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, 2011

OR

 

¨	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: 001-32953

 

 

ATLAS ENERGY, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware		43-2094238
(State or other jurisdiction or incorporation or organization)		(I.R.S. Employer Identification No.)
Park Place Corporate Center One 1000 Commerce Drive, 4th Floor Pittsburgh, PA		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

Title of class

 

 

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

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  x    No  ¨

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.  ¨

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):

 

Large accelerated filer		x		Accelerated filer		¨
Non-accelerated filer		¨		Smaller reporting company		¨

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 voting common stock held by non-affiliates of the registrant, based on the closing price of such stock on the last business day of the registrant’s most recently completed second quarter, June 30, 2011, was approximately $1.1 billion.

The number of outstanding shares of the registrant’s common stock on February 22, 2012 was 51,297,814 shares.

 

 

DOCUMENTS INCORPORATED BY REFERENCE: None

 

 

 

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K

TABLE OF CONTENTS

 

						Page
PART I		Item 1:		Business			7
		Item 1A:		Risk Factors			22
		Item 1B:		Unresolved Staff Comments			43
		Item 2:		Properties			44
		Item 3:		Legal Proceedings			47
		Item 4:		(Removed and Reserved)			47
PART II		Item 5:		Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities			47
		Item 6:		Selected Financial Data			48
		Item 7:		Management’s Discussion and Analysis of Financial Condition and Results of Operations			50
		Item 7A:		Quantitative and Qualitative Disclosures about Market Risk			72
		Item 8:		Financial Statements and Supplementary Data			75
		Item 9:		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			122
		Item 9A:		Controls and Procedures			122
		Item 9B:		Other Information			125
PART III		Item 10:		Directors, Executive Officers and Corporate Governance			125
		Item 11:		Executive Compensation			132
		Item 12:		Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters			158
		Item 13:		Certain Relationships and Related Transactions, and Director Independence			160
		Item 14:		Principal Accountant Fees and Services			161
PART IV		Item 15:		Exhibits and Financial Statement Schedules			162
SIGNATURES							167

 

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GLOSSARY OF TERMS

Definitions of terms and acronyms generally used in the energy industry and in this report are as follows:

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.

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

Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

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 an NGL 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.

MLP. Master Limited Partnership.

MMBtu. One million British thermal units.

 

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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.

Oil. Crude oil and condensate.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved reserves. Proved oil and gas reserves are those quantities of oil and gas that by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves or PUDs. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for undeveloped reserves cannot be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

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 economically productive oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Residue gas. The portion of natural gas remaining after natural gas is processed for removal of NGLs and impurities.

SEC. Securities 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

 

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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 within this report include forward-looking statements. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” 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:

 

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

 

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

 

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Atlas Pipeline Partners, L.P.’s (“APL”) ability to connect new wells to its gathering systems;

 

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changes in the market price of our common units;

 

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future financial and operating results;

 

•

economic conditions and instability in the financial markets;

 

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resource potential;

 

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realized natural gas and oil prices;

 

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

 

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the accuracy of estimated natural gas and oil reserves;

 

•

the financial and accounting impact of hedging transactions;

 

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

 

•

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

 

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•

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 indebtedness of us and APL that may adversely affect operational flexibility;

 

•

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

 

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

 

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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;

 

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the introduction of Pennsylvania severance tax or impact fee;

 

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

 

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

 

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general market, labor and economic conditions and related uncertainties;

 

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the ability to retain certain key customers;

 

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dependence on the gathering and transportation facilities of third parties;

 

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the availability of drilling rigs, equipment and crews;

 

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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;

 

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

 

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expirations of undeveloped leasehold acreage;

 

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

 

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

 

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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 APL’s business and operations;

 

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exposure to new and existing litigations;

 

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

 

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development of alternative energy resources.

Other factors that could cause actual results to differ from those implied by the forward-looking statements in this report are more fully described under “Item 1A: Risk Factors” in this report. Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this report are made only as of the date hereof. 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.

 

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PART I

 

ITEM 1:

BUSINESS

General

We are a publicly-traded Delaware limited partnership, formerly known as Atlas Pipeline Holdings, L.P. (NYSE: ATLS), whose common units are listed on the New York Stock Exchange under the symbol “ATLS”. We are an independent developer and producer of natural gas and oil, with operations in the Appalachian Basin, Illinois Basin and the Rocky Mountain region. We sponsor and manage tax-advantaged investment partnerships, in which we co-invest, to finance a portion of our natural gas and oil production activities. Our goal is to increase the distributions to our unitholders by continuing to grow the net production from our natural gas and oil production business as well as the fee-based revenues from our partnership management business.

On February 17, 2011, we acquired certain assets and liabilities (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of our general partner. These assets principally included the following:

 

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

 

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proved reserves located in the Appalachia 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;

 

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certain producing natural gas and oil properties, upon which we are developers and producers;

 

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all of the ownership interests in Atlas Energy GP, LLC, our general partner; and

 

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a direct and indirect ownership interest in Lightfoot LP and Lightfoot GP (collectively, “Lightfoot”), which incubates new MLPs and invest in existing MLPs. At December 31, 2011, we had an approximate 16% general partner interest and 12% limited partner interest in Lightfoot.

Concurrent with our acquisition of the Transferred Business, AEI completed its merger with Chevron Corporation (“Chevron”), whereby AEI became a wholly owned subsidiary of Chevron.

As of December 31, 2011, our principal development and production assets consisted of:

 

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working interests in approximately 8,500 gross producing natural gas and oil wells;

 

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overriding royalty interests in over 500 gross producing natural gas and oil wells;

 

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net daily production of 35.9 Mmcfed for the twelve months ended December 31, 2011;

 

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proved reserves of 167.6 Bcfe at December 31, 2011; and

 

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our partnership management business, which includes equity interests in 98 investment partnerships and a registered broker-dealer that acts as the dealer-manager of our investment partnership offerings.

In addition to our natural gas and oil development and production operations, we maintain an ownership interest in Atlas Pipeline Partners, L.P. (“APL”), a publicly traded Delaware limited partnership (NYSE: APL) and midstream energy service provider. APL is a leading provider of natural gas gathering, processing and treating services in the Anadarko and Permian Basins located in the southwestern and mid-continent regions of the United States; a provider of natural gas gathering services in the Appalachian Basin in the northeastern region of the United States; and a provider of NGL transportation services in the southwest region of the United States. At December 31, 2011, we owned a 2% general partner interest, all of the incentive distribution rights, and an approximate 10.7% common limited partner interest. Please see our further discussion of these ownership interests under “Interests in APL.”

Our operations include four reportable operating segments: gas and oil production, well construction and completion, other partnership management and APL.

 

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Business Strategy

The key elements of our business strategy are:

Expand our natural gas and oil production. We generate a significant portion of our revenue and net cash flow from natural gas and oil production. We believe our program of sponsoring investment partnerships to exploit our acreage opportunities provides us with enhanced economic returns. For the five year period ended December 31, 2011, we raised over $1.4 billion from outside investors through our investment partnerships. We intend to continue to finance the majority of our drilling and production activities through our investment partnerships.

Expand our fee-based revenue through our sponsorship of investment partnerships. We generate substantial revenue and cash flow from fees paid by the investment partnerships to us for acting as the managing general partner. As we continue to sponsor investment partnerships, we expect that our fee revenues from our drilling and operating agreements with our investment partnerships will increase. We expect that the fee revenue we generate with respect to fees paid by the investment partnerships to us for partnership management will add stability to our revenue and cash flows. Furthermore, the carried interests and fees we earn reduce the net investment in our drilling program and therefore enhance our rates of return on investment.

Expand operations through strategic acquisitions. We continually evaluate opportunities to expand our operations through acquisitions of developed and undeveloped properties or companies that can increase our cash available for distribution. We will continue to seek strategic opportunities in our current areas of operation, as well as other regions of the United States.

Continue to maintain control of operations and costs. We believe it is important to be the operator of wells in which we or our investment partnerships have an interest because we believe it will allow us to achieve operating efficiencies and control costs. As operator, we are better positioned to control the timing and plans for future enhancement and exploitation efforts, costs of enhancing, drilling, completing and producing the well, and marketing negotiations for our natural gas and oil production to maximize both volumes and wellhead price. We were the operator of the vast majority of the properties in which we or our investment partnerships had a working interest at December 31, 2011.

Continue to manage our exposure to commodity price risk. To limit our exposure to changing commodity prices, we use financial hedges for a portion of our natural gas and oil production. We principally use fixed price swaps and collars as the mechanism for the financial hedging of our commodity prices.

Competitive Strengths

We believe our competitive strengths favorably position us to execute our business strategy and to maintain and grow our distributions to unitholders. Our competitive strengths are:

Our partnership management business can improve the economic rates of return associated with our natural gas and oil production activities. A well drilled, net to our equity interest, in our partnership management business will provide us with an enhanced rate of return. For each well drilled in a partnership, we receive an upfront 15% to 18% markup on the investors’ well construction and completion costs and a fixed administration and oversight fee of $15,000 to $250,000. Further, we receive an approximate 5% to 10% incremental equity interest in each well, for which we do not make any corresponding capital contribution. Consequently, our economic interest in each well is significantly greater than our proportional contribution to the total cash costs which enhances our overall rate of return. Additionally, we receive monthly per well fees from the partnership for the life of each individual well, which also increases our rate of return.

Fee-based revenues from our investment partnerships provide a stable foundation for our distributions. Our investment partnerships provide us with stable, fee-based revenues which diminish the influence of commodity price fluctuations on our cash flows. Our fees for managing our investment partnerships accounted for approximately 41% of our segment margin in the twelve months ended December 31, 2011. In addition, because our investment partnerships reimburse us on a cost-plus basis for drilling capital expenses, we are partially protected against increases in drilling costs.

We are one of the leading sponsors of tax-advantaged investment partnerships. We have sponsored limited and general partnerships to raise funds from investors to finance our development drilling activities since 1968, and we believe that we are one of the leading sponsors of such investment partnerships in the country. We believe that our lengthy association with many of the broker-dealers that act as placement agents for our investment partnerships provide us with a competitive advantage over entities with similar operations. We also believe that our sponsorship of investment partnerships has allowed us to generate attractive returns on drilling, operating and production activities.

 

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We have a high quality, long-lived reserve base. Our natural gas properties are located principally in the Appalachian Basin and are characterized by long-lived reserves, favorable pricing for our production and readily available transportation. Moreover, because our production in the Appalachian Basin is located near markets in the northeast United States, we believe we will generally receive a premium over quoted prices on the NYMEX for the natural gas we produce.

We have significant experience in making accretive acquisitions. Our management team has extensive experience in consummating accretive acquisitions. We believe we will be able to generate acquisition opportunities of both producing and non-producing properties through our management’s extensive industry relationships. We intend to use these relationships and experience to find, evaluate and execute on acquisition opportunities.

We have significant engineering, geologic and management experience. Our technical team of geologists and engineers has extensive industry experience. We believe that we have been one of the most active drillers in our core operating areas and, as a result, that we have accumulated extensive geological and geographical knowledge about the area. We have also recently added geologists and engineers to our technical staff that have significant experience in other productive basins within the continental United States, which will allow us to evaluate and possibly expand our core operating areas.

Subsequent Events

Formation of Atlas Resource Partners, L.P. In February 2012, our General Partner’s board of directors approved the formation of a newly created exploration and production master limited partnership named Atlas Resource Partners, L.P. (“ARP”), which will hold substantially all of our current natural gas and oil development and production assets and the partnership management business. Our General Partner’s board of directors also approved the distribution of approximately 5.24 million ARP common units, which will be distributed on March 13, 2012 to our unitholders using a ratio of 0.1021 ARP limited partner units for each of our common units owned on the record date of February 28, 2012. The distribution of ARP limited partner units will represent an approximate 19.6% limited partner interest. Subsequent to the distribution, we will own a 2% general partner interest, all of the incentive distribution rights in ARP and common units representing an approximate 78.4% limited partner interest in ARP. For a further description of ARP’s cash distribution policy, please see “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations - Cash Distributions”.

Geographic and Geologic Overview

Over the last decade, the energy industry in the United States has seen tremendous growth due to advancements in the technology to extract natural gas and oil from conventional and unconventional resource plays, which has made such extraction more economically attractive.

Our proved reserves, both developed and undeveloped, are concentrated in the following areas:

Appalachian Basin Overview. The Appalachian Basin includes the states of Kentucky, Maryland, New York, Ohio, Pennsylvania, Virginia, West Virginia and Tennessee. It is the most mature oil and natural gas producing region in the United States, having established the first oil production in 1860. Because the Appalachian Basin is located near the leading energy-consuming regions of the mid-Atlantic and northeastern United States, Appalachian producers have historically sold their natural gas at a premium to the benchmark price for natural gas on the NYMEX. For the year ended December 31, 2011, the average premium over NYMEX for natural gas delivered to our primary delivery points in the Appalachian Basin was $0.36 per million British thermal units (“MMBtu”). In addition, Appalachian natural gas production has the advantage of a high energy content, ranging from 1.00 to 1.11 dekatherms (“Dth”) per Mcf. The majority of our existing natural gas sales contracts yield upward adjustments from index based pricing for throughput with an energy content above 1.0 Dth per Mcf. This higher energy content resulted in realized premiums averaging 1.05% over normal pipeline quality natural gas for the year ended December 31, 2011.

Historically, producers in the Appalachian Basin developed oil and natural gas from shallow sandstones with low permeability which are prevalent in the region. These shallow wells are characterized by modest initial volumes, low pressures, and high initial decline rates followed by low annual decline rates. Almost all of these wells were drilled vertically and usually produce for 30 years or more. Shallow sandstone formations in the Appalachian Basin are typically homogenous and have a high degree of step-out development success. The primary shallow pay zones are shallow sandstones in the Upper Devonian Shale formation. As the step-out development progresses, reserves from newly completed wells are reclassified from proved undeveloped to proved developed and additional adjacent locations are added to proved undeveloped reserves. As a result, the cumulative amount of total proved reserves tends to increase as development progresses. Traditional shallow wells in the Appalachian Basin generally produce little or no water, contributing to a low cost of operation. In addition, most wells produce dry natural gas, which does not require processing.

 

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In recent years, our predecessors and other operators have targeted the Marcellus Shale for development activity. The Marcellus Shale is a black, organic rich shale formation located at depths between 6,000 and 8,500 feet and ranges in thickness from 75 to 150 feet. As of December 31, 2011, we had an interest in Pennsylvania in approximately 221 wells, consisting of 207 vertical wells and 14 horizontal wells. An additional 24 wells, consisting of eight vertical wells and 16 horizontal wells, have been completed and are scheduled to be turned on-line during the first half of 2012.

As of December 31, 2011, we have drilled 11 Marcellus Shale wells and will be drilling an additional two Marcellus Shale wells during the first quarter of 2012 in West Virginia, all of which we are drilling through our partnership management business, consisting of seven vertical wells and six horizontal wells. We have maximized the lateral lengths of each of the horizontal wells based on lease boundaries. To date, there have been multiple Marcellus Shale wells drilled near our well sites that have shown strong initial production. Our future drilling activity in portions of the Appalachian Basin located in parts of Pennsylvania, West Virginia and New York will be limited by the terms of the non-competition agreements between certain of Atlas Energy’s officers and directors and Chevron.

Additionally, as of December 31, 2011, we have leased additional Marcellus Shale acreage in Lycoming County, PA. We are currently drilling four additional Marcellus wells on this acreage through our partnership management program and have additional sites available to drill. We anticipate expanding our acreage in Lycoming County, which will give us the ability to drill additional wells.

The Chattanooga Shale is a Devonian-age shale found at a depth of approximately 3,500 feet. We have over 100,000 net undeveloped acres in the Chattanooga Shale in northeastern Tennessee. We operate approximately 425 wells in the region, 421 of which are funded through our investment partnerships and 30 of which are horizontal wells. Based on some recent successes around our leasehold acreage, we plan to drill additional horizontal wells during 2012. We also own two gas processing plants in eastern Tennessee with combined capacity of approximately 35 Mmcf per day, which capacity we believe can be increased.

The Utica Shale is an Ordovician-age shale which lies several thousand feet below the Devonian-age Marcellus Shale. The Utica Shale is much thicker than the Marcellus Shale, and we believe has the potential to become a significant resource play. The Utica Shale begins in eastern Ohio and extends eastward, covering a large portion of Pennsylvania, New York and West Virginia. The Utica Shale has a western oil phase, central wet gas phase and eastern dry gas phase. We currently have an interest in approximately 2,100 wells in Ohio and operate three field offices which we intend to use for future Utica Shale development.

Illinois Basin Overview. The Devonian-age New Albany Shale is a blanket formation found at depths of 500 to 3,000 feet, with thicknesses ranging from 100 to 200 feet. We have a leasehold of over 100,000 net acres in the New Albany Shale in southwestern Indiana located is in the “biogenic gas window.” The natural fracture patterns in the New Albany Shale are vertically oriented, which lends itself to a horizontal drilling approach. As of December 31, 2011, we have an interest in 92 wells in the New Albany Shale, of which we operate 90.

Denver-Julesburg Basin Overview. Within the Denver-Julesburg (“DJ”) Basin, we have primarily focused on the Niobrara Shale, which extends from northeastern Colorado to southern Wyoming into western Nebraska. Our developmental drilling program is focused on the shallow, gas-rich Niobrara in eastern Colorado, western Nebraska, and Kansas. Although natural gas was discovered in the Niobrara Shale in 1919, drilling in the area did not become commercial until the use of fracturing technologies became prevalent in the 1970s and 1980s. Development continued through the 1990s, but drilling success rates in the region were enhanced by the more recent development of 3-D seismic technology. The Niobrara Shale is suitable for conventional drilling of shallow developmental natural gas wells, which are wells drilled in an area of proven reserves to the depth of a horizon known to be productive. The Niobrara Shale presents the potential for efficient drilling, completion and production operations, as well as relatively quick well turn-in-line timeframes and favorable topography.

We are a party to a farm-out agreement with Black Raven Energy covering 178,000 acres located in the Niobrara formation in eastern Colorado and western Nebraska, pursuant to which we pay a per well fee and production royalties to Black Raven. The acreage subject to our farm-out agreement encompasses the development of shallow Niobrara gas wells at about 2,700 feet in depth with site selection based on the identification of 3D seismic structures. We operate 41 wells in the region, all of which were funded through our investment partnerships. We have run 3-D seismic imaging over a portion of the acreage subject to the farm-out agreement, which has identified over 600 potential drilling sites. Along with identifying potential Niobrara Shale drilling sites, the 3-D seismic imaging has allowed us to identify potential drilling sites in the D-Sand located under the Niobrara Shale. The D-Sand is a well-established exploration target in the Denver-Julesberg basin. The 3-D seismic imaging helps limit the potential of drilling dry holes while increasing drilling efficiency.

 

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Gas and Oil Production

Production Volumes

Currently, our natural gas, oil and natural gas liquids production operations are focused in various shale plays in the northeastern and midwestern United States, and include direct interest wells and ownership interests in wells drilled through our drilling partnerships. When we drill new wells through our partnership management business we receive an interest in each investment partnership proportionate to the value of our coinvestment in it and the value of the acreage we contribute to it, typically 15% to 31% of the overall capitalization of a particular partnership. We also receive an incremental interest in each partnership, typically 5% to 10%, for which we do not make any additional capital contribution. Consequently, our equity interest in the reserves and production of each partnership is typically between 20% and 41%. The following table presents our total net natural gas, oil and natural gas liquids production volumes and production per day for the three year period ended December 31, 2011, 2010 and 2009:

 

		Years Ended December 31,
		2011				2010				2009
Production per day:(1)(2)
Natural gas (Mcfd)			31,403				35,855				38,644
Oil (Bpd)			307				373				427
Natural gas liquids (Bpd)			444				499				101
Total (Mcfed)			35,912				41,090				41,814

 

(1)

Production quantities consist of the sum of (i) our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells, and (ii) our proportionate share of production from wells owned by the investment partnerships in which we have an interest, based on our equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells.

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

Production Revenues, Prices and Costs

We market the majority of our natural gas production to gas utility companies, gas marketers, local distribution companies, industrial or other end-users, and companies generating electricity. The sales price of natural gas produced in the Appalachian Basin has been primarily based upon the NYMEX spot market price, the natural gas produced in the New Albany Shale and Antrim Shale has been primarily based upon the Texas Gas Zone SL and Chicago spot market prices, and the gas produced in the Niobrara formation has been primarily based upon the Cheyenne Index. Crude oil produced from our wells flows directly into storage tanks where it is picked up by an oil company, a common carrier or pipeline companies acting for an oil company, which is purchasing the crude oil. We sell any oil produced by our Appalachian wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil. Natural gas liquids are produced by our natural gas processing plants, which extract the natural gas liquids from the natural gas production, enabling the remaining “dry” gas (low BTU content) to meet pipeline specifications for long-haul transport to end users. We sell natural gas liquids produced by our natural gas processing plants to regional refining companies at the prevailing spot market price for natural gas liquids.

Our production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised 94% of our proved reserves on an energy equivalent basis at December 31, 2011. The following table presents our production revenues and average sales prices for our natural gas, oil and natural gas liquids production for the years ended December 31, 2011, 2010 and 2009, along with our average production costs, taxes, and transportation and compression costs in each of the reported periods:

 

		Years Ended December 31,
		2011				2010				2009
Production revenues (in thousands):
Natural gas revenue		$	49,096			$	75,630			$	100,526
Oil revenue			10,057				10,541				11,119
Natural gas liquids revenue			7,826				6,879				1,334
Total revenues		$	66,979			$	93,050			$	112,979

 

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		Years Ended December 31,
		2011				2010				2009
Average sales price:(1)
Natural gas (per Mcf):
Total realized price, after hedge(2)		$	4.98			$	7.08			$	7.54
Total realized price, before hedge(2)		$	4.53			$	4.60			$	4.04
Oil (per Bbl):
Total realized price, after hedge		$	89.70			$	77.31			$	71.34
Total realized price, before hedge		$	89.07			$	71.37			$	57.41
Natural gas liquids (per Bbl) total realized price:		$	48.26			$	37.78			$	36.19
Production costs (per Mcfe):(1)
Lease operating expenses(3)		$	1.06			$	1.27			$	1.10
Production taxes			0.10				0.04				0.03
Transportation and compression			0.46				0.65				0.68
Total		$	1.61			$	1.96			$	1.80

 

(1)	“Mcf” represents thousand cubic feet; “Mcfe” represents thousand cubic feet equivalents; and “Bbl” represents barrels.

(2)

Excludes the impact of subordination of our production revenue to investor partners within our investment partnerships for the years ended December 31, 2011, 2010 and 2009. Including the effect of this subordination, the average realized gas sales prices were $4.28 per Mcf ($3.83 per Mcf before the effects of financial hedging), $5.78 per Mcf ($3.30 per Mcf before the effects of financial hedging) and $7.13 per Mcf ($3.62 per Mcf before the effects of financial hedging) for the years ended December 31, 2011, 2010 and 2009, respectively.

(3)

Excludes the effects of our proportionate share of lease operating expenses associated with subordination of our production revenue to investor partners within our investment partnerships. Including the effects of these costs, total lease operating expenses per Mcfe were $0.75 per Mcfe ($1.30 per Mcfe for total production costs), $0.86 per Mcfe ($1.56 per Mcfe for total production costs) and $0.97 per Mcfe ($1.67 per Mcfe for total production costs) for the years ended December 31, 2011, 2010 and 2009, respectively.

Partnership Management Business

We generally fund our drilling activities through sponsorship of tax-advantaged investment partnerships. Accordingly, the amount of development activities we undertake depends in part upon our ability to obtain investor subscriptions to the partnerships. We generally structure our investment partnerships so that, upon formation of a partnership, we coinvest in and contribute leasehold acreage to it, enter into drilling and well operating agreements with it and become its managing general partner. In addition to providing capital for our drilling activities, our investment partnerships are a source of fee-based revenues, which are not directly dependent on natural gas and oil prices. We receive an interest in the investment partnerships proportionate to the amount of capital and the value of the leasehold acreage that we contribute, which interest is typically 15% to 31% of the overall capitalization in a particular partnership. We also receive an additional interest in each partnership, typically 5% to 10%, for operating the wells and managing the general partner for which we do not make any additional capital contribution. This brings our total interest in the partnerships in a range from 20% to 41%.

Over the last five years, we raised over $1.4 billion from outside investors for participation in our drilling partnerships. Net proceeds from these partnerships are used to fund the investors’ share of drilling and completion costs under our drilling contracts with the partnerships. We recognize revenues from drilling operations on the percentage-of-completion method as the wells are drilled, rather than when funds are received.

Our fund raising activities for sponsored drilling partnerships during the last five years are summarized in the following table (amounts in millions):

 

		Drilling Program Capital
		Investor Contributions				Our Contributions				Total Capital
2011		$	141.9			$	28.3			$	170.2
2010(1)			149.3				53.4				202.7
2009			353.4				97.5				450.9
2008			438.4				146.3				584.7
2007			363.3				137.6				500.9
Total		$	1,446.3			$	463.1			$	1,909.4

 

(1)	Does not include funds raised for a fall 2010 drilling program, which was cancelled due to the announcement of the acquisition of the Transferred Business in November 2010.

 

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As managing general partner of our investment partnerships, we receive the following fees:

 

•

Well construction and completion. For each well that is drilled by an investment partnership, we receive a 15% to 18% mark-up on those costs incurred to drill and complete the well.

 

•

Administration and oversight. For each well drilled by an investment partnership, we receive a fixed fee of between $15,000 and $250,000, depending on the type of well drilled. Additionally, the partnership pays us a monthly per well administrative fee of $75 for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

 

•

Well services. Each partnership pays us a monthly per well operating fee, currently $100 to $1,500 for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

 

•

Gathering. Each royalty owner, partnership and certain other working interest owners pay us a gathering fee, which generally ranges from $0.35 per Mcf to the amount of the competitive gathering fee, currently defined as 13% of the gross sales price of the natural gas. In general, pursuant to gathering agreements we have with a third-party gathering system which gathers the majority of our natural gas, we must also pay an additional amount equal to the excess of the gathering fees collected from the investment partnerships up to an amount equal to approximately 16% of the realized natural gas sales price (adjusted for the settlement of natural gas derivative instruments). As a result, some of our gathering expenses within our partnership management segment, specifically those in the Appalachian Basin, will generally exceed the revenues collected from investment partnerships by approximately 3%.

Our investment partnerships provide tax advantages to our investors because an investor’s share of the partnership’s intangible drilling cost deduction may be used to offset ordinary income. Intangible drilling costs include items that do not have salvage value, such as labor, fuel, repairs, supplies and hauling. Generally, for our investment partnerships that were formed after October 2008, approximately 85% of the subscription proceeds received have been used to pay 100% of the partnership’s intangible drilling costs. For example, an investment of $10,000 generally permits the investor to deduct from taxable ordinary income approximately $8,500 in the year in which the investor invests. For our investment partnerships that were formed prior to October 2008, approximately 90% of the subscription proceeds received were used to pay 100% of the partnership’s intangible drilling costs.

Within our investment partnerships, we have agreed to subordinate a portion of our share of production revenues, net of corresponding production costs, to the investor partners until the partners have received specified returns, typically 10% per year, over a specific period, typically the first five to seven years, as stipulated within the individual investor partnership agreement.

Drilling Activity

The number of wells we drill will vary depending on, among other things, the amount of money we raise through our investment 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 drilled, both gross and for our interest, during the periods indicated. There were no exploratory wells drilled during the years ended December 31, 2011, 2010 and 2009.

 

		Years Ended December 31,
		2011				2010				2009
Gross wells drilled			160				117				267
Our share of gross wells drilled(1)			31				34				68

 

(1)	Includes (i) our percentage interest in the wells in which we have a direct ownership interest and (ii) our percentage interest in the wells based on our percentage interest in our investment partnerships.

We do not operate any of the rigs or related equipment used in our drilling operations, relying instead on specialized subcontractors or joint venture partners for all drilling and completion work. This enables us to streamline our 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 perform regular inspection, testing and monitoring functions on our operated wells.

 

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As of December 31, 2011, we had the following ongoing drilling activities:

 

		Gross												Net
		Spud				Total Depth				Completed				Spud				Total Depth				Completed
Marcellus – Vertical			—				3				1				—				2				1
Marcellus – Horizontal			2				—				—				2				—				—
Chattanooga – Vertical			—				—				—				—				—				—
Chattanooga – Horizontal			—				2				2				—				2				2
Niobrara - Vertical			6				21				32				6				21				32
Ohio – Vertical			—				3				—				—				3				—

Natural Gas and Oil Leases

The typical natural gas and oil lease agreement provides for the payment of royalties to the mineral owner for all natural gas and oil produced from any well(s) drilled on the leased premises. In the Appalachian Basin and Colorado Basin, this amount is typically 1/8^th (12.5%) resulting in a 87.5% net revenue interest to us, and, in Michigan, this amount is typically 1/6^th (16.67%) resulting in an 83.3% net revenue interest to us. In certain instances, this royalty amount may increase to 1/6^th in the Appalachian Basin and to 3/16^th (18.75%) in Michigan when leases are taken from larger landowners or mineral owners such as coal and timber companies.

In almost all of the areas we operate in the Appalachian Basin, Colorado, Indiana and Michigan, the surface owner is normally the natural gas and oil owner allowing us to deal with a single owner. This simplifies the research process required to identify the proper owners of the natural gas and oil rights and reduces the per acre lease acquisition cost and the time required to successfully acquire the desired leases.

Because the acquisition of natural gas and oil leases is a very competitive process, and involves certain geological and business risks to identify productive areas, prospective leases are often held by other natural gas and oil operators. In order to gain the right to drill these leases, we may elect to farm-in leases and/or purchase leases from other natural gas and oil operators. Typically the assignor of such leases will reserve an overriding royalty interest, ranging in the Appalachian Basin and Colorado from 1/32^nd to 1/16^th (3.125% to 6.25%), which further reduces the net revenue interest available to us to between 84.375% and 81.25%, and in Michigan from 3.33% to 5.33%, which further reduces the net revenue interest available to us to between 80.0% and 78.0%.

The interests in some of our operated properties and of natural gas and oil leases retain the option to participate in the drilling of wells on leases farmed out or assigned to us for a retained working interest of up to 50% of the wells drilled on the covered acreage. In this event, our working interest ownership will be reduced by the amount retained by the third party. In all other instances, we anticipate owning a 100% working interest in newly drilled wells.

Contractual Revenue Arrangements

Natural Gas. We market the majority of our natural gas production to gas utility companies, gas marketers, local distribution companies, industrial or other end-users, and companies generating electricity. The sales price of natural gas produced in the Appalachian Basin has been primarily based upon the NYMEX spot market price, the natural gas produced in the New Albany Shale and Antrim Shale has been primarily based upon the Texas Gas Zone SL and Chicago spot market prices, and the gas produced in the Niobrara formation has been primarily based upon the Cheyenne Index. For the year ended December 31, 2011, Chevron, South Jersey Resources Group and Sequent Energy Management accounted for approximately 17%, 14% and 10% of our total natural gas and oil production revenues, respectively, with no other single customer accounting for more than 10% for this period.

Crude Oil. Crude oil produced from our wells flows directly into storage tanks where it is picked up by an oil company, a common carrier or pipeline companies acting for an oil company, which is purchasing the crude oil. We sell any oil produced by our Appalachian wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil.

Natural Gas Liquids. Natural gas liquids are produced by our natural gas processing plants, which extract the natural gas liquids from natural gas production, enabling the remaining “dry” gas (low BTU content) to meet pipeline specifications for long-haul transport to end users. We sell natural gas liquids produced by our natural gas processing plants to regional refining companies at the prevailing spot market price for natural gas liquids.

 

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We do not have delivery commitments for fixed and determinable quantities of natural gas or oil in any future periods under existing contracts or agreements.

Investment Partnerships. We generally fund our drilling activities through sponsorship of tax-advantaged investment partnerships. In addition to providing capital for our drilling activities, our investment partnerships are a source of fee-based revenues, which are not directly dependent on natural gas and oil prices. See “Partnership Management Business” for further discussion.

Natural Gas and Oil Hedging

We seek to provide greater stability in our cash flows through our use of financial hedges. 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 ourselves and counterparties and do not require physical delivery of hydrocarbons. Financial hedges allow us 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 secured credit facility do not require cash margin and are secured by our 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 have a management committee to assure that all financial trading is done in compliance with our hedging policies and procedures. We do not intend to contract for positions that we cannot offset with actual production.

Natural Gas Gathering Agreements

We are party to two natural gas gathering agreements with Laurel Mountain Midstream, LLC (“Laurel Mountain”), in which APL formerly owned a 49% interest: (1) a Gas Gathering Agreement for Natural Gas on the Legacy Appalachian System with respect to the existing gathering systems and expansions to it (the “Legacy Agreement”) and (2) a Gas Gathering Agreement for Natural Gas on the Expansion Gathering System with respect to other gathering systems constructed within the specified area of mutual interest (the “Expansion Agreement” and, collectively with the Legacy Agreement, the “Gathering Agreements”). Under the Gathering Agreements, we dedicate our natural gas production in certain areas within the Appalachian Basin to Laurel Mountain for transportation to interstate pipeline systems, local distribution companies, and/or end users in the area, subject to certain exceptions. In return, Laurel Mountain is required to accept and transport our dedicated natural gas in the Appalachian Basin subject to certain conditions.

Under the Gathering Agreements, we are required to pay a gathering fee to Laurel Mountain that is the greater of $0.35 per mcf or 16% of the gross sales price except that a lower fee applies with respect to specific wells subject to existing contracts calling for lower minimum gathering fees and if Laurel Mountain fails to perform specified obligations. In addition, if an investment partnership pays a lesser competitive gathering fee for the natural gas it transports using Laurel Mountain’s gathering system, which currently is 13% of the gross sales price, then we, and not the partnership, will have to pay the difference to Laurel Mountain.

The Gathering Agreements require that, to the extent that we own wells or propose wells that are within 2,500 feet of Laurel Mountain’s gathering system, we must at our cost construct up to 2,500 feet of flowline as necessary to connect the wells to the gathering system. For wells more than 2,500 feet from Laurel Mountain’s gathering system, if we construct a flow line to within 1,000 feet of Laurel Mountain’s gathering system, then Laurel Mountain must, at its own cost, extend its gathering system to connect to such flowline.

The Gathering Agreements remain in effect so long as gas from our wells is produced in economic quantities without lapse of more than 90 days.

Availability of Oil Field Services

We contract for drilling rigs and purchase goods and services necessary for the drilling and completion of wells from a number of drillers and suppliers, none of which supplies a significant portion of our annual needs. During the years ended December 31, 2011 and 2010, we faced no shortage of these goods and services. Over the past several years, we and other oil and natural gas companies have experienced higher drilling and operating costs. We cannot predict the duration or stability of the current level of supply and demand for drilling rigs and other goods and services required for our operations with any certainty due to numerous factors affecting the energy industry, including the demand for natural gas and oil.

 

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We maintain certain agreements pursuant to which subsidiaries of Chevron have agreed to provide certain specified operational services for a limited period of time, including:

 

•

Pennsylvania Operating Services Agreement. Pursuant to this agreement, a subsidiary of Chevron provides us (including drilling partnerships which we manage) with certain operational services including, among other things, gas volumetric control, measurement and balancing services and water disposal services with respect to certain wells in Pennsylvania in exchange for specified fees. We will indemnify the provider against all claims and liabilities arising out of its provision of services under this agreement. We may terminate the agreement or any portion of the services provided under the agreement at any time, and either party may terminate the agreement following an uncured material breach of the agreement by the other party. The initial term of this agreement will expire on February 17, 2014. The agreement may continue from month to month thereafter, subject to the right of either party to cancel the agreement at any time following the expiration of the initial term.

 

•

Petro-Technical Services Agreement. Pursuant to this agreement, a subsidiary of Chevron provides us with certain consulting services including, among others, planning, designing, drilling, stimulating, completing and equipping wells, in exchange for a payment in the amount of the actual costs of providing such services, up to a maximum of the market rate for the same or similar services in Pittsburgh, Pennsylvania or Traverse City, Michigan, depending on the location of the well. We will indemnify the provider against all claims and liabilities arising out of its provision of services under this agreement. The agreement remained in place at December 31, 2011.

Competition

The energy industry is intensely competitive in all of its aspects. We operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital through our investment partnerships, contracting for drilling equipment and securing trained personnel. We also compete with the exploration and production divisions of public utility companies for natural gas and oil property acquisitions. Competition is intense for the acquisition of leases considered favorable for the development of natural gas and oil in commercial quantities. Our competitors may be able to pay more for natural gas and oil properties and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. 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. Product availability and price are the principal means of competition in selling natural gas, oil, and natural gas liquids.

Many of our competitors possess greater financial and other resources which may enable them to identify and acquire desirable properties and market their natural gas and oil production more effectively than we do. Moreover, we also compete with a number of other companies that offer interests in investment partnerships. As a result, competition for investment capital to fund investment partnerships is intense.

Markets

The availability of a ready market for natural gas, oil and natural gas liquids 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 natural gas, oil and natural gas liquids. During the years ended December 31, 2011, 2010 and 2009, we did not experience problems in selling our natural gas, oil and natural gas liquids, although prices have varied significantly during those periods.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas of the Appalachian region and Michigan/Indiana. These seasonal anomalies may pose challenges for meeting our well construction objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay our operations. We have in the past drilled a greater number of wells during the winter months, because we have typically received the majority of funds from investment partnerships during the fourth calendar quarter. 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.

 

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Environmental Matters and Regulation

Overview. Our operations are subject to comprehensive and stringent federal, state and local laws and regulations governing, among other things, where and how we install wells, how we handle wastes from our operations and the discharge of materials into the environment. Our operations will be subject to the same environmental laws and regulations as other companies in the natural gas and oil industry. Among other requirements and restrictions, these laws and regulations:

 

•

require the acquisition of various permits before drilling commences;

 

•

require the installation of expensive pollution control equipment and water treatment facilities;

 

•

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

 

•

limit or prohibit drilling activities on lands lying within or, in some cases, adjoining wilderness, wetlands and other protected areas;

 

•

require remedial measures to reduce, mitigate or respond to releases of pollutants or hazardous substances from former operations, such as pit closure and plugging of abandoned wells;

 

•

impose substantial liabilities for pollution resulting from our operations; and

 

•

with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.

These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently enact new, and revise existing, environmental laws and regulations, and any new laws or changes to existing laws that result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs. We believe that our operations substantially comply with all currently applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict how environmental laws and regulations that may take effect in the future may impact our properties or operations. For the three-year period ended December 31, 2011, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. We are not aware of any environmental issues or claims that will require material capital expenditures during 2012, or that will otherwise have a material impact on our financial position or results of operations.

Environmental laws and regulations that could have a material impact on the natural gas and oil exploration and production industry 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 impact 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 proposed exploration and production activities on federal lands 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 the Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. Under the auspices of the EPA, 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 the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation.

 

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We believe that our 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 our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes to be significant, any more stringent regulation of natural gas and oil exploitation and production wastes could increase our costs to manage and dispose of such wastes.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or 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 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 we utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us or on or under other locations, including off-site locations, where such substances have been taken for disposal. 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, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, into navigable waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state. These permits may require pretreatment of produced waters before discharge. Compliance with such permits and requirements may be costly. Further, much of our 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. 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 our business and operations.

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 our operations are in substantial compliance with the requirements of the Clean Water Act.

Air Emissions. The Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through permits and other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic and other air pollutants at specified sources. Specific federal regulations applicable to the natural gas industry have been proposed under the New Source Performance Standards (“NSPS”) program along with National Emissions Standards for Hazardous Air Pollutants (“NESHAP”s). Final NSPS and NESHAP rules are anticipated in the spring of 2012 and will likely impose additional emissions control requirements and practices on our 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 emission limitations. These regulations may increase the costs of compliance for some facilities, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance. These laws and regulations also apply to entities that use natural gas as fuel, and may increase the costs of compliance of our customers to the point where demand for natural gas is affected. We believe that our operations are in substantial compliance with the requirements of the Clean Air Act.

 

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OSHA and Other Regulations. We are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Greenhouse Gas Regulation and Climate Change. Natural gas contains methane, which is considered to be a greenhouse gas. Additionally, the burning of natural gas produces carbon dioxide, which is also a greenhouse gas. Published studies have suggested that the emission of greenhouse gases may be contributing to global warming. To date, legislative and regulatory initiatives relating to greenhouse gas emissions have not had a material impact on our business. However, Congress has been actively considering climate change legislation. More directly, the EPA 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), the EPA made a final determination that greenhouse gases endangered public health and welfare, 74 Fed. Reg. 66,496 (December 15, 2009). This finding led to the regulation of greenhouse gases under the Clean Air Act. Currently, the EPA has promulgated two rules that will impact our business.

First, the EPA promulgated the so-called “Tailoring Rule” which established emission thresholds for greenhouse gases under the Clean Air Act permitting programs, 75 Fed. Reg. 31514 (June 3, 2010). Both the federal preconstruction review program (Prevention of Significant Deterioration) and the operating permit program (Title V) 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 Title V operating permits.

Second, the EPA finalized its Mandatory Reporting of Greenhouse Gases rule in 2009, 74 Fed. Reg. 56,260 (October 30, 2009). Subsequent revisions, additions, and clarification rules were promulgated, including a rule specifically addressing the natural gas industry. These rules require certain industry sectors that emit greenhouse gases above a specified threshold to report greenhouse gas emissions to the EPA on an annual basis. The natural gas industry is covered by the rule and requires annual greenhouse gas emissions to be reported starting in 2011 with the initial reports due in 2012. This rule imposes additional reporting obligations on us.

There are also ongoing legislative and regulatory efforts to encourage the use of cleaner energy technologies. While natural gas is a fossil fuel, it is considered to be more benign, from a greenhouse gas standpoint, than other carbon-based fuels, such as coal or oil. Thus future regulatory developments could have a positive impact on our business to the extent that they either decrease the demand for other carbon-based fuels or position natural gas as a favored fuel.

In addition to domestic regulatory developments, the United States is a participant in multi-national discussion 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 business.

Finally, as noted above, 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 business, and we are unable to predict at this time what, if any, long-term impact such climate effects would have.

Other Regulation of the Natural Gas and Oil Industry. The natural gas and oil industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the natural gas and oil industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in their industries with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

 

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Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we will operate also regulate one or more of the following:

 

•

the location of wells;

 

•

the manner in which water necessary to develop wells is managed;

 

•

the method of drilling and casing wells;

 

•

the surface use and restoration of properties upon which wells are drilled;

 

•

the plugging and abandoning of wells; and

 

•

notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from its 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 natural gas liquids within its jurisdiction.

State Regulation. 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, Michigan imposes a 5% severance tax on natural gas and a 6.6% severance tax on oil, Tennessee imposes a 3% severance tax on natural gas and oil production and Ohio imposes a severance tax of $0.025 per Mcf of natural gas and $0.10 per Bbl of oil, Indiana imposes a severance tax of $.03 per MCF on natural gas and $.24 per bbl of oil, Colorado imposes a severance tax up to 5% of the value of oil and gas severed from earth, in addition to other applicable taxes, while West Virginia imposes a 5% severance tax on oil and gas. While Pennsylvania has not imposed a severance tax, there is legislation that has been approved by the Pennsylvania legislature and signed by the Governor that will impose an impact fee on oil and gas production. 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 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.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon our unitholders.

Interest in Atlas Pipeline Partners, L.P.

In addition to our production operations, we also maintain the following interest in APL at December 31, 2011:

 

•

a 2.0% general partner interest, which entitles us to receive 2% of the cash distributed by APL;

 

•

all of the incentive distribution rights (“IDRs”), which entitle us to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per APL common unit in any quarter; and

 

•

5,754,253 common units, representing approximately 10.7% of the outstanding common units, or a 10.5% ownership interest in APL.

 

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APL is a leading provider of natural gas gathering, processing and treating services in the Anadarko and Permian Basins located in the southwestern and mid-continent regions of the United States, a provider of natural gas gathering services in the Appalachian Basin in the northeastern region of the United States and a provider of NGL transportation services in the southwestern region of the United States.

As of December 31, 2011, through its Gathering and Processing operations, APL owns and operates:

 

•

seven active natural gas processing plants with aggregate capacity of approximately 610 MMcfd;

 

•

9,000 miles of active natural gas gathering systems located in Oklahoma, Kansas and Texas, which transport gas from wells and central delivery points in the Anadarko and Permian Basins to APL’s natural gas processing and treating plants or third party pipelines;

 

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100 miles of active natural gas gathering systems located in Tennessee, which gather gas from wells and central delivery points and deliver to natural gas processing and treating plants, as well as third-party pipelines; and

 

•

a 20% interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”), which was acquired in May 2011. WTLPG owns an approximately 2,200 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. WTLPG is operated by Chevron Pipeline Company, an affiliate of Chevron, which owns the remaining 80% interest.

Our ownership of APL’s incentive distribution rights entitles us to receive the following increasing percentage of cash distributed by APL as it reaches certain target distribution levels:

 

•

13.0% of all cash distributed in any quarter after each APL common unit has received $0.42 for that quarter;

 

•

23.0% of all cash distributed in any quarter after each APL common unit has received $0.52 for that quarter; and

 

•

48.0% of all cash distributed in any quarter after each APL common unit has received $0.60 for that quarter.

In conjunction with a previous acquisition made by APL, in 2009 we agreed to allocate up to $3.75 million of our IDRs per quarter back to APL after we receive an initial $7.0 million per quarter of IDRs.

Employees

As of December 31, 2011, we employed 683 persons.

Available Information

We make our periodic reports under the Securities Exchange Act of 1934, including our annual report on Form 10-K, our quarterly reports on Form 10-Q, 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 - 4^th Floor, 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.

