Atlas Energy Group, LLC - FORM 10-K

Atlas Energy Group, LLC - FORM 10-K - March 27, 2015

Attached files

Attached files

file	filename
EX-23.3 - EX-23.3 - Atlas Energy Group, LLC	d896820dex233.htm
EX-31.1 - EX-31.1 - Atlas Energy Group, LLC	d896820dex311.htm
EX-21.1 - EX-21.1 - Atlas Energy Group, LLC	d896820dex211.htm
EX-31.2 - EX-31.2 - Atlas Energy Group, LLC	d896820dex312.htm
EX-32.1 - EX-32.1 - Atlas Energy Group, LLC	d896820dex321.htm
EX-23.1 - EX-23.1 - Atlas Energy Group, LLC	d896820dex231.htm
EX-32.2 - EX-32.2 - Atlas Energy Group, LLC	d896820dex322.htm
EX-23.2 - EX-23.2 - Atlas Energy Group, LLC	d896820dex232.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-36725

Atlas Energy Group, LLC

(Exact name of registrant as specified in its charter)


Delaware		45-3741247
(State or other jurisdiction or incorporation or organization)		(I.R.S. Employer Identification No.)

Park Place Corporate Center One 1000 Commerce Drive, Suite 400 Pittsburgh, Pennsylvania		15275
(Address of principal executive offices)		Zip code

Registrant’s telephone number, including area code: 412-489-0006

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered
Common Units representing Limited Partnership Interests		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ¨ No x

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “small reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

The aggregate market value of the equity securities held by non-affiliates of the registrant on March 2, 2015, based upon the closing price of $9.07 of the registrant’s common units as reported on the New York Stock Exchange was approximately $227.1 million. The registrant has elected to use March 2, 2015 as the calculation date, which was the initial regular-way trading date of the registrant’s common units on the New York Stock Exchange, since on June 30, 2014 (the last business day of the registrant’s second fiscal quarter), the registrant was a privately-held company.

As of March 23, 2015, there were 26,010,766 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None

ATLAS ENERGY GROUP, LLC AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K

TABLE OF CONTENTS


			Page
PART I	Item 1:	Business		8
	Item 1A:	Risk Factors		26
	Item 1B:	Unresolved Staff Comments		57
	Item 2:	Properties		57
	Item 3:	Legal Proceedings		63
	Item 4:	Mine Safety Disclosures		63

PART II	Item 5:	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities		64
	Item 6:	Selected Financial Data		64
	Item 7:	Management’s Discussion and Analysis of Financial Condition and Results of Operations		67
	Item 7A:	Quantitative and Qualitative Disclosures about Market Risk		101
	Item 8:	Financial Statements and Supplementary Data		105
	Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		160
	Item 9A:	Controls and Procedures		160
	Item 9B:	Other Information		163

PART III	Item 10:	Directors, Executive Officers and Corporate Governance		163
	Item 11:	Executive Compensation		175
	Item 12:	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		204
	Item 13:	Certain Relationships and Related Transactions, and Director Independence		206
	Item 14:	Principal Accountant Fees and Services		210

PART IV	Item 15:	Exhibits and Financial Statement Schedules		211

SIGNATURES				215

GLOSSARY OF TERMS

Unless the context otherwise requires, references below to “Atlas Energy Group, LLC,” “Atlas Energy Group,” “the Company,” “we,” “us,” “our” and “our company” refer to Atlas Energy Group, LLC and its consolidated subsidiaries. References below to “Atlas Energy” or “Atlas Energy, L.P.” refers to Atlas Energy, L.P. and its consolidated subsidiaries, unless the context otherwise requires.

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.

Bpd. Barrels per day.

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.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Developed acreage. 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.

Dry hole or well. An exploratory, development or extension well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil and gas well.

Dth. One dekatherm, equivalent to one million British thermal units.

Dth/d. Dekatherms per day.

Dry hole or well. An exploratory, development or extension well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil and gas well.

EBITDA. Net income (loss) before net interest expense, income taxes, and depreciation and amortization. EBITDA is considered to be a non-GAAP measurement.

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.

FASB. Financial Accounting Standards Board.

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.

Fractionation. The process used to separate a natural gas liquid stream into its individual components.

GAAP. Generally Accepted Accounting Principles.

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.

Mcfed. One Mcfe per day.

MMBbl. One million barrels of oil or other liquid hydrocarbons.

MMBoe. One million barrels of oil equivalent.

MMBtu. One million British thermal units.

MMcf. One million cubic feet.

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.

NYSE. The New York Stock Exchange.

Oil. Crude oil and condensate.

Productive well. A producing well or well that is found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil and gas well.

Proved developed reserves. 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 reserves. Proved oil and gas reserves are those quantities of oil and gas, 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 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 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.

PV-10. Present value of future net revenues. See the definition of “standardized measure.”

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.

Reservoir. A porous and permeable underground formation containing a natural accumulation of productive oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

SEC. Securities and Exchange Commission.

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 Securities and Exchange Commission (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.

Successful well. A well capable of producing oil and/or gas in commercial quantities.

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.

FORWARD-LOOKING STATEMENTS

The matters discussed in this report include forward-looking statements. 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:

•

our lack of operating history as a separate public company, and that our historical 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;

•

whether we are able to achieve some or all of the expected benefits of the separation from Atlas Energy;

•

the fact that 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;

•

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 differential between benchmark prices for oil and natural gas and wellhead prices that we and ARP achieve;

•

effects of partial depletion or drainage by earlier offset drilling on our and ARP’s acreage;

•

economic conditions and instability in the financial markets;

•

changes in the market price of our common units;

•

future financial and operating results;

•

resource potential;

•

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

•

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;

•

effects of debt payment obligations on the distributable cash;

•

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;

•

the effects of unexpected operational events and drilling conditions, and other risks associated with drilling operations;

•

access to sufficient amounts of carbon dioxide for tertiary recovery operations;

•

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;

•

restrictions on hydraulic fracturing;

•

ability to integrate operations and personnel from acquired businesses;

•

exposure to new and existing litigations;

•

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

•

development of alternative energy resources; and

•

the effects of a cyber event or terrorist attack.

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 “Item 1A: Risk Factors” of this annual report. 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.

PART I

ITEM 1:

BUSINESS

General

We are a Delaware limited liability company formed in October 2011. At December 31, 2014, we were wholly-owned by Atlas Energy, L.P. (“Atlas Energy”), a then publicly-traded Delaware master limited partnership (NYSE: ATLS). On February 27, 2015, Atlas Energy transferred its assets and liabilities, other than those related to its midstream assets, to us, and effected a pro rata distribution to its unitholders of our common units representing a 100% interest in us (the “Separation”). We refer to the assets and liabilities that were transferred to us by Atlas Energy in connection with the separation as “New Atlas”. Our common units began trading “regular-way” under the ticker symbol “ATLS” on the New York Stock Exchange on March 2, 2015. Concurrently with the distribution of our units, Atlas Energy and its remaining midstream interests merged with Targa Resources Corp. (“Targa”; NYSE: TRGP) and ceased trading.

As the Separation was not consummated until after the completion of the historical periods covered by this Form 10-K, we, as the registrant, have provided the combined consolidated financial statements of New Atlas. As such, the remainder of the discussion within this section will reflect the New Atlas business transferred to us on February 27, 2015.

Our assets, assuming the Separation had been completed as of December 31, 2014, consist of:

•

100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 27.7% limited partner interest (consisting of 20,962,485 common and 3,749,986 preferred limited partner units) in Atlas Resource Partners, L.P. (“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;

•

80.0% general partner interest and a 1.9% limited partner interest in the Development Subsidiary, a partnership that currently conducts natural gas and oil operations in the mid-continent region of the United States (the “Development Subsidiary”);

•

15.9% general partner interest and 12.0% limited partner interest in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, its general partner, which incubate new MLPs and invest in existing MLPs; and

•

direct natural gas development and production assets in the Arkoma Basin, which Atlas Energy acquired in July 2013 (“Direct Gas & Oil Production Assets” or “Direct”).

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. We, together with our predecessors and affiliates, have been involved in the energy industry since 1968. The Atlas Energy personnel which were responsible for managing our assets and capital raising continued to do so and became our employees upon completion of the Separation.

Atlas Resource Partners Overview

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, which was consummated on March 5, 2012.

Our ownership in ARP consists of the following:

•

all of the outstanding Class A units, representing 1,819,113 units at December 31, 2014, which entitles us to receive 2% of the cash distributed by ARP without any obligation to make further capital contributions to ARP;

•

all of the incentive distribution rights in ARP, which entitles 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; and

•

an approximate 27.7% limited partner ownership interest (20,962,485 common units and 3,749,986 preferred limited partner units) in ARP at December 31, 2014.

Our ownership of ARP’s incentive distribution rights entitle us to receive an increasing percentage of cash distributed by ARP as it reaches certain target distribution levels. The rights entitle us to receive the following:

•

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.

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 natural gas liquids properties. As of December 31, 2014, ARP’s estimated proved reserves were 1,429 Bcfe, including reserves net to ARP’s equity interest in its Drilling Partnerships. Of ARP’s estimated proved reserves, approximately 77% were proved developed and approximately 71% were natural gas. For the year ended December 31, 2014, ARP’s average daily net production was approximately 270.0 MMcfe. Through December 31, 2014, ARP owns production positions in the following areas:

•

ARP’s Barnett Shale and Marble Falls play in the Fort Worth Basin in northern Texas where it has ownership interests in approximately 715 wells and 399 Bcfe of total proved reserves with average daily production of 79.9 MMcfe for the year ended December 31, 2014;

•

ARP’s coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama, the Central Appalachian Basin in southern West Virginia and southwestern Virginia, and the County Line area of Wyoming where it has ownership interests in approximately 3,440 wells and 523 Bcfe of total proved reserves with average daily production of 120.8 MMcfe for the year ended December 31, 2014;

•

ARP’s Appalachia Basin where it has ownership interests in approximately 8,127 wells and 144 Bcfe of total proved reserves with average daily production of 40.7 MMcfe for the year ended December 31, 2014, including 280 wells in the Marcellus and Utica Shales;

•

ARP’s Eagle Ford Shale in southern Texas where it has ownership interests in approximately 24 wells and 64 Bcfe of total proved reserves with average daily production of 2.1 Bcfe for the year ended December 31, 2014;

•

ARP’s Rangely field in northwest Colorado where it has non-operated ownership interests in approximately 400 wells in the Rangely field and 176 Bcfe of total proved reserves with average daily production of 8.3 Bcfe for the year ended December 31, 2014;

•

ARP’s Mississippi Lime and Hunton plays in northwestern Oklahoma where we own 109 Bcfe of total proved reserves with average daily production of 12.7 MMcfe for the year ended December 31, 2014; and

•

ARP’s other operating areas, including the Chattanooga Shale in northeastern Tennessee, the New Albany Shale in southwestern Indiana and the Niobrara Shale in northeastern Colorado in which ARP has an aggregate 15 Bcfe of total proved reserves with average daily production of 5.4 MMcfe for the year ended December 31, 2014.

ARP seeks to create substantial value by executing a strategy of acquiring properties with stable, long-life production, relatively predictable decline curves and lower risk development opportunities. Since it began operations in March 2012, ARP has 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. (NASD: CRZO; “Carrizo”), for approximately $187.0 million (the “Carrizo Acquisition”). 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. (“Titan”), 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 “Titan Acquisition”). Net production from these assets at the date of acquisition was approximately 24 MMcfed, including approximately 370 Bpd of natural gas liquids. ARP believes there are over 300 potential undeveloped drilling locations on the Titan acreage.

•

Equal Mississippi Lime Acquisition – On April 4, 2012, ARP entered into an agreement with Equal Energy, Ltd. (NYSE: EQU; TSX: EQU; “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 “Equal Acquisition”). 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 (NYSE: DTE; “DTE”) 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 600 identified vertical drilling locations and further potential development opportunities through vertical down-spacing and horizontal drilling. The assets acquired from DTE are in close proximity to ARP’s other assets in the Barnett Shale.

•

EP Energy Acquisition. On July 31, 2013, ARP completed the acquisition of certain assets from EP Energy E&P Company, L.P (“EP Energy”) for approximately $709.6 million in net cash (the “EP Energy Acquisition”). The coal-bed methane producing natural gas assets included 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 in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming. ARP believes there are approximately 1,200 potential undeveloped drilling locations on the acreage acquired.

•

GeoMet Acquisition. On May 12, 2014, ARP completed the acquisition of certain assets from GeoMet, Inc. for approximately $97.9 million in cash, net of purchase price adjustments, with an effective date of January 1, 2014 (the “GeoMet Acquisition”). The coal-bed methane producing natural gas assets include approximately 70 Bcfe of proved reserves with over 400 active wells generating 22 MMcfed on the date of acquisition in the Central Appalachian Basin in West Virginia and Virginia.

•

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 reserves for $409.4 million in cash with an effective date of April 1, 2014 (the “Rangely Acquisition”). 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 90% oil, with the remainder coming from NGLs. Chevron Corporation (NYSE: CVX; “Chevron”) will continue as operator of the assets.

•

Eagle Ford Acquisition—On November 5, 2014, ARP and our Development Subsidiary 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 “Eagle Ford Acquisition”). The purchase price was $339.2 million, of which $179.5 million was paid at closing by ARP and $19.7 million was paid by our Development Subsidiary, 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. Our 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 our deferred portion of the purchase price with the issuance of its Class D Cumulative Redeemable Perpetual Preferred Units at a price of $25.00 per unit (“Class D ARP Preferred Units”). The acquisition has an effective date of July 1, 2014.

Development Subsidiary Overview

During the year ended December 31, 2013, Atlas Energy formed a new subsidiary partnership to conduct natural gas and oil operations initially in the mid-continent region of the United States, specifically in the Marble Falls formation in the Fort Worth Basin and the Mississippi Lime area of the Anadarko Basin in Oklahoma.

On November 5, 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 $339.2 million, of which $179.5 million was paid at closing by ARP and $19.7 million was paid by our Development Subsidiary, 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. Our Development Subsidiary will pay approximately $116.0 million of the deferred portion purchase price in four quarterly installments following closing.

At December 31, 2014, the Development Subsidiary had completed 2 wells in the Eagle Ford and 15 wells in the Marble Falls and Mississippi Lime. At December 31, 2014, after giving effect to the Separation, we owned an 1.9% limited partner interest in the Development Subsidiary and 80.0% of its outstanding general partner Class A units, which are entitled to receive 2% of the cash distributed without any obligation to make further capital contributions.

Lightfoot Overview

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, us, BlackRock Investment Management, LLC, Magnetar Financial LLC, CorEnergy Infrastructure Trust, Inc. and Triangle Peak Partners Private Equity, LP. As of December 31, 2014, after giving effect to the Separation, 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.

Direct Natural Gas and Oil Production Overview

On July 31, 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”). As a result of Arkoma Acquisition, and after giving effect to the Separation, 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, 2014.

Our operations include three reportable operating segments: ARP, New Atlas and Corporate and other (see “Item 8: Financial Statements and Supplementary Data – Note 16”).

SUBSEQUENT EVENTS

Term Loan Credit Facilities. On February 27, 2015, we entered into a Credit Agreement with Deutsche Bank AG New York Branch, as administrative agent, and the lenders from time to time party thereto (the “Credit Agreement”). The Credit Agreement provides for a Secured Senior Interim Term Loan Facility in an aggregate principal amount of $30 million (the “Interim Term Loan Facility”) and a Secured Senior Term A Loan Facility in an aggregate principal amount of approximately $97.8 million (the “Term A Loan Facility” and together with the Interim Term Loan Facility, the “Term Loan Facilities”). The Interim Term Loan Facility matures on August 27, 2015 and the Term A Loan Facility matures on February 26, 2016. Our obligations under the Term Loan Facilities are secured on a first priority basis by security interests in all of our material subsidiaries, including all equity interests directly held by us and all tangible and intangible property. Borrowings under the Term Loan Facilities bear interest, at our option, at either (i) LIBOR plus 7.5% (“Eurodollar Loans”) or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, in each case plus 6.5% (an “ABR Loan”). Interest is generally payable at interest payment periods selected by us for Eurodollar Loans and quarterly for ABR Loans.

We have the right at any time to prepay any borrowings outstanding under the Term Loan Facilities, without premium or penalty, provided the Interim Term Loan Facility is repaid prior to the Term A Loan Facility. Subject to certain exceptions, we may also be required to prepay all or a portion of the Term Loan Facilities in certain instances, including the following:

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if, at any time, the Recognized Value Ratio (as defined in the Credit Agreement) is less than 2.00 to 1.00, we must prepay the Term Loan Facilities and any revolving loans outstanding in an aggregate principal amount necessary to achieve a Recognized Value Ratio of greater than 2.00 to 1.00; the Recognized Value Ratio is equal to the ratio of the Recognized Value (the sum of the discounted net present values of the Loan Parties’ oil and gas properties and the values of the common units, Class A Units and Class C Units of ARP, determined as set forth in the Credit Agreement) to Total Funded Debt (as defined in the Credit Agreement);

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if we dispose of all or any portion of the Arkoma assets (as defined in the Credit Agreement), we must prepay the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds resulting from such disposition;

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if we or any of our restricted subsidiaries dispose of property or assets (including equity interests), we must repay the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds from such disposition or casualty event; and

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if we incur any debt or issue any equity, we must repay the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds of such issuances or incurrences of debt or issuances of equity.

The Credit Agreement 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 swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions. The Credit Agreement also requires that the Total Leverage Ratio (as defined in the Credit Agreement) be greater than (i) as of the last day of any fiscal quarter prior to the full repayment of the Interim Term Loan Facility, 3.75 to 1.00, and (ii) as of the last day of any quarter thereafter, 3.50 to 1.00.

Preferred Unit Purchase Agreement. On February 26, 2015, we entered into the Series A Preferred Unit Purchase Agreement (the “Series A Purchase Agreement”) with certain members of our management, two management members of the Board and an outside investor (the “purchasers”), pursuant to which, on February 27, 2015, we issued and sold an aggregate of 1.6 million of our newly created Series A convertible preferred units, with a liquidation preference of $25.00 per unit (the “Series A preferred units”), to the purchasers for a cash purchase price of $25.00 per unit (the “Private Placement”). We sold the Series A preferred units in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”). The Private Placement resulted in proceeds to us of $40.0 million. We used the proceeds to fund a portion of the $150.0 million cash transfer made by us to Atlas Energy required by the Separation agreement with Atlas Energy, which was a condition to the Separation and distribution of our common units (see “General”). The Series A Purchase Agreement contains customary terms for private placements, including representations, warranties, covenants and indemnities.

Atlas Resource Partners

Credit Facility Amendment. On February 23, 2015, ARP entered into a Sixth Amendment to the Second Amended and Restated Credit Agreement (the “Sixth Amendment”) with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, which amendment amends the Second Amended and Restated Credit Agreement (the “ARP Credit Agreement”), dated July 31, 2013. Among other things, the Sixth Amendment:

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reduces the borrowing base under the ARP Credit Agreement from $900.0 million to $750.0 million;

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permits the incurrence of second lien debt in an aggregate principal amount up to $300.0 million;

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permits an increase in the applicable margin on Eurodollar loans and ABR loans by 0.25% from previous levels if the borrowing base utilization (as defined in the ARP Credit Agreement) is less than 90%;

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following the next scheduled redetermination of the borrowing base, upon the issuance of senior notes or the incurrence of second lien debt, reduces the borrowing base by 25% of the stated amount of such senior notes or additional second lien debt; and

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revises the maximum ratio of Total Funded Debt to EBITDA to be (i) 5.25 to 1.0 as of the last day of the quarters ended on March 31, 2015, June 30, 2015, September 30, 2015, December 31, 2015 and March 31, 2016, (ii) 5.00 to 1.0 as of the last day of the quarters ended on June 30, 2016, September 30, 2016 and December 31, 2016, (iii) 4.50 to 1.0 as of the last day of the quarters ended on March 31, 2017 and (iv) 4.00 to 1.0 as of the last day of each quarter thereafter.

The Amendment was approved by the lenders and was effective on February 23, 2015.

Second Lien Term Loan Facility. On February 23, 2015, ARP entered into a Second Lien Credit Agreement (the “Second Lien Credit Agreement”) with Wilmington Trust, National Association, as administrative agent, and the lenders party thereto. The Second Lien Credit Agreement provides for a second lien term loan in an original principal amount of $250.0 million (the “Term Loan Facility”). The Term Loan Facility matures on February 23, 2020.

ARP has the option to prepay the Term Loan Facility at any time, and is required to offer to prepay the Term Loan Facility with 100% of the net cash proceeds from the issuance or incurrence of any debt and 100% of the excess net cash proceeds from certain asset sales and condemnation recoveries. ARP is also required to offer to prepay the Term Loan Facility upon the occurrence of a change of control. All prepayments are subject to the following premiums, plus accrued and unpaid interest:

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the make-whole premium (plus an additional amount if such prepayment is optional and funded with proceeds from the issuance of equity) for prepayments made during the first 12 months after the closing date;

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4.5% of the principal amount prepaid for prepayments made between 12 months and 24 months after the closing date;

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2.25% of the principal amount prepaid for prepayments made between 24 months and 36 months after the closing date; and

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no premium for prepayments made following 36 months after the closing date.

ARP’s obligations under the Term Loan Facility are secured on a second priority basis by security interests in all of its assets and those of its restricted subsidiaries (the “Loan Parties”) that guarantee ARP’s existing first lien revolving credit facility. In addition, the obligations under the Term Loan Facility are guaranteed by ARP’s material restricted subsidiaries. Borrowings under the Term Loan Facility bear interest, at ARP’s option, at either (i) LIBOR plus 9.0% or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, in each case plus 8.0% (an “ABR Loan”). Interest is generally payable at the applicable maturity date for Eurodollar loans and quarterly for ABR loans.

The Second Lien Credit Agreement contains customary covenants that limit ARP’s ability to make restricted payments, take on indebtedness, issue preferred stock, grant liens, conduct sales of assets and subsidiary stock, make distributions from restricted subsidiaries, conduct affiliate transactions and engage in other business activities. In addition, the Second Lien Credit Agreement contains covenants substantially similar to those in ARP’s existing first lien revolving credit facility, including, among others, restrictions on swap agreements, debt of unrestricted subsidiaries, drilling and operating agreements and the sale or discount of receivables.

Under the Second Lien Credit Agreement, ARP may elect to add one or more incremental term loan tranches to the Term Loan Facility so long as the aggregate outstanding principal amount of the Term Loan Facility plus the principal amount of any incremental term loan does not exceed $300.0 million and certain other conditions are adhered to. Any such incremental term loans may not mature on a date earlier than February 23, 2020.

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 New Atlas. Our direct gas and oil production results from certain coal-bed methane producing natural gas assets in the Arkoma Basin acquired by Atlas Energy on July 31, 2013 from EP Energy and wells drilled in the Marble Falls play by our Development Subsidiary. As of December 31, 2014, after giving effect to the Separation, we own a 1.9% limited partner interest in our 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.

Production Volumes

The following table presents our, ARP’s and our Development Subsidiary’s total net gas, oil and NGL production volumes and production per day during the years ended December 31, 2014, 2013 and 2012:


	Years Ended December 31,
	2014		2013		2012
Production per day:⁽¹⁾⁽²⁾
New Atlas Direct:
Natural gas (Mcfd)		11,528		5,085		—
Oil (Bpd)		—		—		—
NGLs (Bpd)		—		—		—

Total (Mcfed)		11,528		5,085		—

Development Subsidiary:
Natural gas (Mcfd)		691		21		—
Oil (Bpd)		117		7		—
NGLs (Bpd)		88		3		—

Total (Mcfed)		1,920		79		—


	Years Ended December 31,
	2014		2013		2012
Atlas Resource:
Natural gas (Mcfd)		226,526		158,886		69,408
Oil (Bpd)		3,436		1,329		330
NGLs (Bpd)		3,802		3,473		974

Total (Mcfed)		269,958		187,701		77,232

Total production per day:
Natural gas (Mcfd)		238,745		163,992		69,408
Oil (Bpd)		3,553		1,336		330
NGLs (Bpd)		3,891		3,476		974

Total (Mcfed)		283,406		192,866		77,232

⁽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.

Drilling Activity

The number of wells we, ARP and our Development Subsidiary 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 (after giving effect to the Separation).


	Years Ended December 31,
	2014		2013		2012
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		13		2		—
Net wells turned in line⁽¹⁾		13		2		—

Atlas Resource Partners:
Gross wells drilled		129		103		105
Our share of gross wells drilled⁽²⁾		67		66		42
Gross wells turned in line		119		117		154
Net wells turned in line⁽²⁾		64		80		43

⁽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.

Neither we, ARP nor the Development Subsidiary 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, ARP and the Development Subsidiary 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.

As of December 31, 2014, after giving effect to the Separation, we, ARP and the Development Subsidiary had the following ongoing drilling activities:


	Gross						Net
New Atlas Direct:	Spud		Total Depth		Completed		Spud		Total Depth		Completed
Mississippi Lime – Horizontal		7		2		1		3		1		1
Utica – Horizontal		4		—		—		1		—		—
Marble Falls – Vertical		—		9		3		—		3		1
Eagle Ford Horizontal		—		2		—		—		1		—

	Gross						Net
Development Subsidiary:	Spud		Total Depth		Completed		Spud		Total Depth		Completed
Mississippi Lime – Horizontal		—		—		—		—		—		—
Utica – Horizontal		—		—		—		—		—		—
Marble Falls – Vertical		—		—		—		—		—		—
Eagle Ford Horizontal		—		8		—		—		8		—

	Gross						Net
Atlas Resource Partners:	Spud		Total Depth		Completed		Spud		Total Depth		Completed
Mississippi Lime – Horizontal		7		2		1		3		1		1
Utica – Horizontal		4		—		—		2		—		—
Marble Falls – Vertical		—		9		3		—		3		1
Eagle Ford – Horizontal		—		2		—		—		2		—

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 our and ARP’s 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 Zone 4 (200 Leg), 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;

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Raton—ANR, Panhandle and NGPL;

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Black Warrior Basin—Southern Natural;

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Eagle Ford—Transco Zone 1;

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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. The oil and natural gas liquids production of ARP’s Rangely assets flows into a common carrier pipeline and is sold at prevailing market prices, less applicable transportation and oil quality differentials. 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.

For the year ended December 31, 2014, Tenaska Marketing Ventures, Chevron, Enterprise, and Interconn Resources LLC accounted for approximately 25%, 15%, 14% and 13% of 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 our 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 $1,000 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% to 12% per year determined on a cumulative basis, 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.

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 “Item 1A: 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 years ended 2014, 2013 and 2012, neither we nor our predecessors or affiliates experienced 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, ARP’s and our Development Subsidiary’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, ARP and our Development Subsidiary must comply with laws and regulations at the federal, state and local levels. These laws and regulations can restrict or affect our 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 threatened or 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 siting, drilling, completion, production, and plugging 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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requiring preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement with respect to operations affecting federal lands or leases.

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, ARP’s and our Development Subsidiary’s operating costs.

We believe that our, ARP’s and our Development Subsidiary’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 or their 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, ARP’s and our Development Subsidiary’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 , ARP’s and our Development Subsidiary’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 USEPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own more stringent requirements. Drilling fluids, 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 USEPA 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 , ARP’s and our Development Subsidiary’s operations are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we 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 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. The Comprehensive Environmental Response, Compensation, and Liability Act (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, ARP’s and our Development Subsidiary’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 believe that we, ARP and our Development Subsidiary 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 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. However, none of these spills or releases appears to be material to our, ARP’s and our Development Subsidiary’s 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 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, the federal regulations that implement the Clean Water Act, and analogous state laws and regulations 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 USEPA 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 our , ARP’s and our Development Subsidiary’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 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 concluded on November 14, 2014. USEPA is in the process of reviewing the more than 800,000 comments received on the proposed rule, and has indicated that a final rule may be issued in 2015. As drafted, this proposed rule may increase the costs of compliance and result in additional permitting requirements for some of our, ARP’s or our Development Subsidiary’s existing or future facilities. Additionally, USEPA’s Science Advisory Board released its review of USEPA’s Office of Research and Development’s draft “Connectivity of Streams and Wetlands to Downstream Waters: A Review and Synthesis of the Scientific Evidence” report issued October 17, 2014. USEPA released its final report publicly on January 15, 2015.

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, ARP’s and our Development Subsidiary’s operations are in substantial compliance with the requirements of the Clean Water Act.

Air Emissions. Our , ARP’s and our Development Subsidiary’s operations are subject to the federal Clean Air Act, as amended, the federal regulations that implement the Clean Air Act, 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. 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. 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. Various air quality regulations are periodically reviewed by USEPA and are amended as deemed necessary. USEPA may also issue new regulations based on changing environmental concerns.

Recent revisions to federal NSPS and NESHAP rules impose additional emissions control requirements and practices on our, ARP’s or our Development Subsidiary’s operations. Some of our 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 or revised requirements. These regulations may increase the costs of compliance for some facilities. Our, ARP’s and our Development Subsidiary’s failure to comply with these requirements could subject each of us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We believe that our, ARP’s and our Development Subsidiary’s operations are in substantial compliance with the requirements of the Clean Air Act and comparable state laws and regulations.

While we, ARP and our Development Subsidiary will likely be required to incur certain capital expenditures in the future for air pollution control equipment to comply with applicable regulations and to obtain and maintain operating permits and approvals for air emissions, we believe that our, ARP’s and our Development Subsidiary’s 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, ARP and our Development Subsidiary are subject to the requirements of the federal Occupational Safety and Health Act, or “OSHA,” and comparable state statutes. The OSHA hazard communication standard, USEPA 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 , ARP’s and our Development Subsidiary’s operations. We believe that we are all 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, ARP’s and our Development Subsidiary’s businesses. However, Congress has been actively considering climate change legislation. More directly, USEPA has begun regulating greenhouse 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), USEPA 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, USEPA has promulgated two rules that will affect our , ARP’s and our Development Subsidiary’s businesses.

First, USEPA 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 ruled that the PSD program and Tailoring Rule applied 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 , ARP’s and our Development Subsidiary’s operations.

Second, USEPA 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. This subpart was most recently revised in November 2014, when USEPA finalized changes to calculation methods, monitoring and data reporting requirements, and other provisions. Shortly thereafter, in December 2014, USEPA proposed additional revisions to this subpart for public comment. In general, the Greenhouse Gas Reporting Rule requires certain industry sectors that emit greenhouse gases above a specified threshold to report greenhouse gas emissions to USEPA 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, ARP and our Development Subsidiary to determine whether the greenhouse gas reporting applies and if so, to calculate and report greenhouse gas emissions.

In addition to these existing rules, the Obama Administration announced in January 2015 that it is developing additional rules to curb greenhouse gas emissions from the oil and gas sector, as part of a new national strategy for reducing methane emissions from the sector by 40 – 45% from 2012 levels by the year 2025. Among other steps being taken as part of this national methane strategy, USEPA is expected to build on the 2012 NSPS in a rulemaking action aimed at reducing both methane and VOC emissions from the oil and gas sector.

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, ARP’s and our Development Subsidiary’s businesses to the extent that they either decrease the demand for other carbon-based fuels or position natural gas as a favored fuel. However, compliance with recently revised federal air rules, in addition to prospective compliance with the Obama Administration’s yet to be proposed rules to significantly reduce greenhouse gas emissions from the oil and gas sector, could adversely impact the natural gas industry and our businesses.

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 , ARP’s and our Development Subsidiary’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, ARP’s and our Development Subsidiary’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, ARP’s and our Development Subsidiary’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 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, USEPA published a draft “Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels” on May 10, 2012. . In February 2014, USEPA 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 USEPA’s previous draft guidance, a factsheet and a memorandum to USEPA’s regional offices regarding implementation of the guidance. The process for implementing USEPA’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 111^th, 112^th, and 113^th 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. The Frac Act was recently re-introduced in the current 114^th 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, ARP and our Development Subsidiary.

We believe our, ARP’s and our Development Subsidiary’s 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 and our Development Subsidiary conduct its natural gas extraction activities in certain formations where hydrogen sulfide may be, or is known to be, present. ARP and our Development Subsidiary employ numerous safety precautions at their operations to ensure the safety of their employees. There are various federal and state environmental and safety requirements for handling sour gas, and ARP and our Development Subsidiary are 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, ARP’s or our Development Subsidiary’s 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, ARP or our Development Subsidiary can produce from our wells or limit the number of wells or the locations at which we 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 2014, the impact fee for qualifying unconventional horizontal wells spudded during 2014 was $50,300 per well, while the impact fee for unconventional vertical wells was $10,100 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 , ARP’s and our Development Subsidiary’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 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 oil produced and an oil field clean up regulatory fee of $0.000667 per Mcf of gas produced and $.00625 per barrel of crude. New Mexico imposes, among other taxes, a severance tax of up to 3.75% of the value of oil

and gas produced, a conservation tax of up to 0.24% 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, up to 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 on our , ARP’s and our Development Subsidiary’s businesses.

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 believe we, ARP and our Development Subsidiary have been in compliance with OPA, noncompliance could result in varying civil and criminal penalties and liabilities.

A number of federal agencies, including USEPA and the Department of Interior, are currently evaluating a variety of environmental issues related to hydraulic fracturing. For example, USEPA is conducting a study that evaluates any potential effects of hydraulic fracturing on drinking water and ground water. USEPA released a progress report on this study on December 21, 2012 that did not provide any results or conclusions. On December 9, 2013, USEPA’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 USEPA’s study were published in July 2014. Research results are expected to be released in draft form for review by the public and USEPA Science Advisory Board. USEPA has not provided a specific date for completion of the draft report after peer review, which may occur in 2015. 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 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 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.

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 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, ARP’s or our Development Subsidiary’s 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, ARP’s and our Development Subsidiary’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

We employed approximately 670 persons as of February 27, 2015, 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.

Available Information

We make our periodic reports under the Securities Exchange Act of 1934, including our registration statement on Form 10, our annual report on Form 10-K, our current reports on Form 8-K, and any amendments to those reports, available through our website at www.atlasenergy.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. To view these reports, click on “Investor Relations”, then “SEC Filings”. You may also receive, without charge, a paper copy of any such filings by request to us at Park Place Corporate Center One, 1000 Commerce Drive – Suite 400, Pittsburgh, Pennsylvania 15275, telephone number (412) 489-0006. A complete list of our filings is available on the Securities and Exchange Commission’s website at www.sec.gov. Any of our filings is also available at the Securities and Exchange Commission’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The Public Reference Room may be contacted at telephone number (800) 732-0330 for further information.

ITEM 1A:

RISK FACTORS

You should carefully consider each of the following risks, which we believe are the principal risks that we face and of which we are currently aware, and all of the other information in this report. Some of the risks described below relate to our, ARP’s and our Development Subsidiary’s businesses, while others relate principally to the securities markets and ownership of our common units. 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. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In such case, the trading price of our common units could decline.

Risks Relating to Our Business

We have no operating history as a separate public company, and our historical 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 annual report refers to our business as operated by and integrated with Atlas Energy and is derived from the consolidated financial statements and accounting records of Atlas Energy. Therefore, the historical information 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:

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Before 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, 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 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.

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The cost of capital for our business may be higher than Atlas Energy’s cost of capital prior to the Separation.

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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.

We may not achieve some or all of the expected benefits of the Separation from Atlas Energy.

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

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The Separation will facilitate deeper understanding by investors of the different businesses of Atlas Energy and us, 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 us to purchase, and to assist ARP in purchasing, developed and undeveloped resources to accelerate growth of our natural gas and oil production and development business. Current industry trends have created a significant opportunity for us 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.

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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.

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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.

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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, 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.

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.

Our primary assets are our partnership interests, including the IDRs, in ARP. The amount of cash that ARP can distribute to its partners, including us, principally depends upon the amount of cash it generates from its operations, which will fluctuate from time to time and will depend on, among other things:

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the amount of natural gas and oil ARP produces;

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

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the level of ARP’s operating costs;

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

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the results of ARP’s hedging activities;

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

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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:

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

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the cost of acquisitions, if any;

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fluctuations in ARP’s working capital needs;

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timing and collectability of receivables;

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restrictions on distributions imposed by lenders;

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

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the amount, if any, of cash reserves we establish in our discretion as ARP’s general partner for the proper conduct of ARP’s business.

