Directors determines to be necessary or appropriate as a result of a change in the fiscal year or taxable year of the Company including, if the Board of Directors shall so determine, a change in the definition of “Distribution Period” and the dates on which distributions are to be made by the Company;

(f) an amendment that is necessary, in the Opinion of Counsel, to prevent the Company or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

(g) an amendment that the Board of Directors determines to be necessary or appropriate in connection with the authorization or issuance of any class or series of Company Interests, or any options, warrants, rights and/or appreciation rights relating to any Company Interest, pursuant to Section 5.5;

(h) an amendment expressly permitted in this Agreement to be made by the Board of Directors acting alone;

(i) an amendment effected, necessitated or contemplated by a Merger Agreement or Plan of Conversion approved in accordance with Section 13.3, or an amendment contemplated by Section 13.5;

(j) an amendment that the Board of Directors determines to be necessary or appropriate to reflect and account for the formation by the Company of, or investment by the Company in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Company of activities permitted by the terms of Section 2.4;

(k) an amendment effected, necessitated or contemplated by any amendment to the limited partnership or limited liability company agreement of a member of the MLP Group that requires the equityholders of such member of the MLP Group to provide a statement, certificate or other proof of evidence to the Subsidiary regarding whether such equityholder is subject to U.S. federal income tax on the income generated by such member of the MLP Group;

(l) a merger, conveyance or conversion pursuant to Section 13.3(d);

 

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(m) an amendment contemplated by Section 4.7; or

(n) any other amendments substantially similar to the foregoing.

Section 12.2. Amendment Procedures.

Amendments to this Agreement may be proposed only by the Board of Directors. To the fullest extent permitted by law, the Board of Directors shall have no duty or obligation to propose or approve any amendment to this Agreement and may decline to do so in its sole discretion, free of any duty or obligation whatsoever to the Company or any Member and, in declining to propose or approve an amendment, to the fullest extent permitted by law, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. A proposed amendment shall be effective upon its approval by the Board of Directors and, except as otherwise provided in Section 12.1 or 12.3, the holders of a majority of the Outstanding Voting Units, unless a greater or different percentage of Outstanding Voting Units is required under this Agreement or by Delaware law. Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Voting Units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the Board of Directors shall seek the written approval of the requisite percentage of Outstanding Voting Units or call a meeting of the Unitholders to consider and vote on such proposed amendment. The Board of Directors shall notify all Record Holders upon final adoption of any such proposed amendments. The Board of Directors shall be deemed to have notified all Record Holders as required by this Section 12.2 if it has either (i) filed such amendment with the Commission via its Electronic Data Gathering, Analysis and Retrieval system (or any successor system) and such amendment is publicly available on such system or (ii) made such amendment available on any publicly available website maintained by or on behalf of the Company.

Section 12.3. Amendment Requirements.

(a) Notwithstanding the provisions of Sections 12.1 and 12.2, no provision of this Agreement that establishes a percentage of Outstanding Units required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of reducing such voting percentage, unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute not less than the voting requirement sought to be reduced.

(b) Notwithstanding the provisions of Sections 12.1 and 12.2, no amendment to this Agreement may enlarge the obligations of any Member without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 12.3(c).

(c) Except as provided in Section 13.3, and without limitation of the Board of Directors’ authority to adopt amendments to this Agreement without the approval of any Members as contemplated in Section 12.1, any amendment that would have a material adverse effect on the rights or preferences of any class of Company Interests in relation to other classes of Company Interests must be approved by the holders of not less than a majority of the Outstanding Company Interests of the class affected.

(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 12.1 and except as otherwise provided by Section 13.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Voting Units, if the Board of Directors determines that such amendment will affect the limited liability of any Member under applicable law of the state under whose laws the Company is organized (it being understood that the Board of Directors may rely on any Opinion of Counsel in making such determination, but no such Opinion of Counsel shall be required).

(e) Except as provided in Section 12.1, this Section 12.3 shall only be amended with the approval of the holders of at least 90% of the Outstanding Voting Units.

 

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Section 12.4. Unitholder Meetings.

(a) All acts of Members to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XII.

(b) Special Meetings.

(i) Special meetings of the Members may be called only by the Board of Directors. The special meeting shall be held at a time and place determined by the Board of Directors on a date not less than 10 days nor more than 60 days after the mailing of notice of the meeting.

(ii) At any special meeting, only such business shall be conducted or considered as shall have been properly brought before the meeting pursuant to the notice of meeting. To be properly brought before a special meeting, proposals of business must be (A) specified in the Company’s notice of meeting (or any supplement thereto) given by or at the direction of the Board of Directors or (B) otherwise properly brought before the special meeting by or at the direction of the Board of Directors.