 

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ITEM 1A:

RISK FACTORS

As described above in “Item 1: Business – Subsequent Events”, in February 2012, our General Partner’s board of directors approved the formation of Atlas Resource Partners, L.P. (“ARP”), a newly-created exploration and production master limited partnership that will receive and hold substantially all of our natural gas and oil production and development assets and our partnership management business. After we contribute these assets to ARP, we will distribute approximately 5.24 million ARP common units to our unitholders using a ratio of 0.1021 ARP limited partner units for each common unit of ours owned on the record date. Upon completion of the distribution, substantially all of our assets will be represented by our limited partner interests, general partner interests and incentive distribution rights in ARP and Atlas Pipeline Partners, L.P. (“APL”). After completion of the distribution, we will become dependent principally upon the cash distributions from ARP and APL to grow, fund our operations, pay debt service or make distributions to our limited partners. Many of the risk factors set forth below with respect to our interests in APL, such as the impact of reduced distributions, ability to sell general partner interests and incentive distribution rights, as well as various tax risks, will equally apply to our ownership in ARP after we contribute the assets referenced above.

Risks Relating to Our Business

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

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

 

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the level of domestic and foreign supply and demand;

 

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the price and level of foreign imports;

 

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the level of consumer product demand;

 

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weather conditions and fluctuating and seasonal demand;

 

•

overall domestic and global economic conditions;

 

•

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

 

•

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

 

•

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

 

•

technological advances affecting energy consumption;

 

•

domestic and foreign governmental relations, regulations and taxation;

 

•

the impact of energy conservation efforts;

 

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

 

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the price and availability of alternative fuels.

In the past, the prices of natural gas and oil have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2011, the NYMEX Henry Hub natural gas index price ranged from a high of $4.85 per MMBtu to a low of $2.99 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $113.93 per Bbl to a low of $75.67 per Bbl. Between January 1, 2012 and February 17, 2012, the NYMEX Henry Hub natural gas index price ranged from a high of $3.10 per MMBtu to a low of $2.32 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $103.24 per Bbl to a low of $96.36 per Bbl.

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

We operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital through our investment partnerships, contracting for drilling equipment and securing trained personnel. Our competitors may be able to pay more for natural gas 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, our 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 do. All of these challenges could make it more difficult for us to execute our growth strategy. We 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 competitors possess greater financial and other resources than we do, 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 operations and results.

Increased demand for drilling rigs, equipment and crews, due to increased activity by participants in our 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 revenues.

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

Our key project areas are located in active drilling areas in the Appalachian Basin, and many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of natural gas in these areas.

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

The natural gas and oil industry is capital intensive. If we 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 investment partnerships, we may be unable to increase or maintain our inventory of properties and reserve base, or be forced to curtail drilling or other activities. This could cause our revenues to decline and diminish our ability to service any debt that we may have at such time. If we do not make sufficient or effective expansion capital expenditures, including with funds from third-party sources, we will be unable to expand our business operations, and may not generate sufficient revenue or have sufficient available cash to pay distributions on our units.

 

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Our cash distribution policy limits our ability to grow.

Consistent with the terms of our partnership agreement, we distribute to our partners our available cash each quarter. In determining the amount of cash available for distribution, we each set aside cash reserves, including reserves we believe prudent to maintain for the proper conduct of our businesses or to provide for future distributions. Accordingly, to the extent we do not have sufficient cash reserves or are unable to finance growth externally, our cash distribution policies will significantly impair our ability to grow. In addition, to the extent either of us issue additional units or incur additional debt in connection with any acquisitions or capital expenditures, the payment of distributions on those additional common units may increase the risk that we will be unable to maintain our or increase our prior per common unit distribution level. Moreover, the incurrence of additional debt to finance our growth strategy would result in increased interest expense, which in turn, may impact the cash we have available to distribute to our unitholders.

We may not have sufficient cash to pay distributions.

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

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

 

•

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

 

•

restrictions on distributions contained in any current or future debt agreements;

 

•

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

 

•

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

 

•

reserves necessary for us to make the necessary capital contributions to maintain our 2.0% general partner interest in APL as required by its partnership agreement upon the issuance of additional partnership securities by APL; and

 

•

reserves our general partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

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

We may issue an unlimited number of limited partner interests without the consent of our unitholders, which will dilute existing limited partners’ ownership interest in us and may increase the risk that we will not have sufficient available cash to make distributions.

We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders on terms and conditions established by our general partner at any time. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

•

our unitholders’ proportionate ownership interest in us will decrease;

 

•

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

 

•

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

 

•

the ratio of taxable income to distributions may increase; and

 

•

the market price of the common units may decline.

Our ability to sell our general partner interest and incentive distribution rights in APL is limited.

We face contractual limitations on our ability to sell our general partner interest and incentive distribution rights in APL and the market for such interests is illiquid.

 

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

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

 

•

an increase in our operating expenses;

 

•

an increase in general and administrative expenses;

 

•

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

 

•

an increase in working capital requirements.

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

While our cash distribution policy, which is consistent with the terms of our partnership agreement, requires that we distribute all of our available cash quarterly, our cash distribution policy is subject to the following restrictions and limitations and may be changed at any time, including in the following ways:

 

•

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

 

•

Our cash distribution policy is, and APL’s cash distribution policy is, subject to restrictions on distributions under our credit facility and APL’s credit facility, respectively, such as material financial tests and covenants and limitations on paying distributions during an event of default;

 

•

Our general partner’s board of directors has the authority under our partnership agreement to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders. The establishment of those reserves could result in a reduction in future cash distributions to our unitholders pursuant to our stated cash distribution policy;

 

•

Our partnership agreement, including the cash distribution policy contained therein, may be amended by a vote of the holders of a majority of our common units;

 

•

Even if our cash distribution policy is not amended, modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement; and

 

•

Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

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

Covenants in our credit facility restrict our business in many ways.

Our credit facility contains various restrictive covenants that limit our ability to, among other things:

 

•

incur additional debt or liens or provide guarantees in respect of obligations of other persons;

 

•

pay distributions or redeem or repurchase our securities;

 

•

prepay, redeem or repurchase debt;

 

•

make loans, investments and acquisitions;

 

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•

enter into hedging arrangements;

 

•

sell assets;

 

•

enter into certain transactions with affiliates; and

 

•

consolidate or merge with or into, or sell substantially all of our assets to, another person.

In addition, our credit facility requires us to maintain specified financial ratios. Our ability to meet those financial ratios can be affected by events beyond our control, and we may be unable to meet those tests. A breach of any of these covenants could result in a default under our credit facility. Upon the occurrence of an event of default under our credit facility, the lenders could elect to declare all amounts outstanding immediately due and payable and terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders could proceed against the collateral granted to them to secure that indebtedness. We have pledged a significant portion of our assets as collateral under our credit facility. If the lenders under our credit facility accelerate the repayment of borrowings, we may not have sufficient assets to repay our credit facility and our other liabilities. Our borrowings under our credit facility are, and are expected to continue to be, at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income would decrease.

We or one of our subsidiaries may be exposed to financial and other liabilities as the managing general partner in investment partnerships.

We or one of our subsidiaries serves as the managing general partner of the investment partnerships and will be the managing general partner of new investment partnerships that we sponsor. As a general partner, we or one of our subsidiaries will be contingently liable for the obligations of the partnerships to the extent that partnership assets or insurance proceeds are insufficient. We have agreed to indemnify each investor partner in the investment partnerships from any liability that exceeds such partner’s share of the investment partnership’s assets, and we or one of our subsidiaries are bound by this agreement after the sale of the Transferred Business.

Economic conditions and instability in the financial markets could negatively impact our and APL’s business which, in turn, could impact the cash we have to make distributions to our unitholders.

Our and APL’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 and APL’s service areas and in wells currently connected to APL’s pipeline system being shut in by their operators until prices improved. Any of these events may adversely affect our and APL’s revenues and ability to fund capital expenditures and, in the future, may impact the cash that we have available to fund our operations, pay required debt service on our credit facility and make distributions to our unitholders.

Potential instability in the financial markets, as a result of recession or otherwise, can cause volatility in the markets and may affect our and APL’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 or APL to the extent required and on acceptable terms. Disruptions in the capital and credit markets could negatively impact our and APL’s access to liquidity needed for our businesses and impact flexibility to react to changing economic and business conditions. We and APL may be unable to execute our growth strategies, take advantage of business opportunities or to respond to competitive pressures, any of which could negatively impact our business.

Economic situations could have an adverse impact on producers, key suppliers or other customers, or on our and APL’s lenders, causing them to fail to meet their obligations to APL. Market conditions could also impact our and APL’s derivative instruments. If a counterparty is unable to perform its obligations and the derivative instrument is terminated, our and APL’s cash flow and ability to pay distributions could be impacted 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 and APL currently cannot predict or anticipate.

 

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Significant physical effects of climatic 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.

We currently sell the majority of our natural gas production to a single customer. To the extent this customer reduces the volumes of natural gas it purchases from us, or ceases to purchase natural gas from us, upon the expiration of our existing sales contracts, our revenues could be negatively affected.

Certain of our subsidiaries sell gas produced in four key counties in southwest Pennsylvania to a subsidiary of Chevron Corporation pursuant to a gas marketing agreement with a term expiring in February 2014, and all of the gas produced by the wells in Michigan owned by the investment partnerships are marketed by a subsidiary of Chevron pursuant to an operating agreement between the parties. To the extent Chevron reduces the amount of natural gas it purchases from us upon the expiration of these contracts, or if the gas marketing agreement is terminated or the gas marketing services provided under the operating agreement are no longer provided, our revenues could be harmed in the event we are unable to sell to other purchasers at similar prices.

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

The prices that we 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 receive could significantly reduce our cash available for distribution to our unitholders and adversely affect our financial condition. We use the relevant benchmark price to calculate our hedge positions, and we do not have or plan to have any commodity derivative contracts covering the amount of the basis differentials we experience in respect of our production. As such, we will be exposed to any increase in such differentials, which could adversely affect our results of operations.

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

As of December 31, 2011, leases covering approximately 25,541 of our 286,533 net undeveloped acres, or 8.9%, are scheduled to expire on or before December 31, 2012. An additional 15% and 9% are scheduled to expire in the years 2013 and 2014, respectively. If we are unable to renew these leases or any leases scheduled for expiration beyond their expiration date, on favorable terms, we will lose the right to develop the acreage that is covered by an expired lease and our production would decline, which would reduce our cash flows from operations.

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

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas 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 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;

 

•

unexpected operational events and drilling conditions;

 

•

adverse weather conditions;

 

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facility or equipment malfunctions;

 

•

title problems;

 

•

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;

 

•

injury or loss of life;

 

•

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;

 

•

fires, blowouts, craterings and explosions; and

 

•

uncontrollable flows of natural gas or well fluids.

Any one or more of the factors discussed above could reduce or delay our receipt of drilling and production revenues, thereby reducing our earnings, and could reduce revenues in one or more of our investment partnerships, which may make it more difficult to finance our drilling operations through sponsorship of future partnerships. In addition, any of these events can cause substantial losses, including 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 will maintain insurance against various losses and liabilities arising from our operations, insurance against all operational risks will not be 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 results of operations.

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

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

A decrease in natural gas prices could subject our 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 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. Accordingly, further declines in the

 

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price of natural gas may cause the carrying value of our 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.

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

Pricing for natural gas and oil has been volatile and unpredictable for many years. To limit exposure to changing natural gas and oil prices, we use financial and physical hedges for our production. Physical hedges are not deemed hedges for accounting purposes because they require firm delivery of natural gas and are considered normal sales of natural gas. We generally limit these arrangements to smaller quantities than those projected to be available at any delivery point.

In addition, we 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. The futures contracts are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to six years in the future.

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

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

With the objective of enhancing the predictability of future revenues, from time to time we and APL enter into natural gas, natural gas liquids and crude oil derivative contracts. We and APL account for these derivative contracts by applying the mark-to-market accounting treatment required for these derivative contracts. We and APL 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 us recognizing a non-cash loss in our consolidated combined statements of operations and a consequent non-cash decrease in our equity between reporting periods. Any such decrease could be substantial. In addition, we or APL may be required to make cash payments upon the termination of any of these derivative contracts.

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

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our and APL’s ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our and APL’s business. The Dodd-Frank Wall Street Reform and Consumer Protection Act, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The legislation requires the Commodities Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the new legislation. The CFTC finalized its regulations and has set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The financial reform legislation may also require us and APL to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our and APL’s existing or future derivative activities, although the application of those provisions to us and APL is uncertain at this time. The financial reform legislation may also require the counterparties to our and APL’s derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any 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 APL encounter; reduce our and APL’s ability to monetize or restructure our and APL’s derivative contracts in existence at that time; and increase our and APL’s exposure to less creditworthy counterparties. If we and APL reduce or change the way we use derivative instruments as a result of the legislation or regulations, our and APL’s results of operations may become more volatile and cash flows may be less predictable, which could adversely affect our and APL’s ability to plan for and fund capital expenditures. Finally, the legislation was 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

 

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related to oil and natural gas. Our and APL’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 APL’s consolidated financial position, results of operations and/or cash flows.

The scope and costs of the risks involved in making acquisitions may prove greater than estimated at the time of the acquisition.

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

 

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mistaken assumptions about revenues and costs, including synergies;

 

•

significant increases in our indebtedness and working capital requirements;

 

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an inability to integrate successfully or timely the businesses we acquire;

 

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the assumption of unknown liabilities;

 

•

limitations on rights to indemnity from the seller;

 

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

 

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increased demands on existing personnel;

 

•

customer or key employee losses at the acquired businesses; and

 

•

the failure to realize expected growth or profitability.

The scope and cost of these risks may be materially greater than estimated at the time of the acquisition. Any of these factors could adversely affect our future growth.

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 may acquire in the future, include, among other things:

 

•

operating a significantly larger combined entity;

 

•

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

 

•

integrating personnel with diverse business backgrounds and organizational cultures;

 

•

consolidating operational and administrative functions;

 

•

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

 

•

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

 

•

customer or key employee loss from the acquired businesses;

 

•

a significant increase in our indebtedness; and

 

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potential environmental or regulatory liabilities and title problems.

 

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

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

One of our growth strategies is to capitalize on opportunistic acquisitions of natural gas reserves. However, reviews of acquired properties are often incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. A detailed review of records and properties also may not necessarily reveal existing or potential problems, and may not permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well that we acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we inspect a well. Any unidentified problems could result in material liabilities and costs that negatively affect our 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. Even if a seller agrees to provide indemnity, the indemnity may not be fully enforceable and may be limited by floors and caps on such indemnity.

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

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

Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, New York has imposed a de facto moratorium on the issuance of permits for high volume, horizontal hydraulic fracturing until state administered environmental studies are finalized. Public hearings on the studies and proposed regulations were held in November 2011, with the public comment period for the proposed regulations closing in January 2012. Further, Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed. In February 2012, legislation was passed in Pennsylvania requiring, among other things, disclosure of chemicals used in hydraulic fracturing. Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas (RCT) and the public of certain information regarding the components used in the hydraulic fracturing process. In December 2011, West Virginia enacted legislation imposing more stringent regulation of horizontal drilling. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. If state, local, or municipal legal restrictions are adopted in areas where we and our subsidiaries are currently conducting, or in the future plan to conduct, operations, we and our subsidiaries 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.

Although the process is not generally subject to regulation at the federal level, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices, and some federal regulation has taken place. The Environmental Protection Agency, or EPA, has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel as an additive under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, legislation that would provide for federal regulation of hydraulic fracturing and require disclosure of the chemicals used in the hydraulic fracturing process could be introduced in the future. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the U.S. House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands.

 

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Certain members of U.S. Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, 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, and 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. These ongoing or 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 and our subsidiaries 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 and our subsidiaries’ ability to drill wells. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our and our subsidiaries’ fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we and our subsidiaries are ultimately able to produce from our respective reserves.

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

On July 28, 2011, the EPA proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (VOCs) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. Final regulations are anticipated in the spring of 2012. Once finalized, these rules will likely require a number of modifications to our and our subsidiaries’ operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our and our subsidiaries’ businesses.

In addition, both houses of U.S. Congress have actively considered legislation to reduce emissions of greenhouse gases, and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall greenhouse gas emission reduction goal is achieved. The adoption of any legislation or regulations that requires reporting of greenhouse gases or otherwise limits emissions of greenhouse gases from our and our subsidiaries’ equipment and operations could require us and our subsidiaries to incur costs to monitor and report on greenhouse gas emissions or reduce emissions of greenhouse gases associated with our and our subsidiaries’ operations, and such requirements also could adversely affect demand for the oil and natural gas that we and our subsidiaries produce.

Climate change legislation or regulations restricting emissions of greenhouse gases (“GHGs”) could result in increased operating costs and reduced demand for our and our subsidiaries’ services.

In response to findings that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climate changes, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that require entities that produce certain gases to inventory, monitor and report such gases. On November 30, 2010, the EPA published a final GHG emissions reporting rule relating to natural gas processing, transmission, storage, and distribution activities, which requires reporting beginning in 2012 for emissions occurring in 2011. Additionally, in 2010, EPA issued rules to regulate GHG emissions through traditional major source construction and operating permit programs. These permitting programs require consideration of and, if deemed necessary, implementation of best available control technology to reduce GHG emissions. As a result, our and our subsidiaries’ operations could face additional costs for emissions control and higher costs of doing business.

 

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The third parties on whom we 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 our business.

The operations of the third parties on whom we 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 business, financial condition, results of operations and ability to make distributions to our unitholders.

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

A significant portion of our and our subsidiaries’ natural gas extraction activity will utilize 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 and our subsidiaries’ operations and financial performance. Our and our subsidiaries’ ability to collect and dispose of water will affect our and our subsidiaries’ production, and the cost of water treatment and disposal may affect our and our subsidiaries’ profitability. The imposition of new environmental initiatives and regulations could include restrictions on our and our subsidiaries’ 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.

A severance tax or impact fee in Pennsylvania could materially increase our liabilities.

While Pennsylvania has historically not imposed a severance tax (relating to the extraction of natural gas), with a focus on its budget deficit and the increasing exploration of the Marcellus Shale, various legislation has been proposed since 2008. In February 2012, Pennsylvania implemented an impact fee. This new law imposes an impact fee on all unconventional wells drilled in the Commonwealth of Pennsylvania in counties that elect to impose the fee. The 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. Based upon natural gas prices for 2011, operators will pay $50,000 per unconventional horizontal well. Unconventional vertical wells will pay a fee equal to twenty percent of the horizontal well fee and the impact fee will not apply to any unconventional vertical well that produces less than 90mcf per day. 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 a horizontal well and 10 years for a vertical well.

Because we and our subsidiaries handle natural gas 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 hazardous substances into the environment.

The operations of our and our subsidiaries’ wells and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:

 

•

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

 

•

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

 

•

the federal Resource Conservation and Recovery Act (which we refer to as “RCRA”) and comparable state laws that impose requirements for the handling and disposal of waste, including produced waters, from our and our subsidiaries’ facilities; and

 

•

the federal Comprehensive Environmental Response, Compensation, and Liability Act (which we refer to as “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, our subsidiaries and Atlas Energy, Inc. (“AEI”) or at locations to which we, our subsidiaries and AEI have sent waste for disposal.

 

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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. 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 hazardous substances have been disposed of or otherwise released. 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 and our subsidiaries may incur environmental costs and liabilities due to the nature of our and our subsidiaries’ businesses and the substances we and our subsidiaries handle. For example, an accidental release from one of our or our subsidiaries’ wells could subject us or the applicable subsidiary to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies may be enacted or adopted and could significantly increase our and our subsidiaries’ compliance costs and the cost of any remediation that may become necessary. We or the applicable subsidiary may not be able to recover remediation costs under our respective insurance policies.

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

Our and our subsidiaries’ operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon natural gas and oil wells. Under these laws and regulations, we and our subsidiaries could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our or our subsidiaries’ operations and subject us and our subsidiaries to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Part of the regulatory environment in which we and our subsidiaries 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 and our subsidiaries’ activities will be subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our and our subsidiaries’ operations and limit the quantity of natural gas we and our subsidiaries may produce and sell. A major risk inherent in our and our subsidiaries’ drilling plans 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 and our subsidiaries’ ability to develop our respective properties. Additionally, the natural gas and oil regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, reduce our and our subsidiaries’ profitability. For example, Pennsylvania’s General Assembly approved legislation in February 2012 that would impose significant, costly requirements on the natural gas industry, including the imposition of increased bonding requirements and impact fees for gas wells, based on the price of natural gas and the age of the well. Furthermore, we and our subsidiaries may be put at a competitive disadvantage to larger companies in our industry who can spread these additional costs over a greater number of wells and larger operating staff.

We may not be able to continue to raise funds through our investment partnerships at desired levels, which may in turn restrict our ability to maintain our drilling activity at recent levels.

We have sponsored limited and general partnerships to finance certain of our development drilling activities. Accordingly, the amount of development activities that we will undertake depends in large part upon our ability to obtain investor subscriptions to invest in these partnerships. We have raised $141.9 million, $149.3 million and $353.4 million in calendar years 2011, 2010 and 2009, respectively. In the future, we may not be successful in raising funds through these investment partnerships at the same levels that we experienced, and we also may not be successful in increasing the amount of funds we raise. Our ability to raise funds through our investment 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 our historical track record of generating returns and tax benefits to the investors in our existing partnerships.

 

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In the event that our investment partnerships do not achieve satisfactory returns on investment or the anticipated tax benefits, we may have difficulty in maintaining or increasing the level of investment partnership fundraising relative to the levels achieved by us. In this event, we may need to seek financing for our drilling activities through alternative methods, which may not be available, or which may be available only on a less attractive basis than the financing we realized through these investment partnerships, or we may determine to reduce drilling activity.

Changes in tax laws may impair our ability to obtain capital funds through investment partnerships.

Under current federal tax laws, there are tax benefits to investing in investment partnerships, including deductions for intangible drilling costs and depletion deductions. However, the current administration has proposed, among other tax changes, the repeal of certain oil and gas tax benefits, including the repeal of the percentage depletion allowance, the election to expense intangible drilling costs, the passive activity exception for working interests and the marginal production tax credit. These proposals may or may not be adopted. 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 our investment partnerships. These or other changes to federal tax law may make investment in our investment partnerships less attractive and, thus, reduce our ability to obtain funding from this significant source of capital funds.

Fee-based revenues may decline if we are unsuccessful in sponsoring new investment partnerships.

Our fee-based revenues will be based on the number of investment partnerships we sponsor and the number of partnerships and wells we manage or operate. If we are unsuccessful in sponsoring future investment partnerships, our fee-based revenues may decline.

Our revenues may decrease if investors in our investment partnerships do not receive a minimum return.

We have agreed to subordinate up to 50% of our share of production revenues, net of corresponding production costs, to specified returns to the investor partners in our investment partnerships, typically 10% per year for the first five years of distributions, and we are bound by this agreement following the sale of the Transferred Business. Our revenues from a particular investment partnership will therefore decrease if the investment partnership does not achieve the specified minimum return. For the years ended December 31, 2011, 2010 and 2009, $4.0 million, $10.9 million and $3.9 million, respectively, of our revenues, net of corresponding production costs, were subordinated, which reduced our cash distributions received from the investment partnerships.

Certain of our officers and directors are subject to non-competition agreements that may effectively restrict our ability to expand our business in the Marcellus Shale.

Edward Cohen, who serves as our Chief Executive Officer, and Jonathan Cohen, who serves as our Chairman of the board of our general partner, are each parties to a non-competition and non-solicitation agreement with Chevron Corporation. These agreements restrict each such individual, until February 17, 2014, from engaging in any capacity (whether as officer, director, owner, partner, stockholder, investor, consultant, principal, agent, employee, coventurer or otherwise) in a business engaged in the exploration, development or production of hydrocarbons in certain designated counties within the States of Pennsylvania, West Virginia and New York, and from engaging in certain solicitation activities with respect to oil and gas leases, customers, suppliers and contractors of AEI. The foregoing restrictions are subject to certain limited exceptions, including exceptions permitting Jonathan Cohen and Edward Cohen in certain circumstances to engage in the businesses conducted by us (including with respect to the operation of the assets we acquired from AEI in February 2011) and APL. The non-competition agreements also prohibit Edward Cohen and Jonathan Cohen, until February 17, 2013, from soliciting for employment, or hiring, any person who was employed by AEI before its merger with Chevron and became an employee of AEI or Chevron after the merger, subject to certain limited exceptions.

Therefore, our ability to expand our business in the Marcellus Shale may be limited.

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

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and

 

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operating results would be harmed. We cannot be certain that our efforts to 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 maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

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 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 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 PV-10 and standardized measure are calculated using natural gas prices that include our physical hedges but not our 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 our 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 our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on historical prices and costs. However, actual future net cash flows from our natural gas properties also will be affected by factors such as:

 

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actual prices we receive for natural gas;

 

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the amount and timing of actual production;

 

•

the amount and timing of our capital expenditures;

 

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supply of and demand for natural gas; and

 

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changes in governmental regulations or taxation.

The timing of both our production and incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor 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 us 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 our 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 our reserves because the economic life of our wells could end sooner. Similarly, a decline in market prices for natural gas or oil may reduce our PV-10 and standardized measure.

 

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Certain provisions of our limited partnership 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 partnership 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;

 

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

 

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rules regarding how our common unitholders may call special meetings; and

 

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limitations on the right of our common unitholders to remove 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. Any of the foregoing provisions could limit the price that some investors might be willing to pay for our common units.

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

APL has wide discretion to issue additional limited partner units, including units that rank senior to its common units and the incentive distribution rights as to quarterly cash distributions, on the terms and conditions established by its general partner. The payment of distributions on additional APL common units may increase the risk of APL being unable to make distributions at its prior per unit distribution levels. To the extent new APL limited partner units are senior to the APL 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 APL will disproportionately affect the amount of cash distributions to which we are entitled.

We are entitled to receive incentive distributions from APL, through our ownership of Atlas Pipeline GP, with respect to any particular quarter only if APL distributes more than $0.42 per common unit for such quarter. Atlas Pipeline GP agreed to allocate up to $3.75 million of incentive distributions per quarter back to APL.

Atlas Pipeline GP’s incentive distribution rights entitle it to receive percentages increasing up to 48% of all cash distributed by APL, subject to the IDR Adjustment Agreement. Distribution by APL above $0.60 per common unit per quarter would result in Atlas Pipeline GP’s incremental cash distributions to be the maximum 48%. Atlas Pipeline GP’s percentage of the incremental cash distributions reduces from 48% to 23% if APL’s distribution is between $0.52 and $0.59, and to 13% if APL’s distribution is between $0.43 and $0.51, subject in both cases to the effect of the IDR Adjustment Agreement. As a result, lower quarterly cash distributions from APL have the effect of disproportionately reducing the amount of all incentive distributions that Atlas Pipeline GP receives as compared to cash distributions Atlas Pipeline GP receives on its 2.0% general partner interest in APL.

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

We own APL’s general partner, which owns the incentive distribution rights in APL that entitle us to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per common unit in any quarter. APL’s board of directors may reduce the incentive distribution rights payable to us without our consent, which we may provide without the approval of our unitholders. In July 2007, in connection with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems, Atlas Pipeline GP agreed to allocate up to $3.75 million of incentive distribution rights per quarter back to APL after it receives the initial $7.0 million per quarter of incentive distribution rights.

 

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In order to facilitate acquisitions by APL, the general partner of APL may elect to limit the incentive distributions we are entitled to receive with respect to a particular acquisition or unit issuance contemplated by APL. This is because a potential acquisition might not be accretive to APL’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 APL, the cash flows associated with that acquisition could be accretive to APL’s common unitholders as well as substantially beneficial to us. In doing so, the managing board of APL’s general partner would be required to consider both its fiduciary obligations to investors in APL as well as to us. Our partnership agreement specifically permits our general partner to authorize the general partner of APL to limit or modify the incentive distribution rights held by us if our general partner determines that such limitation or modification does not adversely affect our limited partners in any material respect.

APL’s common unitholders have the right to remove APL’s 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 APL and the ability to manage APL.

We currently manage APL through Atlas Pipeline GP, APL’s general partner and our wholly-owned subsidiary. APL’s partnership agreement, however, gives common unitholders of APL the right to remove the general partner of APL upon the affirmative vote of holders of 66 2/3% of APL’s outstanding common units. If Atlas Pipeline GP were removed as general partner of APL, it would receive cash or common units in exchange for its 2.0% general partner interest and the incentive distribution rights and would lose ability to manage APL. While the common units or cash we would receive are intended under the terms of APL’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 APL’s general partner is not fully reimbursed or indemnified for obligations and liabilities it incurs in managing the business and affairs of APL, its value, and therefore the value of our common units, could decline.

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

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

If we cease to manage and control APL 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, including the purchase and sale of certain 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.

Risks Relating to the Ownership of Our Common Units

If the unit price declines, our common unitholders could lose a significant part of their investment.

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 or APL’s 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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•

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 recently have experienced record lows in interest rates. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our and APL’s financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our and APL’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 and APL’s ability to issue additional equity or to incur debt to make acquisitions or for other purposes and could impact our and APL’s ability to make cash distributions at our and APL’s intended levels.

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

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

Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Unitholders could be liable for any and all of our obligations as it they were a general partner if, among other potential reasons:

 

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a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

 

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a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our business.

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

 

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Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement.

Risks Related to Our Conflicts of Interest

Although we control APL through our ownership of its general partner, APL’s general partner owes fiduciary duties to APL and APL’s 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 APL’s general partner, on the one hand, and APL and its limited partners, on the other hand. The directors and officers of Atlas Pipeline GP have fiduciary duties to manage APL in a manner beneficial to us, its owner. At the same time, these directors and officers have a fiduciary duty to manage APL in a manner beneficial to APL and its limited partners. The managing board of APL or its conflicts committee will resolve any such conflict and has 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.

For example, conflicts of interest may arise in the following situations:

 

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the allocation of shared overhead expenses to APL and us;

 

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the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and APL, on the other hand;

 

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the determination and timing of the amount of cash to be distributed to APL’s partners and the amount of cash reserved for the future conduct of APL’s business;

 

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

 

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

The fiduciary duties of our general partner’s officers and directors may conflict with those of APL’s general partner’s officers and directors.

Our general partner’s officers and directors have fiduciary duties to manage our business in a manner beneficial to us and our partners. However, certain of our general partner’s executive officers and non-independent directors also serve as executive officers and directors of APL’s general partner, and, as a result, have fiduciary duties to manage the business of APL in a manner beneficial to APL and its partners. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to APL, 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.

If we are presented with certain business opportunities, APL will have the first right to pursue such opportunities.

Pursuant to the omnibus agreement between us and APL, we have agreed to certain business opportunity arrangements to address potential conflicts that may arise between us and APL. If a business opportunity in respect of any business activity in which APL is currently engaged is presented to us or APL, then APL will have the first right to pursue such business opportunity.

APL and affiliates of our general partner are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.

 

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Neither our partnership agreement nor the omnibus agreement between us and APL prohibits APL or affiliates of our general partner from owning assets or engaging in businesses that compete directly or indirectly with us or one another. In addition, APL and its affiliates may acquire, construct or dispose of additional assets related to the gathering and processing of natural gas, NGLs or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. As a result, competition among these entities could adversely impact APL’s or our results of operations and cash available for paying required debt service on our credit facility or making distributions.

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 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 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 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.

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 its 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 APL.

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

Tax gain or loss on disposition of our common units could be more or less than expected.

If a unitholder sells their common units, they will recognize a gain or loss equal to the difference between the amount realized and the adjusted tax basis in those common units. Prior distributions and the allocation of losses, including depreciation deductions, to the unitholder in excess of the total net taxable income allocated to them, which decreased the tax basis in their common units, will, in effect, become taxable income to them if the common units are sold at a price greater than their tax basis in those common units, even if the price is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to the unitholder.

 

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

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

We will be considered to have terminated our partnership for 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, APL will be considered to have terminated its partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interest in APL’s capital and profits within a 12-month period. The termination would, among other things, result in the closing of our or APL’s taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income for the year in which the termination occurs. Thus, if this occurs, the unitholder will be allocated an increased amount of 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 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. In addition, 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 as a result of investing in our common units.

In addition to U.S. federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or APL do business or own property now or in the future, even if our unitholders do not reside in any of those

 

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jurisdictions. Our unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We and APL presently anticipate that substantially all of our income will be generated in Oklahoma, Pennsylvania and Texas. As we make acquisitions or expand our business, 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. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.

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

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

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

When we or APL issue additional units or engage in certain other transactions, APL determines the fair market value of its assets and allocates any unrealized gain or loss attributable to such assets to the capital accounts of APL’s unitholders and us. Although APL may from time to time consult with professional appraisers regarding valuation matters, including the valuation of its assets, APL 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. APL’s methodology may be viewed as understating the value of APL’s assets. In that case, there may be a shift of income, gain, loss and deduction between certain APL unitholders and us, which may be unfavorable to such APL unitholders. Moreover, under APL’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 APL’s tangible assets and a lesser portion allocated to APL’s intangible assets. The IRS may challenge APL’s valuation methods, or our or APL’s allocation of Section 743(b) adjustment attributable to APL’s tangible and intangible assets, and allocations of income, gain, loss and deduction between us and certain of APL’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.

 

ITEM 1B:

UNRESOLVED STAFF COMMENTS

None.

 

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ITEM 2:

PROPERTIES

Natural Gas and Oil Reserves

The following tables summarize information regarding our estimated proved natural gas and oil reserves as of December 31, 2011. In accordance with prevailing accounting literature, we determined that the acquisition of the Transferred Business constituted a transaction between entities under common control, and as such, we retrospectively adjusted prior year amounts within the tables below (See “Item 1: Business – General”). Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids 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 direct ownership interests in oil and gas properties as well as the reserves attributable to our percentage interests in the oil and gas properties owned by investment partnerships in which we own partnership interests. All of the reserves are located in the United States. We base these estimated proved natural gas and oil reserves and future net revenues of natural gas and oil reserves upon reports prepared by Wright & Company, Inc. We have adjusted these estimates to reflect the settlement of asset retirement obligations on gas and oil properties. A summary of the reserve report related to our estimated proved reserves at December 31, 2011 is included as Exhibit 99.2 to this report. In accordance with SEC guidelines, we make the standardized measure estimates of future net cash flows from proved reserves using natural gas and oil sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. Our 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 within the prior 12-month period, and are listed below as of the dates indicated:

 

		December 31,
		2011				2010
Unadjusted
Natural gas (per Mcf)		$	4.12			$	4.38
Oil (per Bbl)		$	96.19			$	79.43
Adjusted
Natural gas (per Mcf)(1)		$	4.42			$	4.63
Oil (per Bbl) (1)		$	91.04			$	72.70

 

(1)

The adjusted weighted average natural gas price is the Base product price, with the representative price of natural gas adjusted for basis premium and the Btu content to arrive at the appropriate net price. The adjusted weighted average oil price is the Base product price, adjusted for local contracted gathering arrangements. Natural gas liquid prices have not been presented as the reserve amounts are immaterial. Amounts shown do not include financial hedging transactions.

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil 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 and oil 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 natural gas and oil reserve estimates was completed in accordance with our prescribed internal control procedures by our reserve engineers. The accompanying reserve information included below was derived from the reserve reports prepared for our annual report on Form 10-K for the year ended December 31, 2011. 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 and oil reserves which are all located in the United States, primarily in Colorado, Indiana, New York, Ohio, Pennsylvania, Tennessee and West Virginia. The independent reserves engineer’s evaluation was based on more than 35 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. Our internal control procedures include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 13 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our senior engineering staff and management, with final approval by our Executive Vice 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 and oil may be different from those estimated by Wright &

 

44

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Company, Inc. 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. Please read “Item 1A: Risk Factors—Risks Relating to Our Business.” You should not construe the estimated standardized measure values as representative of the current or future fair market value of our proved natural gas and oil properties. Standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas and oil 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 evaluate natural gas reserves at constant temperature and pressure. A change in either of these factors can affect the measurement of natural gas reserves. We deduct operating costs, development costs and production-related and ad valorem taxes in arriving at the estimated future cash flows. We base the estimates on operating methods and conditions prevailing as of the dates indicated:

 

		Proved natural gas and oil reserves at December 31,
		2011				2010
Proved reserves:
Natural gas reserves (Mmcf):
Proved developed reserves			138,403				137,393
Proved undeveloped reserves(1)			19,273				38,672
Total proved reserves of natural gas			157,676				176,065
Oil reserves (Mbbl):
Proved developed reserves			1,638				1,833
Proved undeveloped reserves(1)			8				—
Total proved reserves of oil(2)			1,646				1,833
Total proved reserves (Mmcfe)			167,552				187,056
Standardized measure of discounted future cash flows (in thousands)(3)		$	219,859			$	236,630

 

(1)

Our ownership in these reserves is subject to reduction as we generally make capital contributions, which includes leasehold acreage associated with our proved undeveloped reserves, to our investment partnerships in exchange for an equity interest in these partnerships, which historically ranges from 20% to 41%, which effectively will reduce our ownership interest in these reserves from 100% to our respective ownership interest as we make these contributions.

(2)	Includes less than 500 Mbbl of natural gas liquids proved reserves.

(3)

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 are a limited partnership, no provision for federal or state income taxes has been included in the December 31, 2011 and 2010 calculations of standardized measure, which is, therefore, the same as the PV-10 value.

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

Proved Undeveloped Reserves (“PUDS”)

PUD Locations. As of December 31, 2011, we had 76 PUD locations totaling approximately 19.3 Bcfe’s of natural gas and oil. These PUDS are based on the definition of PUD’s in accordance with the Securities and Exchange Commission 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 our drilling operations has been in the Appalachian Basin. We will continue to focus in this area to increase our proved reserves through organic leasing as well as drilling on our existing undeveloped acreage.

Our organic growth will focus on expanding our Marcellus Shale acreage position and targeting other formations in the United States. Through our previous drilling in the Marcellus as well as our geologic analysis of these areas, we are expecting these expansion locations to have a significant impact on our proved reserves. In addition, we have drilled successful Clinton formation natural gas and oil wells in eastern Ohio. We plan to continue drilling shallow Clinton wells.

 

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In the Chattanooga Shale in Tennessee, where we have drilled more than 90 producing wells, we plan to increase our proved reserves through continued drilling activity in this area.

Changes in PUDs. Changes in PUDS that occurred during the year ended December 31, 2011 were due to the following:

 

•

Conversion of approximately 15.7 Bcfe from Marcellus Shale PUDs to proved developed reserves;

 

•

Addition of approximately 0.8 Bcfe of Marcellus, Clinton/Medina and Niobrara drilled locations; and

 

•

Negative revisions of approximately 4.5 Bcfe in PUDs primarily due to the reduction of drilling plans in the New Albany Shale formation over the next five years.

Development Costs. Costs incurred related to the development of PUDs were approximately $40.5 million, $80.1 million, and $80.2 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Productive Wells

The following table sets forth information regarding productive natural gas and oil wells in which we have a working interest as of December 31, 2011. 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 have an interest, directly or through our ownership interests in investment partnerships, and net wells are the sum of our fractional working interests in gross wells, based on the percentage interest we own in the investment partnership that owns the well:

 

		Number of productive  wells(1)
		Gross				Net
Appalachia:
Gas wells			7,715				3,198
Oil wells			498				314
Total			8,213				3,512
New Albany/Antrim:
Gas wells			153				42
Oil wells			—				—
Total			153				42
Niobrara:
Gas wells			85				23
Oil wells			—				—
Total			85				23
Total:
Gas wells			7,953				3,263
Oil wells			498				314
Total			8,451				3,577

 

(1)	Includes our proportionate interest in wells owned by 98 investment partnerships for which we serve as managing general partner and various joint ventures. This does not include royalty or overriding interests in 514 wells.

Developed and Undeveloped Acreage

The following table sets forth information about our developed and undeveloped natural gas and oil acreage as of December 31, 2011. The information in this table includes our proportionate interest in acreage owned by investment partnerships.

 

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		Developed acreage (1)								Undeveloped  acreage(2)
		Gross (3)				Net (4)				Gross (3)				Net (4)
Pennsylvania			154,492				154,492				758				758
Ohio(5)			104,612				75,619				31,608				31,608
Indiana			33,916				29,033				174,572				104,712
Tennessee			19,841				19,475				101,185				98,936
New York			13,197				12,699				43,697				42,379
Other			27,706				23,105				12,799				8,140
Total			353,764				314,423				364,619				286,533

 

(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 own a working interest. The number of gross acres is the total number of acres in which we 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)	Does not include Utica Shale natural gas and oil rights.

The leases for our developed acreage generally have terms that extend for the life of the wells, while the leases on our 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, 2011.

We believe that we hold good and indefeasible title to our producing properties, in accordance with standards generally accepted in the natural gas industry, subject to exceptions stated in the opinions of counsel employed by us in the various areas in which we conduct our activities. We do not believe that these exceptions detract substantially from our use of any property. As is customary in the natural gas industry, we conduct only a perfunctory title examination at the time we acquire a property. Before we commence drilling operations, we conduct an extensive title examination and we perform curative work on defects that we deem significant. We or our predecessors have obtained title examinations for substantially all of our managed producing properties. No single property represents a material portion of our holdings.

Our properties are subject to royalty, overriding royalty and other outstanding interests customary in the industry. Our 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 use of our properties.

 

ITEM 3:

LEGAL PROCEEDINGS

We are party to various routine legal proceedings arising in the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations. See Note 13 of Notes to the Consolidated Combined Financial Statements.

 

ITEM 4:

[REMOVED AND RESERVED]

PART II

 

ITEM 5:

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

Our common units trade on the New York Stock Exchange under the symbol “ATLS.” At the close of business on February 22, 2012, the closing price of our units was $25.98, and there were 205 holders of record of our common units. The following table sets forth the high and low sales price per unit of our common limited partner units as reported by the New York Stock Exchange and the cash distributions declared by quarter per unit on our common limited partner units for the years ended December 31, 2011 and 2010:

 

										Cash Distribution per Common Limited Partner
		High				Low				Declared(1)
Year ended December 31, 2011:
Fourth quarter		$	25.59			$	15.82			$	0.24
Third quarter		$	25.72			$	17.69			$	0.24
Second quarter		$	27.36			$	20.41			$	0.22
First quarter		$	23.24			$	13.11			$	0.11
Year ended December 31, 2010:
Fourth quarter		$	15.44			$	8.86			$	0.07
Third quarter		$	9.88			$	3.76			$	0.05
Second quarter		$	6.80			$	3.67			$	—
First quarter		$	7.45			$	5.14			$	—

 

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

 

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We have a cash distribution policy under which we distribute, within 50 days after the end of each quarter, all of our available cash (as defined in the partnership agreement) for that quarter to our common unitholders. See “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations—Cash Distributions.”

For information concerning common units authorized for issuance under our long-term incentive plans, see “Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters – Equity Compensation Plan Information”.

 

ITEM 6.

SELECTED FINANCIAL DATA

We have derived the selected financial data set forth in the following table for each of the years ended December 31, 2011, 2010 and 2009 from our consolidated financial statements appearing elsewhere in this report, which have been audited by Grant Thornton LLP, independent registered public accounting firm. We derived the financial data for the years ended December 31, 2008 and 2007 from our consolidated financial statements which are not included in this report.

The consolidated combined financial statements include our accounts and that of our consolidated subsidiaries, all of which are wholly-owned at December 31, 2011 except for APL, which we control. Due to the structure of our ownership interests in APL, in accordance with generally accepted accounting principles, we consolidate the financial statements of APL into our financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in APL are reflected as income (loss) attributable to non-controlling interests in our consolidated combined statements of operations and as a component of partners’ capital on our consolidated combined balance sheets. Throughout this section, when we refer to “our” consolidated combined financial statements, we are referring to the consolidated combined results for us and our wholly-owned subsidiaries and the consolidated results of APL, adjusted for non-controlling interests in APL.

On February 17, 2011, we acquired certain producing natural gas and oil properties, an investment management business which 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 our 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 purchase method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in our consolidated combined 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 consolidated combined 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 partners’ capital;

 

•

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

 

•

Adjusted the presentation of our consolidated combined 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’ historical

 

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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.

The following table should be read together with our consolidated financial statements and notes thereto included within Item 7: “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8: “Financial Statements and Supplementary Data” of this report.