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.

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

Our and ARP’s cash distribution policies, consistent with the terms of our limited liability company agreement and ARP’s limited partnership agreement, require that we distribute all of our available cash quarterly. However, our cash distribution policies are subject to the following restrictions and limitations and may be changed at any time, including in the following ways:

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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.

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Our cash distribution policies are subject to restrictions on distributions under our credit facilities, such as material financial tests and covenants and limitations on paying distributions during an event of default.

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Our board of directors has the discretion to establish reserves for the prudent conduct of our and ARP’s business and for future cash distributions to our and ARP’s unitholders. The establishment of those reserves could result in a reduction in future cash distributions to our and ARP’s unitholders.

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Our limited liability company agreement, including the cash distribution policy contained in it, may be amended by a vote of the holders of a majority of our common units. ARP’s partnership agreement may be similarly amended.

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Even if our cash distribution policies are not amended, the decision to make any distribution is at the discretion of our board of directors.

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We and ARP can issue additional units, including units that are senior to our respective common units, without the consent of our unitholders, subject to certain limitations under existing NYSE listing rules, and these additional units would dilute our common unitholders’ ownership interests in us and our ownership interest in ARP.

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Under Delaware law, neither we nor ARP may 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 policies and our ability to change them, 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.

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, and we may not have enough cash to meet our needs if any of the following events occur:

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an increase in operating expenses;

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an increase in general and administrative expenses;

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

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an increase in working capital requirements.

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.

Natural gas and oil prices fluctuate widely, and low prices for an extended period would likely have a material adverse impact on our business.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and oil, which have recently declined substantially. Lower commodity prices may reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results and could result in an impairment charge. Because our reserves are predominantly natural gas, changes in natural gas prices have a more significant impact on our financial results.

Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include the following:

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the levels and location of natural gas and oil supply and demand and expectations regarding supply and demand, including the potential long-term impact of an abundance of natural gas and oil (such as that produced from our Marcellus Shale properties) on the domestic and global natural gas and oil supply;

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the level of industrial and consumer product demand;

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weather conditions;

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fluctuating seasonal demand;

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political conditions or hostilities in natural gas and oil producing regions, including the Middle East, Africa and South America;

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

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the price level of foreign imports;

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actions of governmental authorities;

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the availability, proximity and capacity of gathering, transportation, processing and/or refining facilities in regional or localized areas that may affect the realized price for natural gas and oil;

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inventory storage levels;

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the nature and extent of domestic and foreign governmental regulations and taxation, including environmental and climate change regulation;

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the price, availability and acceptance of alternative fuels;

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technological advances affecting energy consumption;

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speculation by investors in oil and natural gas;

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variations between product prices at sales points and applicable index prices; and

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overall economic conditions, including the value of the U.S. dollar relative to other major currencies.

These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of natural gas and oil. 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, 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 March 23, 2015, the NYMEX Henry Hub natural gas index price ranged from a high of $3.23 per MMBtu to a low of $2.58 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $53.53 per Bbl to a low of $43.46 per Bbl. If natural gas and oil prices decline significantly for a sustained period of time, the lower prices may adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations.

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

Our, ARP’s and our Development Subsidiary’s 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, ARP’s and our Development Subsidiary’s 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, ARP’s and our Development Subsidiary’s 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 to the extent required and on acceptable terms. Disruptions in the capital and credit markets could negatively affect our, ARP’s and our Development Subsidiary’s access to liquidity needed for our businesses and affect flexibility to react to changing economic and business conditions. We 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 businesses.

A weakening of the current economic situation could have an adverse impact on producers, key suppliers or other customers, or on our or ARP’s lenders, causing them to fail to meet their obligations. Market conditions could also affect our derivative instruments. If a counterparty is unable to perform its obligations and the derivative instrument is terminated, our and ARP’s 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.

Restrictions in our term loan credit facility could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

Our term loan credit facility limits our ability to, among other things:

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incur or guarantee additional debt;

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redeem or repurchase units or make distributions under certain circumstances;

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make certain investments and acquisitions;

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incur certain liens or permit them to exist;

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enter into certain types of transactions with affiliates;

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merge or consolidate with another company; and

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transfer, sell or otherwise dispose of assets.

Our term loan credit facility also contains covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet any such ratios and tests.

The provisions of our term loan credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our term loan credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

Our debt obligations could restrict our ability to pay cash distributions and have a negative impact on our financing options and liquidity position.

Our debt obligations could have important consequences to us and our investors, including:

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requiring a substantial portion of our cash flow to make interest payments on this debt;

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

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

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increasing our vulnerability to general adverse economic and industry conditions;

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reducing the cash flow available to fund capital expenditures and other corporate purposes and to grow our business;

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limiting our flexibility in planning for, or reacting to, changes in our business and the industry;

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placing us at a competitive disadvantage relative to our competitors that may not be as leveraged with debt;

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limiting our ability to borrow additional funds as needed or take advantage of business opportunities as they arise; and

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limiting our ability to pay cash distributions.

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

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 ARP may use financial and physical hedges for production. Physical hedges are not deemed hedges for accounting purposes because they require firm delivery of natural gas and oil and are considered normal sales of natural gas and oil. We generally limit these arrangements to smaller quantities than those we project to be available at any delivery point.

In addition, we and ARP 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. In addition, these arrangements expose us to risks of financial loss if, among other circumstances:

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production is substantially less than expected

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a counterparty is unable to satisfy its obligations; or

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there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.

In addition, it is not always possible to engage in a derivative transaction that completely mitigates exposure to commodity prices and interest rates. Our 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.

The failure by counterparties to our derivative risk management activities to perform their obligations could have a material adverse effect on our results of operations.

The use of derivative risk management transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. If any of these counterparties were to default on its obligations under our derivative arrangements, such a default could have a material adverse effect on our results of operations, and could result in a larger percentage of our future production being subject to commodity price changes.

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 businesses.

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 are implemented through regulation, primarily through rules adopted by the Commodity Futures Trading Commission. Many market participants are 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 are subject to new reporting and recordkeeping requirements. The new regulations may require us to comply with certain clearing and trade-execution requirements in connection with our existing or future derivative activities. As commercial end-users which use swaps to hedge or mitigate commercial risk, rather than for speculative purposes, we and ARP 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.

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 derivative contracts in existence at that time; and increase our 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’ 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:

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

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an inability to successfully integrate the businesses acquired;

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

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

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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;

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

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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;

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unforeseen difficulties encountered in operating in new geographic areas;

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customer or key employee losses at the acquired businesses; and

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the failure to realize expected growth or profitability.

Our decision to acquire oil and natural gas properties depends in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses, seismic data and other information, the results of which are often inconclusive and subject to various interpretations. 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.

We may be unsuccessful in integrating the operations from any future acquisitions with our operations and in realizing all of the anticipated benefits of these acquisitions.

The integration of 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:

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operating a significantly larger combined entity;

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

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integrating personnel with diverse business backgrounds and organizational cultures;

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consolidating operational and administrative functions;

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

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

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customer or key employee loss from the acquired businesses;

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a significant increase in indebtedness; and

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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 business 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. 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 receive 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 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 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 us as 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. 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 you and a reduction in the value of our common units.

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 common 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 common 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 merger with Targa Resources. We were still part of Atlas Energy at that 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.

Atlas Energy may fail to perform under various transaction agreements that were executed as part of the Separation.

In connection with the Separation, we and Atlas Energy entered 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 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 govern the relationship between us and Atlas Energy subsequent to the completion of the Separation. We rely on Atlas Energy to satisfy its performance and payment obligations under these agreements. If Atlas Energy and/or Targa Resources is unable to satisfy Atlas Energy’s obligations under these agreements, including indemnification obligations, we could incur operational difficulties or losses.

A cyber incident or terrorist attack could result in information theft, data corruption, operational disruption and/or financial loss.

We have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves, as well as other activities related to our businesses. Strategic targets, such as energy-related assets, may be at greater risk of future cyber or terrorist attacks than other targets in the United States. Deliberate attacks on, or security breaches in our systems or infrastructure, or the systems or infrastructure of third parties or the cloud, could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, challenges in maintaining our books and records and other operational disruptions and third party liability. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

Risks Relating to Our, ARP’s and our Development Subsidiary’s Exploration and Production Operations

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

We, ARP and our Development Subsidiary 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, ARP’s and our Development Subsidiary’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 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, ARP or our Development Subsidiary have. All of these challenges could make it more difficult for us to execute our growth strategies. We, ARP and our Development Subsidiary 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, ARP’s and our Development Subsidiary’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 can.

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

Increased demand for drilling rigs, equipment and crews, due to increased activity by participants in our, ARP’s and our Development Subsidiary’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 ability to drill the wells and conduct the operations that we currently have planned. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our, ARP’s or our Development Subsidiary’s revenues.

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

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

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

The natural gas and oil industry is capital intensive. Because we distribute our available cash to our unitholders each quarter in accordance with the terms of our limited liability company agreement, and ARP distributes its available cash to its unitholders, we expect that each of us 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, ARP or our Development Subsidiary are 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 may be unable to increase or maintain our inventories of properties and reserve base, or be forced to curtail drilling or other activities. This could cause our, ARP’s and our Development Subsidiary’s revenues to decline and diminish its and our ability to service any debt that any of us may have at such time. If we, ARP or our Development Subsidiary do not make sufficient or effective expansion capital expenditures, including with funds from third-party sources, we will be unable to expand our respective business operations, and may not generate sufficient revenue or have sufficient available cash to pay distributions on our units.

We, ARP and our Development Subsidiary depend on certain key customers for sales of our 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 cease to purchase or process natural gas, crude oil and NGLs from us, our, ARP’s and our Development Subsidiary’s revenues and cash available for distribution could decline.

We, ARP and our Development Subsidiary market the majority of our natural gas production to gas marketers directly or to third-party plant operators who process and market our gas. Crude oil produced from our, ARP’s and our Development Subsidiary’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. For the year ended December 31, 2014, Tenaska Marketing Ventures, Chevron, Enterprise and Interconn Resources LLC accounted for approximately 25%, 15%, 14% and 13% of natural gas, crude oil and natural gas liquids production revenue, respectively, with no other single customer accounting for more than 10% for this period. To the extent these and other key customers reduce the amount of natural gas, crude oil and NGLs they purchase from us, ARP or our Development Subsidiary, our revenues and cash available for distributions to unitholders could temporarily decline in the event we are 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, ARP or our Development Subsidiary receive for our production could significantly reduce our cash available for distribution and adversely affect our financial condition.

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

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

As of December 31, 2014, leases covering approximately 40,103 of ARP’s 794,030 net undeveloped acres, or 5.1%, are scheduled to expire on or before December 31, 2015. An additional 0.7% of ARP’s net undeveloped acres are scheduled to expire in 2016 and 1.6% in 2017. If ARP is unable to renew these leases or any leases scheduled for expiration beyond their expiration date, on favorable terms, ARP will lose the right to develop the acreage that is covered by an expired lease.

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

Our, ARP’s and our Development Subsidiary’s drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas and oil can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our, ARP’s or our Development Subsidiary’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, ARP’s and our Development Subsidiary’s receipt of drilling and production revenues, thereby reducing our, ARP’s and our Development Subsidiary’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, ARP and our Development Subsidiary maintain insurance against various losses and liabilities arising from operations, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we 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, ARP’s or our Development Subsidiary’s results of operations.

Unless we, ARP and our Development Subsidiary replace our 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, ARP’s and our Development Subsidiary’s natural gas and oil reserves and production and, therefore, cash flow and income are highly dependent on our success in efficiently developing and exploiting reserves and economically finding or acquiring additional recoverable reserves. Our, ARP’s and our Development Subsidiary’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, including, 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 commodity prices could subject our, ARP’s and our Development Subsidiary’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, ARP and our Development Subsidiary test our 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 economic interests and our 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 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 commodities may cause the carrying value of our, ARP’s and our Development Subsidiary’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.

Our, ARP’s and our Development Subsidiary’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, ARP’s and our Development Subsidiary’s estimates of future reserves and estimates of future production for our acquisitions are initially based on detailed information furnished by the sellers and subject to review, analysis and adjustment by our 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 perform a review of the acquired properties that we believe is generally consistent with industry practices. Nevertheless, such a review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we 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 pay to acquire oil and natural gas properties may exceed the value we 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, ARP or our Development Subsidiary 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 from such risks, which may result in unexpected liabilities and costs to us.

We, ARP and our Development Subsidiary 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 to review in detail every individual property involved in a potential acquisition. In making acquisitions, we generally focus most of the title, environmental and valuation efforts on the properties that we 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 to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not inspect in detail every well that any of us acquires. 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 perform a detailed inspection. Any unidentified problems could result in material liabilities and costs that negatively affect our, ARP’s or our Development Subsidiary’s financial condition and results of operations.

Even if we 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, ARP’s or our Development Subsidiary’s financial condition and results of operations.

Any production associated with the assets ARP acquired in the Rangely acquisition will decline if the operator’s access to sufficient amounts of carbon dioxide is limited.

Production associated with the assets ARP acquired in the Rangely acquisition is dependent on CO₂ tertiary recovery operations in the Rangely Field. The crude oil and NGL production from these tertiary recovery operations depends, in large part, on having access to sufficient amounts of CO₂. The ability to produce oil and NGLs from these assets would be hindered if the supply of CO₂ was limited due to, among other things, problems with the Rangely Field’s current CO₂ producing wells

and facilities, including compression equipment, or catastrophic pipeline failure. Any such supply limitation could have a material adverse effect on the results of operations and cash flows associated with these tertiary recovery operations. ARP’s anticipated future crude oil and NGL production from tertiary operations is also dependent on the timing, volumes and location of CO₂ injections and, in particular, on the operator’s ability to increase its combined purchased and produced volumes of CO₂ and inject adequate amounts of CO₂ into the proper formation and area within the Rangely Field.

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

Good and clear title to our, ARP’s and our Development Subsidiary’s oil and gas properties is important. Although we 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, ARP or our Development Subsidiary from such properties.

Federal 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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On December 17, 2014, New York Governor Andrew Cuomo’s administration said it would ban hydraulic fracturing for shale gas development throughout the state. Dr. Howard Zucker, the Acting Commissioner of Health, announced that the state Department of Health completed its long-awaited public health review report, which recommended prohibiting hydraulic fracturing in New York. Dr. Zucker cited significant uncertainties regarding risks to public health in concluding that hydraulic fracturing should not proceed in New York until more research is completed. Based upon the Department of Health report, New York State Department of Environmental Conservation Commissioner Joe Martens announced that it will soon issue a legally-binding findings statement that will prohibit hydraulic fracturing in the state. Martens noted that the public health risks associated with hydraulic fracturing outweigh its potential economic benefits, particularly in light of the number of municipalities that have banned natural gas drilling within their borders.

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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, which we refer to as 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, 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). PADEP has indicated that it will bifurcate its 25 Pa. Code Chapter 78 regulations into two parts as a result of a 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. In January 2015, PADEP issued the results of its Technologically Enhanced Naturally Occurring Radioactive Materials Study, which analyzed levels of radioactivity

associated with oil and gas development in Pennsylvania. Initiated in January 2013, the study evaluated radioactivity levels in flowback waters, treatment solids, and drill cuttings, in addition to the transportation, storage and disposal of these materials. According to the study, PADEP concluded that there is little potential for harm to workers or the public from radiation exposure due to oil and gas development, as well as provided recommendations for further study to be conducted.

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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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For wells spudded January 1, 2014 and after, 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. Recent Railroad Commission rules and regulations focus on prevention of waste, as evidenced by regulations relating to the commercial recycling of produced water and/or hydraulic fracturing flowback fluid approved in September 2012, and more stringent permitting for venting/flaring of casinghead gas and gas well gas beginning in January 2014.

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A new West Virginia rule that became effective July 1, 2013 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 2014, West Virginia revised its solid waste regulations to allow landfills to increase their tonnage limits specifically for natural gas drilling wastes, along with requiring more stringent controls and radiation testing of landfills located in the state.

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 rulings has been increased regulatory impediments and disputes at the local government level, as well as validity challenges initiated by private landowners alleging that local ordinances do not adequately protect health, safety, and welfare.

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. On October 16, 2014, the New York Court of Appeals denied a request by the petitioner – the bankruptcy trustee for Norse Energy – to re-hear arguments in the case. 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 regarding unconventional gas development. EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel as an additive under the Safe Drinking Water Act. In May 2012, EPA issued draft permitting guidance for oil and gas hydraulic fracturing activities using diesel fuel. In February 2014, EPA released its revised final guidance document on Safe Drinking Water Act underground injection control permitting for hydraulic fracturing using diesel fuels, along with responses to selected substantive public comments on EPA’s previous draft guidance, a fact sheet and a memorandum to EPA’s regional offices regarding implementation of the guidance. The process for implementing EPA’s final guidance document may vary across the states depending on the regulatory authority responsible for implementing the Safe Drinking Water Act 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, EPA is currently studying the potential environmental effects of hydraulic fracturing on drinking water and groundwater.

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, 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 EPA’s study were published in July 2014. Research results are expected to be released in draft form for review by the public and EPA’s Science Advisory Board. EPA has not provided a specific date for completion of the draft report after peer review, which may occur in 2015. In 2013, 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, EPA has yet to propose the draft water quality criteria document and it has not provided an updated timeframe for the proposal. 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. EPA proposed in that same document a detailed study of centralized waste treatment facilities that accept oil and gas extraction wastewater. The public comment period on the Preliminary 2014 Effluent Guidelines Program Plan closed on November 17, 2014. EPA is evaluating the comments submitted and will next prepare and issue the Final 2014 Effluent Guidelines Program Plan. 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 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 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. The next Annual Energy Outlook is reported to be in March 2015 by U.S. Energy Information Administration. 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 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 the following:

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additional permitting requirements and permitting delays;

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increased costs;

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changes in the way operations, drilling and/or completion must be conducted;

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increased recordkeeping and reporting; and

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restrictions on the types of additives that can be used.

Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we, ARP or our Development Subsidiary are ultimately able to produce from our reserves.

The third parties on whom we, ARP and our Development Subsidiary 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, ARP and our Development Subsidiary 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 pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our, ARP’s or our Development Subsidiary’s business, financial condition, results of operations and our ability to make distributions to unitholders.

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas, while potential physical effects of climate change could disrupt our operations and cause us to incur significant costs in preparing for or responding to those effects.

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases, or greenhouse gases, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of greenhouse gas emissions. Facilities required to obtain Prevention of Significant Deterioration permits because of their potential criteria pollutant emissions will be required to comply with “best available control technology” standards for greenhouse gases. These regulations could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.

While Congress has from time to time considered legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of adopted legislation to reduce greenhouse gas emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing greenhouse gas emissions by means of cap and trade programs that typically require major sources of greenhouse gas emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those greenhouse gases. In addition, the Obama Administration announced its Climate Action Plan in 2013, which, among other things, directs federal agencies to develop a strategy for the reduction of methane emissions, including emissions from the oil and gas industry. As part of the Climate Action Plan, the Obama Administration also announced that it intends to adopt additional regulations to reduce emissions of greenhouse gases and to encourage greater use of low carbon technologies in the coming years. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our, ARP’s and our Development Subsidiary’s equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations.

Significant physical effects of climate change have the potential to damage our facilities, disrupt our production activities and cause us 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, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities either because of climate-related damages to our facilities or our 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 our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We 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.

Our, ARP’s and our Development Subsidiary’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 are unable to dispose of the flowback and produced water from the strata at a reasonable cost and within applicable environmental rules, our ability to produce gas economically and in commercial quantities could be impaired.

A significant portion of our, ARP’s and our Development Subsidiary’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, ARP’s and our Development Subsidiary’s operations and financial performance. For example, the 2012 Oil and Gas Act requires the development, submission and approval of a water management plan before withdrawing or using water from water sources in Pennsylvania to drill or hydraulically fracture 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, we will be required to develop a Water Conservation Plan and obtain a withdrawal permit for that project. West Virginia also requires that if a certain amount of water is withdrawn water management plans are required and/or registration and reporting requirements are triggered.

Our 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 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, ARP and our Development Subsidiary to incur increased capital expenditures and operating costs.

In August 2012, EPA published final rules that established new and revised requirements for emissions from oil and natural gas production and natural gas processing operations. Specifically, EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and National Emission Standards for Hazardous Air Pollutants to address emissions of hazardous air pollutants frequently associated with oil and natural gas production, processing, transmission and storage activities. The New Source Performance Standards require operators, beginning January 1, 2015, to reduce volatile organic compounds emissions from oil and natural gas production facilities by conducting “green completions” for hydraulic fracturing, that is, recovering rather than venting or flaring the gas and NGLs that come to the surface during completion of the fracturing process. The New Source Performance Standards also established new notification and reporting requirements, more stringent leak detection standards for natural gas processing plants, and specific requirements regarding emissions from compressors, storage tanks, and other sources. In 2013, EPA made significant changes to the New Source Performance Standards applicable to storage vessels, and in December 2014, EPA finalized additional revisions to the New Source Performance Standards, including revisions to the green completion requirements. Compliance with recently revised New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our, ARP’s and our Development Subsidiary’s businesses.

States are also proposing more stringent requirements for emissions from well sites and compressor stations. For example, in August 2013, Pennsylvania revised its list of sources exempt from air permitting requirements such that previously exempted types of sources associated with unconventional oil and gas exploration and production now are required to demonstrate compliance with specific criteria (e.g. emission limits, monitoring and recordkeeping) in order to claim the permit exemption. PADEP has since released implementation instructions that expand the list of information which operators must submit in a compliance demonstration in order to rely on the exemption. Additionally, PADEP issued a revised General Permit for Natural Gas Compression and/or Processing Facilities in January 2015 that requires the permittee to annually certify its compliance with the terms and conditions of the general permit. In April 2014, Ohio revised its current General Permit for Natural Gas Production Operations to cover emissions from completion activities. In 2013, West Virginia issued General Permit 70-A for natural gas production facilities at the well site. In February 2015, West Virginia issued a draft General Permit 80-A to replace General Permit 70-A and other exiting general permits for natural gas compressor and dehydration facilities.

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. Pennsylvania’s Oil and Gas Act of 2012, passed in February 2012, implemented an impact fee for unconventional wells drilled in the Commonwealth. 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 2014, the impact fee for qualifying unconventional horizontal wells spudded during 2014 was $50,300 per well and the impact fee for unconventional vertical wells was $10,100 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 $1.0 million for the year ended December 31, 2014. If new laws implementing additional taxes and fees become applicable, our operating costs may materially increase.

President Obama’s budget proposals for fiscal year 2016 include proposed provisions with significant tax consequences. The proposed budget, if enacted, would repeal over $4 billion per year in U.S. tax subsidies to oil, gas and other fossil fuel producers.

Because we, ARP and our Development Subsidiary handle natural gas, NGLs and oil, we 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, ARP and our Development Subsidiary 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:

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

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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;

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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, ARP’s and our Development Subsidiary’s facilities;

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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, ARP or our Development Subsidiary or at locations to which we have sent waste for disposal; and

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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 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, ARP or our Development Subsidiary 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 EPA and/or the appropriate state agency. In some cases, 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. 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, particularly for activities occurring in West Virginia. We also understand that 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, ARP’s or our Development Subsidiary’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 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, ARP’s or our Development Subsidiary’s wells could subject us 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 possibility exists that stricter laws, regulations or enforcement policies may be enacted or adopted and could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover remediation costs under our insurance policies.

We, ARP and our Development Subsidiary 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, ARP’s and our Development Subsidiary’s operations are regulated extensively at the federal, state and local levels. The regulatory environment in which we operate includes, 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 activities will be subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our 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, the 2012 Oil and Gas Act imposes significant, costly requirements on the natural gas industry, including the imposition of increased bonding requirements and impact fees for unconventional gas wells, based on the price of natural gas and the age of the unconventional gas well. Proposed regulations associated with this legislation were published for public comment by the PADEP 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 has developed new aboveground storage tank laws that are being applied broadly and impose stringent requirements that affect the natural gas industry. We 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, ARP’s or our Development Subsidiary’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, ARP’s and our Development Subsidiary’s engineers prepare estimates of our proved reserves. Over time, our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of our 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 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, ARP’s and our Development Subsidiary’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 reserve estimates are based, as described above, often result in the actual quantities of natural gas and oil we ultimately recover being different from the reserve estimates.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of the estimated natural gas and oil reserves. We 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 and oil properties will also be affected by factors such as:

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actual prices received for natural gas and oil;

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the amount and timing of actual production;

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the amount and timing of capital expenditures;

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supply of and demand for natural gas and oil; and

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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 and oil 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 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 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 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 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 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 $166.8 in 2014, $150.0 million in 2013 and $127.1 million in 2012. In the future, ARP may not be successful in raising funds through these Drilling Partnerships at these 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 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 2016 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 year ended December 31, 2014, $5.3 million of ARP’s revenues, net of corresponding production costs, were subordinated, which reduced ARP’s cash distributions received from the Drilling Partnerships. For the year ended December 31, 2013, the subordinated amount, net or corresponding production costs, was $9.6 million and for the year ended December 31, 2012, it was $6.3 million.

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 and our unit price may fluctuate significantly. If the unit price declines, you could lose a significant part of your investment.

We cannot guarantee that an active trading market will develop or be sustained for our common units. 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:

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

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

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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;

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fluctuations in natural gas and oil prices;

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changes in market valuations of similar companies;

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departures of key personnel;

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commencement of or involvement in litigation;

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

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variations in the amount of our quarterly cash distributions;

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future issuances and sales of our units; and

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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.

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, ARP’s and our Development Subsidiary’s financing costs to increase accordingly. As with other yield-oriented securities, our unit price is affected by the level of our, ARP’s and our Development Subsidiary’s cash distributions 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, ARP’s and our Development Subsidiary’s ability to issue additional equity or to incur debt to make acquisitions or for other purposes and could affect our, ARP’s and our Development Subsidiary’s ability to make cash distributions at our 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.

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 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:

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our unitholders’ proportionate ownership interest in us will decrease;

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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;

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the ratio of taxable income to distributions may increase; and

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the market price of the common units may decline.

In addition, the payment of distributions on any additional units may increase the risk that we will not be able to make distributions at our prior per unit distribution levels. To the extent new units are senior to our common units, their issuance will increase the uncertainty of the payment of distributions on our common units.

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:

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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;

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

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

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the inability of our common unitholders to remove directors; and

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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.

With limited exceptions, our limited liability company agreement restricts the voting rights of unitholders that own 20% or more of our common units.

Our limited liability company agreement prohibits any person or group that owns 20% or more of our common units then outstanding, other than persons who acquire common units with the prior approval of our board of directors, from voting on any matter.

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 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.

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, ARP’s and our Development Subsidiary’s capital and profits interest within a 12-month period will result in the termination of our, ARP’s and our Development Subsidiary’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. Likewise, ARP and our Development Subsidiary 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 their capital and profits within a 12-month period. The termination would, among other things, result in the closing of our 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, ARP or our Development Subsidiary 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, ARP and our Development Subsidiary presently anticipate that substantially all of our income will be generated in Alabama, Colorado, Indiana, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, Virginia, West Virginia and Wyoming. As we make acquisitions or expand our businesses, we 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.

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 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, 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 Development Subsidiary, on the one hand, and our Development Subsidiary and its limited partners, on the other hand. Our directors and officers and our 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 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 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;

•

the determination and timing of the amount of cash to be distributed to our and 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 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 our 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 or 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 or our Development Subsidiary 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 agreements of ARP or our Development Subsidiary prohibit ARP, our Development Subsidiary or our affiliates from owning assets or engaging in businesses that compete directly or indirectly with us, our affiliates or ARP or our Development Subsidiary. In addition, ARP, our Development Subsidiary and their 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 our, ARP’s and our Development Subsidiary’s 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, will 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 and our Development Subsidiary. 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, our Development Subsidiary and their 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 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 our registration statement on Form 10, 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 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.

ITEM 1B:

UNRESOLVED STAFF COMMENTS

None.

ITEM 2:

PROPERTIES

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, 2014. 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 independent third-party engineers. We and ARP have adjusted these estimates to reflect the settlement of asset retirement obligations on gas and oil properties. A summary of the reserve reports related to our and ARP’s estimated proved reserves at December 31, 2014 are included as Exhibits 99.1 through 99.3 to this report. 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, 2014 and 2013, and are listed below as of the dates indicated:


	December 31,
Unadjusted Prices⁽¹⁾	2014		2013
Natural gas (per Mcf)	$	4.35	$	3.67
Oil (per Bbl)	$	94.99	$	96.78
NGLs (per Bbl)	$	30.21	$	30.10

Average Realized Prices, Before Hedge⁽¹⁾⁽²⁾
Natural gas (per Mcf)	$	3.93	$	3.25
Oil (per Bbl)	$	82.42	$	95.86
NGLs (per Bbl)	$	29.37	$	29.43

⁽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, 2014 and 2013. Including the effect of this subordination, the average realized sales price was $3.84 per Mcf before the effects of financial hedging and $2.99 per Mcf before the effects of financial hedging for years ended December 31, 2014 and 2013, respectively.

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, 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. Other than for ARP’s Rangely assets, 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 38 years of experience in the estimation and evaluation of petroleum reserves, specified economic parameters, operating conditions and government regulations. For ARP’s Rangely assets, Cawley, Gillespie and Associates, Inc. was retained to prepare a report of proved reserves. The independent reserves engineer’s evaluation was based on more than 32 years of experience in the estimation of 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 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 16 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 our independent third-party engineers in preparing its reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, 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 and oil 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,
	2014		2013
Proved reserves:
Natural gas reserves (MMcf):⁽¹⁾
Proved developed reserves		889,073		766,872
Proved undeveloped reserves⁽²⁾⁽³⁾		175,804		236,907

Total proved reserves of natural gas		1,064,877		1,003,779

Oil reserves (MBbl):⁽¹⁾
Proved developed reserves		31,150		3,459
Proved undeveloped reserves⁽²⁾⁽³⁾		31,799		11,530

Total proved reserves of oil		62,949		14,989

NGL reserves (MBbl):
Proved developed reserves		12,210		7,676
Proved undeveloped reserves⁽²⁾⁽³⁾		11,170		11,281

Total proved reserves of NGL		23,380		18,957

Total proved reserves (MMcfe)⁽¹⁾		1,582,853		1,207,455

Standardized measure of discounted future cash flows (in thousands)⁽⁴⁾	$	2,236,764	$	1,079,291

⁽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, 2014, 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.

⁽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 taxed as partnerships, no provision for federal or state income taxes has been included in the December 31, 2014 and 2013 calculations of standardized measure, which is, therefore, the same as the PV-10 value. Standardized measure for the years ended December 31, 2014 and 2013 includes approximately ($36.7) million and $2.0 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 99.1 through 99.3 in this report.

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 Reserves (“PUDs”)

PUD Locations. As of December 31, 2014, there were no PUD locations related to our natural gas and oil reserves and ARP had 426 PUD locations totaling approximately 331.9 Bcfe of natural gas, oil and NGLs. These PUDS are based on the definition of PUD’s 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 acquisitions in the Arkoma Basin and ARP’s acquisitions in the Barnett Shale and Marble Falls play, the Mississippi Lime play, 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, Marble Falls play, the Mississippi Lime play, 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, 2014 were due to ARP’s:

•

addition of approximately 50.5 Bcfe due to ARP’s drilling activity in the Marcellus Shale, Utica Shale, Mississippi Lime and Marble Falls play;

•

addition of approximately 29.2 Bcfe due to ARP’s acquisition of acreage in the Raton and Black Warrior Basins;

•

addition of approximately 31.8 Bcfe due to ARP’s acquisition of acreage in the Eagle Ford Shale; partially offset by

•

negative revisions of approximately 147.2 Bcfe in PUDs primarily due to the reduction of ARP’s five year drilling plans in the Barnett Shale and pricing scenario revisions.

Development Costs. Costs incurred related to the development of our and our subsidiary’s PUDs were approximately $177.7 million, $103.3 million, and $79.4 million for the years ended December 31, 2014, 2013, and 2012, respectively. During the years ended December 31, 2014, 2013, and 2012, approximately 41.2 Bcfe, 58.4 Bcfe, and 30.6 Bcfe of our and our subsidiary’s reserves, respectively, were converted from PUDs to proved developed reserves. Of the 30.6 Bcfe of 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 “Item 1. Business” for further information. As of December 31, 2014, there were no PUDs that had remained undeveloped for five years or more.

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, 2014. 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 Direct and Development Subsidiary	Gross		Net
Barnett/Marble Falls:
Gas wells		8		8
Oil wells		5		5

Total		13		13

Coal-bed Methane⁽³⁾:
Gas wells		594		449
Oil wells		—		—

Total		594		449

Mississippi Lime:
Gas wells		2		—
Oil wells		—		—

Total		2		—

Eagle Ford:
Gas wells		—		—
Oil wells		10		10

Total		10		10

Total:
Gas wells		604		457
Oil wells		15		15

Total		619		472


	Number of Productive Wells⁽¹⁾⁽²⁾
Atlas Resource Partners	Gross		Net
Appalachia:
Gas wells		7,634		3,751
Oil wells		493		354

Total		8,127		4,105

Coal-bed Methane⁽³⁾:
Gas wells		3,440		2,584
Oil wells		—		—

Total		3,440		2,584

Barnett/Marble Falls:
Gas wells		565		469
Oil wells		150		99

Total		715		568

Mississippi Lime/Hunton:
Gas wells		99		61
Oil wells		—		—

Total		99		61

Rangely/Eagle Ford:
Gas wells		—		—
Oil wells		424		123

Total		424		123

Other operating areas⁽⁴⁾:
Gas wells		763		237
Oil wells		2		1

Total		765		238

Total:
Gas wells		12,501		7,102
Oil wells		1,069		577

Total		13,570		7,679

⁽¹⁾

There were no exploratory or dry wells drilled by us during the years ended December 31, 2014, 2013 and 2012. There were no exploratory wells drilled by ARP during the years ended December 31, 2014, 2013 and 2012; there were no gross or net dry wells within ARP’s operating areas during the years ended December 31, 2014 and 2013. During the year ended December 31, 2012, there were eight gross (three net) ARP dry wells drilled in the Niobrara Shale.

⁽²⁾	Includes ARP’s proportionate interest in wells owned by 67 Drilling Partnerships for which it serves as managing general partner and various joint ventures. This does not include royalty or overriding interests in 646 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, the County Line area of Wyoming, and the Central Appalachian Basin in Virginia and West Virginia.

⁽⁴⁾	Other operating areas include ARP’s production located in the Chattanooga, New Albany Shale and the Niobrara Shale.

Developed and Undeveloped Acreage

The following table sets forth information about our and ARP’s developed and undeveloped natural gas and oil acreage as of December 31, 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 Direct and Development Subsidiary:	Gross⁽³⁾		Net⁽⁴⁾		Gross⁽³⁾		Net⁽⁴⁾
Oklahoma		101,936		73,408		66,910		28,029
Texas		6,988		6,980		1,174		1,129
Arkansas		1,016		559		368		334

Total		109,940		80,947		68,452		29,492


	Developed acreage⁽¹⁾				Undeveloped acreage⁽²⁾
Atlas Resource Partners:	Gross⁽³⁾		Net⁽⁴⁾		Gross⁽³⁾		Net⁽⁴⁾
West Virginia		387,478		157,699		3,946		2,047
Pennsylvania		154,445		74,819		2,358		2,327
New Mexico		126,246		126,246		447,713		447,713
Ohio⁽⁵⁾		109,736		101,345		100,431		98,154
Texas		83,384		72,085		65,572		53,224
Alabama		56,200		55,218		40,488		37,104
Colorado		39,778		31,663		20,924		20,924
Indiana		32,388		24,781		61,949		54,648
Wyoming		29,737		5,677		830		156
Oklahoma		22,253		18,266		13,170		11,060
Tennessee		20,119		8,409		45,108		44,908
New York		13,254		12,122		20,957		18,936
Virginia		6,489		6,040		—		—
Other		1,290		207		3,014		2,829

Total		1,082,797		694,577		826,460		794,030

⁽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 10,608 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 December 31, 2014. As of December 31, 2014, none of the leases covering our approximately 29,492 net undeveloped acres, or 0.0%, are scheduled to expire on or before December 31, 2015, while leases covering approximately 40,103 of ARP’s 794,030 net undeveloped acres, or 5.1%, are scheduled to expire on or before December 31, 2015. An additional 0.7% and 1.6% of ARP’s net undeveloped acres are scheduled to expire in each of the years 2016 and 2017, respectively.