(iii) Without qualification or limitation, subject to any rights of the Members to request inclusion of proposals in the Company’s proxy statement pursuant to Rule 14a-8 under the Exchange Act and to this Section 12.4, in the event the Board of Directors calls a special meeting for the purpose of electing one or more directors to the Board of Directors, any Member may nominate an individual or individuals (as the case may be) for election to such position(s) as specified in the notice of meeting, provided that such Member (A) is a Member at the time of giving of such notice of such special meeting and at the time of the special meeting, (B) is entitled to vote at such special meeting and (C) gives timely notice of such nomination (including the completed and signed questionnaire, representation and agreement required by Section 12.13), and timely updates and supplements thereof, in each case in proper form, in writing, to the Board of Directors. To be timely, a Member’s notice must:

(A) be delivered to the Board of Directors pursuant to Section 14.1 not earlier than the close of business on the 120th day prior to the date of such special meeting and not later than the close of business on the later of the 90th day prior to the date of such special meeting or, if the first public announcement of the date of such special meeting is less than 100 days prior to the date of such special meeting, the 10th day following the day on which public announcement of the date of the special meeting is first made. In no event shall an adjournment or postponement of a special meeting, or the public announcement thereof, commence a new time period for the giving of a Member’s notice as described above.

(B) further be updated and supplemented, if necessary, so that the information provided or required to be provided in such notice shall be true and correct as of the record date for the meeting and as of the date that is ten (10) Business Days prior to the meeting or any adjournment or postponement thereof, and such updates and supplements shall be delivered to the Board of Directors pursuant to Section 14.1 not later than five (5) Business Days after the record date for the meeting in the case of the update and supplement required to be made as of the record date, and not later than eight (8) Business Days prior to the date for the meeting, any adjournment or postponement thereof in the case of the update and supplement required to be made as of ten (10) Business Days prior to the meeting or any adjournment or postponement thereof.

(c) Annual Meetings.

(i) An annual meeting of the Members holding Voting Units for the election of directors to the Board of Directors and such other matters as the Board of Directors shall submit to a vote of the Members holding Voting Units shall be held at such date and time as may be fixed from time to time by the Board of Directors at such place within or without the State of Delaware as may be fixed from time to time by the Board of Directors and all as stated in the notice of the meeting. Notice of the annual meeting shall be given in accordance with Section 12.5 not less than 10 days nor more than 60 days prior to the date of such meeting.

 

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(ii) At any annual meeting, only such nominations of persons for election to the Board of Directors shall be made, and only such other business shall be conducted or considered, as shall have been properly brought before the meeting. For nominations to be properly made at an annual meeting, and proposals of other business to be properly brought before an annual meeting, nominations and proposals of other business must be: (A) specified in the notice of meeting, (B) otherwise properly made at the annual meeting, by or at the direction of the Board of Directors or (C) otherwise properly requested to be brought before the annual meeting by a Member in accordance with this Section 12.4. For nominations of persons for election to the Board of Directors or proposals of other business to be properly requested by a Member to be made at an annual meeting, a Member must (I) be a Member at the time of giving of notice of such annual meeting and at the time of the annual meeting, (II) be entitled to vote at such annual meeting and (III) comply with the procedures set forth in this Section 12.4 as to such business or nomination. The immediately preceding sentence shall be the exclusive means for a Member to make nominations or other business proposals (other than matters properly brought under Rule 14a-8 under the Exchange Act and included in the notice of meeting) before an annual meeting.

(iii) The Members holding Outstanding Voting Units shall vote together as a single class. The Members entitled to vote shall elect by a plurality of the votes cast, in person or by proxy, at such meeting persons to serve on the Board of Directors who are nominated in accordance with the provisions of this Article XII.

(iv) Without qualification or limitation, subject to any rights of the Members to request inclusion of proposals in the Company’s proxy statement pursuant to Rule 14a-8 under the Exchange Act and to this Section 12.4, for any nominations or any other business to be properly requested to be brought before an annual meeting by a Member, the Member must have given timely notice thereof (including, in the case of nominations, the completed and signed questionnaire, representation and agreement required by Section 12.13) in a proper form and timely updates and supplements thereof in writing to the Board of Directors and such business must otherwise be a proper matter for Member action. To be timely, a Member’s notice must:

(A) be delivered to the Board of Directors pursuant to Section 14.1 not earlier than the close of business on the 120th day nor later than the close of business on the 90th day prior to the first anniversary of the preceding year’s annual meeting; provided, however, that (x) in the event that the date of the annual meeting is more than 30 days before or more than 60 days after such anniversary date and (y) in the case of the 2016 annual meeting, a Member’s notice to be timely must be so delivered not earlier than the close of business on the 120th day prior to the date of such annual meeting and not later than the close of business on the later of the 90th day prior to the date of such annual meeting or, if the first public announcement of the date of such annual meeting is less than 100 days prior to the date of such annual meeting, the 10th day following the day on which public announcement of the date of the annual meeting is first made. In no event shall an adjournment or postponement of an annual meeting, or the public announcement thereof, commence a new time period for the giving of a Member’s notice as described above.