 

		Years Ended December 31,
		2011				2010				2009				2008				2007
		(in thousands, except per unit data)
Statement of operations data:
Revenues:
Gas and oil production		$	66,979			$	93,050			$	112,979			$	127,083			$	99,015
Well construction and completion			135,283				206,802				372,045				415,036				321,471
Gathering and processing			1,329,753				945,228				714,145				1,185,254				591,570
Administration and oversight			7,741				9,716				15,554				19,277				17,955
Well services			19,803				20,994				17,859				18,513				16,663
Gain (loss) on mark-to-market derivatives			(20,453	)			(5,944	)			(35,815	)			29,741				(104,524	)
Other, net			31,803				17,437				15,295				7,330				5,263
Total revenues			1,570,909				1,287,283				1,212,062				1,802,234				947,413
Costs and expenses:
Gas and oil production			17,100				23,323				25,557				25,104				17,638
Well construction and completion			115,630				175,247				315,546				359,609				279,540
Gathering and processing			1,123,386				790,167				605,222				978,178				450,984
Well services			8,738				10,822				9,330				10,654				9,062
General and administrative			80,584				37,561				38,932				633				63,175
Depreciation, depletion and amortization			109,373				115,655				119,396				111,545				62,841
Goodwill and other asset impairment			6,995				50,669				166,684				615,724				—
Total costs and expenses			1,461,806				1,203,444				1,280,667				2,101,447				883,240
Operating income (loss)			109,103				83,839				(68,605	)			(299,213	)			64,173
(Loss) gain on early extinguishment of debt			(19,574	)			(4,359	)			(2,478	)			17,420				(4,972	)
Gain (loss) on asset sales			256,292				(13,676	)			108,947				—				—
Interest expense			(38,394	)			(90,448	)			(104,053	)			(89,284	)			(60,120	)
Income (loss) from continuing operations			307,427				(24,644	)			(66,189	)			(371,077	)			(919	)
Income (loss) from discontinued operations			(81	)			321,155				84,148				(93,802	)			(23,641	)
Net income (loss)			307,346				296,511				17,959				(464,879	)			(24,560	)
(Income) loss attributable to non-controlling interests			(257,643	)			(245,764	)			(53,924	)			536,455				129,380
Net income (loss) after non-controlling interests			49,703				50,747				(35,965	)			71,576				104,820
(Income) loss not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition)			(4,711	)			(22,813	)			40,000				(145,229	)			(120,467	)
Net income (loss) attributable to common limited partners		$	44,992			$	27,934			$	4,035			$	(73,653	)		$	(15,647	)
Allocation of net income (loss) attributable to common limited partners:
Continuing operations		$	45,002			$	(11,994	)		$	(7,287	)		$	(62,331	)		$	(12,940	)
Discontinued operations			(10	)			39,928				11,322				(11,322	)			(2,707	)
		$	44,992			$	27,934			$	4,035			$	(73,653	)		$	(15,647	)
Net income (loss) attributable to common limited partners per unit:
Basic:
Income (loss) from continuing operations attributable to common limited partners		$	0.91			$	(0.43	)		$	(0.26	)		$	(2.23	)		$	(0.55	)
Income (loss) from discontinued operations attributable to common limited partners			—				1.44				0.41				(0.45	)			(0.11	)
Net income (loss) attributable to common limited partners		$	0.91			$	1.01			$	0.15			$	(2.68	)		$	(0.66	)
Diluted(1):
Income (loss) from continuing operations attributable to common limited partners		$	0.88			$	(0.43	)		$	(0.26	)		$	(2.23	)		$	(0.55	)
Income (loss) from discontinued operations attributable to common limited partners			—				1.44				0.41				(0.45	)			(0.11	)
Net income (loss) attributable to common limited partners		$	0.88			$	1.01			$	0.15			$	(2.68	)		$	(0.66	)
Balance sheet data (at period end):
Property, plant and equipment, net		$	2,093,283				1,849,486			$	1,831,090			$	2,031,774			$	1,675,934
Total assets			2,684,098				2,435,262				2,838,007				3,262,986				3,405,466
Total debt, including current portion			524,140				601,389				1,262,183				1,539,427				1,254,426
Total partners’ capital			1,744,081				1,406,123				1,053,855				1,135,216				1,518,807
Cash flow data:
Net cash provided by operating activities		$	88,195			$	157,253			$	236,664			$	108,844			$	312,115
Net cash provided by (used in) investing activities			14,159				502,330				142,637				(555,123	)			(2,181,118	)
Net cash provided by (used in) financing activities			(25,225	)			(660,439	)			(385,483	)			435,477				1,885,216

 

(1)

For the year ended December 31, 2010, approximately 180,000 stock awards were excluded from the computation of diluted net income (loss) attributable to common limited partners per unit because the inclusion of such common limited partner units would have been anti-dilutive. For the year ended December 31, 2009, approximately 187,000 stock awards were excluded from the computation of diluted net income (loss) attributable to common limited partners per unit because the inclusion of such common limited partner units would have been anti-dilutive. For the year ended December 31, 2008, approximately 553,000 stock awards were excluded from the computation of diluted net income (loss) attributable to common limited partners per unit because the inclusion of such common limited partner units would have been anti-dilutive. For the year ended December 31, 2007, approximately 515,000 stock awards were excluded from the computation of diluted net income (loss) attributable to common limited partners per unit because the inclusion of such common limited partner units would have been anti-dilutive.

 

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ITEM 7:

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

The following discussion provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with “Item 6 – Selected Financial Data” and “Item 8 – Financial Statements and Supplemental Data”.

BUSINESS OVERVIEW

We are a publicly-traded Delaware limited partnership, formerly known as Atlas Pipeline Holdings, L.P. (NYSE: ATLS), and independent developer and producer of natural gas and oil, with operations in the Appalachian Basin, Illinois Basin and the Rocky Mountain region. We sponsor and manage tax-advantaged investment partnerships, in which we co-invest, to finance a portion of our natural gas and oil production activities.

On February 17, 2011, we acquired certain assets and liabilities (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of our general partner (see “Recent Developments”). These assets principally included the following:

 

•

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

 

•

proved reserves located in the Appalachia 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;

 

•

certain producing natural gas and oil properties, upon which we are developers and producers;

 

•

all of the ownership interests in Atlas Energy GP, LLC, our general partner; and

 

•

a direct and indirect ownership interest in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC (collectively, “Lightfoot”), which incubates new MLPs and invest in existing MLPs. At December 31, 2011, we had an approximate 16% general partner interest and 12% limited partner interest in Lightfoot.

We also maintain an ownership interest in Atlas Pipeline Partners, L.P. (“APL”), a publicly traded Delaware limited partnership (NYSE: APL) and midstream energy service provider engaged in the gathering and processing of natural gas in the Mid-Continent and Appalachia regions of the United States. At December 31, 2011, we owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate 10.7% common limited partner interest.

FINANCIAL PRESENTATION

Our consolidated combined financial statements contain our accounts and those of our consolidated subsidiaries, all of which are wholly-owned at December 31, 2011 except for APL, which we control. Due to the structure of our ownership interests in APL, in accordance with generally accepted accounting principles, we consolidate the financial statements of APL into our financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in APL are reflected as income attributable to non-controlling interests in our consolidated combined statements of operations and as a component of partners’ capital on our consolidated combined balance sheets. Throughout this section, when we refer to “our” consolidated combined financial statements, we are referring to the consolidated combined results for us, our wholly-owned subsidiaries and the consolidated results of APL, adjusted for non-controlling interests in APL’s.

In accordance with prevailing accounting literature, we determined that the acquisition of the Transferred Business constituted a transaction between entities under common control (see –“Recent Developments”). In comparison to the purchase method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable assets and liabilities of the Transferred Business with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital. Also, in comparison to the purchase method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in our consolidated combined financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect of the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, we reflected the impact of the acquisition of the Transferred Business on our consolidated combined financial statements in the following manner:

 

•

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

 

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•

Retrospectively adjusted our consolidated combined balance sheet as of December 31, 2010, our consolidated combined statement of partners’ capital for the years ended December 31, 2011, 2010 and 2009, our consolidated combined statements of comprehensive income (loss) for the years ended December 31, 2011, 2010 and 2009, and our consolidated combined statements of operations for the years ended December 31, 2011, 2010 and 2009, and our consolidated combined statements of cash flows for the years ended December 31, 2011, 2010 and 2009 to reflect our results combined with the results of the Transferred Business as of or at the beginning of the respective period; and

 

•

Adjusted the presentation of our consolidated combined statements of operations for the years ended December 31, 2011, 2010 and 2009 to reflect the results of operations attributable to the Transferred Business prior to the date of acquisition as a reduction of net income to determine income attributable to common limited partners. However, the Transferred Business’ 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 Corporation in February 2011 and not activities related to the Transferred Business.

SUBSEQUENT EVENTS

Formation of Atlas Resource Partners, L.P. In February 2012, our General Partner’s board of directors approved the formation of a newly created exploration and production master limited partnership named Atlas Resource Partners, L.P. (“ARP”), which will hold substantially all of our current natural gas and oil development and production assets and the partnership management business. Our General Partner’s board of directors also approved the distribution of approximately 5.24 million ARP common units, which will be distributed on March 13, 2012 to our unitholders using a ratio of 0.1021 ARP limited partner units for each of our common units owned on the record date of February 28, 2012. The distribution of ARP limited partner units will represent an approximate 19.6% limited partner interest. Subsequent to the distribution, we will own a 2% general partner interest, all of the incentive distribution rights in ARP and common units representing an approximate 78.4% limited partner interest in ARP. For a further description of ARP’s cash distribution policy, please see “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations - Cash Distributions”.

Cash Distributions. On January 26, 2012, we declared a cash distribution of $0.24 per unit on our outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2011. The $12.3 million distribution was paid on February 17, 2012 to unitholders of record at the close of business on February 7, 2012.

APL Cash Distributions. On January 26, 2012, APL declared a cash distribution of $0.55 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2011. The $31.5 million distribution, including $5.2 million to us, was paid on February 14, 2012 to unitholders of record at the close of business on February 7, 2012.

RECENT DEVELOPMENTS

APL Senior Notes. In November 2011, APL issued $150.0 million of its 8.75% Senior Notes in a private placement transaction. The 8.75% Senior Notes were issued at a premium of 103.5% of the principal amount for a yield of 7.82%. APL received net proceeds of $154.2 million after underwriting commissions and other transaction costs and utilized the proceeds to reduce the outstanding balance on its revolving credit facility.

Lightfoot Capital Partners. In October 2011, we announced that GE Energy Financial Services, a unit of General Electric, has invested in Lightfoot. GE Financial Services will own a general partner interest and a 58% limited partner interest. Following this investment, we will hold an approximate 16% general partner interest and 12% limited partner interest in Lightfoot.

 

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APL Credit Facility. In July 2011, APL exercised the $100.0 million accordion feature on its revolving credit facility to increase the capacity from $350.0 million to $450.0 million. The other terms of the credit agreement put in place in December 2010 remain unchanged.

APL Pipeline Acquisition. In May 2011, APL acquired a 20% interest in West Texas LPG Pipeline Limited Partnership (“West Texas LPG”) from Buckeye Partners, L.P. for $85.0 million. West Texas LPG owns a common-carrier pipeline system that transports natural gas liquids from New Mexico and Texas to Mont Belvieu for fractionation. West Texas LPG is operated by Chevron Pipeline Company, a subsidiary of Chevron, which owns the remaining 80% interest.

Redemption of APL Senior Notes. In April 2011, APL completed the redemption of all of its 8.125% Senior Notes for a total redemption of $293.7 million, including accrued interest of $7.0 million and premium of $11.2 million. Also in April, APL redeemed $7.2 million of the APL 8.75% Senior Notes, which were tendered upon its offer to purchase the senior notes at par. APL funded its purchase with a portion of the net proceeds from its sale of its 49% non-controlling interest in Laurel Mountain.

Acquisition from AEI. On February 17, 2011, we completed an acquisition of the Transferred Business from AEI, the former parent of our general partner. For the assets acquired and liabilities assumed, we issued approximately 23.4 million of our common limited partner units and paid $30.0 million in cash consideration. Based on our February 17, 2011 common unit closing price of $15.92, the common units issued to AEI were valued at approximately $372.2 million. In connection with the transaction, we also received $118.7 million with respect to a contractual cash transaction adjustment from Chevron related to certain liabilities assumed by the Transferred Business, including certain amounts subject to a reconciliation period following the consummation of the transaction. Including the cash transaction adjustment, the net book value of the Transferred Business was approximately $522.9 million.

Concurrent with our acquisition of the Transferred Business, AEI completed its merger with Chevron Corporation (“Chevron”), whereby AEI became a wholly-owned subsidiary of Chevron. Also concurrent with our acquisition of the Transferred Business and immediately preceding AEI’s merger with Chevron, APL completed its sale to AEI of its 49% non-controlling interest in the Laurel Mountain joint venture (the “Laurel Mountain Sale”). APL received $409.5 million in cash, net of expenses, including adjustments based on certain capital contributions APL made to and distributions it received from the Laurel Mountain joint venture after January 1, 2011. APL retained the preferred distribution rights under the limited liability company agreement of the Laurel Mountain joint venture entitling APL to receive all payments made under the note receivable issued to Laurel Mountain by Williams Laurel Mountain, LLC in connection with the formation of the Laurel Mountain joint venture. The note was paid in full as of December 31, 2011.

CONTRACTUAL REVENUE ARRANGEMENTS

Natural Gas. We market the majority of our natural gas production to gas utility companies, gas marketers, local distribution companies, industrial or other end-users, and companies generating electricity. The sales price of natural gas produced in the Appalachian Basin has been primarily based upon the NYMEX spot market price, the natural gas produced in the New Albany Shale and Antrim Shale has been primarily based upon the Texas Gas Zone SL and Chicago spot market prices, and the gas produced in the Niobrara formation has been primarily based upon the Cheyenne Index. For the year ended December 31, 2011, Chevron, South Jersey Resources Group and Sequent Energy Management accounted for approximately 17%, 14% and 10% of our total natural gas and oil production revenues, respectively, with no other single customer accounting for more than 10% for this period.

Crude Oil. Crude oil produced from our wells flows directly into storage tanks where it is picked up by an oil company, a common carrier or pipeline companies acting for an oil company, which is purchasing the crude oil. We sell any oil produced by our Appalachian wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil.

Natural Gas Liquids. Natural gas liquids (“NGL’s”) are produced by our natural gas processing plants, which extract the natural gas liquids from the natural gas production, enabling the remaining “dry” gas (low BTU content) to meet pipeline specifications for long-haul transport to end users. We sell natural gas liquids produced by our natural gas processing plants to regional refining companies at the prevailing spot market price for natural gas liquids.

We do not have delivery commitments for fixed and determinable quantities of natural gas, oil or natural gas liquids in any future periods under existing contracts or agreements.

 

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Investment Partnerships. We generally have funded a portion of our drilling activities through sponsorship of tax-advantaged investment drilling partnerships. In addition to providing capital for our drilling activities, our investment partnerships are a source of fee-based revenues, which are not directly dependent on natural gas and oil prices. As managing general partner of the investment partnerships, we receive the following fees:

 

•

Well construction and completion. For each well that is drilled by an investment partnership, we receive a 15% to 18% mark-up on those costs incurred to drill and complete the well;

 

•

Administration and oversight. For each well drilled by an investment partnership, we receive a fixed fee of between $15,000 and $250,000, depending on the type of well drilled. Additionally, the partnership pays us a monthly per well administrative fee of $75 for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well;

 

•

Well services. Each partnership pays us a monthly per well operating fee, currently $100 to $1,500, for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the wells; and

 

•

Gathering. Each royalty owner, partnership and certain other working interest owners pay us a gathering fee, which generally ranges from $0.35 per Mcf to the amount of the competitive gathering fee, currently defined as 13% of the gross sales price of the natural gas. In general, pursuant to gathering agreements we have with a third-party gathering system which gathers the majority of our natural gas, we must also pay an additional amount equal to the excess of the gathering fees collected from the investment partnerships up to an amount equal to approximately 16% of the realized natural gas sales price (adjusted for the settlement of natural gas derivative instruments). As a result, some of our gathering expenses within our partnership management segment, specifically those in the Appalachian Basin, will generally exceed the revenues collected from investment partnerships by approximately 3%.

APL Revenue. APL’s principal revenue is generated from the gathering and sale of natural gas, natural gas liquids and condensate. Variables that affect its revenue are:

 

•

the volumes of natural gas APL gathers and processes, which in turn, depend upon the number of wells connected to its gathering systems, the amount of natural gas they produce, and the demand for natural gas, NGLs and condensate;

 

•

the price of the natural gas APL gathers and processes and the NGLs and condensate it recovers and sells, which is a function of the relevant supply and demand in the mid-continent, mid-Atlantic and northeastern areas of the United States;

 

•

the NGL and BTU content of the gas that is gathered and processed;

 

•

the contract terms with each producer; and

 

•

the efficiency of APL’s gathering systems and processing plants.

Under certain agreements, APL purchases natural gas from producers and moves it into receipt points on its pipeline systems and then sells the natural gas and NGLs off of delivery points on its systems. Under other agreements, APL gathers natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas.

GENERAL TRENDS AND OUTLOOK

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

Natural Gas Supply and Outlook. The areas in which we operate are experiencing a significant increase in natural gas production related to new and increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques, including horizontal and multiple fracturing techniques. This increase in the supply of natural gas has put a downward pressure on domestic prices. While we 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 by third parties in the development of new natural gas reserves.

 

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Reserve Outlook. Our future gas and oil reserves, production, cash flow, our ability to make payments on our revolving credit facility and our ability to make distributions to our unitholders depend on our success in producing our current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. We face the challenge of natural production declines and volatile natural gas and oil prices. As initial reservoir pressures are depleted, natural gas production from particular wells decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce.

RESULTS OF OPERATIONS

GAS AND OIL PRODUCTION

Production Profile. Currently, we have focused our natural gas and oil production operations in various shale plays in the northeastern and midwestern United States. As part of our agreement with AEI to acquire the Transferred Business, we have entered into certain agreements which restrict our ability to drill additional wells in certain areas of Pennsylvania, New York and West Virginia, including portions of the Marcellus Shale. Through December 31, 2011, we have established production positions in the following areas:

 

•

the Appalachia basin, including the Marcellus Shale, a rich, organic shale that generally contains dry, pipeline-quality natural gas, and 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 Niobrara Shale in northeastern Colorado, a predominantly biogenic shale play that produces dry gas;

 

•

the New Albany Shale in southwestern Indiana, a biogenic shale play with a long-lived and shallow decline profile; and

 

•

the Antrim Shale in Michigan, where we produce out of the biogenic region of the shale similar to the New Albany Shale;

The following table presents the number of wells we drilled, both gross and for our interest, and the number of gross wells we turned in line during the three years ended December 31, 2011, 2010 and 2009:

 

		Years Ended December 31,
		2011				2010				2009
Gross wells drilled:
Appalachia			22				22				174
New Albany/Antrim			—				66				93
Niobrara			138				29				—
			160				117				267
Our share of gross wells drilled(1):
Appalachia			4				6				45
New Albany/Antrim			—				19				23
Niobrara			27				9				—
			31				34				68
Gross wells turned in line:
Appalachia			9				83				307
New Albany/Antrim			13				76				65
Niobrara			77				8				—
			99				167				372

 

(1)	Includes (i) our percentage interest in the wells in which we have a direct ownership interest and (ii) our percentage interest in the wells based on our percentage ownership in our investment partnerships.

 

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Production Volumes. The following table presents our total net natural gas, oil, and natural gas liquids production volumes and production per day for the years ended December 31, 2011, 2010 and 2009:

 

		Years Ended December 31,
		2011				2010				2009
Production:(1)(2)
Appalachia:(3)
Natural gas (MMcf)			10,163				12,363				13,905
Oil (000’s Bbls)			112				136				156
Natural gas liquids (000s Bbls)			162				182				37
Total (MMcfe)			11,809				14,274				15,062
New Albany/Antrim:
Natural gas (MMcf)			1,148				724				200
Oil (000’s Bbls)			—				—				—
Natural gas liquids (000s Bbls)			—				—				—
Total (MMcfe)			1,148				724				200
Niobrara:
Natural gas (MMcf)			152				—				—
Oil (000’s Bbls)			—				—				—
Natural gas liquids (000s Bbls)			—				—				—
Total (MMcfe)			152				—				—
Total:
Natural gas (MMcf)			11,462				13,087				14,105
Oil (000’s Bbls)			112				136				156
Natural gas liquids (000s Bbls)			162				182				37
Total (MMcfe)			13,108				14,998				15,262
Production per day: (1)(2)
Appalachia:(3)
Natural gas (Mcfd)			27,843				33,872				38,096
Oil (Bpd)			307				373				427
Natural gas liquids (Bpd)			444				499				101
Total (Mcfed)			32,352				39,107				41,267
New Albany/Antrim:
Natural gas (Mcfd)			3,144				1,983				548
Oil (Bpd)			—				—				—
Natural gas liquids (Bpd)			—				—				—
Total (Mcfed)			3,144				1,983				548
Niobrara:
Natural gas (Mcfd)			416				—				—
Oil (Bpd)			—				—				—
Natural gas liquids (Bpd)			—				—				—
Total (Mcfed)			416				—				—
Total:
Natural gas (Mcfd)			31,403				35,855				38,644
Oil (Bpd)			307				373				427
Natural gas liquids (Bpd)			444				499				101
Total (Mcfed)			35,912				41,090				41,814

 

(1)

Production quantities consist of the sum of (i) our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells, and (ii) our proportionate share of production from wells owned by the investment partnerships in which we have an interest, based on our equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells.

(2)

“MMcf” represents million cubic feet; “MMcfe” represent million cubic feet equivalents; “Mcfd” represents thousand cubic feet per day; “Mcfed” represents thousand cubic feet equivalents per day; and “Bbls” and “Bpd” represent barrels and barrels per day. Barrels are converted to Mcfe using the ratio of approximately six Mcf’s to one barrel.

(3)	Appalachia includes our production located in Pennsylvania, Ohio, New York, West Virginia and Tennessee.

 

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Production Revenues, Prices and Costs. Our production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised 94% of our proved reserves on an energy equivalent basis at December 31, 2011. The following table presents our production revenues and average sales prices for our natural gas, oil, and natural gas liquids production for the years ended December 31, 2011, 2010, and 2009, along with our average production costs, taxes, and transmission and compression costs in each of the reported periods:

 

		Years Ended December 31,
		2011				2010				2009
Production revenues (in thousands):
Appalachia:(1)
Natural gas revenue		$	43,310			$	71,726			$	99,024
Oil revenue			10,057				10,541				11,119
Natural gas liquids revenue			7,826				6,879				1,334
Total revenues		$	61,193			$	89,146			$	111,477
New Albany/Antrim:
Natural gas revenue		$	5,154			$	3,904			$	1,502
Oil revenue			—				—				—
Natural gas liquids revenue			—				—				—
Total revenues		$	5,154			$	3,904			$	1,502
Niobrara:
Natural gas revenue		$	632			$	—			$	—
Oil revenue			—				—				—
Natural gas liquids revenue			—				—				—
Total revenues		$	632			$	—			$	—
Total:
Natural gas revenue		$	49,096			$	75,630			$	100,526
Oil revenue			10,057				10,541				11,119
Natural gas liquids revenue			7,826				6,879				1,334
Total revenues		$	66,979			$	93,050			$	112,979
Average sales price:(2)
Natural gas (per Mcf):
Total realized price, after hedge(3)		$	4.98			$	7.08			$	7.54
Total realized price, before hedge(3)		$	4.53			$	4.60			$	4.04
Oil (per Bbl):
Total realized price, after hedge		$	89.70			$	77.31			$	71.34
Total realized price, before hedge		$	89.07			$	71.37			$	57.41
Natural gas liquids (per Bbl) total realized price:		$	48.26			$	37.78			$	36.19
Production costs (per Mcfe):(2)
Appalachia:(1)
Lease operating expenses(4)		$	1.05			$	1.25			$	1.08
Production taxes			0.10				0.03				0.03
Transportation and compression			0.50				0.68				0.68
		$	1.64			$	1.97			$	1.79
New Albany/Antrim:
Lease operating expenses		$	1.14			$	1.59			$	2.54
Production taxes			0.13				0.10				0.05
Transportation and compression			0.03				0.09				0.09
		$	1.31			$	1.77			$	2.67
Niobrara:
Lease operating expenses		$	1.16			$	—			$	—
Production taxes			0.03				—				—
Transportation and compression			0.43				—				—
		$	1.62			$	—			$	—
Total:
Lease operating expenses(4)		$	1.06			$	1.27			$	1.10
Production taxes			0.10				0.04				0.03
Transportation and compression			0.46				0.65				0.68
		$	1.61			$	1.96			$	1.80

 

(1)	Appalachia includes our operations located in Pennsylvania, Ohio, New York, West Virginia and Tennessee.

(2)	“Mcf” represents thousand cubic feet; “Mcfe” represents thousand cubic feet equivalents; and “Bbl” represents barrels.

(3)

Excludes the impact of subordination of our production revenue to investor partners within our investment partnerships for the years ended December 31, 2011, 2010 and 2009. Including the effect of this subordination, the average realized gas sales price was $4.28 per Mcf ($3.83 per Mcf before the effects of financial hedging), $5.78 per Mcf ($3.30 per Mcf before the effects of financial hedging), and $7.13 per Mcf ($3.62 per Mcf before the effects of financial hedging) for the years ended December 31, 2011, 2010 and 2009, respectively.

 

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(4)

Excludes the effects of our proportionate share of lease operating expenses associated with subordination of our production revenue to investor partners within our investment partnerships for the years ended December 31, 2011, 2010 and 2009. Including the effects of these costs, Appalachia lease operating expenses per Mcfe were $0.71 per Mcfe ($1.30 per Mcfe for total production costs), $0.83 per Mcfe ($1.54 per Mcfe for total production costs), and $0.95 per Mcfe ($1.66 per Mcfe for total production costs) for the years ended December 31, 2011, 2010 and 2009, respectively. Including the effects of these costs, total lease operating expenses per Mcfe were $0.75 per Mcfe ($1.30 per Mcfe for total production costs), $0.86 per Mcfe ($1.56 per Mcfe for total production costs), and $0.97 per Mcfe ($1.67 per Mcfe for total production costs) for the years ended December 31, 2011, 2010 and 2009, respectively.

Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010. Total natural gas revenues were $49.1 million for the year ended December 31, 2011, a decrease of $26.5 million from $75.6 million for the year ended December 31, 2010. This decrease consisted of a $24.0 million decrease attributable to lower realized natural gas prices and an $11.5 million decrease attributable to lower production volumes, partially offset by a $9.0 million decrease in gas revenues subordinated to the investor partners within our investment partnerships for the year ended December 31, 2011 compared with the prior year period. Total oil and natural gas liquids revenues were $17.9 million for the year ended December 31, 2011, an increase of $0.4 million from $17.5 million for the comparable prior year period. This increase resulted from a $1.4 million increase associated with higher average oil and natural gas liquids realized prices and a $0.9 million increase from the sale of natural gas liquids, partially offset by a $1.9 million decrease associated with lower oil production volumes. The decrease in natural gas and oil volumes was the result of fewer wells turned in line due to the cancellation of our fall 2010 drilling program, which was the result of AEI’s announcement of the acquisition of the Transferred Business in November 2010. The decrease in gas revenues subordinated to the investor partners within our investment partnerships was related to the overall decrease in natural gas revenue.

Appalachia production costs were $15.4 million for the year ended December 31, 2011, a decrease of $6.6 million from $22.0 million for the year ended December 31, 2010. This decrease was principally due to a $3.8 million decrease in transportation costs, a $3.0 million decrease associated with water hauling and disposal costs, a $0.5 million decrease for labor-related costs and a $1.3 million decrease associated with maintenance expenses and other costs associated with our natural gas and oil operations, partially offset by a $2.0 million decrease associated with our proportionate share of lease operating expenses associated with our revenue that was subordinated to the investor partners within our investment partnerships. The decreases in transportation costs, water hauling and disposal costs, labor-related costs and maintenance expenses and other costs were primarily due to a decrease in natural gas volumes between the periods. New Albany/Antrim production costs were $1.5 million for the year ended December 31, 2011, an increase of $0.2 million from $1.3 million for the comparable prior year period. This increase was primarily attributable to a $0.1 million increase for maintenance and repair expense and a $0.1 million increase associated with parts, materials and other costs associated with our increased natural gas production in New Albany/Antrim.

Year Ended December 31, 2010 Compared with the Year Ended December 31, 2009. Total natural gas revenues were $75.6 million for the year ended December 31, 2010, a decrease of $24.9 million from $100.5 million for the year ended December 31, 2009. This decrease consisted of a $7.8 million decrease attributable to lower natural gas production volumes, a $6.0 million decrease attributable to lower realized natural gas prices and an $11.1 million increase in gas revenues subordinated to the investor partners within our investment partnerships for the year ended December 31, 2010 compared with the prior year. Total oil and natural gas liquids revenues were $17.4 million for the year ended December 31, 2010, an increase of $4.9 million from $12.5 million for the year ended December 31, 2009. This increase resulted from a $5.7 million increase from the sale of natural gas liquids and a $0.8 million increase attributable to higher average oil and natural gas liquids realized prices, partially offset by a $1.6 million decrease associated with lower oil production volumes. The decrease in natural gas and oil volumes was the result of fewer wells turned in line due to the cancellation of our fall 2010 drilling program, which was the result of AEI’s announcement of the acquisition of the Transferred Business in November 2010. The increase in gas revenues subordinated to the investor partners within our investment partnerships was primarily the result of an increase in our natural gas revenues that qualified for subordination to the investor partners within our investment partnerships, partially offset by an overall decrease in our realized natural gas revenues between the periods.

Appalachia production costs were $22.0 million for the year ended December 31, 2010, a decrease of $3.0 million from $25.0 million for the year ended December 31, 2009. This decrease was principally due a $4.1 million increase associated with our proportionate share of lease operating expenses associated with our revenue that was subordinated to the investor partners within our investment partnerships, partially offset by an increase of $1.1 million associated with labor, maintenance expenses and other costs associated with the growth of our operations. New Albany/Antrim production costs were $1.3 million for the year ended December 31, 2010, an increase of $0.8 million from $0.5 million for the prior year. This increase was primarily attributable to an increase in labor, maintenance and compression station expenses associated with the growth of our operations.

 

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PARTNERSHIP MANAGEMENT

Well Construction and Completion

Drilling Program Results. The number of wells we drill will vary within the partnership management segment depending on the amount of capital we raise through our investment 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 we drilled for our investment partnerships during the years ended December 31, 2011, 2010 and 2009. There were no exploratory wells drilled during the years ended December 31, 2011, 2010 and 2009:

 

		Years Ended December 31,
		2011				2010				2009
Drilling partnership investor capital:
Raised		$	141,929			$	149,342			$	353,444
Deployed		$	135,283			$	206,802			$	372,045
Gross partnership wells drilled:
Appalachia			22				22				174
New Albany/Antrim			—				66				93
Niobrara			138				29				—
Total			160				117				267
Net partnership wells drilled:
Appalachia			19				21				159
New Albany/Antrim			—				58				84
Niobrara			138				29				—
Total			157				108				243

Well construction and completion revenues and costs and expenses incurred represent the billings and costs associated with the completion of wells for investment partnerships we sponsor. 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,
		2011				2010				2009
Average construction and completion:
Revenue per well		$	886			$	1,600			$	1,531
Cost per well			757				1,356				1,299
Gross profit per well		$	129			$	244			$	232
Gross profit margin		$	19,653			$	31,555			$	56,499
Partnership net wells associated with revenue recognized(1):
Appalachia			21				44				166
New Albany/Antrim			3				63				77
Niobrara			129				22				—
			153				129				243

 

(1)	Consists of partnership net wells for which well construction and completion revenue was recognized on a percentage of completion basis.

Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010. Well construction and completion segment margin was $19.7 million for the year ended December 31, 2011, a decrease of $11.9 million from $31.6 million for the year ended December 31, 2010. This decrease consisted of a $14.9 million decrease associated with lower gross profit per well, partially offset by a $3.0 million increase related to an increased number of wells recognized for revenue within the investment partnerships. Average revenue and cost per well decreased between periods due to higher capital deployed for Niobrara formation wells within the drilling partnerships during 2011, while 2010 included higher capital deployment pertaining to Marcellus Shale and New Albany/Antrim Shale wells. Typically, the Niobrara formation wells we have drilled within the drilling partnerships have a lower cost per well as compared to the Marcellus Shale and New Albany/Antrim Shale wells. Since our drilling contracts with the investment partnerships are on a “cost-plus” basis, an increase or decrease in our average cost per well also results in a proportionate increase or decrease in our average revenue

 

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per well, which directly affects the number of wells we drill. In addition, the decrease in well construction and completion margin was due to the cancellation of our Fall 2010 drilling program, which occurred following AEI’s announcement of the acquisition of the Transferred Business in November 2010.

Year Ended December 31, 2010 Compared with the Year Ended December 31, 2009. Well construction and completion segment margin was $31.6 million for the year ended December 31, 2010, a decrease of $24.9 million from $56.5 million for the year ended December 31, 2009. This decrease was due to a $26.4 million decrease associated with a decrease in the number of wells recognized for revenue within the investment partnerships, partially offset by a $1.5 million increase associated with higher gross profit per well. The decrease in the number of wells recognized for revenue was the result of the cancellation of our Fall 2010 drilling program, as discussed above.

Our consolidated combined balance sheet at December 31, 2011 includes $71.7 million of “liabilities associated with drilling contracts” for funds raised by our investment 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 consolidated combined statements of operations. We expect to recognize this amount as revenue during 2012.

Administration and Oversight

Administration and oversight fee revenues represent supervision and administrative fees earned for the drilling and subsequent ongoing management of wells for our investment partnerships.

Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010. Administration and oversight fee revenues were $7.7 million for the year ended December 31, 2011, a decrease of $2.0 million from $9.7 million for the year ended December 31, 2010. This decrease was primarily due to a decrease in the number of Marcellus Shale and New Albany Shale wells drilled during the current year period in comparison to the prior year period, partially offset by the increase in the number of wells drilled in the Niobrara Shale during the current year period in comparison to the prior year period. Typically, we receive a lower administration and oversight fee related to the Niobrara formation wells we have drilled within the drilling partnerships as compared to the Marcellus Shale and New Albany/Antrim Shale wells. In addition, the decrease in administration and oversight revenues was due to the cancellation of our Fall 2010 drilling program, which occurred following AEI’s announcement of the acquisition of the Transferred Business in November 2010.

Year Ended December 31, 2010 Compared with the Year Ended December 31, 2009. Administration and oversight fee revenues were $9.7 million for the year ended December 31, 2010, a decrease of $5.9 million from $15.6 million for the year ended December 31, 2009. This decrease was primarily due to a decrease in the number of wells drilled during the current year in comparison to the prior year resulting from the cancellation of our Fall 2010 drilling program, as discussed above.

Well Services

Well service revenue and expenses represent the monthly operating fees we charge and the work our service company performs for our investment partnership wells during the drilling and completing phase as well as ongoing maintenance of these wells and other wells in which we serve as operator.

Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010. Well services revenues were $19.8 million for the year ended December 31, 2011, a decrease of $1.2 million from $21.0 million for year ended December 31, 2010. Well services expenses were $8.7 million for the year ended December 31, 2011, a decrease of $2.1 million from $10.8 million for the year ended December 31, 2010. The decrease in well services revenue and expense is primarily related to a reduction in repairs and maintenance projects due to fewer wells turned in line during the year ended December 31, 2011 as compared with the comparable prior year period.

Year Ended December 31, 2010 Compared with the Year Ended December 31, 2009. Well services revenues were $21.0 million for the year ended December 31, 2010, an increase of $3.1 million from $17.9 million for the year ended December 31, 2009. Well services expenses were $10.8 million for the year ended December 31, 2010, an increase of $1.5 million from $9.3 million for the year ended December 31, 2009. These increases were primarily attributable to a temporary increase in the quantity and scope of ongoing maintenance projects and an increase in the number of producing wells.

Gathering and Processing

Gathering and processing margin includes gathering fees we charge to our investment partnership wells and the related expenses, as well as gross margin for our processing plants in the New Albany Shale and the Chattanooga Shale, and the operating revenues and expenses of APL. The gathering fees charged to our investment partnership wells generally range from $0.35 per Mcf to the amount of the competitive gathering fee, currently defined as 13% of the gross sales price of the

 

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natural gas. In general, pursuant to gathering agreements we have with a third-party gathering system which gathers the majority of our natural gas, we must also pay an additional amount equal to the excess of the gathering fees collected from the investment partnerships up to an amount equal to approximately 16% of the realized natural gas sales price (adjusted for the settlement of natural gas derivative instruments). However, in most of our direct investment partnerships we collect a gathering fee of 13% of the realized natural gas sales price per the respective partnership agreement. As a result, some of our gathering expenses within our partnership management segment, specifically those in the Appalachia Basin, will generally exceed the revenues collected from the investment partnerships by approximately 3%.

The following table presents our gathering and processing revenues and expenses and those attributable to APL for each of the respective periods:

 

		Years Ended December 31,
		2011				2010				2009
Gathering and Processing:
Atlas Energy:
Revenue		$	17,746			$	14,087			$	18,839
Expense			(20,842	)			(20,221	)			(25,269	)
Gross Margin		$	(3,096	)		$	(6,134	)		$	(6,430	)
Atlas Pipeline:
Revenue		$	1,312,007			$	931,141			$	695,306
Expense			(1,102,544	)			(769,946	)			(579,953	)
Gross Margin		$	209,463			$	161,195			$	115,353
Total:
Revenue		$	1,329,753			$	945,228			$	714,145
Expense			(1,123,386	)			(790,167	)			(605,222	)
Gross Margin		$	206,367			$	155,061			$	108,923

Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010. Our net gathering and processing expense for the year ended December 31, 2011 was $3.1 million compared with $6.1 million for the year ended December 31, 2010. This favorable decrease was principally due to lower natural gas volume and prices between the periods.

Gathering and processing margin for APL was $209.5 million for the year ended December 31, 2011 compared with $161.2 million for the year ended December 31, 2010. This increase was due principally to higher production volumes related to on-going capacity expansion projects, as well as higher average natural gas liquids and crude oil commodity prices between periods.

Year Ended December 31, 2010 Compared with the Year Ended December 31, 2009. Our net gathering and processing expense for the year ended December 31, 2010 was $6.1 million compared with $6.4 million for the year ended December 31, 2009. This favorable decrease was principally due to lower natural gas prices as compared with the prior year period, partially offset by an increase in gathering expenses in the Appalachian Basin resulting from a full year of our third-party gathering system agreement formed in June 2009, whereby our gathering expenses generally exceeded the revenues collected from the investment partnerships by approximately 3%.

Gathering and processing margin for APL was $161.2 million for the year ended December 31, 2010 compared with $115.4 million for the year ended December 31, 2009. This increase was due principally to higher production volumes and higher average natural gas liquids and crude oil commodity prices between periods.

Loss on Mark-to-Market Derivatives

Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010. Loss on mark-to-market derivatives was $20.5 million for the year ended December 31, 2011 as compared with $5.9 million for the year ended December 31, 2010. This unfavorable movement was due primarily due to a $33.5 million unfavorable variance in non-cash mark-to-market adjustments on APL’s derivatives and a $15.7 million unfavorable movement in cash settlements on net cash derivative expense related to APL’s commodity based derivatives, partially offset by a $34.6 million favorable variance of net cash derivative expense related to the early termination of a portion of APL’s derivative contracts in the prior period.

Year Ended December 31, 2010 Compared with the Year Ended December 31, 2009. Loss on mark-to-market derivatives was $5.9 million for the year ended

 

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December 31, 2010 as compared with $35.8 million for the year ended December 31, 2009. This favorable movement was due primarily to a $63.6 million favorable variance in non-cash mark-to-market adjustments on APL’s derivatives and $3.9 million favorable variance in non-cash derivative gains related to early termination of a portion of APL’s derivative contracts, partially offset by a $32.3 million unfavorable variance of net cash derivative expense related to the early termination of a portion of APL’s derivative contracts in the prior period, and a $5.3 million unfavorable movement in cash settlements on net cash derivative expense related to APL’s commodity-based derivatives.

Other, Net

Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010. Other, net was $31.8 million for the year ended December 31, 2011 as compared with $17.4 million for the comparable prior year period. This favorable increase was due primarily to a $14.4 million increase associated with our equity earnings in Lightfoot. During the year ended December 31, 2011, we recorded a gain of $15.0 million pertaining to our share of Lightfoot LP’s gain recognized on the sale of International Resource Partners LP, its metallurgical and steam coal business, in March 2011.

Year Ended December 31, 2010 Compared with the Year Ended December 31, 2009. Other, net was $17.4 million for the year ended December 31, 2010 as compared with $15.3 million for the comparable prior year period. This favorable increase was due primarily to a $2.1 million increase associated with our equity earnings in Lightfoot.

OTHER COSTS AND EXPENSES

General and Administrative Expenses

The following table presents our general and administrative expenses and those attributable to APL for each of the respective periods:

 

		Years Ended December 31,
		2011				2010				2009
General and Administrative expenses:
Atlas Energy		$	44,230			$	3,540			$	1,652
Atlas Pipeline			36,354				34,021				37,280
Total		$	80,584			$	37,561			$	38,932

Total general and administrative expenses increased to $80.6 million for the year ended December 31, 2011 compared with $37.6 million for the year ended December 31, 2010. Because the Transferred Business was not accounted for by AEI as a stand-alone business unit, it was not practicable for us to allocate general and administrative expenses to it for historical periods. Therefore, the general and administrative expenses for the years ended December 31, 2010 and 2009 were comprised of our stand-alone general and administrative expenses, while the expenses for the year ended December 31, 2011 were comprised of our stand-alone general and administration expenses and that of the Transferred Business. In addition, our general and administrative expenses for the year ended December 31, 2011 included $19.0 million of reimbursements received from Chevron for the transition services we provided during the period. Our $44.2 million of general and administrative expense for the year ended December 31, 2011 was comprised of $17.8 million of net salary and wages expense, $13.1 million of non-cash compensation expense, $1.8 million of syndication expenses related to the cancellation of our Fall 2010 drilling program, $2.1 million of transaction costs related to the acquisition of the Transferred Business, and $9.4 million of other corporate activities. APL’s $36.4 million of general and administrative expense for the year ended December 31, 2011 represents an increase of $2.3 million from the comparable prior year period, which was principally due to an increase in salaries and wages resulting mainly from the expansion of its business.

Depreciation, Depletion and Amortization

The following table presents our depreciation, depletion and amortization expense and that which was attributable to APL for each of the respective periods:

 

		Years Ended December 31,
		2011				2010				2009
Depreciation, depletion and amortization:
Atlas Energy		$	31,938			$	40,758			$	43,712
Atlas Pipeline			77,435				74,897				75,684
Total		$	109,373			$	115,655			$	119,396

 

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Total depreciation, depletion and amortization decreased to $109.4 million for the year ended December 31, 2011 compared with $115.7 million for the comparable prior year period primarily due to a $9.3 million decrease in our depletion expense. Total depreciation, depletion and amortization decreased to $115.7 million for the year ended December 31, 2010 compared with $119.4 million for the comparable prior year period primarily due to a $3.4 million decrease in our depletion expense. The following table presents our depletion expense per Mcfe for our operations for the respective periods:

 

		Years Ended December 31,
		2011				2010				2009
Depletion expense (in thousands):
Total		$	27,430			$	36,668			$	40,067
Depletion expense as a percentage of gas and oil production revenue			41	%			39	%			35	%
Depletion per Mcfe		$	2.09			$	2.44			$	2.63

Depletion expense varies from period to period and is directly affected by changes in our gas and oil reserve quantities, production levels, product prices and changes in the depletable cost basis of our gas and oil properties. For the year ended December 31, 2011, depletion expense decreased $9.3 million to $27.4 million compared with $36.7 million for the year ended December 31, 2010. Our depletion expense of gas and oil properties as a percentage of gas and oil revenues was 41% for the year ended December 31, 2011, compared with 39% for the year ended December 31, 2010, which was primarily due to a decrease in realized natural gas prices between periods. Depletion expense per Mcfe was $2.09 for the year ended December 31, 2011, a decrease of $0.35 per Mcfe from $2.44 for the year ended December 31, 2010. Depletion expense decreased between periods principally due to the $50.7 million impairment of our Chattanooga and Upper Devonian shale fields recorded during the three months ended December 31, 2010 and an overall decrease in production volumes.

For the year ended December 31, 2010, depletion expense decreased $3.4 million to $36.7 million compared with $40.1 million for the year ended December 31, 2009. Our depletion expense of gas and oil properties as a percentage of gas and oil revenues was 39% for the year ended December 31, 2010, compared with 35% for the year ended December 31, 2009. Depletion expense per Mcfe was $2.44 for the year ended December 31, 2010, a decrease of $0.19 per Mcfe from $2.63 for the year ended December 31, 2009. Depletion expense decreased between periods principally due to an overall decrease in production volumes combined with the $156.4 million impairment of our Upper Devonian Shale field recorded during the three months ended December 31, 2009.

Asset Impairment

During the year ended December 31, 2011, we recognized $7.0 million of asset impairment related to gas and oil properties within property, plant and equipment on the consolidated combined balance sheet for our shallow natural gas wells in the Niobrara Shale. This impairment related to the carrying amount of these gas and oil properties being in excess of our estimate of their fair value at December 31, 2011. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices during the fourth quarter of 2011.

During the year ended December 31, 2010, we recognized $50.7 million of asset impairment related to gas and oil properties within property, plant and equipment on the consolidated combined balance sheet for our shallow natural gas wells in the Chattanooga and Upper Devonian shales. This impairment related to the carrying amount of these gas and oil properties being in excess of our estimate of their fair value at December 31, 2010. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices.

During the year ended December 31, 2009, we recognized $156.4 million of asset impairment related to gas and oil properties within property, plant and equipment on the consolidated combined balance sheet for our shallow natural gas wells in the Upper Devonian Shale. This impairment related to the carrying amount of these gas and oil properties being in excess of our estimate of their fair value at December 31, 2009. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices. In addition, during the year ended December 31, 2009, APL evaluated its long-lived assets for impairment and recognized $10.3 million of impairment related to inactive pipelines and a reduction in estimated useful lives.

Gain (Loss) on Asset Sales

During the year ended December 31, 2011, the gain on asset sales was $256.3 million, compared to a loss of $13.7 million for the year ended December 31, 2010. This increase is principally due to APL’s gain on the sale of its 49% non- controlling interest in the Laurel Mountain joint venture which was finalized and recorded in February 2011.

 

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During the year ended December 31, 2010, the loss on asset sales was $13.7 million, compared to a gain of $108.9 million for the year ended December 31, 2009. This decrease is principally due to APL’s sale of a 51% ownership interest in its Appalachia natural gas gathering system to the Laurel Mountain joint venture during 2009.

Interest Expense and Loss on Early Extinguishment of Debt

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

 

		Years Ended December 31,
		2011				2010				2009
Interest Expense:
Atlas Energy		$	6,791			$	3,175			$	2,744
Atlas Pipeline			31,603				87,273				101,309
Total		$	38,394			$	90,448			$	104,053

Total interest expense decreased to $38.4 million for the year ended December 31, 2011 as compared with $90.4 million for the year ended December 31, 2010. This $52.1 million decrease was primarily due to a $55.7 million decrease related to APL, partially offset by our $3.6 million increase. Our $3.6 million increase in interest expense was primarily due to $4.9 million of accelerated amortization of deferred financing costs for our interim bridge credit facility that was used for the acquisition of the Transferred Business and our note payable to AEI, which was terminated in 2011. The bridge credit facility was terminated and replaced in March 2011. The $55.7 million decrease in interest expense for APL was primarily due to a $21.1 million decrease in interest expense associated with its term loan, an $11.6 million decrease in interest expense associated with its revolving credit facility and a $16.4 million decrease in interest expense associated with its 8.125% Senior Notes. The lower interest expense on APL’s term loan and revolving credit facility was due to the retirement of its term loan and a reduction of its credit facility borrowings with proceeds from the sale of its Elk City system. The lower interest expense on APL’s 8.125% Senior Notes was due to the redemption of the 8.125% Senior Notes in April 2011, with proceeds from the sale of APL’s 49% non-controlling interest in Laurel Mountain.