We believe that we and ARP hold good and indefeasible title to producing properties, in accordance with standards generally accepted in the industry, subject to exceptions stated in the opinions of counsel employed by us and ARP in the various areas in which we and ARP conduct activities. We do not believe that these exceptions detract substantially from our or ARP’s use of any property. As is customary in the industry, we and ARP conduct only a perfunctory title examination at the time we or it 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.

ITEM 3:

LEGAL PROCEEDINGS

We and our subsidiaries are party to various routine legal proceedings arising out of the ordinary course of our business. Management believes that any of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations. See “Item 8: Financial Statements and Supplementary Data – Note 12”.

ITEM 4:

MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5:

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common units began trading on March 2, 2015 and are listed on the New York Stock Exchange (“NYSE”) and are traded under the ticker symbol “ATLS”. From March 2, 2015 through March 23, 2015, the highest sales price for our common units on the NYSE was $10.25 per unit and the lowest sales price for our common units on the NYSE was $5.81 per unit. On March 23, 2015, there were 166 holders of record of our common units.

ITEM 6:

SELECTED FINANCIAL DATA

The following selected historical combined consolidated financial data table reflects our financial position and results of operations, including the assets and liabilities and related results of operations transferred to us (“New Atlas”), by our former parent, Atlas Energy, L.P. (“Atlas Energy”). New Atlas consists of Atlas Energy’s interests in the following:

•

100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 27.7% limited partner interest (consisting of 20,962,485 common and 3,749,986 preferred limited partner units) in Atlas Resource Partners, L.P. (“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;

•

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

The selected historical combined consolidated financial and other operating data presented below should be read in conjunction with our audited combined consolidated financial statements and accompanying notes (see “Item 8: Financial Statements and Summary Data”) and “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations”. Our 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 we operated as an independent, publicly traded company during the periods presented.

We have derived the selected financial data set forth in the following table for each of the years ended December 31, 2014, 2013 and 2012, with the exception of combined consolidated balance sheet data for the year ended December 31, 2012, 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 selected financial data for the year ended December 31, 2011, with the exception of combined consolidated balance sheet data for the year ended December 31, 2011, from our combined consolidated financial statements not included in this report, which have been audited by Grant Thornton LLP. We derived the financial data for the year ended December 31, 2010, 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 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 combined consolidated financial statements include our accounts and that of our consolidated subsidiaries, all of which are wholly owned at December 31, 2014, except for ARP and our Development Subsidiary, which we control (see “Item 8: Financial Statements and Supplementary Data - Note 2”). 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 Atlas Energy, Inc. (“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 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 (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 included within “Item 8: Financial Statements and Supplementary Data” and “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report.


	Year Ended December 31,
	2014			2013			2012			2011			2010
Statement of operations data:	(in thousands, except per unit data)
Revenues:
Gas and oil production	$	475,758		$	273,906		$	92,901		$	66,979		$	93,050
Well construction and completion		173,564			167,883			131,496			135,283			206,802
Gathering and processing		14,107			15,676			16,267			17,746			14,087
Administration and oversight		15,564			12,277			11,810			7,741			9,716
Well services		24,959			19,492			20,041			19,803			20,994
Other, net		4,558			(14,135	)		(3,346	)		16,527			2,126

Total revenues		708,510			475,099			269,169			264,079			346,775

Costs and expenses:
Gas and oil production		184,296			100,178			26,624			17,100			23,323
Well construction and completion		150,925			145,985			114,079			115,630			175,247
Gathering and processing		15,525			18,012			19,491			20,842			20,221
Well services		10,007			9,515			9,280			8,738			10,822
General and administrative		90,476			89,957			75,475			27,688			11,381
Chevron transaction expense		—			—			7,670			—			—
Depreciation, depletion and amortization		242,079			139,916			52,582			31,938			40,758
Asset impairment		580,654			38,014			9,507			6,995			50,669

Total costs and expenses		1,273,962			541,577			314,708			228,931			332,421

Operating income (loss)		(565,452	)		(66,478	)		(45,539	)		35,148			14,354
Gain (loss) on asset sales and disposal		(1,859	)		(987	)		(6,980	)		90			(2,947	)
Interest expense		(73,435	)		(39,712	)		(4,548	)		(4,244	)		—

Net income (loss)	$	(640,746	)	$	(107,177	)	$	(57,067	)	$	30,994		$	11,407

Balance sheet data (at period end):
Property, plant and equipment, net	$	2,419,289		$	2,186,683		$	1,302,228		$	525,454		$	508,484
Total assets		3,026,315			2,455,870			1,526,652			732,641			668,144
Total debt, including current portion		1,542,585			1,091,959			357,050			—			—
Total equity		915,215			1,043,996			868,804			485,348			400,794
Cash flow data:
Net cash provided by operating activities	$	76,087		$	3,841		$	13,524		$	83,410		$	59,586
Net cash used in investing activities		(962,947	)		(1,053,524	)		(837,825	)		(57,984	)		(98,745	)
Net cash provided by financing activities		934,593			1,037,038			792,863			29,282			39,159
Capital expenditures		(225,636	)		(267,480	)		(127,226	)		(47,324	)		(93,608	)

ITEM 7:

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

The historical financial statements included in this Annual Report reflect substantially all the assets, liabilities and operations of our and Atlas Energy’s controlled subsidiaries contributed to us on February 27, 2015. We refer to our, Atlas Energy’s and such subsidiaries’ assets, liabilities and operations as New Atlas. The discussion and analysis presented below refer to and should be read in conjunction with “Item 6: Selected Financial Data” and “Item 8: Financial Statements and Supplementary Data”, which contains the combined consolidated financial statements of New Atlas. 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 in “Item 1A: Risk Factors” and “Forward-Looking Statements”. 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.

Unless the context otherwise requires, references in this annual report to “New Atlas,” “the Company,” “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 contributed to Atlas Energy Group, LLC in connection with the separation and distribution on February 27, 2015 and refer to Atlas Energy Group, LLC, a Delaware limited liability company, and its combined subsidiaries. References in this Annual Report 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 annual report to “ARP” or “Atlas Resource Partners” refer to Atlas Resource Partners, L.P., a Delaware limited partnership. References 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 at December 31, 2014. References in this information statement to “AEI” refer to Atlas Energy, Inc. the former owner of Atlas Energy’s general partner.

GENERAL

We are a Delaware limited liability company formed in October 2011. At December 31, 2014, we were wholly-owned by Atlas Energy, L.P. (“Atlas Energy”), a then publicly-traded Delaware master limited partnership (NYSE: ATLS). On February 27, 2015, Atlas Energy transferred its assets and liabilities, other than those related to its midstream assets, to us, and effected a pro rata distribution to its unitholders of our common units representing a 100% interest in us (the “Separation”). We refer to the assets and liabilities that were transferred to us by Atlas Energy in connection with the Separation as “New Atlas”. Our common units began trading “regular-way” under the ticker symbol “ATLS” on the New York Stock Exchange on March 2, 2015. Concurrently with the distribution of our units, Atlas Energy and its remaining midstream interests merged with Targa Resources Corp. (“Targa”; NYSE: TRGP) and ceased trading.

Our assets, assuming the Separation had been completed as of December 31, 2014, consist of:

•

direct natural gas development and production assets in the Arkoma Basin, which Atlas Energy acquired in July 2013 (“Direct Gas & Oil Production Assets” or “Direct”).

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.

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. Actual balances and results could be different from those estimates.

In connection with Atlas Energy’s merger with Targa and our concurrent unit distribution, we were required to repay $150.0 million of Atlas Energy’s term loan credit facility, which was issued in July 2013 for $240.0 million. In accordance with generally accepted accounting principles, we included $150.0 million of Atlas Energy’s original term loan at the time of issuance, and the related interest expense, within our historical financial statements. In addition, all of Atlas Energy’s other historical borrowings were allocated to our historical financial statements in the same ratio.

Our combined consolidated financial statements contain our accounts and those of our combined consolidated subsidiaries, all of which are wholly-owned at December 31, 2014, except for ARP and our Development Subsidiary, which we control. 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 partners’ capital on our combined consolidated balance sheets. Throughout this section, when we refer to “our” combined consolidated financial statements, we are referring to the combined consolidated results for us, our wholly-owned subsidiaries and the consolidated results of ARP and our Development Subsidiary, adjusted for non-controlling interests in ARP and our Development Subsidiary. All significant intercompany transactions and balances have been eliminated in the combination of the financial statements.

SUBSEQUENT EVENTS

•

the Recognized Value (the sum of the discounted net present values of the Loan Parties’ oil and gas properties and the values of the common units, Class A Units and Class C Units of ARP, determined as set forth in the Credit Agreement) to Total Funded Debt (as defined in the Credit Agreement);

•

Preferred Unit Purchase Agreement. On February 26, 2015, we entered into the Series A Preferred Unit Purchase Agreement (the “Series A Purchase Agreement”) with certain members of our management, two management members of the Board and an outside investor (the “purchasers”), pursuant to which, on February 27, 2015 we issued and sold an aggregate of 1.6 million of our newly issued Series A convertible preferred units, with a liquidation preference of $25.00 per unit (the “Series A preferred units”), to the purchasers for a cash purchase price of $25.00 per unit in a privately negotiated transaction (the “Private Placement”). We sold the Series A preferred units in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”). The Private Placement resulted in proceeds to us of $40.0 million. We used the proceeds to fund a portion of the $150.0 million cash transfer made by us to Atlas Energy required by the Separation agreement with Atlas Energy, which was a condition to the Separation and distribution of our common units (see “Item 1: Business—General”). The Series A Purchase Agreement contains customary terms for private placements, including representations, warranties, covenants and indemnities.

Atlas Resource

•

reduces the borrowing base under the ARP Credit Agreement from $900.0 million to $750.0 million;

•

permits the incurrence of second lien debt in an aggregate principal amount up to $300.0 million;

•

The Amendment was approved by the lenders and was effective on February 23, 2015.

•

4.5% of the principal amount prepaid for prepayments made between 12 months and 24 months after the closing date;

•

2.25% of the principal amount prepaid for prepayments made between 24 months and 36 months after the closing date; and

•

no premium for prepayments made following 36 months after the closing date.

Cash distributions. On January 28, 2015, ARP declared a monthly distribution of $0.1966 per common unit for the month of December 31, 2014. The $18.9 million distribution, including $1.4 million and $0.7 million to us, as general partner and preferred limited partners, respectively, was paid on February 13, 2015 to unitholders of record at the close of business on February 9, 2015.

On February 23, 2015, ARP declared a monthly distribution of $0.1083 per common unit for the month of January 2015. The $10.1 million distribution, including $0.2 million and $0.6 million, to us, as general partner and preferred limited partners, respectively, was paid on March 17, 2015 to unitholders of record at the close of business on March 10, 2015.

RECENT DEVELOPMENTS

Eagle Ford Shale Asset Acquisition. On November 5, 2014, ARP and our Development Subsidiary completed an acquisition of oil and natural gas liquid assets in the Eagle Ford Shale in Atascosa County, Texas. The purchase price was $339.2 million, of which $179.5 million was paid at closing by ARP and $19.7 million was paid by our Development Subsidiary, 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. Our 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 our deferred portion of the purchase price with the issuance of its Class D Cumulative Redeemable Perpetual Preferred Units (“Class D ARP Preferred Units”). The acquisition has an effective date of July 1, 2014.

Atlas Resource

Issuance of Senior Notes. In connection with the Eagle Ford Acquisition, on October 14, 2014, ARP issued an additional $75.0 million of its 9.25% Senior Notes due 2021 (“9.25% ARP Senior Notes”) in a private transaction under Rule 144A and Regulation S of the Securities Act of 1933, as amended (the “Securities Act”) at an offering price of 100.5%. In connection with the issuance, ARP also entered into a registration rights agreement. Under the registration rights 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 no later than 270 days after the issuance of the ARP 9.25% 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 (see “Senior Notes”).

Issuance of Preferred Units. Also in connection with the Eagle Ford Acquisition, in October 2014 ARP issued 3,200,000 8.625% Class D Preferred Units at a public offering price of $25.00 per Class D Unit. On January 15, 2015, ARP paid an initial quarterly distribution of $0.616927 per unit for the extended period from October 2, 2014 through January 14, 2015 to holders of record as of January 2, 2015. ARP will pay future cumulative distributions on a quarterly basis, at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference.

Equity Distribution Program. On August 29, 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 (see “Issuances of Units”). As of December 31, 2014, no units have been sold under this program.

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 $409.4 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 its 7.75% Senior Notes due 2021 (“7.75 ARP Senior Notes”) (see “Senior Notes”) and the issuance of 15,525,000 of ARP’s common limited partner units (see “Issuance of Units”). The Rangely Acquisition had an effective date of April 1, 2014. Our consolidated financial statements reflect the operating results of the acquired business commencing June 30, 2014.

GeoMet Acquisition. On May 12, 2014, ARP completed the acquisition of assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $97.9 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.

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 $297.3 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 (see “Issuance of Units”).

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 $129.0 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 (see “Issuance of Units”).

Cash Distribution Practice. On January 29, 2014, ARP’s board of directors approved the modification of its cash distribution payment practice to a monthly cash distribution program, whereby a monthly cash distribution is paid within 45 days from the month end.

CONTRACTUAL REVENUE ARRANGEMENTS

Natural Gas and Oil Production

Natural Gas. We and our subsidiaries market the majority of our natural gas production to gas marketers directly or to third party plant operators who process and market our and our subsidiaries’ 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 pricing indices for the majority of our and our subsidiaries’ production areas are as follows:

•

Appalachian Basin - Dominion South Point, Tennessee Gas Pipeline Zone 4 (200 Leg), Transco Leidy Line, Columbia Appalachia, NYMEX and Transco Zone 5;

•

Mississippi Lime - Southern Star;

•

Barnett Shale and Marble Falls- primarily Waha;

•

Raton – ANR, Panhandle, and NGPL;

•

Black Warrior Basin – Southern Natural;

•

Eagle Ford – Transco Zone 1;

•

Arkoma – Enable Gas; and

•

Other regions - primarily the Texas Gas Zone SL spot market (New Albany Shale) and the Cheyenne Hub spot market (Niobrara).

We and our subsidiaries attempt to sell the majority of natural gas produced at monthly, fixed index prices and a smaller portion at index daily prices.

ARP holds firm transportation obligations on Colorado Interstate Gas for the benefit of production from the Raton Basin in the New Mexico/Colorado Area. The total of firm transportation held is approximately 82,500 dth/d at a weighted average rate of $0.2575/MMBtu under contracts expiring in 2016. ARP also holds firm transportation obligations on East Tennessee Natural Gas, Columbia Gas Transmission and Equitrans for the benefit of production from the central Appalachian Basin. The total of firm transportation held is approximately 25,000 dth/d, 15,500 dth/d and 2,300 dth/d, respectively, under contracts expiring between the years 2015 and 2022.

Crude Oil. Crude oil produced from our and our subsidiaries’ 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. The oil and natural gas liquids production of ARP’s Rangely assets flows into a common carrier pipeline and is sold at prevailing market prices, less applicable transportation and oil quality differentials. We and our subsidiaries 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 indicated above and our and our subsidiaires’ 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 our subsidiaries do not have delivery commitments for fixed and determinable quantities of NGLs in any future periods under existing contracts or agreements.

Atlas Resources’ 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 it deploys Drilling Partnership investor capital, ARP 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, ARP will recognize a current liability titled “Liabilities Associated with Drilling Contracts” on our 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%.

As managing general partner of our Drilling Partnerships, we recognize our Drilling Partnership management fees in the following manner:

•

Administration and oversight. For each well drilled by a Drilling Partnership, ARP currently 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 a 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; and

•

Gathering and processing revenue includes gathering fees ARP charges to the Drilling Partnership wells for its 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 it remits. In Appalachia, a majority of ARP’s Drilling Partnership wells are subject to a gathering agreement, whereby it 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 ARP’s gathering expenses within its partnership management segment, specifically those in the Appalachian Basin, will generally exceed the revenues collected from Drilling Partnerships by approximately 3%.

GENERAL TRENDS AND OUTLOOK

We expect our and our subsidiaries’ businesses to be affected by the following key trends. Our expectations are based on assumptions made by us and our subsidiaries and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our and our subsidiaries’ actual results may vary materially from our expected results.

Natural Gas and Oil Production

The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines during the fourth quarter of 2014 and early 2015, particularly in December 2014 and January 2015. The causes of these declines are based on a number of factors, including, but not limited to, a significant increase in natural gas, oil and NGL production. While we and our subsidiaries anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments in the development of new natural gas, oil and NGL reserves.

Our and our subsidiaries’ future gas and oil reserves, production, cash flow, the ability to make payments on debt and the ability to make distributions to unitholders, including ARP’s ability to make distributions to us, depend on our and our subsidiaries’ success in producing current reserves efficiently, developing existing acreage and acquiring additional proved reserves economically. We and our subsidiaries face the challenge of natural production declines and volatile natural gas, oil and NGL prices. As initial reservoir pressures are depleted, natural gas and oil production from particular wells decrease. We and our subsidiaries attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than produced.

RESULTS OF OPERATIONS

Gas and Oil Production

Production Profile. At December 31, 2014, our consolidated gas and oil production revenues and expenses consisted of our and our subsidiaries’ gas and oil production activities. Currently, our gas and oil production entails the production generated by our assets acquired in the Arkoma Acquisition. Our Development Subsidiary’s gas and oil production emanates from its wells drilled in the Marble Falls and Mississippi Lime plays. ARP has focused its natural gas, crude oil and NGL production operations in various plays throughout the United States. ARP previously had certain agreements which 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. Through December 31, 2014, we and our subsidiaries have established production positions in the following operating areas:

•

our coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma, where we established a position following our acquisition of certain assets from EP Energy E&P Company, L.P. in July 2013 (the “Arkoma Acquisition”);

•

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

•

our Development Subsidiary’s and ARP’s Barnett Shale and Marble Falls play, both in the Fort Worth Basin in northern Texas. The Barnett Shale contains mostly dry gas and the Marble Falls play contains liquids rich 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. Our Development Subsidiary acquired leasehold acreage within the Marble Falls play shortly after commencing operations during the year ended December 31, 2013;

•

ARP’s 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”, 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 (see “Recent Developments”);

•

ARP’s 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 ARP’s acquisition on June 30, 2014, which is referred to as the “Rangely Acquisition” (see “Recent Developments”);

•

ARP’s Appalachia 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;

•

our Development Subsidiary’s and ARP’s Mississippi Lime and Hunton plays in northwestern Oklahoma, an oil and NGL-rich area, where our Development Subsidiary participated in non-operated well drilling during 2014 and ARP established a position following ARP’s acquisition from Equal in 2012; and

•

ARP’s other operating areas, including the Chattanooga Shale in northeastern Tennessee, which enables us 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 and our subsidiaries drilled and the number of wells we and our subsidiaries turned in line, both gross and for our respective interests, during the years ended December 31, 2014, 2013 and 2012:


	Year Ended December 31,
	2014		2013		2012
New Atlas Direct:
Gross wells drilled		—		—		—
Our share of gross wells drilled		—		—		—
Gross wells turned in line		—		—		—
Net wells turned in line		—		—		—

	Year Ended December 31,
	2014		2013		2012
Development Subsidiary:
Gross wells drilled		11		2		—
Our share of gross wells drilled		11		2		—
Gross wells turned in line		13		2		—
Net wells turned in line		13		2		—

	Year Ended December 31,
	2014		2013		2012
Atlas Resource:
Gross wells drilled		129		103		105
Share of gross wells drilled⁽¹⁾		67		66		42
Gross wells turned in line		119		117		154
Net wells turned in line⁽¹⁾		64		80		43

⁽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.

Production Volumes. The following table presents total net natural gas, crude oil and NGL production volumes and production per day for the years ended December 31, 2014, 2013, and 2012:


	Year Ended December 31,
	2014		2013		2012
Production:⁽¹⁾⁽²⁾
Atlas Resource:⁽³⁾
Appalachia:
Natural gas (MMcf)		13,928		13,397		12,403
Oil (000’s Bbls)		139		121		102
NGLs (000’s Bbls)		15		8		4

Total (MMcfe)		14,852		14,171		13,036

Coal-bed Methane:
Natural gas (MMcf)		44,080		17,465		—
Oil (000’s Bbls)		—		—		—
NGLs (000’s Bbls)		—		—		—

Total (MMcfe)		44,080		17,465		—

Barnett/Marble Falls:
Natural gas (MMcf)		20,937		23,744		10,561
Oil (000’s Bbls)		389		295		10
NGLs (000’s Bbls)		985		1,004		173

Total (MMcfe)		29,180		31,539		11,661


	Year Ended December 31,
	2014		2013		2012
Rangely/Eagle Ford:
Natural gas (MMcf)		64		—		—
Oil (000’s Bbls)		561		—		—
NGLs (000’s Bbls)		63		—		—

Total (MMcfe)		3,810		—		—

Mississippi Lime/Hunton:
Natural gas (MMcf)		2,486		1,779		510
Oil (000’s Bbls)		156		63		3
NGLs (000’s Bbls)		205		118		30

Total (MMcfe)		4,648		2,859		705

Other operating areas:
Natural gas (MMcf)		1,187		1,609		1,929
Oil (000’s Bbls)		9		7		6
NGLs (000’s Bbls)		121		138		150

Total (MMcfe)		1,965		2,477		2,865

Total Atlas Resource:
Natural gas (MMcf)		82,682		57,993		25,403
Oil (000’s Bbls)		1,254		485		121
NGLs (000’s Bbls)		1,388		1,268		357

Total (MMcfe)		98,535		68,511		28,267

New Atlas Direct:
Natural gas (MMcf)		4,208		1,856		—
Oil (000’s Bbls)		—		—		—
NGLs (000’s Bbls)		—		—		—

Total (MMcfe)		4,208		1,856		—

Development Subsidiary:
Natural gas (MMcf)		252		8		—
Oil (000’s Bbls)		43		3		—
NGLs (000’s Bbls)		32		1		—

Total (MMcfe)		701		29		—

Total production:
Natural gas (MMcf)		87,142		59,857		25,403
Oil (000’s Bbls)		1,297		488		121
NGLs (000’s Bbls)		1,420		1,269		357

Total (MMcfe)		103,443		70,396		28,267

Production per day:⁽¹⁾⁽²⁾
Atlas Resource:⁽³⁾
Appalachia:
Natural gas (Mcfd)		38,160		36,705		33,889
Oil (Bpd)		381		332		278
NGLs (Bpd)		41		22		10

Total (Mcfed)		40,689		38,825		35,618

Coal-bed Methane:
Natural gas (Mcfd)		120,768		47,848		—
Oil (Bpd)		—		—		—
NGLs (Bpd)		—		—		—

Total (Mcfed)		120,768		47,848		—


	Year Ended December 31,
	2014		2013		2012
Barnett/Marble Falls:
Natural gas (Mcfd)		57,361		65,053		28,855
Oil (Bpd)		1,066		808		28
NGLs (Bpd)		2,698		2,751		473

Total (Mcfed)		79,946		86,409		31,861

Rangely/Eagle Ford:⁽⁴⁾
Natural gas (Mcfd)		175		—		—
Oil (Bpd)		1,538		—		—
NGLs (Bpd)		173		—		—

Total (Mcfed)		10,438		—		—

Mississippi Lime/Hunton:
Natural gas (Mcfd)		6,810		4,873		1,392
Oil (Bpd)		427		171		8
NGLs (Bpd)		561		322		81

Total (Mcfed)		12,734		7,834		1,926

Other operating areas:
Natural gas (Mcfd)		3,253		4,408		5,271
Oil (Bpd)		25		18		16
NGLs (Bpd)		330		378		410

Total (Mcfed)		5,384		6,786		7,827

Total Atlas Resource:
Natural gas (Mcfd)		226,526		158,886		69,408
Oil (Bpd)		3,436		1,329		330
NGLs (Bpd)		3,802		3,473		974

Total (Mcfed)		269,958		187,701		77,232

New Atlas Direct:
Natural gas (Mcfd)		11,528		5,085		—
Oil (Bpd)		—		—		—
NGLs (Bpd)		—		—		—

Total (Mcfed)		11,528		5,085		—

Development Subsidiary:
Natural gas (Mcfd)		691		21		—
Oil (Bpd)		117		7		—
NGLs (Bpd)		88		3		—

Total (Mcfed)		1,920		79		—

Total production per day:
Natural gas (Mcfd)		238,745		163,992		69,408
Oil (Bpd)		3,553		1,336		330
NGLs (Bpd)		3,891		3,476		974

Total (Mcfed)		283,406		192,866		77,232

⁽¹⁾

⁽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/Eagle Ford includes ARP’s 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado and our Development Subsidiary’s and ARP’s production located in southern Texas; Other operating areas include ARP’s production located in the Chattanooga, New Albany and Niobrara Shales.

⁽⁴⁾

Rangely includes production from July 1, 2014, the date of the acquisition, through December 31, 2014; Eagle Ford includes production from November 5, 2014, the date of the acquisition, through December 31, 2014. Production per day represents production based on the full 365-day year ended December 31, 2014.

Production Revenues, Prices and Costs. Production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas and oil. 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 years ended December 31, 2014, 2013 and 2012, along with average production costs, which include lease operating expenses, taxes, and transportation and compression costs, in each of the reported periods:


	Year Ended December 31,
	2014		2013		2012
Production revenues (in thousands):
New Atlas Direct:
Natural gas revenue	$	16,094	$	6,821	$	—
Oil revenue		—		—		—
NGLs revenue		—		—		—

Total revenues	$	16,094	$	6,821	$	—

Development Subsidiary:
Natural gas revenue	$	1,009	$	28	$	—
Oil revenue		3,770		241		—
NGLs revenue		928		33		—

Total revenues	$	5,707	$	302	$	—

Atlas Resource:
Natural gas revenue	$	302,826	$	186,229	$	70,151
Oil revenue		110,070		44,160		11,351
NGLs revenue		41,061		36,394		11,399

Total revenues	$	453,957	$	266,783	$	92,901

Total production revenues:
Natural gas revenue	$	319,929	$	193,078	$	70,151
Oil revenue		113,840		44,401		11,351
NGLs revenue		41,989		36,427		11,399

Total revenues	$	475,758	$	273,906	$	92,901

Average sales price:
New Atlas Direct:
Natural gas (per Mcf):⁽¹⁾
Total realized price, after hedge	$	3.82	$	3.68	$	—
Total realized price, before hedge	$	3.98	$	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	$	4.00	$	3.63	$	—
Total realized price, before hedge	$	4.00	$	3.63	$	—
Oil (per Bbl):⁽¹⁾
Total realized price, after hedge	$	88.61	$	93.16	$	—
Total realized price, before hedge	$	88.61	$	93.16	$	—


	Year Ended December 31,
	2014		2013		2012
NGLs (per Bbl):⁽¹⁾
Total realized price, after hedge	$	28.80	$	34.88	$	—
Total realized price, before hedge	$	28.80	$	34.88	$	—
Atlas Resource:
Natural gas (per Mcf):⁽¹⁾
Total realized price, after hedge⁽²⁾	$	3.76	$	3.47	$	3.29
Total realized price, before hedge⁽²⁾	$	3.93	$	3.25	$	2.60
Oil (per Bbl):⁽¹⁾
Total realized price, after hedge	$	87.76	$	91.01	$	94.02
Total realized price, before hedge	$	82.22	$	95.88	$	91.32
NGLs (per Bbl):⁽¹⁾
Total realized price, after hedge	$	29.59	$	28.71	$	31.97
Total realized price, before hedge	$	29.39	$	29.43	$	31.97
Total:
Natural gas (per Mcf):⁽¹⁾
Total realized price, after hedge⁽²⁾	$	3.76	$	3.48	$	3.29
Total realized price, before hedge⁽²⁾	$	3.93	$	3.25	$	2.60
Oil (per Bbl):⁽¹⁾
Total realized price, after hedge	$	87.79	$	91.02	$	94.02
Total realized price, before hedge	$	82.42	$	95.86	$	91.32
NGLs (per Bbl):⁽¹⁾
Total realized price, after hedge	$	29.57	$	28.71	$	31.97
Total realized price, before hedge	$	29.37	$	29.43	$	31.97

Production costs (per Mcfe):⁽¹⁾
New Atlas Direct:
Lease operating expenses	$	0.86	$	0.79	$	—
Production taxes		0.25		0.21		—
Transportation and compression		0.33		0.54		—

	$	1.43	$	1.54	$	—

Development Subsidiary:
Lease operating expenses	$	2.47	$	—	$	—
Production taxes		0.48		—		—
Transportation and compression		—		—		—

	$	2.95	$	—	$	—

Atlas Resource:
Lease operating expenses⁽³⁾	$	1.29	$	1.09	$	0.82
Production taxes		0.27		0.18		0.12
Transportation and compression		0.25		0.24		0.24

	$	1.81	$	1.50	$	1.19

Total production costs:
Lease operating expenses⁽³⁾	$	1.28	$	1.08	$	0.82
Production taxes		0.27		0.18		0.12
Transportation and compression		0.25		0.25		0.24

	$	1.81	$	1.50	$	1.19

⁽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 years ended December 31, 2014, 2013 and 2012. Including the effect of this subordination, the average realized gas sales price was $3.67 per Mcf ($3.84 per Mcf before the effects of financial hedging), $3.23 per Mcf ($3.00 per Mcf before the effects of financial hedging), and $2.76 per Mcf ($2.08 per Mcf before the effects of financial hedging) for years ended December 31, 2014, 2013 and 2012, 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 years ended December 31, 2014, 2013, and 2012. Including the effects of these costs, total lease operating expenses per Mcfe were $1.26 per Mcfe ($1.78 per Mcfe for total production costs), $1.00 per Mcfe ($1.42 per Mcfe for total production costs) and $0.58 per Mcfe ($0.94 per Mcfe for total production costs) for the years ended December 31, 2014, 2013 and 2012, respectively.

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Total production revenues were $475.8 million for the year ended December 31, 2014, an increase of $201.9 million from $273.9 million for the year ended December 31, 2013. This increase consisted of a $125.0 million increase attributable to our and ARP’s newly acquired coal-bed methane assets, a $51.0 million increase attributable to ARP’s newly acquired Rangely and Eagle Ford assets, a $13.3 million increase attributable to our Development Subsidiary’s and ARP’s Mississippi Lime/Hunton assets, a $9.0 million increase attributable to our Development Subsidiary’s and ARP’s Barnett Shale/Marble Falls operations, and a $5.3 million increase attributable to ARP’s Appalachia assets due primarily to the Marcellus and Utica Shale wells drilled.

Total production costs were $184.3 million for the year ended December 31, 2014, an increase of $84.1 million from $100.2 million for the year ended December 31, 2013. This increase primarily consisted of a $53.7 million increase attributable to production costs associated with our and ARP’s newly acquired coal-bed methane assets, a $16.3 million increase attributable to ARP’s newly acquired Rangely assets and our and ARP’s Eagle Ford assets, an $11.1 million increase primarily attributable to new well connections, consisting of $6.3 million attributable to our Development Subsidiary’s and ARP’s Barnett Shale/Marble Falls assets, $3.5 million attributable to our Development Subsidiary’s and ARP’s Mississippi Lime/Hunton assets, and $1.3 million attributable to ARP’s Appalachia operations, and a $3.1 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 $1.81 per Mcfe for the year ended December 31, 2014 from $1.50 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 Development Subsidiary’s 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 2013 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 period.

Well Construction and Completion

Drilling Program Results. At December 31, 2014, our well construction and completion revenues and expenses consisted 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 years ended December 31, 2014, 2013 and 2012. There were no exploratory wells drilled during the years ended December 31, 2014, 2013 and 2012.


	Year Ended December 31,
	2014		2013		2012
Drilling partnership investor capital:
Raised	$	166,798	$	149,967	$	127,071
Deployed	$	173,564	$	167,883	$	131,496
Gross partnership wells drilled:
Appalachia
Marcellus Shale		—		—		10
Utica		4		3		5
Ohio		—		—		7
Barnett/Marble Falls		77		51		4
Eagle Ford		2		—		—
Mississippi Lime/Hunton		17		21		11
Niobrara		—		—		51

Total		100		75		88

Net partnership wells drilled:
Appalachia
Marcellus Shale		—		—		10
Utica		4		3		5
Ohio		—		—		7
Barnett/Marble Falls		64		25		2
Eagle Ford		1		—		—
Mississippi Lime/Hunton		16		21		9
Niobrara		—		—		51

Total		85		49		84

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):


	Years Ended December 31,
	2014		2013		2012
Average construction and completion:
Revenue per well	$	2,227	$	3,276	$	1,444
Cost per well		1,937		2,849		1,253

Gross profit per well	$	290	$	427	$	191

Gross profit margin	$	22,639	$	21,898	$	17,417

Partnership net wells associated with revenue recognized⁽¹⁾:
Appalachia:
Marcellus Shale		—		4		7
Utica		3		5		2
Ohio		—		—		8
Barnett/Marble Falls		60		24		2
Eagle Ford		1		—		—
Mississippi Lime/Hunton		14		18		7
Chattanooga		—		—		2
Niobrara		—		—		63

Total		78		51		91

⁽¹⁾	Consists of ARP’s Drilling Partnership net wells for which well construction and completion revenue was recognized on a percentage of completion basis.

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Well construction and completion segment margin was $22.6 million for year ended December 31, 2014, an increase of $0.7 million from $21.9 million for the year ended December 31, 2013. This increase consisted of a $7.7 million increase related to a greater number of wells recognized for revenue within ARP’s Drilling Partnerships, partially offset by a $7.0 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 year ended December 31, 2014 compared with capital deployed for higher cost Marcellus and Utica Shale wells during the prior year period. As ARP’s drilling contracts with its Drilling Partnerships are on a “cost-plus” basis, an increase or decrease in its average cost per well also results in a proportionate increase or decrease in its average revenue per well, which directly affects the number of wells ARP drills.

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.

At December 31, 2014, our combined consolidated balance sheet includes $40.6 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 2015.

Administration and Oversight

At December 31, 2014, 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 Shales.

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Administration and oversight fee revenues were $15.6 million for the year ended December 31, 2014, an increase of $3.3 million from $12.3 million for the year ended December 31, 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 play.

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 plays, partially offset by a decrease in the number of Marcellus Shale wells drilled during the year ended December 31, 2013.

Well Services

At December 31, 2014, our well services revenues and expenses consisted 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.

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Well services revenues were $25.0 million for the year ended December 31, 2014, an increase of $5.5 million from $19.5 million for the year ended December 31, 2013. Well services expenses were $10.0 million for the year ended December 31, 2014, an increase of $0.5 million from $9.5 million for the year ended December 31, 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.

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.

Gathering and Processing

At December 31, 2014, our gathering and processing margin consisted solely of ARP’s activities. Gathering 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, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%.

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Our net gathering and processing expense for the year ended December 31, 2014 was $1.4 million, a favorable movement of $0.9 million compared with net expense of $2.3 million for the year ended December 31, 2013. This favorable movement was principally due to a full year of gathering fees from ARP’s Marcellus Shale Drilling Partnership wells in Northeastern Pennsylvania, which are utilizing ARP’s 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 from ARP’s new Marcellus Shale Drilling Partnership wells in Northeastern Pennsylvania, which are utilizing ARP’s gathering pipeline.