(B) further be updated and supplemented, if necessary, so that the information provided or required to be provided in such notice shall be true and correct as of the record date for the meeting and as of the date that is ten (10) Business Days prior to the meeting or any adjournment or postponement thereof, and such updates and supplements shall be delivered to the Board of Directors pursuant to Section 14.1 not later than five (5) Business Days after the record date for the meeting in the case of the update and supplement required to be made as of the record date, and not later than eight (8) Business Days prior to the date for the meeting, any adjournment or postponement thereof in the case of the update and supplement required to be made as of ten (10) Business Days prior to the meeting or any adjournment or postponement thereof. The obligation to update and supplement set forth in this paragraph or any other provision of this Section 12.4 shall not limit the Company’s rights with respect to any deficiencies in any notice

 

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provided by a Member, extend any applicable deadlines hereunder or enable or be deemed to permit a Member who has previously submitted notice hereunder to amend or update any proposal or to submit any new proposal, including by changing or adding nominees, matters, business and/or resolutions proposed to be brought before an annual meeting.

(v) This Article XII may not be amended except upon the prior approval of Members that hold 80% of the Outstanding Voting Units.

(d) Notice Requirements. To be in proper form, a Unitholder’s notice given pursuant to this Section 12.4 to the Board of Directors must include the following, as applicable:

(i) As to the Unitholder giving the notice and the beneficial owner, if any, on whose behalf the nomination or proposal is made, a Unitholder’s notice must set forth: (A) the name and address of such Unitholder, as they appear on the Company’s books, of such beneficial owner, if any, and of their respective affiliates or associates or others acting in concert therewith, (B) (I) the class or series and number of Company Interests that are, directly or indirectly, owned beneficially and of record by such Unitholder, such beneficial owner, if any, and their respective affiliates or associates or others acting in concert therewith, (II) any option, warrant, convertible security, stock appreciation right, or similar right with an exercise or conversion privilege or a settlement payment or mechanism at a price related to any Company Interest or with a value derived in whole or in part from the value of any Company Interest, or any derivative or synthetic arrangement having the characteristics of a long position in any Company Interest, or any contract, derivative, swap or other transaction or series of transactions designed to produce economic benefits and risks that correspond substantially to the ownership of any Company Interest, including due to the fact that the value of such contract, derivative, swap or other transaction or series of transactions is determined by reference to the price, value or volatility of any Company Interest, whether or not such instrument, contract or right shall be subject to settlement in the underlying Company Interest, through the delivery of cash or other property, or otherwise, and without regard to whether the Unitholder of record, the beneficial owner, if any, or any affiliates or associates or others acting in concert therewith, may have entered into transactions that hedge or mitigate the economic effect of such instrument, contract or right, or any other direct or indirect opportunity to profit or share in any profit derived from any increase or decrease in the value of Units or Company Interests (any of the foregoing, a “Derivative Instrument”) directly or indirectly owned beneficially by such Unitholder, the beneficial owner, if any, or any affiliates or associates or others acting in concert therewith, (III) any proxy, contract, arrangement, understanding, or relationship pursuant to which such Unitholder, such beneficial owner, if any, and their respective affiliates or associates or others acting in concert therewith have any right to vote any Company Interest, (IV) any agreement, arrangement, understanding, relationship or otherwise, including any repurchase or similar so-called “stock borrowing” agreement or arrangement, involving such Unitholder, such beneficial owner, if any, and their respective affiliates or associates or others acting in concert therewith, directly or indirectly, the purpose or effect of which is to mitigate loss to, reduce the economic risk (of ownership or otherwise) of any Company Interest by, manage the risk of share or unit price changes for, or increase or decrease the voting power of, such Unitholder with respect to any Company Interest, or which provides, directly or indirectly, the opportunity to profit or share in any profit derived from any decrease in the price or value of any Company Interest (any of the foregoing, a “Short Interest”), (V) any rights to dividends or distributions on any Company Interest owned beneficially by such Unitholder, such beneficial owner, if any, and their respective affiliates or associates or others acting in concert therewith that are separated or separable from the underlying Company Interest, (VI) any proportionate interest in any Company Interest or Derivative Instruments held, directly or indirectly, by a general or limited partnership in which such Unitholder, such beneficial owner, if any, and their respective affiliates or associates or others acting in concert therewith is a general partner or, directly or indirectly, beneficially owns an interest in a general partner of such general or limited partnership, (VII) any performance-related fees (other than an asset-based fee) that such Unitholder, such beneficial owner and their respective affiliates or associates or others acting in concert therewith is entitled to based on any increase or