Total interest expense decreased to $90.4 million for the year ended December 31, 2010 as compared with $104.1 million for the year ended December 31, 2009. This $13.6 million decrease was primarily due to a $14.0 million decrease related to APL, partially offset by our $0.4 million increase. Our $0.4 million increase in interest expense relates to the note payable with AEI, which was terminated in 2011. The $14.0 million decrease in interest expense for APL was due to a $9.5 million decrease in interest rate swap expense due to the interest rate swaps expiring in April 2010 and a $5.8 million decrease in interest expense associated with its term loan. The lower interest expense on APL’s term loan is due to the retirement of the term loan in September 2010 with proceeds from the sale of Elk City.

Loss on early extinguishment of debt of $19.6 million for the year ended December 31, 2011 represents the premium paid for the redemption of the APL 8.125% Senior Notes and APL’s recognition of deferred finance costs related to the redemption. Loss on early extinguishment of debt of $4.4 million for the year ended December 31, 2010 represents the accelerated amortization of deferred financing costs related to the early retirement of APL’s term loan with proceeds from the sale of its Elk City processing and gathering system in September 2010. Loss on extinguishment of debt for the year ended December 31, 2009 represents the accelerated amortization of deferred financing costs related to the early retirement of a portion of APL’s term loan with proceeds from the sale of NOARK gas gathering and interstate pipeline, which was sold in May 2009.

Income (Loss) from Discontinued Operations

For the year ended December 31, 2010, income from discontinued operations, which consists of amounts associated with APL’s Elk City system that was sold in September 2010, was $321.2 million including the gain on sale. For the year ended December 31, 2009, income from discontinued operations, which consists of amounts associated with APL’s NOARK gas gathering and interstate pipeline system that was sold in May 2009 and APL’s Elk City natural gas gathering and processing system that was sold in September 2010, was $84.1 million including the gain on sale.

Income Attributable to Non-Controlling Interests

Income attributable to non-controlling interests was $257.6 million for the year ended December 2011 as compared with $245.8 million for the comparable prior year period. Income attributable to non-controlling interests includes an

 

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allocation of APL’s net income (loss) to non-controlling interest holders. The increase between the year ended December 31, 2011 and the prior year comparable period was primarily due to the increase in APL’s net earnings between periods, which was related to an increase in APL’s gathering and processing revenue.

Income attributable to non-controlling interests was $245.8 million for the year ended December, 2010 as compared with $53.9 million for the comparable prior year period. Income attributable to non-controlling interests includes an allocation of APL’s net income (loss) to non-controlling interest holders. The increase between the year ended December 31, 2010 and the prior year comparable period was primarily due to APL’s increase in net earnings between periods.

LIQUIDITY AND CAPITAL RESOURCES

General

Our primary sources of liquidity are cash generated from operations, capital raised through investment partnerships, and borrowings under our credit facility. Our primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures, and quarterly distributions to our common unitholders. In general, we expect 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 investment partnerships; and

 

•

Debt principal payments through additional borrowings as they become due or by the issuance of additional common units or asset sales.

We rely on cash flow from operations and our credit facility to execute our growth strategy and to meet our financial commitments and other short-term liquidity needs. We cannot be certain that additional capital will be available to us to the extent required and on acceptable terms. We 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 are subject to business, operational and other risks that could adversely affect our cash flow. We may supplement our cash generation with proceeds from financing activities, including borrowings under our credit facility and other borrowings, the issuance of additional common units, the sale of assets and other transactions.

Credit Facility

On March 22, 2011, we entered into a new credit facility with a syndicate of banks that matures in March 2016. The credit facility has maximum lender commitments of $300 million and a current borrowing base of $160 million. The borrowing base is redetermined semiannually in May and November subject to changes in gas and oil reserves and is automatically reduced by 25% of the stated principal of any senior unsecured notes we issued. Up to $20.0 million of the credit facility may be in the form of standby letters of credit. The facility is secured by substantially all of our assets and is guaranteed by substantially all of our subsidiaries (excluding APL and its subsidiaries). The credit agreement contains customary covenants that limit our 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 our assets. The credit agreement also requires us to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to four quarters (actual or annualized, as applicable) of EBITDA (as defined in the credit agreement) not greater than 3.75 to 1.0 as of the last day of any fiscal quarter ending on or after June 30, 2011, a ratio of current assets (as defined in the credit agreement) to current liabilities (as defined in the credit agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter, and a ratio of four quarters (actual or annualized, as applicable) of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) of not less than 2.5 to 1.0 as of the last day of any fiscal quarter ending on or after June 30, 2011. Based on the definitions contained in the credit facility, our ratio of current assets to current liabilities was 1.7 to 1.0, our ratio of Total Funded Debt to EBITDA was 0.01 to 1.0 and our ratio of EBITDA to Consolidated Interest Expense was 63.3 to 1.0 at December 31, 2011.

Upon the closing of the Atlas Resource Partners transaction, most of the collateral which secures our current credit facility will be owned by Atlas Resource Partners. Accordingly, we anticipate that our credit facility will terminate and that Atlas Resource Partners will enter into a senior secured revolving credit facility that will be substantially similar to our current credit facility. We anticipate that the credit facility will allow Atlas Resource Partners to borrow up to the determined amount of the borrowing base, which will be based upon the loan collateral value assigned to our various natural gas and oil properties and other assets.

 

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Cash Flows – Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010

Net cash provided by operating activities of $88.2 million for the year ended December 31, 2011 represented an unfavorable movement of $69.1 million from net cash provided by operating activities of $157.3 million for the comparable prior year period. The decrease was derived principally from a $20.1 million unfavorable movement in working capital, a $64.5 million increase in distributions paid to non-controlling interests and a $23.5 million unfavorable movement in net cash provided by discontinued operations, partially offset by a $30.1 million increase in net income excluding non-cash items and an $8.9 million increase in distributions received from unconsolidated subsidiaries. The non-cash charges which impacted net income include a $332.1 million increase in net income from continuing operations and a favorable movement in non-cash gain on derivatives of $11.7 million, partially offset by a $270.0 million unfavorable movement in gains on asset sales, a $28.8 million unfavorable movement in non-cash expenses, including loss on early extinguishment of debt, asset impairment loss, compensation expense, depreciation, depletion and amortization and amortization of deferred financing costs and a $14.9 million movement in equity income from unconsolidated subsidiaries. The increase in net income from continuing operations was primarily due to a $256.3 million net gain on the sale of APL’s interest in Laurel Mountain, partially offset by a decrease in well construction and completion margin due to the cancellation of our fall 2010 drilling program, which was the result of our announcement of the acquisition of the Transferred Business in November 2010. The movement in cash distributions to non-controlling interest holders was due principally to increases in the cash distributions of APL. The movement in working capital was principally due to a $60.6 million unfavorable movement in accounts receivable and other current assets, due to an increase in subscriptions receivable for funds raised for our new drilling program in the fourth quarter of 2011 and an increase in APL’s accounts receivable between the periods, partially offset by a $40.6 million favorable movement in accounts payable and other current liabilities.

Net cash provided by investing activities of $14.2 million for the year ended December 31, 2011 represented an unfavorable movement of $488.1 million from net cash provided by investing activities of $502.3 million for the comparable prior year period. This unfavorable movement was principally due to a $669.2 million unfavorable movement in cash provided by discontinued investing activities related to APL’s sale of its Elk City system in September 2010, a $70.7 million unfavorable movement in investments in our and APL’s unconsolidated subsidiaries, including APL’s 20% investment in the West Texas LPG Pipeline, a $153.4 million unfavorable movement in capital expenditures and a $0.5 million unfavorable movement in other assets, partially offset by a $405.7 million increase in net proceeds from asset sales associated with APL’s sale of its investment in the Laurel Mountain joint venture. See further discussion of capital expenditures under “- Capital Requirements”.

Net cash used in financing activities of $25.2 million for the year ended December 31, 2011 represented a change of $635.2 million from $660.4 million for the comparable prior year period. This movement was principally due to a net $336.0 million increase in APL’s net borrowings under its credit facility, a $152.4 million increase in net proceeds from the issuance of long-term debt, a $104.2 million decrease in repayments of long-term debt, an $85.5 million non-cash transaction adjustment related to the acquisition of the Transferred Business and a $18.4 million favorable movement in other financing activities, partially offset by a $31.5 million decrease in net proceeds from APL’s equity and preferred unit offerings and an $29.8 million increase in distributions paid to unitholders.

Cash Flows—Year Ended December 31, 2010 Compared with Year Ended December 31, 2009

Net cash provided by operating activities of $157.3 million for the year ended December 31, 2010 represented an unfavorable movement of $79.4 million from net cash provided by operating activities of $236.7 million for the comparable prior year period. The decrease was derived principally from by a $77.1 million unfavorable movement in working capital and an $18.8 million unfavorable movement in net cash provided from discontinued operations, partially offset by a $9.0 million increase in net income excluding non-cash items and a $7.5 million increase in distributions received from unconsolidated subsidiaries. The non-cash charges which impacted net income include a $111.9 million unfavorable movement in non-cash expenses, including asset impairment loss, compensation expense, depreciation, depletion and amortization and amortization of deferred financing costs, an unfavorable movement in non-cash gain on derivatives of $40.6 million and a $2.7 million movement in equity in income from unconsolidated subsidiaries, partially offset by a $41.6 million increase in net income from continuing operations and a $122.6 million favorable movement in loss on asset sales. The increase in net income from continuing operations was primarily due to an increase in APL’s gathering and processing margin partially offset by a decrease in our well construction and completion margin due to the cancellation of our fall 2010 drilling program, which was the result of our announcement of the acquisition of the Transferred Business in November 2010. The movement in working capital was principally due to a $73.8 million unfavorable movement in accounts payable and other current liabilities, due to a reduction in our liabilities associated with drilling contracts and well drilling and completion liabilities in 2010 and a $3.2 million favorable movement in accounts receivable and other current assets.

 

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Net cash provided by investing activities of $502.3 million for the year ended December 31, 2010 represented a favorable movement of $359.7 million from net cash provided by investing activities of $142.6 million for the comparable prior year period. This favorable movement was principally due to a $403.8 million favorable movement in cash provided by discontinued investing activities primarily related to APL’s sale of its Elk City system in September 2010, a $70.2 million favorable movement in capital expenditures and a $2.0 million favorable movement in other assets, partially offset by an $24.8 million unfavorable movement in investments in our and APL’s unconsolidated subsidiaries and a $91.5 million decrease in net proceeds from asset sales. See further discussion of capital expenditures under “- Capital Requirements”.

Net cash used in financing activities of $660.4 million for the year ended December 31, 2010 represented a change of $274.9 million from $385.5 million for the comparable prior year period. This movement was principally due to a net $250.0 million decrease in APL’s net borrowings under its credit facility and a $159.8 million increase in repayments of long-term debt, partially offset by a $22.4 million increase in net proceeds from APL’s equity and preferred unit offerings, a $25.6 million non-cash transaction adjustment related to the acquisition of the Transferred Business, an $83.3 million movement in net investment received from AEI prior to February 17, 2011, a $0.3 million decrease in distributions paid to unitholders and a $3.3 million movement in deferred financing costs and other.

Capital Requirements

Our capital requirements consist primarily of:

 

•

maintenance capital expenditures — capital expenditures we make on an ongoing basis to maintain our current levels of production over the long term; and

 

•

expansion capital expenditures — capital expenditures we make to increase our current levels of production for longer than the short-term and includes new leasehold interests and the development and exploitation of existing leasehold interests through acquisitions and investments in our drilling partnerships.

Atlas Pipeline Partners. APL’s operations require continual investment to upgrade or enhance existing operations and to ensure compliance with safety, operational and environmental regulations. APL’s capital requirements consist primarily of:

 

•

maintenance capital expenditures to maintain equipment reliability and safety and to address environmental regulations; and

 

•

expansion capital expenditures to acquire complementary assets and to expand the capacity of its existing operations.

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

 

		Years Ended December 31,
		2011				2010				2009
Atlas Energy
Maintenance capital expenditures		$	9,833			$	—			$	—
Expansion capital expenditures			37,491				93,608				99,302
Total		$	47,324			$	93,608			$	99,302
Atlas Pipeline
Maintenance capital expenditures		$	18,247			$	10,921			$	3,750
Expansion capital expenditures			227,179				34,831				106,524
Total		$	245,426			$	45,752			$	110,274
Consolidated Combined
Maintenance capital expenditures		$	28,080			$	10,921			$	3,750
Expansion capital expenditures			264,670				128,439				205,826
Total		$	292,750			$	139,360			$	209,576

 

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During the year ended December 31, 2011, our $47.3 million of total capital expenditures consisted primarily of $28.8 million of well costs, principally our investments in the investment partnerships, compared with $56.3 million for the prior year comparable period, $9.5 million of leasehold acquisition costs compared with $17.1 million for the prior year comparable period, $3.2 million of gathering and processing costs compared with $17.2 million for the prior year comparable period and $5.8 million of corporate and other compared with $3.0 million for the prior year comparable period. The decrease in investments in the investment partnerships and gathering and processing costs was the result of the cancellation of the Fall 2010 drilling program. Maintenance capital expenditures were $9.8 million during the year ended December 31, 2011. Prior to our acquisition of the Transferred Business on February 17, 2011, we had no maintenance capital requirements with regard to our gas and oil properties.

During the year ended December 31, 2010, we had $93.6 million of capital expenditures compared with $99.3 million for the year ended December 31, 2009. The decrease was principally due to a $16.0 million decrease in investments in the investment partnerships, which were $73.4 million for the year ended December 31, 2010 compared with $89.4 million for the prior year, partially offset by a $7.3 million increase in gathering and processing costs, which were $17.2 million for the year ended December 31, 2010 compared with $9.9 million for the prior year. The decrease in investments in the investment partnerships was the result of the cancellation of the Fall 2010 drilling program, while the increase in gathering and processing costs was related to the expansion of our compression facilities associated with the wells drilled during the year ended December 31, 2009.

We continuously evaluate acquisitions of gas and oil assets. In order to make any acquisition, we 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 will be successful in our efforts to obtain outside capital. For 2012, we estimate our total capital expenditures, excluding acquisitions, will be approximately $103.3 million related to our natural gas and oil program. This estimate is under continuous review and is subject to ongoing adjustment. We expect to fund these capital expenditures primarily with cash flow from operations and capital raised through our investment partnerships.

Atlas Pipeline Partners. APL’s capital expenditures increased to $245.4 million for the year ended December 31, 2011 compared with $45.8 million for the comparable prior year period. The increase was due principally to costs incurred related to APL’s processing facility expansions, compressor upgrades and pipeline projects.

APL’s capital expenditures decreased to $45.8 million for the year ended December 31, 2010 compared with $110.3 million for the comparable prior year period. The decrease was due primarily to the completion of the Madill to Velma pipeline and the construction of the Consolidator gas plant in the prior year.

As of December 31, 2011, we and APL are committed to expend approximately $159.4 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

OFF BALANCE SHEET ARRANGEMENTS

As of December 31, 2011, our and APL’s off-balance sheet arrangements are limited to our letters of credit outstanding of $0.8 million, APL’s letters of credit outstanding of $0.1 million and commitments to spend $159.4 million related to our drilling and completion expenditures, and our and APL’s capital expenditures.

CASH DISTRIBUTIONS

The board of directors of our general partner has adopted a cash distribution policy, pursuant to our partnership agreement, which requires that we distribute all of our available cash quarterly to our limited partners within 50 days following the end of each calendar quarter in accordance with their respective percentage interests. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of cash reserves established by our general partner to, among other things:

 

•

provide for the proper conduct of our business;

 

•

comply with applicable law, any of our debt instruments or other agreements; or

 

•

provide funds for distributions to our unitholders for any one or more of 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. When our general partner determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level. Our distributions to limited partners are not cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter, our unitholders are not entitled to receive such payments in the future.

 

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Atlas Resource Partners’ Cash Distribution Policy: In connection with the pending distribution of 19.6% of ARP to our unitholders as discussed in “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations – Subsequent Events”, ARP’s partnership agreement requires that it distribute 100% of available cash to its common unitholders and general partner, our wholly-owned subsidiary, 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.

Available cash will initially be distributed 98% to ARP’s common limited partners and 2% to its 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 to common limited partners 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 the following increasing percentage of cash distributed by ARP as it reaches certain target distribution levels:

 

•

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.

APL’S CASH DISTRIBUTIONS

APL’s partnership agreement requires that it distribute 100% of available cash to its common unitholders and general partner, our wholly-owned subsidiary, within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all of APL’s cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments.

APL’s general partner is granted discretion by APL’s 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. When APL’s general partner determines its quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Available cash is initially distributed 98% to APL’s common limited partners and 2% to its general partner. These distribution percentages are modified to provide for incentive distributions to be paid to APL’s general partner if quarterly distributions to common limited partners exceed specified targets. Incentive distributions are generally defined as all cash distributions paid to APL’s general partner that are in excess of 2% of the aggregate amount of cash being distributed. Atlas Pipeline GP agreed to allocate up to $3.75 million of incentive distribution rights per quarter back to APL after Atlas Pipeline GP receives the initial $7.0 million per quarter of incentive distribution rights as set forth in the IDR Adjustment Agreement. During the year ended December 31, 2011, we received incentive distributions of $1.7 million. We did not receive any incentive distributions during the year ended December 31, 2010.

APL Credit Facility

At December 31, 2011, APL had a $450.0 million senior secured revolving credit facility with a syndicate of banks, which matures in December 2015, of which $142.0 million was outstanding. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) three-month LIBOR plus 1.0%, or (ii) the LIBOR rate for the applicable period (each plus the applicable margin). The weighted average interest rate on APL’s outstanding revolving credit facility borrowings at December 31, 2011 was 3.1%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $0.1 million was outstanding at December 31, 2011. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated combined balance sheet at December 31, 2011. At December 31, 2011, APL had $307.9 million of remaining committed capacity under this credit facility, subject to covenant limitations.

 

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Borrowings under APL’s credit facility are secured by a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by the West OK and West TX joint ventures, and by the guarantee of each of APL’s consolidated subsidiaries other than the joint venture companies. The revolving credit facility contains customary covenants, including requirements that APL maintains certain financial thresholds and restrictions on its ability to (i) incur additional indebtedness, (ii) make certain acquisitions, loans or investments, (iii) make distribution payments to its unitholders if an event of default exists, or (iv) enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement.

The events which constitute an event of default for the revolving credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against APL in excess of a specified amount and a change of control in APL’s general partner. APL was in compliance with these covenants as of December 31, 2011.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

The following table summarizes our contractual obligations at December 31, 2011 (in thousands):

 

						Payments Due By Period
		Total				Less than 1 Year				1 – 3 Years				4 – 5 Years				After 5 Years
Contractual cash obligations:
Total debt		$	507,822			$	—			$	—			$	142,000			$	365,822
Interest on total debt(1)			224,543				36,469				72,938				68,367				46,769
Operating leases			12,723				3,395				3,330				2,378				3,620
Capital leases			12,125				2,685				9,440				—				—
Total contractual cash obligations		$	757,213			$	42,549			$	85,708			$	212,745			$	416,211

 

(1)	Based on the interest rates of our and APL’s respective debt components as of December 31, 2011.

 

						Amount of Commitment Expiration Per Period
		Total				Less than 1 Year				1 – 3 Years				4 – 5 Years				After  5 Years
Other commercial commitments:
Standby letters of credit		$	910			$	910			$	—			$	—			$	—
Other commercial commitments(1)			26,740				12,385				14,355				—				—
Total commercial commitments		$	27,650			$	13,295			$	14,355			$	—			$	—

 

(1)

Our other commercial commitments include our share of capital contributions associated with the funds raised during our Fall 2011 drilling program and APL’s through-put contracts. We do not have delivery commitments for fixed and determinable quantities of natural gas or oil in any future periods under existing contracts or agreements.

ISSUANCE OF UNITS

Pursuant to prevailing accounting literature, we recognize gains on APL’s equity transactions as a credit to partners’ capital rather than as income. These gains represent our portion of the excess net offering price per unit of each of APL’s common units over the book carrying amount per unit.

In February 2011, we paid $30.0 million in cash and issued approximately 23.4 million newly issued common limited partner units for the Transferred Business acquired from AEI. Based on our common limited partner unit’s February 17, 2011 closing price on the NYSE, the common units issued to AEI were valued approximately at $372.2 million.

Atlas Pipeline Partners

In June 2010, APL sold 8,000 newly-created 12% Cumulative Class C Limited Partner Preferred Units (the “APL Class C Preferred Units”) to AEI for cash consideration of $1,000 per APL Class C Preferred Unit (the “Face Value”). The APL Class C Preferred Units were redeemable by APL for an amount equal to the Face Value of the units being redeemed plus all accrued but unpaid dividends. AEI was entitled to distributions of 12% per annum, paid quarterly on the same date

 

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as the distribution payment date for APL’s common units. On February 17, 2011, the APL Class C Preferred Units were acquired from AEI by Chevron as part of AEI’s merger with Chevron. On May 27, 2011, APL redeemed all 8,000 APL Class C Preferred Units outstanding for cash at the liquidation value of $1,000 per unit, or $8.0 million, plus $0.2 million, representing the accrued dividend on the 8,000 APL Class C Preferred Units prior to APL’s redemption. At December 31, 2011, APL had no APL Class C Preferred Units outstanding.

In January 2010, APL executed amendments to the warrants to purchase 2,689,765 of its common units. The warrants were originally issued along with its common units in connection with a private placement to institutional investors that closed in August 2009. The amendments to the warrants provided that, for the period January 8 through January 12, 2010, the warrant exercise price was lowered to $6.00 from $6.35 per unit. In connection with the amendments, the holders of the warrants agreed to exercise all of the warrants for cash, which resulted in net cash proceeds of approximately $15.3 million. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan and to fund the early termination of certain derivative agreements.

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 Regulations”). 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 have ongoing environmental compliance programs. However, risks of accidental leaks or spills are associated with our and their 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 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 and use, storage and handling of chemical substances, that may impact human health, the environment and/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.

CHANGES IN PRICES AND INFLATION

Our revenues, the value of our assets, our and our subsidiaries’ ability to obtain bank loans or additional capital on attractive terms, and our ability to finance our drilling activities through drilling investment partnerships, have been and will continue to be affected by changes in natural gas and oil market prices. Natural gas and oil prices are subject to significant fluctuations that are beyond our ability to control or predict.

Inflation affects the operating expenses of our operations. Inflationary trends may occur if commodity prices were to increase, since such an increase may cause the demand for energy equipment and services to increase, thereby increasing the costs of acquiring or obtaining such equipment and services. Increases in those expenses are not necessarily offset by increases in revenues and fees that our operations are able to charge. While we anticipate that inflation will affect our future operating costs, we cannot predict the timing or amounts of any such effects.

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 of 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

 

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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 combined financial statements included in “Item 8: Financial Statements and Supplementary Data”. 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 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. 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.

During the year ended December 31, 2011, the Partnership recognized $7.0 million of asset impairment related to gas and oil properties within property, plant and equipment on its consolidated combined balance sheet for its shallow natural gas wells in the Niobrara Shale. During the year ended December 31, 2010, the Partnership recognized $50.7 million of asset impairment related to gas and oil properties within property, plant and equipment on its consolidated combined balance sheet for its shallow natural gas wells in the Chattanooga and Upper Devonian shales. During the year ended December 31, 2009, the Partnership recorded $156.4 million of asset impairment related to gas and oil properties within property, plant and equipment on its consolidated combined balance sheet for its shallow natural gas wells in the Upper Devonian Shale. These impairments related to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2011, 2010 and 2009. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement. In addition, during the year ended December 31, 2009, APL evaluated its long-lived assets for impairment and recognized $10.3 million of impairment related to inactive pipelines and a reduction in estimated useful lives. No impairment charges were recognized by APL for the years ended December 31, 2011 and 2010.

Goodwill and Intangibles with Infinite Lives. Goodwill and intangibles with infinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment loss should be recognized if the carrying value of an entity’s reporting units exceeds its estimated fair value.

There were no goodwill impairments recognized by us during the years ended December 31, 2011, 2010 and 2009.

Fair Value of Financial Instruments

We 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 APL’s outstanding derivative contracts.

 

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Our and APL’s commodity hedges, with the exception of APL’s NGL fixed price swaps and NGL options, 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. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of natural gas, crude oil and propane prices and therefore are defined as Level 3 fair value measurements. Valuations for APL’s NGL options are based on forward price curves developed by the related financial institution and therefore are defined as Level 3 fair value measurements.

Liabilities that are required to be measured at fair value on a nonrecurring basis include our asset retirement obligations (“ARO’s”) that are defined as Level 3. Estimates of the fair value of ARO’s 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.

Reserve Estimates

Our estimates of proved natural gas and oil 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 and oil prices, drilling and operating expenses, capital expenditures and availability of funds. Any significant variance in these assumptions could materially affect the estimated quantity of our reserves. As a result, our estimates of proved natural gas and oil reserves are inherently imprecise. Actual future production, natural gas and oil prices, revenues, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves may vary substantially from our estimates or estimates contained in the reserve reports and may affect our ability to pay amounts due under our credit facility or cause a reduction in our credit facility. In addition, our proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing natural gas and oil prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control.

Asset Retirement Obligations

On an annual basis, we and our subsidiaries estimate the cost of future dismantlement, restoration, reclamation and abandonment of our operating assets. We and our subsidiaries also estimate the salvage value of equipment recoverable upon abandonment. As of December 31, 2011 and 2010, the estimate of salvage values was greater than or equal to our estimate of the costs of future dismantlement, restoration, reclamation and abandonment. Projecting future retirement cost estimates is difficult as it involves the estimation of many variables such as economic recoveries of reserves, future labor and equipment rates, future inflation rates and our subsidiaries’ credit adjusted risk free rate. To the extent future revisions to these assumptions impact the fair value of our existing asset retirement obligation, a corresponding adjustment is made to our gas and oil properties and other property, plant and equipment. A decrease in salvage values or an increase in dismantlement, restoration, reclamation and abandonment costs from those we and our subsidiaries have estimated, or changes in their estimates or costs, could reduce our gross profit from operations.

 

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 potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and natural gas and oil 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 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 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, 2011. 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.

 

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Current market conditions elevate our concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us, if any. The counterparties related to our commodity derivative and interest-rate derivative contracts are banking institutions or their affiliates, who also participate in our revolving credit facilities. The creditworthiness of our counterparties is constantly monitored, and we currently believe them to be financially viable. We are not aware of any inability on the part of our counterparties to perform under their contracts and believe our exposure to non-performance is remote.

Interest Rate Risk. At December 31, 2011, we had no outstanding borrowings under our $160.0 million revolving credit facility. At December 31, 2011, APL had $142.0 million of outstanding borrowings under its $450.0 million senior secured revolving credit facility. Holding all other variables constant, a hypothetical 100 basis-point or 1% change in variable interest rates would change our consolidated combined interest expense, net of non-controlling interests, by $0.2 million.

Commodity Price Risk. Our market risk exposure to commodities is due to the fluctuations in the price of natural gas, natural gas liquids, condensate and oil and the impact those price movements have on the financial results of us and our subsidiaries. To limit our exposure to changing natural gas, oil, and natural gas liquids prices, we use financial derivative instruments for a portion of our future natural gas and oil production. We enter into financial swap and option instruments to hedge forecasted sales against the variability in expected future cash flows attributable to changes in market prices. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, natural gas liquids, condensate and oil are sold. Under these swap agreements, we 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 natural gas, natural gas liquids, condensate and oil at a fixed price for the relevant period.

Holding all other variables constant, including the effect of commodity derivatives, a 10% change in the average price of natural gas, natural gas liquids, condensate and oil would result in a change to our consolidated combined operating income from continuing operations attributable to common limited partners for the twelve-month period ending December 31, 2012 of approximately $3.5 million, net of non-controlling interests.

Realized pricing of our 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 exposure to changing natural gas, oil and natural gas liquids prices, we enter into natural gas and oil swap 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 futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. 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.

At December 31, 2011, 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)
2012			5,520,000			$	5.000
2013			3,120,000			$	5.288
2014			2,880,000			$	5.590
2015			2,880,000			$	5.861

 

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Natural Gas Costless Collars

 

Production Period Ending December 31,		Option Type		Volumes				Average Floor and  Cap
				(mmbtu)(1)				(per mmbtu) (1)
2012		Puts purchased			4,320,000			$	4.074
2012		Calls sold			4,320,000			$	5.279
2013		Puts purchased			5,520,000			$	4.395
2013		Calls sold			5,520,000			$	5.443
2014		Puts purchased			3,840,000			$	4.221
2014		Calls sold			3,840,000			$	5.120
2015		Puts purchased			3,840,000			$	4.296
2015		Calls sold			3,840,000			$	5.233

Crude Oil Costless Collars

 

Production Period Ending December 31,		Option Type		Volumes				Average Floor and  Cap
				(Bbl) (1)				(per Bbl) (1)
2012		Puts purchased			60,000			$	90.000
2012		Calls sold			60,000			$	117.912
2013		Puts purchased			60,000			$	90.000
2013		Calls sold			60,000			$	116.396
2014		Puts purchased			24,000			$	80.000
2014		Calls sold			24,000			$	121.250
2015		Puts purchased			24,000			$	80.000
2015		Calls sold			24,000			$	120.750

 

(1)	“Mmbtu” represents million British Thermal Units; “Bbl” represents barrels.

As of December 31, 2011, APL had the following commodity derivatives:

Fixed Price Swaps

 

Production Period		Sold		Commodity		Volumes				Average Fixed Price
Natural Gas Liquids
2012		Sold		Ethane			6,678,000			$	0.744
2012		Sold		Propane			19,278,000			$	1.302
2012		Sold		Normal Butane			5,292,000			$	1.769
2012		Sold		Isobutane			2,646,000			$	1.657
2012		Sold		Natural Gasoline			4,158,000			$	2.401
2013		Sold		Propane			10,080,000			$	1.251
2013		Sold		Normal Butane			1,512,000			$	1.610
Crude Oil
2012		Sold		Crude Oil			303,000			$	95.612
2013		Sold		Crude Oil			156,000			$	92.776

Options

 

Production Period		Purchased/ Sold		Commodity		Volumes(1)				Average Strike Price
Natural Gas
2012		Purchased		Ethane			3,150,000			$	0.718
2012		Purchased		Propane			28,476,000			$	1.386
2012		Purchased		Normal Butane			5,166,000			$	1.552
2012		Purchased		Isobutane			3,654,000			$	1.617
2012		Purchased		Natural Gasoline			13,608,000			$	2.087
2013		Purchased		Normal Butane			10,458,000			$	1.667
2013		Purchased		Isobutane			4,158,000			$	1.687
2013		Purchased		Natural Gasoline			23,940,000			$	2.108
Crude Oil
2012		Sold(2)		Crude Oil			498,000			$	94.694
2012		Purchased(2)		Crude Oil			180,000			$	125.200
2012		Purchased		Crude Oil			180,000			$	106.421
2013		Purchased		Crude Oil			282,000			$	100.100

 

(1)	Volumes for natural gas are stated in MMBTU’s. Volumes for NGLs are stated in gallons. Volumes for crude oil are stated in barrels.

(2)	Calls purchased for 2012 represent offsetting positions for calls sold as part of a costless collar. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise.

 

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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, L.P.

We have audited the accompanying consolidated combined balance sheets of Atlas Energy, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2011 and 2010, and the related consolidated combined statements of operations, comprehensive income (loss), partners’ capital and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Partnership’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 consolidated combined financial statements referred to above present fairly, in all material respects, the financial position of Atlas Energy, L.P. and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, 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 Partnership’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 28, 2012 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 28, 2012

 

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED BALANCE SHEETS

(in thousands, except share and per share data)

 

		December 31,
		2011				2010
ASSETS
Current assets:
Cash and cash equivalents		$	77,376			$	247
Accounts receivable			136,853				120,697
Current portion of derivative asset			15,447				36,621
Subscriptions receivable			34,455				—
Prepaid expenses and other			24,779				23,652
Total current assets			288,910				181,217
Property, plant and equipment, net			2,093,283				1,849,486
Intangible assets, net			104,777				128,543
Investment in joint venture			86,879				153,358
Goodwill, net			31,784				31,784
Long-term derivative asset			30,941				36,125
Other assets, net			47,524				54,749
		$	2,684,098			$	2,435,262
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current portion of long-term debt		$	2,085			$	35,625
Accounts payable			93,554				75,339
Liabilities associated with drilling contracts			71,719				65,072
Accrued producer liabilities			88,096				72,996
Current portion of derivative liability			—				4,917
Current portion of derivative payable to Drilling Partnerships			20,900				30,797
Accrued interest			1,629				1,921
Accrued well drilling and completion costs			17,585				30,126
Advances from affiliates			—				14,335
Accrued liabilities			61,653				42,654
Total current liabilities			357,221				373,782
Long-term debt, less current portion			522,055				565,764
Long-term derivative liability			—				11,901
Long-term derivative payable to Drilling Partnerships			15,272				34,796
Other long-term liabilities			45,469				42,896
Commitments and contingencies
Partners’ Capital:
Common limited partners’ interests			554,999				413,054
Accumulated other comprehensive income			29,376				3,882
			584,375				416,936
Non-controlling interests			1,159,706				989,187
Total partners’ capital			1,744,081				1,406,123
		$	2,684,098			$	2,435,262

See accompanying notes to consolidated combined financial statements

 

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

 

		Years Ended December 31,
		2011				2010				2009
Revenues:
Gas and oil production		$	66,979			$	93,050			$	112,979
Well construction and completion			135,283				206,802				372,045
Gathering and processing			1,329,753				945,228				714,145
Administration and oversight			7,741				9,716				15,554
Well services			19,803				20,994				17,859
Loss on mark-to-market derivatives			(20,453	)			(5,944	)			(35,815	)
Other, net			31,803				17,437				15,295
Total revenues			1,570,909				1,287,283				1,212,062
Costs and expenses:
Gas and oil production			17,100				23,323				25,557
Well construction and completion			115,630				175,247				315,546
Gathering and processing			1,123,386				790,167				605,222
Well services			8,738				10,822				9,330
General and administrative			80,584				37,561				38,932
Depreciation, depletion and amortization			109,373				115,655				119,396
Asset impairment			6,995				50,669				166,684
Total costs and expenses			1,461,806				1,203,444				1,280,667
Operating income (loss)			109,103				83,839				(68,605	)
Loss on early extinguishment of debt			(19,574	)			(4,359	)			(2,478	)
Gain (loss) on asset sales			256,292				(13,676	)			108,947
Interest expense			(38,394	)			(90,448	)			(104,053	)
Income (loss) from continuing operations			307,427				(24,644	)			(66,189	)
Discontinued operations:
Gain (loss) on sale of discontinued operations			—				312,102				53,571
Income from discontinued operations			(81	)			9,053				30,577
Net income			307,346				296,511				17,959
Income attributable to non-controlling interests			(257,643	)			(245,764	)			(53,924	)
Income (loss) after non-controlling interests			49,703				50,747				(35,965	)
(Income) loss not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition (see Note 2))			(4,711	)			(22,813	)			40,000
Net income attributable to common limited partners		$	44,992			$	27,934			$	4,035
Net income attributable to common limited partners per unit – basic:
Income (loss) from continuing operations attributable to common limited partners		$	0.91			$	(0.43	)		$	(0.26	)
Income from discontinued operations attributable to common limited partners			—				1.44				0.41
Net income attributable to common limited partners		$	0.91			$	1.01			$	0.15
Net income attributable to common limited partners per unit – diluted:
Income (loss) from continuing operations attributable to common limited partners		$	0.88			$	(0.43	)		$	(0.26	)
Income from discontinued operations attributable to common limited partners			—				1.44				0.41
Net income attributable to common limited partners		$	0.88			$	1.01			$	0.15
Weighted average common limited partner units outstanding:
Basic			48,235				27,718				27,663
Diluted			49,694				27,718				27,663
Income attributable to common limited partners:
Income (loss) from continuing operations		$	45,002			$	(11,994	)		$	(7,287	)
Income (loss) from discontinued operations			(10	)			39,928				11,322
Net income attributable to common limited partners		$	44,992			$	27,934			$	4,035

See accompanying notes to consolidated combined financial statements

 

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

 

		Years Ended December 31,
		2011				2010				2009
Net income		$	307,346			$	296,511			$	17,959
Income attributable to non-controlling interests			(257,643	)			(245,764	)			(53,924	)
(Income) loss not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of the acquisition (see Note 2))			(4,711	)			(22,813	)			40,000
Net income attributable to common unitholders			44,992				27,934				4,035
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges			35,156				25,801				25,577
Less: reclassification adjustment for realized (gains) losses in net income			(3,708	)			1,343				14,278
Changes in non-controlling interest related to items in other comprehensive income (loss)			(5,954	)			(32,848	)			(46,517	)
Total other comprehensive income (loss)			25,494				(5,704	)			(6,662	)
Comprehensive income (loss) attributable to common unitholders		$	70,486			$	22,230			$	(2,627	)

See accompanying notes to consolidated combined financial statements

 

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED STATEMENTS OF PARTNERS’ CAPITAL

(in thousands, except share data)

 

										Accumulated
		Common Limited								Other				Non-				Total
		Partners’ Capital								Comprehensive				Controlling				Partners’
		Shares				Amount				Income (Loss)				Interests				Capital
Balance, January 1, 2009			27,659,154				487,865				16,248				631,103				1,135,216
Issuance of common units to the public			—				(45	)			—				16,074				16,029
Net transaction adjustment related to the acquisition of the Transferred Business (see Note 3)			—				(106,289	)			—				—				(106,289	)
APL distributions to non-controlling interests			—				—				—				(23,326	)			(23,326	)
Unissued common units under incentive plans			—				563				—				702				1,265
Issuance of common units under incentive plans			44,425				—				—				—				—
Distributions paid to common limited partners			—				(1,660	)			—				—				(1,660	)
Distribution equivalent rights paid on unissued units under incentive plans			—				(14	)			—				(59	)			(73	)
APL preferred unit distribution			—				—				—				(775	)			(775	)
APL preferred unit redemption			—				—				—				(25,000	)			(25,000	)
Other comprehensive (loss) income			—				—				(6,662	)			47,171				40,509
Net loss on purchase and sale of APL units			—				(5,172	)			—				5,172				—
Loss not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition (see Note 2))			—				(40,000	)			—				—				(40,000	)
Net income			—				4,035				—				53,924				57,959
Balance at December 31, 2009			27,703,579				339,283				9,586				704,986				1,053,855
Net transaction adjustment related to the acquisition of the Transferred Business (see Note 3)			—				25,627				—				—				25,627
Issuance of common units to the public			—				—				—				15,319				15,319
Issuance of common units under incentive plans			131,675				—				—				156				156
APL distributions to non-controlling interests			—				—				—				(23,236	)			(23,236	)
Unissued common units under incentive plans			—				1,245				—				3,484				4,729
Other comprehensive (loss) income			—				—				(5,704	)			32,918				27,214
Repurchase and retirement of common limited partner units			—				—				—				(246	)			(246	)
Distributions paid to common limited partners			—				(1,385	)			—				—				(1,385	)
Distribution equivalent rights paid on unissued units under incentive plans			—				(7	)			—				(174	)			(181	)
APL preferred unit distribution			—				—				—				(240	)			(240	)
APL issuance of preferred units			—				—				—				8,000				8,000
Net loss on purchase and sale of APL equity			—				(2,456	)			—				2,456				—
Income not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition (see Note 2))			—				22,813				—				—				22,813
Net income			—				27,934				—				245,764				273,698
Balance at December 31, 2010			27,835,254			$	413,054			$	3,882			$	989,187			$	1,406,123
Issuance of common limited partner units related to the acquisition of the Transferred Business (see Note 3)			23,379,384				372,200				—				—				372,200
Net transaction adjustment related to the acquisition of the Transferred Business (see Note 3)			—				(261,042	)			—				—				(261,042	)
APL distributions to non-controlling interests			—				—				—				(87,094	)			(87,094	)
Unissued common units under incentive plans			—				13,101				—				3,003				16,104
Issuance of units under incentive plans			63,724				167				—				468				635
Distributions paid to common limited partners			—				(31,164	)			—				—				(31,164	)
Distribution equivalent rights paid on unissued units under incentive plans			—				(1,020	)			—				(764	)			(1,784	)
APL preferred unit distribution			—				—				—				(629	)			(629	)
APL preferred unit redemption			—				—				—				(8,000	)			(8,000	)
Other comprehensive income			—				—				25,494				5,892				31,386
Income not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition (see Note 2))			—				4,711				—				—				4,711
Net income			—				44,992				—				257,643				302,635
Balance at December 31, 2011			51,278,362			$	554,999			$	29,376			$	1,159,706			$	1,744,081

See accompanying notes to consolidated combined financial statements

 

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED STATEMENTS OF CASH FLOWS

(in thousands)

 

		Years Ended December 31,
		2011				2010				2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	307,346			$	296,511			$	17,959
Income (loss) from discontinued operations			(81	)			321,155				84,148
Income (loss) from continuing operations			307,427				(24,644	)			(66,189	)
Adjustments to reconcile net income (loss) from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization			109,373				115,655				119,396
Asset impairment loss			6,995				50,669				166,684
Amortization of deferred finance costs			5,105				10,618				8,178
Non-cash gain on derivative value, net			16,312				4,609				45,200
Non-cash compensation expense			16,104				4,729				1,265
(Gain) loss on asset sales and dispositions			(256,292	)			13,676				(108,947	)
Loss on early extinguishment of debt			19,574				4,359				2,478
Distributions paid to non-controlling interests			(87,857	)			(23,410	)			(23,385	)
Equity income in unconsolidated companies			(21,582	)			(6,701	)			(4,043	)
Distributions received from unconsolidated companies			20,643				11,784				4,310
Changes in operating assets and liabilities:
Accounts receivable and prepaid expenses and other			(66,251	)			(5,640	)			(2,403	)
Accounts payable and accrued liabilities			18,725				(21,825	)			51,978
Net cash provided by continuing operating activities			88,276				133,879				194,522
Net cash provided by (used in) discontinued operating activities			(81	)			23,374				42,142
Net cash provided by operating activities			88,195				157,253				236,664
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures			(292,750	)			(139,360	)			(209,576	)
Investments in unconsolidated companies			(97,250	)			(26,514	)			(1,680	)
Net proceeds from asset sales			403,668				(2,019	)			89,472
Other			491				1,031				(966	)
Net cash provided by (used in) continuing investing activities			14,159				(166,862	)			(122,750	)
Net cash provided by discontinued investing activities			—				669,192				265,387
Net cash provided by investing activities			14,159				502,330				142,637
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facilities			1,585,500				482,000				694,000
Repayments under credit facilities			(1,513,500	)			(746,000	)			(708,000	)
Net proceeds from issuance of long-term debt			152,366				—				—
Repayments of long-term debt			(329,314	)			(433,505	)			(273,675	)
Net proceeds from equity offerings			—				15,475				11,119
Issuance of Atlas Pipeline Partners, L.P.’s preferred units			—				8,000				4,955
Redemption of Atlas Pipeline Partners, L.P.’s preferred units			(8,000	)			—				(15,000	)
Distributions paid to unitholders			(31,164	)			(1,385	)			(1,660	)
Net transaction adjustment related to the acquisition of the Transferred Business (see Note 3)			111,158				25,627				—
Net investment received from Atlas Energy, Inc. prior to February 17, 2011 (see Note 3)			—				—				(83,289	)
Deferred financing costs and other			7,729				(10,651	)			(13,933	)
Net cash used in financing activities			(25,225	)			(660,439	)			(385,483	)
Net change in cash and cash equivalents			77,129				(856	)			(6,182	)
Cash and cash equivalents, beginning of year			247				1,103				7,285
Cash and cash equivalents, end of year		$	77,376			$	247			$	1,103

See accompanying notes to consolidated combined financial statements

 

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED COMBINED FINANCIAL STATEMENTS

NOTE 1 – BASIS OF PRESENTATION

Atlas Energy, L.P., (the “Partnership” or “Atlas Energy”) is a publicly-traded Delaware limited partnership, formerly known as Atlas Pipeline Holdings, L.P. (NYSE: ATLS). On February 17, 2011, the Partnership acquired certain producing natural gas and oil properties, a partnership management business which 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 its general partner (see Note 3).

The Partnership also maintains ownership interests in the following entities:

 

•

Atlas Pipeline Partners, L.P. (“APL”), a publicly traded Delaware limited partnership (NYSE: APL) and midstream energy service provider engaged in the gathering and processing of natural gas in the Mid-Continent and Appalachia regions of the United States. At December 31, 2011, the Partnership owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate 10.7% common limited partner interest; and

 

•

Lightfoot Capital Partners, LP (“Lightfoot LP”) and Lightfoot Capital Partners GP, LLC (“Lightfoot GP”), the general partner of Lightfoot L.P. (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. At December 31, 2011, the Partnership had an approximate 16% general partner interest and 12% limited partner interest in Lightfoot (see Note 7).

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Combination

The consolidated combined financial statements include the accounts of the Partnership and its consolidated subsidiaries, all of which are wholly-owned at December 31, 2011 except for APL, which is controlled by the Partnership. Due to the structure of the Partnership’s ownership interests in APL, in accordance with generally accepted accounting principles, the Partnership consolidates the financial statements of APL into its consolidated combined financial statements rather than present its ownership interest as equity investments. As such, the non-controlling interests in APL are reflected as income attributable to non-controlling interests in its consolidated combined statements of operations and as a component of partners’ capital on its consolidated combined balance sheets. All material intercompany transactions have been eliminated.