Other, Net

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Other, net for the year ended December 31, 2014 was income of $4.6 million as compared with expense of $14.1 million for the comparable prior year period. This $18.7 million favorable movement was primarily due to a $16.8 million decrease in premium amortization associated with our and ARP’s swaption derivative contracts for production volumes related to wells we and ARP acquired from EP Energy during the prior year period, and a $2.8 million increase attributable to ARP’s gain on mark-to-market derivatives in the current year in connection with it entering into derivative instruments upon signing the Eagle Ford Acquisition (see “Recent Developments”), partially offset by a $1.5 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 $10.8 million 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 our equity investment in Lightfoot.

Other Costs and Expenses

General and Administrative Expenses

The following table presents our and our subsidiaries’ general and administrative expenses for each of the respective periods (in thousands):


	Years Ended December 31,
	2014		2013		2012
General and Administrative expenses:
New Atlas Direct	$	6,381	$	8,162	$	6,352
Development Subsidiary		11,746		3,732		—
Atlas Resource Partners		72,349		78,063		69,123

Total	$	90,476	$	89,957	$	75,475

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Total general and administrative expenses increased to $90.5 million for the year ended December 31, 2014 from $90.0 million for the year ended December 31, 2013. Our $6.4 million of general and administrative expenses for the year ended December 31, 2014 represents a $1.8 million decrease from the comparable prior year period, due to a $1.1 million decrease in salaries, wages and other corporate activities and a $0.7 million decrease in third-party services. Our Development Subsidiary’s $11.7 million of general and administrative expenses for the year ended December 31, 2014 represents an $8.0 million increase from the comparable prior year period due to a $7.7 increase in salaries, wages, and other corporate activities and a $0.3 million increase in third-party services. ARP’s $72.3 million of general and administrative expenses for the year ended December 31, 2014 represents a $5.7 million decrease from the comparable prior year period, which was primarily due to a $12.1 million decrease in non-recurring transaction costs related to the acquisitions of assets in the current and prior year periods and a $4.6 million decrease in non-cash compensation expense, partially offset by a $7.0 million increase in salaries, wages and benefits, and a $3.9 million increase in other corporate activities due to the growth of ARP’s 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 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. Our 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.

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 (see “Item 8: Financial Statements and Supplementary Data – Note 3”).

Depreciation, Depletion and Amortization

The following table presents our and our subsidiaries’ depreciation, depletion and amortization expense for each of the respective periods (dollars in thousands):


	Years Ended December 31,
	2014		2013		2012
Depreciation, depletion and amortization:
New Atlas Direct	$	6,192	$	3,020	$	—
Development Subsidiary		2,156		133		—
Atlas Resource Partners		233,731		136,763		52,582

Total	$	242,079	$	139,916	$	52,582

Total depreciation, depletion and amortization increased to $242.1 million for the year ended December 31, 2014 compared with $139.9 million for the comparable prior year period, which was primarily due to a $98.8 million increase in our, our Development Subsidiary’s and ARP’s depletion expense resulting from the acquisitions consummated during 2014 and 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.

The following table presents our and our subsidiaries’ depletion expense per Mcfe for our, our Development Subsidiary’s and ARP’s operations for the respective periods (in thousands, except per Mcfe data):


	Years Ended December 31,
	2014			2013			2012
Depletion expense:
Total	$	231,638		$	132,860		$	47,000
Depletion expense as a percentage of gas and oil production revenue		49	%		49	%		51	%
Depletion per Mcfe	$	2.24		$	1.89		$	1.66

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Depletion expense was $231.6 million for the year ended December 31, 2014, an increase of $98.8 million compared with $132.9 million for the year ended December 31, 2013. Depletion expense of gas and oil properties as a percentage of gas and oil revenues remained consistent at 49% for the years ended December 31, 2014 and 2013. Depletion expense per Mcfe was $2.24 for the year ended December 31, 2014, an increase of $0.35 per Mcfe from $1.89 per Mcfe for the year ended December 31, 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.

Asset Impairment

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Asset impairment for the year ended December 31, 2014, was $580.7 million compared with $38.0 million for the comparable prior year period. The $580.7 million of asset impairment primarily consisted of $562.6 million of oil and gas impairment primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. In addition, $18.1 million of asset impairment is due to ARP’s goodwill impairment. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014 through the impairment testing date in January 2015. During the year ended December 31, 2013, ARP recognized $38.0 million of asset impairment related to impairments of gas and oil properties within property, plant and equipment, net on our consolidated balance sheet primarily for our 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 these gas and oil properties being in excess of our and our subsidiaries’ estimates of their fair values at December 31, 2014 and 2013 and our intention not to drill on certain expiring unproved acreage. The estimates of fair values of these gas and oil properties were impacted by, among other factors, the deterioration of commodity prices in comparison to their carrying values at December 31, 2014 and 2013.

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 year ended December 31, 2012. 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 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 and Niobrara Shales. These impairments by ARP related to the carrying amounts of these gas and oil properties being in excess of ARP’s estimates of their fair values at December 31, 2013 and 2012 and ARP’s intention not to drill on certain expiring unproved acreage. 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, 2013 and 2012.

Loss on Asset Sales and Disposal

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. During the years ended December 31, 2014 and 2013, losses on asset sales and disposal were $1.9 million and $1.0 million, respectively. The $1.9 million loss on asset sales and disposal for year ended December 31, 2014 was primarily related to ARP’s sale of producing wells in its Niobrara Shale in connection with the settlement of a third party farm-out agreement and a $0.3 million loss from ARP’s involuntary conversion of its Mossy Oak compressor station. 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.

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.

Interest Expense

The following table presents our interest expense and that which was attributable to ARP for each of the respective periods:


	Years Ended December 31,
	2014		2013		2012
Interest Expense:
New Atlas Direct	$	11,291	$	5,388	$	353
Atlas Resource Partners		62,144		34,324		4,195

Total	$	73,435	$	39,712	$	4,548

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Total interest expense increased to $73.4 million for the year ended December 31, 2014, compared with $39.7 million for the year ended December 31, 2013. This $33.7 million increase was due to our $5.9 million increase and a $27.8 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 Atlas Energy’s credit facility. The $27.8 million increase in ARP’s interest expense consisted of a $20.7 million increase associated with interest expense on ARP’s Senior Notes, a $6.4 million increase associated with higher weighted-average outstanding borrowings under ARP’s revolving credit facility, a $0.2 million increase in the amortization of ARP’s 7.75% and 9.25% Senior Notes’ discounts, and interest that was capitalized on ARP’s ongoing capital projects, partially offset by a $0.4 million decrease associated with amortization of ARP’s deferred financing costs and a $0.3 million decrease in ARP’s commitment fees. The increase in interest expense related to ARP’s Senior Notes is primarily due to the issuance of an additional $100.0 million of ARP’s 7.75% Senior Notes due 2021 in June 2014 and an additional $75.0 million of ARP’s 9.25% Senior Notes due 2021 in October 2014, as well as a full year of interest expense related to the $275.0 million ARP 7.75% Senior Notes issued in January 2013 and $250.0 million of ARP’s 9.25% Senior Notes issued in July 2013. Our Development Subsidiary had no interest expense for the years ended December 31, 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 Atlas Energy’s 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, 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.

Loss Attributable to Non-Controlling Interests

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Loss attributable to non-controlling interests was $471.4 million for the year ended December 31, 2014, compared with a loss of $58.4 million for the comparable prior year period. Loss attributable to non-controlling interests includes an allocation of ARP’s and our 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, 2014, 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 and our Development Subsidiary during the year ended December 31, 2014.

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 year ended December 31, 2012. Loss attributable to non-controlling interests includes an allocation of ARP’s and our 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.

Liquidity and Capital Resources

General

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. Our primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures, and 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 revolving credit facility (see “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 term loan 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—Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013

Net cash provided by operating activities of $76.1 million for the year ended December 31, 2014 represented a favorable movement of $72.3 million from net cash provided by operating activities of $3.8 million for the comparable prior year period. The $72.3 million favorable movement was derived principally from a favorable movement of $109.5 million in net loss, excluding non-cash items and a $32.3 million favorable movement in working capital, partially offset by a $69.5 million unfavorable movement in distributions paid to non-controlling interests. The non-cash charges which impacted net loss primarily included an increase of $542.6 million in goodwill and other asset impairment, an increase of $102.2 million in depreciation, depletion and amortization, a $2.1 million favorable movement in equity income and distributions related to unconsolidated subsidiaries, an increase of $0.9 million in loss on asset sales and disposal and an increase of $0.2 million in amortization of deferred financing costs, partially offset by an unfavorable movement of $533.6 million in net loss and an unfavorable movement of $4.9 million on non-cash compensation expense. The movement in working capital was due to a $68.9 million favorable movement in accounts payable and accrued liabilities, primarily due to the timing of ARP’s capital programs and the growth of ARP’s business during the year ended December 31, 2014, partially offset by a $36.6 million unfavorable movement in accounts receivable, prepaid expenses and other. The movement in cash distributions to non-controlling interest holders was due principally to increases in cash distributions of ARP.

Net cash used in investing activities of $962.9 million for the year ended December 31, 2014 represented a favorable movement of $90.6 million from net cash used in investing activities of $1,053.5 million for the comparable prior year period. This favorable movement was principally due to a $41.8 million decrease in capital expenditures, a $39.3 million decrease in net cash paid for our, our Development Subsidiary’s and ARP’s acquisitions and a $9.5 million favorable movement in other assets. See further discussion of capital expenditures under “Capital Requirements.”

Net cash provided by financing activities of $934.6 million for the year ended December 31, 2014 represented an unfavorable movement of $102.4 million from net cash provided by financing activities of $1,037.0 million for the comparable prior year period. This unfavorable movement was principally due to a decrease of $339.8 million in net

proceeds from ARP’s long-term debt, an increase of $221.5 million in repayments of our term loan facility, Atlas Energy’s revolving credit facility and ARP’s then-existing term loan facility and revolving credit facility, and a $98.5 million unfavorable movement in net investment from (distribution to) Atlas Energy, partially offset by an increase of $285.4 million for our, Atlas Energy’s and ARP’s borrowings under our term loan facility, Atlas Energy’s revolving credit facility and ARP’s revolving credit facility, an increase of $258.8 million of net proceeds from our Development Subsidiary’s and ARP’s equity offerings and a $13.2 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.

The deferred portion of the purchase price related to the Eagle Ford Acquisition (see “Recent Developments”) represented a non-cash transaction during the year ended December 31, 2014.

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 income 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 term loan facility 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 term loan facility 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 term loan facility, Atlas Energy’s credit facility 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 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.

ARP’s July 2012 acquisition of Titan in exchange for 3.8 million ARP common units and 3.8 million convertible ARP 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.

Capital Requirements

At December 31, 2014, the capital requirements of our and our subsidiaries’ 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.

The following table summarizes consolidated maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented (in thousands):


	Years Ended December 31,
	2014		2013		2012
New Atlas Direct and Development Subsidiary
Maintenance capital expenditures	$	1,200	$	600	$	—
Expansion capital expenditures		11,802		3,343		—

Total	$	13,002	$	3,943	$	—

Atlas Resource Partners
Maintenance capital expenditures	$	65,300	$	31,500	$	10,200
Expansion capital expenditures		147,334		232,037		117,026

Total	$	212,634	$	263,537	$	127,226

Consolidated
Maintenance capital expenditures	$	66,500	$	32,100	$	10,200
Expansion capital expenditures		159,136		235,380		117,026

Total	$	225,636	$	267,480	$	127,226

New Atlas Direct and Development Subsidiary. During the year ended December 31, 2014, our total direct capital expenditures consisted primarily of gathering and processing costs. During the year ended December 31, 2014, our Development Subsidiary’s total capital expenditures consisted primarily of the wells drilled and leasehold acquisition costs.

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 year ended December 31, 2013, our Development Subsidiary’s total capital expenditures consisted primarily of the wells drilled and leasehold acquisition costs.

Atlas Resource Partners. During the year ended December 31, 2014, ARP’s $212.6 million of total capital expenditures consisted primarily of $82.2 million for wells drilled exclusively for ARP’s own account compared with $110.8 million for the comparable prior year period, $72.4 million of investments in its Drilling Partnerships compared with $92.3 million for the prior year comparable period, $25.5 million of leasehold acquisition costs compared with $20.9 million for the prior year comparable period and $32.5 million of corporate and other costs compared with $39.5 million for the prior year comparable period, which primarily related to a decrease in gathering and processing costs.

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 year ended December 31, 2012, $92.3 million of investments in its Drilling Partnerships compared with $54.4 million for the year ended December 31, 2012, $20.9 million of leasehold acquisition costs compared with $35.6 million for the year ended December 31, 2012, and $39.5 million of corporate and other costs compared with $9.9 million for the year ended December 31, 2012, which primarily related to an increase in capitalized interest expense.

We and our subsidiaries continuously evaluate acquisitions of gas and oil assets. In order to make any acquisitions in the future, we and our subsidiaries 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 our subsidiaries will be successful in our and our subsidiaries’ efforts to obtain outside capital.

As of December 31, 2014, we and our subsidiaries are committed to expending approximately $18.9 million on drilling and completion and other capital expenditures.

Off-Balance Sheet Arrangements

As of December 31, 2014, our off-balance sheet arrangements were limited to ARP’s letters of credit outstanding of $4.4 million, and commitments to spend $18.9 million related to capital expenditures.

ARP has certain long-term unconditional purchase obligations and commitments, primarily throughput contracts (see “Contractual Obligations and Commercial 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 December 31, 2014, management 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 adopted a cash distribution policy that requires, 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 cash distribution payment practice to a monthly cash distribution program. Monthly cash distributions are paid approximately 45 days following the end of each respective monthly period.

Available cash will generally be distributed: first, 98% to ARP’s Class B and D 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 and with respect to ARP’s Class D Preferred Unit, an amount equal to its fixed quarterly distribution; 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 December 31, 2014, we had not guaranteed any of ARP’s debt obligations. As of December 31, 2014, our Development Subsidiary had no outstanding debt instruments or facilities.

Term Loan Credit Facility

On February 27, 2015, we entered into a Credit Agreement with Deutsche Bank AG New York Branch, as administrative agent, and the lenders from time to time party thereto (see “Subsequent Events”).

Atlas Resource Partners

ARP has a credit agreement with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (as amended, the “ARP Credit Agreement”). As of February 23, 2015, the ARP Credit Agreement provided for

a senior secured revolving credit facility with a syndicate of banks with a borrowing base of $900.0 million and a maximum facility amount of $1.5 billion scheduled to mature in July 2018. ARP’s borrowing base under the revolving credit facility is scheduled for semi-annual redeterminations on May 1 and November 1 of each year.

At December 31, 2014, $696.0 million was outstanding under ARP’s credit facility. 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 December 31, 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 ARP’s facility are guaranteed by certain of ARP’s material subsidiaries, and any of its non-guarantor subsidiaries of ARP’s are minor. Borrowings under the credit facility bear interest, at ARP’s election, at either an adjusted LIBOR rate plus an applicable margin between 1.50% 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 combined consolidated statements of operations.

A Fifth Amendment to the ARP Credit Agreement was entered into on November 24, 2014 in connection with our restructuring and the separation. Among other things, the Fifth Amendment amended several definitions for the purpose of ensuring that the separation did not result in a Change of Control or Event of Default determination under the ARP Credit Agreement (each as defined in the ARP Credit Agreement).

A Sixth Amendment to the ARP Credit Agreement was entered into on February 23, 2015. Among other things, the Sixth Amendment reduced ARP’s borrowing base to $750.0 million and revised the maximum ratio of Total Funded Debt to EBITDA (actual or annualized, as applicable) (each as defined in the ARP Credit Agreement), to be (i) 5.25 to 1.0 as of the last day of the quarters ended on March 31, 2015, June 30, 2015, September 30, 2015, December 31, 2015 and March 31, 2016, (ii) 5.00 to 1.0 as of the last day of the quarters ended on June 30, 2016, September 30, 2016 and December 31, 2016, (iii) 4.50 to 1.0 as of the last day of the quarters ended on March 31, 2017 and (iv) 4.00 to 1.0 as of the last day of each quarter thereafter. (See “Recent Developments” for a discussion of the Sixth Amendment).

ATLAS RESOURCE SECURED HEDGE FACILITY

At December 31, 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.

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 SENIOR NOTES

At December 31, 2014, ARP had $374.5 million outstanding of its 7.75% senior unsecured notes due 2021 (“7.75% ARP Senior Notes”), including $100.0 million of such notes issued 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 (see “Recent Developments”). The 7.75% ARP Senior Notes were presented net of a $0.5 million unamortized discount as of December 31, 2014. ARP issued $275.0 million of its 7.75% ARP Senior Notes in a private placement transaction at par on January 23, 2013. 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.

At December 31, 2014, ARP had $323.9 million outstanding of its 9.25% senior unsecured notes due 2021 (“9.25% ARP Senior Notes”), including $75.0 million of such notes issued in a private placement transaction on October 14, 2014 at an offering price of 100.5% of par value, which yielded net proceeds of approximately $73.6 million. The 9.25% ARP Senior Notes issued in October 2014 were presented net of a $0.4 million unamortized premium as of December 31, 2014. ARP used the net proceeds from this offering to fund a portion of ARP’s Eagle Ford Acquisition (see “Recent Developments”). The 9.25% ARP Senior Notes issued in July 2013 were presented net of a $1.5 million unamortized discount as of December 31, 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 its 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 its 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 its 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 its 9.25% ARP Senior Notes.

In connection with the issuance of the $75.0 million of 9.25% ARP Senior Notes on October 14, 2014, 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 not 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 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, 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 statement is declared effective, as applicable.

The 7.75% ARP Senior Notes and 9.25% ARP Senior Notes are guaranteed by certain of ARP’s material subsidiaries. The guarantees under the 7.75% ARP Senior Notes and 9.25% 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 7.75% ARP Senior Notes and 9.25% 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 ARP’s assets. ARP was in compliance with these covenants as of December 31, 2014.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

The following tables summarize our and our subsidiaries contractual obligations at December 31, 2014 (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	$	148,125	$	1,125	$	3,375	$	143,625	$	—
ARP total debt		1,396,000		—		—		696,000		700,000
New Atlas interest on total debt		45,458		9,592		18,891		16,975		—


			Payments Due By Period
	Total		Less than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
Eagle Ford deferred payment⁽¹⁾		105,000		105,000		—		—		—
ARP interest on total debt		446,952		79,279		158,559		129,989		79,125
ARP operating leases		17,545		3,903		6,397		4,152		3,093

Total contractual cash obligations	$	2,159,080	$	198,899	$	187,222	$	990,741	$	782,218

(1)

In connection with the Eagle Ford Acquisition, ARP guaranteed our Development Subsidiary’s deferred purchase obligation, whereby ARP provided a guaranty of timely payment of the deferred portion of the purchase price that is to be paid by our Development Subsidiary. Pursuant to the agreement between ARP and our Development Subsidiary, ARP will have the right to receive some or all of the assets acquired by our Development Subsidiary in the event of its failure to contribute its portion of any deferred payments.


			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	$	4,401	$	4,401	$	—	$	—	$	—
ARP other commercial commitments⁽²⁾		39,731		20,101		8,203		4,555		6,872

Total commercial commitments	$	44,132	$	24,502	$	8,203	$	4,555	$	6,872

(2)

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 GeoMet and EP Energy acquisitions. See “Business—Contractual Revenue Arrangements” for a description of ARP’s firm transportation obligations.

ISSUANCE OF UNITS

We recognize gains on ARP’s and our Development Subsidiary’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 and our Development Subsidiary’s common units over the book carrying amount per unit.

On February 26, 2015, we entered into the Series A Purchase Agreement with certain members of our management, two management members of the Board and an outside investor, pursuant to which, on February 27, 2015 we issued and sold an aggregate of 1.6 million of our newly created Series A convertible preferred units representing limited liability company interests, with a liquidation preference of $25.00 per unit, to the purchasers for a cash purchase price of $25.00 per unit in a privately negotiated transaction (see “Subsequent Events”).

Development Subsidiary Equity Offerings

During the year ended December 31, 2014, our Development Subsidiary issued $81.7 million of its common limited partner units, which was included within non-controlling interests on our combined consolidated balance sheets. During the year ended December 31, 2014, our Development Subsidiary paid $1.4 million to unitholders, which was included within distributions paid to non-controlling interests on our consolidated statement of cash flows. For the year ended December 31, 2014, in connection with the issuance of our Development Subsidiary’s common units, we recorded a gain of $4.5 million within equity and a corresponding decrease in non-controlling interests on our combined consolidated balance sheets.

Atlas Resource Equity Offerings

In October 2014, in connection with the Eagle Ford Acquisition (see “Recent Developments”), ARP issued 3,200,000 8.625% Class D Preferred Units at a public offering price of $25.00 per Class D Preferred Unit, yielding net proceeds of approximately $77.4 million from the offering, after deducting underwriting discounts and estimated offering expenses. ARP used the net proceeds from the offering to fund a portion of the Eagle Ford Acquisition. On January 15, 2015, ARP paid an initial quarterly distribution of $0.616927 per unit for the extended period from October 2, 2014 through January 14, 2015 to holders of record as of January 2, 2015. ARP will pay future cumulative distributions on a quarterly basis, at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference.

The Class D ARP Preferred Units rank senior to ARP’s common units and Class C convertible preferred units with respect to the payment of distributions and distributions upon a liquidation event and equal with ARP’s Class B convertible preferred units. The Class D ARP Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by ARP or converted into its common units in connection with a change in control. At any time on or after October 15, 2019, ARP may, at its option, redeem the Class D ARP Preferred Units in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, ARP may redeem the Class D ARP Preferred Units following certain changes of control, as described in the Certificate of Designation. If ARP does not exercise this redemption option upon a change of control, then holders of the Class D ARP Preferred Units will have the option to convert the Class D ARP Preferred Units into a number of ARP common units per Class D ARP Preferred Unit as set forth in the Certificate of Designation. If ARP exercises any of its redemption rights relating to the Class D ARP Preferred Units, the holders of such Class D ARP Preferred Units will not have the conversion right described above with respect to the Class D ARP Preferred Units called for redemption.

In August 2014, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of 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 December 31, 2014, no units have been sold under this program.

In May 2014, in connection with the closing of the Rangely Acquisition (see “Recent Developments”), 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 $297.3 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.

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 years ended December 31, 2014 and 2013, in connection with the issuance of ARP’s common units, we recorded gains of $40.5 million and $27.3 million, respectively, within equity and a corresponding decrease in non-controlling interests on our combined consolidated balance sheets and combined consolidated statement of equity.

ENVIRONMENTAL REGULATION

Our and our subsidiaries’ operations are subject to federal, state and local laws and regulations governing the release of regulated materials into the environment or otherwise relating to environmental protection or human health or safety (see “Item 1: Business—Environmental Matters and Regulation”). We believe that our and our subsidiaries’ operations and facilities are in substantial compliance with applicable environmental laws and regulations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; imposition of remedial requirements; issuance of injunctions affecting our operations; or other measures. We and our subsidiaries maintained and expect to continue to maintain environmental compliance programs. However, risks of accidental leaks or spills are associated with our and our subsidiaries’ operations. There can be no assurance that we and our subsidiaries will not incur significant costs and liabilities relating to claims for damages to property, the environment, natural resources, or persons resulting from the operation of our and our subsidiaries’ business. Moreover, it is possible other developments, such as increasingly strict federal, state and local environmental laws and regulations and enforcement policies, could result in increased costs and liabilities to us and our subsidiaries.

Environmental laws and regulations have changed substantially and rapidly over the last 25 years, and we anticipate that there will be continuing changes. Trends in environmental regulation include increased reporting obligations and placing more restrictions and limitations on activities, such as emissions of greenhouse gases and other pollutants; generation and disposal of wastes, including wastes that may have naturally occurring radioactivity; and use, storage and handling of chemical substances that may impact human health, the environment and/or threatened or endangered species. Other increasingly stringent environmental restrictions and limitations have resulted in increased operating costs for us and our subsidiaries and other similar businesses throughout the United States. It is possible that the costs of compliance with environmental laws and regulations may continue to increase. We and our subsidiaries will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly, but there can be no assurance that we and our subsidiaries will identify and properly anticipate each such change, or that our and our subsidiaries’ efforts will prevent material costs, if any, from rising.

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. We summarize our significant accounting policies within our consolidated financial statements included in “Item 8: Financial Statements and Supplementary Data – Note 2” included in this report. 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.

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. As discussed in “General Trends and Outlook”, recent increases in natural gas and oil drilling have driven an increase in the supply of natural gas and oil and put a downward pressure on domestic prices. Further declines in natural gas prices may result in additional impairment charges in future periods. Declines in natural gas and oil prices may result in impairment charges in future periods.

During the year ended December 31, 2014, we recognized $562.6 million of asset impairments related to oil and gas properties primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014 through the impairment testing date in January 2015. 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 and New Albany Shales. 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 and Niobrara Shales. These impairments related to the carrying amount of these gas and oil properties being in excess of our and our subsidiaries’ estimates of their fair values at December 31, 2014, 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 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 “Item 1A: Risk Factors” in this report.

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.

During the year ended December 31, 2014, ARP recorded an $18.1 million goodwill non-cash impairment loss within asset impairment on our combined consolidated statement of operations related to an impairment of goodwill in its gas and oil production reporting unit due to a decline in overall commodity prices. There were no goodwill impairments recognized by ARP during the years ended December 31, 2013 and 2012.

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.

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 years ended December 31, 2014, 2013 and 2012, we and our subsidiaries completed several acquisitions of oil and gas properties and related assets. 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 (see “Item 8: Financial Statements and Supplementary Data—Note 7”). 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. We and ARP engaged independent third-party reserve engineers, to prepare reports of our and ARP’s proved reserves (see “Item 2: Properties”).

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.

Asset Retirement Obligations

We and our subsidiaries estimate the cost of future dismantlement, restoration, reclamation and abandonment of our operating assets.

We and our subsidiaries recognize an estimated liability for the plugging and abandonment of gas and oil wells and related facilities. We and our subsidiaries 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 our subsidiaries 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 our subsidiaries 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

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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 our subsidiaries 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 our subsidiaries’ tangible long-lived assets.

ITEM 7A:

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 December 31, 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. We and ARP 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.

Interest Rate Risk. As of December 31, 2014, we had $148.1 million of allocated outstanding borrowings under Atlas Energy’s Term Facility and ARP had $696.0 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 December 31, 2014 by $8.4 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 ARP 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 ARP 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 December 31, 2015 of approximately $4.2 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 ARP’s 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

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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 December, 2014, we had the following commodity derivatives:

Natural Gas—Fixed Price Swaps


Production Period Ending December 31,	Volumes		Average Fixed Price
	(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾
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.

As of December 31, 2014, ARP had the following commodity derivatives:

Natural Gas – Fixed Price Swaps


Production Period Ending December 31,	Volumes		Average Fixed Price
	(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾
2015		54,834,500	$	4.226
2016		53,546,300	$	4.229
2017		46,320,000	$	4.276
2018		35,760,000	$	4.250
2019		9,720,000	$	4.234

Natural Gas – Costless Collars


Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap
		(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾
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	Volumes		Average Fixed Price
		(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾
2015	Puts purchased		1,440,000	$	4.000
2016	Puts purchased		1,440,000	$	4.150

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Natural Gas – WAHA Basis Swaps


Production Period Ending December 31,	Volumes		Average Fixed Price
	(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾
2015		5,250,000	$	(0.082	)

Natural Gas Liquids – Natural Gasoline Fixed Price Swaps


Production Period Ending December 31,	Volumes		Average Fixed Price
	(Gal)⁽¹⁾		(per Gal)⁽¹⁾
2015		5,040,000	$	1.983

Natural Gas Liquids – Propane Fixed Price Swaps


Production Period Ending December 31,	Volumes		Average Fixed Price
	(Gal)⁽¹⁾		(per Gal)⁽¹⁾
2015		8,064,000	$	1.016

Natural Gas Liquids – Butane Fixed Price Swaps


Production Period Ending December 31,	Volumes		Average Fixed Price
	(Gal)⁽¹⁾		(per Gal)⁽¹⁾
2015		1,512,000	$	1.248

Natural Gas Liquids – Iso Butane Fixed Price Swaps


Production Period Ending December 31,	Volumes		Average Fixed Price
	(Gal)⁽¹⁾		(per Gal)⁽¹⁾
2015		1,512,000	$	1.263

Natural Gas Liquids – Crude Fixed Price Swaps


Production Period Ending December 31,	Volumes		Average Fixed Price
	(Bbl)⁽¹⁾		(per Bbl)⁽¹⁾
2016		84,000	$	85.651
2017		60,000	$	83.780

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Crude Oil – Fixed Price Swaps


Production Period Ending December 31,	Volumes		Average Fixed Price
	(Bbl)⁽¹⁾		(per Bbl)⁽¹⁾
2015		1,743,000	$	90.645
2016		1,209,000	$	87.360
2017		672,000	$	85.669
2018		540,000	$	85.466

Crude Oil – Costless Collars


Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap
		(Bbl)⁽¹⁾		(per Bbl)⁽¹⁾
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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ITEM 8:

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Atlas Energy Group, LLC

We have audited the accompanying combined consolidated balance sheets of Atlas Energy Group, LLC (a Delaware limited liability company) and subsidiaries and affiliates as defined in Note 1 (collectively “New Atlas Operations and subsidiaries” or the “Company”) as of December 31, 2014 and 2013, 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, 2014. These financial statements are the responsibility of the Company’s 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. 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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2014, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 27, 2015 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

March 27, 2015

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NEW ATLAS OPERATIONS AND SUBSIDIARIES

COMBINED CONSOLIDATED BALANCE SHEETS

(in thousands)


	December 31,
	2014		2013
ASSETS
Current assets:
Cash and cash equivalents	$	58,358	$	10,625
Accounts receivable		115,290		60,167
Advances to affiliates		4,389		2,912
Current portion of derivative asset		144,259		1,891
Subscriptions receivable		32,398		47,692
Prepaid expenses and other		26,789		10,181

Total current assets		381,483		133,468
Property, plant and equipment, net		2,419,289		2,186,683
Intangible assets, net		691		963
Goodwill		13,639		31,784
Long-term derivative asset		130,602		28,598
Other assets, net		80,611		74,374

Total assets	$	3,026,315	$	2,455,870

LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	1,500	$	1,500
Accounts payable		123,670		70,228
Liabilities associated with drilling contracts		40,611		49,377
Current portion of derivative liability		—		6,386
Current portion of derivative payable to Drilling Partnerships		932		2,676
Accrued interest		26,479		20,649
Accrued well drilling and completion costs		92,910		40,899
Deferred acquisition purchase price		105,000		—
Accrued liabilities		64,854		34,097

Total current liabilities		455,956		225,812
Long-term debt, less current portion		1,541,085		1,090,459
Asset retirement obligations and other		114,059		95,603

Commitments and contingencies

Equity:
Owner’s equity		147,308		357,378
Accumulated other comprehensive income		54,008		10,338

		201,316		367,716
Non-controlling interests		713,899		676,280

Total equity		915,215		1,043,996

Total liabilities and equity	$	3,026,315	$	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)


	Years Ended December 31,
	2014			2013			2012
Revenues:
Gas and oil production	$	475,758		$	273,906		$	92,901
Well construction and completion		173,564			167,883			131,496
Gathering and processing		14,107			15,676			16,267
Administration and oversight		15,564			12,277			11,810
Well services		24,959			19,492			20,041
Other, net		4,558			(14,135	)		(3,346	)

Total revenues		708,510			475,099			269,169

Costs and expenses:
Gas and oil production		184,296			100,178			26,624
Well construction and completion		150,925			145,985			114,079
Gathering and processing		15,525			18,012			19,491
Well services		10,007			9,515			9,280
General and administrative		90,476			89,957			75,475
Chevron transaction expense		—			—			7,670
Depreciation, depletion and amortization		242,079			139,916			52,582
Asset impairment		580,654			38,014			9,507

Total costs and expenses		1,273,962			541,577			314,708

Operating loss		(565,452	)		(66,478	)		(45,539	)
Loss on asset sales and disposal		(1,859	)		(987	)		(6,980	)
Interest expense		(73,435	)		(39,712	)		(4,548	)

Net loss		(640,746	)		(107,177	)		(57,067	)
Loss attributable to non-controlling interests		471,439			58,389			17,184

Net loss attributable to owner	$	(169,307	)	$	(48,788	)	$	(39,883	)

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,
	2014			2013			2012
Net loss	$	(640,746	)	$	(107,177	)	$	(57,067	)
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges		156,551			15,828			10,921
Less: reclassification adjustment for realized (gains) loss of cash flow hedges in net income (loss)		7,739			(10,216	)		(19,281	)

Total other comprehensive income (loss)		164,290			5,612			(8,360	)

Comprehensive loss		(476,456	)		(101,565	)		(65,427	)
Comprehensive loss attributable to non-controlling interests		350,819			53,416			5,314

Comprehensive loss attributable to owner	$	(125,637	)	$	(48,149	)	$	(60,113	)

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 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 from 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 from 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
Distributions to non-controlling interests		—			—			(142,386	)		(142,386	)
Net issued and unissued common units under incentive plan		—			—			7,391			7,391
Non-controlling interests’ capital contribution		—			—			585,240			585,240
Net distribution to Atlas Energy		(85,772	)		—			—			(85,772	)
Distribution equivalent rights paid on unissued units under incentive plans		—			—			(2,158	)		(2,158	)
Distribution payable		—			—			(14,640	)		(14,640	)
Gain on sale from subsidiary unit issuances		45,009			—			(45,009	)		—
Other comprehensive income		—			43,670			120,620			164,290
Net loss		(169,307	)		—			(471,439	)		(640,746	)

Balance at December 31, 2014	$	147,308		$	54,008		$	713,899		$	915,215

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,
	2014			2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(640,746	)	$	(107,177	)	$	(57,067	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		242,079			139,916			52,582
Asset impairment		580,654			38,014			9,507
Amortization of deferred financing costs		10,462			10,263			1,963
Non-cash compensation expense		7,731			12,680			10,797
Loss on asset sales and disposal		1,859			987			6,980
Distributions paid to non-controlling interests		(144,544	)		(75,068	)		(14,014	)
Equity income in unconsolidated companies		(1,136	)		(2,594	)		(1,540	)
Distributions received from unconsolidated companies		1,695			1,022			931
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other		(58,869	)		(22,283	)		(62,663	)
Accounts payable and accrued liabilities		76,902			8,081			66,048

Net cash provided by operating activities		76,087			3,841			13,524

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(225,636	)		(267,480	)		(127,226	)
Net cash paid for acquisitions		(741,522	)		(780,857	)		(709,832	)
Other		4,211			(5,187	)		(767	)

Net cash used in investing activities		(962,947	)		(1,053,524	)		(837,825	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facilities		1,393,000			1,107,625			672,724
Repayments under credit facilities		(1,117,500	)		(896,050	)		(315,674	)
Net proceeds from issuance of subsidiary long-term debt		170,596			510,396			—
Net proceeds from subsidiary equity offerings		585,240			326,421			483,277
Net investment from (distributions to) Atlas Energy		(85,772	)		12,774			(31,177	)
Deferred financing costs, distribution equivalent rights and other		(10,971	)		(24,128	)		(16,287	)

Net cash provided by financing activities		934,593			1,037,038			792,863

Net change in cash and cash equivalents		47,733			(12,645	)		(31,438	)
Cash and cash equivalents, beginning of year		10,625			23,270			54,708

Cash and cash equivalents, end of year	$	58,358		$	10,625		$	23,270

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 formed in October 2011 (the “Company”). At December 31, 2014, the Company was wholly-owned by Atlas Energy, L.P. (“Atlas Energy”), a then publicly-traded Delaware master limited partnership (NYSE: ATLS). On February 27, 2015, Atlas Energy transferred its assets and liabilities, other than those related to its midstream assets, to the Company, and effected a pro rata distribution to its unitholders of the Company’s common units representing a 100% interest in the Company (the “Separation”). The assets and liabilities that were transferred to the Company by Atlas Energy in connection with the Separation are referred to as “New Atlas”. New Atlas’s common units began trading “regular-way” under the ticker symbol “ATLS” on the New York Stock Exchange on March 2, 2015. Concurrently with the distribution of New Atlas’s units, Atlas Energy and its remaining midstream interests merged with Targa Resources Corp. (“Targa”; NYSE: TRGP) and ceased trading.