 

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decrease in the value of any Company Interest or Derivative Instruments, if any, including any such interests held by members of the immediate family sharing the same household with such Unitholder, such beneficial owner and their respective affiliates or associates or others acting in concert therewith, (VIII) any significant equity interests or any Derivative Instruments or Short Interests in any principal competitor of the Company held by such Unitholder, such beneficial owner and their respective affiliates or associates or others acting in concert therewith, and (IX) any direct or indirect interest of such Unitholder, such beneficial owner and their respective affiliates or associates or others acting in concert therewith in any contract with the Company, any affiliate of the Company or any principal competitor of the Company (including, in any such case, any employment agreement, collective bargaining agreement or consulting agreement), (C) all information that would be required to be set forth in a Schedule 13D filed pursuant to Rule 13d-1(a) under the Exchange Act or an amendment pursuant to Rule 13d-2(a) under the Exchange Act if such a statement were required to be filed under the Exchange Act and the rules and regulations promulgated thereunder by such Unitholder, such beneficial owner and their respective affiliates or associates or others acting in concert therewith, if any, and (D) any other information relating to such Unitholder, such beneficial owner and their respective affiliates or associates or others acting in concert therewith, if any, that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for, as applicable, the proposal and/or for the election of directors in a contested election pursuant to Section 14 of the Exchange Act and the rules and regulations promulgated thereunder;

(ii) If the notice relates to any business other than a nomination of a Director or Directors that the Unitholder proposes to bring before the meeting, a Unitholder’s notice must, in addition to the matters set forth in paragraph (i) above, also set forth: (A) a brief description of the business desired to be brought before the meeting, the reasons for conducting such business at the meeting and any material interest of such Unitholder, such beneficial owner, and their respective affiliates or associates or others acting in concert therewith, if any, in such business, (B) the text of the proposal or business (including the text of any resolutions proposed for consideration), and (C) a description of all agreements, arrangements and understandings between such Unitholder, beneficial owner and their respective affiliates or associates acting in concert therewith, if any, and any other person or persons (including their names) in connection with the proposal of such business by such Unitholder;

(iii) As to each person, if any, whom the Unitholder proposes to nominate for election or reelection to the Board of Directors, a Unitholder’s notice must, in addition to the matters set forth in paragraph (i) above, also: (A) set forth all information relating to such person that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors in a contested election pursuant to Section 14 of the Exchange Act and the rules and regulations promulgated thereunder (including such person’s written consent to being named in the proxy statement as a nominee and to serving as a Director if elected); (B) set forth a description of all direct and indirect compensation and other material monetary agreements, arrangements and understandings during the past three years, and any other material relationships, between or among such Unitholder and beneficial owner, if any, and their respective affiliates and associates, or others acting in concert therewith, on the one hand, and each proposed nominee, and his or her respective affiliates and associates, or others acting in concert therewith, on the other hand, including all information that would be required to be disclosed pursuant to Rule 404 promulgated under Regulation S-K if the Unitholder making the nomination and any beneficial owner on whose behalf the nomination is made, if any, or any affiliate or associate thereof or person acting in concert therewith, were the “registrant” for purposes of such rule and the nominee were a director or executive officer of such registrant; and (C) include a completed and signed questionnaire, representation and agreement required by Section 12.13. In addition, the Company may require any proposed nominee to furnish such other information as may reasonably be required by the Company to determine the eligibility of such proposed nominee to serve as an independent Director or that could be material to a reasonable Unitholder’s understanding of the independence, or lack thereof, of such nominee.

 

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Section 12.5. Notice of a Meeting.

Notice of a meeting called pursuant to Section 12.4 shall be given to the Record Holders of the class or classes of Company Interests for which a meeting is proposed in writing by mail or other means of written communication in accordance with Section 14.1. The notice shall be deemed to have been given at the time when deposited in the mail or sent by other means of written communication.

Section 12.6. Record Date.