In accordance with prevailing accounting literature, management of the Partnership determined that the acquisition of the Transferred Business constituted a transaction between entities under common control (see Note 3). In comparison to the purchase method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable assets and liabilities of the Transferred Business based upon their fair values with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital on the Partnership’s consolidated combined balance sheet. Also, in comparison to the purchase method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in the Partnership’s consolidated combined financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect to the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, the Partnership reflected the impact of the acquisition of the Transferred Business on its consolidated combined financial statements in the following manner:

 

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

 

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Retrospectively adjusted the Partnership’s consolidated combined balance sheet as of December 31, 2010, the Partnership’s consolidated combined statement of partners’ capital for the years ended December 31, 2011, 2010 and 2009, the Partnership’s consolidated combined statements of comprehensive income (loss) for the years ended

 

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December 31, 2011, 2010 and 2009, and the Partnership’s consolidated combined statements of operations for the years ended December 31, 2011, 2010 and 2009, and the Partnership’s consolidated combined statements of cash flows for the years ended December 31, 2011, 2010 and 2009 and the notes to such consolidated combined financial statements to reflect the Partnership’s results combined with the results of the Transferred Business as of or at the beginning of the respective period; and

 

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Adjusted the presentation of the Partnership’s consolidated combined statements of operations for the years ended December 31, 2011, 2010 and 2009 to reflect the results of operations attributable to the Transferred Business prior to the date of acquisition as a reduction of net income to determine income attributable to common limited partners. However, the Transferred Business’ 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 Corporation in February 2011 and not activities related to the Transferred Business.

In accordance with established practice in the oil and gas industry, the Partnership’s financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the energy partnerships in which the Partnership has an interest (“the Drilling Partnerships”). Such interests typically range from 15% to 35%. The Partnership’s financial statements do not include proportional consolidation of the depletion or impairment expenses of the Drilling Partnerships. Rather, the Partnership calculates these items specific to its own economics as further explained under the heading “Property, Plant and Equipment” elsewhere within this note.

The Partnership’s consolidated combined financial statements also include APL’s 95% ownership interest in joint ventures which individually own a 100% ownership interest in the West OK natural gas gathering system and processing plants and a 72.8% undivided interest in the West TX natural gas gathering system and processing plants. APL consolidates 100% of these joint ventures. The Partnership reflects the non-controlling 5% ownership interest in the joint ventures as non-controlling interests on its consolidated combined statements of operations. The Partnership also reflects the 5% ownership interest in the net assets of the joint ventures as non-controlling interests within partners’ capital on its consolidated combined balance sheets. The joint ventures have a $1.9 billion note receivable from the holder of the 5% ownership interest in the joint ventures, which was reflected within non-controlling interests on the Partnership’s consolidated combined balance sheets.

The West TX joint venture has a 72.8% undivided joint venture interest in the West TX system, of which the remaining 27.2% interest is owned by Pioneer Natural Resources Company (NYSE: PXD). Due to the West TX system’s status as an undivided joint venture, the West TX joint venture proportionally consolidates its 72.8% ownership interest in the assets and liabilities and operating results of the West TX system.

Use of Estimates

The preparation of the Partnership’s consolidated combined financial statements in conformity with accounting principles generally accepted in the United States 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 the Partnership’s consolidated combined financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s consolidated combined financial statements are based on a number of significant estimates, including the 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. Such estimates included estimated allocations made from the historical accounting records of AEI in order to derive the historical period financial statements of the Transferred Business prior to February 17, 2011, the date of acquisition (see “Principles of Consolidation and Combination”). Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the year ended December 31, 2011, 2010 and 2009 represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).

 

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Cash Equivalents

The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments.

Receivables

Accounts receivable on the consolidated combined balance sheets consist solely of the trade accounts receivable associated with the Partnership’s and APL’s operations. In evaluating the realizability of their accounts receivable, the Partnership’s and APL’s management perform ongoing credit evaluations of their customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the Partnership’s and APL’s customers’ credit information. The Partnership and APL extend credit on sales on an unsecured basis to many of their customers. At December 31, 2011 and 2010, the Partnership and APL had recorded no allowance for uncollectible accounts receivable on their consolidated combined balance sheets.

Inventory

The Partnership and APL had $16.0 million and $16.9 million of inventory at December 31, 2011 and 2010, respectively, which were included within prepaid expenses and other current assets on the Partnership’s consolidated combined balance sheets. The Partnership and APL value inventories at the lower of cost or market. The Partnership’s inventories, which consist of materials, pipes, supplies and other inventories, were principally determined using the average cost method. APL’s crude oil and refined product inventory costs have been determined using the first-in, first-out method (“FIFO”). Under this methodology, the cost of products sold consists of APL’s natural gas liquids line fill and condensate inventories. Such costs are adjusted to reflect increases or decreases in inventory quantities, which are valued based on the changes in the FIFO inventory layers.

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 (see “Principles of Consolidation and Combination”). Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property 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 the Partnership’s results of operations. APL follows the composite method of depreciation and has determined the composite groups to be the major asset classes of its gathering and processing systems. Under the composite depreciation method, any gain or loss upon disposition or retirement of pipeline, gas gathering and processing components, is recorded to accumulated depreciation.

The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil is converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to 6 Mcf of natural gas.

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include the Partnership’s costs of property interests in proportionately consolidated investment partnerships, joint venture wells, wells drilled solely by the Partnership 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 Partnership eliminates the cost from the property accounts, and the resultant gain or loss is reclassified to the Partnership’s consolidated combined statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its consolidated combined balance sheets. Upon the Partnership’s 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 the Partnership’s consolidated combined 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

The Partnership reviews its 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 the Partnership’s 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 the Partnership’s 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. The Partnership estimates prices based upon current contracts in place at December 31, 2011, 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, the Partnership’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 the Partnership’s actual capital contributions, an additional carried interest (generally 5% to 10%), a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

The Partnership’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to the Partnership their proportionate share of these expenses plus a profit margin. These assumptions could result in the Partnership’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. The Partnership cannot predict what reserve revisions may be required in future periods.

The Partnership’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 the Partnership sponsors and owns an interest in but does not control. The Partnership’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships which the Partnership may be unable to recover due to the Drilling Partnerships’ legal structure. The Partnership may have to pay additional consideration in the future as a well or Drilling Partnership becomes uneconomic under the terms of the Drilling Partnership’s agreement in order to recover these excess reserves and to acquire any additional residual interests in the wells held by other partnership investors. The acquisition of any well interest from the Drilling Partnership by the Partnership is governed under the Drilling Partnership’s agreement and in general, must be at fair market value supported by an appraisal of an independent expert selected by the Partnership.

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 the Partnership 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. There were no impairments of unproved gas and oil properties recorded by the Partnership for the years ended December 31, 2011, 2010 and 2009.

During the year ended December 31, 2011, the Partnership recognized $7.0 million of asset impairment related to gas and oil properties within property, plant and equipment on its consolidated combined balance sheet for its shallow natural gas wells in the Niobrara Shale. During the year ended December 31, 2010, the Partnership recognized $50.7 million of asset impairment related to gas and oil properties within property, plant and equipment on its consolidated combined balance sheet for its shallow natural gas wells in the Chattanooga and Upper Devonian shales. During the year ended December 31, 2009,

 

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the Partnership recorded $156.4 million of asset impairment related to gas and oil properties within property, plant and equipment on its consolidated combined balance sheet for its shallow natural gas wells in the Upper Devonian Shale. These impairments related to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2011, 2010 and 2009. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement. In addition, during the year ended December 31, 2009, APL evaluated its long-lived assets for impairment and recognized $10.3 million of impairment related to inactive pipelines and a reduction in estimated useful lives. No impairment charges were recognized by APL for the years ended December 31, 2011 and 2010.

Capitalized Interest

The Partnership and APL capitalize 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 the Partnership and APL in the aggregate were 6.9%, 7.5% and 6.3% for the years ended December 31, 2011, 2010 and 2009, respectively. The aggregate amounts of interest capitalized by the Partnership and APL were $5.3 million, $0.8 million and $2.6 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Intangible Assets

Customer contracts and relationships. APL amortizes intangible assets with finite lives in connection with natural gas gathering contracts and customer relationships assumed in certain consummated acquisitions, which APL amortizes over their estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset must be amortized over the best estimate of its useful life. At a minimum, APL will assess the useful lives of all intangible assets on an annual basis to determine if adjustments are required. The estimated useful life for APL’s customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition, adjusted for APL’s management’s estimate of whether the individual relationships will continue in excess or less than the average length.

Partnership management and operating contracts. The Partnership recorded its own intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. The Partnership amortizes contracts acquired on a declining balance and straight-line method over their respective estimated useful lives.

The following table reflects the components of intangible assets being amortized at December 31, 2011 and 2010 (in thousands):

 

		December 31,								Estimated Useful Lives
		2011				2010				In Years
Gross Carrying Amount:
Customer contracts and relationships		$	205,313			$	205,313			7 – 10
Partnership management and operating contracts			14,344				14,344			1 – 13
		$	219,657			$	219,657
Accumulated Amortization:
Customer contracts and relationships		$	(102,037	)		$	(78,934	)
Partnership management and operating contracts			(12,843	)			(12,180	)
		$	(114,880	)		$	(91,114	)
Net Carrying Amount:
Customer contracts and relationships		$	103,276			$	126,379
Partnership management and operating contracts			1,501				2,164
		$	104,777			$	128,543

Amortization expense on intangible assets was $23.8 million, $23.8 million and $24.1 million for the years ended December 31 2011, 2010 and 2009, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2012 - $23.3 million; 2013 - $23.3 million; 2014 - $19.7 million; 2015 - $14.7 million; and 2016 - $14.6 million.

 

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Goodwill

At December 31, 2011 and 2010, the Partnership had $31.8 million of goodwill recorded in connection with its prior consummated acquisitions. There were no changes in the carrying amount of goodwill for the years ended December 31, 2011, 2010 and 2009.

The Partnership tests its 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, the Partnership’s management must apply judgment in determining the estimated fair value of these reporting units. The Partnership’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 Partnership’s assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to the Partnership’s market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including the Partnership’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, the Partnership’s management 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 the Partnership’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in the Partnership’s industry to determine whether those valuations appear reasonable in management’s judgment. Management will continue to evaluate goodwill at least annually or when impairment indicators arise. During the years ended December 31, 2011, 2010 and 2009 no goodwill impairments were recognized by the Partnership.

Capital Leases

Leased property and equipment meeting capital lease criteria are capitalized based on the minimum payments required under the lease and are included within property plant and equipment on the Partnership’s consolidated combined balance sheets. Obligations under capital leases are accounted for as current and noncurrent liabilities and are included within debt on the Partnership’s consolidated combined balance sheets. Amortization is calculated on a straight-line method based upon the estimated useful lives of the assets (see Note 9).

Derivative Instruments

The Partnership and APL enter into certain financial contracts to manage their exposure to movement in commodity prices and interest rates (see Note 10). The derivative instruments recorded in the consolidated combined balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s consolidated combined statements of operations unless specific hedge accounting criteria were met.

Asset Retirement Obligations

Pursuant to prevailing accounting literature, the Partnership recognized an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 8). The Partnership recognizes a liability for future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership is required to consider estimated salvage value in the calculation of depreciation, depletion and amortization.

Income Taxes

The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income reported in the accompanying consolidated combined financial statements. Certain corporate subsidiaries of the Partnership are subject to federal and state income tax. The federal and state income taxes related to the

 

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Partnership and these corporate subsidiaries were immaterial to the consolidated combined financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the accompanying consolidated combined financial statements.

The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s 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. The Partnership’s management does not believe it has any tax positions taken within its consolidated combined financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. However, the Partnership has not recognized any potential interest or penalties in its consolidated combined financial statements as of December 31, 2011, 2010 and 2009.

The Partnership files income tax returns in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2008. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2011.

Stock-Based Compensation

The Partnership recognizes all share-based payments to employees, including grants of employee stock options, in the consolidated combined financial statements based on their fair values (see Note 16).

Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of net income attributable to participating securities, if applicable, by the weighted average number of common limited partner units outstanding during the period.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. The Partnership’s phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plans and incentive compensation agreements (see Note 16), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights result in a non-contingent transfer of value each time the Partnership declares a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis.

The following is a reconciliation of net income (loss) from continuing operations and net income (loss) from discontinued operations allocated to the common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands, except per unit data):

 

		Years Ended December 31,
		2011				2010				2009
Continuing operations:
Net income (loss)		$	307,427			$	(24,644	)		$	(66,189	)
(Income) loss attributable to non-controlling interests			(257,714	)			35,463				18,902
(Income) loss not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition (see Note 2)			(4,711	)			(22,813	)			40,000
Net income (loss) attributable to common limited partners			45,002				(11,994	)			(7,287	)
Less: Net income attributable to participating securities – phantom units(1)			(1,243	)			—				—
Net income (loss) utilized in the calculation of net income (loss) from continuing operations attributable to common limited partners per unit		$	43,759			$	(11,994	)		$	(7,287	)
Discontinued operations:
Net income (loss)		$	(81	)		$	321,155			$	84,148
(Income) loss attributable to non-controlling interests			71				(281,227	)			(72,826	)
Net income (loss) utilized in the calculation of net income from discontinued operations attributable to common limited partners per unit		$	(10	)		$	39,928			$	11,322

 

(1)

Net income attributable to common limited partners’ ownership interests is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the years ended December 31, 2010 and 2009, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 130,000 and 185,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.

 

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Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income attributable to common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, as calculated by the treasury stock method. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of the Partnership’s long-term incentive plans (see Note 16).

The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands):

 

		Years Ended December 31,
		2011				2010				2009
Weighted average common limited partners per unit - basic			48,235				27,718				27,663
Add effect of dilutive incentive awards(1)			1,459				—				—
Weighted average common limited partners per unit - diluted			49,694				27,718				27,663

 

(1)	For the years ended December 31, 2010 and 2009, approximately 180,000 and 187,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive.

Environmental Matters

The Partnership is subject to various federal, state and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. The Partnership maintains insurance which may cover in whole or in part certain environmental expenditures. At December 31, 2011 and 2010, the Partnership had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

Concentration of Credit Risk

Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Partnership places its temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. At December 31, 2011, the Partnership had $88.0 million in deposits at various banks, of which $82.1 million was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date.

The Partnership and APL sell natural gas, NGLs and condensate under contract to various purchasers in the normal course of business. For the year ended December 31, 2011, the Partnership had three customers that individually accounted for approximately 17%, 14% and 10%, respectively, of the Partnership’s natural gas and oil consolidated combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2010, the Partnership had four customers that individually accounted for approximately 13%, 12%, 12% and 11%, respectively, of the Partnership’s natural gas and oil consolidated combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2009, the Partnership had one customer that individually accounted for approximately 16% of the Partnership’s natural gas and oil consolidated combined revenues, excluding the impact of all financial derivative activity.

 

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For the year ended December 31, 2011, APL had two customers that individually accounted for approximately 60% and 16% of its revenues. No other single customer exceeded ten percent of revenues or accounts receivable for the year ended December 31, 2011. For the year ended December 31, 2010, APL had two customers that individually accounted for approximately 58% and 17% of its revenues. For the year ended December 31, 2009, APL had two customers that individually accounted for approximately 56% and 16% of its revenues. Additionally, APL had two customers that individually accounted for 56% and 15% of its accounts receivable at December 31, 2011, and two customers that individually accounted for 55% and 17% of its accounts receivable at December 31, 2010.

Revenue Recognition

Certain energy activities are conducted by the Partnership through, and a portion of its revenues are attributable to, the Drilling Partnerships. The Partnership contracts with the Drilling Partnerships to drill partnership wells. The contracts require that the Drilling Partnerships must pay the Partnership the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed between 60 and 270 days. On an uncompleted contract, the Partnership classifies the difference between the contract payments it has received and the revenue earned as a current liability titled “Liabilities Associated with Drilling Contracts” on the Partnership’s consolidated combined balance sheets. The Partnership recognizes well services revenues at the time the services are performed. The Partnership is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned and includes them in administration and oversight revenues within its consolidated combined statements of operations.

The Partnership generally sells natural gas, crude oil and natural gas liquids (“NGLs”) at prevailing market prices. Generally, the Partnership’s 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 2 business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil, in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.

Atlas Pipeline. APL’s revenue primarily consists of the sale of natural gas and NGLs, along with the fees earned from its gathering and processing operations. Under certain agreements, APL purchases natural gas from producers, moves it into receipt points on its pipeline systems and then sells the natural gas, or produced NGLs, if any, off of delivery points on its systems. Under other agreements, APL gathers natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas is recognized upon physical delivery. In connection with its gathering, processing and transportation operations, APL enters into the following types of contractual relationships with its producers and shippers:

 

•

Fee-Based Contracts. These contracts provide a set fee for gathering and/or processing raw natural gas and for transporting NGLs. APL’s revenue is a function of the volume of natural gas that it gathers and processes or the volume of NGLs transported and is not directly dependent on the value of the natural gas or NGLs. APL is also paid a separate compression fee on many of its gathering systems. The fee is dependent upon the volume of gas flowing through its compressors and the quantity of compression stages utilized to gather the gas.

 

•

Percentage of Proceeds (“POP”) Contracts. These contracts provide for APL to retain a negotiated percentage of the sale proceeds from residue gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this contract-type, APL and the producer are directly dependent on the volume of the commodity and its value; APL effectively owns a percentage of the commodity and revenues are directly correlated to its market value. POP contracts may include a fee component which is charged to the producer.

 

•

Keep-Whole Contracts. These contracts require APL, as the processor and gatherer, to gather or purchase raw natural gas at current market rates per MMBtu. The volume and energy content of gas gathered or purchased is based on the measurement at an agreed upon location (generally at the wellhead). The BTU quantity of gas redelivered or sold at the tailgate of APL’s processing facility may be lower than the BTU quantity purchased at the wellhead primarily due to the NGLs extracted from the natural gas when processed through a plant. APL must make up or “keep the producer whole” for this loss in BTU quantity. To offset the make-up obligation, APL retains the NGLs which are extracted and sells them for its own account. Therefore, APL bears the economic risk

 

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(the “processing margin risk”) that (i) the BTU quantity of residue gas available for redelivery to the producer may be less than APL received from the producer; and/or (ii) aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that it paid for the unprocessed natural gas. In order to help mitigate the risk associated with Keep-Whole contracts, APL generally imposes a fee to gather the gas that is settled under this arrangement. Also, because the natural gas volumes contracted under some Keep-Whole agreements are lower in BTU content and thus can meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants on these systems and delivered directly into downstream pipelines during periods when the processing margin is uneconomic.

The Partnership accrues 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 from the Partnership’s and APL’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “–Use of Estimates” accounting policy for further description). The Partnership had unbilled revenues at December 31, 2011 and 2010 of $81.2 million and $78.6 million, respectively, which were included in accounts receivable within the Partnership’s consolidated combined balance sheets.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income 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 accounting principles generally accepted in the United States, have not been recognized in the calculation of net income. These changes, other than net income, are referred to as “other comprehensive income” and for the Partnership includes changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.

Recently Adopted Accounting Standards

In December 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-29, Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations (“Update 2010-29”). The amendments in Update 2010-29 affect any public entity, as defined by Topic 805 Business Combinations, that enters into business combinations that are material on an individual or aggregate basis. Update 2010-29 specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. Update 2010-29 also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The Partnership applied the requirements of Update 2010-29 upon its adoption on January 1, 2011, and it did not have a material impact on its financial position, results of operations or related disclosures.

In December 2010, the FASB issued Accounting Standards Update 2010-28, Intangibles - Goodwill and Other (Topic 350): When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts (“Update 2010-28”). Update 2010-28 modifies Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist in between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The Partnership applied the requirements of Update 2010-28 upon its adoption on January 1, 2011, and it did not have a material impact on its financial position, results of operations or related disclosures.

Recently Issued Accounting Standards

In December 2011, the FASB issued Accounting Standards Update 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“Update 2011-12”). The amendments in this update effectively defer implementation of changes made in Update 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income (“Update 2011-05”), related to the presentation of reclassification adjustments out of accumulated other comprehensive income. Under Update 2011-05 which was issued by the FASB in June 2011, entities are provided the option to present the total of comprehensive income, the components of net income and the components of other

 

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comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with a total net income, each component of other comprehensive income and a total amount for comprehensive income. Update 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. As a result of Update 2011-12, entities are required to disclose reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect prior to Update 2011-05. All other requirements in Update 2011-05 are not affected by Update 2011-12. Update 2011-12 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Accordingly, entities will not be required to comply with presentation requirements of Update 2011-05 related to the disclosure of reclassifications out of accumulated other comprehensive income. The Partnership will apply the requirements of Update 2011-12 upon its effective date of January 1, 2012, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In December 2011, the FASB issued Accounting Standards Update 2011-11, Balance Sheet (Topic 210): Disclosure about Offsetting Assets and Liabilities (“Update 2011-11”). The amendments in this update require an entity to disclose both gross and net information about both financial and derivative instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the statement of financial position. An entity shall disclose at the end of a reporting period certain quantitative information separately for assets and liabilities that are within the scope of Update 2011-11, as well as provide a description of the rights of setoff associated with an entity’s recognized assets and recognized liabilities subject to an enforceable master netting arrangement or similar agreement. Update 2011-11 will be effective for annual reporting periods, and interim periods within those years, beginning on or after January 1, 2013. Upon adoption, the presentation requirements of Update 2011-11 are required to be applied to all comparative periods presented. The Partnership will apply the requirements of Update 2011-11 upon its effective date of January 1, 2013, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In September 2011, the FASB issued Accounting Standards Update 2011-08, Intangibles-Goodwill and Other (Topic 350): Testing Goodwill for Impairment (“Update 2011-08”). The amendments in Update 2011-08 allow an entity to first assess qualitative factors in determining the necessity of performing the two-step quantitative goodwill impairment test. If, after assessing qualitative factors, an entity determines it is not likely that the fair value of a reporting unit is less than its carrying amount, performing the two-step impairment test is unnecessary. Under the amendments in Update 2011-08, an entity has the option to bypass the qualitative assessment and proceed directly to performing the first step of the two-step impairment test. Update 2011-08 will be effective for fiscal years beginning after December 15, 2011, with early adoption permitted. The Partnership will apply the requirements of Update 2011-08 upon its effective date of January 1, 2012, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In May 2011, the FASB issued Accounting Standards Update 2011-04, Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“Update 2011-04”). The amendments in Update 2011-04 revise the wording used to describe many of the requirements for measuring fair value and for disclosing information about fair value measurements in U.S. GAAP. For many of the amendments, the guidance is not necessarily intended to result in a change in the application of the requirements in Topic 820; rather it is intended to clarify the intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. As a result, Update 2011-04 aims to provide common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards. Update 2011-04 will be effective for interim and annual periods beginning after December 15, 2011. Early adoption by public entities is not permitted. The Partnership will apply the requirements of Update 2011-04 upon its effective date of January 1, 2012, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

NOTE 3 – ACQUISITION FROM ATLAS ENERGY, INC.

On February 17, 2011, the Partnership acquired the Transferred Business from AEI (see Note 2), the former parent of its general partner, which included the following assets:

 

•

AEI’s investment management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which the Partnership 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;

 

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•

certain producing natural gas and oil properties, upon which the Partnership is the developer and producer;

 

•

all of the ownership interests in Atlas Energy GP, LLC, the Partnership’s general partner (“General Partner”); and

 

•

a direct and indirect ownership interest in Lightfoot (see Notes 1 and 7).

For the assets acquired and liabilities assumed, the Partnership issued approximately 23.4 million of its common limited partner units and paid $30.0 million in cash consideration. Based on the Partnership’s February 17, 2011 common unit closing price of $15.92, the common units issued to AEI were valued at approximately $372.2 million. In connection with the transaction, the Partnership also received $118.7 million with respect to a contractual cash transaction adjustment from AEI related to certain liabilities assumed by the Transferred Business, including certain amounts subject to a reconciliation period following the consummation of the transaction. The reconciliation period was ongoing at December 31, 2011, and certain amounts included within the contractual cash transaction adjustment are in dispute between the parties. The resolution of the disputed amounts could result in the Partnership being required to repay a portion of the cash transaction adjustment (see Note 13). Including the cash transaction adjustment, the net book value of the Transferred Business was approximately $522.9 million.

Concurrent with the Partnership’s acquisition of the Transferred Business, AEI completed its merger with Chevron Corporation (“Chevron”), whereby AEI became a wholly owned subsidiary of Chevron. Also concurrent with the Partnership’s acquisition of the Transferred Business and immediately preceding AEI’s merger with Chevron, APL completed its sale to AEI of its 49% non-controlling interest in the Laurel Mountain joint venture (the “Laurel Mountain Sale”). APL received $409.5 million in cash, including adjustments based on certain capital contributions APL made to and distributions it received from the Laurel Mountain joint venture after January 1, 2011. APL retained the preferred distribution rights under the limited liability company agreement of the Laurel Mountain joint venture entitling APL to receive all payments made under the note receivable issued to Laurel Mountain by Williams Laurel Mountain, LLC in connection with the formation of the Laurel Mountain joint venture.

In accordance with prevailing accounting literature, management of the Partnership determined that the acquisition of the Transferred Business constituted a transaction between entities under common control (see Note 2). As such, the Partnership 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 partners’ capital on its consolidated combined balance sheet. The Partnership recognized a non-cash decrease of $261.0 million in partner’s capital on its consolidated combined balance sheet based on the excess net book value above the value of the consideration paid to AEI. The following table presents the historical carrying value of the assets acquired and liabilities assumed by the Partnership, including the effect of cash transaction adjustments, as of February 17, 2011 (in thousands):

 

Cash		$	153,350
Accounts receivable			18,090
Accounts receivable – affiliate			45,682
Prepaid expenses and other			6,955
Total current assets			224,077
Property, plant and equipment, net			516,625
Goodwill			31,784
Intangible assets, net			2,107
Other assets, net			20,416
Total long-term assets			570,932
Total assets acquired		$	795,009
Accounts payable		$	59,202
Net liabilities associated with drilling contracts			47,929
Accrued well completion costs			39,552
Current portion of derivative payable to Drilling Partnerships			25,659
Accrued liabilities			25,283
Total current liabilities			197,625
Long-term derivative payable to Drilling Partnerships			31,719
Asset retirement obligations			42,791
Total long-term liabilities			74,510
Total liabilities assumed		$	272,135
Historical carrying value of net assets acquired		$	522,874

 

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Also in accordance with prevailing accounting literature, the Partnership reflected the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which the Transferred Business was acquired and retrospectively adjusted its prior year financial statements to furnish comparative information (see Note 2).

NOTE 4 – APL INVESTMENT IN JOINT VENTURES

West Texas LPG Pipeline Limited Partnership

On May 11, 2011, APL acquired a 20% interest in West Texas LPG Pipeline Limited Partnership (“West Texas LPG”) from Buckeye Partners, L.P. (NYSE: BPL) for $85.0 million. West Texas LPG owns a common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. West Texas LPG is operated by Chevron Pipeline Company, a subsidiary of Chevron, which owns the remaining 80% interest. APL has accounted for its ownership interest in West Texas LPG under the equity method of accounting, with recognition of its ownership interest in the income of West Texas LPG in other, net on the Partnership’s consolidated combined statements of operations. During the year ended December 31, 2011, APL recognized $4.6 million of equity income within other, net on the Partnership’s consolidated combined statements of operations related to its West Texas LPG interest.

Laurel Mountain

On February 17, 2011, APL completed the sale of its 49% non-controlling interest in Laurel Mountain Midstream, LLC (“Laurel Mountain”), a joint venture which was formed in May 2009 by APL and subsidiaries of The Williams Companies, Inc. (NYSE: WMB) (“Williams”) to own and operate APL’s Appalachia Basin natural gas gathering system, excluding APL’s Northern Tennessee operations, to Atlas Energy Resources, LLC for $409.5 million in cash, including certain closing adjustments and net of expenses. Concurrently with the sale, AEI became a wholly-owned subsidiary of Chevron and divested its interests in the Partnership, resulting in the Laurel Mountain sale being classified as a third party sale (see Note 3). APL used the proceeds from the sale to repay its indebtedness (see Note 9) and for general corporate purposes. APL also retained its preferred distribution rights with respect to a remaining $8.5 million note receivable due from Williams, an investment grade rated entity, related to the formation of Laurel Mountain, including interest due on this note. Since APL accounted for its ownership of Laurel Mountain as an equity investment included within investment in joint venture on the Partnership’s consolidated combined balance sheet at fair value and recognition of its ownership interest in the income of Laurel Mountain as other income (loss) on the Partnership’s consolidated combined statements of operations, APL did not reclassify the earnings or the gain on sale related to Laurel Mountain to discontinued operations upon the sale of its ownership interest. The Partnership recognized a net gain of $254.1 million, comprised of a $256.3 million gain during the year ended December 31, 2011 and a $2.2 million loss during the year ended December 31, 2010 for expenses related to the sale, which is included in gain (loss) on asset sales within the Partnership’s consolidated combined statements of operations. The Partnership also reclassified the $8.5 million note receivable previously recorded to investment in joint venture to prepaid expenses and other on the Partnership’s consolidated combined balance sheets.

To form Laurel Mountain, Williams contributed cash of $100.0 million to the joint venture (of which APL received approximately $87.8 million, net of working capital adjustments) and a note receivable of $25.5 million. APL contributed its Appalachia Basin natural gas gathering system and retained a 49% ownership interest, with Williams retaining the remaining 51% ownership interest. APL recognized a gain on sale of $108.9 million, including $54.2 million associated with the re-measurement of APL’s investment in Laurel Mountain to fair value as determined by the purchase price of the assets upon completion of the transaction, during the year ended December 31, 2009. APL used the net proceeds from the transaction to reduce borrowings under its senior secured credit facility (see Note 9).

During the years ended December 31, 2010 and 2009, APL utilized $15.3 million and $1.7 million, respectively, of the $25.5 million note receivable to make capital contributions to Laurel Mountain and made additional capital contributions of $26.5 million in cash payments in the year ended December 31, 2010. In December 2011, Williams made cash payment to the Partnership to settle the remaining $8.5 million balance on the note receivable plus accrued interest of $0.2 million.

The following tables summarize the components of the investment in joint ventures on the Partnership’s consolidated combined balance sheets and the components of equity income on the Partnership’s consolidated combined statements of operations (in thousands).

 

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		December 31,
		2011				2010
Investment in Laurel Mountain		$	—			$	153,358
Investment in WTLPG			86,879				—
Investment in joint ventures		$	86,879			$	153,358

 

		Years Ended December 31,
		2011				2010				2009
Equity income in Laurel Mountain		$	462			$	4,920			$	4,043
Equity income in WTLPG			4,563				—				—
Equity income in joint ventures		$	5,025			$	4,920			$	4,043

NOTE 5 – DISCONTINUED OPERATIONS

On September 16, 2010, APL completed the sale of its Elk City natural gas gathering and processing system to Enbridge Energy Partners, L.P. (NYSE: EEP) for $682.0 million in cash, excluding any working capital or other adjustments. APL used the net proceeds from the transaction to terminate its term loan and reduce borrowings under its revolving credit facility (see Note 9). The Partnership accounted for the sale of the Elk City system assets as discontinued operations within its consolidated combined financial statements and recorded a gain of $312.1 million, on the sale within income (loss) from discontinued operations on its consolidated combined statement of operations for the year ended December 31, 2010.

On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system to Spectra Energy Partners OLP, LP (NYSE:SEP) (“Spectra”) for net proceeds of $294.5 million in cash, net of working capital and other adjustments. APL used the net proceeds from the transaction to reduce borrowings under its senior secured term loan and revolving credit facility (see Note 9). The Partnership accounted for the sale of the NOARK system assets as discontinued operations within its consolidated combined financial statements and recorded a gain of $51.1 million on the sale of APL’s NOARK assets within income from discontinued operations on its consolidated combined statements of operations during the year ended December 31, 2009.

The following table summarizes the components included within income (loss) from discontinued operations on the Partnership’s consolidated combined statements of operations (in thousands):

 

		Years Ended December 31,
		2011				2010				2009
NOARK
Total revenues		$	—			$	—			$	21,274
Total costs and expenses			—				—				(9,857	)
Income from discontinued operations		$	—			$	—			$	11,417
Elk City
Total revenues		$	—			$	129,908			$	167,543
Total costs and expenses			(81	)			(120,855	)			(148,383	)
Income (loss) from discontinued operations		$	(81	)		$	9,053			$	19,160
Total income (loss) from discontinued operations		$	(81	)		$	9,053			$	30,577

NOTE 6 – 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
		2011				2010
Natural gas and oil properties:
Proved properties:
Leasehold interests		$	61,587			$	46,495
Pre-development costs			2,540				2,337
Wells and related equipment			828,780				798,269
Total proved properties			892,907				847,101
Unproved properties			43,253				42,520
Support equipment			9,413				8,138
Total natural gas and oil properties			945,573				897,759
Pipelines, processing and compression facilities			1,646,320				1,370,230			2  – 40
Rights of way			161,275				156,797			20 – 40
Land, buildings and improvements			23,416				14,465			3 – 40
Other			22,734				26,367			3 – 10
			2,799,318				2,465,618
Less – accumulated depreciation, depletion and amortization			(706,035	)			(616,132	)
		$	2,093,283			$	1,849,486

 

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During the year ended December 31, 2011, the Partnership recognized $7.0 million of asset impairment related to gas and oil properties within property, plant and equipment on its consolidated combined balance sheet for its shallow natural gas wells in the Niobrara Shale. During the year ended December 31, 2010, the Partnership recognized $50.7 million of asset impairment related to gas and oil properties within property, plant and equipment on its consolidated combined balance sheet for its shallow natural gas wells in Chattanooga and Upper Devonian shales. During the year ended December 31, 2009, the Partnership recognized $156.4 million of asset impairment related to gas and oil properties within property, plant and equipment on its consolidated combined balance sheet for its shallow natural gas wells in the Upper Devonian Shale. These impairments related to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2011, 2010 and 2009, respectively. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement. In addition, during the year ended December 31, 2009, APL evaluated its long-lived assets for impairment and recognized $10.3 million of impairment related to inactive pipelines and a reduction in estimated useful lives. No impairment charges were recognized by APL for the years ended December 31, 2011 and 2010.

On July 13, 2009, APL sold a natural gas processing facility and a one-third undivided interest in other associated assets located in its Mid-Continent operating segment for approximately $22.6 million in cash. The facility was sold to Penn Virginia Resource Partners, L.P. (NYSE: PVR), who will provide natural gas volumes to the facility and reimburse APL for its proportionate share of the operating expenses. APL will continue to operate the facility. APL used the proceeds from this transaction to reduce outstanding borrowings under its senior secured credit facility. APL recognized a gain on sale of $2.5 million, which is recorded within gain on asset sales on the Partnership’s consolidated combined statements of operations.

NOTE 7 – OTHER ASSETS

The following is a summary of other assets at the dates indicated (in thousands):

 

		December 31,
		2011				2010
Deferred financing costs, net of accumulated amortization of $19,331 and $24,436 at December 31, 2011 and 2010, respectively		$	23,426			$	28,327
Investment in Lightfoot			19,514				18,912
Security deposits			4,584				2,841
Long-term derivative receivable from Drilling Partnerships			—				4,669
		$	47,524			$	54,749

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 9). In April 2011, APL recorded $5.2 million related to accelerated amortization of deferred financing costs associated with the retirement of its 8.125% Senior Notes and partial redemption of its 8.75% Senior Notes (see Note 9), which is included within loss on early extinguishment of debt on the Partnership’s consolidated combined statement of operations. In March 2011, the Partnership recorded $4.9 million of accelerated amortization of deferred financing costs associated with the retirement of its $70.0 million credit facility (see Note 9), which is included within interest expense on the Partnership’s consolidated combined statement of operations. In September 2010, APL recorded $4.4 million of accelerated amortization of deferred financing costs associated with the retirement of its term loan with the proceeds from the sale of its Elk City system (see Note 5), which is included within loss on early extinguishment of debt on the Partnership’s consolidated combined statement of operations. During the year ended December 31, 2009, APL recorded $2.5 million of accelerated amortization of deferred financing costs, which is recorded within interest expense on the Partnership’s consolidated statement of operations.

 

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At December 31, 2011, the Partnership owns an approximate 12% interest in Lightfoot LP and an approximate 16% interest in Lightfoot GP, the general partner of Lightfoot LP, an entity for which Jonathan Cohen, Chairman of the General Partner’s board of directors, is the Chairman of the Board. The Partnership has certain co-investment rights until such point as Lightfoot LP raises additional capital through a private offering to institutional investors or a public offering. Lightfoot LP had initial equity funding commitments of approximately $160.0 million and focuses its investments primarily on incubating new master limited partnerships and providing capital to existing MLPs in need of additional equity or structured debt. The Partnership accounts for its investment in Lightfoot under the equity method of accounting. During the year ended December 31, 2011, the Partnership recorded equity income of $16.6 million, including a $15.0 million gain associated with its share of Lightfoot LP’s gain recognized on the sale of International Resource Partners LP (“IRP”), its metallurgical and steam coal business, in March 2011. During the years ended December 31, 2010 and 2009, the Partnership recorded $2.1 million of equity income and $1.5 million of equity loss, respectively. The equity income was recorded within other, net on the Partnership’s consolidated combined statements of operations. In 2011, the Partnership received net cash distributions of $16.2 million, including $14.2 million, representing its share of the cash distribution made to investors by Lightfoot LP with proceeds from the IRP sale. During the years ended December 31, 2010 and 2009, the Partnership received net cash distributions of $0.7 million and $0.6 million, respectively.

Long-term derivative receivable from Drilling Partnerships represents a portion of the Partnership’s long-term unrealized derivative liability on contracts that have been allocated to the Drilling Partnerships based on their share of total production volumes sold (see Note 10).

NOTE 8 – ASSET RETIREMENT OBLIGATIONS

The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities. It also recognizes 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. The Partnership also considers the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability is based on the Partnership’s 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. 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. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its gas and oil properties, the Partnership has determined that there are no other material retirement obligations associated with tangible long-lived assets.

A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):

 

		Years Ended December 31,
		2011				2010				2009
Asset retirement obligations, beginning of year		$	42,673			$	36,599			$	33,881
Liabilities incurred			713				472				909
Liabilities settled			(209	)			(373	)			(248	)
Accretion expense			2,602				2,205				2,057
Revisions			—				3,770				—
Asset retirement obligations, end of year		$	45,779			$	42,673			$	36,599

The above accretion expense was included in depreciation, depletion and amortization in the Partnership’s consolidated combined statements of operations and the asset retirement obligation liabilities were included within other long-term liabilities in the Partnership’s consolidated combined balance sheets.

 

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NOTE 9 — DEBT

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

 

		December 31,
		2011				2010
Note payable to affiliate		$	—			$	35,415
APL revolving credit facility			142,000				70,000
APL 8.125 % senior notes – due 2015			—				272,181
APL 8.75 % senior notes – due 2018			370,983				223,050
APL capital leases			11,157				743
Total debt			524,140				601,389
Less current maturities			(2,085	)			(35,625	)
Total long-term debt		$	522,055			$	565,764

Credit Facility

On March 22, 2011, the Partnership entered into a new credit facility with a syndicate of banks that matures in March 2016. The credit facility has maximum lender commitments of $300 million and a current borrowing base of $160 million. The borrowing base is redetermined semiannually in May and November subject to changes in oil and gas reserves and is automatically reduced by 25% of the stated principal of any senior unsecured notes issued by the Partnership. Up to $20.0 million of the credit facility may be in the form of standby letters of credit, of which $0.8 million was outstanding at December 31, 2011, which was not reflected as borrowings on the Partnership’s consolidated combined balance sheets. The facility is secured by substantially all of the Partnership’s assets and is guaranteed by substantially all of its subsidiaries (excluding APL and its subsidiaries). At December 31, 2011, there were no borrowings outstanding under the credit facility. Borrowings under the credit facility bear interest, at the Partnership’s election, at either LIBOR plus an applicable margin (based upon the utilization of the facility, as defined in the credit agreement) 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 (based on the utilization of the facility, as defined in the credit agreement). The Partnership is also required to pay a fee of 0.5% per annum on the unused portion of the borrowing base, which is included within interest expense on the Partnership’s consolidated statements of operations.

On February 17, 2011, the Partnership entered into a bridge credit facility in connection with the closing of the acquisition of the Transferred Business, which was replaced with the credit facility previously noted. The credit facility provided for an initial borrowing base of $70 million and a maturity of February 2012.

The credit agreement contains customary covenants that limit the Partnership’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 the Partnership’s assets. The Partnership was in compliance with these covenants as of December 31, 2011. The credit agreement also requires the Partnership to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to four quarters (actual or annualized, as applicable) of EBITDA (as defined in the credit agreement) not greater than 3.75 to 1.0 as of the last day of any fiscal quarter ending on or after June 30, 2011, a ratio of current assets (as defined in the credit agreement) to current liabilities (as defined in the credit agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter, and a ratio of four quarters (actual or annualized, as applicable) of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) of not less than 2.5 to 1.0 as of the last day of any fiscal quarter ending on or after June 30, 2011. Based on the definitions contained in the Partnership’s credit facility, its ratio of current assets to current liabilities was 1.7 to 1.0, its ratio of Total Funded Debt to EBITDA was 0.01 to 1.0 and its ratio of EBITDA to Consolidated Interest Expense was 63.3 to 1.0 at December 31, 2011.

APL Credit Facility

At December 31, 2011, APL had a $450.0 million senior secured revolving credit facility with a syndicate of banks, which matures in December 2015, of which $142.0 million was outstanding. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) three-month LIBOR plus 1.0%, or (ii) the LIBOR rate for the applicable period (each plus the applicable margin). The weighted average interest rate on APL’s outstanding revolving credit facility borrowings at December 31, 2011 was 3.1%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $0.1 million was outstanding at December 31, 2011. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated combined balance sheet at December 31, 2011. At December 31, 2011, APL had $307.9 million of remaining committed capacity under its credit facility, subject to covenant limitations. The Partnership has not guaranteed any of the obligations under APL’s senior secured revolving credit facility.

 

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Borrowings under APL’s credit facility are secured by a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by West OK and West TX joint ventures, and by the guarantee of each of APL’s consolidated subsidiaries other than the joint venture companies. The revolving credit facility contains customary covenants, including requirements that APL maintains certain financial thresholds and restrictions on its ability to (i) incur additional indebtedness, (ii) make certain acquisitions, loans or investments, (iii) make distribution payments to its unitholders if an event of default exists, or (iv) enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement.

The events which constitute an event of default for the revolving credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against APL in excess of a specified amount and a change of control of APL’s general partner. APL was in compliance with these covenants as of December 31, 2011.

In July 2011, the revolving credit facility was increased from $350.0 million to $450.0 million. In September 2010, a $425.8 million term loan, scheduled to mature in July 2014, was paid in full with proceeds received from the Elk City asset sale (see Note 5).

APL Senior Notes

At December 31, 2011, APL had $371.0 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“APL 8.75% Senior Notes”). Interest on the APL 8.75% Senior Notes is payable semi-annually in arrears on June 15 and December 15. The APL 8.75% Senior Notes are redeemable at any time after June 15, 2013, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. The APL 8.75% Senior Notes are subject to repurchase by APL at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if APL does not reinvest the net proceeds within 360 days. The APL 8.75% Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its credit facility.

In November 2011, APL issued $150.0 million of the 8.75% Senior Notes, priced at a premium of $155.3 million, in a private placement transaction under Rule 144A and Regulation S under the Securities Act of 1933, as amended, for net proceeds of $152.4 million after underwriting commissions and other transaction costs. APL utilized the proceeds to reduce the outstanding balance on its revolving credit facility.

In April 2011, APL redeemed all of its 8.125% senior notes, due December 15, 2015, for a total redemption of $293.7 million, including accrued interest of $7.0 million and premium of $11.2 million. APL also redeemed $7.2 million of the APL 8.75% Senior Notes in April 2011, which were tendered upon its offer to purchase the senior notes at par. APL funded its purchase with a portion of the net proceeds from its sale of its 49% non-controlling interest in Laurel Mountain (see Note 4).

The indenture governing the APL 8.75% Senior Notes in the aggregate contains covenants, including limitations of APL’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. APL was in compliance with these covenants as of December 31, 2011.

APL Capital Leases

At December 31, 2011 and 2010, APL had $11.2 million and $0.7 million, respectively, long-term debt related to capital leases. On July 15, 2011, APL amended an operating lease for eight natural gas compressors to include a mandatory purchase of the equipment at the end of the lease term, thereby converting the agreement to a capital lease upon the effective date of the amendment. As a result, APL recorded an asset of $11.4 million within property, plant and equipment with an offsetting liability recorded within long term debt on the Partnership’s consolidated combined balance sheets based on the minimum payments required under the lease and APL’s incremental borrowing rate. During the year ended December 31, 2010, APL entered into capital lease arrangements having obligations of $0.9 million at inception, which were recorded within property, plant and equipment with an offsetting liability recorded within long term debt on the Partnership’s consolidated combined balance sheets.

 

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The following is a summary of the leased property under capital leases, which are included within property, plant and equipment (see Note 6) (in thousands):

 

		December 31,
		2011				2010
Pipelines, processing and compression facilities		$	12,507			$	1,139
Less – accumulated depreciation			(199	)			(47	)
		$	12,308			$	1,092

As of December 31, 2011, future minimum lease payments related to the capital leases are as follows (in thousands):

 

		Capital Lease Minimum Payments
2012		$	2,685
2013			9,376
2014			64
2015			—
2016			—
Thereafter			—
Total minimum lease payments			12,125
Less amounts representing interest			(968	)
Present value of minimum lease payments			11,157
Less current capital lease obligations			(2,085	)
Long-term capital lease obligations		$	9,072

The aggregate amount of the Partnership’s and APL’s debt maturities is as follows (in thousands):

 

Years Ended December 31:
2012		$	2,085
2013			9,008
2014			64
2015			142,000
2016			—
Thereafter			370,983
Total debt		$	524,140

Cash payments for interest for the Partnership and its subsidiaries were $33.0 million, $91.8 million and $93.2 million for the years ended December 31, 2011, 2010 and 2009, respectively.

NOTE 10 – DERIVATIVE INSTRUMENTS

The Partnership and APL use a number of different derivative instruments, principally swaps, collars and options, in connection with their commodity and interest rate price risk management activities. The Partnership and APL enter into financial instruments to hedge forecasted natural gas, NGL, crude oil and condensate 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 natural gas, NGLs, crude oil and condensate are sold or interest payments on the underlying debt instrument are due. Under commodity-based swap agreements, the Partnership and APL receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not the obligation, to receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period.