As the Separation was not consummated until after the completion of the historical periods covered by this Form 10-K, the Company has included within its combined consolidated financial statements the assets and liabilities and related results of operations of New Atlas. As such, the remainder of the discussion within these financial statements and notes thereto will reflect the New Atlas business transferred to the Company on February 27, 2015.

New Atlas’s assets, assuming the Separation had been completed as of December 31, 2014, consist of:

•

100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 27.7% limited partner interest (consisting of 20,962,485 common and 3,749,986 preferred limited partner units) in Atlas Resource Partners, L.P. (“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;

•

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

In February 2012, the Board of Directors of Atlas Energy 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, 2014 and 2013 and the related combined consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012 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 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.

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In connection with Atlas Energy’s merger with Targa and New Atlas’s concurrent unit distribution, New Atlas was required to repay $150.0 million of Atlas Energy’s term loan credit facility, which was issued in July 2013 for $240.0 million. In accordance with generally accepted accounting principles, New Atlas included $150.0 million of Atlas Energy’s original term loan at the time of issuance, and the related interest expense, within its historical financial statements. In addition, all of Atlas Energy’s other historical borrowings were allocated to New Atlas’s historical financial statements in the same ratio.

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 controls 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 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. On December 23, 2014, 3,796,900 of Class B ARP preferred units were voluntarily converted into common units. In October 2014, in connection with ARP’s acquisition of assets in the Eagle Ford Shale (see Note 4), ARP issued 3.2 million of its 8.625% Class D cumulative redeemable perpetual preferred units (“Class D ARP Preferred Units”). The initial quarterly distribution on the Class D ARP Preferred Units was $0.616927 per unit, representing the distribution for the period from October 2, 2014 through January 14, 2015. Subsequent to January 14, 2015, ARP will pay a future quarterly distribution on the Class D ARP Preferred Units at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference. At December 31, 2014 and 2013, $78.0 million and $96.5 million, respectively, related to ARP’s preferred units, are included within non-controlling interests on New Atlas’s combined consolidated statements of equity.

During the year ended December 31, 2014, the Development Subsidiary issued $81.7 million of its common limited partner units, which was included within non-controlling interests on New Atlas’s combined consolidated balance sheet. During the year ended December 31, 2014, the Development Subsidiary paid $1.4 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 year ended December 31, 2014, in connection with the issuance of the Development Subsidiary’s common units, New Atlas recorded gains of $4.5 million within equity and a corresponding decrease in non-controlling interests on New Atlas’s combined consolidated statement of equity (see Note 13).

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 Atlas Energy in order to derive the historical financial statements of New Atlas. 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.

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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, 2014 and 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 December 31, 2014 and 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’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 is then delivered to Anthem. The investor contributions are then 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 and its subsidiaries follow 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 its subsidiaries’ 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 and its subsidiaries review 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 its subsidiaries’ 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 and its subsidiaries estimate 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 indicate that New Atlas and its subsidiaries 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 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, 2014 and 2012.

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, 2014, New Atlas recognized $562.6 million of asset impairment related to oil and gas properties within property, plant and equipment, net on its combined consolidated

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balance sheet primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014 through the impairment testing date in January 2015. 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.

These impairments related to the carrying amounts of these gas and oil properties being in excess of New Atlas and its subsidiaries’ estimates of their fair values at December 31, 2014, 2013 and 2012 and ARP’s intention not to drill on certain expiring unproved acreage. The estimates of the fair values of these gas and oil properties were impacted by, among other factors, the deterioration of commodity prices at the respective dates 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 5.6%, 6.0% and 3.5% for the years ended December 31, 2014, 2013 and 2012, respectively. The amounts of interest capitalized by ARP were $13.0 million, $14.2 million and $2.1 million for the years ended December 31, 2014, 2013 and 2012, respectively.

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, 2014 and 2013 (in thousands):


	December 31,						Estimated Useful Lives In Years
	2014			2013			Estimated Useful Lives In Years
Gross Carrying Amount	$	14,344		$	14,344		13
Accumulated Amortization		(13,653	)		(13,381	)

Net Carrying Amount	$	691		$	963

Amortization expense on intangible assets was $0.3 million, $0.4 million and $0.2 million for the years ended December 31, 2014, 2013 and 2012, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2015 - $0.2 million; 2016 - $0.1 million; 2017 - $0.1 million; 2018 - $0.1 million; and 2019 - $0.1 million.

Goodwill

At December 31, 2014 and 2013, New Atlas had $13.6 million and $31.8 million, respectively, of goodwill recorded in connection with ARP’s prior consummated acquisitions. The change in ARP’s goodwill during the year end December 31, 2014 resulted from goodwill impairment related to its gas and oil production reporting unit.

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

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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.

As a result of its impairment evaluation at December 31, 2014, ARP recognized an $18.1 million goodwill impairment charge within asset impairments on New Atlas’s combined consolidated statement of operations for the year ended December 31, 2014. The goodwill impairment resulted from the reduction in ARP’s estimated fair value of its gas and oil production reporting unit in comparison to its carrying amount at December 31, 2014. ARP’s estimated fair value of its gas and oil production reporting unit was impacted by a decline in overall commodity prices during the fourth quarter of 2014. During the years ended December 31, 2013 and 2012, no impairment indicators arose and no goodwill impairments were recognized.

Derivative Instruments

New Atlas and ARP enter 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 and its subsidiaries recognize an estimated liability for the plugging and abandonment of gas and oil wells and related facilities (see Note 7). New Atlas and its subsidiaries also recognize 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 and its subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

Income Taxes

ARP, the 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 December 31, 2014 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 evaluates 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, 2014, 2013 and 2012.

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 December 31, 2014.

General and Administrative Expenses

For the years ended December 31, 2014, 2013 and 2012, Atlas Energy has allocated $6.4 million, $8.2 million and $6.4 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.

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Interest Expense

For the years ended December 31, 2014, 2013 and 2012, Atlas Energy has allocated $11.3 million, $5.4 million and $0.4 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 and its subsidiaries are 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 and its subsidiaries’ 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 and its subsidiaries maintain insurance which may cover in whole or in part certain environmental expenditures. New Atlas and its subsidiaries had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, 2014 and 2013. During the 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 and its subsidiaries to concentrations of credit risk consist principally of periodic temporary investments of cash and cash equivalents. New Atlas and its subsidiaries place their temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. At December 31, 2014 and 2013, New Atlas had $60.8 million and $23.9 million, respectively, in deposits at various banks, of which $57.7 million and $21.9 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 and its subsidiaries sell natural gas, oil, NGLs and condensate under contract to various purchasers in the normal course of business. For the year ended December 31, 2014, ARP had four customers within its gas and oil production segment that individually accounted for approximately 25%, 15%, 14% and 13%, respectively, of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. 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.

Revenue Recognition

Natural gas and oil production. New Atlas and its subsidiaries’ 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

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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 and its subsidiaries have 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 $1,000 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.

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 its subsidiaries’ 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

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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, 2014 and 2013 of $85.5 million and $56.9 million, respectively, which were included in accounts receivable within its combined consolidated balance sheets.

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 November 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-17, Business Combinations (Topic 805) – Pushdown Accounting (“Update 2014-17”). The amendments in Update 2014-17 provide an acquired entity with an option to apply pushdown accounting in its separate financial statements upon occurrence of an event in which an acquirer obtains control of the acquired entity. The amendments in Update 2014-17 also provide U.S. GAAP guidance on whether and at what threshold an acquired entity that is a business can apply pushdown accounting in its separate financial statements. The amendments in Update 2014-17 became effective on November 18, 2014. After the effective date, an acquired entity can make an election to apply the guidance to future change-in-control events or to its most recent change-in-control event. However, if the financial statements for the period in which the most recent change-in-control event occurred already have been issued or made available to be issued, the application of this guidance would be a change in accounting principle. New Atlas adopted the requirements of Update 2014-17 upon its effective date of November 18, 2014, and it had no material impact on its financial position, results of operations or related disclosures.

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 February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“Update 2015-02”). The amendments in Update 2015-02 are intended to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures. The amendments simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The amendments in Update 2015-02 are effective for periods beginning after December 31, 2015. Early adoption is permitted, including adoption in an interim period. New Atlas will adopt the requirements of Update 2015-02 upon its effective date of January 1, 2016, and is evaluating the impact of adoption on its financial position, results of operations or related disclosures.

In January 2015, the FASB issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update 2015-01”). The amendments in Update 2015-01 simplify the income statement presentation requirements in Subtopic 225-20 by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. Eliminating the extraordinary classification simplifies income statement presentation by altogether removing the concept of extraordinary items from consideration. The amendments in Update 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A

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reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. New Atlas will adopt the requirements of Update 2015-01 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 November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815) – Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity (“Update 2014-16”). Certain classes of shares include features that entitle the holders to preferences and rights (such as conversion rights, redemption rights, voting powers, and liquidation and dividend payment preferences) over the other shareholders. Shares that include embedded derivative features are referred to as hybrid financial instruments, which must be separated from the host contract and accounted for as a derivative if certain criteria are met under Subtopic 815-10. One criterion requires evaluating whether the nature of the host contract is more akin to debt or to equity and whether the economic characteristics and risks of the embedded derivative feature are “clearly and closely related” to the host contract. In making that evaluation, an issuer or investor may consider all terms and features in a hybrid financial instrument including the embedded derivative feature that is being evaluated for separate accounting or may consider all terms and features in the hybrid financial instrument except for the embedded derivative feature that is being evaluated for separate accounting. The use of different methods can result in different accounting outcomes for economically similar hybrid financial instruments. Additionally, there is diversity in practice with respect to the consideration of redemption features in relation to other features when determining whether the nature of a host contract is more akin to debt or to equity. The amendments in Update 2014-16 clarify how current GAAP should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. The effects of initially adopting the amendments in Update 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in the form of a share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. The amendments in Update 2014-16 are effective for fiscal years, and interim periods within those fiscal years, New Atlas will adopt the requirements of Update 2014-16 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 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 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,

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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 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 interest, 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 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.

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.

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NOTE 4—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 from Merit Management Partners I, L.P., Merit Energy Partners III, L.P. and Merit Energy Company, LLC (collectively, “Merit Energy”) for approximately $409.4 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 8) and the issuance of 15,525,000 of ARP’s common limited partner units (see Note 13). 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 10). In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $11.6 million of transaction fees which were included within non-controlling interests at December 31, 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		405,876
Other assets, net		2,888

Total assets acquired	$	412,805

Liabilities:
Accrued liabilities		2,117
Asset retirement obligation		1,305

Total liabilities assumed		3,422

Net assets acquired	$	409,383

Revenues and net income of $41.5 million and $18.8 million, respectively, have been included in New Atlas’s combined consolidated statement of operations related to the Rangely Acquisition for the year ended December 31, 2014.

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.

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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:
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

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).

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

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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.

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.

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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

Pro Forma Financial Information

The following data presents pro forma revenues and net loss for New Atlas as if the Rangely and EP Energy 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, 2013. For the year ended December 31, 2014, New Atlas has also included the pro forma effect of the Rangely Acquisition and its related financings (see Note 8). 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):


	Years Ended December 31,
	2014			2013
Total revenues and other	$	754,511		$	657,300
Net loss		(602,707	)		(21,402	)
Net income (loss) attributable to owner		(146,227	)		(186	)

Other Acquisitions

On November 5, 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 from Cima Resources, LLC and Cinco Resources, Inc. (together “Cinco”) for $339.2 million, net of purchase price adjustments (the “Eagle Ford Acquisition”). Approximately $179.5 million was paid in cash by ARP and $19.7 million was paid by the Development Subsidiary at closing, and approximately $140.0 million will be paid over the four quarters following closing. The deferred portion of the purchase price represents a non-cash transaction for statement of cash flow purposes during the year ended December 31, 2014. 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 its 8.625% Class D ARP Preferred Units at a price of $25.00 per unit (see Note 13). In connection with the closing of the Eagle Ford Acquisition, ARP’s revolving credit facility was amended to increase the borrowing base to $900.0 million and to make certain amendments to allow for the deferred purchase payments. The Eagle Ford Acquisition had an effective date of July 1, 2014. New Atlas recorded $2.8 million of gains on mark-to-market derivatives within other, net on its combined consolidated statement of operations for the year ended December 31, 2014 in conjunction with the entering into derivative instruments upon signing the Eagle Ford Acquisition.

On May 12, 2014, ARP completed the acquisition of certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $97.9 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.

On September 20, 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.

On July 31, 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.

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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.

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
	2014			2013			Estimated Useful Lives in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	535,893		$	322,217
Pre-development costs		7,378			4,367
Wells and related equipment		3,096,562			2,231,213

Total proved properties		3,639,833			2,557,797
Unproved properties		217,321			211,851
Support equipment		37,359			23,258

Total natural gas and oil properties		3,894,513			2,792,906
Pipelines, processing and compression facilities		49,547			43,120		2–40
Rights of way		830			830		20–40
Land, buildings and improvements		9,160			9,462		3–40
Other		17,936			15,321		3–10

		3,971,986			2,861,639
Less—accumulated depreciation, depletion and amortization		(1,552,697	)		(674,956	)

	$	2,419,289		$	2,186,683

During the year ended December 31, 2014, New Atlas recognized $1.9 million of loss on asset sales and disposal primarily pertaining to ARP’s sale of producing wells in the Niobrara Shale in connection with the settlement of a third party farm-out agreement. 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, 2014, New Atlas recognized $562.6 million of asset impairment related to oil and gas properties within property, plant and equipment, net on New Atlas’s combined consolidated balance sheet primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014 through the impairment testing date in January 2015. 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.

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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.

These impairments related to the carrying amounts of gas and oil properties being in excess of New Atlas and its subsidiaries’ estimates of their fair values at December 31, 2014, 2013 and 2012 and ARP’s intention not to drill on certain expiring unproved acreage. The estimates of fair values of these gas and oil properties were impacted by, among other factors, the deterioration of commodity prices at the respective dates of measurement.

During the years ended December 31, 2014 and 2013, the Company recognized $36.8 million and $11.4 million of non-cash property, plant and equipment additions, respectively, which were excluded 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,
	2014		2013
Deferred financing costs, net of accumulated amortization of $23,193 and $12,731 at December 31, 2014 and 2013, respectively	$	46,120	$	41,686
Investment in Lightfoot		21,123		21,454
Rabbi Trust		3,925		3,705
Security deposits		229		264
ARP notes receivable		3,866		3,978
Other		5,348		3,287

	$	80,611	$	74,374

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 and its subsidiaries’ deferred financing costs was $9.9 million, $7.0 million and $2.0 million for the years ended December 31, 2014, 2013 and 2012, respectively, which was recorded within interest expense on New Atlas’s combined consolidated statements of operations. There was no accelerated amortization of deferred financing costs for New Atlas during the years ended December 31, 2014, 2013 and 2012.

During the year ended December 31, 2014, ARP recognized $0.6 million for accelerated amortization of deferred financing costs associated with a reduction of the borrowing base under its revolving credit facility. During the year ended December 31, 2013, ARP recognized $3.2 million for accelerated amortization of deferred financing costs associated with the retirement of a portion of its 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 8). There was no accelerated amortization of deferred financing costs for ARP during the year ended December 31, 2012.

ARP notes receivable. At December 31, 2014 and 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 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 each of the years ended December 31, 2014 and 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 year ended December 31, 2012. At December 31, 2014 and 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 December 31, 2014, 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 Company’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, 2014, 2013 and 2012, New Atlas recognized equity income of approximately $1.1 million,

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$2.6 million and $1.5 million, respectively, within other, net on New Atlas’s combined consolidated statements of operations. During the years ended December 31, 2014, 2013 and 2012, New Atlas received net cash distributions of approximately $1.7 million, $1.0 million and $0.9 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”.

NOTE 7—ASSET RETIREMENT OBLIGATIONS

New Atlas and its subsidiaries recognized an estimated liability for the plugging and abandonment of their respective gas and oil wells and related facilities. New Atlas and its subsidiaries 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 its subsidiaries 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 its subsidiaries have no assets legally restricted for purposes of settling asset retirement obligations. Except for New Atlas and its subsidiaries’ 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, 2014, the Drilling Partnerships had $47.6 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, 2014, ARP withheld approximately $1.6 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 and ARP’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):


	Years Ended December 31
	2014			2013			2012
Asset retirement obligations, beginning of year	$	91,214		$	64,794		$	45,779
Liabilities incurred		10,674			23,129			16,568
Liabilities settled		(1,664	)		(1,188	)		(546	)
Accretion expense		5,759			4,479			2,993
Revisions		2,118			—			—

Asset retirement obligations, end of year	$	108,101		$	91,214		$	64,794

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 years ended December 31, 2014 and 2013, New Atlas incurred $0.1 million and $1.3 million, respectively, of future plugging and abandonment costs within purchase accounting related to the acquisitions it consummated during the periods. During the years ended December 31,

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2014, 2013 and 2012, ARP incurred $7.0 million, $16.7 million and $15.6 million, respectively, of future plugging and abandonment liabilities within purchase accounting related to the acquisitions it consummated during the periods. New Atlas did not incur any future plugging and abandonment costs related to acquisitions during the year ended December 31, 2012.

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NOTE 8—DEBT

Total debt consists of the following at the dates indicated (in thousands):


	December 31,
	2014			2013
Term loan facility	$	148,125		$	149,625
Revolving credit facility		—			—
ARP revolving credit facility		696,000			419,000
ARP 7.75% Senior Notes—due 2021		374,544			275,000
ARP 9.25% Senior Notes—due 2021		323,916			248,334

Total debt		1,542,585			1,091,959
Less current maturities		(1,500	)		(1,500	)

Total long-term debt	$	1,541,085		$	1,090,459

Term Loan Facility

On July 31, 2013, in connection with the Arkoma Acquisition (see Note 4), Atlas Energy entered into a $240.0 million secured term loan facility with a group of outside investors (the “Term Facility”). At December 31, 2014, $148.1 million of the Term Facility was attributable to New Atlas. The Term Facility had 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 was required to repay principal at the rate of $0.6 million per quarter commencing December 31, 2013 and continuing until the maturity date when the remaining balance was due. At December 31, 2014, the weighted average interest rate on outstanding borrowings under the Term Facility was 6.5%.

The Term Facility contained 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 contained covenants that required 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 December 31, 2014, Atlas Energy was in compliance with these covenants. The events which constituted 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.

Atlas Energy’s obligations under the Term Facility were 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 Atlas Pipeline Partners, L.P. (“APL”) and ARP. Additionally, Atlas Energy’s obligations under its Term Facility were guaranteed by its material wholly-owned subsidiaries (excluding Atlas Pipeline Partners GP, LLC) and may be guaranteed by future subsidiaries. Any of Atlas Energy’s subsidiaries, other than the subsidiary guarantors, are minor. The Term Facility was subject to an intercreditor agreement, which provided 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.

In connection with Atlas Energy’s merger with Targa, the Term Facility was repaid in full on February 27, 2015 (see Note 17).

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ARP’s Credit Facility

On November 24, 2014, ARP entered into a Fifth Amendment to its Second Amended and Restated Credit Agreement dated July 31, 2013 with Wells Fargo Bank National Association, as administrative agent, and the lenders party thereto, among ARP as borrower, the administrative agent and the lenders party thereto (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 $900.0 million and a maximum facility amount of $1.5 billion scheduled to mature in July 2018.

The Fifth Amendment was entered into in connection with the previously announced restructuring of ARP’s general partner and the sale of Atlas Energy and its midstream assets (see Note 1). Among other things, the Fifth Amendment amended several definitions for the purpose of ensuring that the sale did not result in a Change of Control or Event of Default as defined in the ARP Credit Agreement.

On September 24, 2014, in connection with its Eagle Ford Acquisition (see Note 4), ARP entered into a fourth amendment to the ARP Credit Agreement. In connection with the closing of the Eagle Ford Acquisition, the borrowing base under ARP’s revolving credit facility was increased from $825.0 million to $900.0 million. The fourth amendment amended 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 to be acquired in the Eagle Ford Acquisition.

On June 30, 2014, in connection with the Rangely Acquisition (see Note 4), ARP entered into a third amendment to the ARP Credit Agreement. Among other things, pursuant to the third amendment:

•

the borrowing base was increased to $825.0 million;

•

if the borrowing base utilization is less than 25%, ARP will incur the applicable margin on Eurodollar loans of 1.50%, the applicable margin on alternative base rate loans of 0.50% and a commitment fee rate of 0.375%; and

•

the maximum ratio of Total Funded Debt to EBITDA was revised to be (i) 4.50 to 1.0 as of the last day of the quarters ended on June 30, 2014, September 30, 2014 and December 31, 2014, (ii) 4.25 to 1.0 as of the last day of the quarter ending on March 31, 2015 and (iii) 4.00 to 1.0 as of the last day of each quarter thereafter.

ARP’s borrowing base is scheduled for semi-annual redeterminations on May 1 and November 1 of each year. At December 31, 2014, $696.0 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 $4.4 million was outstanding at December 31, 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 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% per annum 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 December 31, 2014, the weighted average interest rate on outstanding borrowings under the credit facility was 2.9%.

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 December 31, 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 on June 30, 2014, September 30, 2014 and 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. Based on the definitions contained in the ARP Credit Agreement, at December 31, 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 3.6 to 1.0.

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On February 23, 2015, ARP entered into a Sixth Amendment to the ARP Credit Agreement (the “Sixth Amendment”) and a Second Lien Credit Agreement (the “Second Lien Credit Agreement”) (see Note 17).

ARP Senior Notes

At December 31, 2014, ARP had $374.5 million outstanding of its 7.75% ARP Senior Notes, including $100.0 million of such notes issued 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 (see Note 4). The 7.75% ARP Senior Notes were presented net of a $0.5 million unamortized discount as of December 31, 2014. 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 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 its 7.75% ARP Senior Notes. Under the registration rights agreements, ARP agreed to (a) file exchange offer registration statements with the SEC to exchange the privately issued notes for registered notes, (b) cause the exchange offer for the $275.0 million of 7.75% ARP Senior Notes issued on January 23, 2013 to be consummated not later than 365 days after the issuance of such notes and (c) cause the exchange offer for the $100.0 million of 7.75% ARP Senior Notes issued on June 2, 2014 to be consummated not later than 270 days after the issuance of such notes. A registration statement relating to the exchange offer for the $275.0 million of 7.75% ARP Senior Notes issued January 23, 2013 was declared effective on December 2, 2013, and the exchange offer for such notes was completed on January 2, 2014. A registration statement relating to the exchange offer for the $100.0 million of 7.75% ARP Senior Notes issued June 2, 2014 was declared effective on October 17, 2014 and the exchange offer for such notes was completed on November 18, 2014.

At December 31, 2014, ARP had $323.9 million outstanding of its 9.25% ARP Senior Notes, including $75.0 million of such notes issued in a private placement transaction on October 14, 2014 at an offering price of 100.5% of par value, which yielded net proceeds of approximately $73.6 million. The 9.25% ARP Senior Notes issued in October 2014 were presented net of a $0.4 million unamortized premium as of December 31, 2014. The 9.25% ARP Senior Notes issued in July 2013 were presented net of a $1.5 million unamortized discount as of December 31, 2014. ARP used the net proceeds from this offering to fund a portion of its Eagle Ford Acquisition (see Note 4). 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 109.250%. 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 $75.0 million of 9.25% ARP Senior Notes on October 14, 2014, ARP entered into a registration rights agreement whereby 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 not 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 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 period, 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 statement is declared effective, as applicable.

In connection with the issuance of the $250.0 million of 9.25% ARP Senior Notes on July 30, 2013, ARP entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange

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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 7.75% ARP Senior Notes and 9.25% ARP Senior Notes are guaranteed by certain of ARP’s material subsidiaries. The guarantees under the 7.75% ARP Senior Notes and 9.25% 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 7.75% ARP Senior Notes and 9.25% 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, 2014.

The aggregate amounts of New Atlas’s and ARP’s future debt maturities are as follows (in thousands):


Years Ended December 31:
2015	$	1,500
2016		1,500
2017		145,125
2018		696,000
2019		—
Thereafter		700,000

Total principal maturities		1,544,125
Unamortized premiums		364
Unamortized discounts		(1,904	)

Total debt	$	1,542,585

Cash payments for interest by New Atlas were $68.5 million, $22.3 million and $3.1 million for the years ended December 31, 2014, 2013 and 2012, 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 apply the principles of hedge accounting for derivatives qualifying as hedges. 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

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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 other, net 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 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 other, net 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 $274.9 million and $24.0 million at December 31, 2014 and 2013, respectively. Of the $54.0 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, 2014, if the fair values of the instruments remain at current market values, New Atlas will reclassify $27.2 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 $26.8 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 $2.5 million and $3.9 million of derivative gains were reclassified from other comprehensive income related to derivative instruments entered into during the year ended December 31, 2014 and 2013, respectively.

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,
	2014		2013			2012
(Gain) loss reclassified from accumulated other comprehensive income:
Gas and oil production revenue	$	7,739	$	(10,216	)	$	(19,281	)

Total	$	7,739	$	(10,216	)	$	(19,281	)

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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, 2014
Current portion of derivative assets	$	2,893	$	—		$	2,893
Long-term portion of derivative assets		2,669		—			2,669

Total derivative assets	$	5,562	$	—		$	5,562

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 December 31, 2014
Current portion of derivative assets	$	—		$	—	$	—
Long-term portion of derivative assets		—			—		—

Total 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	)

During the years ended December 31, 2014 and 2013, New Atlas recorded gains of $0.7 million and $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 statements of operations. No gains or losses were recorded on settled derivative contracts within New Atlas’s combined consolidated statements of operations for the year ended December 31, 2012 as New Atlas had no derivative contracts in 2012. 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 years ended December 31, 2014 and 2013 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

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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, 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⁾
2015		2,280,000	$	4.302	$	2,893
2016		1,440,000	$	4.433		1,374
2017		1,200,000	$	4.590		960
2018		420,000	$	4.797		335

		New Atlas’s net asset			$	5,562

⁽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 December 31, 2014
Current portion of derivative assets	$	141,464	$	(98	)	$	141,366
Long-term portion of derivative assets		128,303		(370	)		127,933

Total derivative assets	$	269,767	$	(468	)	$	269,299

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 December 31, 2014
Current portion of derivative assets	$	(98	)	$	98	$	—
Long-term portion of derivative assets		(370	)		370		—

Total derivative liabilities	$	(468	)	$	468	$	—

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	)

During the year ended December 31, 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 4). 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 and were fully amortized as of September 30, 2013. Swaption contract premiums paid are amortized over the period from initiation of the contract through their 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.

During the year ended December 31, 2012, ARP entered into swaptions 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 and were initially recorded as derivative assets on New Atlas’s combined consolidated balance sheet and were fully amortized as of June 30, 2012. For the year ended December 31, 2012, ARP recorded approximately $4.6 million of amortization expense in other, net on New Atlas’s combined consolidated statement of operations related to the swaption contracts.

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. 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.

ARP recognized losses of $7.1 million and gains of $9.7 million and $19.3 million for the years ended December 31, 2014, 2013, and 2012, respectively, on settled contracts covering commodity production. These gains and loss 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, 2014, 2013, and 2012, respectively, for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

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At December 31, 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⁾
2015		54,834,500	$	4.226	$	65,393
2016		53,546,300	$	4.229		40,428
2017		46,320,000	$	4.276		22,999
2018		35,760,000	$	4.250		9,881
2019		9,720,000	$	4.234		1,023

					$	139,724

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⁾
2015	Puts purchased		3,480,000	$	4.234	$	4,478
2015	Calls sold		3,480,000	$	5.129		(59	)

						$	4,419

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⁾
2015	Puts purchased		1,440,000	$	4.000	$	1,506
2016	Puts purchased		1,440,000	$	4.150		1,261

						$	2,767

Natural Gas – WAHA Basis Swaps


Production Period Ending December 31,	Volumes		Average Fixed Price			Fair Value Asset
	(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾			(in thousands)⁽⁷⁾
2015		5,250,000	$	(0.082	)	$	153

						$	153

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)⁽⁸⁾
2015		5,040,000	$	1.983	$	4,630

					$	4,630

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Natural Gas Liquids – Propane Fixed Price Swaps


Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Gal)⁽¹⁾		(per Gal)⁽¹⁾		(in thousands)⁽⁴⁾
2015		8,064,000	$	1.016	$	4,011

					$	4,011

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)⁽⁵⁾
2015		1,512,000	$	1.248	$	829

					$	829

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)⁽⁶⁾
2015		1,512,000	$	1.263	$	826

					$	826

Natural Gas Liquids – Crude Fixed Price Swaps


Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Bbl)⁽¹⁾		(per Bbl)⁽¹⁾		(in thousands)⁽³⁾
2016		84,000	$	85.651	$	1,851
2017		60,000	$	83.780		984

					$	2,835

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⁾
2015		1,743,000	$	90.645	$	58,765
2016		1,209,000	$	87.360		28,663
2017		672,000	$	85.669		12,248
2018		540,000	$	85.466		8,595

					$	108,271

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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⁾
2015	Puts purchased		29,250	$	83.846	$	842
2015	Calls sold		29,250	$	110.654		(8	)

						$	834

					ARP’s net assets	$	269,299

⁽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 propane prices, as applicable.

⁽⁵⁾	Fair value based on forward Mt. Belvieu butane prices, as applicable.

⁽⁶⁾	Fair value based on forward Mt. Belvieu iso butane prices, as applicable.

⁽⁷⁾	Fair value based on forward WAHA natural gas prices, as applicable

⁽⁸⁾	Fair value based on forward Mt. Belvieu natural gasoline prices, as applicable.

At December 31, 2014, ARP had net cash proceeds of $0.2 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, 2014 and 2013.

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 December 31, 2014 and 2013, net unrealized derivative assets of $2.8 million and $1.4 million, respectively, were payable to the limited partners in the Drilling Partnerships related to these natural gas put option contracts.

At December 31, 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 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 and its subsidiaries have 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 and its subsidiaries’ 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.

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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.

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.

Information for New Atlas and ARP’s assets and liabilities measured at fair value at December 31, 2014 and 2013 was as follows (in thousands):


	Level 1		Level 2			Level 3		Total
As of December 31, 2014
Assets, gross
Rabbi trust	$	3,925	$	—		$	—	$	3,925
Commodity swaps		—		5,562			—		5,562
ARP Commodity swaps		—		261,680			—		261,680
ARP Commodity puts		—		2,767			—		2,767
ARP Commodity options		—		5,320			—		5,320

Total assets, gross		3,925		275,329			—		279,254

Liabilities, gross
Commodity swaps		—		—			—		—
ARP Commodity swaps		—		(401	)		—		(401	)
ARP Commodity options		—		(67	)		—		(67	)

Total derivative liabilities, gross		—		(468	)		—		(468	)

Total assets, fair value, net	$	3,925	$	274,861		$	—	$	278,786

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

Other Financial Instruments

The estimated fair values of New Atlas and its subsidiaries’ other financial instruments have 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 its subsidiaries could realize upon the sale or refinancing of such financial instruments.

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New Atlas and its subsidiaries’ 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, 2014 and 2013, which consist principally of ARP’s senior notes, borrowings under New Atlas’s term loan facility, and borrowings under ARP’s term loan and revolving credit facilities, were $1,363.4 million and $1,088.3 million, respectively, compared with the carrying amounts of $1,542.6 million and $1,092.0 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 its subsidiaries 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 its subsidiaries 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, 2014 and 2013 was as follows (in thousands):


	Years Ended December 31,
	2014				2013
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	10,674	$	10,674	$	23,129	$	23,129

Total	$	10,674	$	10,674	$	23,129	$	23,129

New Atlas and its subsidiaries estimate the fair value 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 years ended December 31, 2014, 2013 and 2012, ARP recognized $580.7 million, $38.0 million and $9.5 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, 2014, ARP completed the Eagle Ford, Rangely and GeoMet acquisitions (see Note 4). 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 estimated fair values of the assets acquired and liabilities assumed in the Eagle Ford, Rangely and GeoMet acquisitions as of the respective acquisition dates, which are reflected in New Atlas’s combined consolidated balance sheet as of December 31, 2014 are subject to change as the final valuations have not yet been completed, and such changes could 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’s and its subsidiaries’ 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 its subsidiaries’ 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

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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. At December 31, 2014, Atlas Energy maintained a general partner ownership interest in APL, formerly 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 the years ended December 31, 2014, 2013 and 2012, $0.3 million, $0.3 million and $0.4 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 in 2013 for these services.

Relationship with Resource America, Inc. In connection with the issuance of Atlas Energy’s 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 such 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

New Atlas leases office space and equipment under leases with varying expiration dates. Rental expense was $16.7 million, $13.1 million, and $4.1 million for the years ended December 31, 2014, 2013, and 2012, respectively. Future minimum rental commitments for the next five years are as follows (in thousands):


Years Ended December 31,
2015	$	3,903
2016		3,307
2017		3,090
2018		2,845
2019		1,307
Thereafter		3,093

	$	17,545

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, 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.

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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, 2014, 2013 and 2012, $5.3 million, $9.6 million and $6.3 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 was a party to employment agreements with certain executives that provided compensation and certain other benefits. The agreements also provided for severance payments under certain circumstances.

In connection with the Eagle Ford Acquisition (see Note 4), ARP guaranteed the Development Subsidiary’s deferred purchase obligation, whereby ARP provided a guaranty of timely payment of the deferred portion of the purchase price that is to be paid by the Development Subsidiary. Pursuant to the agreement between ARP and the Development Subsidiary, ARP will have the right to receive some or all of the assets acquired by the Development Subsidiary in the event of its failure to contribute its portion of any deferred payments.

In connection with ARP’s GeoMet 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, 2014 were as follows: 2015— $2.5 million; 2016— $2.4 million; 2017— $2.0 million; 2018— $1.8 million; 2019— $1.8 million; thereafter— $6.9 million.

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, 2014 were as follows: 2015— $8.3 million; 2016— $2.1 million; and 2017 to 2019— none.

As of December 31, 2014, New Atlas and its subsidiaries are committed to expend approximately $18.9 million on drilling and completion expenditures.

Legal Proceedings

New Atlas and its subsidiaries are parties to various routine legal proceedings arising out of the ordinary course of its business. Management of New Atlas and its subsidiaries believe 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 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 October 2014, in connection with the Eagle Ford Acquisition (see Note 4), ARP issued 3,200,000 8.625% Class D ARP Preferred Units at a public offering price of $25.00 per Class D ARP Preferred Unit, yielding net proceeds of approximately $77.4 million from the offering, after deducting underwriting discounts and estimated offering expenses. ARP used the net proceeds from the offering to fund a portion of the Eagle Ford Acquisition. On January 15, 2015, ARP paid an initial quarterly distribution of $0.616927 per unit for the extended period from October 2, 2014 through January 14, 2015 to holders of record as of January 2, 2015 (see Note 14). ARP will pay future cumulative distributions on a quarterly basis, at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference.

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The Class D ARP Preferred Units rank senior to ARP’s common units and Class C ARP convertible preferred units with respect to the payment of distributions and distributions upon a liquidation event and equal with ARP’s Class B convertible preferred units. The Class D ARP Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by ARP or converted into its common units in connection with a change in control. At any time on or after October 15, 2019, ARP may, at its option, redeem the Class D ARP Preferred Units in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, ARP may redeem the Class D ARP Preferred Units following certain changes of control, as described in the Certificate of Designation. If ARP does not exercise this redemption option upon a change of control, then holders of the Class D ARP Preferred Units will have the option to convert the Class D ARP Preferred Units into a number of ARP common units per Class D unit as set forth in the Certificate of Designation. If ARP exercises any of its redemption rights relating to the Class D ARP Preferred Units, the holders of such Class D ARP Preferred Units will not have the conversion right described above with respect to the Class D ARP Preferred Units called for redemption.

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 December 31, 2014, no units have been sold under this program.