For purposes of determining the Members entitled to notice of or to vote at a meeting of the Members or to give approvals without a meeting as provided in Section 12.11 the Board of Directors may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any U.S. federal securities laws or any National Securities Exchange on which the Company Interests are listed or admitted for trading, in which case such U.S. federal securities laws or the rule, regulation, guideline or requirement of such National Securities Exchange shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Members are requested in writing by the Board of Directors to give such approvals. If the Board of Directors does not set a Record Date, then (x) the Record Date for determining the Members entitled to notice of or to vote at a meeting of the Members shall be the close of business on the day immediately preceding the day on which notice is given, and (y) the Record Date for determining the Members entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Company in care of the Board of Directors in accordance with Section 12.11.

Section 12.7. Adjournment.

When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days. At the adjourned meeting, the Company may transact any business which might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XII.

Section 12.8. Waiver of Notice; Approval of Meeting.

The transactions of any meeting of Members, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present, either in person or by proxy. Attendance of a Member at a meeting shall constitute a waiver of notice of the meeting, except when the Member attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove the consideration of matters required to be included in the notice of the meeting, but not so included, if the disapproval is expressly made at the meeting.

Section 12.9. Quorum and Voting.

The holders of a majority of the Outstanding Voting Units of the class or classes for which a meeting has been called represented in person or by proxy shall constitute a quorum at a meeting of Members of such class or classes unless any such action by the Members requires approval by holders of a greater percentage of such Voting Units, in which case the quorum shall be such greater percentage. At any meeting of the Members duly called and held in accordance with this Agreement at which a quorum is present, the act of Members holding Outstanding Voting Units that in the aggregate represent a majority of the Outstanding Voting Units cast, in person or by proxy, at such meeting shall be deemed to constitute the act of all Members, unless a greater or different percentage is required with respect to such action under the provisions of this Agreement, in which case

 

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the act of the Members holding Outstanding Voting Units that in the aggregate represent at least such greater or different percentage shall be required. The Members present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Members to leave less than a quorum, if any action taken (other than adjournment) is approved by the required percentage of Outstanding Voting Units specified in this Agreement. In the absence of a quorum, any meeting of Members may be adjourned from time to time by the affirmative vote of holders of at least a majority of the Outstanding Voting Units cast at such meeting represented either in person or by proxy, but no other business may be transacted, except as provided in Section 12.7.

Section 12.10. Conduct of a Meeting.

The Board of Directors shall have full power and authority concerning the manner of conducting any meeting of the Members or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of this Article XII, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The Board of Directors shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Company maintained by the Board of Directors. The Board of Directors may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Members or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the revocation of approvals in writing.

Section 12.11. Action Without a Meeting.

If authorized by the Board of Directors, any action that may be taken at a meeting of the Members may be taken without a meeting if an approval in writing setting forth the action so taken is signed by Members owning not less than the minimum percentage of the Outstanding Voting Units that would be necessary to authorize or take such action at a meeting at which all the Members were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Voting Units are listed or admitted for trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern). Prompt notice of the taking of action without a meeting shall be given to the Members who have not approved in writing. The Board of Directors may specify that any written ballot submitted to Members for the purpose of taking any action without a meeting shall be returned to the Company within the time period, which shall be not less than 20 days, specified by the Board of Directors. If a ballot returned to the Company does not vote all of the Voting Units held by the Members, the Company shall be deemed to have failed to receive a ballot for the Voting Units that were not voted.

If action by written consent is not specifically authorized by the Board of Directors, any action required or permitted to be taken by the Members must be effected at an annual or special meeting of Members and may not be effected by any consent in writing by such Members.

Section 12.12. Voting and Other Rights.

(a) Only those Record Holders of the Outstanding Voting Units on the Record Date set pursuant to Section 12.6 (and also subject to the limitations contained in the definition of “Outstanding”) shall be entitled to notice of, and to vote at (in person or by proxy), a meeting of Members or to act with respect to matters as to which the holders of the Outstanding Voting Units have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Voting Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Voting Units.

 

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(b) With respect to Voting Units that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Voting Units are registered, such other Person shall, in exercising the voting rights in respect of such Voting Units on any matter, and unless the arrangement between such Persons provides otherwise, vote such Voting Units in favor of, and at the direction of, the Person who is the beneficial owner, and the Company shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 12.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

(c) Each Member holding Voting Units shall be entitled to one vote for each Outstanding Unit that is registered in the name of such Member on the Record Date for such meeting; provided, however, that the Company shall not be entitled to vote Units that are owned, directly or indirectly, by the Company, and any such Units that are not entitled to be voted pursuant to this provision shall not be deemed to be Outstanding for purposes of determining a quorum under Section 12.9.