The Partnership and APL 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. The Partnership and APL 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

 

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hedged, the Partnership and APL will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by management of the Partnership and APL through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated combined statements of operations. For derivatives qualifying as hedges, the Partnership and APL recognize the effective portion of changes in fair value of derivative instruments in partners’ capital as accumulated other comprehensive income and reclassify the portion relating to the Partnership’s commodity derivatives to gas and oil production revenues and gathering and processing revenues for APL’s commodity derivatives and the portion relating to interest rate derivatives to interest expense within the Partnership’s consolidated combined statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership and APL recognize changes in fair value within gain (loss) on mark-to-market derivatives in its consolidated combined statements of operations as they occur.

Derivatives are recorded on the Partnership’s consolidated combined balance sheets as assets or liabilities at fair value. The Partnership reflected net derivative assets on its consolidated combined balance sheets of $46.4 million and $55.9 million at December 31, 2011 and 2010, respectively. Of the $29.4 million of net gain in accumulated other comprehensive income within partners’ capital on the Partnership’s consolidated combined balance sheet related to derivatives at December 31, 2011, if the fair values of the instruments remain at current market values, the Partnership will reclassify $13.3 million of gains to its consolidated combined statement of operations over the next twelve month period as these contracts expire, consisting of $13.8 million of gains to gas and oil production revenues and $0.5 million of losses to gathering and processing revenues. Aggregate gains of $16.1 million to gas and oil production revenues will be reclassified to the Partnership’s consolidated combined statements of operations in later periods as these remaining contracts expire. Actual amounts that will be reclassified will vary as a result of future price changes.

The following table summarizes the fair value of the Partnership’s own derivative instruments as of December 31, 2011 and 2010, as well as the gain or loss recognized in the consolidated combined statements of operations for effective derivative instruments for the years ended December 31, 2011, 2010 and 2009:

 

				December 31,
Contract Type		Balance Sheet Location		2011				2010
Asset Derivatives
Commodity contracts		Current portion of derivative asset		$	14,146			$	36,528
Commodity contracts		Long-term derivative asset			21,485				36,020
					35,631				72,548
Liability Derivatives
Commodity contracts		Current portion of derivative asset			(345	)			(311	)
Commodity contracts		Long-term derivative asset			(5,357	)			(6,137	)
					(5,702	)			(6,448	)
Total derivatives				$	29,929			$	66,100

 

		Years Ended December 31,
		2011				2010				2009
Gain recognized in accumulated OCI		$	35,156			$	16,542			$	27,846
(Gain) reclassified from accumulated OCI into income		$	(10,541	)		$	(27,364	)		$	(43,745	)

The Partnership enters into natural gas and crude oil future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in natural gas prices and oil 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 delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

The Partnership recognized gains of $10.5 million, $27.4 million and $43.7 million for the years ended December 31, 2011, 2010 and 2009, respectively, on settled contracts covering natural gas and oil production for historical periods prior to the acquisition of the Transferred Business. These gains are included within gas and oil production revenue in the Partnership’s consolidated combined statements of operations. As the underlying prices and terms in the Partnership’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, 2011, 2010 and 2009 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

 

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Prior to its merger transaction with Chevron on February 17, 2011, AEI monetized all of its derivative instruments, including those related to the future natural gas and oil production of the Transferred Business (see Note 3). AEI also monetized derivative instruments which were specifically related to the future natural gas and oil production of the limited partners of the Drilling Partnerships. Monetization proceeds of $57.4 million related to the amounts hedged on behalf of the Drilling Partnerships’ limited partners were included within cash and cash equivalents acquired of the Transferred Business at the date of acquisition. The Partnership has and will continue to allocate the monetization net proceeds received to the Drilling Partnerships’ limited partners based on their natural gas and oil production generated over the period of the original derivative contracts. At December 31, 2011, the Partnership recognized a current and long-term derivative payable to Drilling Partnerships of $20.9 million and $15.3 million, respectively, on its consolidated combined balance sheets related to the future allocation of the monetization net proceeds.

At December 31, 2011, the Partnership 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)
2012			5,520,000			$	5.000			$	9,704
2013			3,120,000			$	5.288				4,155
2014			2,880,000			$	5.590				3,526
2015			2,880,000			$	5.861				3,523
										$	20,908

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)
2012		Puts purchased			4,320,000			$	4.074			$	4,064
2012		Calls sold			4,320,000			$	5.279				(133	)
2013		Puts purchased			5,520,000			$	4.395				4,469
2013		Calls sold			5,520,000			$	5.443				(884	)
2014		Puts purchased			3,840,000			$	4.221				2,169
2014		Calls sold			3,840,000			$	5.120				(1,480	)
2015		Puts purchased			3,840,000			$	4.296				2,395
2015		Calls sold			3,840,000			$	5.233				(2,258	)
												$	8,342

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)
2012		Puts purchased			60,000			$	90.000			$	379
2012		Calls sold			60,000			$	117.912				(212	)
2013		Puts purchased			60,000			$	90.000				711
2013		Calls sold			60,000			$	116.396				(396	)
2014		Puts purchased			24,000			$	80.000				248
2014		Calls sold			24,000			$	121.250				(158	)
2015		Puts purchased			24,000			$	80.000				290
2015		Calls sold			24,000			$	120.750				(183	)
												$	679
Total Partnership net asset												$	29,929

 

(1)	“Mmbtu” represents million British Thermal Units; “Bbl” represents barrels.

(2)	Fair value based on forward NYMEX natural gas prices, as applicable.

(3)	Fair value based on forward WTI crude oil prices, as applicable.

 

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The Partnership’s commodity price risk management activities include the estimated future natural gas and crude oil production of the Drilling Partnerships. Therefore, prior to the Partnership’s acquisition of the Transferred Business, a portion of any unrealized derivative gain or loss was allocable to the limited partners of the Drilling Partnerships based on their share of estimated gas and oil production related to the derivatives not yet settled. Prior to the Partnership’s acquisition of the Transferred Business, AEI monetized all of its derivative instruments, including those related to the future natural gas and oil production of the limited partners of the Drilling Partnerships. At December 31, 2011, hedge monetization cash proceeds of $36.2 million related to the amounts hedged on behalf of the Drilling Partnerships’ limited partners were included within cash and cash equivalents, and the Partnership will allocate the monetization net proceeds received to the Drilling Partnerships’ limited partners based on their natural gas and oil production generated over the period of the original derivative contracts. The derivative payable related to the hedge monetization proceeds at December 31, 2011 and net unrealized derivative assets at December 31, 2010 were payable to the limited partners in the Drilling Partnerships and are included in the consolidated combined balance sheets as follows (in thousands):

 

		December 31,
		2011				2010
Current portion of derivative receivable from Drilling Partnerships		$	—			$	138
Long-term derivative receivable from Drilling Partnerships			—				4,669
Current portion of derivative payable to Drilling Partnerships			(20,900	)			(30,797	)
Long-term portion of derivative payable to Drilling Partnerships			(15,272	)			(34,796	)
		$	(36,172	)		$	(60,786	)

Atlas Pipeline Partners

For the years ended December 31, 2011, 2010 and 2009, APL did not apply hedge accounting for derivatives. As such, changes in fair value of derivatives are recognized immediately within gain (loss) on mark-to-market derivatives on the Partnership’s consolidated combined statements of operations. The change in fair value of commodity-based derivative instruments entered into prior to the discontinuation of hedge accounting will be classified from within accumulated other comprehensive income on the Partnership’s consolidated combined balance sheets to gathering and processing revenue on the Partnership’s consolidated combined statements of operations at the time the originally hedged physical transactions settle.

The following table summarizes APL’s gross fair values of derivative instruments for the period indicated (in thousands):

 

				December 31,
Contract Type		Balance Sheet Location		2011				2010
Asset Derivatives
Commodity contracts		Current portion of derivative asset		$	11,603			$	—
Commodity contracts		Long-term derivative asset			17,011				—
Commodity contracts		Current portion of derivative liability			—				2,624
Commodity contracts		Long-term derivative liability			—				1,052
				$	28,614			$	3,676
Liability Derivatives
Commodity contracts		Current portion of derivative asset		$	(9,958	)		$	—
Commodity contracts		Long-term derivative asset			(2,197	)			—
Commodity contracts		Current portion of derivative liability			—				(7,188	)
Commodity contracts		Long-term derivative liability			—				(6,660	)
					(12,155	)			(13,848	)
Total derivatives				$	16,459			$	(10,172	)

 

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As of December 31, 2011, APL had the following commodity derivatives:

Fixed Price Swaps

 

Production Period		Sold				Commodity		Volumes(2)				Average Fixed Price				Fair  Value(1) Asset/(Liability) (in thousands)
Natural Gas Liquids
2012			Sold			Ethane			6,678,000			$	0.744			$	31
2012			Sold			Propane			19,278,000			$	1.302				(828	)
2012			Sold			Normal Butane			5,292,000			$	1.769				(520	)
2012			Sold			Isobutane			2,646,000			$	1.657				(1,020	)
2012			Sold			Natural Gasoline			4,158,000			$	2.401				1,310
2013			Sold			Propane			10,080,000			$	1.251				(494	)
2013			Sold			Normal Butane			1,512,000			$	1.610				(212	)
Crude Oil
2012			Sold			Crude Oil			303,000			$	95.612				(982	)
2013			Sold			Crude Oil			156,000			$	92.776				(514	)
Total Fixed Price Swaps																$	(3,229	)

Options

 

Production Period		Purchased/ Sold		Type		Commodity		Volumes(2)				Average Strike Price				Fair  Value(1) Asset/(Liability) (in thousands)
Natural Gas
2012		Purchased		Put		Ethane			3,150,000			$	0.718			$	119
2012		Purchased		Put		Propane			28,476,000			$	1.386				4,118
2012		Purchased		Put		Normal Butane			5,166,000			$	1.552				522
2012		Purchased		Put		Isobutane			3,654,000			$	1.617				266
2012		Purchased		Put		Natural Gasoline			13,608,000			$	2.087				2,184
2013		Purchased		Put		Normal Butane			10,458,000			$	1.667				2,650
2013		Purchased		Put		Isobutane			4,158,000			$	1.687				924
2013		Purchased		Put		Natural Gasoline			23,940,000			$	2.108				7,496
Crude Oil
2012		Sold		Call		Crude Oil			498,000			$	94.694				(5,819	)
2012		Purchased(3)		Call		Crude Oil			180,000			$	125.200				354
2012		Purchased(3)		Put		Crude Oil			180,000			$	106.421				2,317
2013		Purchased(3)		Put		Crude Oil			282,000			$	100.100				4,557
Total Options																$	19,688
Total APL net asset																$	16,459

 

(1)	See Note 11 for discussion on fair value methodology.

(2)	Volumes for natural gas are stated in MMBTU’s. Volumes for NGLs are stated in gallons. Volumes for crude oil are stated in barrels.

(3)	Calls purchased for 2012 represent offsetting positions for calls sold. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise.

The following tables summarize the gross effect of APL’s derivative instruments on the Partnership’s consolidated combined statement of operations for the period indicated (in thousands):

 

		Years ended December 31,
		2011				2010				2009
Loss Recognized in Accumulated Other Comprehensive Loss
Contract Type
Interest rate contracts(1)		$	—			$	—			$	(2,268	)
		$	—			$	—			$	(2,268	)

 

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Gain (Loss) Reclassified from Accumulated OCI into Income

 

				Years Ended December 31,
Contract Type		Location		2011				2010				2009
Interest rate contracts(1)		Interest expense		$	—			$	(2,242	)		$	(11,754	)
Commodity contracts(1)		Gathering and processing revenue			(6,835	)			(15,570	)			(31,000	)
Commodity contracts(1)		Discontinued operations			—				(20,154	)			(15,268	)
				$	(6,835	)		$	(37,966	)		$	(58,022	)

Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)

				Years Ended December 31,
Contract Type		Location		2011				2010				2009
Interest rate contracts(2)		Other, net		$	—			$	(6	)		$	(1,041	)
Commodity contracts(1)		Gathering and processing revenue			—				—				273
Commodity contracts(1)		Discontinued operations			—				—				(396	)
Commodity contracts(2)		Gain (loss) on mark-to market derivatives			(20,453	)			(5,939	)			(34,774	)
Commodity contracts(2)		Discontinued operations			—				665				(1,190	)
				$	(20,453	)		$	(5,280	)		$	(37,128	)

 

(1)	Hedges previously designated as cash flow hedges.

(2)	Dedesignated cash flow hedges and non-designated hedges.

The fair value of the derivatives included in the Partnership’s consolidated combined balance sheets was as follows (in thousands):

 

		December 31,
		2011				2010
Current portion of derivative asset		$	15,447			$	36,621
Long-term derivative asset			30,941				36,125
Current portion of derivative liability			—				(4,917	)
Long-term derivative liability			—				(11,901	)
Total Partnership net asset		$	46,388			$	55,928

NOTE 11 – FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership and APL 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. 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.

 

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Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership and APL use a fair value methodology to value the assets and liabilities for their outstanding derivative contracts (see Note 10). The Partnership’s and APL’s commodity derivative contracts, with the exception of APL’s NGL fixed price swaps and NGL options, are valued 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. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGL’s for similar locations, and therefore are defined as Level 3 fair value measurements. Valuations for APL’s NGL options are based on forward price curves developed by the related financial institution, and therefore are defined as Level 3 fair value measurements.

Information for assets and liabilities measured at fair value at December 31, 2011 and 2010 was as follows (in thousands):

 

		Level 1				Level 2				Level 3				Total
December 31, 2011
Partnership commodity-based derivatives		$	—			$	29,929			$	—			$	29,929
APL commodity-based derivatives			—				(87	)			16,546				16,459
Total		$	—			$	29,842			$	16,546			$	46,389
December 31, 2010
Partnership commodity-based derivatives		$	—			$	66,100			$	—			$	66,100
APL commodity-based derivatives			—				(8,382	)			(1,790	)			(10,172	)
Total		$	—			$	57,718			$	(1,790	)		$	55,928

APL’s Level 3 fair value amount relates to its derivative contracts on NGL fixed price swaps and NGL options. The following table provides a summary of changes in fair value of APL’s Level 3 derivative instruments as of December 31, 2011 (in thousands):

 

		NGL Fixed Price Swaps								NGL Put Options								Total
		Volume(1)				Amount				Volume(1)				Amount				Amount
Balance – January 1, 2010			—			$	—				43,470			$	1,268			$	1,268
New contracts(2)			57,246				—				8,820				—				—
Cash settlements from unrealized gain (loss)(3)(4)			(24,486	)			1,634				(52,290	)			7,246				8,880
Net change in unrealized loss(3)			—				(3,424	)			—				(2,005	)			(5,429	)
Option premium recognition(4)			—				—				—				(6,509	)			(6,509	)
Balance – December 31, 2010			32,760				(1,790	)			—				—				(1,790	)
New contracts(2)			58,002				—				110,796				28,187				28,187
Cash settlements from unrealized gain (loss)(3)(4)			(41,118	)			10,826				(18,186	)			2,398				13,224
Net change in unrealized loss(3)			—				(10,769	)			—				(9,875	)			(20,644	)
Option premium recognition(4)			—				—				—				(2,431	)			(2,431	)
Balance – December 31, 2011			49,644			$	(1,733	)			92,610			$	18,279			$	16,546

 

(1)	Volumes are stated in thousand gallons.

(2)	Swaps are entered into with no value on the date of trade. Options include premiums paid, which are included in the value of the derivatives on the date of trade.

(3)	Included within gain (loss) on mark-to-market derivatives on the Partnership’s consolidated combined statements of operations.

(4)	Includes option premium cost reclassified from unrealized gain (loss) to realized gain (loss) at time of option expiration.

Other Financial Instruments

The estimated fair value of the Partnership’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Partnership could realize upon the sale or refinancing of such financial instruments.

The Partnership’s other current assets and liabilities on its consolidated combined balance sheets are financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature. The estimated fair values of the Partnership’s debt at December 31, 2011 and 2010, which consist principally of

 

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APL’s Senior Notes and borrowings under the Partnership’s and APL’s revolving credit facilities, were $537.3 million and $532.3 million, respectively, compared with the carrying amounts of $524.1 million and $601.4 million, respectively. The APL Senior Notes were valued based upon recent trading activity. The carrying value of outstanding borrowings under the credit facilities, which bear interest at a variable interest rate, approximates their estimated fair value.

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

The Partnership estimates the fair value of 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 the Partnership and estimated inflation rates (see Note 8). Information for assets that were measured at fair value on a nonrecurring basis for the years ended December 31, 2011 and 2010 were as follows (in thousands):

 

		Years Ended December 31,
		2011								2010
		Level 3				Total				Level 3				Total
Asset retirement obligations		$	713			$	713			$	472			$	472
Total		$	713			$	713			$	472			$	472

The Partnership estimates the fair value of its long-lived assets by 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 December 31, 2011, 2010 and 2009, the Partnership recognized impairments of long-lived assets in the amount of $7.0 million, $50.7 million and $156.4 million, respectively. Each of these impairments is defined as a Level 3 fair value measurement (See Note 2 – Impairment of Long-Lived Assets).

NOTE 12 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

In the ordinary course of its business operations, the Partnership has ongoing relationships with several related entities:

Relationship with the Partnership’s Sponsored Investment Partnerships. The Partnership conducts certain activities through, and a portion of its revenues are attributable to, the Drilling Partnerships. The Partnership serves as general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the general partner, the Partnership is liable for the Drilling Partnerships’ liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Drilling Partnerships. The Partnership is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Partnership’s revenue, and costs and expenses according to the respective partnership agreements.

Relationship with Laurel Mountain. Concurrently with the Partnership’s acquisition of the Transferred Business, APL completed its sale to Atlas Energy Resources of its 49% non-controlling interest in Laurel Mountain (the “Laurel Mountain Sale”) for $409.5 million in cash, including adjustments based on certain capital contributions APL made to and distributions it received from Laurel Mountain after January 1, 2011. APL retained the preferred distribution rights under the limited liability company agreement of Laurel Mountain entitling APL Laurel Mountain LLC to receive all payments made under a note issued to Laurel Mountain by Williams Laurel Mountain, LLC in connection with the formation of Laurel Mountain.

Subsequent to the Laurel Mountain Sale, the Partnership has maintained its gas gathering agreements with Laurel Mountain, whereby the Partnership is obligated to pay Laurel Mountain all of the gathering fees it collects from the Drilling Partnerships, which is currently defined as 13% of the gross sales price received for the Drilling Partnerships’ gas, plus any excess amount of the gathering fees collected up to an amount equal to approximately 16% of the natural gas sales price. The gathering agreements contain additional provisions which define certain obligations and options of each party to build and connect newly drilled wells to any Laurel Mountain gathering system.

 

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NOTE 13 — COMMITMENTS AND CONTINGENCIES

General Commitments

The Partnership leases equipment under leases with varying expiration dates through 2014. Rental expense was $7.3 million, $7.8 million and $8.2 million for the years ended December 31, 2011, 2010 and 2009, respectively. Future minimum rental commitments for the next five years are as follows (in thousands):

 

Years Ended December 31,
2012		$	3,395
2013			1,940
2014			1,390
2015			1,267
2016			1,111
Thereafter			3,620
		$	12,723

The Partnership 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. Subject to certain conditions, investor partners in certain Drilling Partnerships have the right to present their interests for purchase by the Partnership, as managing general partner. The Partnership is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on past experience, the management of the Partnership believes that any liability incurred would not be material. Also, the Partnership has agreed to subordinate a portion of its share of net partnership revenues from the Drilling Partnerships to the benefit of the investor partners until they have received specified returns, typically 10% per year determined on a cumulative basis, over a specific period, typically the first five to seven years, in accordance with the terms of the partnership agreements. For the years ended December 31, 2011, 2010 and 2009, $4.0 million, $10.9 million and $3.9 million, respectively, of the Partnership’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the Drilling Partnerships.

Immediately following the acquisition of the Transferred Business, the Partnership received from Chevron $118.7 million related to a contractual cash transaction adjustment related to certain liabilities of the Transferred Business at February 17, 2011. Following the closing of the acquisition of the Transferred Business, the Partnership entered into a reconciliation process with Chevron to determine the final cash adjustment amount pursuant to the transaction agreement. The reconciliation period was ongoing at December 31, 2011, and certain amounts included within the contractual cash transaction adjustment are in dispute between the parties. The Partnership believes the amounts included within the contractual cash transaction adjustment are appropriate and is currently engaged in an on-going reconciliation process with Chevron. The resolution of the disputed amounts could result in the Partnership being required to repay a portion of the cash transaction adjustment (see Note 3). According to the transaction agreement, should the Partnership and Chevron not be able to come to an agreement during the reconciliation process, the two parties will enter into arbitration with a neutral public accounting firm. At December 31, 2011, the Partnership believes the range of loss associated with the disputed balances is between zero and $45.0 million.

In May 2011, the Partnership entered into a joint venture agreement with Mountain V Oil and Gas, Inc. (“Mountain V”), a privately-held oil and gas exploration and production company, under which the Partnership’s Drilling Partnerships will invest approximately $35 million to drill 13 wells into the Marcellus Shale formation in Upshur County, West Virginia. As of December 31, 2011, the Partnership has drilled 11 wells, for which approximately $29.7 million has been invested. The Partnership expects to drill the remaining two wells during 2012.

On February 26, 2010, APL received notice from Williams, its former joint venture partner in Laurel Mountain, alleging that certain title defects existed with respect to the real property contributed by APL to Laurel Mountain. In August 2010, Williams asserted additional indemnity claims under the Formation and Exchange Agreement with Williams totaling approximately $19.8 million. Based on APL’s analysis, an accrual was established with respect to the portion of Williams’ claims that it deemed probable, which was less than 51% of the amounts asserted by Williams. In December 2011, APL resolved the claims with Williams for an amount approximately equal to APL’s accrual.

The Partnership is party to employment agreements with certain executives that provide compensation and certain other benefits. The agreements also provide for severance payments under certain circumstances.

As of December 31, 2011, the Partnership and APL are committed to expend approximately $159.4 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

 

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Legal Proceedings

The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.

NOTE 14 – ISSUANCES OF UNITS

Pursuant to prevailing accounting literature, the Partnership recognizes gains on APL’s equity transactions as a credit to partners’ capital on its consolidated combined balance sheets rather than as income on its consolidated combined statements of operations. These gains represent the Partnership’s portion of the excess net offering price per unit of each of APL’s common units over the book carrying amount per unit.

In February 2011, the Partnership paid $30.0 million in cash and issued approximately 23.4 million newly issued common limited partner units for the Transferred Business acquired from AEI. Based on the Partnership’s common limited partner unit’s February 17, 2011 closing price on the NYSE, the common units issued to AEI were valued approximately at $372.2 million.

Atlas Pipeline Partners

In June 2010, APL sold 8,000 newly-created 12% Cumulative Class C Limited Partner Preferred Units (the “APL Class C Preferred Units”) to AEI for cash consideration of $1,000 per APL Class C Preferred Unit (the “Face Value”). The APL Class C Preferred Units were redeemable by APL for an amount equal to the Face Value of the units being redeemed plus all accrued but unpaid dividends. AEI was entitled to distributions of 12% per annum, paid quarterly on the same date as the distribution payment date for APL’s common units. On February 17, 2011, the APL Class C Preferred Units were acquired from AEI by Chevron as part of AEI’s merger with Chevron. On May 27, 2011, APL redeemed all 8,000 APL Class C Preferred Units outstanding for cash at the liquidation value of $1,000 per unit, or $8.0 million, plus $0.2 million, representing the accrued dividend on the 8,000 APL Class C Preferred Units prior to APL’s redemption. At December 31, 2011, APL had no APL Class C Preferred Units outstanding.

In January 2010, APL executed amendments to warrants to purchase 2,689,765 of its common units. The warrants were originally issued along with its common units in connection with a private placement to institutional investors that closed in August 2009. The amendments to the warrants provided that, for the period January 8 through January 12, 2010, the warrant exercise price was lowered to $6.00 from $6.35 per unit. In connection with the amendments, the holders of the warrants agreed to exercise all of the warrants for cash, which resulted in net cash proceeds of approximately $15.3 million. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan and credit facility.

In August 2009, APL sold 2,689,765 common units in a private placement at an offering price of $6.35 per unit, yielding net proceeds of approximately $16.1 million. APL also received a capital contribution from the Partnership of $0.4 million for the Partnership to maintain its 2.0% general partner interest in APL. In addition, APL issued warrants granting investors in the private placement the right to purchase an additional 2,689,765 common units at a price of $6.35 per unit for a period of two years following the issuance of the original common units. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan.

In March 2009, APL issued 5,000 12.0% cumulative convertible Class B preferred units of limited partner interests (the “Class B Preferred Units”) to AEI for cash consideration of $1,000 per Class B Preferred Unit (the “Face Value”) pursuant to a certificate of designation (the “Class B Preferred Units Certificate of Designation”), increasing the outstanding Class B Preferred Units to 15,000 Class B Preferred Units, which were all held by AEI. The proceeds from the sale of the Class B Preferred Units were used for general partnership purposes. Additionally, in March 2009, APL and AEI agreed to amend the terms of the Class B Preferred Units Certificate of Designation to remove the conversion feature, thus the Class B Preferred Units were not convertible into APL common units. In November 2010, APL redeemed the 15,000 units of Class B Preferred Units for cash, at the liquidation value of $1,000 per unit, or $15.0 million, plus $0.2 million accrued dividends representing the quarterly dividend on the 15,000 Class B Preferred Units prior to its redemption. At December 31, 2011 and 2010, APL had no Class B Preferred Units outstanding.

In January 2009, APL and Sunlight Capital Partners, LLC (“Sunlight Capital”), an affiliate of Elliott & Associates, amended certain terms of the then outstanding 30,000 cumulative convertible preferred units (“Class A Preferred Units”) owned by Sunlight Capital. The amendment (a) increased the dividend yield from 6.5% to 12.0% per annum, effective

 

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January 1, 2009, and (b) required that APL issue Sunlight Capital $15.0 million of its 8.125% senior unsecured notes due 2015 to redeem 10,000 Class A Preferred Units. APL’s management estimated that the fair value of the $15.0 million 8.125% senior unsecured notes issued to redeem the Class A Preferred Units was approximately $10.0 million at the date of redemption based upon the market price of the publicly-traded senior notes. In April 2009, APL redeemed 10,000 of Class A Preferred Units for cash at the liquidation value of $1,000 per unit, or $10.0 million and APL converted 5,000 of the Class A Preferred Units into 1,465,653 common units. In May 2009, APL redeemed the remaining 5,000 Class A Preferred Units for cash at the liquidation value of $1,000 per unit, or $5.0 million plus $0.2 million, representing the quarterly dividend on the 5,000 Class A Preferred Units prior to APL’s redemption. At December 31, 2011, 2010, and 2009, APL had no Class A Preferred Units outstanding.

NOTE 15 – CASH DISTRIBUTIONS

The Partnership has a cash distribution policy under which it distributes, within 50 days after the end of each quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders. Distributions declared by the Partnership for the period from January 1, 2009 through December 31, 2011 were as follows (in thousands, except per unit amounts):

 

Date Cash Distribution Paid or Payable		For Quarter Ended		Cash Distribution  per Common Limited Partner Unit
February 13, 2009		December 31, 2008		$	0.06
November 16, 2010		September 30, 2010		$	0.05
February 18, 2011		December 31, 2010		$	0.07
May 20, 2011		March 31, 2011		$	0.11
August 19, 2011		June 30, 2011		$	0.22
November 18, 2011		September 30, 2011		$	0.24

On January 26, 2012, the Partnership declared a cash distribution of $0.24 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2011. The $12.3 million distribution will be paid on February 17, 2012 to unitholders of record at the close of business on February 7, 2012.

Atlas Pipeline Partners Cash Distributions. APL is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders and the Partnership, as general partner. If APL’s common unit distributions in any quarter exceed specified target levels, the Partnership will receive between 15% and 50% of such distributions in excess of the specified target levels. Common unit and general partner distributions declared by APL for the period from January 1, 2009 through December 31, 2011 were as follows (in thousands, except per unit amounts):

 

Date Cash Distribution Paid		For Quarter Ended		APL  Cash Distribution per  Common Limited Partner Unit				Total APL  Cash Distribution to  Common Limited Partners				Total APL  Cash Distribution to  the General Partner
February 13, 2009		December 31, 2008		$	0.38			$	17,463			$	2,545
May 15, 2009		March 31, 2009		$	0.15			$	7,149			$	1,010
November 14, 2010		September 30, 2010		$	0.35			$	18,660			$	2,377
February 14, 2011		December 31, 2010		$	0.37			$	19,735			$	2,534
May 13, 2011		March 31, 2011		$	0.40			$	21,400			$	2,730
August 12, 2011		June 30, 2011		$	0.47			$	25,184			$	3,687
November 7, 2011		September 30, 2011		$	0.54			$	28,953			$	4,946

On January 26, 2012, APL declared a cash distribution of $0.55 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2011. The $31.5 million distribution, including $5.2 million to the Partnership, will be paid on February 14, 2012 to unitholders of record at the close of business on February 7, 2012.

 

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NOTE 16 – BENEFIT PLANS

2010 Long-Term Incentive Plan

The Board of Directors of the General Partner approved and adopted the Partnership’s 2010 Long-Term Incentive Plan (“2010 LTIP”) effective February 2011. The 2010 LTIP provides equity incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for the Partnership. The 2010 LTIP is administered by a committee consisting of the Board or committee of the Board or board of an affiliate appointed by the Board (the “LTIP Committee”), which is the Compensation Committee of the General Partner’s board of directors. Under the 2010 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 5,300,000 common limited partner units. At December 31, 2011, the Partnership had 4,142,464 phantom units and unit options outstanding under the 2010 LTIP, with 1,157,536 phantom units and unit options available for grant.

Upon a change in control, as defined in the 2010 LTIP, all unvested awards held by directors will immediately vest in full. In the case of awards held by eligible employees, upon the eligible employee’s termination of employment without “cause”, as defined in the 2010 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 our 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 our 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 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 committee deems necessary or appropriate.

2010 Phantom Units. A phantom unit entitles a Participant to receive a Partnership common unit upon vesting of the phantom unit. In tandem with phantom unit grants, the LTIP Committee may grant Participant Distribution Equivalent Rights (“DERs”), which are the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions the Partnership makes on a common unit during the period such phantom unit is outstanding. Through December 31, 2011, phantom units granted under the 2010 LTIP generally will vest 25% on the third anniversary of the date of grant and the remaining 75% on the fourth anniversary of the date of grant. Of the phantom units outstanding under the 2010 LTIP at December 31, 2011, there are 6,274 units that will vest within the following twelve months. All phantom units outstanding under the 2010 LTIP at December 31, 2011 include DERs granted to the Participants by the LTIP Committee. There was $1.0 million paid with respect to the 2010 LTIP DERs for the year ended December 31, 2011. There were no amounts paid with respect to the 2010 LTIP DERs for the years ended December 31, 2010 and 2009.

 

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The following table sets forth the 2010 LTIP phantom unit activity for the periods indicated:

 

		Years Ended December 31,
		2011								2010								2009
		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 period			—			$	—				—			$	—				—			$	—
Granted			1,891,539				22.11				—				—				—				—
Vested (1)			—				—				—				—				—				—
Forfeited			(53,375	)			22.21				—				—				—				—
Outstanding, end of period(2)			1,838,164			$	22.11				—			$	—				—			$	—
Non-cash compensation expense recognized (in thousands)						$	8,060							$	—							$	—

 

(1)	No phantom unit awards vested during the years ended December 31, 2011, 2010 and 2009.

(2)	The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2011 was $44.7 million.

At December 31, 2011, the Partnership had approximately $32.7 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2010 LTIP based upon the fair value of the awards.

2010 Unit Options. A unit option entitles a Participant to receive a common unit of the Partnership upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option is equal to the fair market value of the Partnership’s common unit on the date of grant of the option. The LTIP Committee also shall determine how the exercise price may be paid by the Participant. The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through December 31, 2011, unit options granted under the 2010 LTIP generally will vest 25% of the original granted amount three years from the date of grant and the remaining 75% of the original granted amount four years from the date of grant. Awards will automatically vest upon a change of control of the Partnership, as defined in the 2010 LTIP. There are 1,875 unit options outstanding under the 2010 LTIP at December 31, 2011 that will vest within the following twelve months.

The following table sets forth the 2010 LTIP unit option activity for the periods indicated:

 

		Years Ended December 31,
		2011								2010								2009
		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 period			—			$	—				—			$	—				—			$	—
Granted			2,384,300				22.12				—				—				—				—
Forfeited			(80,000	)			22.23				—				—				—				—
Outstanding, end of period(1)(2)			2,304,300			$	22.12				—			$	—				—			$	—
Options exercisable, end of period(3)			—			$	—				—			$	—				—			$	—
Non-cash compensation expense recognized (in thousands)						$	4,591							$	—							$	—

 

(1)	The weighted average remaining contractual life for outstanding options at December 31, 2011was 9.3 years.

(2)	The options outstanding at December 31, 2011 had an aggregate intrinsic value of $5.0 million.

(3)	No options were exercisable at December 31, 2011. No options vested during the years ended December 31, 2011, 2010 and 2009.

At December 31, 2011, the Partnership had approximately $18.0 million in unrecognized compensation expense related to unvested unit options outstanding under the 2010 LTIP based upon the fair value of the awards. The Partnership used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the period indicated:

 

		Year Ended December 31, 2011
Expected dividend yield			1.6	%
Expected unit price volatility			48.0	%
Risk-free interest rate			2.7	%
Expected term (in years)			6.87
Fair value of unit options granted		$	9.79

 

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2006 Long-Term Incentive Plan

The Board of Directors of the General Partner approved and adopted the Partnership’s 2006 Long-Term Incentive Plan (“2006 LTIP”), which provides equity incentive awards to Participants who perform services for the Partnership. The 2006 LTIP is administered by the LTIP Committee. The LTIP Committee may grant such awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units. At December 31, 2011, the Partnership had 936,255 phantom units and unit options outstanding under the 2006 LTIP, with 922,871 phantom units and unit options available for grant. Share based payments to non-employees, which have a cash settlement option, are recognized within liabilities in the financial statements based upon their current fair market value.

2006 Phantom Units. Through December 31, 2011, phantom units granted under the 2006 LTIP generally will vest 25% of the original granted amount three years from the date of grant and the remaining 75% of the original granted amount four years from the date of grant. Awards will automatically vest upon a change of control of the Partnership, as defined in the 2006 LTIP. Of the phantom units outstanding under the 2006 LTIP at December 31, 2011, 9,800 units will vest within the following twelve months. All phantom units outstanding under the 2006 LTIP at December 31, 2011 include DERs granted to the Participants by the LTIP Committee. The amount paid with respect to 2006 LTIP’s DERs was $20,000 for the year ended December 31, 2011. This amount was recorded as a reduction of partners’ capital on the Partnership’s consolidated combined balance sheet. The amounts paid with respect to 2006 LTIP’s DERs were $7,000 and $14,000 for the years ended December 31, 2010 and 2009, respectively.

The following table sets forth the 2006 LTIP phantom unit activity for the periods indicated:

 

		Years Ended December 31,
		2011								2010								2009
		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 period			27,294			$	13.81				138,875			$	23.72				226,300			$	23.67
Granted			17,685				17.71				20,594				10.68				2,000				3.60
Vested (1)			(12,338	)			13.65				(131,675	)			23.70				(44,425	)			23.75
Forfeited			—				—				(500	)			32.28				(45,000	)			22.56
Outstanding, end of period(2)			32,641			$	15.99				27,294			$	13.81				138,875			$	23.72
Non-cash compensation expense recognized (in thousands)						$	422							$	726							$	515

 

(1)	The intrinsic values for phantom unit awards vested during the year ended December 31, 2011, 2010 and 2009 were $0.2 million, $1.8 million and $0.2 million, respectively.

(2)	The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2011 was $0.8 million.

At December 31, 2011, the Partnership had approximately $0.4 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2006 LTIP based upon the fair value of the awards.

2006 Unit Options. The exercise price of the unit option may be equal to or more than the fair market value of the Partnership’s common unit on the date of grant of the option. Unit option awards expire 10 years from the date of grant. Through December 31, 2011, unit options granted under the 2006 LTIP generally will vest 25% on the third anniversary of the date of grant and the remaining 75% on the fourth anniversary of the date of grant. Awards will automatically vest upon

 

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a change of control of the Partnership, as defined in the 2006 LTIP. There are no unit options outstanding under the 2006 LTIP at December 31, 2011 that will vest within the following twelve months. For the year ended December 31, 2011, the Partnership received $0.2 million from the exercise of options. For the years ended December 31, 2010 and 2009, no options were exercised.

The following table sets forth the 2006 LTIP unit option activity for the periods indicated:

 

		Years Ended December 31,
		2011								2010								2009
		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 period			955,000			$	20.54				955,000			$	20.54				1,215,000			$	22.56
Granted			—				—				—				—				100,000				3.24
Exercised(1)			(51,386	)			3.24				—				—				—				—
Forfeited			—				—				—				—				(360,000	)			22.56
Outstanding, end of period(2)(3)			903,614			$	21.52				955,000			$	20.54				955,000			$	20.54
Options exercisable, end of period(4)			903,614			$	21.52				855,000			$	22.56				213,750			$	22.56
Non-cash compensation expense recognized (in thousands)						$	28							$	519							$	48

 

(1)	The intrinsic value of options exercised during the year ended December 31, 2011 was $1.0 million. No options were exercised during the years ended December 31, 2010 and 2009.

(2)	The weighted average remaining contractual life for outstanding options at December 31, 2011 was 5.0 years.

(3)	The aggregate intrinsic value of options outstanding at December 31, 2011 was approximately $2.5 million.

(4)	The weighted average remaining contractual life for options exercisable at December 31, 2011 was 5.0 years.

At December 31, 2011, the Partnership had no unrecognized compensation expense related to unvested unit options outstanding under the 2006 LTIP based upon the fair value of the awards. The Partnership uses the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. No options were granted during the years ended December 31, 2011 and 2010 under the 2006 Plan. The following weighted average assumptions were used for the period indicated:

 

		Year Ended December 31, 2009
Expected dividend yield			7.0	%
Expected unit price volatility			40.0	%
Risk-free interest rate			2.3	%
Expected term (in years)			6.88
Fair value of unit options granted		$	0.61

APL Long-Term Incentive Plans

APL has a 2004 Long-Term Incentive Plan (“APL 2004 LTIP”), and a 2010 Long-Term Incentive Plan, which was modified on April 26, 2011, (“APL 2010 LTIP” and collectively with the APL 2004 LTIP, the “APL LTIPs”), in which officers, employees and non-employee managing board members of APL’s general partner and employees of APL’s general partner’s affiliates and consultants are eligible to participate. The APL LTIPs are administered by a committee (the “APL LTIP Committee”) appointed by APL’s general partner. Under the 2010 APL LTIP, the APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 3,000,000 common units, in addition to the 435,000 common units authorized in previous plans. At December 31, 2011, APL had 394,489 phantom units outstanding under the APL LTIPs, with 2,364,279 phantom units and unit options available for grant. APL generally issues new common units for phantom units and unit options, which have vested and have been exercised. Share based payments to non-employees, which have a cash settlement option, are recognized within liabilities in the financial statements based upon their current fair market value.

 

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APL Phantom Units. Through December 31, 2011, phantom units granted under the APL LTIPs generally had vesting periods of four years. In conjunction with the approval of the 2010 LTIP, the holders of 300,000 of the 375,000 equity indexed bonus units (“APL Bonus Units”) under APL’s subsidiary’s plan discussed below agreed to exchange their APL Bonus Units for an equivalent number of phantom units, effective as of June 1, 2010. These phantom units will vest over a two year period. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards may automatically vest upon a change of control, as defined in the APL LTIPs. Of the units outstanding under the APL LTIPs at December 31, 2011, 180,748 units will vest within the following twelve months. APL is authorized to repurchase common units to cover employee-related taxes on certain phantom units, when they have vested. APL purchased and retired 28,878 common units and 20,442 common units during the years ended December 31, 2011 and 2010, respectively, for a cost of $1.0 million and $0.2 million, respectively, which were recorded as reductions of non-controlling interest on the Partnership’s consolidated balance sheet. On February 17, 2011, the employment agreement with APL’s Chief Executive Officer (“CEO”) was terminated in connection with AEI’s merger with Chevron and 75,250 outstanding phantom units, which represents all outstanding phantom units held by APL’s CEO, automatically vested and were issued.

All phantom units outstanding under the APL LTIPs at December 31, 2011 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL LTIP DERs were $0.8 million, $0.2 million and $0.1 million for the years ended December 31, 2011, 2010 and 2009, respectively. These amounts were recorded as reductions of non-controlling interest on the Partnership’s consolidated combined balance sheet.

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

 

		Years Ended December 31,
		2011								2010								2009
		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 period			490,886			$	11.75				52,233			$	39.72				126,565			$	44.22
Granted			178,318				33.47				575,112				10.49				2,000				4.75
Vested and issued(1)(2)			(233,465	)			11.34				(126,584	)			17.11				(58,257	)			45.68
Forfeited			(41,250	)			13.49				(9,875	)			17.39				(18,075	)			48.17
Outstanding, end of period(3)(4)			394,489			$	21.63				490,886			$	11.75				52,233			$	39.72
Non-cash compensation expense recognized (in thousands)(5)						$	3,271							$	3,480							$	694

 

(1)	The intrinsic values for phantom unit awards vested and issued during the years ended December 31, 2011, 2010 and 2009 were $7.4 million, $1.5 million and $0.3 million, respectively.

(2)	There were 414 matured phantom units which were settled for $14,000 cash during the year ended December 31, 2011. No phantom units were settled in cash during the years ended December 31, 2010 and 2009.

(3)	The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2011 was $14.7 million.

(4)	There were 14,675 and 8,010 outstanding phantom unit awards at December 31, 2011 and 2010, respectively, which were classified as liabilities due to a cash option available on the related phantom unit awards.

(5)

Non-cash compensation expense for the year ended December 31, 2011 includes incremental compensation expense of $0.5 million, related to the accelerated vesting of phantom units held by the CEO of APL’s General Partner. Non-cash compensation expense for the year ended December 31, 2010 includes $2.2 million related to Bonus Units converted to phantom units.

At December 31, 2011, APL had approximately $5.3 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIPs based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 2.1 years.

APL Unit Options. The exercise price of the unit option is equal to the fair market value of APL’s common unit on the date of grant of the option. The APL LTIP Committee also shall determine how the exercise price may be paid by the Participant. The APL LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through December 31, 2011, unit options granted under the APL LTIPs generally will vest 25% on each of the next four anniversaries of the date of grant. Awards will automatically vest upon a change of control of APL, as defined in the APL LTIPs. On February 17, 2011, the employment agreement with the CEO of APL’s General Partner was terminated in connection with AEI’s merger with Chevron, and 50,000 outstanding unit options held by the CEO automatically vested. As of December 31, 2011, all unit options were exercised. There are no unit options outstanding under APL LTIPs at December 31, 2011 that will vest within the following twelve months.

 

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The following table sets forth the APL LTIPs’ unit option activity for the periods indicated:

 

		Years Ended December 31,
		2011								2010								2009
		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 period			75,000			$	6.24				100,000			$	6.24				—			$	—
Granted			—				—				—				—				100,000				6.24
Exercised(1)(2)			(75,000	)			6.24				(25,000	)			6.24				—				—
Forfeited			—				—				—				—				—				—
Outstanding, end of period(3)			—			$	—				75,000			$	6.24				100,000			$	6.24
Options exercisable, end of period(3)			—			$	—				—			$	—				—			$	—
Non-cash compensation expense recognized (in thousands)(4)						$	3							$	4							$	7

 

(1)

The intrinsic values for the options exercised during the years ended December 31, 2011 and 2010, were $1.7 million and $0.5 million, respectively. Approximately $0.5 million and $0.2 million were received from the exercise of unit option awards during the years ended December 31, 2011 and 2010. No options were exercised during the year ended December 31, 2009.

(2)	No options are outstanding or exercisable at December 31, 2011.

(3)	Incremental compensation expense of $2,000, related to the accelerated vesting of options held by the CEO of APL’s General Partner, was recognized during the year ended December 31, 2011.

At December 31, 2011, APL had no unrecognized compensation expense related to unvested unit options outstanding under APL’s LTIPs based upon the fair value of the awards.

APL uses the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. No options were granted during the years ended December 31, 2011 and 2010 under the APL LTIPs. The following weighted average assumptions were used for the period indicated:

 

		Year Ended December 31, 2009
Expected dividend yield			11.0	%
Expected unit price volatility			20.0	%
Risk-free interest rate			2.2	%
Expected term (in years)			6.25
Fair value of unit options granted		$	0.14

APL Employee Incentive Compensation Plan and Agreement

In June 2009, a wholly-owned subsidiary of APL adopted an incentive plan (the “Cash Plan”), which allows for equity-indexed cash incentive awards to employees of APL (the “Participants”). The Cash Plan is administered by a committee appointed by the CEO of the General Partner. Under the Cash Plan, cash bonus units may be awarded to Participants at the discretion of the committee. During 2009, the committee granted 375,000 APL Bonus Units. An APL Bonus Unit entitles the employee to receive the cash equivalent of the then-fair market value of a common limited partner unit, without payment of an exercise price, upon vesting of the APL Bonus Unit. APL Bonus Units vest ratably over a three year period from the date of grant and will automatically vest upon a change of control, death, or termination without cause, each as defined in the governing document. Vesting will terminate upon termination of employment with cause. In conjunction with the approval of the 2010 LTIP, the holders of 300,000 of the then outstanding 375,000 APL Bonus Units agreed to exchange their Bonus Units for phantom units during the year ended December 31, 2010.