In May 2014, in connection with the closing of the Rangely Acquisition (see Note 4), 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 $297.3 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, in connection with the GeoMet Acquisition (see Note 4), 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 $129.0 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 4), ARP issued 3,749,986 of its newly created Class C convertible preferred units to Atlas Energy, at a negotiated price per unit of $23.10, for proceeds of $86.6 million. 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 such 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, Atlas Energy, as purchaser of the Class C preferred units, 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 common units of ARP at an exercise price of $23.10 per unit, subject to adjustments provided therein. The warrants will expire on July 31, 2016.

145

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. 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 this 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 had 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. On December 23, 2014, 3,796,900 of the ARP Class B preferred units were voluntarily converted into common units.

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 years ended December 31, 2014 and 2013, New Atlas recorded gains of $40.5 million and $27.3 million, respectively, within equity and a corresponding decrease in non-controlling interests on its combined consolidated balance sheets and combined consolidated statement of equity.

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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 its common units owned on the record date of February 28, 2012.

NOTE 14—CASH DISTRIBUTIONS

New Atlas has a cash distribution policy under which it distributes, within 50 days following the end of each calendar quarter, all of its available cash (as defined in its limited liability agreement) for that quarter to its common unitholders.

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 whereby it distributes 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 from January 1, 2012 through December 31, 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’s Class A Units
May 15, 2012	March 31, 2012	$	0.1200	⁽¹⁾	$	3,144	$	—		$	64
August 14, 2012	June 30, 2012	$	0.4000		$	12,891	$	—		$	263
November 14, 2012	September 30, 2012	$	0.4300		$	15,510	$	1,652		$	350
February 14, 2013	December 31, 2012	$	0.4800		$	21,107	$	1,841		$	618

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
November 14, 2014	September 30, 2014	$	0.1966		$	16,032	$	1,492		$	1,378
December 15, 2014	October 31, 2014	$	0.1966		$	16,033	$	1,491		$	1,378
January 14, 2015	November 30, 2014	$	0.1966		$	16,779	$	745	⁽²⁾	$	1,378

(1)	Represents a pro-rated cash distribution of $0.40 per common limited partner unit for the period from March 5, 2012, the date New Atlas’s exploration and production assets were transferred to ARP, to March 31, 2012.

(2)	Excludes ARP’s initial Class D preferred unit quarterly distribution (see Note 13).

At December 31, 2014, ARP had 3.2 million of its 8.625% Class D ARP Preferred Units outstanding (see Note 13). On January 15, 2015, ARP paid an initial quarterly distribution of $0.616927 per unit for the extended period from October 2, 2014 through January 14, 2015 to holders of record as of January 2, 2015. ARP will pay future cumulative distributions on a quarterly basis, at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference.

On January 28, 2015, ARP declared a monthly distribution of $0.1966 per common unit for the month of December 2014. The $18.9 million distribution, including $1.4 million and $0.7 million to its general partner and preferred limited partners, respectively, was paid on February 13, 2015 to unitholders of record at the close of business on February 9, 2015.

On February 23, 2015, ARP declared a monthly distribution of $0.1083 per common unit for the month of January 2015. The $10.1 million distribution, including $0.2 million and $0.6 million to its general partner and preferred limited partners, respectively, was paid on March 17, 2015 to unitholders of record at the close of business on March 10, 2015.

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, 2014 and 2013, New Atlas reflected $3.9 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 $3.9 million and $3.7 million as of those same dates within asset retirement obligations and other on its combined consolidated balance sheets. During the year ended December 31, 2014, New Atlas distributed $1.8 million to participants related to the rabbi trust. No amounts were distributed during the year ended December 31, 2013.

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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 December 31, 2014, ARP had 2,257,492 phantom units, restricted units and unit options outstanding under the ARP LTIP with 135,663 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 consolidated financial statements based upon their current fair market value.

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.

ARP Phantom Units. Phantom units represent rights to receive a common unit, an amount of cash or other securities or property based on the value of a common unit, or a combination of common units and cash or other securities or property upon vesting. Phantom units are subject to terms and conditions determined by the ARP LTIP Committee, which may include vesting restrictions. In tandem with phantom unit grants, the ARP LTIP Committee may grant distribution equivalent rights (“DERs”), which are 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 ARP with respect to a common unit during the period that the underlying phantom unit is outstanding. 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, 2014, 317,587 units will vest within the following twelve months. All phantom units outstanding under the ARP LTIP at December 31, 2014 include DERs. During the years ended December 31, 2014, 2013, and 2012, ARP paid $2.0 million, $1.9 million, and $0.7 million, respectively, with respect to the ARP LTIP’s DERs. These amounts were recorded as reductions of equity on New Atlas’s combined consolidated balance sheets.

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The following table sets forth the ARP LTIP phantom unit activity for the periods indicated:


	Years Ended December 31,
	2014					2013					2012
	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		839,808		$	24.31		948,476		$	24.76		—		$	—
Granted		264,173			19.43		145,813			21.87		949,476			24.76
Vested⁽¹⁾		(274,414	)		24.46		(215,981	)		24.73		—			—
Forfeited		(30,375	)		22.76		(38,500	)		23.96		(1,000	)		24.67

Outstanding, end of year⁽²⁾⁽³⁾		799,192		$	22.70		839,808		$	24.31		948,476		$	24.76

Non-cash compensation expense recognized (in thousands)				$	6,367				$	9,166				$	7,630

⁽¹⁾	The intrinsic values of phantom unit awards vested during the years ended December 31, 2014 and 2013 were $5.4 million and $6.1 million, respectively. No phantom unit awards vested during the year ended December 31, 2012.

⁽²⁾	The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2014 was $8.6 million.

⁽³⁾

There was approximately $0.2 million and $0.1 million recognized as liabilities on New Atlas’s combined consolidated balance sheets at December 31, 2014 and 2013, respectively, representing 26,579 and 16,084 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 $21.16 and $22.15 at December 31, 2014 and 2013, respectively.

At December 31, 2014, ARP had approximately $6.7 million in unrecognized compensation expense related to unvested phantom units outstanding under the ARP LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 1.7 years.

ARP Unit Options. A unit option is the right to purchase an ARP common unit in the future at a predetermined price (the exercise price). 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 361,325 unit options outstanding under the ARP LTIP at December 31, 2014 that will vest within the following twelve months. No cash was received from the exercise of options for the years ended December 31, 2014, 2013, and 2012.

The following table sets forth the ARP LTIP unit option activity for the periods indicated:


	Years Ended December 31,
	2014					2013					2012
	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		1,482,675		$	24.66		1,515,500		$	24.68		—		$	—
Granted		—			—		5,000			21.56		1,517,500			24.68
Exercised ⁽¹⁾		—			—		—			—		—			—
Forfeited		(24,375	)		24.52		(37,825	)		24.80		(2,000	)		24.67

Outstanding, end of year⁽²⁾⁽³⁾		1,458,300		$	24.66		1,482,675		$	24.66		1,515,500		$	24.68

Options exercisable, end of year⁽⁴⁾		730,775		$	24.67		370,700		$	24.67		—		$	—

Non-cash compensation expense recognized (in thousands)				$	1,700				$	3,514				$	3,198

⁽¹⁾	No options were exercised during the years ended December 31, 2014, 2013 and 2012.

⁽²⁾	The weighted average remaining contractual life for outstanding options at December 31, 2014 was 7.4 years.

⁽³⁾	There was no aggregate intrinsic value of options outstanding at December 31, 2014. 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, 2014 and 2013 was 7.4 years and 8.4 years, respectively. There were no intrinsic values for options exercisable at December 31, 2014, 2013, and 2012.

150

At December 31, 2014, ARP had approximately $1.0 million in unrecognized compensation expense related to unvested unit options outstanding under the ARP LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 1.1 years. 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,
	2014			2013			2012
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

Restricted Units

Restricted units are actual common units issued to a participant that are subject to vesting restrictions and evidenced in such manner as the ARP LTIP 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 ARP LTIP Committee will condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals or both. A holder of restricted units will have certain rights of holders of common units in general, including the right to vote the restricted units. However, during the period in which the restricted units are subject to vesting restrictions, the holder will not be permitted to sell, assign, transfer, pledge or otherwise encumber the restricted units.

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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,
	2014			2013			2012
Atlas Resource Partners:
Revenues	$	685,560		$	467,655		$	267,629
Operating costs and expenses		(425,000	)		(348,812	)		(246,267	)
Depreciation, depletion and amortization expense		(233,731	)		(136,763	)		(52,582	)
Asset impairment		(573,774	)		(38,014	)		(9,507	)
Loss on asset sales and disposal		(1,869	)		(987	)		(6,980	)
Interest expense		(62,144	)		(34,324	)		(4,195	)

Segment loss	$	(610,958	)	$	(91,245	)	$	(51,902	)

New Atlas:
Revenues	$	21,801		$	7,123		$	—
Operating costs and expenses		(8,102	)		(2,941	)		—
Depreciation, depletion and amortization expense		(8,348	)		(3,153	)		—
Asset impairment		(6,880	)		—			—

Segment income (loss)	$	(1,529	)	$	1,029		$	—

Corporate and other:
Revenues	$	1,149		$	321		$	1,540
General and administrative		(18,127	)		(11,894	)		(6,352	)
Gain on asset sales and disposal		10			—			—
Interest expense		(11,291	)		(5,388	)		(353	)

Segment loss	$	(28,259	)	$	(16,961	)	$	(5,165	)

Reconciliation of segment income (loss) to net loss:
Segment income (loss):
Atlas Resource	$	(610,958	)	$	(91,245	)	$	(51,902	)
New Atlas		(1,529	)		1,029			—
Corporate and other		(28,259	)		(16,961	)		(5,165	)

Net loss	$	(640,746	)	$	(107,177	)	$	(57,067	)

Reconciliation of segment revenues to total revenues:
Segment revenues:
Atlas Resource	$	685,560		$	467,655		$	267,629
New Atlas		21,801			7,123			—
Corporate and other		1,149			321			1,540

Total revenues	$	708,510		$	475,099		$	269,169

Capital expenditures:
Atlas Resource	$	212,634		$	263,537		$	127,226
New Atlas		13,002			3,943			—
Corporate and other		—			—			—

Total capital expenditures	$	225,636		$	267,480		$	127,226


	December 31,
	2014		2013
Balance sheet:
Goodwill:
Atlas Resource	$	13,639	$	31,784
New Atlas		—		—
Corporate and other		—		—

	$	13,639	$	31,784

Total assets:
Atlas Resource	$	2,727,575	$	2,343,800
New Atlas		257,800		76,004
Corporate and other		40,940		36,066

	$	3,026,315	$	2,455,870

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NOTE 17—SUBSEQUENT EVENTS

Term Loan Credit Facilities. On February 27, 2015, New Atlas entered into a Credit Agreement with Deutsche Bank AG New York Branch, as administrative agent, and the lenders from time to time party thereto (the “Credit Agreement”). The Credit Agreement provides for a Secured Senior Interim Term Loan Facility in an aggregate principal amount of $30 million (the “Interim Term Loan Facility”) and a Secured Senior Term A Loan Facility in an aggregate principal amount of approximately $97.8 million (the “Term A Loan Facility” and together with the Interim Term Loan Facility, the “Term Loan Facilities”). The Interim Term Loan Facility matures on August 27, 2015 and the Term A Loan Facility matures on February 26, 2016. New Atlas’s obligations under the Term Loan Facilities are secured on a first priority basis by security interests in all of New Atlas’s material subsidiaries, including all equity interests directly held by New Atlas and all tangible and intangible property. Borrowings under the Term Loan Facilities bear interest, at New Atlas’s option, at either (i) LIBOR plus 7.5% (“Eurodollar Loans”) or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, in each case plus 6.5% (an “ABR Loan”). Interest is generally payable at interest payment periods selected by New Atlas for Eurodollar Loans and quarterly for ABR Loans.

New Atlas has the right at any time to prepay any borrowings outstanding under the Term Loan Facilities, without premium or penalty, provided the Interim Term Loan Facility is repaid prior to the Term A Loan Facility. Subject to certain exceptions, New Atlas may also be required to prepay all or a portion of the Term Loan Facilities in certain instances, including the following:

•

if, at any time, the Recognized Value Ratio (as defined in the Credit Agreement) is less than 2.00 to 1.00, New Atlas must prepay the Term Loan Facilities and any revolving loans outstanding in an aggregate principal amount necessary to achieve a Recognized Value Ratio of greater than 2.00 to 1.00; the Recognized Value Ratio is equal to the ratio of the Recognized Value (the sum of the discounted net present values of the Loan Parties’ oil and gas properties and the values of the common units, Class A Units and Class C Units of ARP, determined as set forth in the Credit Agreement) to Total Funded Debt (as defined in the Credit Agreement);

•

if New Atlas disposes of all or any portion of the Arkoma assets (as defined in the Credit Agreement), New Atlas must prepay the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds resulting from such disposition;

•

if New Atlas or any of our restricted subsidiaries dispose of property or assets (including equity interests), New Atlas must repay the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds from such disposition or casualty event; and

•

if New Atlas incurs any debt or issues any equity, New Atlas must repay the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds of such issuances or incurrences of debt or issuances of equity.

The Credit Agreement contains customary covenants that limit New Atlas’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 swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions. The Credit Agreement also requires that the Total Leverage Ratio (as defined in the Credit Agreement) be greater than (i) as of the last day of any fiscal quarter prior to the full repayment of the Interim Term Loan Facility, 3.75 to 1.00, and (ii) as of the last day of any quarter thereafter, 3.50 to 1.00.

Preferred Unit Purchase Agreement. On February 26, 2015, New Atlas entered into the Series A Preferred Unit Purchase Agreement (the “Series A Purchase Agreement”) with certain members of our management, two management members of the Board and an outside investor (the “purchasers”), pursuant to which, on February 27, 2015 New Atlas issued and sold an aggregate of 1.6 million of its newly issued Series A convertible preferred units, with a liquidation preference of $25.00 per unit (the “Series A preferred units”), to the purchasers for a cash purchase price of $25.00 per unit (the “Private Placement”). New Atlas sold the Series A preferred units in a private transaction exempt from registration under Section 4(2) of the Securities Act. The Private Placement resulted in proceeds to New Atlas of $40.0 million. New Atlas used the proceeds to fund a portion of the $150.0 million cash transfer made by New Atlas to Atlas Energy required by the Separation agreement with Atlas Energy, which was a condition to the Separation and distribution of its common units (see Note 1). The Series A Purchase Agreement contains customary terms for private placements, including representations, warranties, covenants and indemnities.

153

Atlas Resource

•

reduces the borrowing base under the ARP Credit Agreement from $900.0 million to $750.0 million;

•

permits the incurrence of second lien debt in an aggregate principal amount up to $300.0 million;

•

The Amendment was approved by the lenders and was effective on February 23, 2015.

•

4.5% of the principal amount prepaid for prepayments made between 12 months and 24 months after the closing date;

•

2.25% of the principal amount prepaid for prepayments made between 24 months and 36 months after the closing date; and

•

no premium for prepayments made following 36 months after the closing date.

154

Cash Distributions. On January 28, 2015, ARP declared a monthly distribution of $0.1966 per common unit for the month of December 31, 2014. The $18.9 million distribution, including $1.4 million and $0.7 million to its general partner and preferred limited partners, respectively, was paid on February 13, 2015 to unitholders of record at the close of business on February 9, 2015.

On February 23, 2015, ARP declared a monthly distribution of $0.1083 per common unit for the month of January 2015. The $10.1 million distribution, including $0.2 million and $0.6 million to its general partner and preferred limited partners, respectively, was paid on March 17, 2015 to unitholders of record at the close of business on March 10, 2015.

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, 2014. Other than for ARP’s Rangely assets, 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 38 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. For ARP’s Rangely assets, Cawley, Gillespie, and Associates, Inc. was retained to prepare a report of proved reserves. The independent reserves engineer’s evaluation was based on more than 32 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 16 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by New Atlas and ARP’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 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

155

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, 2014, 2013 and 2012 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, 2014, 2013 and 2012, 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.

156

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, 2012		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⁽³⁾		(27,760,192	)		(153,413	)		206,091
Production		(25,403,318	)		(120,736	)		(356,550	)

Balance, December 31, 2012⁽⁴⁾		573,774,257			8,868,836			16,061,897
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⁽⁵⁾		(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
Extensions, discoveries and other additions⁽²⁾		58,461,204			3,372,177			3,986,986
Sales of reserves in-place		(169,035	)		(1,519	)		(11,326	)
Purchase of reserves in-place		88,635,059			51,168,449			3,567,531
Transfers to limited partnerships		(4,887,095	)		(684,613	)		956,810
Revisions		5,947,622			(4,639,546	)		(2,689,372	)
Production		(86,889,803	)		(1,254,247	)		(1,387,865	)

Balance, December 31, 2014		1,064,877,455			62,949,525			23,379,780

Proved developed reserves at:
January 1, 2012		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
December 31, 2014		889,073,136			31,150,298			12,209,825

Proved undeveloped reserves at:
January 1, 2012		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
December 31, 2014		175,804,319			31,799,227			11,169,954

⁽¹⁾	Oil includes NGL information at January 1, 2012, which was less than 500 MBbls.

⁽²⁾	Principally includes increases of proved reserves due to the addition of Marcellus wells in 2012 and 2013, and Marble Falls wells in 2014.

⁽³⁾	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 1^st day of the month price for the year ended December 31, 2012 as compared with the year ended December 31, 2011.

⁽⁴⁾	Prior to the Arkoma Acquisition on July 31, 2013, New Atlas had no oil and gas reserves. At December 31, 2014, there were no proved undeveloped reserves related to New Atlas’s oil and gas assets.

⁽⁵⁾	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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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,
	2014			2013
Natural gas and oil properties:
Proved properties	$	3,639,833		$	2,557,797
Unproved properties		217,321			211,851
Support equipment		37,359			23,258

		3,894,513			2,792,906
Accumulated depreciation, depletion and amortization		(1,518,686	)		(649,635	)

Net capitalized costs	$	2,375,827		$	2,143,271

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,
	2014			2013			2012
Revenues	$	475,758		$	273,906		$	92,901
Production costs		(184,296	)		(100,178	)		(26,624	)
Depreciation, depletion and amortization		(231,638	)		(132,860	)		(47,000	)
Asset impairment⁽¹⁾		(580,654	)		(38,014	)		(9,507	)

	$	(520,830	)	$	2,854		$	9,770

⁽¹⁾

During the year ended December 31, 2014, New Atlas recognized $580.7 million of asset impairment consisting of $562.6 million related to oil and gas properties within property, plant, and equipment, net on New Atlas’s combined consolidated balance sheet primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income, and $18.1 million goodwill impairment resulting from the decline in overall commodity prices. 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.

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,
	2014		2013		2012
Property acquisition costs:
Proved properties	$	754,197	$	863,421	$	528,684
Unproved properties		10,978		895		213,638
Exploration costs⁽¹⁾		722		1,053		1,026
Development costs		177,726		214,383		83,538

Total costs incurred in oil & gas producing activities	$	943,623	$	1,079,752	$	826,886

⁽¹⁾	There were no exploratory wells drilled during the years ended December 31, 2014, 2013 and 2012.

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, 2014, 2013 and 2012, 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 include the effect on

158

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,
	2014			2013			2012
Future cash inflows	$	10,802,697		$	5,268,148		$	2,930,514
Future production costs		(4,561,129	)		(2,397,997	)		(1,185,084	)
Future development costs		(1,623,218	)		(752,369	)		(441,423	)

Future net cash flows		4,618,350			2,117,782			1,304,007
Less 10% annual discount for estimated timing of cash flows		(2,381,586	)		(1,038,491	)		(680,331	)

Standardized measure of discounted future net cash flows	$	2,236,764		$	1,079,291		$	623,676

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,
	2014			2013			2012
Balance, beginning of year	$	1,079,291		$	623,676		$	219,859
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs		(275,789	)		(171,409	)		(54,969	)
Net changes in prices and production costs		339,776			85,191			(87	)
Revisions of previous quantity estimates		(33,526	)		(1,881	)		(6,378	)
Development costs incurred		52,077			27,245			575
Changes in future development costs		(90,887	)		(21,579	)		—
Transfers to limited partnerships		(2,966	)		(53,392	)		—
Extensions, discoveries, and improved recovery less related costs		69,436			143,338			64
Purchases of reserves in-place		1,018,345			516,985			510,467
Sales of reserves in-place		(332	)		(2,053	)		—
Accretion of discount		107,929			62,368			21,986
Estimated settlement of asset retirement obligations		(16,824	)		(18,858	)		(2,823	)
Estimated proceeds on disposals of well equipment		(21,896	)		17,052			3,806
Changes in production rates (timing) and other		12,130			(127,392	)		(68,824	)

Outstanding, end of year	$	2,236,764		$	1,079,291		$	623,676

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NOTE 19 — QUARTERLY RESULTS (UNAUDITED)


	Fourth Quarter			Third Quarter			Second Quarter			First Quarter
	(in thousands, except unit data)
Year ended December 31, 2014:
Revenues	$	196,170		$	208,589		$	141,604		$	162,147
Net loss		(594,552	)		(4,349	)		(24,394	)		(17,451	)
Loss attributable to non-controlling interests		437,611			5,137			15,042			13,649

Net income (loss) attributable to owner	$	(156,941	)	$	788		$	(9,352	)	$	(3,802	)


	Fourth Quarter			Third Quarter			Second Quarter			First Quarter
	(in thousands, except unit data)
Year ended December 31, 2013:
Revenues	$	185,810		$	93,854		$	83,384		$	112,051
Net loss		(44,429	)		(46,085	)		(8,777	)		(7,886	)
Loss attributable to non-controlling interests		26,905			26,380			3,065			2,039

Net loss attributable to owner	$	(17,524	)	$	(19,705	)	$	(5,712	)	$	(5,847	)

ITEM 9:

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A:

CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report, excluding assets acquired by our Development Subsidiary and ARP in the Eagle Ford Shale in Atascosa County, Texas. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2014, our disclosure controls and procedures were effective at the reasonable assurance level.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of internal control over financial reporting based upon criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in the 2013 Internal Control – Integrated Framework (COSO framework).

An effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, effectiveness of an internal control system in future periods cannot be guaranteed

160

because the design of any system of internal controls is based in part upon assumptions about the likelihood of future events. There can be no assurance that any control design will succeed in achieving its stated goals under all potential future conditions. Over time certain controls may become inadequate because of changes in business conditions, or the degree of compliance with policies and procedures may deteriorate. As such, misstatements due to error or fraud may occur and not be detected.

In conducting management’s evaluation of the effectiveness of its internal control over financial reporting, management has excluded, due to the timing, the operations of our Development Subsidiary’s and ARP’s newly acquired assets in the Eagle Ford Shale, which were acquired in November 2014, from its December 31, 2014 Sarbanes-Oxley 404 review (see “Item 8. Financial Statements and Supplemental Data – Note 4”). In connection with this acquisition, our Development Subsidiary and ARP have entered into a transition services agreement with the previous owner. As a result, the Development Subsidiary and ARP did not begin to perform substantially all accounting control functions related to the Eagle Ford Acquisition until February 6, 2015. The Eagle Ford Acquisition constituted 11.8% of our total assets as of December 31, 2014 and 1.4% of our total revenues for the year ended December 31, 2014. We are continuing to integrate this system’s historical internal controls over financial reporting with our existing internal controls over financial reporting. This integration may lead to changes in our or the acquired systems’ historical internal controls over financial reporting in future fiscal reporting periods. During the year ended December 31, 2014, ARP acquired certain assets in the Rangely field in northwestern Colorado. During the year ended December 31, 2013, we and ARP acquired certain assets from EP Energy which have been fully integrated into our existing internal control environment in 2014. Other than the previously mentioned items, there have been no changes in our internal control over financial reporting during the fourth quarter of 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Based on our evaluation under the COSO framework, management concluded that our internal control over financial reporting was effective at the reasonable assurance level as of December 31, 2014. Grant Thornton LLP, an independent registered public accounting firm, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2014, which is included herein.

161

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Atlas Energy Group, LLC

We have audited the internal control over financial reporting of Atlas Energy Group, LLC. (a Delaware limited liability company) and subsidiaries and affiliates (collectively, the “Company”) as of December 31, 2014, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting (“Management’s Report”). Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. Our audit of, and opinion on, the Company’s internal control over financial reporting does not include the internal control over financial reporting of ARP Eagle Ford, LLC and Atlas Growth Eagle Ford, LLC, both of which are consolidated subsidiaries of the Company, whose financial statements reflect aggregate total assets and revenues constituting 11.8% and 1.4%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2014. As indicated in Management’s Report, the Eagle Ford Shale assets of ARP Eagle Ford, LLC and Atlas Growth Eagle Ford, LLC were acquired during 2014. Management’s assertion on the effectiveness of the Company’s internal control over financial reporting excluded internal control over financial reporting of ARP Eagle Ford, LLC and Atlas Growth Eagle Ford, LLC.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the combined consolidated financial statements of the Company as of and for the year ended December 31, 2014, and our report dated March 27, 2015 expressed an unqualified opinion on those financial statements.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

March 27, 2015

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ITEM 9B:

OTHER INFORMATION

None.

PART III

ITEM 10:

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors and Executive Officers

The following table sets forth information regarding our directors and executive officers.


Name	Age		Position(s)
Edward E. Cohen		76	Chief Executive Officer, President and Director
Jonathan Z. Cohen		44	Executive Chairman of the Board
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
Sean P. McGrath		43	Chief Financial Officer
Daniel C. Herz		38	Senior Vice President, Corporate Development & Strategy
Matthew A. Jones		53	Senior Vice President and President of 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 has been our President since February 2015, and Chief Executive Officer and a director since February 2012. He served as our Chairman from February 2012 until February 2015. Mr. Cohen held a number of titles at the general partner of Atlas Energy, L.P. at various points from its formation in January 2006 until February 2015, including Chairman of the Board, Chief Executive Officer, President and member of the executive committee. He also held a number of titles at the general partner of Atlas Pipeline Partners, L.P. from its formation in 1999 until February 2015, including Executive Chair of the managing board and, from 1999 to January 2009, Chief Executive Officer. Mr. Cohen was the Chairman of the Board and Chief Executive Officer of Atlas Energy, Inc. from its organization in 2000 until February 2011, and its President from September 2000 to October 2009; and 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 February 2011. In addition, Mr. Cohen has been Chairman of the Board of Resource America, Inc. since 1990, and was its Chief Executive Officer from 1988 until 2004 and President from 2000 until 2003; a director of Resource Capital Corp. since its formation in September 2005, serving as its Chairman until November 2009; and Chairman of the Board of Brandywine Construction & Management, Inc. since 1994. Mr. Cohen is the father of Jonathan Z. 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, enables Mr. Cohen to provide valuable perspectives on many issues facing us. Mr. Cohen’s service on the board of directors creates an important link between management and the board and provides us with decisive and effective leadership. Mr. Cohen’s extensive experience in founding, operating and managing public and private companies of varying size and complexity enables him to provide valuable expertise to us. Additionally, among the reasons for his appointment as a director, Mr. Cohen brings 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 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.

Jonathan Z. Cohen has been the Executive Chairman of our Board since February 2015, and before that was Vice Chairman from February 2012. Mr. Cohen held a number of titles at the general partner of Atlas Energy, L.P. at various points from its formation in January 2006 until February 2015, including Executive Chairman and Vice Chairman of the Board, and chairman of the executive committee. Mr. Cohen was also the Executive Vice Chairman of the managing board of Atlas Pipeline Partners GP, LLC from its formation in 1999 until February 2015. He was the Vice Chairman of the Board of

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Atlas Energy, Inc. from its formation in September 2000 until February 2011, and 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 February 2011. Mr. Cohen has been a senior officer of Resource America 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’s extensive knowledge of our business resulting from his long service with Atlas Energy and its predecessors, as well as his strong financial and industry experience, allows him to contribute valuable perspectives on many issues facing us. Mr. Cohen’s service on our board of directors creates an important link between management and the rest of the board of directors and provides us 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 us. 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, 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.

Mark C. Biderman has been a director since February 2015. Mr. Biderman served as a director of the general partner of Atlas Energy L.P. from February 2011 to February 2015. Before that, he was a director of Atlas Energy, Inc. from July 2009 until February 2011. Mr. Biderman was Vice Chairman of National Financial Partners Corp. from September 2008 to December 2008, and was its Executive Vice President and Chief Financial Officer from November 1999 to September 2008. From May 1987 to October 1999, he served as Managing Director and Head of the Financial Institutions Group at CIBC World Markets Group and its predecessor, Oppenheimer & Co., Inc. Mr. Biderman has served as a director and chair of the audit committee, as well as a member of the corporate governance and nominating committee, of Full Circle Capital Corporation since August 2010; a director and chair of the compensation committee, as well as a member of the audit committee, of Apollo Commercial Real Estate Finance, Inc. since November 2010; and a director and chair of the audit committee, and a member of the nominating and corporate governance committee, of Apollo Residential Mortgage, Inc. since July 2011. Mr. Biderman is a Chartered Financial Analyst. Mr. Biderman brings 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 also brings 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 has been a director since March 2012. Dr. Craig was a consultant to Atlas Energy, L.P. from April 2011 to January 2012. She has been an Adjunct Professor in the Petroleum Engineering Department of the Colorado School of Mines since January 2009, and a member of the Colorado Oil and Gas Conservation Commission since March 2009. Dr. Craig was the Senior Vice President – Asset Assessment of CNX Gas Corporation from September 2007 until February 2009, and President of Phillips Petroleum Resources (a Canadian subsidiary of Phillips Petroleum) and Manager of Worldwide Drilling and Production from July 1992 to October 1996. Dr. Craig has been a director for Samson Oil & Gas Limited since July 2011 and is the chair of its audit committee as well as a member of its compensation committee. She is a Past-President of the Society of Petroleum Engineers, currently serving as the Treasurer for the Society of Petroleum Engineers’ Foundation, and a Past-President of the American Institute of Mining, Metallurgical, and Petroleum Engineers. Dr. Craig is a Registered Professional Engineer in the State of Colorado. Dr. Craig brings 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 provides 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 has been a director since February 2015. Mr. Holtz served as a director of the general partner of Atlas Energy, L.P. from February 2011 until February 2015. 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 our nominating and governance committee. As a licensed attorney with approximately 50 years of business experience, Mr. Holtz offers 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 our former affiliated companies for nine years.

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Walter C. Jones has been as a director since February 2015. Mr. Jones served as a director of the general partner of Atlas Energy, L.P. from October 2013 until February 2015, 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. Since November 2013, Mr. Jones has been the managing director of the Jones Pohl Group, an investment firm based in Dubai, UAE, that invests in clean energy projects, primarily in developing and developed markets around the globe. JPG is also the majority shareholder of a Dubai-based geothermal energy developer, RG Safa Energy. 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. Mr. Jones served as the Head of Private Equity and General Counsel at GRAVITAS Capital Advisors, LLC from June 2005 until May 2007. Mr. Jones served in a number of positions at the Overseas Private Investment Corporation from May 1994 to May 2005, and then again from September 2007 until April 2010, including Manager for Asia, Africa, the Middle East, Latin America and the Caribbean and Senior Investment Officer in the Finance Department; and was an International Consultant at the Washington, D.C. firm of Neill & Co. before that. 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 and a director of Atlas Energy, Inc. 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 has been a director since February 2015. Mr. Kupfer served as a director of the general partner of Atlas Energy, L.P. from March 2014 until February 2015. He has been an Adjunct Professor of Policy and Management at Carnegie Mellon University’s H. John Heinz III College since October 2009. Mr. Kupfer served as a senior advisor for policy and government affairs at Chevron from February 2011 to January 2014, and a Senior Vice President at Atlas Energy, Inc. from September 2009 to February 2011. Before that, Mr. Kupfer held a number of high level positions in the U.S. Department of Energy, including Acting Deputy Secretary and Chief Operating Officer from March 2008 to January 2009, and Chief of Staff from October 2006 to March 2008. 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 brings 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 we view as complementary to the industry perspective of other members of the board of directors.

Ellen F. Warren has been a director since February 2015. Ms. Warren served as a director of the general partner of Atlas Energy, L.P. from February 2011 until February 2015, a director of Atlas Energy, Inc. from September 2009 until February 2011, and a director of Atlas Energy Resources, LLC from December 2006 until September 2009. She is founder and President of OutSource Communications, a marketing communications firm that services corporate and nonprofit clients. Before 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 from September 1992 to February 1998, and President of Diversified Advertising, Inc. 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, 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 also offers 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 is uniquely positioned to provide leadership to the board of directors in public relations and communications matters. Ms. Warren also brings valuable management, communication, community involvement and leadership skills to the board of directors.

Sean P. McGrath has been our Chief Financial Officer since February 2012. Mr. McGrath served as Chief Financial Officer of the general partner of Atlas Energy, L.P from February 2011 until February 2015, and Chief Accounting Officer from January 2006 until November 2009. Mr. McGrath served as Chief Accounting Officer of Atlas Pipeline Partners GP, LLC from May 2005 until November 2009, and of Atlas Energy, Inc. and Atlas Energy Resources, LLC from December 2008 until February 2011. Mr. McGrath was Controller of Sunoco Logistics Partners L.P. from 2002 until 2005. Mr. McGrath is a Certified Public Accountant.

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Daniel C. Herz has been our Senior Vice President of Corporate Development and Strategy since March 2012. Mr. Herz served as Senior Vice President of Corporate Development and Strategy of the general partner of Atlas Energy, L.P. from February 2011 until February 2015, and Vice President of Corporate Development from January 2006 until February 2011. Mr. Herz was also Senior Vice President of Corporate Development of Atlas Pipeline Partners GP, LLC from August 2007 until February 2015, and Vice President of Corporate Development from December 2004 until August 2007; and Senior Vice President of Corporate Development of Atlas Energy, Inc. and Atlas Energy Resources, LLC from August 2007 until February 2011, and Vice President of Corporate Development for Atlas Energy, Inc. from December 2004 until August 2007. Before that, Mr. Herz was an investment banker with Banc of America Securities from 1999 to 2003.

Matthew A. Jones has been our Senior Vice President and President of ARP since February 2015. Before that, he was President and a director from March 2012 until February 2015, and Chief Operating Officer from March 2012 until October 2013. Mr. Jones served in a number of capacities at the general partner of Atlas Energy, L.P., including as a Senior Vice President and President and Chief Operating Officer of the exploration and production division from February 2011 until February 2015, Chief Financial Officer from January 2006 until September 2009, and a member of the Board from February 2006 to February 2011. Mr. Jones was Chief Financial Officer of Atlas Energy, Inc. from March 2005 until February 2011 and Executive Vice President from October 2009 until February 2011; Chief Financial Officer of Atlas Energy Resources, LLC and Atlas Energy Management, Inc. from June 2006 until February 2011; and Chief Financial Officer of Atlas Pipeline Partners GP, LLC 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, and in its Energy Investment Banking Group from 1999 to 2005. Mr. Jones is a Chartered Financial Analyst.

Freddie M. Kotek has been the Senior Vice President of our Investment Partnership Division since March 2012. Mr. Kotek has been Chairman of Atlas Resources, LLC since September 2001, and Chief Executive Officer and President since January 2002. Mr. Kotek served as Senior Vice President of the Investment Partnership Division of the general partner of Atlas Energy, L.P. from February 2011 until February 2015; an Executive Vice President of Atlas Energy, Inc. from February 2004 until February 2011, a director from September 2001 until February 2004 and Chief Financial Officer from February 2004 until March 2005; a Senior Vice President of Resource America, Inc. from 1995 until May 2004; and President of Resource Leasing, Inc. from 1995 until May 2004.