Section 12.13. Submission of Questionnaire, Representation and Agreement. To be eligible to be a nominee for election or reelection as a Director, a person must deliver (in accordance with the time periods prescribed for delivery of notice under Section 12.4) to the Board of Directors pursuant to Section 14.1 a written questionnaire with respect to the background and qualification of such person and the background of any other person or entity on whose behalf the nomination is being made (which questionnaire shall be provided by the Company upon written request), and a written representation and agreement (in the form provided by the Company upon written request) that such person (a) is not and will not become a party to (i) any agreement, arrangement or understanding with, and has not given any commitment or assurance to, any person or entity as to how such person, if elected as a Director, will act or vote on any issue or question (a “Voting Commitment”) that has not been disclosed to the Company or (ii) any Voting Commitment that could limit or interfere with such person’s ability to comply, if elected as a Director, with such person’s duties under applicable law, (b) is not and will not become a party to any agreement, arrangement or understanding with any person or entity other than the Company with respect to any direct or indirect compensation, reimbursement or indemnification in connection with service or action as a Director that has not been disclosed therein, and (c) in such person’s individual capacity and on behalf of any person or entity on whose behalf the nomination is being made, would be in compliance, if elected as a Director, and will comply, with all applicable publicly disclosed corporate governance, conflict of interest, confidentiality and stock ownership and trading policies and guidelines of the Company.

ARTICLE XIII

MERGER, CONSOLIDATION OR CONVERSION

Section 13.1. Authority.

The Company may merge or consolidate with or into one or more corporations, limited liability companies, statutory trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a partnership (whether general or limited (including a limited liability partnership)) or convert into any such entity, whether such entity is formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written agreement or plan of merger or consolidation (“Merger Agreement”) or a written plan of conversion (“Plan of Conversion”), as the case may be, in accordance with this Article XIII. It is expressly agreed that any merger or consolidation of any member of the Company Group (other than the Company) shall not be subject to the requirements of this Article XIII.

Section 13.2. Procedure for Merger, Consolidation or Conversion.

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of Directors shall have no duty or obligation to approve any merger, consolidation or conversion of the Company and may decline to do so free of any duty or obligation whatsoever to the Company or any Member and, in declining to approve a merger, consolidation or conversion, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

(b) If the Board of Directors shall determine to approve the merger or consolidation, the Board of Directors shall approve the Merger Agreement, which shall set forth:

(i) the names and jurisdictions of formation or organization of each of the business entities proposing to merge or consolidate;

(ii) the name and jurisdiction of formation or organization of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity”);

(iii) the terms and conditions of the proposed merger or consolidation;

(iv) the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (i) if any interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity, the cash, property or interests, rights, securities or obligations of any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity) which the holders of such interests, securities or rights are to receive in exchange for, or upon conversion of their interests, securities or rights, and (ii) in the case of securities represented by certificates, upon the surrender of such certificates, which cash, property or interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

(v) a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership, operating agreement or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

(vi) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 13.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger is to be later than the date of the filing of such certificate of merger, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of merger and stated therein); and

(vii) such other provisions with respect to the proposed merger or consolidation that the Board of Directors determines to be necessary or appropriate.

(c) If the Board of Directors shall determine to approve the conversion, the Board of Directors may approve and adopt a Plan of Conversion containing such terms and conditions that the Board of Directors determines to be necessary or appropriate.

Section 13.3. Approval by Members.

(a) Except as provided in Section 13.3(d), the Board of Directors, upon its approval of the Merger Agreement or the Plan of Conversion, as the case may be, shall direct that the Merger Agreement or the Plan of Conversion, as applicable, be submitted to a vote of Members, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XII. A copy or a summary of the Merger Agreement or the Plan of Conversion, as applicable, shall be included in or enclosed with the notice of a special meeting or the written consent.

 

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(b) Except as provided in Sections 13.3(d) and 13.3(e), the Merger Agreement or the Plan of Conversion, as applicable, shall be approved upon receiving the affirmative vote or consent of the holders of a majority of the Outstanding Voting Units.

(c) Except as provided in Sections 13.3(d) and 13.3(e), after such approval by vote or consent of the Members, and at any time prior to the filing of the certificate of merger or the certificate of conversion pursuant to Section 13.4, the merger, consolidation or conversion may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement or the Plan of Conversion, as the case may be.