 

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At December 31, 2011, APL had 25,500 outstanding APL Bonus Units, which will all vest within the following twelve months. APL recognizes compensation expense related to these awards based upon the fair value, which is re-measured each reporting period based upon the current fair value of the underlying common units. APL recognized compensation expense related to the re-measurement of the outstanding Bonus Units of $0.9 million during the year ended December 31, 2011, a credit of $0.2 million during the year ended December 31, 2010 and expense of $1.2 million during the year ended December 31, 2009, which were recorded within general and administrative expense on the Partnership’s consolidated combined statements of operations. APL had $0.8 million at both December 31, 2011 and 2010 included within accrued liabilities on the Partnership’s consolidated balance sheet with regard to these awards, which represents their fair value as of those dates.

NOTE 17 — OPERATING SEGMENT INFORMATION

The Partnership’s operations include four reportable operating segments. These operating segments reflect the way the Partnership manages its operations and makes business decisions. Operating segment data for the periods indicated are as follows (in thousands):

 

		Years Ended December 31,
		2011				2010				2009
Gas and oil production
Revenues		$	66,979			$	93,050			$	112,979
Operating costs and expenses			(17,100	)			(23,323	)			(25,557	)
Depreciation, depletion and amortization expense			(27,430	)			(36,668	)			(40,067	)
Asset impairment			(6,995	)			(50,669	)			(156,359	)
Segment income (loss)		$	15,454			$	(17,610	)		$	(109,004	)
Well construction and completion
Revenues		$	135,283			$	206,802			$	372,045
Operating costs and expenses			(115,630	)			(175,247	)			(315,546	)
Segment income		$	19,653			$	31,555			$	56,499
Other partnership management(1)
Revenues		$	61,862			$	46,923			$	50,390
Operating costs and expenses			(29,580	)			(31,043	)			(34,599	)
Depreciation, depletion and amortization expense			(4,508	)			(4,090	)			(3,645	)
Segment income		$	27,774			$	11,790			$	12,146
Atlas Pipeline
Revenues (2)		$	1,306,785			$	940,508			$	676,648
Operating costs and expenses			(1,102,544	)			(769,946	)			(579,953	)
Depreciation and amortization expense			(77,435	)			(74,897	)			(75,684	)
Other asset impairment			—				—				(10,325	)
Segment income		$	126,806			$	95,665			$	10,686
Reconciliation of segment income (loss) to net income (loss) from continuing operations
Segment income (loss)
Gas and oil production		$	15,454			$	(17,610	)		$	(109,004	)
Well construction and completion			19,653				31,555				56,499
Other partnership management			27,774				11,790				12,146
Atlas Pipeline			126,806				95,665				10,686
Total segment income (loss)			189,687				121,400				(29,673	)
General and administrative expenses(2)			(80,584	)			(37,561	)			(38,932	)
Gain (loss) on asset sales(2)			256,292				(13,676	)			108,947
Interest expense(2)			(38,394	)			(90,448	)			(104,053	)
Loss on early extinguishment of debt(2)			(19,574	)			(4,359	)			(2,478	)
Net income (loss) from continuing operations		$	307,427			$	(24,644	)		$	(66,189	)

 

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Capital expenditures
Gas and oil production		$	38,362			$	73,400			$	89,389
Well construction and completion			—				—				—
Other partnership management			3,223				17,200				9,900
Atlas Pipeline			245,426				45,752				110,274
Corporate and other			5,739				3,008				13
Total capital expenditures		$	292,750			$	139,360			$	209,576

 

		December 31,
		2011				2010
Balance sheet
Goodwill:
Gas and oil production		$	18,145			$	18,145
Well construction and completion			6,389				6,389
Other partnership management			7,250				7,250
Atlas Pipeline			—				—
		$	31,784			$	31,784
Total assets:
Gas and oil production		$	593,320			$	593,368
Well construction and completion			6,987				9,627
Other partnership management			45,991				37,677
Atlas Pipeline			1,930,813				1,764,848
Corporate and other			106,987				29,742
		$	2,684,098			$	2,435,262

 

(1)	Includes revenues and expenses from well services, transportation, administration and oversight, and other that do not meet the quantitative threshold for reporting segment information.

(2)	The Partnership notes that interest expense, loss on early extinguishment of debt, gain (loss) on asset sales and general and administrative expenses have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.

NOTE 18 – SUBSEQUENT EVENTS

Formation of Atlas Resource Partners, L.P. In February 2012, the board of directors of the Partnership’s General Partner approved the formation of a newly created exploration and production master limited partnership named Atlas Resource Partners, L.P. (“ARP”), which will hold substantially all of the Partnership’s current natural gas and oil development and production assets and the partnership management business. The board of directors of the Partnership’s General Partner also approved the distribution of approximately 5.24 million ARP common units, which will be distributed on March 13, 2012 to the Partnership’s unitholders using a ratio of 0.1021 ARP limited partner units for each of the Partnership’s common units owned on the record date of February 28, 2012. The distribution of ARP limited partner units will represent an approximate 19.6% limited partner interest. Subsequent to the distribution, the Partnership will own a 2% general partner interest, all of the incentive distribution rights in ARP and common units representing an approximate 78.4% limited partner interest in ARP.

Cash Distributions. On January 26, 2012, the Partnership declared a cash distribution of $0.24 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2011. The $12.3 million distribution was paid on February 17, 2012 to unitholders of record at the close of business on February 7, 2012.

APL Cash Distributions. On January 26, 2012, APL declared a cash distribution of $0.55 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2011. The $31.5 million distribution, including $5.2 million to the Partnership, was paid on February 14, 2012 to unitholders of record at the close of business on February 7, 2012.

NOTE 19 — SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Gas Reserve Information. The preparation of the Partnership’s natural gas and oil reserve estimates was completed in accordance with its prescribed internal control procedures by its reserve engineers. The accompanying reserve information included below was derived from the reserve reports prepared for the Partnership’s annual report on Form 10-K

 

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for the year ended December 31, 2011. 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 and oil reserves which are all located in the United States, primarily in Colorado, Indiana, New York, Ohio, Pennsylvania, Tennessee and West Virginia. The independent reserves engineer’s evaluation was based on more than 35 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. The Partnership’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 Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 13 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our senior engineering staff and management, with final approval by our Executive Vice President.

The reserve disclosures that follow reflect estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of royalty interests, of natural gas, crude oil, condensate and natural gas liquids owned at year end and changes in proved reserves during the last three years. Proved oil and gas reserves are those quantities of oil and gas, that by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved developed reserves are those reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for undeveloped reserves cannot be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. In accordance with the prevailing accounting literature, the proved reserves quantities and future net cash flows as of December 31, 2011, 2010 and 2009 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, 2011, 2010 and 2009, 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 the Partnership or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors, for their effects have not been proved.

Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership are as follows (unaudited):

 

		Gas (Mcf)				Oil (Bbls)  (1)
Balance, January 1, 2009			203,636,945				1,725,834
Extensions, discoveries and other additions(2)			58,349,703				25,737
Sales of reserves in-place			(101,295	)			(1,944	)
Purchase of reserves in-place			110,953				302
Transfers to limited partnerships			(22,125,866	)			—
Revisions(3)			(42,110,044	)			265,371
Production			(14,105,432	)			(192,578	)
Balance, December 31, 2009			183,654,964				1,822,722
Extensions, discoveries and other additions(2)			64,776,600				—
Sales of reserves in-place			(9,241,358	)			—
Purchase of reserves in-place			366,276				1,203

 

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		Gas (Mcf)				Oil (Bbls)  (1)
Transfers to limited partnerships			(8,824,000	)			—
Revisions(4)			(41,580,400	)			326,913
Production			(13,087,079	)			(318,303	)
Balance, December 31, 2010			176,065,003				1,832,535
Extensions, discoveries and other additions(2)			9,966,952				8,217
Sales of reserves in-place			(990	)			—
Purchase of reserves in-place			586,662				2,216
Transfers to limited partnerships			(6,042,432	)			—
Revisions(5)			(11,436,615	)			77,661
Production			(11,462,149	)			(274,330	)
Balance, December 31, 2011			157,676,431				1,646,299
Proved developed reserves at:
January 1, 2009			66,622,045				48,170
December 31, 2009			140,392,057				1,785,712
December 31, 2010			137,393,017				1,832,535
December 31, 2011			138,403,225				1,638,083
Proved undeveloped reserves at:
January 1, 2009			137,014,900				1,677,664
December 31, 2009			43,262,907				37,010
December 31, 2010			38,671,986				—
December 31, 2011			19,273,206				8,216

 

(1)	Includes NGL information as reserve amounts are immaterial.

(2)	Principally includes increases of proved reserves due to the addition of Marcellus wells.

(3)

Represents a decrease in the price of natural gas and oil compared from the year ended December 31, 2008 to the year ended December 31, 2009, based on the change in pricing methodology to a twelve-month unweighted average based on the first-day-of-the-month prices for the year ended December 31, 2009.

(4)	Represents a downward revision, and related impairment charge, related to the Partnership’s shallow natural gas wells in Pennsylvania and Ohio, principally due to the reduction of drilling plans in the Clinton/Medina and Upper Devonian formations over the next five years.

(5)	Represents a downward revision of proved undeveloped reserves in the New Albany Shale due to the reduction of certain drilling plans related to the Partnership’s shallow natural gas wells.

Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities of the Partnership during the periods indicated were as follows (in thousands):

 

		Year Ended December 31,
		2011				2010
Natural gas and oil properties:
Proved properties		$	892,907			$	847,101
Unproved properties			43,253				42,520
Support equipment			9,413				8,138
			945,573				897,759
Accumulated depreciation, depletion and amortization(1)			(451,924	)			(419,375	)
Net capitalized costs		$	493,649			$	478,384

 

(1)

During the year ended December 31, 2011, the Partnership recognized $7.0 million of impairment related to its shallow natural gas wells in the Niobrara Shale. During the year ended December 31, 2010, the Partnership recognized $50.7 million of impairment related to its shallow natural gas wells in the Chattanooga and Upper Devonian shales.

 

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Results of Operations from Oil and Gas Producing Activities. The results of operations related to the Partnership’s oil and gas producing activities during the periods indicated were as follows (in thousands):

 

		Years Ended December 31,
		2011				2010				2009
Revenues		$	66,979			$	93,050			$	112,979
Production costs			(17,100	)			(23,323	)			(25,557	)
Depreciation, depletion and amortization			(27,430	)			(36,668	)			(40,067	)
Long-lived asset impairment(1)			(6,995	)			(50,669	)			(156,359	)
		$	15,454			$	(17,610	)		$	(109,004	)

 

(1)

During the year ended December 31, 2011, the Partnership recognized $7.0 million of impairment related to its shallow natural gas wells in the Niobrara Shale. During the year ended December 31, 2010, the Partnership recognized $50.7 million of impairment related to its shallow natural gas wells in the Chattanooga and Upper Devonian shales. During the year ended December 31, 2009, the Partnership recognized $156.4 million of impairment related to its shallow natural gas wells in the Upper Devonian Shale.

Costs incurred in Oil and Gas Producing Activities. The costs incurred by the Partnership in its oil and gas activities during the periods indicated are as follows (in thousands):

 

		Years Ended December 31,
		2011				2010				2009
Property acquisition costs:
Proved Properties		$	9,199			$	3,007			$	20
Unproved Properties			323				2,259				12,123
Exploration costs			1,156				—				—
Development costs			29,809				74,821				68,101
Total costs incurred in oil & gas producing activities		$	40,487			$	80,087			$	80,244

The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2011, 2010 and 2009, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (in thousands):

 

		Years Ended December 31,
		2011				2010				2009
Future cash inflows		$	949,286			$	1,045,725			$	993,206
Future production costs			(425,493	)			(464,392	)			(429,630	)
Future development costs			(27,266	)			(35,357	)			(75,011	)
Future net cash flows			496,527				545,976				488,565
Less 10% annual discount for estimated timing of cash flows			(276,668	)			(309,346	)			(309,747	)
Standardized measure of discounted future net cash flows		$	219,859			$	236,630			$	178,818

 

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The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves (in thousands), including amounts related to asset retirement obligations. Since the Partnership allocates taxable income to its owner, no recognition has been given to income taxes:

 

		Years Ended December 31,
		2011				2010				2009
Balance, beginning of year		$	236,630			$	178,818			$	271,616
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs			(46,304	)			(51,522	)			(38,316	)
Net changes in prices and production costs			(34	)			41,978				(95,712	)
Revisions of previous quantity estimates			757				21,598				22,126
Development costs incurred			1,842				7,565				9,936
Changes in future development costs			(3,591	)			(803	)			(43,615	)
Transfers to limited partnerships			(8,022	)			(4,148	)			(9,834	)
Extensions, discoveries, and improved recovery less related costs			14,923				54,887				24,882
Purchases of reserves in-place			736				492				141
Sales of reserves in-place			(1	)			(12,254	)			(303	)
Accretion of discount			23,663				17,882				25,298
Estimated settlement of asset retirement obligations			(3,105	)			(6,074	)			(2,252	)
Estimated proceeds on disposals of well equipment			3,363				2,227				2,285
Changes in production rates (timing) and other			(998	)			(14,016	)			12,566
Outstanding, end of year		$	219,859			$	236,630			$	178,818

NOTE 20 — QUARTERLY RESULTS (Unaudited)

 

		Fourth Quarter(1)				Third Quarter				Second Quarter				First Quarter
		(in thousands, except unit data)
Year ended December 31, 2011:
Revenues		$	415,614			$	441,479			$	408,892			$	304,924
Income (loss) from continuing operations		$	(9,628	)		$	50,907			$	24,438			$	241,710
Income (loss) from discontinued operations			—				—				—				(81	)
Net income (loss)			(9,628	)			50,907				24,438				241,629
(Income) loss attributable to non-controlling interests			5,454				(43,794	)			(7,925	)			(211,378	)
(Income) loss not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition (see Note 2)			—				—				—				(4,711	)
Net income (loss) attributable to common unitholders		$	(4,174	)		$	7,113			$	16,513			$	25,540
Net income (loss) attributable to common unitholders per unit – basic:
Income (loss) from continuing operations attributable to common shareholders		$	(0.08	)		$	0.13			$	0.31			$	0.65
Income from discontinued operations attributable to common unitholders			—				—				—				—
Net income (loss) attributable to common unitholders		$	(0.08	)		$	0.13			$	0.31			$	0.65
Net income (loss) attributable to common unitholders per unit – diluted:
Income (loss) from continuing operations attributable to common unitholders		$	(0.08	)		$	0.13			$	0.30			$	0.65
Income from discontinued operations attributable to common unitholders			—				—				—				—
Net income (loss) attributable to common unitholders		$	(0.08	)		$	0.13			$	0.30			$	0.65

 

(1)	For the fourth quarter of the year ended December 31, 2011, approximately 1,944,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive.

 

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		Fourth Quarter(1)				Third Quarter(1)				Second Quarter(1)				First Quarter(1)
		(in thousands, except unit data)
Year ended December 31, 2010:
Revenues		$	319,015			$	320,015			$	298,250			$	350,003
Income (loss) from continuing operations		$	(46,966	)		$	(3,206	)		$	7,360			$	18,168
Income (loss) from discontinued operations			471				305,927				7,976				6,781
Net income (loss)			(46,495	)			302,721				15,336				24,949
(Income) loss attributable to non-controlling interests			9,295				(252,564	)			(688	)			(1,807	)
(Income) loss not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition (see Note 2)			33,192				(15,711	)			(15,788	)			(24,506	)
Net income (loss) attributable to common unitholders		$	(4,008	)		$	34,446			$	(1,140	)		$	(1,364	)
Net income (loss) attributable to common unitholders per unit – basic:
Income (loss) from continuing operations attributable to common unitholders		$	(0.14	)		$	(0.13	)		$	(0.08	)		$	(0.08	)
Income from discontinued operations attributable to common unitholders			—				1.37				0.04				0.03
Net income (loss) attributable to common unitholders		$	(0.14	)		$	1.24			$	(0.04	)		$	(0.05	)
Net income (loss) attributable to common unitholders per unit – diluted:
Income (loss) from continuing operations attributable to common unitholders		$	(0.14	)		$	(0.13	)		$	(0.08	)		$	(0.08	)
Income from discontinued operations attributable to common unitholders			—				1.37				0.04				0.03
Net income (loss) attributable to common unitholders		$	(0.14	)		$	1.24			$	(0.04	)		$	(0.05	)

 

(1)

For the first, second, third and fourth quarters of the year ended December 31, 2010, approximately 181,000, 175,000, 198,000 and 166,000 units, respectively, were excluded from the computation of diluted net income (loss) per common units because the inclusion of such units would have been anti-dilutive.

 

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 general partner’s 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 general partner’s 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. Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2011, our disclosure controls and procedures were effective at the reasonable assurance level.

Management’s Report on Internal Control over Financial Reporting

The management of our general partner 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 general partner’s 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 Internal Control – Integrated Framework (COSO framework).

 

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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 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.

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, 2011. Grant Thornton LLP, an independent registered public accounting firm, has issued an attestation report on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2011, which is included herein.

On February 17, 2011, we acquired certain producing natural gas and oil properties, an investment management business which 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 our general partner. In addition, in connection with this acquisition, we have installed the management team that managed the Transferred Business under AEI into our organization, including our general partner’s Chief Executive Officer and Chief Financial Officer, and adopted AEI’s internal controls over financial reporting under which the Transferred Business operated. However, we continue to integrate these internal controls into our internal control structure. This integration may lead to changes in our internal control over financial reporting in future fiscal reporting periods. Other than the previously mentioned item, there have been no changes in our internal control over financial reporting during the fourth quarter of 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Atlas Energy, L.P.

We have audited Atlas Energy, L.P.’s (a Delaware limited partnership) internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Atlas Energy, L.P.’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. Our responsibility is to express an opinion on Atlas Energy, L.P.’s internal control over financial reporting based on our audit.

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, Atlas Energy, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in 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 consolidated combined balance sheets of Atlas Energy, L.P. and subsidiaries as of December 31, 2011 and 2010 and the related consolidated combined statements of operations, comprehensive income (loss), partner’s capital and cash flows for each of the three years in the period ended December 31, 2011, and our report dated February 28, 2012 expressed an unqualified opinion thereon.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 28, 2012

 

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ITEM 9B.

OTHER INFORMATION

None.

PART III

 

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Our general partner manages our activities. Unitholders do not directly or indirectly participate in our management or operation or have actual or apparent authority to enter into contracts on our behalf or to otherwise bind us. Our general partner will be liable, as general partner, for all of our debts to the extent not paid, except to the extent that indebtedness or other obligations incurred by us are specifically with recourse only to our assets. Whenever possible, our general partner intends to make any of our indebtedness or other obligations with recourse only to our assets.

As set forth in our Partnership Governance Guidelines and in accordance with New York Stock Exchange (“NYSE”) listing standards, the non-management members of our general partner’s board of directors meet in executive session regularly without management. The managing 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 non-management board members. Interested parties wishing to communicate directly with the non-management members may contact the chairman of the audit committee, Harvey Magarick. Correspondence to Mr. Magarick should be marked “Confidential” and sent to Mr. Magarick’s attention, c/o Atlas Energy, L.P., 1845 Walnut Street, 10th Floor, Philadelphia, PA 19103.

The independent board members comprise all of the members of the audit committee, the nominating and governance committee, the compensation committee and the investment committee.

Until the consummation of the merger with Chevron Corporation, a Delaware corporation (“Chevron”), in which Atlas Energy Inc. (“AEI”) became a wholly-owned subsidiary of Chevron on February 17, 2011 (the “Chevron Merger”), we did not directly employ any of the persons responsible for our management or operation. Rather, AEI personnel managed and operated our business. With the completion of the Chevron Merger, we are no longer affiliated with AEI. We now employ certain former AEI employees, including the members of our senior management. In addition, as a result of the sale of assets from AEI to us on February 17, 2011 (the “AHD Transactions”), we now own our general partner, and our unitholders will elect our general partner’s board of directors, rather than AEI.

 

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Board of Directors and Executive Officers of Our General Partner

The following table sets forth information with respect to the executive officers and directors of our general partner:

 

Name		Age		Position with the general partner		Year in which service began		Term expires
Edward E. Cohen		73		Chief Executive Officer, President and Director		2006		2014
Sean P. McGrath		40		Chief Financial Officer		2011		—
Jonathan Z. Cohen		41		Chairman of the Board		2006		2013
Matthew A. Jones		50		Senior Vice President and President and Chief Operating Officer of E&P Division		2011		—
Eugene N. Dubay		63		Senior Vice President of Midstream		2011		—
Freddie M. Kotek		56		Senior Vice President of Investment Partnership Division		2011
Lisa Washington		44		Vice President, Chief Legal Officer and Secretary		2011		—
Jeffrey M. Slotterback		29		Chief Accounting Officer		2011		—
Carlton M. Arrendell		50		Director		2011		2013
Mark C. Biderman		66		Director		2011		2013
Dennis A. Holtz		71		Director		2011		2012
William G. Karis		63		Director		2006		2012
Harvey G. Magarick		72		Director		2006		2012
Ellen F. Warren		55		Director		2011		2014

Edward E. Cohen was the Chairman of the Board of our general partner from its formation in January 2006 until February 2011, when he became our Chief Executive Officer and President. Mr. Cohen served as the Chief Executive Officer of our general partner from its formation in January 2006 until February 2009. Mr. Cohen has been the Chairman of the managing board of Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP”), since its formation in 1999. From 1999 to January 2009, Mr. Cohen was the Chief Executive Officer of Atlas Pipeline GP. Mr. Cohen also was the Chairman of the Board and Chief Executive Officer of Atlas Energy, Inc. (formerly known as Atlas America, Inc.) from its organization in 2000 until the consummation of the Chevron Merger in February 2011 and also served as its President from 2000 to October 2009 when Atlas Energy Resources, LLC became its wholly-owned subsidiary following its merger transaction. Mr. Cohen was the Chairman of the Board and Chief Executive Officer of Atlas Energy Resources, LLC and its manager, Atlas Energy Management, Inc.; from their formation in June 2006 until the consummation of the Chevron Merger in February 2011. In addition, Mr. Cohen has been Chairman of the Board of Directors of Resource America, Inc. (a publicly-traded specialized asset management company) since 1990 and was its Chief Executive Officer from 1988 until 2004, and President from 2000 until 2003; Chairman of the Board of Resource Capital Corp. (a publicly-traded real estate investment trust) since its formation in September 2005 until November 2009 and still serves on its board; a director of TRM Corporation (a publicly-traded consumer services company) from 1998 to July 2007; and Chairman of the Board of Brandywine Construction & Management, Inc. (a property management company) since 1994. Mr. Cohen is the father of Jonathan Z. Cohen. Mr. Cohen has been active in the energy business since the late 1970s. Among the reasons for his appointment as a director, Mr. Cohen brings to the board the vast experience that he has accumulated through his activities as a financier, investor and operator in various parts of the country.

Sean P. McGrath has been our Chief Financial Officer since February 2011. Before that he was the Chief Accounting Officer of AEI and the Chief Accounting Officer of Atlas Energy Resources, LLC from December 2008 until February 2011. Mr. McGrath served as the Chief Accounting Officer of our general partner from January 2006 until November 2009 and as the Chief Accounting Officer of Atlas Pipeline GP from May 2005 until November 2009. Mr. McGrath was the Controller of Sunoco Logistics Partners L.P., a publicly-traded partnership that transports, terminals and stores refined products and crude oil, from 2002 to 2005. Mr. McGrath is a Certified Public Accountant.

Jonathan Z. Cohen has been the Chairman of the Board of our general partner since February 2011. Before that, he served as Vice Chairman of the Board of our general partner from its formation in January 2006 until February 2011. Mr. Cohen has been the Vice Chairman of the managing board of Atlas Pipeline GP since its formation in 1999. Mr. Cohen also was the Vice Chairman of the Board of Atlas Energy, Inc. (formerly known as Atlas America, Inc.) from its organization in 2000 until the consummation of the Chevron Merger in February 2011. Mr. Cohen was the Vice Chairman of the Board of Atlas Energy Resources, LLC and Atlas Energy Management from their formation in June 2006 until the consummation of the Chevron Merger in 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 and was a trustee and secretary of

 

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RAIT Financial Trust (a publicly-traded real estate investment trust) from 1997, and its Vice Chairman from 2003, until December 2006. Mr. Cohen is a son of Edward E. Cohen. Among the reasons for his appointment as a director, Mr. Cohen’s financial, business and energy experience add strategic vision to our general partner’s board to assist with our growth and development.

Matthew A. Jones has been Senior Vice President of our general partner and President and Chief Operating Officer of our exploration and production division since February 2011. Before that, he was the Chief Financial Officer from March 2005 and an Executive Vice President from October 2009 until February 2011 of AEI. Mr. Jones was the Chief Financial Officer of Atlas Energy Resources and Atlas Energy Management from their formation until the consummation of the Chevron Merger in February 2011. Mr. Jones served as the Chief Financial Officer of our general partner from January 2006 until September 2009 and as the Chief Financial Officer of Atlas Pipeline GP from March 2005 to September 2009. From 1996 to 2005, Mr. Jones worked in the Investment Banking Group at Friedman Billings Ramsey, concluding as Managing Director. Mr. Jones worked in Friedman Billings Ramsey’s Energy Investment Banking Group from 1999 to 2005, and in Friedman Billings Ramsey’s Specialty Finance and Real Estate Group from 1996 to 1999. Mr. Jones served as a director of our general partner from February 2006 to February 2011. Mr. Jones is a Chartered Financial Analyst.

Eugene N. Dubay has been our Senior Vice President of Midstream since February 2011. Before that, he was the Chief Executive Officer, President and a director of our general partner from February 2009 until February 2011. Mr. Dubay has been President and Chief Executive Officer of Atlas Pipeline GP since January 2009. Mr. Dubay has served as a member of the managing board of Atlas Pipeline GP since October 2008, where he served as an independent member until his appointment as President and Chief Executive Officer. Mr. Dubay has been the President of Atlas Pipeline Mid-Continent, LLC since January 2009. Mr. Dubay was the Chief Operating Officer of Continental Energy Systems LLC, the parent of SEMCO Energy, from 2002 to January 2009. Mr. Dubay has also held positions with ONEOK, Inc. and Southern Union Company and has over 20 years experience in midstream assets and utilities operations, strategic acquisitions, regulatory affairs and finance. Mr. Dubay is a certified public accountant and a graduate of the U.S. Naval Academy.

Freddie M. Kotek has been a Senior Vice President of the Investment Partnership Division of our general partner since February 2011. Before that, he was the Executive Vice President of AEI from February 2004 until February 2011 and served as a director from September 2001 until February 2004. Mr. Kotek has been Chairman of Atlas Resources, LLC since September 2001 and has served as an Executive Vice President since October 2009. He has also served as Chief Executive Officer and President of Atlas Resources since January 2002. Mr. Kotek served as AEI’s Chief Financial Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice President of Resource America from 1995 until May 2004 and President of Resource Leasing, Inc. (a wholly-owned subsidiary of Resource America) from 1995 until May 2004.

Lisa Washington has been our Vice President, Chief Legal Officer and Secretary of our general partner since February 2011. Ms. Washington previously served as Chief Legal Officer and Secretary of AEI, from November 2005 until February 2011 and as a Senior Vice President from October 2008 until February 2011. Ms. Washington was a Vice President of Atlas Energy, Inc. from November 2005 until October 2008. Ms. Washington served as Chief Legal Officer and Secretary of our general partner from January 2006 to October 2009 and as a Senior Vice President of our general partner from October 2008 to October 2009. Ms. Washington served as Chief Legal Officer and Secretary of Atlas Pipeline GP from November 2005 to October 2009 and as a Senior Vice President from October 2008 to October 2009. Ms. Washington was a Vice President of Atlas Pipeline GP from November 2005 until October 2008. Ms. Washington served as Chief Legal Officer and Secretary of Atlas Energy Resources, LLC from 2006 until February 2011 and as a Senior Vice President from July 2008 until February 2011. Ms. Washington was a Vice President of Atlas Energy Resources, LLC 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 2011. Before that, Mr. Slotterback served as the Manager of Financial Reporting for AEI from July 2009 until February 2011 and then served as the Manager of Financial Reporting for our general partner from February 2011 until March 2011. Mr. Slotterback served as Manager of Financial Reporting for both our general partner and Atlas Pipeline GP from May 2007 until July 2009. Mr. Slotterback was a Senior Auditor at Deloitte and Touche, LLP from 2004 until 2007, where he focused on energy and health care clients. Mr. Slotterback is a Certified Public Accountant.

Carlton M. Arrendell has been a director since February 2011. Before that, he was a director of AEI from February 2004 until February 2011. Mr. Arrendell has been the Chief Investment Officer and a Vice President of Full Spectrum of NY LLC since May 2007. Prior to joining Full Spectrum, Mr. Arrendell served as a special real estate consultant to the AFL-CIO Investment Trust Corporation following six years of service as Investment Trust Corporation’s Chief Investment Officer. Mr. Arrendell is also an attorney admitted to practice law in Maryland and the District of Columbia. Mr. Arrendell’s investment expertise is valuable to our company and its subsidiaries in the pursuit of acquisitions. In addition, the board is benefitted by his strong background in finance.

 

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Mark C. Biderman has been a director since February 2011. Before that, he was a director of AEI from July 2009 until February 2011. Mr. Biderman was Vice Chairman of National Financial Partners Corp., a publicly-traded financial services company, from September 2008 to December 2008. Before that, from November 1999 to September 2008, he was National Financial’s Executive Vice President and Chief Financial Officer. From May 1987 to October 1999, Mr. Biderman served as Managing Director and Head of the Financial Institutions Group at CIBC World Markets Group, an investment banking firm, and its predecessor, Oppenheimer & Co., Inc. Mr. Biderman serves as a director and chairman of the audit committee, and a member of the corporate governance and nominating committee of Full Circle Capital Corporation, a publicly-traded investment company, since August 2010. Mr. Biderman serves as a director and chairman of the compensation committee, and a member of the audit committee of Apollo Commercial Real Estate Finance, Inc., a publicly-traded commercial real estate finance company, since November 2010. He also serves as a director and chairman of the audit committee and a member of the nominating and corporate governance committee of Apollo Residential Mortgage, Inc., a publicly-traded residential real estate finance company, since July 2011. Mr. Biderman is a Chartered Financial Analyst. Mr. Biderman brings extensive financial expertise to the board as well as to the audit committee.

Dennis A. Holtz has been a director since February 2011. Before that, he was a director of AEI from February 2004 until 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 secretary of numerous private and public business entities and this extensive experience with corporate governance issues was the reason he was chosen as chairman of the nominating and governance committee. In addition, Mr. Holtz has had extensive experience with lease issues and provides valuable insight into interacting with lessors of drilling sites. Mr. Holtz served on the AEI board for six years, since its spin-off from Resource America and his length of service on AEI’s board provides him with extensive knowledge of our acquired business and industry. Since our company interacts in the Appalachian region with many small firms, Mr. Holtz’s experience as an operator of his own law office is believed to provide insight into interacting with smaller companies.

William G. Karis has been the principal of Karis and Associates, LLC, a consulting company that provides financial and consulting services to the coal industry, since 1997. Prior to that, Mr. Karis was President and CEO of CONSOL Inc. (now CONSOL Energy Company). Mr. Karis is a member of the Boards of Directors and is Chairman of the Audit and Finance Committees of Blue Danube Inc., and Greenbriar Minerals, LLC. Mr. Karis has extensive experience in the energy industry, primarily relating to coal. Mr. Karis’ experience in the coal industry has helped the Board shape its thinking regarding the relative competition between Atlas Pipeline Partners’ products in relation to other energy sources (most notably coal). Mr. Karis also brings valuable management insight in various areas based on his experience as a chief executive officer. These combined experiences and insight serve as the basis, among other reasons, for Mr. Karis’ appointment as a director.

Harvey G. Magarick has maintained his own consulting practice since June 2004. From 1997 to 2004, Mr. Magarick was a partner at BDO Seidman. Mr. Magarick is a member of the Board of Trustees of the Hirtle Callaghan Trust, an investment fund, and has been the Chairman of its audit committee since 2004. Mr. Magarick brings a strong accounting background to our general partner’s board and, as a “financial expert”, serves as the chair of our audit committee. Mr. Magarick’s accounting experience is critical to an understanding of the varied issues that face us. This experience, among other reasons, serves as the basis for Mr. Magarick’s appointment as a director.

Ellen F. Warren has been a director since February 2011. Before that, she was a director of AEI from September 2009 until February 2011. She is founder and President of OutSource Communications, a marketing communications firm that services corporate and nonprofit clients. Prior to founding OutSource Communications in August 2005, she was President of Levy Warren Marketing Media, a public relations and marketing firm she co-founded in March 1998. She was previously Vice President of Marketing/Communications for Jefferson Bank, a Philadelphia-based financial institution, from September 1992 to February 1998. Ms. Warren served as an independent member of the Board of Directors of Atlas Energy Resources, LLC from December 2006 until September 2009. Ms. Warren is a seasoned director, having previously served on the board of Atlas Energy Resources, LLC from its formation until its merger. Ms. Warren brings management, communication and leadership skills to our general partner’s board.

We have assembled a board of directors of our general partner comprised of individuals who bring diverse but complementary skills and experience to oversee our business. Our directors collectively have a strong background in energy, finance, law, accounting and management. Based upon the experience and attributes of the directors discussed herein, our board of our general partner determined that each of the directors should, as of the date hereof, serve on the board of our general partner.

 

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Jonathan Z. Cohen serves as the chairman of the board of directors of our general partner and Edward E. Cohen serves as the chief executive officer and president of our general partner. The board of directors of our general partner believes that the most effective leadership structure at the present time is for separation of the chairman of the board of directors from the chief executive officer position. The chief executive officer contacts the chairman of the board of directors on a regular basis and provides status updates of operations during these discussions.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires executive officers and managing board members of our general partner 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.

Based solely upon our review of reports received by us, or representations from certain reporting persons that no filings were required for those persons, we believe that during fiscal year 2011 our executive officers, directors of our general partner and persons who beneficially owned more than 10% of our common units complied with all applicable filing requirements except Ms. Warren and Messrs. Biderman, Holtz and Arrendell each inadvertently filed one Form 4 late.

Nominations to Our General Partner’s Board of Directors

Effective with the amendment in February 2011 of our limited partnership agreement and the limited liability company agreement of our general partner, our unitholders will elect our general partner’s board of directors. Pursuant to our limited partnership agreement, our unitholders may nominate candidates for election to our general partner’s board by providing timely prior notice to our general partner as follows:

 

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The notice must be delivered to our general partner not earlier than the close of business on the 120th day nor later than the close of business on the 90th day prior to the first anniversary of the preceding year’s annual meeting; provided, however, that (x) in the event that the date of the annual meeting is more than 30 days before or more than 60 days after such anniversary date and (y) in the case of the 2012 annual meeting, a limited partner’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 shall 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 general partner 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 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: (A) 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, (B) (I) 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, (II) any option, warrant, convertible security, stock appreciation right, or similar right with an exercise or conversion privilege or a settlement payment or mechanism at a price related to any 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

 

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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, (III) any proxy, contract, arrangement, understanding, or relationship pursuant to which such unitholder has a right to vote any of our securities, (IV) any agreement, arrangement, understanding, relationship or otherwise, including any repurchase or similar so-called “stock borrowing” agreement or arrangement, involving such unitholder, 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”), (V) any rights to dividends on any of our securities owned beneficially by such unitholder that are separated or separable from the underlying security, (VI) 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 is a general partner or, directly or indirectly, beneficially owns an interest in a general partner of such general or limited partnership, (VII) any performance-related fees (other than an asset-based fee) that such unitholder 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 unitholder’s immediate family sharing the same household, (VIII) any significant equity interests or any Derivative Instruments or Short Interests in any of our principal competitors held by such unitholder, and (IX) any direct or indirect interest of such unitholder 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), and (C) 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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As to each person whom the unitholder proposes to nominate for election or reelection to the board, the notice must also: (A) set forth all information relating to such person that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors in a contested election pursuant to Section 14 of the 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); (B) set forth a description of all direct and indirect compensation and other material monetary agreements, arrangements and understandings during the past three years, and any other material relationships, between or among such unitholder and beneficial owner, if any, and their respective affiliates and associates, or others acting in concert therewith, on the one hand, and each proposed nominee, and his or her respective affiliates and associates, or others acting in concert therewith, on the other hand, including, 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 (C) 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 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.

 

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Information Concerning the Audit Committee

The board of directors of our general partner has a standing audit committee. All of the members of the audit committee are independent directors as defined by NYSE rules. The members of the audit committee are Mr. Karis, Mr. Biderman and Mr. Magarick, with Mr. Magarick acting as the chairman. Our general partner’s board has determined that Mr. Magarick is 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 of our general partner 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 general partner’s audit committee. The audit committee reviews the scope and effectiveness of audits by the independent accountants, is responsible for the engagement of independent accountants and reviews the adequacy of our internal controls.

Compensation Committee Interlocks and Insider Participation

The compensation committee of our general partner’s board of directors consists of Ms. Warren and Messrs. Arrendell and Holtz.

None of the independent directors of our general partner is an employee or former employee of ours or of our general partner. No executive officer of our general partner is a director or executive officer of any entity in which an independent director is a director or executive officer.

Code of Business Conduct and Ethics, Partnership Governance Guidelines and Audit Committee Charter

We have adopted a code of business conduct and ethics that applies to the principal executive officer, principal financial officer and principal accounting officer of our general partner, as well as to persons performing services for us generally. We have also adopted Partnership Governance Guidelines and a charter for the audit committee. We will make a printed copy of our code of ethics, our Partnership Governance Guidelines and our audit committee charter available to any unitholder who so requests. Requests for print copies may be directed to us as follows: Atlas Energy, L.P., Park Place Corporate Center One, 1000 Commerce Drive, Suite 400, Pittsburgh, PA 15275, Attention: Secretary. Each of the code of business conduct and ethics, the Partnership Governance Guidelines and the audit committee charter are posted, and any waivers we grant to our code of business conduct and ethics will be posted, on our website at www.atlasenergy.com.

Risk Oversight

General

We administer our risk oversight function through our audit committee. The audit committee monitors material enterprise risks and, in order to assist in its oversight function, it oversaw the creation of the management risk committee. It meets with the members of the management risk committee as needed to discuss our risk management framework and related areas. The audit committee 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. Our audit committee also oversees our internal audit function. Our audit committee is also 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. Our audit committee incorporates its risk oversight function into its regular reports to the Board.

In addition to our audit committee’s role in overseeing risk management, our full Board regularly engages in discussions of the most significant risks that we face and how these risks are being managed. Our senior executives provide the Board and its committees with 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 also provide a venue for directors to discuss issues of concern with management. The Board and committees 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 attend Board meetings to provide additional insight into items being

 

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discussed, including risk exposures. In addition, senior executives of our key divisions as well as our Chief Financial Officer and Chief Legal Officer report directly to our President and Chief Executive Officer as well as our Chairman of the Board, providing them with visibility to our risk profile.

Compensation Programs

Our compensation policies and programs are intended to encourage our employees to remain focused on both our short-term and long-term goals. For example, our equity awards typically vest 25% on the third anniversary and 75% on the fourth anniversary of the date of grant. We believe this practice encourages our employees to focus on sustained unit price appreciation, thus limiting the potential of our executives to engage in excessive risk-taking. Annual incentives are intended to tie a significant portion of each of the named executive officer’s compensation to our annual performance and/or that of the subsidiaries or divisions for which the officer is responsible. We believe that our focus on revenue growth and distributable cash flow in making incentive bonus awards and unit price performance in granting equity awards provides a check on excessive risk taking. Our Code of Business Conduct and Ethics, which applies to all officers and directors, further seeks to mitigate the potential for inappropriate risk taking. We also prohibit hedging transactions involving our units so our officers and directors cannot insulate themselves from the effects of our unit price performance.

Our Compensation Committee, together with senior management, also reviews compensation programs and benefits plans affecting employees generally (in addition to those applicable to our executive officers), and we have concluded that our compensation policies and practices do not create risks that are reasonably likely to have a material adverse effect on the company. We also believe that our incentive compensation arrangements provide incentives that do not encourage risk-taking beyond our ability to effectively identify and manage significant risks; are compatible with effective internal controls and our risk management practices; and are supported by the oversight and administration of the Compensation Committee with regard to executive compensation programs.

 

ITEM 11.

EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Before the consummation of the Chevron Merger, we did not directly compensate our executive officers. Rather, the AEI compensation committee was responsible for compensation decisions, and allocated the compensation of our executive officers based upon an estimate of the time spent by such persons on activities for our publicly traded subsidiary, Atlas Pipeline Partners, L.P. (“APL”) and for AEI and its other affiliates. APL reimbursed AEI for the compensation allocated to it; AEI did not make a separate allocation to us.

In February 2011, we formed our own compensation committee, which is responsible for assisting our board of directors in carrying out its responsibilities with respect to compensation. The committee is responsible for evaluating the compensation to be paid to our CEO, CFO and the three other most highly-compensated executive officers, which we refer to as our “Named Executive Officers” or “NEOs.” The compensation committee is also responsible for administering our employee benefit plans, including incentive plans. The compensation committee is comprised solely of independent directors, consisting of Ms. Warren and Messrs. Arrendell and Holtz, with Ms. Warren acting as the chairperson.

Compensation Objectives

We believe that our compensation program must support our business strategy, be competitive, and provide both significant rewards for outstanding performance and clear financial consequences for underperformance. We also believe that a significant portion of the NEOs’ compensation should be “at risk” in the form of annual and long-term incentive awards that are paid, if at all, based on individual and company accomplishment. Accounting and cost implications of compensation programs are considered in program design; however, the essential consideration is that a program is consistent with our business needs.

Compensation Methodology

Our compensation committee was formed in February 2011 and, at its initial meeting, recommended base salaries to be paid to our NEOs for our 2011 fiscal year. Going forward, we anticipate that our compensation committee will make its determination on compensation amounts shortly after the close of our fiscal year. In the case of base salaries, the committee will recommend the amounts to be paid for the new fiscal year. In the case of annual bonus and long-term incentive

 

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compensation, the committee will determine the amount of awards based on the most recently concluded fiscal year. We expect to pay cash awards and issue equity awards in February of each year, although our compensation committee has the discretion to recommend salary adjustments and the issuance of equity awards at other times during the fiscal year. In addition, our NEOs and other employees who perform services for APL may receive stock-based awards from APL which has delegated compensation decisions to our compensation committee since it does not currently have its own compensation committee.

Our Chief Executive Officer (“CEO”) provides the compensation committee with key elements of our company’s and the NEOs’ performance during the year. Our CEO makes recommendations to the compensation committee regarding the salary, bonus, and incentive compensation component of each NEO’s total compensation. Our CEO, at the compensation committee’s request, may attend committee meetings solely to provide insight into our company’s performance, as well as the performance of other comparable companies in the same industry.

Role of Compensation Consultant

Following the closing of the Chevron Merger, the compensation committee engaged Mercer (US) Inc., an independent compensation consulting firm, to provide market data for equity awards to be made to our NEOs. As our company was essentially reconstituted as a result of the acquisition of AEI’s partnership management business and certain E&P assets, the compensation committee intended the awards to represent multi-year long-term incentive grants competitive with the 75th percentile of the market. In order to assist the committee in assessing the competitiveness of proposed awards, Mercer provided market data for long-term incentive grants to the 75th percentile from its 2010 oil and gas survey of data from 111 organizations. In addition, Mercer advised the compensation committee with respect to current employment agreement practices generally.

Elements of our Compensation Program

Our executive officer compensation package generally includes a combination of annual cash and long-term incentive compensation. Annual cash compensation is comprised of base salary plus cash bonus. Long-term incentives consist of a variety of equity awards. Both the annual cash incentives and long-term incentives may be performance-based.

Base Salary

Base salary is intended to provide fixed compensation to the NEOs for their performance of core duties that contributed to our success as measured by the elements of corporate performance mentioned above. Base salaries are not intended to compensate individuals for their extraordinary performance or for above average company performance.

Annual Incentives

Annual incentives are intended to tie a significant portion of each of the NEO’s compensation to our annual performance and/or that of our subsidiaries or divisions for which the officer is responsible. Generally, the higher the level of responsibility of the executive within our company, the greater is the incentive component of that executive’s target total cash compensation. The compensation committee may recommend awards of performance-based bonuses and discretionary bonuses.

Performance-Based Bonuses—In April 2011, the compensation committee adopted an Annual Incentive Plan for Senior Executives, which we refer to as the Senior Executive Plan, to award bonuses for achievement of predetermined, objective performance measures through the end of 2011. Awards under the Senior Executive Plan could be paid in cash or in a combination of cash and equity. Under the Senior Executive Plan, the maximum award payable to an individual was $15,000,000.

At the time the compensation committee adopted the Senior Executive Plan, it approved 2011 target bonus awards to be paid from a bonus pool. The bonus pool was equal to 18.3% of our distributable cash flow unless the distributable cash flow included any capital transaction gains in excess of $50 million, in which case only 10% of that excess would be included in the bonus pool. If the distributable cash flow did not equal at least 80% of the 2011 budgeted distributable cash flow of $84,498,000, no bonuses would be paid. Distributable cash flow means the sum of (i) cash available for distribution by us, including our ownership interest in the distributable cash flow of any of our 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

 

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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 our 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 our basis in the subsidiary.

The maximum award payable, expressed as a percentage of our estimated 2011 distributable cash flow, for each participant was as follows: Edward E. Cohen, 6.14%; Jonathan Z. Cohen, 4.37%; Matthew A. Jones, 3.46%; Eugene Dubay, 2.60% and Freddie Kotek, 1.73%. Sean McGrath and Eric Kalamaras did not participate in the Senior Executive Plan. Pursuant to the terms of the Senior Executive Plan, the compensation committee had the discretion to recommend reductions, but not increases, in awards under the Senior Executive Plan.

Discretionary Bonuses—Discretionary bonuses may be awarded to recognize individual and group performance.

Long-Term Incentives

We believe that our long-term success depends upon aligning our executives’ and unitholders’ interests. To support this objective, we provide our executives with various means to become significant equity holders, including awards under our 2006 Long-Term Incentive Plan (the “2006 Plan”) and our 2010 Long-Term Incentive Plan (the “2010 Plan”), which we refer to as our Plans. Our NEOs are also eligible to receive awards under Atlas Pipeline Partners’ 2004 Long-Term Incentive Plan and its 2010 Long-Term Incentive Plan, which we refer to as the APL Plans.