Lisa Washington has been our Vice President since February 2015, and our Chief Legal Officer and Secretary since February 2012. Ms. Washington served as Chief Legal Officer and Secretary of the general partner of Atlas Energy, L.P. from January 2006 until February 2015, and Vice President from February 2011 until February 2015. She also served as Chief Legal Officer and Secretary of Atlas Pipeline Partners GP, LLC from November 2005 to October 2009, a Senior Vice President from October 2008 to October 2009 and a Vice President from November 2005 until October 2008; Chief Legal Officer and Secretary of Atlas Energy, Inc. from November 2005 until February 2011, a Senior Vice President from October 2008 until February 2011, and a Vice President from November 2005 until October 2008; and Chief Legal Officer and Secretary of Atlas Energy Resources, LLC from 2006 until February 2011, a Senior Vice President from July 2008 until February 2011 and a 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 has been our Chief Accounting Officer since March 2012. Mr. Slotterback served as Chief Accounting Officer of the general partner of Atlas Energy, L.P. from March 2011 until February 2015, and Manager of Financial Reporting from May 2007 until July 2009 and again from February 2011 until March 2011. Mr. Slotterback was the Manager of Financial Reporting for Atlas Energy, Inc. from July 2009 until February 2011and for Atlas Pipeline Partners GP, LLC 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.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires executive officers and board members and persons who beneficially own more than 10% of a registered class of our equity securities to file reports of ownership and changes in ownership with the Securities and Exchange Commission and to furnish us with copies of all such reports. We did not have a registered class of equity securities during the 2014 fiscal year.

Composition of the Board of Directors

Our board of directors is divided into three classes, comprised of two, three and three directors, respectively. The directors designated as Class I directors will have terms expiring at our first annual meeting of unitholders to be held in 2016. The directors designated as Class II directors have terms expiring at the 2017 annual meeting of unitholders, and the directors

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designated as Class III directors have terms expiring at the 2018 annual meeting of unitholders. The Class I directors are Mark C. Biderman and DeAnn Craig; Class II directors are Edward E. Cohen, Walter C. Jones and Jeffrey F. Kupfer; and Class III directors are Jonathan Z. Cohen, Dennis A. Holtz and Ellen F. Warren. Commencing with the first annual meeting of unitholders, 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

The board has determined that all directors other than Edward E. Cohen and Jonathan Z. Cohen, qualify as “independent” as defined by the rules of the NYSE, which is the standard of independence adopted by the board. These standards 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 (i) adheres to all of the specific tests for independence included in the NYSE listing standards, and (ii) considers 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. Under NYSE listing standards:

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a director is not independent if the director is, or has been within the last three years, an employee of us or any of our subsidiaries, or if an immediate family member is, or has been within the last three years, an executive officer of us or any of our subsidiaries;

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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 us or any of our 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);

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a director is not independent if (A) the director or an immediate family member is a current partner of a firm that is our 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 our 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 our audit within that time;

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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 us or any of our subsidiaries at the same time serves or served on that company’s compensation committee;

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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, us or any of our 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

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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 us or any of our 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.

The board of directors assesses 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.

Committees of the Board of Directors

The standing committees of the board of directors are the Audit Committee, the Compensation Committee, the Nominating and Governance Committee, the Investment Committee and the Environmental, Health and Safety Committee.

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As discussed in Item 11 – Executive Compensation, we did not have a compensation committee for the year ended December 31, 2014. Until the separation, compensation of Atlas Energy’s senior executives who provided services to us was determined by Atlas Energy’s compensation committee.

Audit Committee. The Audit Committee’s duties include recommending to our board of directors the independent public accountants to audit our financial statements and establishing the scope of, and overseeing, the annual audit. The committee also approves any other services provided by public accounting firms. The Audit Committee provides assistance to the board of directors in fulfilling its oversight responsibility to the unitholders, the investment community and others relating to the integrity of our financial statements, our compliance with legal and regulatory requirements, the independent auditor’s qualifications and independence and the performance of internal audit function. The Audit Committee oversees our system of disclosure controls and procedures and system of internal controls regarding financial, accounting, legal compliance and ethics that our management and the board of directors have established. In doing so, it is the responsibility of the Audit Committee to maintain free and open communication between the committee and the independent auditors, internal accounting function and our management. In accordance with the Sarbanes-Oxley Act of 2002, the Audit Committee has adopted 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. All of the members of the Audit Committee meet the independence standards established by the NYSE and the board. The members of the Audit Committee are Mr. Biderman, Mr. W. Jones and Mr. Kupfer. Mr. Biderman is the chair and has been determined by the board of directors to be an “audit committee financial expert,” as defined by SEC rules. Mr. Biderman serves on the audit committee of more than three public companies. The board of directors has determined that Mr. Biderman’s simultaneous service on the audit committees of more than three public companies will not impair his ability to serve effectively on our audit committee.

Compensation Committee. The principal functions of the Compensation Committee are to assist the board of directors in carrying out its responsibilities with respect to compensation, particularly including evaluation of the compensation paid or payable to our chief executive officer and other named executive officers. The Compensation Committee reviews 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 named 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 our company. The Compensation Committee has the sole authority to select, retain and/or terminate independent compensation advisors. Ms. Warren and Mr. Holtz are the members of the Compensation Committee, with Ms. Warren acting as the chair. The board of directors has determined that each member of the Compensation Committee is independent, as defined by the rules of the NYSE and in accordance with the independence standards adopted by the board. In addition, the members of the Compensation Committee qualify as “non-employee directors” for purposes of Rule 16b-3 under the Exchange Act.

Nominating and Governance Committee. The principal functions of the Nominating and Governance Committee are to recommend to the board the criteria for members of the board and to identify individuals who meet such criteria, and recommend such individuals to the board for election to fill vacancies on the Board; review all compensation paid to directors, in cash or in equity grants, and, on a biannual basis, recommend changes to such compensation, if appropriate; establish procedures for the annual self-assessment by directors set forth by the NYSE, and implement and supervise each self-assessment; and periodically review our formation documents and suggest revisions to them. Ms. Warren and Messrs. Holtz and Kupfer are the members of the Nominating and Governance Committee, with Mr. Holtz acting as the chair. The board of directors has determined that each of the members of the Nominating and Governance Committee is independent, as defined by the rules of the NYSE and in accordance with the independence standards adopted by the board.

Investment Committee. The principal functions of the Investment Committee are to assist the board in reviewing management investment practices, policies, strategies, transactions and performance, as well as evaluating and monitoring existing and proposed investments. Messrs. Biderman, W. Jones and Kupfer are the members of the Investment Committee, with Mr. W. Jones acting as the chair. The board of directors has determined that each of the members of the Investment Committee is independent, as defined by the rules of the NYSE and in accordance with the independence standards adopted by the board.

Environmental, Health and Safety Committee. The Environmental, Health and Safety Committee assists the board of directors in determining whether we have appropriate policies and management systems in place with respect to environment, health and safety and related matters. The committee monitors the adequacy of our policies and management for addressing environmental, health and safety matters consistent with prudent exploration and production industry practices. The

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Environmental, Health and Safety Committee monitors and reviews compliance with applicable environmental, health and safety laws, rules and regulations. The committee reviews actions taken by management with respect to deficiencies identified or improvements recommended. The members of the Environmental, Health and Safety Committee are Dr. Craig, Mr. Holtz and Mr. Kupfer. Dr. Craig serves as chair of the committee. The board of directors has determined that each of the members of the The Environmental, Health and Safety Committee is independent, as defined by the rules of the NYSE and in accordance with the independence standards adopted by the board.

Code of Business Conduct and Ethics, Governance Guidelines and Committee Charters

We have adopted a code of business conduct and ethics that applies to our principal executive officer, principal financial officer and principal accounting officer, as well as to persons performing services for us generally. We have also adopted governance guidelines and charters for the Audit Committee, Compensation Committee, Nominating and Governance Committee and Environmental, Health and Safety Committee. We will make a printed copy of our code of ethics, our governance guidelines and committee charters available to any unitholder who so requests. Requests for print copies may be directed to us as follows: Atlas Energy Group, LLC, Park Place Corporate Center One, 1000 Commerce Drive, 4^th Floor, Pittsburgh, Pennsylvania 15275-1011, Attention: Secretary. The code of business conduct and ethics, the governance guidelines and our committee charters are also posted, and any waivers we grant to our code of business conduct and ethics will be posted, on our website at www.atlasenergy.com.

Compensation Committee Interlocks and Insider Participation

During the year ended December 31, 2014, 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 Item 11 below.

Corporate Governance

Board Leadership; Executive Sessions of the Board

Jonathan Z. Cohen serves as the Executive Chairman of the board and Edward E. Cohen serves as our Chief Executive Officer, President and director. 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. The Chief Executive Officer and the Executive Chairman of the board are in regular contact and to serve together with Matthew A. Jones, who serves as a Senior Vice President, as our executive committee.

As set forth in our governance guidelines and in accordance with NYSE listing standards, the independent members of our board of directors meet in executive session regularly without management. The board member who presides at these meetings rotates each meeting. The purpose of these executive sessions is to promote open and candid discussion among the independent board members.

Governance Guidelines

The board of directors has adopted governance guidelines 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

General

The role in risk oversight of the board of directors recognizes the multifaceted nature of risk management. The board has empowered several of its committees with aspects of risk oversight. We administer our risk oversight function through the Audit Committee, which monitors material enterprise risks, and the Environmental, Health and Safety Committee, which assists in determining whether appropriate policies and management systems are in place with respect to environment, health and safety and related matters and monitors and reviews compliance with applicable environmental, health and safety laws, rules and regulations. In order to assist in its oversight function, the Audit Committee oversaw the creation of the enterprise risk management committee consisting of senior officers from our various divisions that are responsible for day-to-day risk oversight. The Audit Committee meets with the members of the enterprise risk management committee as needed to discuss

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our risk management framework and related areas. It also reviews any major transactions or decisions affecting our risk profile or exposure, and reviews with counsel legal compliance and legal matters that could have a significant impact on our financial statements. The Audit Committee also oversees our internal audit function and is 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. The Audit Committee incorporates its risk oversight function into its regular reports to the board of directors. The Environmental, Health and Safety Committee reviews actions taken by management with respect to deficiencies identified or improvements recommended.

In addition to these committees’ role in overseeing risk management, the full board of directors regularly engages in discussions of the most significant risks that we face and how these risks are being managed. Our senior executives will provide regular updates about our strategies and objectives and the risks inherent within 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 may call special meetings when necessary to address specific issues or matters that should be addressed before the next regularly scheduled meeting. In addition, our directors 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.

Compensation Programs

Historically, Atlas Energy’s compensation policies and programs were intended to encourage employees to remain focused on both our short-term and long-term goals. Annual incentives were intended to tie a significant portion of each of the named executive officer’s compensation to Atlas Energy’s annual performance and/or that of the divisions for which the officer was responsible. Atlas Energy believed that the focus on revenue growth and distributable cash flow in making incentive bonus awards and unit price performance in granting equity awards provided a check on excessive risk taking. In addition, Atlas Energy adopted a clawback policy that allowed it to recoup any excess incentive compensation paid to its NEOs if the financial results on which the awards were based are materially restated due to fraud, illegal or intentional misconduct or gross negligence of the executive officer.

Atlas Energy’s compensation committee, together with senior management, also reviewed compensation programs and benefits plans affecting employees generally (in addition to those applicable to its executive officers), and Atlas Energy concluded that its compensation policies and practices did not create risks that were reasonably likely to have a material adverse effect on the company. Atlas Energy also believed that its incentive compensation arrangements provided incentives that did not encourage risk-taking beyond its ability to effectively identify and manage significant risks; were compatible with effective internal controls and its risk management practices; and were supported by the oversight and administration of Atlas Energy’s compensation committee with regard to executive compensation programs.

Our Compensation Committee has only recently been formed, and our policies and executive compensation philosophy will be developed and established by it. In addition, our code of business conduct and ethics, which applies to all our officers and directors, seeks to mitigate the potential for inappropriate risk taking.

Director Nomination Process

The Nominating and Governance Committee is 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 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.

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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 contains 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.

Unitholder Nominations to Our Board of Directors

Pursuant to our limited liability agreement, our unitholders may nominate candidates for election to our board by providing timely prior notice to our board as described below under “—Communicating with the Board of Directors” as follows:

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The notice must be delivered to our board 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

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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

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in the case of the 2016 annual meeting, a unitholder’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 limited partner’s notice as described above.

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The notice must be updated and supplemented, if necessary, so that the information provided or required to be provided in such notice will be true and correct as of the record date for the meeting and as of the date that is ten business days prior to the meeting or any adjournment or postponement thereof, and such updates and supplements must be delivered to our board

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not later than five 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

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not later than eight 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 business days prior to the meeting or any adjournment or postponement thereof.

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The notice must set forth:

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the name and address of the unitholder, as they appear on our books, of the beneficial owner, if any, and of their respective affiliates or associates or others acting in concert therewith;

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(1) the class or series and number of our securities which are, directly or indirectly, owned beneficially and of record by such unitholder, such beneficial owner and their respective affiliates or associates or others acting in concert therewith, (2) 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 of our securities or with a value derived in whole or in part from the value of any of our securities, or any derivative or synthetic arrangement having the characteristics of a long position in any of our securities, 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 of our securities, 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 of our securities, whether or not such instrument, contract or right shall be subject to settlement in the underlying security, 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 common units or any of our securities (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, (3) any proxy, contract, arrangement, understanding, or relationship pursuant to which such unitholder, such beneficial owner, if any, and their respective affiliates or others acting in concert therewith has a right to vote any of our securities, (4) 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 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 of our securities by, manage the risk of share price changes for, or increase or decrease the voting power of, such unitholder with respect to any of our securities, 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 Partnership Security (any of the foregoing, a “Short Interest”), (5) any rights to dividends on any of our securities owned beneficially by such unitholder, such beneficial owner, if any, and their respective affiliates or others acting in concert therewith that are separated or separable from the underlying security, (6) any proportionate interest in any of our securities 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 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, (7) any performance-related fees (other than an asset-based fee) that such unitholder, such beneficial owner, if any, and their respective affiliates or others acting in concert therewith is entitled to based on any increase or decrease in the value of any of our securities or Derivative Instruments, if any, including without limitation any such interests held by members of such person’s immediate family sharing the same household, (8) any significant equity interests or any Derivative Instruments or Short Interests in any of our principal competitors held by such unitholder, such beneficial owner, if any, and their respective affiliates or others acting in concert therewith, and (9) any direct or indirect interest of such unitholder, such beneficial owner, if any, and their respective affiliates or others acting in concert therewith in any contract with us, any of our affiliates or any of our principal competitors (including, in any such case, any employment agreement, collective bargaining agreement or consulting agreement);

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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

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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

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any other information relating to such unitholder and beneficial owner, 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 Securities Exchange Act and the rules and regulations promulgated thereunder.

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If the notice relates to any business other than a nomination of a director that the unitholder proposes to bring before the meeting, the notice must, in addition to the matters set forth in paragraph above, also set forth:

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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 the unitholder and beneficial owner, if any, in such business;

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the text of the proposal or business (including the text of any resolutions proposed for consideration); and

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a description of all agreements, arrangements and understandings between the unitholder and beneficial owner, if any, and any other person or persons (including their names) in connection with the proposal of such business by the unitholder.

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As to each person whom the unitholder proposes to nominate for election or reelection to the board, the notice must also:

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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 Securities 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);

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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, without limitation 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

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include a completed and signed questionnaire with respect to the background and qualification of the person nominated and the background of any other person or entity on whose behalf the nomination is being made, and a completed and signed representation and agreement that the person nominated (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 the person, if elected as a director, will act or vote on any issue or question (a “Voting Commitment”) that has not been disclosed to us or (ii) any Voting Commitment that could limit or interfere with the person’s ability to comply, if elected as a director, with the person’s fiduciary 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 us 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 the 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 of our applicable

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publicly disclosed corporate governance, conflict of interest, confidentiality and stock ownership and trading policies and guidelines. In addition, we may require any proposed nominee to furnish such other information as we may reasonably require 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.

Communicating with the Board of Directors

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 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.

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ITEM 11:

EXECUTIVE COMPENSATION

COMPENSATION DISCUSSION AND ANALYSIS

Until February 2015, we were part of Atlas Energy and not an independent company, and our compensation committee had 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.

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

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 our Compensation Committee consistent with the compensation and benefit plans, programs and policies adopted by us. Initially, our compensation policies will be substantially the same as those employed by Atlas Energy. Our 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

An understanding of Atlas Energy’s executive compensation program begins with its program objectives.

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Aligning the interests of executives and unitholders. Atlas Energy sought to align the interests of its executives with those of its unitholders through equity-based compensation and executive unit ownership requirements.

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Linking rewards to performance. Atlas Energy sought to implement a pay-for-performance philosophy by tying a significant portion of executives’ compensation to their achievement of financial goals that were linked to its business strategy and each executive’s contributions towards the achievement of those goals.

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Offering competitive compensation. Atlas Energy sought to offer an executive compensation program that was competitive and that helped attract, motivate and retain top performing executives.

The Atlas Energy Compensation Committee believed that a significant portion of executive compensation should be variable and based on defined performance goals and/or unit price change (i.e., “at risk”). Our program met this goal by delivering compensation in the form of equity and other performance-based awards.

Going Forward

As noted above, since our Compensation Committee has only recently been formed, our policies and executive compensation philosophy will be developed and established by it.

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Governance of Executive Compensation

COMPENSATION COMMITTEE

Historically

The Atlas Energy Compensation Committee was 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 was also responsible for administering Atlas Energy’s clawback policy, stock ownership guidelines and employee benefit plans, including incentive plans.

The Atlas Energy Compensation Committee was comprised solely of independent directors of the Atlas Energy board.

Going Forward

Our Compensation Committee has recently been formed. Its responsibilities are identical to those of the Atlas Energy Compensation Committee and it is comprised solely of independent directors.

CHIEF EXECUTIVE OFFICER

Historically

The Atlas Energy Chief Executive Officer made 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 provided 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, might 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

Since our Compensation Committee has only recently been formed, the role of our Chief Executive Officer in making recommendations will be developed and established by our Compensation Committee.

INDEPENDENT COMPENSATION CONSULTANT

Historically

For 2014, the Atlas Energy Compensation Committee engaged Mercer (US) Inc., an independent compensation consulting firm, to provide information and objective advice regarding executive compensation. All of the decisions with respect to Atlas Energy’s NEOs’ compensation, however, were made by the Atlas Energy Compensation Committee or, in the case of awards from Atlas Pipeline Partners, which we refer to as APL, the APL compensation committee, which communicated 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 was comprised of 14 oil and gas companies with the majority having revenues ranging from 1/2 to 2 times Atlas Energy’s revenues, which were near the median. The 2014 peer group was the same as the peer group used in 2013. The members of the peer group were:


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

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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.

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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 did not provide any other services to Atlas Energy or its affiliated companies. In addition to reaffirming this on an annual basis, Atlas Energy also conducted a search of its accounts payable system to confirm that no Mercer affiliates are providing services outside of the compensation consulting services. Atlas Energy had a Code of Business Conduct and Ethics as well as a related party transaction policy which governed potential conflicts of interest. Atlas Energy directors and officers were also required to complete questionnaires on an annual basis, which allowed Atlas Energy to review whether there were any potential conflicts as a result of personal or business relationships. There were 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

Our Compensation Committee expects 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. Our Compensation Committee will also work with the selected compensation consultant to develop a peer group that reflects, as closely as possible, our business mix, structure, and size.

TIMING OF COMPENSATION DECISION PROCESS

Historically

The Atlas Energy Compensation Committee made its determination on compensation amounts shortly after the close of Atlas Energy’s and our fiscal year. In the case of base salaries, the committee recommended the amounts to be paid for the new fiscal year. In the case of annual bonus and long-term incentive compensation, the committee determined the amount of awards based on the most recently concluded fiscal year.

Atlas Energy typically paid cash awards and issued equity awards in February of each year, although the Atlas Energy Compensation Committee had the discretion to recommend salary adjustments and the issuance of equity awards at other times during the fiscal year.

Going Forward

Our 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 was intended to provide fixed compensation to the NEOs for their performance of core duties that contributed to our success. Base salaries were not intended to compensate individuals for their extraordinary performance or for above average company performance.

ANNUAL INCENTIVES

Annual incentives were intended to tie a significant portion of each of the NEO’s compensation to Atlas Energy’s annual performance and/or that of its subsidiaries or divisions for which the officer was responsible. Generally, the higher the level of responsibility of the executive within Atlas Energy, the greater was the incentive component of that executive’s target total cash compensation. The Atlas Energy Compensation Committee could recommend awards of performance-based bonuses and discretionary bonuses.

PERFORMANCE-BASED BONUSES

Atlas Energy had an Annual Incentive Plan for Senior Executives, which we refer 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

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Executive Plan. Awards under the Atlas Energy Senior Executive Plan could be paid in cash or in a combination of cash and time-vesting equity. Making all equity awards vest over time added an additional performance-based component to the bonuses.

Summary of performance factors that determine bonus

• No awards are made unless at least one of the performance goals is met, except in exceptionally rare circumstances

• Equity awards vest over time—a delayed payout feature that further aligns interests of NEOs with sustainable long-term growth in unitholder value

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 had not historically been an Atlas Energy NEO. The theoretical bonus pool was 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.

The goals were set early in the year, but actual awards were ultimately determined by the Atlas Energy Compensation Committee’s year-end evaluation that also evaluated other factors as set forth below. The Atlas Energy Compensation Committee had the discretion to make awards even if one of the goals was not met.

In the event that distributable cash flow included any capital transaction gains in excess of $50 million, then only 10% of that excess was included in the bonus pool. Distributable cash flow means the sum of (i) cash available for distribution by Atlas Energy, 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 had 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 considered 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 could be awarded to recognize individual and group performance without regard to limitations otherwise in effect.

LONG-TERM INCENTIVES

Atlas Energy believed that its long-term success depended upon aligning its executives’ and unitholders’ interests. To support this objective, Atlas Energy provided 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 could recommend grants of equity awards in the form of options and/or phantom units. Generally, the unit options and phantom units vested over a three- or four-year period.

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Atlas Energy’s NEOs were eligible to receive awards under Atlas Resource Partners’, which we refer to as ARP, 2012 Long-Term Incentive Plan, which we refer to as the ARP Plan. Atlas Energy’s NEOs were 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 were determined by the APL compensation committee and the amount of the APL awards was communicated to the Atlas Energy Compensation Committee.

Going Forward

Our 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 similar to Atlas Energy’s compensation plans. Additional information about our Senior Executive Plan and 2015 Long-Term Incentive Plan is set forth in the sections of this information statement captioned “—Our Senior Executive Plan” and “—2015 Long-Term Incentive Plan,” respectively.

Our 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. We expect that the target levels for the annual incentive and long-term incentive compensation opportunities of our Named Executive Officers 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, were treated as follows:

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Each option to purchase Atlas Energy common units was converted into an adjusted Atlas Energy option and a option for our common units. The exercise price and number of units subject to each option was 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, retained those awards and also received a phantom unit award covering a number of our 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.

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Immediately following the separation and distribution, all of our options and phantom unit awards were cancelled and settled for the implied value of a common unit less, in the case of our options, the applicable exercise price. All of our options and phantom unit awards were settled in cash.

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The adjusted Atlas Energy equity awards were cancelled and converted or settled as provided in the Atlas merger agreement.

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APL equity awards were cancelled and converted or settled as provided in the APL merger agreement.

ARP equity awards were not adjusted in connection with the separation and remain outstanding in accordance with their respective terms.

Additional Information Concerning Executive Compensation

Historically

DEFERRED COMPENSATION

All Atlas Energy employees could participate in the Atlas Energy 401(k) plan, which was 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 was designed to permit individuals who exceeded certain income thresholds and who might 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 was 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

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retirement. Under the Atlas Energy Deferred Compensation Plan, a participant could 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 was 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 did not pay above-market or preferential earnings on deferred compensation. Participation in the Atlas Energy Deferred Compensation Plan was 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 its, 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, provided 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:

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“Double trigger” severance payments—Change in control severance benefits (base salary and bonus payments) to each NEO would be 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 changed substantially and was essentially an involuntary termination, and (2) after a change in control.

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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 could be required to return incentive compensation paid to them if the financial results upon which the awards were based were restated due to the fraud or intentional illegal conduct of the executive officer.

The Clawback Policy did not authorize the Atlas Energy Compensation Committee to seek recovery to the extent it determined 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 could determine in its discretion if it would seek to recover applicable compensation, taking into account the following considerations as it deemed 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 might prejudice Atlas Energy’s interests, including in any related proceeding or investigation;

•

the passage of time since the occurrence of the misconduct; and

•

any pending legal action related to the misconduct.

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Atlas Energy believed its Clawback Policy was sufficiently broad to reduce the potential risk that an executive officer would intentionally misstate results in order to benefit under an incentive program and provided a right of recovery in the event that an executive officer took actions that, in hindsight, should not have been rewarded.

This Clawback Policy applied in addition to the clawback provisions of awards under the Atlas Energy Plans, which provided that the Atlas Energy Compensation Committee had the express right to cancel an option or phantom unit grant, and to demand the return of any vested units, if the recipient 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, was convicted of a felony or a crime of moral turpitude with respect to Atlas Energy or engaged 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 were 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 counted toward the satisfaction of the ownership guidelines included 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 could also satisfy the ownership guidelines so long as at least 50% of an executive’s holdings were Atlas Energy common units. Executives had five years from the date of the commencement of the guidelines or the date the executive was designated a covered executive by the Atlas Energy Compensation Committee, whichever was later, to attain these ownership levels. If an executive officer did not meet the applicable guideline by the end of the five-year period, the executive officer was required to hold any net shares resulting from any future vesting of restricted or phantom units or exercise of stock options until the guideline was met. The Atlas Energy Compensation Committee believed these guidelines reinforced the importance of aligning the interests of Atlas Energy’s executive officers with the interests of its unitholders and encouraged its executive officers to consider the long-term perspective when managing Atlas Energy.

NO HEDGING OF COMPANY STOCK

All of Atlas Energy’s employees were prohibited from hedging their company stock.

NO TAX GROSS-UPS

Atlas Energy did not provide tax reimbursements to its NEOs.

PERQUISITES

At the discretion of the Atlas Energy Compensation Committee, Atlas Energy provided 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 chair 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, and now we, receive from the Lightfoot entities, excluding amounts that constitute a return of capital.

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Going Forward

Our 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 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 Atlas Energy 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

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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.

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 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,” as a result of the separation were 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 Atlas Energy Compensation Committee made continuity awards of Atlas Energy phantom units (with DERs) to a number of executives, including to the

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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,” as a result of the separation were cancelled and converted into a right to receive the merger consideration and our phantom units.

Going Forward

Our 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, our Compensation Committee will need to evaluate the relevance of peer data and determine the appropriate peer group, if any, for us.

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 our 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 the Atlas Energy 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 our Compensation Committee.

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
Chief Executive Officer and President		2014		1,000,000		—		17,812,798		—		2,000,000		4,178,447	⁽³⁾		24,991,245
		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
Chief Financial Officer		2014		400,000		—		3,411,694		—		600,000		236,718	⁽⁴⁾		4,648,412
		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
Executive Chairman of the Board		2014		700,000		—		17,312,821		—		2,000,000		3,766,497	⁽⁵⁾		23,779,318
		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
Senior Vice President, Corporate Development and Strategy		2014		392,308		750,000		5,844,469		—		—		1,042,524	⁽⁶⁾		8,029,301
		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

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Matthew A. Jones
Senior Vice President and President of E&P Division	2014	400,000	—	4,945,806	—	750,000	593,093	⁽⁷⁾	6,688,899
	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.

⁽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.

⁽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.

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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 ($)		Grant date		All other stock awards: Number of units					Exercise or base price of option awards ($/Unit)		Grant date fair value of unit and option awards ($)⁽⁵⁾
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.

⁽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 had employment agreements with its NEOs that provided for severance compensation to be paid if their employment was terminated under certain conditions.

Terms Used

“Good reason” was 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 ceased to be a public company unless Atlas Energy becomes a subsidiary of a public company and,

•

in the case of Mr. E. Cohen, became the chief executive officer of the public parent immediately following the applicable transaction;

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•

in the case of Mr. J. Cohen, became 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 was not Atlas Energy’s CEO or the CEO of the acquiring entity;

•

the executive were 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 Atlas Energy’s board; or

•

any material breach of the agreement.

“Cause” was defined in Mr. E. Cohen’s and Mr. J. Cohen’s employment agreements as:

•

the executive was convicted of a felony, or any crime involving fraud or embezzlement;

•

the executive intentionally and continually failed to perform his reasonably assigned duties (other than as a result of disability), which failure was materially and demonstrably detrimental to Atlas Energy and continued for 30 days after written notice signed by a majority of the independent directors of the General Partner; or

•

the executive was determined, through arbitration, to have materially breached the restrictive covenants in the agreement.

“Cause” was defined in Messrs. Jones’s and Herz’s employment agreements as:

•

the executive committed any demonstrable and material fraud;

•

illegal or gross misconduct that was willful and resulted in damage to Atlas Energy’s business or reputation;

•

the executive was 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.

The separation constituted a termination for good reason by each of these executives under their employment agreements, and their agreements terminated on February 27, 2015.

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 had a term of three years, which automatically renewed daily unless terminated before the expiration of the term pursuant to the termination provisions of the agreement.

The agreement provided for an initial annual base salary of $700,000, which could be increased at the discretion of the board of directors of Atlas Energy’s general partner. Mr. Cohen was 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 participated in the Atlas Energy Deferred Compensation Plan, under which he could elect to defer up to 10% of his total annual cash compensation, which Atlas Energy was required to 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 was required to maintain a term life insurance policy on Mr. Cohen’s life that provided a death benefit of $3 million, which could be assumed by Mr. Cohen upon a termination of employment.

The agreement provided 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 would 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 was entitled to receive, in addition to

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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 could terminate Mr. Cohen’s employment if he were 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 was required to pay his base salary until it acted to terminate his employment. Upon termination of employment due to disability, Mr. Cohen would 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 could elect to pay Mr. Cohen 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 was entitled to either (i) if he did not execute and not revoke a release of claims against Atlas Energy, payment of the Accrued Obligations, or (ii) in addition to payment of the Accrued Obligations, if he executed and did not revoke a release of claims against Atlas Energy, (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 was 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 would be reduced such that the total payments to the executive which were subject to Internal Revenue Code Section 280G were 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.

When Mr. Cohen’s employment agreement terminated in February 2015, in connection with the Atlas mergers, he received the following: $32,538,286 in cash severance, $476,712 in a pro-rated bonus and all of his units were accelerated. As a result of the Atlas mergers, he received $32,057,049 for the cash-out of the Atlas Energy and APL equity awards subject to accelerated vesting. 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.

189

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 had a term of three years, which automatically renewed daily unless terminated before the expiration of the term pursuant to the termination provisions of the agreement.

The agreement provided for an initial annual base salary of $500,000, which could be increased at the discretion of the board of directors of Atlas Energy’s general partner. Mr. Cohen was 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 participated in the Atlas Energy Deferred Compensation Plan, under which he could elect to defer up to 10% of his total annual cash compensation, which Atlas Energy was required to 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 was required to maintain a term life insurance policy on Mr. Cohen’s life that provided a death benefit of $2 million, which could be assumed by Mr. Cohen upon a termination of employment.

The agreement provided the same benefits in the event of a termination of employment as described above in Mr. E. Cohen’s employment agreement summary.

When Mr. Cohen’s employment agreement terminated in February 2015, in connection with the Atlas mergers, he received the following: $30,888,289 in cash severance, $476,712 in a pro-rated bonus and all of his units were accelerated. As a result of the Atlas mergers, he received $27,105,927 for the cash-out of the Atlas Energy and APL equity awards subject to accelerated vesting. 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⁾

⁽³⁾	Represents life insurance policy proceeds.

⁽⁴⁾

Daniel C. Herz

In November 2011, Atlas Energy entered into an employment agreement with Daniel C. Herz. Under the agreement, Mr. Herz had the title of Senior Vice President—Corporate Development and Strategy. The agreement had an effective date of November 4, 2011 and an initial term of two years, which automatically renewed daily after the first anniversary of the agreement for one-year terms.

190

The agreement provided for an initial annual base salary of $280,000. Mr. Herz was 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 provided 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 was 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 was unable to perform his duties), all equity awards held by Mr. Herz would accelerate and vest in full upon such termination (“Acceleration of Equity Vesting”), and Mr. Herz or his estate was 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 was the number of days in the fiscal year in which the termination occurs through the date of termination, and the denominator of which was the total number of days in such fiscal year (the “Pro-Rata Bonus”). In addition, his family was 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” included a non-renewal of the agreement) or by the executive for good reason, Mr. Herz was entitled to either: if Mr. Herz did not timely execute (or revoked) 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 executed and did 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 was 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 occured); 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 could 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 would be reduced such that the total payments to the executive which were subject to Section 280G of the Internal Revenue Code were 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.

When Mr. Herz’s employment agreement terminated in February 2015, in connection with the Atlas mergers, he received the following: $2,866,667 in cash severance, $182,740 in a pro-rated bonus and all of his units were accelerated. As a result of the Atlas mergers, he received $11,070,685 for the cash-out of the Atlas Energy and APL equity awards subject to accelerated vesting. 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.

191

⁽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 had the title of Senior Vice President and President of the Exploration and Production Division. The agreement had an effective date of November 4, 2011 and an initial term of two years, which automatically renewed daily after the first anniversary of the agreement for one year terms.

The agreement provided for an initial annual base salary of $280,000. Mr. Jones was 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.

The agreement provided 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 was 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 was unable to perform his duties), all equity awards held by Mr. Jones would accelerate and vest in full upon such termination (“Acceleration of Equity Vesting”), and Mr. Jones or his estate was 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 was the number of days in the fiscal year in which the termination occurs through the date of termination, and the denominator of which was the total number of days in such fiscal year (the “Pro Rata Bonus”). In addition, his family was entitled to company-paid health insurance for the one-year period after his death.

•

if Mr. Jones did not timely execute (or revoked) 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. Jones timely executed and did not revoke a release of claims against Atlas Energy:

•

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.

192

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 would be reduced such that the total payments to the executive which were subject to Section 280G were 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.

When Mr. Jones’ employment agreement terminated in February 2015, in connection with the Atlas mergers, he received the following: $2,900,000 in cash severance, $119,178 in a pro-rated bonus and all of his units were accelerated. As a result of the Atlas mergers, he received $11,889,674 for the cash-out of the Atlas Energy and APL equity awards subject to accelerated vesting. 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⁾

⁽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 terminated in connection with the separation effective February 27, 2015. It provided equity incentive awards to officers, employees and board members and employees of its general partner and its affiliates, consultants and joint-venture partners who performed services for it. The Atlas Energy 2006 Plan was administered by the Atlas Energy Compensation Committee. The committee could grant awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units.

Partnership Phantom Units. A phantom unit entitled a participant to receive a common unit upon vesting of the phantom unit. Non-employee directors could receive an annual grant of phantom units having a fair market value of $125,000, which upon vesting entitled 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 vested over four years. In tandem with phantom unit grants, the committee could grant a DER. The committee determined the vesting period for phantom units. Phantom units granted under the Atlas Energy 2006 Plan generally vested 25% on the third anniversary of the date of grant, with the remaining 75% vesting on the fourth anniversary of the date of grant, except non-employee director grants vested 25% per year.

Partnership Unit Options. A unit option entitled 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 could 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 determined the vesting and exercise period for unit options. Unit option awards would expire 10 years from the date of grant. Unit options granted generally vested 25% on the third anniversary of the date of grant, with the remaining 75% vesting on the fourth anniversary of the date of grant.

193

Change of Control.


Individual	Triggering event	Acceleration
Eligible employees	Change of Control (as defined in the Atlas Energy 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 terminated in connection with the separation effective February 27, 2015. It provided equity incentive awards to officers, employees and board members and employees of its general partner and its affiliates, consultants and joint-venture partners who performed services for it. The Atlas Energy 2010 Plan was administered by the Atlas Energy Compensation Committee which could grant awards of either phantom units, unit options or restricted units for an aggregate of 5,300,000 common limited partner units.

Partnership Restricted Units. A restricted unit was a common unit issued that entitled a participant to receive it upon vesting of the restricted unit. Prior to or upon grant of an award of restricted units, the committee would condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals or both.

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 the Atlas Energy 2010 Plan 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.

194

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”), terminated in connection with the APL merger effective February 27, 2015. They provided 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 performed services for APL or in furtherance of its business. The APL Plans were administered by APL’s compensation committee (the “APL Committee”). Under the APL Plans, the APL Committee could 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 entitled the grantee to receive a common unit upon the vesting of the phantom unit. In addition, the APL Committee could 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 was outstanding.