(d) Notwithstanding anything else contained in this Article XIII or in this Agreement, the Board of Directors is permitted, without Member approval, to convert the Company or any Group Member into a new limited liability entity, to merge the Company or any Group Member into, or convey all of the Company’s assets to, another limited liability entity that shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives from the Company or other Group Member if (i) the Board of Directors has received an Opinion of Counsel that the conversion, merger or conveyance, as the case may be, would not result in the loss of the limited liability of any Member as compared to its limited liability under the Delaware Act or cause the Company to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not previously treated as such), (ii) the purpose of such conversion, merger or conveyance is to effect a change in the legal form of the Company into another limited liability entity and (iii) the Board of Directors determines that the governing instruments of the new entity provide the Members with substantially the same rights and obligations as are herein contained.

(e) Additionally, notwithstanding anything else contained in this Article XIII or in this Agreement, the Board of Directors is permitted, without Member approval, to merge or consolidate the Company with or into another entity if (i) the Board of Directors has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability of any Member as compared to its limited liability under the Delaware Act or cause the Company to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not previously treated as such), (ii) the merger or consolidation would not result in an amendment to this Agreement, other than any amendments that could be adopted pursuant to Section 12.1, (iii) the Company is the Surviving Business Entity in such merger or consolidation, (iv) each Unit Outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Unit of the Company after the effective date of the merger or consolidation and (v) the number of Company Interests to be issued by the Company in such merger or consolidation does not exceed 20% of the Company Interests Outstanding immediately prior to the effective date of such merger or consolidation.

Section 13.4. Certificate and Effect of Merger or Conversion.

(a) Upon the required approval, if any, by the Board of Directors and the Unitholders of a Merger Agreement or a Plan of Conversion, as the case may be, a certificate of merger or certificate of conversion, as applicable, shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

(b) At the effective time of the merger:

(i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;

(ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

 

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(iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

(iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

(c) At the effective time of the conversion:

(i) the Company shall continue to exist, without interruption, but in the organizational form of the converted entity rather than in its prior organizational form;

(ii) all rights, title, and interests to all real estate and other property owned by the Company shall continue to be owned by the converted entity in its new organizational form without reversion or impairment, without further act or deed, and without any transfer or assignment having occurred, but subject to any existing liens or other encumbrances thereon;

(iii) all liabilities and obligations of the Company shall continue to be liabilities and obligations of the converted entity in its new organizational form without impairment or diminution by reason of the conversion;

(iv) all rights of creditors or other parties with respect to or against the prior interest holders or other owners of the Company in their capacities as such in existence as of the effective time of the conversion will continue in existence as to those liabilities and obligations and may be pursued by such creditors and obligees as if the conversion did not occur;

(v) a proceeding pending by or against the Company or by or against any of the Members in their capacities as such may be continued by or against the converted entity in its new organizational form and by or against the prior partners without any need for substitution of parties; and

(vi) the Company Interests that are to be converted into partnership interests, shares, evidences of ownership, or other securities in the converted entity as provided in the Plan of Conversion or certificate of conversion shall be so converted, and Members shall be entitled only to the rights provided in the Plan of Conversion or certificate of conversion.

(d) A merger, consolidation or conversion effected pursuant to this Article XIII shall not be deemed to result in a transfer or assignment of assets or liabilities from one entity to another.

Section 13.5. Amendment of Company Agreement.

Pursuant to Section 18-209(f) of the Delaware Act, an agreement or plan of merger or consolidation approved in accordance with Section 18-209(b) of the Delaware Act may (a) effect any amendment to this Agreement or (b) effect the adoption of a new limited liability company agreement for a limited liability company if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Article XIII shall be effective at the effective time or date of the merger or consolidation.

ARTICLE XIV

GENERAL PROVISIONS

Section 14.1. Addresses and Notices; Written Communications.

Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Member under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Member at the address described below. Any notice, payment or report to be given or made to a Member hereunder shall be

 

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deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Company Interests at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Company, regardless of any claim of any Person who may have an interest in such Company Interests by reason of any assignment or otherwise. Notwithstanding the foregoing, if (i) a Member shall consent to receiving notices, demands, requests, reports or proxy materials via electronic mail or by the Internet or (ii) the rules of the Commission shall permit any report or proxy materials to be delivered electronically or made available via the Internet, any such notice, demand, request, report or proxy materials shall be deemed given or made when delivered or made available via such mode of delivery. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 14.1 executed by the Company, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report addressed to a Record Holder at the address of such Record Holder appearing on the books and records of the Transfer Agent or the Company is returned by the United States Postal Service marked to indicate that the United States Postal Service is unable to deliver it, such notice, payment or report and any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Company of a change in his address) if they are available for the Member at the principal office of the Company for a period of one year from the date of the giving or making of such notice, payment or report to the other Members. Any notice to the Company shall be deemed given if received by the Company at the principal office of the Company designated pursuant to Section 2.3. The Board of Directors and the Officers may rely on and shall be protected in relying on any notice or other document from a Member or other Person if believed by it to be genuine. The terms “in writing,” “written communications,” “written notice” and words of similar import shall be deemed satisfied under this Agreement by use of e-mail and other forms of electronic communication.