APL Unit Options. An option entitled the grantee to purchase APL common units at an exercise price determined by the APL Committee, which could be less than, equal to or more than the fair market value of APL common units on the date of grant. The compensation committee also had discretion to determine how the exercise price could be paid.

Except for phantom units awarded to non-employee managers of Atlas Pipeline GP, the APL Committee determined the vesting period for phantom units and the exercise period for options. Phantom units awarded to non-employee managers generally vested over a 4-year period at the rate of 25% per year. Both types of awards would automatically vest upon a change of control, as defined in the APL Plans.

ARP Plan

The ARP 2012 Long-Term Incentive Plan (the “ARP Plan”) provides equity incentive awards to our officers, employees and board members and employees of our affiliates, consultants and joint venture partners who perform services for ARP. The ARP Plan was historically administered by the Atlas Energy Compensation Committee,and is now administered by our 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

195

The change in control definition in the ARP Plan was amended in February 2015 so the Atlas Merger would not be deemed a change of control under such plan.

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

196


	—		—		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.

⁽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. We assumed all of Atlas Energy’s obligations under the Atlas Energy Deferred Compensation Plan as part of the separation effective February 27, 2015, and refer to it as the Deferred Compensation Plan. The 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 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 we are 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 Deferred Compensation Plan and we 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 Deferred Compensation Plan constitutes a general, unsecured obligation, payable out of our general assets, and Messrs. E. Cohen and J. Cohen do not have any rights to any specific asset of our company.

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The 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.

Our Senior Executive Plan

In February 2015, we adopted the Atlas Energy Group, LLC Annual Incentive Plan for Senior Executives, which we refer to as the “Senior Executive Plan.” The following is a summary of the Senior Executive Plan.

Purpose

The Senior Executive Plan provides a means for awarding annual bonuses to our senior executive employees and senior executive employees of our subsidiaries based on the achievement of performance goals over a designated performance period. The performance period is our 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 our unitholders by providing compensation that varies based on our success.

Administration

The Senior Executive Plan will be administered and interpreted by our Compensation Committee. The committee has the authority to establish rules and regulations relating to the Senior Executive Plan, to interpret the 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 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 Senior Executive Plan, including the delegation of its authority or power, where appropriate.

Eligibility and Participation

Our senior executive employees are eligible to participate in the Senior Executive Plan. The Compensation Committee will select the senior executive employees who will participate in the Senior Executive Plan for each performance period.

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Establishment of Performance Goals

As soon as practicable following the beginning of a performance period, the Compensation Committee will determine 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 committee may consider factors including performance relative to an appropriate group designated by the 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 us as a whole, to a subsidiary, to a business unit of us or any subsidiary, to an affiliate 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, will use the information set forth in our audited financial statements and other objectively determinable information. The performance goals established by the 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 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 our financial results for the relevant performance period. Payment of the awards certified by the 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 any long-term incentive plan.

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 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 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 committee.

Change in Control

Unless the Compensation Committee determines otherwise, if a “change in control” (as defined in the Senior Executive Plan) 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 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 Senior Executive Plan not been terminated, as determined by the committee.

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2015 Long-Term Incentive Plan

In February 2015, we adopted the Atlas Energy Group, LLC 2015 Long-Term Incentive Plan, which we refer to as the “2015 LTIP.” The following is a brief description of the principal features of the 2015 LTIP.

Purpose

The 2015 LTIP is intended to promote our interests by providing to our officers, employees, and directors, employees of our affiliates, consultants, and joint venture partners who perform services for us incentive awards for superior performance that are based on our common units. The 2015 LTIP is intended to enhance our ability to attract and retain the services of individuals who are essential for our growth and profitability, and to encourage them to devote their best efforts to our business and advancing our interests.

Administration

Grants made under the 2015 LTIP will be determined by our board of directors or a committee of the board of appointed by the board of directors to administer the 2015 LTIP. Our board has appointed the Compensation Committee to administer the 2015 LTIP, which we refer to as the “committee.”

Subject to the provisions of the 2015 LTIP, the committee is authorized to administer and interpret the 2015 LTIP, to make factual determinations, and to adopt or amend its rules, regulations, agreements, and instruments for implementing the 2015 LTIP. The committee also has the full power and authority to determine the recipients of grants under the 2015 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 2015 LTIP, including the power to award grants under the 2015 LTIP, to our Chief Executive Officer, 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 2015 LTIP are (a) officers and employees of us, our affiliates, consultants, or joint venture partners who perform services for us or an affiliate or in furtherance of our business (we refer to each such officer and employee as an “eligible employee”) and (b) our non-employee directors.

Unit Reserve; Adjustments

Awards in respect of up to 5.25 million of our common units (approximately 20% of the fully diluted issued and outstanding number of common units basis after giving effect to the distribution) may be issued under the 2015 LTIP. This amount is subject to adjustment as provided in the 2015 LTIP for events such as distributions (in common units or other securities or property, including cash), unit splits (including reverse splits), recapitalizations, mergers, consolidations, reorganizations, reclassifications, and other extraordinary events affecting our outstanding 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 2015 LTIP. Common units issued under the 2015 LTIP may consist of newly issued common units, common units acquired in the open market or from any of our affiliates, or any other person, or any combination of the foregoing. If any award granted under the 2015 LTIP is forfeited or otherwise terminates or is cancelled or paid without the delivery of common units, then the common units covered by the award will (to the extent of the forfeiture, termination, or cancellation, as the case may be) again be available for grants of awards under the 2015 LTIP. Common units surrendered in payment of the exercise price of an option, and withheld or surrendered for payment of taxes, will not be available for re-issuance under the 2015 LTIP.

Awards

Awards granted under the 2015 LTIP may consist of options to purchase common units, phantom units, and restricted units. All grants are subject to such terms and conditions as the committee deems appropriate, including vesting conditions.

Options. An option is the right to purchase a 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 common unit on the date the option is granted. The committee will determine the vesting and

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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 board of directors, a tender of 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 board of directors and that does not violate the Sarbanes-Oxley Act of 2002, a “net exercise” that permits us to withhold a number of 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.

Phantom Units. Phantom units represent rights to receive common units, an amount of cash or other securities or property based on the value of a common unit, or a combination of 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 us with respect to common units during the period that the underlying phantom unit is outstanding. Distribution equivalents may (a) be paid currently 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 common units or in a combination of cash and common units, in each case as determined by the committee.

Restricted Units. Restricted units are actual 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 our 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 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 2015 LTIP), all unvested awards granted under the 2015 LTIP held by directors will immediately vest in full. In the case of awards granted under the 2015 LTIP held by eligible employees, upon the eligible employee’s termination of employment without “cause” (as defined in the 2015 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 we (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 common units that otherwise would have been unvested so that participants (as holders of awards granted under the 2015 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

•

make such other modifications, adjustments, or amendments to outstanding awards or the 2015 LTIP as the committee deems necessary or appropriate.

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No Assignment

Except as otherwise determined by the committee, no award granted under the 2015 LTIP is 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 2015 LTIP will be subject to applicable federal (including FICA), state, and local tax withholding requirements. If we so permit, common units may be withheld to satisfy tax withholding obligations with respect to awards paid in 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. We 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 2015 LTIP at any time without the consent of participants, except that the committee may not amend the 2015 LTIP without approval of the unitholders if such approval is required in order to comply with applicable stock exchange requirements. We may waive any conditions or rights under, amend any terms of, or alter any award previously granted under the 2015 LTIP; however, no change to any award previously granted under the 2015 LTIP may materially reduce the benefit to a participant, unless the participant has consented or such change is explicitly allowed in the 2015 LTIP or the applicable award agreements. The committee may not reprice options, nor may the 2015 LTIP be amended to permit option repricing, unless the unitholders approve such repricing or amendment.

Plan Term

The 2015 LTIP will continue until the date terminated by our board of directors or the date upon which common units are no longer available for the grant of awards, whichever occurs first.

2014 DIRECTOR COMPENSATION TABLE


Name	Fees earned or paid in cash($)		Stock awards($)			All other compensation($)⁽¹⁾		Total($)
DeAnn Craig		70,000		74,980	⁽²⁾		15,716		160,696
Jeffrey C. Key		65,000		74,980	⁽²⁾		15,716		155,696
Harvey G. Magarick		90,000		74,997	⁽³⁾		11,114		176,111
Bruce Wolf		70,000		74,980	⁽²⁾		15,716		160,696

(1)	Represents payments on DERs for ARP phantom units.

(2)	For Messrs. Key and Wolf and Dr. Craig, represents 3,591 phantom units granted under the ARP Plan, having a grant date fair value of $20.88. The phantom units vest 25% on the anniversary of the date of grant as follows: 4/3/15—897, 4/3/16—897, 4/3/17—897 and 4/3/18—900.

(3)	For Mr. Magarick, represents 3,900 phantom units granted under the ARP Plan, having a grant date fair value of $19.23. The phantom units vest 25% on the anniversary of the date of grant as follows: 9/24/15—975, 9/24/16—975, 9/24/17—975 and 9/24/18—975.

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Director Compensation

Our officers or employees who also served as directors of our general partner did not receive additional compensation for their service as a director. In fiscal 2014, the annual retainer for non-employee directors was comprised of $65,000 in cash and an annual grant of phantom units with DERs under the ARP Plan having a fair market value of $75,000. These units will vest ratably over four years beginning on the grant date. The chair of the audit committee received an annual fee of $25,000 and the chairs of the conflicts committee and the environmental, health and safety committee each received an annual fee of $5,000. For fiscal 2015, the annual retainer for non-employee directors is comprised of $75,000 in cash and an annual grant of phantom units with DERs under the 2015 LTIP having a fair market value of $125,000. These units will vest ratably over four years beginning on the grant date. The chair of the audit committee receives an annual fee of $25,000, the chair of the compensation committee receives an annual fee of $10,000, the chairs of the nominating and governance committee and the investment committee receive an annual fee of $7,500 and the chair of the environmental, health and safety committee receives an annual fee of $5,000.

ITEM 12:

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

The following table sets forth the number and percentage of common units owned, as of March 23, 2015, by (a) each person who, to our knowledge, is the beneficial owner of more than 5% of the outstanding common units, (b) each of our present directors and nominees, (c) each of our executive officers serving during the 2014 fiscal year, and (d) all of our directors, nominees and executive officers as a group. This information is reported in accordance with the beneficial ownership rules of the Securities and Exchange Commission under which a person is deemed to be the beneficial owner of a security if that person has or shares voting power or investment power with respect to such security or has the right to acquire such ownership within 60 days. Common units issuable pursuant to options or warrants are deemed to be outstanding for purposes of computing the percentage of the person or group holding such options or warrants but are not deemed to be outstanding for purposes of computing the percentage of any other person. Unless otherwise indicated in footnotes to the table, each person listed has sole voting and dispositive power with respect to the securities owned by such person.


Beneficial owner Directors ⁽¹⁾	Common unit amount and nature of beneficial ownership			Percent of class
Mark C. Biderman		10,986			*
Edward E. Cohen		737,804	⁽²⁾		2.8	%
Jonathan Z. Cohen		691,991	⁽³⁾		2.6	%
DeAnn Craig		2,199			*
Dennis A. Holtz		8,380			*
Walter C. Jones		323			*
Jeffrey F. Kupfer		3,213			*
Ellen F. Warren		3,774			*
Non-director principal officers⁽¹⁾
Freddie M. Kotek		51,435	⁽⁴⁾		*
Matthew A. Jones		41,234			*
Daniel C. Herz		8,419			*
Sean P. McGrath		8,536			*
Jeffrey M. Slotterback		2,202			*
Lisa Washington		4,377			*
All executive officers, directors and nominees as a group (14 persons)		970,751	⁽⁵⁾		*
Other owners of more than 5% of outstanding common units
Leon G. Cooperman		4,050,495	⁽⁶⁾		15.6	%
Morgan Stanley/ Morgan Stanley Strategic Investments, Inc.		2,526,169	⁽⁷⁾		9.7	%
Tourbillon Capital Partners LP		1,305,500	⁽⁸⁾		5.0	%

*	Less than 1%

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⁽¹⁾	The business address for each director, director nominee 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 are among the 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. 603,799 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 are among the trustees. These common units are also included in the common units referred to in footnote 2 above. Mr. J. Cohen disclaims beneficial ownership to the units described in (ii) above.

⁽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 3 filed with the SEC on March 9, 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 filed with the SEC on March 9, 2015. The address of Morgan Stanley and Morgan Stanley Strategic Investments, Inc. is 1585 Broadway, New York, NY 10036.

⁽⁸⁾

This information is based on a Schedule 13G filed with the SEC on May 7, 2014. The number of units owned have been adjusted in accordance with the separation effected on 2/27/15. The address of the principal business office of Tourbillon Capital Partners LP is 444 Madison Avenue, 26^th Floor, New York, NY 10022.

The following table sets forth the number and percentage of Series A convertible preferred units (“Series A Preferred Units”) owned, as of March 23, 2015, by (a) each person who, to our knowledge, is the beneficial owner of more than 5% of the outstanding Series A preferred units, (b) each of our present directors and nominees, (c) each of our executive officers serving during the 2014 fiscal year, and (d) all of our directors, nominees and executive officers as a group. This information is reported in accordance with the beneficial ownership rules of the Securities and Exchange Commission under which a person is deemed to be the beneficial owner of a security if that person has or shares voting power or investment power with respect to such security or has the right to acquire such ownership within 60 days. Unless otherwise indicated in footnotes to the table, each person listed has sole voting and dispositive power with respect to the securities owned by such person.


Beneficial owner Director⁽¹⁾	Series A preferred unit amount and nature of beneficial ownership			Percent of class
Mark C. Biderman		—			—
Edward E. Cohen		440,000	⁽²⁾⁽³⁾		27.5	%
Jonathan Z. Cohen		440,000	⁽⁴⁾		27.5	%
DeAnn Craig		—			—
Dennis A. Holtz		—			—
Walter C. Jones		—			—
Jeffrey F. Kupfer		—			—
Ellen F. Warren		—			—
Non-director principal officers⁽¹⁾
Daniel C. Herz		48,000			3.0	%
Matthew A. Jones		24,000			1.5	%
Freddie M. Kotek		48,000			3.0	%
Sean P. McGrath		8,000			*
Jeffrey M. Slotterback		—			—
Lisa Washington		—			—
All executive officers, directors and nominees as a group (14 persons)		788,000	⁽⁵⁾		21.8	%
Other owners of more than 5% of outstanding Series A preferred units
Leon G. Cooperman		800,000	⁽⁶⁾		50	%

*	less than 1%

(1)	The business address for each director, director nominee and executive officer is Park Place Corporate Center One, 1000 Commerce Drive, 4th Floor, Pittsburgh, PA 15275-1011.

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(2)	This amount includes 220,000 units held by Solomon Investment Partnership, L.P. (the “Partnership”). Mr. E. Cohen and his spouse are the sole shareholders, officers and directors of the corporate general partner of the Partnership and are the sole partners of the Partnership.

(3)	This amount includes 220,000 units held by a charitable foundation of which Mr. E. Cohen, his spouse and his children serve as co-trustees. Mr. E. Cohen disclaims beneficial ownership of these units. These units are also referred to in footnote 4 below.

(4)	This amount includes 220,000 units held by a charitable foundation of which Mr. J. Cohen, his parents and his sibling serve as co-trustees. Mr. J. Cohen disclaims beneficial ownership of these units.

(5)	This number has been adjusted to exclude 220,000 Series A Preferred Units which were included in both Mr. E. Cohen’s beneficial ownership amount and Mr. J. Cohen’s beneficial ownership amount.

(6)	The address of Mr. Cooperman is 11431 W. Palmetto Park Road, Boca Raton, FL 33428.

Equity Compensation Plan Information

The Atlas Energy Plans terminated in February 2015 in connection with the Atlas merger and separation. The 2015 LTIP was adopted in February 2015, and thus was not in place at the end of the 2014 fiscal year.

The following table contains information about the ARP Plan as of December 31, 2014:

Plan category

Number of
securities to be
issued upon
exercise of
equity
instruments

Weighted-
average
exercise price
of outstanding
equity
instruments

Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities reflected in
column (a))

(a)

(b)

(c)

Equity compensation plans approved by security holders – phantom units

799,192

n/a

Equity compensation plans approved by security holders – unit options

1,458,300

24.66

Equity compensation plans approved by security holders – Total

2,257,492

135,663

ITEM 13:

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Our Relationship with Atlas Energy

As a result of the separation and distribution, Atlas Energy no longer owns any of our outstanding common units and therefore no longer has any limited liability company interest in us, and is a subsidiary of Targa Resources.

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 non-independent directors of our board of directors also served as directors of Atlas Energy’s general partner.

We entered into the agreements described in this section with Atlas Energy in February 2015 to facilitate an orderly transition and govern the relationship between the companies after completion of the distribution and the Atlas Merger.

206

Separation and Distribution Agreement

Atlas Energy transferred its assets and liabilities other than those related to its “Atlas Pipeline Partners” segment to us and, immediately prior to the Atlas Merger, effected a pro rata distribution to the Atlas Energy unitholders of common units representing a 100% interest in us. 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.

The liabilities that we assumed from Atlas Energy, which we refer to as “Assumed Liabilities,” included:

•

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 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 transferred to us 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.

We will indemnify Atlas Energy and its affiliates 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 liability retained by Atlas Energy, 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 the information statement.

Atlas Energy will indemnify us and our subsidiaries, directors, officers and employees against liabilities relating to, arising out of or resulting from:

•

the liabilities retained by Atlas Energy;

•

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.

207

The separation and distribution agreement specifies procedures with respect to claims subject to indemnification and related matters.

Employee Matters Agreement

Immediately before the separation and distribution, we entered into an employee matters agreement with Atlas Energy 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 are employed by Atlas Energy following the separation and distribution and former employees whose last employment was with the business retained by Atlas Energy, whom we collectively refer to as the “Atlas Energy allocated employees,” and we will be responsible for liabilities associated with employees who we employ following the separation and distribution and former employees whose last employment was with our businesses, whom we collectively refer to as the “our allocated employees.”

Transfer of Employees

The employee matters agreement provides that, prior to the separation and distribution, all our allocated employees were transferred to us to the extent not already employed by us or our subsidiaries. Subject to certain exceptions, the transfer of our allocated employees to us did not constitute a separation from service for purposes of any applicable laws or severance programs.

Employee Benefits

Pursuant to the employee matters agreement, we assumed 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 our allocated employees following the separation and distribution. In general, we will credit each of our allocated employees with his or her service with Atlas Energy prior to the separation and distribution for all purposes under our 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 provides 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 us, and the subsequent cancellation and settlement of all of our awards issued in connection with the adjustment.

Term Loan Participation and Private Placement

In connection with the Term Loan Facilities, the lenders thereunder syndicated participations in loans underlying the facilities. Certain of our officers and 5% or more unitholders participated in the loan syndication as well of the Private Placement of our Series A preferred units. Mr. Edward E. Cohen, our Chief Executive Officer, President and Director, purchased approximately $4.1 million in loans and $5.5 million of Series A preferred units; Mr. Jonathan Z. Cohen, our Executive Chairman, purchased approximately $4.1 in loans and $5.5 million of Series A preferred units; Mr. Daniel Herz and Mr. Freddie Kotek, each a Senior Vice President, each purchased approximately $889,000 in loans and $1.2 million of Series A preferred units; Mr. Matthew A. Jones, our Senior Vice President, purchased approximately $444,000 in loans and $600,000 of Series A preferred units; Mr. Sean P. McGrath, our Chief Financial Officer, purchased approximately $111,000 in loans and $200,000 of Series A preferred units; and a charitable foundation of which Messrs. E. Cohen and J. Cohen, are among the trustees, purchased approximately $4.1 million in loans and $5.5 million of Series A preferred units. Additionally the managing member of Omega Associates, LLC, the general partner of various private investment firms that collectively own more than 5% of our outstanding equity securities, purchased approximately $15.0 million in loans and $20.0 million of Series A preferred units.

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

208

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, 2014, 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. Atlas Energy contributed the Class C preferred units and the warrants to us in the separation on February 27, 2015.

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.

Procedures for Approval of Related Person Transactions

The board of directors has adopted a written policy designed to minimize potential conflicts of interest in connection with our transactions with related persons. This policy defines 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 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 defines 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 were 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

209

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.

Director Independence

Our board of directors has determined that Dr. Craig, Ms. Warren and Messrs. Biderman, Holtz, Jones and Kupfer each satisfy the requirement for independence set out in Section 303A.02 of the rules of the New York Stock Exchange including those set forth in Rule 10A-3(b)(1) of the Securities Exchange Act, and meet the definition of an independent member set forth in our Governance Guidelines. In making these determinations, the board of directors reviewed information from each of these independent board members concerning all their respective relationships with us and analyzed the materiality of those relationships.

ITEM 14:

PRINCIPAL ACCOUNTANT FEES AND SERVICES

For the years ended December 31, 2014 and 2013, the accounting fees and services (in thousands) charged by Grant Thornton, LLP, our independent auditors, were as follows:


	Years Ended December 31,
	2014		2013
Audit fees⁽¹⁾	$	1,688	$	1,627
Audit-related fees⁽²⁾		134		242
Tax fees⁽³⁾		182		206
All other fees		—		—

Total accounting fees and services	$	2,004	$	2,075

⁽¹⁾

Represents the aggregate fees recognized in each of the last two years for professional services rendered by Grant Thornton LLP principally for the audits of our and our subsidiaries’ annual financial statements and the quarterly reviews of our and our subsidiaries’ financial statements included in Form 10-Qs and also for services related to our and our subsidiaries’ registration statements, Form 8-Ks and comfort letters, and audits related to the spin-off of assets associated with the Atlas Merger.

⁽²⁾

Represents the aggregate fees recognized during the years ended December 31, 2014 and 2013 for professional services rendered by Grant Thornton LLP substantially related to the historical audit of recently acquired EP Energy in 2013, certain necessary audit related services in connection with the registration and/or private placement of ARP’s Drilling Partnerships and audits of our benefit plans.

⁽³⁾	The fees for tax services rendered related to tax compliance.

Audit Committee Pre-Approval Policies and Procedures

The audit committee, on at least an annual basis, will review audit and non-audit services performed by Grant Thornton LLP as well as the fees charged by Grant Thornton LLP for such services. Our policy is that all audit and non-audit services must be pre-approved by the audit committee. All of such services and fees were pre-approved during 2014 and 2013 by the Atlas Energy audit committee.

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PART IV

ITEM 15:

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)

The following documents are filed as part of this report:

(1)

Financial Statements

The financial statements required by this Item 15(a)(1) are set forth in Item 8: Financial Statements and Supplementary Data.

(2)

Financial Statement Schedules

None

(3)

Exhibits:


Exhibit Number		Exhibit Description

2.1		Separation and Distribution Agreement by and among Atlas Energy, L.P., Atlas Energy GP LLC and Atlas Energy Group, LLC⁽²⁸⁾

2.2		Employee Matters Agreement by and among Atlas Energy, L.P., Atlas Energy GP LLC and Atlas Energy Group, LLC⁽²⁸⁾

3.1(a)		Certificate of Formation of Atlas Resource Partners GP, LLC⁽¹⁾

3.1(b)		Amendment to Certificate of Formation of Atlas Resource Partners GP, LLC⁽²⁾

3.2(a)		Second Amended and Restated Limited Liability Company Agreement of Atlas Resource Partners GP, LLC⁽³⁾

3.2(b)		Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of Atlas Resource Partners GP, LLC, dated as of November 3, 2014⁽²⁾

3.3(a)		Third Amended and Restated Limited Liability Company Agreement of Atlas Energy Group, LLC, dated as of February 27, 2015⁽²⁸⁾

3.3(b)		Amendment No. 1 to the Third Amended and Restated Limited Liability Company Agreement of Atlas Energy Group, LLC, dated as of February 27, 2015⁽²⁸⁾

10.1(a)		Amended and Restated Limited Partnership Agreement of Atlas Resource Partners, L.P.⁽⁴⁾

10.1(b)		Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Atlas Resource Partners, L.P., dated as of July 25, 2012⁽⁵⁾

10.1(c)		Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Atlas Resource Partners, L.P., dated as of July 31, 2013⁽⁶⁾

10.1(d)		Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Atlas Resource Partners, L.P., dated as of October 2, 2014⁽⁷⁾

10.1(e)		Amendment No. 4 to Amended and Restated Agreement of Limited Partnership of Atlas Resource Partners, L.P., dated as of November 3, 2014⁽²⁾

10.1(f)		Amendment No. 5 to Amended and Restated Agreement of Limited Partnership of Atlas Resource Partners, L.P.⁽²⁹⁾

10.2		Atlas Resource Partners, L.P. Certificate of Designation of the Powers, Preferences and Relative, Participating, Optional and Other Special Rights and Qualifications, Limitations and Restrictions thereof of Class B Preferred Units, dated as of June 25, 2012⁽⁵⁾

10.3		Atlas Resource Partners, L.P. Certificate of Designation of the Powers, Preferences and Relative, Participating, Optional and Other Special Rights and Qualifications, Limitations and Restrictions thereof of Class C Convertible Preferred Units, dated as of July 31, 2013⁽⁶⁾

10.4		Atlas Resource Partners, L.P. Certificate of Designation of the Powers, Preferences and Relative, Participating, Optional, and Other Special Rights and Qualifications, Limitations and Restrictions thereof of Class D Preferred Units, dated as of October 2, 2014⁽⁷⁾

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10.5		Atlas Energy Group, LLC 2015 Long-Term Incentive Plan⁽²⁸⁾

10.6		Form of Phantom Unit Grant under Atlas Energy Group, LLC 2015 Long-Term Incentive Plan⁽¹⁴⁾

10.7		Form of Phantom Unit Grant Agreement for Non-Employee Directors under Atlas Energy Group, LLC 2015 Long-Term Incentive Plan⁽¹⁴⁾

10.8		Form of Option Grant Agreement under Atlas Energy Group, LLC 2015 Long-Term Incentive Plan⁽¹⁴⁾

10.9		Atlas Energy Group, LLC Annual Incentive Plan for Senior Executives⁽²⁸⁾

10.10(a)		Second Amended and Restated Credit Agreement dated July 31, 2013 among Atlas Resource Partners, L.P., the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent for the lenders⁽⁶⁾

10.10(b)		First Amendment to Second Amended and Restated Credit Agreement dated December 6, 2013 among Atlas Resource Partners, L.P., the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent for the lenders⁽⁹⁾

10.10(c)		Third Amendment to Second Amended and Restated Credit Agreement dated June 30, 2014 among Atlas Resource Partners, L.P., the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent for the lenders⁽¹⁰⁾

10.10(d)		Fourth Amendment to Second Amended and Restated Credit Agreement dated September 24, 2014 among Atlas Resource Partners, L.P., the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent for the lenders⁽¹¹⁾

10.10(e)		Fifth Amendment to Second Amended and Restated Credit Agreement dated November 24, 2014 among Atlas Resource Partners, L.P., the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent for the lenders⁽¹²⁾

10.10(f)		Sixth Amendment to Second Amended and Restated Credit Agreement dated February 23, 2015 among Atlas Resource Partners, L.P., the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent for the lenders⁽³⁰⁾

10.11		Secured Hedge Facility Agreement dated as of March 5, 2012 among Atlas Resources, LLC, the participating partnerships from time to time party thereto, the hedge providers from time to time party thereto and Wells Fargo Bank, N.A., as collateral agent for the hedge providers⁽¹³⁾

10.12		Atlas Resource Partners, L.P. 2012 Long-Term Incentive Plan⁽³⁾

10.13		Registration Rights Agreement, dated as of July 25, 2012, among Atlas Resource Partners, L.P. and the various parties listed therein⁽⁵⁾

10.14		Registration Rights Agreement, dated as of January 23, 2013 among Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation and the Initial Purchasers named therein⁽¹⁸⁾

10.15		Warrant to Purchase Atlas Resource Partners, L.P. Common Units⁽⁶⁾

10.16		Class C Preferred Unit Purchase Agreement, dated as of June 9, 2013, between Atlas Resource Partners, L.P. and Atlas Energy, L.P.⁽¹⁹⁾

10.17(a)		Indenture dated as of July 30, 2013, by and between Atlas Resource Escrow Corporation and Wells Fargo Bank, National Association⁽²⁰⁾

10.17(b)		Supplemental Indenture dated as of July 31, 2013, by and among Atlas Resource Partners, L.P., Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, the guarantors named therein and Wells Fargo Bank, National Association⁽²⁰⁾

10.17(c)		Second Supplemental Indenture dated as of October 14, 2014, by and among Atlas Resource Partners, L.P., Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, the guarantors named therein and Wells Fargo Bank, National Association⁽²²⁾

10.18(a)		Indenture dated as of January 23, 2013 among Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, Atlas Resource Partners, L.P., the subsidiaries named therein and U.S. Bank National Association⁽¹⁸⁾

10.18(b)		Supplemental Indenture dated as of June 2, 2014, by and among Atlas Resource Partners, L.P., Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, the subsidiary guarantors named therein and U.S. Bank, National Association⁽²¹⁾

212


10.19		Registration Rights Agreement dated as of July 31, 2013, by and among Atlas Resource Partners, L.P., Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, the guarantors named therein and Deutsche Bank Securities, Inc., for itself and on behalf of the Initial Purchasers⁽²⁰⁾

10.20		Registration Rights Agreement dated as of June 2, 2014, by and among Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, the guarantors named therein and Wells Fargo Securities, LLC and Deutsche Bank Securities, Inc.⁽²¹⁾

10.21		Registration Rights Agreement dated as of July 31, 2013 by and among Atlas Energy, L.P. and Atlas Resource Partners⁽⁶⁾

10.22		Amended and Restated Registration Rights Agreement, dated as of July 31, 2013, between Atlas Resource Partners, L.P., Wells Fargo Bank, National Association and the lenders named in the Amended and Restated Credit Agreement dated July 31, 2013 by and among Atlas Energy, L.P. and the lenders named therein⁽²⁹⁾

10.23		Registration Rights Agreement dated as of October 14, 2014, by and among Atlas Resource Partners, L.P., Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, the guarantors named therein and Wells Fargo Securities, LLC⁽²³⁾

10.24		Purchase and Sale Agreement, dated as of May 6, 2014, by and among Merit Management Partners I, L.P., Merit Energy Partners III, L.P., Merit Energy Company, LLC, ARP Rangely Production, LLC and Atlas Resource Partners, L.P., as Guarantor. The exhibits and schedules to the Purchase and Sale Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted exhibits and schedules will be furnished to the U.S. Securities and Exchange Commission upon request.⁽²⁴⁾

10.25		Purchase and Sale Agreement, dated as of September 24, 2014, by and among Cinco Resources, Inc., Cima Resources, LLC, ARP Eagle Ford, LLC, Atlas Growth Eagle Ford, LLC and Atlas Resource Partners, L.P. The schedules to the Purchase and Sale Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted exhibits and schedules will be furnished to the U.S. Securities and Exchange Commission upon request.⁽¹¹⁾

10.26		First Amendment to Purchase and Sale Agreement dated October 27, 2014, by and between Cinco Resources, Inc., Cima Resources, LLC, ARP Eagle Ford, LLC, Atlas Growth Eagle Ford, LLC and Atlas Resource Partners, L.P.⁽²⁷⁾

10.27		Shared Acquisition and Operating Agreement, dated as of September 24, 2014, by and among ARP Eagle Ford, LLC and Atlas Growth Eagle Ford, LLC and Atlas Resource Partners, L.P. The schedules to the Shared Acquisition and Operating Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted exhibits and schedules will be furnished to the U.S. Securities and Exchange Commission upon request.⁽¹¹⁾

10.28		Distribution Agreement dated as of August 29, 2014, between Atlas Resource Partners, L.P. and Deutsche Bank Securities Inc., as representative of the several agents.⁽²⁵⁾

10.29		Second Lien Credit Agreement dated as of February 23, 2015, among Atlas Resource Partners, L.P., the lenders party thereto and Wilmington Trust, National Association, as administrative agent.⁽³⁰⁾

10.30		Credit Agreement dated as of February 27, 2015 among Atlas Energy Group, LLC, New Atlas Holdings, LLC, Deutsche Bank AG New York Branch, as administrative agent, and the lenders party thereto.⁽²⁸⁾

10.31		Series A Preferred Unit Purchase Agreement by and among Atlas Energy Group, LLC and the purchasers signatory thereto. ⁽²⁸⁾

10.32		Registration Rights Agreement by and among Atlas Energy Group, LLC and the purchasers signatory thereto.⁽²⁸⁾

21.1		Subsidiaries of Atlas Energy Group, LLC

23.1		Consent of Grant Thornton LLP

23.2		Consent of Wright and Company, Inc.

23.3		Consent of Cawley, Gillespie, and Associates, Inc.

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31.1		Rule 13(a)-14(a)/15(d)-14(a) Certification

31.2		Rule 13(a)-14(a)/15(d)-14(a) Certification

32.1		Section 1350 Certification

32.2		Section 1350 Certification

99.1		Summary Reserve Report of Wright & Company, Inc. (Arkoma assets) ⁽³¹⁾

99.2		Atlas Resource Partners, L.P. Summary Reserve Report of Wright & Company, Inc.⁽²⁹⁾

99.3		Rangely Summary Reserve Report of Cawley, Gillespie, and Associates. Inc.⁽²⁹⁾

⁽¹⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s Registration Statement on Form 10, as amended (File No. 1-35317).

⁽²⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on November 5, 2014.

⁽³⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended September 30, 2013.

⁽⁴⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on March 14, 2012.

⁽⁵⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on July 26, 2012.

⁽⁶⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on August 6, 2013.

⁽⁷⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-A filed on October 2, 2014.

⁽⁸⁾	Previously filed as an exhibit to Atlas Energy, L.P.’s quarterly report on Form 10-Q for the quarter ended March 31, 2011.

⁽⁹⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s annual report on Form 10-K for the year ended December 31, 2013.

⁽¹⁰⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on July 2, 2014.

⁽¹¹⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on September 30, 2014.

⁽¹²⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on November 25, 2014.

⁽¹³⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on March 7, 2012.

⁽¹⁴⁾	Previously filed as an exhibit to our Registration Statement on Form 10, as amended (File No. 1-36725).

⁽¹⁵⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on December 26, 2012.

⁽¹⁶⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on January 11, 2013.

⁽¹⁷⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on May 31, 2013.

⁽¹⁸⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on January 25, 2013.

⁽¹⁹⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on June 13, 2013.

⁽²⁰⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on August 2, 2013.

⁽²¹⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on June 3, 2014.

⁽²²⁾	Previously filed as an exhibit to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2012.

⁽²³⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on October 15, 2014.

⁽²⁴⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on May 7, 2014.

⁽²⁵⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on August 29, 2014.

⁽²⁶⁾	[Intentionally Omitted]

⁽²⁷⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on November 6, 2014.

⁽²⁸⁾	Previously filed as an exhibit to our current report on Form 8-K filed on March 2, 2015.

⁽²⁹⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2014.

⁽³⁰⁾	Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on February 23, 2015.

⁽³¹⁾	Previously filed as an exhibit to Atlas Energy, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2014.

214

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities indicated as of March 27, 2015.


/s/ EDWARD E. COHEN		Chief Executive Officer, President and Director
Edward E. Cohen

/s/ JONATHAN Z. COHEN		Executive Chairman of the Board
Jonathan Z. Cohen

/s/ SEAN P. MCGRATH		Chief Financial Officer
Sean P. McGrath

/s/ JEFFREY M. SLOTTERBACK		Chief Accounting Officer
Jeffrey M. Slotterback

/s/ MARK C. BIDERMAN		Director
Mark C. Biderman

/s/ DEANN CRAIG		Director
DeAnn Craig

/s/ DENNIS A. HOLTZ		Director
Dennis A. Holtz

/s/ WALTER C. JONES		Director
Walter C. Jones

/s/ JEFFREY F. KUPFER		Director
Jeffrey F. Kupfer

/s/ ELLEN F. WARREN		Director
Ellen F. Warren

215

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company