Section 14.2. Further Action.

The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

Section 14.3. Binding Effect.

This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

Section 14.4. Integration.

This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 14.5. Creditors.

None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Company.

Section 14.6. Waiver.

No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

Section 14.7. Third-Party Beneficiaries.

Each Member agrees that (a) any Indemnitee shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or

 

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privilege to such Indemnitee and (b) any Unrestricted Person shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Unrestricted Person.

Section 14.8. Counterparts.

This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Member Interest pursuant to Section 10.1(a), without execution hereof.

Section 14.9. Applicable Law; Forum; Venue and Jurisdiction.

(a) This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

(b) Each of the Members and each Person holding any beneficial interest in the Company (whether through a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing or otherwise):

(i) irrevocably agrees that, unless the Company (through the approval of the Board of Directors) consents in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware shall be the sole and exclusive forum for any claims, suits, actions or proceedings (A) arising out of or relating in any way to this Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of this Agreement or the duties, obligations or liabilities among Members or of Members to the Company, or the rights or powers of, or restrictions on, the Members or the Company), (B) brought in a derivative manner on behalf of the Company, (C) asserting a claim of breach of a duty owed by any director, officer or other employee of the Company or any Indemnitee, (D) asserting a claim arising pursuant to any provision of the Delaware Act or (E) asserting a claim governed by the internal affairs doctrine, in each case regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims; provided that if and only if the Court of Chancery of the State of Delaware dismisses any such claims, suits, actions or proceedings for lack of subject matter jurisdiction, such claims, suits, actions or proceedings may be brought in another state or federal court sitting in the State of Delaware;

(ii) irrevocably submits, unless the Company (through the approval of the Board of Directors) consents in writing to the selection of an alternative forum, to the exclusive jurisdiction of the Court of Chancery of the State of Delaware in connection with any such claim, suit, action or proceeding; provided that if and only if the Court of Chancery of the State of Delaware dismisses any such claims, suits, actions or proceedings for lack of subject matter jurisdiction, it irrevocably submits to the exclusive jurisdiction of any state or federal court sitting in the State of Delaware;

(iii) irrevocably agrees not to, and irrevocably waives any right to, assert in any such claim, suit, action or proceeding that (A) it is not personally subject to the jurisdiction of the Court of Chancery of the State of Delaware (unless the Company (through the approval of the Board of Directors) consents in writing to the selection of an alternative forum) or of any other court to which proceedings in the Court of Chancery of the State of Delaware may be appealed (unless the Company (through the approval of the Board of Directors) consents in writing to the selection of an alternative forum); provided that if and only if the Court of Chancery of the State of Delaware dismisses any such claims, suits, actions or proceedings for lack of subject matter jurisdiction, then it irrevocably agrees not to, and irrevocably waives any right to, assert in any such claim, suit, action or proceeding that (A) it is not personally subject to the jurisdiction of any state or federal court sitting in the State of Delaware, (B) such claim, suit, action or proceeding is brought in an inconvenient forum, or (C) the venue of such claim, suit, action or proceeding is improper;

 

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(iv) expressly waives any requirement for the posting of a bond by a party bringing such claim, suit, action or proceeding; and

(v) consents to process being served in any such claim, suit, action or proceeding by mailing, certified mail, return receipt requested, a copy thereof to such party at the address in effect for notices hereunder, and agrees that such services shall constitute good and sufficient service of process and notice thereof; provided, nothing in clause (v) hereof shall affect or limit any right to serve process in any other manner permitted by law.

Section 14.10. Invalidity of Provisions.

If any provision or part of a provision of this Agreement is or becomes for any reason, invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions and/or parts thereof contained herein shall not be affected thereby and this Agreement shall, to the fullest extent permitted by law, be reformed and construed as if such invalid, illegal or unenforceable provision, or part of a provision, had never been contained herein, and such provisions and/or part shall be reformed so that it would be valid, legal and enforceable to the maximum extent possible.

Section 14.11. Consent of Members.

Each Member hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Members, such action may be so taken upon the concurrence of less than all of the Members and each Member shall be bound by the results of such action.

Section 14.12. Facsimile and PDF Signatures.

The use of facsimile signatures and signatures delivered by email in portable document format (.pdf) affixed in the name and on behalf of the transfer agent and registrar of the Company on certificates representing Common Units is expressly permitted by this Agreement.

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.

 

 

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