Grants under our Plans: Under our Plans, the compensation committee may recommend grants of equity awards in the form of options and/or phantom units. Generally, the unit options and phantom units vest 25% on the third anniversary and 75% on the fourth anniversary of the date of grant.

Grants under Other Plans: As described above, our NEOs who perform services for us and Atlas Pipeline Partners are eligible to receive unit-based awards under the APL Plans. In addition, we anticipate that some of our NEOs will be eligible to receive awards under the long-term incentive plan to be adopted by Atlas Resource Partners, L.P., our newly formed subsidiary.

Deferred Compensation

All of our employees may participate in our 401(k) plan, which is a qualified defined contribution plan designed to help participating employees accumulate funds for retirement. In July 2011 we established the Atlas Energy Executive Excess 401(k) Plan (the “Excess 401(k) Plan”), a non-qualified deferred compensation plan that is designed to permit individuals who exceed certain income thresholds and who may be subject to compensation and/or contribution limitations under our 401(k) plan to defer an additional portion of their compensation. The purpose of the Excess 401(k) Plan is to provide participants with an incentive for a long-term career with us by providing them with an appropriate level of replacement income upon retirement. Under the Excess 401(k) Plan, a participant may contribute to an account an amount up to 10% of annual cash compensation (which means a participant’s salary and non-performance-based bonus) and up to all performance-based bonuses. We are 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. The investment options under the Excess 401(k) Plan are substantially the same as the investment options under our 401(k) plan; we do not pay above-market or preferential earnings on deferred compensation. Participation in the Excess 401(k) Plan is available pursuant to the terms of an individual’s employment agreement or at the designation of the compensation committee. Currently, Messrs. E. Cohen and J. Cohen are the only participants in the Excess 401(k) Plan. For further details, please see 2011 Non-Qualified Deferred Compensation table.

Post-Termination Compensation

Our 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 with AEI, which are described under “—Employment Agreements and Potential Payments Upon Termination or Change of Control,” and their equity holdings in AEI. Our compensation committee believed that the amounts thus realized left our NEOs without adequate financial incentives to continue employment with us, which the committee did not believe was in our interest as we moved forward with significant new operations. In order to encourage these executives to remain with us on a long-term basis, we made certain long-term incentive grants, which are described under “—Long-Term Incentives,” and we entered into employment agreements with Messrs. E. Cohen, J. Cohen, Jones and Dubay that, among other things, provide compensation upon termination of their

 

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employment by reason of death or disability, by us without cause or by each of them for good reason. See “—Employment Agreements and Potential Payments Upon Termination or Change of Control.” “Good reason” is defined under the agreements as:

 

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a material reduction in the executive’s base salary;

 

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a demotion from the position held by the executive at the time the agreement was entered into;

 

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a material reduction in the executive’s duties, it being deemed such a material reduction if we cease to be a public company unless, we become a subsidiary of a public company and, in the case of Mr. E. Cohen’s agreement, he becomes the chief executive officer of the public parent, or, in the case of Mr. J. Cohen’s agreement, he becomes an executive of the public parent with responsibilities substantially equivalent to his position, or, in the case Messrs. Jones’s and Dubay’s respective agreements, our CEO or chairman of our board are not, immediately following the transaction in which we cease to be a public company, our CEO or the CEO of the acquiring entity;

 

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the executive is required to relocate to a location more than 35 miles from his previous location;

 

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in the case of Messrs. E. and J. Cohen’s agreements, he ceases to be elected to our board; and

 

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any material breach of the agreement.

The compensation committee’s rationale behind the design of the provisions of these agreements for termination by the executive for good cause are as follows:

 

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Determination of Triggering Events—The compensation committee elected not to include a change of control of us as a good reason triggering event and instead limited the triggering events to those (including after a change of control of us) where his position with us changes substantially and is essentially an involuntary termination.

 

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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.

Perquisites

We provide limited perquisites to our NEOs at the discretion of the compensation committee. In 2011, these benefits were limited to providing cars to some NEOs and reimbursement of relocation expenses.

Determination of 2011 Compensation Amounts

Base Salary

In February 2011, our newly formed compensation committee approved the base salaries for our NEOs as follows: Mr. E. Cohen—$700,000, Mr. Dubay—$500,000, Mr. McGrath—$250,000, Mr. J. Cohen—$500,000, Mr. Jones—$280,000, and Mr. Kotek—$280,000. These amounts matched or represented a decrease from their 2010 base salaries paid by AEI.

Annual and Transaction Incentives

The compensation committee was attentive to our unique circumstances after the Chevron Merger, in that we had both completed a significant and transformative transaction and were re-establishing ourselves as a stand-alone entity. As part of the terms of the Chevron Merger, Chevron agreed that AEI could use $10 million for payments to key employees for retention bonuses and to reward performance, with approximately $3 million to be paid to key employees at or immediately prior to closing of the Chevron Merger and approximately $7 million (which was unallocated) to be transferred from AEI to us for allocation and payment to key employees following the Chevron Merger. Mr. McGrath was awarded a $900,000 retention bonus by the AEI compensation committee before he became our Chief Financial Officer. While our other NEOs did not receive any such retention bonuses from AEI, after the Chevron Merger, our compensation committee considered both individual and company performance of our NEOs based upon their outstanding performance and leadership until the closing of the Chevron Merger and our successful establishment as a stand-alone entity, and shortly after the closing of the Chevron Merger in February 2011 awarded cash bonuses to Messrs. E. Cohen, J. Cohen and Jones as follows: Mr. E. Cohen—$2,500,000, Mr. J. Cohen—$2,500,000, and Mr. Jones—$1,250,000.

 

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After the end of our 2011 fiscal year, our compensation committee recommended incentive awards pursuant to the Senior Executive Plan based on the prior year’s performance. In determining the actual amounts to be paid to the NEOs, the compensation committee considered both individual and company performance. Our CEO made recommendations of incentive award amounts based upon our performance as well as the performance of our subsidiaries; however, the compensation committee had the discretion to approve, reject, or modify the recommendations. The compensation committee noted that our total unitholder return was 67% during 2011 and that our cash distributions increased by approximately 600% over the prior year; we were able to reestablish our partnership fund raising programs despite the abbreviated sales period; our management team worked throughout the year to prepare for the spin-off of our E&P and partnership management business to Atlas Resource Partners, in which we will retain an approximate 80% interest, and successfully rebuilt our operations team after the transfer of senior executives and technical staff to Chevron; we made fresh entries into the Marcellus Shale in areas not restricted by the non-competition agreements with Chevron, and increased our drilling in Tennessee, Colorado and Ohio; and that APL had operated its plants at full capacity, declared distributions at a sharp increase from the prior year, continued to expand capacity and distributable cash flow through organic growth and enjoyed multiple credit rating upgrades. In addition, the compensation committee reviewed the calculations of our distributable cash flow and determined that 2011 distributable cash flow exceeded the pre-determined minimum threshold of 80% of the budgeted distributable cash flow of $84,498,000. The compensation committee determined that based upon the strong performance of the NEOs as highlighted above, the bonuses for the NEOs were as follows: Mr. E. Cohen—$3,500,000, Mr. Dubay—$1,000,000, Mr. J. Cohen—$3,000,000, Mr. Jones—$1,250,000, and Mr. Kotek—$1,000,000. The bonuses awarded to the NEOs did not exceed 55% of the maximum bonus allocable to each NEO under the Senior Executive Plan formula, and were reduced in part in recognition of the cash bonus awards made in February for service until the date of such bonuses.

Mr. McGrath is not a participant in the Senior Executive Plan. Our compensation committee awarded him a discretionary bonus of $375,000.

Long-Term Incentives

Immediately after the Chevron Merger, our compensation committee recognized that the leadership of our NEOs was essential to the Company as it established itself as a stand-alone entity. It further concluded that strong incentive for our NEOs to remain with the Company for a significant period of time and their close alignment with our unitholders is critical in attracting and retaining additional key employees. However, the compensation committee further understood that our NEOs had 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 with AEI, which are described under “—Employment Agreements and Potential Payments Upon Termination or Change of Control,” and their equity holdings in AEI, and that could have left our NEOs without the adequate financial incentives to continue employment with us for a significant period of time, which the committee considered important. To provide such incentives and alignment, we made certain long-term incentive grants under the 2010 Plan to our NEOs in March 2011 as follows: Mr. E. Cohen- 300,000 phantom units and 700,000 options; Mr. Dubay—80,000 phantom units and 100,000 options; Mr. McGrath—30,000 phantom units and 35,000 options; Mr. Kalamaras—50,000 phantom units and 70,000 options; Mr. J. Cohen—250,000 phantom units and 500,000 options; Mr. Jones—150,000 phantom units and 200,000 options; and Mr. Kotek—30,000 phantom units and 70,000 options. (Mr. Kotek received an additional grant of 20,000 phantom units in April 2011 which brought his grant in line with the multiples of the other NEO grants described below.) The compensation committee intended the awards to represent multi-year long-term incentive grants competitive with the 75th percentile of the market. For each of the NEOs, consistent with Mercer’s advice, the grants represented between 3.5 to 5.4 times the annual market long-term incentive level from Mercer’s survey. The awards will vest 25% on the third anniversary of the grant and 75% on the fourth anniversary.

In connection with the distribution of 19.6% of Atlas Resource Partners, L.P. (“ARP”) to our unitholders, as discussed further in “Item 1: Business – Subsequent Events”, our Compensation Committee has determined that such distribution qualifies under the Plans as the type of event necessitating an adjustment to the outstanding options and phantom units issued pursuant to our Plans. Accordingly, on or after March 13, 2012, the anticipated distribution date for the ARP units, the outstanding options held by our NEOs will be 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. Outstanding phantom units will be adjusted to maintain the award’s pre-adjustment value. All other terms of these awards will remain unchanged.

 

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The tables which follow reflect corrections to information previously provided in our Current Report on Form 8-K filed on January 30, 2012.

SUMMARY COMPENSATION TABLE

 

Name and principal position		Year				Salary ($)(1)				Bonus ($)				Unit  awards ($)(2)				Option  awards ($)(3)				Non-equity incentive plan compensation ($)				All other compensation ($)				Total ($)
Edward E. Cohen, Chief Executive Officer and President(4)			2011				746,154				—				6,669,000	(5)			6,951,000	(6)			3,500,000				3,066,906	(7)			20,933,060
			2010				1,000,000				—				2,500,014				3,170,200				5,000,000				3,375				11,673,589
			2009				983,846				—				—				—				2,500,000				134,600				3,618,446
Eugene N. Dubay, Senior Vice President of Midstream			2011				500,000				—				1,778,400	(5)			993,000	(6)			1,000,000				5,136,128	(8)			9,407,528
			2010				500,000				1,000,000				1,334,009				1,008,700				—				26,484				3,869,193
			2009				438,846				500,000				—				564,000				—				555,805				2,058,652
Sean P. McGrath, Chief Financial Officer(9)			2011				250,000				1,275,000				666,900	(5)			347,550	(6)			—				17,638	(10)			2,557,088
Eric Kalamaras, former Chief Financial Officer			2011				274,577				—				1,111,500	(5)			695,100	(6)			—				94,486	(11)			2,175,653
			2010				274,519				180,000				660,020	(12)			273,790				—				49,572				1,437,901
			2009				76,923				152,917				66,620				—				—				—				296,460
Jonathan Z. Cohen, Chairman of the Board			2011				530,769				—				5,557,500	(5)			4,965,000	(6)			3,000,000				2,892,500	(13)			16,945,769
			2010				700,000				—				2,000,005				3,170,000				4,000,000				1,688				9,871,693
			2009				676,923				—				—				—				2,000,000				88,163				2,765,086
Matthew A. Jones, Senior Vice President and President and Chief Operating Officer of E&P Division			2011				298,024				—				3,334,500	(5)			1,986,000	(6)			1,250,000				1,344,910	(14)			8,213,434
Freddie M. Kotek, Senior Vice President of Investment Partnership Division			2011				298,462				—				1,170,900	(5)			695,100	(6)			1,000,000				37,774	(15)			3,202,236

 

(1)	The amounts in this column for Messrs. E. Cohen, J. Cohen, Jones and Kotek reflect amounts earned for a partial year of service with AEI and a partial year of service with us. The amount in this column for Mr. Kalamaras reflects a partial year of service.

(2)

The amounts reflect the grant date fair value of the phantom units under our 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 our units and APL’s units. See Item 8: Financial Statements and Supplementary Data—Note 16 for further discussion regarding assumptions made in fair value valuation.

(3)

The amounts in this column reflect the grant date fair value of options awarded under our Plans and the APL Plans calculated in accordance with FASB ASC Topic 718. See Item 8: Financial Statements and Supplementary Data—Note 16 for further discussion regarding assumptions made in fair value valuation.

(4)	On February 18, 2011, Mr. E. Cohen was appointed to serve in the capacity as Chief Executive Officer and President of Atlas Energy GP, LLC, a position previously held by Mr. Dubay.

(5)

In connection with our establishment as a stand-alone entity following the Chevron Merger, the board approved awards of phantom units representing approximately four years worth of long-term incentive grants as follows: Mr. E. Cohen- 300,000 phantom units; Mr. Dubay - 80,000 phantom units; Mr. McGrath - 30,000 phantom units; Mr. Kalamaras - 50,000 phantom units; Mr. J. Cohen - 250,000 phantom units; Mr. Jones - 150,000 phantom units; and Mr. Kotek - 50,000 phantom units. These grants will vest 25% on the third anniversary of the grant and 75% on the fourth anniversary of the grant.

(6)

In connection with our establishment as a stand-alone entity following the Chevron Merger, the board approved awards of options representing approximately four years worth of long-term incentive grants as follows: Mr. E. Cohen- 700,000 options; Mr. Dubay - 100,000 options; Mr. McGrath - 35,000 options; Mr. Kalamaras - 70,000 options; Mr. J. Cohen - 500,000 options; Mr. Jones - 200,000 options; and Mr. Kotek - 70,000 options. These grants will vest 25% on the third anniversary of the grant and 75% on the fourth anniversary of the grant.

(7)

Comprised of payments on DERs of $171,000 with respect to the phantom units awarded under our Plans, $45,906 for an automobile made available for the use of Mr. E. Cohen (based on the purchase cost of the car and the cost of tax, title and insurance premiums), $2,500,000 transaction cash payment awarded February 2011, and matching contribution of $350,000 under the Excess 401(k) Plan.

(8)

Includes payments on DERs of $45,600 with respect to the phantom units awarded under our Plans and $27,842 with respect to the phantom units awarded under the APL Plans. Also includes amounts paid by Chevron in connection with the termination of Mr. Dubay’s employment agreement as a result of the Chevron Merger as follows: $879,712 severance and $4,182,865 for the cash-out of equity awards subject to accelerated vesting, representing 15,454 stock awards reported in the Unit awards column for 2010 and 145,000 options reported in Option awards column for 2009 and 2010. See “Employment Agreements and Potential Payments Upton Termination or Change of Control—Eugene N. Dubay—2009 Employment Agreement” and 2011 Option Exercises and Stock Vested table.

(9)	On February 18, 2011, Mr. McGrath was appointed to serve in the capacity of Chief Financial Officer of Atlas Energy GP, LLC, a position previously held by Mr. Kalamaras.

(10)	Comprised of payments on DERs of $17,100 with respect to the phantom units awarded under our Plans and $538 with respect to the phantom units awarded under the APL Plans.

(11)	Includes payments on DERs of $16,500 with respect to the phantom units awarded under our Plans and $68,820 with respect to the phantom units awarded under the APL Plans.

(12)	Reflects a change from what was reported in our Form 10-K for fiscal year 2010 to now reflect the cash bonus units that had been converted to phantom units during 2010.

(13)	Includes payments on DERs of $142,500 with respect to the phantom units awarded under our Plans, transaction cash payment of $2,500,000 awarded in February 2011, and matching contribution of $250,000 under the Excess 401(k) Plan.

(14)	Includes payments on DERs of $85,500 with respect to the phantom units awarded under our Plans and a $1,250,000 transaction cash payment awarded in February 2011.

(15)	Includes payments on DERs of $28,500 with respect to the phantom units awarded under our Plans.

 

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2011 Grants of Plan-Based Awards

 

Name		Estimated Possible Payments Under Non-Equity Incentive Plan Awards(1)												Grant Date				All Other Stock Awards: Number of Shares of Stock or Units(2)				All Other Option Awards: Number of Securities Underlying Options(3)				Exercise of Base Price of Option Awards ($/Sh) (4)				Grant Date Fair Value of Unit and Option Awards ($)(5)
		Threshold ($)				Target ($)				Maximum ($)
Edward E. Cohen			N/A				N/A				7,673,000				3/25/11				300,000				—				22.23				6,669,000
															3/25/11				—				700,000				—				6,951,000
Eugene N. Dubay			N/A				N/A				3,249,000				3/25/11				80,000				—				22.23				1,778,400
															3/25/11				—				100,000				—				993,000
Sean P. McGrath			N/A				N/A				N/A				3/25/11				30,000				—				22.23				666,900
															3/25/11				—				35,000				—				347,550
Eric Kalamaras			N/A				N/A				N/A				3/25/11				50,000	(6)			—				22.23				1,111,500
															3/25/11				—				70,000	(6)			—				695,100
Jonathan Z. Cohen			N/A				N/A				5,461,000				3/25/11				250,000				—				22.23				5,557,500
															3/25/11				—				500,000				—				4,965,000
Matthew A. Jones			N/A				N/A				4,332,000				3/25/11				150,000				—				22.23				3,334,500
															3/25/11				—				200,000				—				1,986,000
Freddie M. Kotek			N/A				N/A				2,166,000				3/25/11				30,000				—				22.23				666,900
															3/25/11				—				70,000				—				695,100
															4/27/11				20,000				—				25.20				504,000

 

(1)

Represents performance-based bonuses under our Senior Executive Plan. As discussed under “Compensation Discussion and Analysis—Elements of our Compensation Program—Annual Incentives—Performance-Based Bonuses,” the Compensation Committee set performance goals based on our distributable cash flow and established maximum awards, but not minimum or target amounts, for each eligible NEO. Our Senior Executive Plan sets an individual limit of $15,000,000 per annum regardless of the maximum amounts that might otherwise be payable.

(2)	Represents phantom units granted under the 2010 Plan.

(3)	Represents options granted under the 2010 Plan.

(4)	The exercise price is equal to the closing price of our common units on the date of grant.

(5)	The grant date fair value was calculated in accordance with FASB ASC Topic 718.

(6)	Units and options were forfeited upon Kalamaras’ resignation effective October 31, 2011.

Employment Agreements and Potential Payments Upon Termination or Change of Control

Edward E. Cohen

2004 Employment Agreement

In May 2004, AEI entered into an employment agreement with Edward E. Cohen, who currently serves as our Chief Executive Officer and President. The agreement was amended as of December 31, 2008 to comply with requirements under Section 409A of the Code relating to deferred compensation. As discussed above under “Compensation Discussion and Analysis,” AEI allocated a portion of Mr. Cohen’s compensation cost to APL based on an estimate of the time spent by Mr. Cohen on our and APL’s activities. AEI added 50% to the compensation amount allocated to APL to cover the costs of health insurance and similar benefits. Mr. Cohen’s employment agreement terminated in February 2011 in connection with the Chevron Merger, and we entered into a new employment agreement with Mr. Cohen on May 13, 2011.

Mr. Cohen’s employment agreement required him to devote such time to AEI as was reasonably necessary to the fulfillment of his duties, although it permitted him to invest and participate in outside business endeavors. The agreement provided for initial base compensation of $350,000 per year, which could be increased by the AEI compensation committee based upon its evaluation of Mr. Cohen’s performance. Mr. Cohen was eligible to receive incentive bonuses and stock option grants and to participate in all employee benefit plans in effect during his period of employment.

 

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The agreement had a term of three years and, until notice to the contrary, the term was automatically extended so that on any day on which the agreement was in effect it had a then-current three-year term. Mr. Cohen’s former employment agreement was entered into in 2004, around the time that AEI was preparing to launch its initial public offering in connection with its spin-off from Resource America, Inc. At that time, it was important to establish a long-term commitment to and from Mr. Cohen as the Chief Executive Officer and then-current President of AEI. The rolling three-year term was determined to be an appropriate amount of time to reflect that commitment and was deemed a term that was commensurate with Mr. Cohen’s position. The multiples of the compensation components upon termination or a change of control, discussed below, were generally aligned with competitive market practice for similar executives at the time that the agreement was negotiated.

The agreement provided the following regarding termination and termination benefits:

 

•

Upon termination of employment due to death, Mr. Cohen’s estate will receive (a) a lump sum payment in an amount equal to three times his final base salary and (b) automatic vesting of all stock and option awards.

 

•

AEI may terminate Mr. Cohen’s employment if he is disabled for 180 consecutive days during any 12-month period. If his employment is terminated due to disability, Mr. Cohen will receive (a) a lump sum payment in an amount equal to three times his final base salary, (b) a lump sum amount equal to the COBRA premium cost for continued health coverage, less the premium charge that is paid by AEI’s employees, during the three years following his termination, (c) a lump sum amount equal to the cost AEI would incur for life, disability and accident insurance coverage during the three-year period, less the premium charge that is paid by our employees, (d) automatic vesting of all stock and option awards and (e) any amounts payable under AEI’s long-term disability plan.

 

•

AEI may terminate Mr. Cohen’s employment without cause, including upon or after a change of control, upon 30 days’ prior written notice. He may terminate his employment for good reason. Good reason is defined as a reduction in his base pay, a demotion, a material reduction in his duties, relocation, his failure to be elected to AEI’s Board of Directors or AEI’s material breach of the agreement. Mr. Cohen must provide AEI with 30 days’ notice of a termination by him for good reason within 60 days of the event constituting good reason. AEI then would have 30 days in which to cure and, if it does not do so, Mr. Cohen’s employment will terminate 30 days after the end of the cure period. If employment is terminated by AEI without cause, by Mr. Cohen for good reason or by either party in connection with a change of control, he will be entitled to either (a) if Mr. Cohen does not sign a release, severance benefits under AEI’s then-current severance policy, if any, or (b) if Mr. Cohen signs a release, (i) a lump sum payment in an amount equal to three times his average compensation (defined as the average of the three highest years of total compensation), (ii) a lump sum amount equal to the COBRA premium cost for continued health coverage, less the premium charge that is paid by AEI’s employees, during the three years following his termination, (iii) a lump sum amount equal to the cost AEI would incur for life, disability and accident insurance coverage during the three-year period, less the premium charge that is paid by AEI’s employees, and (iv) automatic vesting of all stock and option awards.

 

•

Mr. Cohen may terminate the agreement without cause with 60 days notice to AEI, and if he signs a release, he will receive (a) a lump sum payment equal to one-half of one year’s base salary then in effect and (b) automatic vesting of all stock and option awards.

“Change of control” was defined as:

 

•

the acquisition of beneficial ownership, as defined in the Securities Exchange Act of 1933, of 25% or more of AEI’s voting securities or all or substantially all of AEI’s assets by a single person or entity or group of affiliated persons or entities, other than an entity affiliated with Mr. Cohen or any member of his immediate family;

 

•

AEI consummates a merger, consolidation, combination, share exchange, division or other reorganization or transaction with an unaffiliated entity in which either (a) AEI’s directors immediately before the transaction constitute less than a majority of the board of the surviving entity, unless 1/2 of the surviving entity’s board were AEI’s directors immediately before the transaction and AEI’s chief executive officer immediately before the transaction continues as the chief executive officer of the surviving entity; or (b) AEI’s voting securities immediately prior to the transaction represent less than 60% of the combined voting power immediately after the transaction of AEI, the surviving entity or, in the case of a division, each entity resulting from the division;

 

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•

during any period of 24 consecutive months, individuals who were AEI Board members at the beginning of the period cease for any reason to constitute a majority of the AEI Board, unless the election or nomination for election by AEI’s stockholders of each new director was approved by a vote of at least 2/3 of the directors then still in office who were directors at the beginning of the period; or

 

•

AEI’s stockholders approve a plan of complete liquidation or winding up of AEI, or agreement of sale of all or substantially all of AEI’s assets or all or substantially all of the assets of AEI’s primary subsidiaries to an unaffiliated entity.

Termination amounts will not be paid until 6 months after the termination date, if such delay is required by Section 409A. In the event that any amounts payable to Mr. Cohen upon termination become subject to any excise tax imposed under Section 4999 of the Code, AEI must pay Mr. Cohen an additional sum such that the net amounts retained by Mr. Cohen, after payment of excise, income and withholding taxes, equals the termination amounts payable, unless Mr. Cohen’s employment terminates because of his death or disability.

When Mr. Cohen’s employment agreement terminated in February 2011, in connection with the Chevron Merger, he received the following, all of which was paid by Chevron: $60,354,580 for the cash-out of the AEI equity he held, $17,872,308 in severance, $71,842 in benefits payments, and $6,052,204 for excise tax gross-up.

2011 Employment Agreement

On May 13, 2011, we entered into a new employment agreement with Mr. Cohen to secure his service as President and Chief Executive Officer. The agreement has an effective date of May 16, 2011 and has a term of three years, which automatically renews daily, unless terminated before the expiration of the term pursuant to the termination provisions of the agreement.

The agreement provides for an initial annual base salary of $700,000, which may be increased at the discretion of the board of directors of our general partner. Mr. Cohen is entitled to participate in any short-term and long-term incentive programs and health and welfare plans and receive perquisites and reimbursement of business expenses, in each case as provided by us for our senior level executives generally. Mr. Cohen participates in the Excess 401(k) Plan, under which he may elect to defer up to 10% of his total annual cash compensation, which we must match on a dollar-for-dollar basis up to 50% of his annual base salary. See “2011 Non-Qualified Deferred Compensation.” During the term of the agreement, we must maintain a term life insurance policy on Mr. Cohen’s life which provides a death benefit of $3 million, which can be assumed by Mr. Cohen upon a termination of employment.

The agreement provides the following benefits in the event of a termination of employment:

 

•

Upon termination of employment due to death, all equity awards held by Mr. Cohen accelerate and vest in full upon the later of the termination of employment or six months after the date of grant of the awards (“Acceleration of Equity Vesting”), and Mr. Cohen’s estate is entitled to receive, in addition to payment of all accrued and unpaid amounts of base salary, vacation, business expenses and other benefits (“Accrued Obligations”), a pro-rata bonus for the year of termination, based on the actual bonus that would have been earned had the termination of employment not occurred, determined and paid consistent with past practice (the “Pro-Rata Bonus”).

 

•

We may terminate Mr. Cohen’s employment if he has been unable to perform the material duties of his employment for 180 days in any 12-month period because of physical or mental injury or illness, but we are required to pay his base salary until we act to terminate his employment. Upon termination of employment due to disability, Mr. Cohen will receive the Accrued Obligations, all amounts payable under our long-term disability plans, three years’ continuation of group term life and health insurance benefits (or, alternatively, we may elect to pay executive cash in lieu of such coverage in an amount equal to three years’ healthcare coverage at COBRA rates and the premiums we 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 us without cause or by Mr. Cohen for good reason, Mr. Cohen will be entitled to either (i) if he does not execute and not revoke a release of claims against us, payment of the Accrued Obligations, or (ii), in addition to payment of the Accrued Obligations, if he executes and does not revoke a release

 

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of claims against us, (A) a lump-sum cash payment in an amount equal to three years of his average compensation (which is generally defined as the sum of (1) his base salary in effect immediately before the termination of employment plus (2) the average of the cash bonuses earned for the three calendar years preceding the year in which the date of termination of employment occurs (or $1,000,000 if the period of employment ended before the 2011 annual bonuses had been paid), (B) Continued Benefits, (C) the Pro-Rata Bonus, and (D) Acceleration of Equity Vesting.

 

•

Upon a termination by us for cause or by Mr. Cohen without good reason, he is entitled to receive payment of the Accrued Obligations.

“Good reason” is defined under the agreement as:

 

•

a material reduction in Mr. Cohen’s base salary;

 

•

a demotion from his position;

 

•

a material reduction in Mr. Cohen’s duties, it being deemed such a material reduction if we cease to be a public company unless we become a subsidiary of a public company and Mr. Cohen becomes the chief executive officer of the public parent immediately following the applicable transaction;

 

•

Mr. Cohen is required to relocate to a location more than 35 miles from his previous location;

 

•

Mr. Cohen ceases to be elected to our board; or

 

•

any material breach of the agreement.

“Cause” is defined as:

 

•

Mr. Cohen is convicted of a felony, or any crime involving fraud or embezzlement;

 

•

Mr. Cohen intentionally and continually fails to perform his reasonably assigned duties (other than as a result of disability), which failure is materially and demonstrably detrimental to our company and has continued for 30 days after written notice signed by a majority of the independent directors of our general partner; or

 

•

Mr. Cohen is determined, through arbitration, to have materially breached the restrictive covenants in the agreement.

In connection with a change of control, any “excess parachute payments” (within the meaning of Section 280G of the Internal Revenue Code) otherwise payable to Mr. Cohen will be reduced such that the total payments to the executive which are subject to Internal Revenue Code Section 280G are no greater than the Section 280G “safe harbor amount” if he would be in a better after-tax position as a result of such reduction.

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, 2011.

 

Reason for Termination		Lump Sum Severance Payment				Benefits(1)				Accelerated vesting of stock awards and option awards(2)
Death		$	6,500,000	(3)		$	—			$	8,739,000
Disability			3,500,000				51,480				8,739,000
Termination by us without cause or by Mr. Cohen for good reason			5,100,000	(4)			51,480				8,739,000

 

(1)	Dental and medical benefits were calculated using 2011 COBRA rates.

(2)

Represents the value of unexercisable option and unvested unit awards disclosed in the “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, 2011. 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, 2011.

(3)	Includes the $3 million death benefit from the life insurance policy and payment of the 2011 bonus.

(4)	Calculated based on Mr. Cohen’s current base salary plus the applicable bonus.

 

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Jonathan Z. Cohen

2009 Employment Agreement

In January 2009, AEI entered into an employment agreement with Jonathan Z. Cohen, who currently serves as our Chairman. As discussed above under “Compensation Discussion and Analysis,” AEI allocated a portion of Mr. Cohen’s compensation cost based on an estimate of the time spent by Mr. Cohen on our and APL’s activities. Mr. Cohen’s employment agreement terminated in February 2011 in connection with the Chevron Merger, and we entered into a new employment agreement with Mr. Cohen on May 13, 2011.

Mr. Cohen’s employment agreement required him to devote such time to AEI as was reasonably necessary to the fulfillment of his duties, although it permitted him to invest and participate in outside business endeavors. The agreement provided for initial base compensation of $600,000 per year, which could be increased by the AEI board based upon its evaluation of Mr. Cohen’s performance. Mr. Cohen was eligible to receive incentive bonuses and stock option grants and to participate in all employee benefit plans in effect during his period of employment. The agreement had a term of three years and, until notice to the contrary, the term was automatically extended so that on any day on which the agreement was in effect it had a then-current three-year term. The rolling three-year term and the multiples of the compensation components upon termination or a change of control, discussed below, were generally aligned with competitive market practice for similar executives at the time that the employment agreement was negotiated.

The agreement provided the following regarding termination and termination benefits:

 

•

Upon termination of employment due to death, Mr. Cohen’s estate will receive (a) accrued but unpaid bonus and vacation pay and (b) automatic vesting of all equity-based awards.

 

•

AEI may terminate Mr. Cohen’s employment without cause upon 90 days’ prior notice or if he is physically or mentally disabled for 180 days in the aggregate or 90 consecutive days during any 365-day period and AEI’s board determines, in good faith based upon medical evidence, that he is unable to perform his duties. Upon termination by AEI other than for cause, including disability, or by Mr. Cohen for good reason (defined as any action or inaction that constitutes a material breach by AEI of the employment agreement or a change of control), Mr. Cohen will receive either (a) if Mr. Cohen does not sign a release, severance benefits under our then-current severance policy, if any, or (b) if Mr. Cohen signs a release, (i) a lump sum payment in an amount equal to three years of his average compensation (which is defined as his base salary in effect immediately before termination plus the average of the cash bonuses earned for the three calendar years preceding the year in which the termination occurred), less, in the case of termination by reason of disability, any amounts paid under disability insurance provided by us, (ii) monthly reimbursement of any COBRA premium paid by Mr. Cohen, less the amount Mr. Cohen would be required to contribute for health and dental coverage if he were an active employee and (iv) automatic vesting of all equity-based awards.

 

•

AEI may terminate Mr. Cohen’s employment for cause (defined as a felony conviction or conviction of a crime involving fraud, deceit or misrepresentation, failure by Mr. Cohen to materially perform his duties after notice other than as a result of physical or mental illness, or violation of confidentiality obligations or representations contained in the employment agreement). Upon termination by AEI for cause or by Mr. Cohen for other than good reason, Mr. Cohen’s vested equity-based awards will not be subject to forfeiture.

“Change of control” was defined as:

 

•

the acquisition of beneficial ownership, as defined in the Securities Exchange Act, of 25% or more of AEI’s voting securities or all or substantially all of AEI’s assets by a single person or entity or group of affiliated persons or entities, other than an entity affiliated with Mr. Cohen or any member of his immediate family;

 

•

AEI consummates a merger, consolidation, combination, share exchange, division or other reorganization or transaction with an unaffiliated entity in which either (a) AEI’s directors immediately before the transaction constitute less than a majority of the board of the surviving entity, unless 1/2 of the surviving entity’s board were our directors immediately before the transaction and AEI’s Chief Executive Officer immediately before the transaction continues as the Chief Executive Officer of the surviving entity; or (b) AEI’s voting securities immediately prior to the transaction represent less than 60% of the combined voting power immediately after the transaction of AEI, the surviving entity or, in the case of a division, each entity resulting from the division;

 

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during any period of 24 consecutive months, individuals who were AEI board members at the beginning of the period cease for any reason to constitute a majority of AEI’s board, unless the election or nomination for election by AEI’s stockholders of each new director was approved by a vote of at least 2/3 of the directors then still in office who were directors at the beginning of the period; or

 

•

AEI’s stockholders approve a plan of complete liquidation or winding up, or agreement of sale of all or substantially all of AEI’s assets or all or substantially all of the assets of its primary subsidiaries to an unaffiliated entity.

Termination amounts will not be paid until 6 months after the termination date, if such delay is required by Section 409A. When Mr. Cohen’s employment agreement terminated in February 2011, in connection with the Chevron Merger, he received the following, all of which was paid by Chevron: $36,837,883 for the cash-out of the AEI equity he held and $8,600,000 in severance.

2011 Employment Agreement

On May 13, 2011, we entered into a new employment agreement with Mr. Cohen to secure his service as Chairman of the Board. The agreement has an effective date of May 16, 2011 and has a term of three years, which automatically renews daily, unless terminated before the expiration of the term pursuant to the termination provisions of the agreement.

The agreement provides for an initial annual base salary of $500,000, which may be increased at the discretion of the board of directors of our general partner. Mr. Cohen is entitled to participate in any short-term and long-term incentive programs and health and welfare plans of the company and receive perquisites and reimbursement of business expenses, in each case as provided by us for our senior level executives generally. Mr. Cohen participates in the Excess 401(k) Plan, under which he may elect to defer up to 10% of his total annual cash compensation, which we must match on a dollar-for-dollar basis up to 50% of his annual base salary. See “2011 Non-Qualified Deferred Compensation.” During the term of the agreement, we must maintain a term life insurance policy on Mr. Cohen’s life which provides a death benefit of $2 million, which can be assumed by Mr. Cohen upon a termination of employment.

The agreement provides the following benefits in the event of a termination of employment:

 

•

Upon termination of employment due to death, all equity awards held by Mr. Cohen accelerate and vest in full upon the later of the termination of employment or six months after the date of grant of the awards (“Acceleration of Equity Vesting”), and Mr. Cohen’s estate is entitled to receive, in addition to payment of all accrued and unpaid amounts of base salary, vacation, business expenses and other benefits (“Accrued Obligations”), a pro-rata bonus for the year of termination, based on the actual bonus that would have been earned had the termination of employment not occurred, determined and paid consistent with past practice (the “Pro-Rata Bonus”).

 

•

We may terminate Mr. Cohen’s employment if he has been unable to perform the material duties of his employment for 180 days in any 12-month period because of physical or mental injury or illness, but we are required to pay his base salary until we act to terminate his employment. Upon termination of employment due to disability, Mr. Cohen will receive the Accrued Obligations, all amounts payable under our long-term disability plans, three years’ continuation of group term life and health insurance benefits (or, alternatively, we may elect to pay executive cash in lieu of such coverage in an amount equal to three years’ healthcare coverage at COBRA rates and the premiums we 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 us without cause or by Mr. Cohen for good reason, Mr. Cohen will be entitled to either (i) if he does not execute and not revoke a release of claims against us, payment of the Accrued Obligations, or (ii), in addition to payment of the Accrued Obligations, if he executes and does not revoke a release of claims against us, (A) a lump-sum cash payment in an amount equal to three years of his average compensation (which is generally defined as the sum of (1) his base salary in effect immediately before the termination of employment plus (2) the average of the cash bonuses earned for the three calendar years preceding the year in which the date of termination of employment occurs (or $250,000 if the period of employment ended before the 2011 annual bonuses had been paid), (B) Continued Benefits, (C) the Pro-Rata Bonus, and (D) Acceleration of Equity Vesting.

 

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Upon a termination by us for cause or by Mr. Cohen without good reason, he is entitled to receive payment of the Accrued Obligations.

“Good reason” is defined under the agreement as:

 

•

a material reduction in Mr. Cohen’s base salary;

 

•

a demotion from his position;

 

•

a material reduction in Mr. Cohen’s duties, it being deemed such a material reduction if we cease to be a public company unless we become a subsidiary of a public company and Mr. Cohen becomes an executive officer of the public parent with responsibilities substantially equivalent to his previous position immediately following the applicable transaction;

 

•

Mr. Cohen is required to relocate to a location more than 35 miles from his previous location;

 

•

Mr. Cohen ceases to be elected to our board; or

 

•

any material breach of the agreement.

“Cause” is defined as:

 

•

Mr. Cohen is convicted of a felony, or any crime involving fraud or embezzlement;

 

•

Mr. Cohen intentionally and continually fails to perform his reasonably assigned duties (other than as a result of disability), which failure is materially and demonstrably detrimental to our company and has continued for 30 days after written notice signed by a majority of the independent directors of our general partner; or

 

•

Mr. Cohen is determined, through arbitration, to have materially breached the restrictive covenants in the agreement.

In connection with a change of control, any “excess parachute payments” (within the meaning of Section 280G of the Internal Revenue Code) otherwise payable to Mr. Cohen will be reduced such that the total payments to the executive which are subject to Internal Revenue Code Section 280G are no greater than the Section 280G “safe harbor amount” if he would be in a better after-tax position as a result of such reduction.

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, 2011.

 

Reason for Termination		Lump Sum Severance Payment				Benefits(1)				Accelerated vesting of stock awards and option awards(2)
Death		$	5,000,000	(3)		$	—			$	7,110,000
Disability			3,000,000				74,210				7,110,000
Termination by us without cause or by Mr. Cohen for good reason			3,750,000	(4)			74,210				7,110,000

 

(1)	Dental and medical benefits were calculated using 2011 COBRA rates.

(2)

Represents the value of unexercisable option and unvested unit awards disclosed in the “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, 2011. 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, 2011.

(3)	Includes the $2 million death benefit from the life insurance policy and payment of the 2011 bonus.

(4)	Calculated based on Mr. Cohen’s current base salary plus the applicable bonus.

 

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Matthew Jones

2009 Employment Agreement

In July 2009, AEI entered into an employment agreement with Matthew A. Jones, who served as its Chief Financial Officer. The agreement provided for initial base compensation of $300,000 per year, which provided that it may be increased at the discretion of our Board of Directors. Mr. Jones was eligible to receive grants of equity based compensation from us, APL, and other affiliates, which we refer to as the Atlas Entities, and to participate in all employee benefit plans in effect during his period of employment. The agreement provided that any unvested equity compensation will be subject to forfeiture in accordance with the long-term incentive plan of the applicable entity except that, if AEI terminates Mr. Jones’s employment without cause, including his disability, or if Mr. Jones terminates his employment for good reason or in the event of his death, all of his unvested awards will be fully vested.

The agreement had a term of two years. It provided that AEI may terminate the agreement:

 

•

at any time for cause;

 

•

without cause upon 90 days’ prior written notice;

 

•

if Mr. Jones was physically or mentally disabled for 180 days in the aggregate or 90 consecutive days during any 365-day period and AEI’s Board of Directors determines, in good faith based upon medical evidence, that he was unable to perform his duties; or

 

•

in the event of Mr. Jones’s death.

Mr. Jones had the right to terminate the agreement for good reason, defined as material breach by us of the agreement or a change of control. Mr. Jones must provide notice of a termination by him for good reason within 30 days of the event constituting good reason. AEI then would have 30 days in which to cure and, if it did not do so, Mr. Jones’s employment will terminate 30 days after the end of the cure period. Mr. Jones may also terminate the agreement without good reason upon 30 days’ notice. Termination amounts will not be paid until six months after the termination date, if such delay is required by Section 409A of the Internal Revenue Code.

“Cause” was defined as

 

•

Mr. Jones’ having committed a demonstrable and material act of fraud;

 

•

illegal or gross misconduct that is willful and results in damage to the business or reputation of the Atlas Entities;

 

•

being charged with a felony;

 

•

continued failure by Mr. Jones to perform his duties after notice other than as a result of physical or mental illness; or

 

•

Mr. Jones’s failure to follow reasonable written directions consistent with his duties.

“Good reason” was defined as any action or inaction that constitutes a material breach by AEI of the agreement or a change of control.

“Change of control” was defined as:

 

•

the acquisition of beneficial ownership, as defined in the Securities Exchange Act, of 50% or more of AEI’s voting securities or all or substantially all of AEI’s assets by a single person or entity or group of affiliated persons or entities, other than by a related entity, defined as any of the Atlas Entities or any affiliate of AEI or of Mr. Jones or any member of his immediate family;

 

•

the consummation of a merger, consolidation, combination, share exchange, division or other reorganization or transaction with an unaffiliated entity, other than a related entity, in which either (a) AEI’s directors immediately before the transaction constitute less than a majority of the board of directors of the surviving entity, unless 1/2 of the surviving entity’s board were AEI’s directors immediately before the transaction and AEI’s Chief Executive Officer immediately before the transaction continues as the Chief Executive Officer of the surviving entity; or (b) AEI’s voting securities immediately before the transaction represent less than 60% of the combined voting power immediately after the transaction of AEI, the surviving entity or, in the case of a division, each entity resulting from the division;

 

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•

during any period of 24 consecutive calendar months, individuals who were Board members at the beginning of the period cease for any reason to constitute a majority of the Board, unless the election or nomination for the election by AEI’s stockholders of each new director was approved by a vote of at least 2/3 of the directors then still in office who were directors at the beginning of the period; or

 

•

AEI’s stockholders approve a plan of complete liquidation or winding-up, or agreement of sale of all or substantially all of AEI’s assets or all or substantially all of the assets of AEI’s primary subsidiaries other than to a related entity.

The agreement provided the following regarding termination and termination benefits:

 

•

upon termination of employment due to death, Mr. Jones’s designated beneficiaries would receive a lump sum cash payment within 60 days of the date of death of (a) any unpaid portion of his annual salary earned and not yet paid; (b) an amount representing the incentive compensation earned for the period up to the date of termination computed by assuming that the amount of all such incentive compensation would be equal to the amount that Mr. Jones earned during the prior fiscal year, pro-rated through the date of termination; (c) any accrued but unpaid incentive compensation and vacation pay; and (d) all equity compensation awards would immediately vest.

 

•

upon termination by us for cause or by Mr. Jones for other than good reason, Mr. Jones would receive only base salary and vacation pay to the extent earned and not paid. Mr. Jones’s equity awards that have vested as of the date of termination would not be subject to forfeiture.

 

•

upon termination by us other than for cause, including disability, or by Mr. Jones for good reason, he would be entitled to either (a) if Mr. Jones did not sign a release, severance benefits under our then current severance policy, if any, or (b) if Mr. Jones signed a release, (i) a lump sum payment in an amount equal to two years of his average compensation (which was defined as his base salary in effect immediately before termination plus the average of the cash bonuses earned for the three calendar years preceding the year in which the date of terminated occurred), less, in the case of termination by reason of disability, any amounts paid under disability insurance provided by AEI; (ii) monthly reimbursement of any COBRA premium paid Mr. Jones, less the amount Mr. Jones would be required to contribute for health and dental coverage if he were an active employee, for the 24 months following the date of termination, and (iii) automatic vesting of Mr. Jones’s equity awards.

When Mr. Jones’s employment agreement terminated in February 2011, in connection with the Chevron Merger, he received the following, all of which was paid by Chevron: $14,471,906 for the cash-out of the AEI equity he held and $3,400,000 in severance.

2011 Employment Agreement

In November 2011, we entered into an employment agreement with Matthew A. Jones. Under the agreement, Mr. Jones has the title of Senior Vice President and President and Chief Operating Officer of the Exploration and Production Division of the Company. The agreement has an effective date of November 4, 2011 and has an initial term of two years, which automatically ends at the end of such initial two-year term unless we elect to renew the agreement for a subsequent two-year term pursuant to the agreement.

The agreement provides for an initial annual base salary of $280,000. Mr. Jones is entitled to participate in any of our 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 us for our senior executives generally.

The agreement provides the following benefits in the event of a termination of employment:

 

•

Upon a termination by us for cause or by Mr. Jones without good reason, he is entitled to receive payment of accrued but unpaid base salary and (to the extent required to be paid under Company policy) amounts of accrued but unpaid vacation, in each through the date of termination (together, the “Accrued Obligations”).

 

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•

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 our general partner’s board of directors, in good faith based upon medical evidence, that he is unable to perform his duties), all equity awards held by Mr. Jones accelerate and vest in full upon such termination (“Acceleration of Equity Vesting”), and Mr. Jones or his estate is entitled to receive, in addition to payment of all Accrued Obligations, a pro-rata amount in respect of the bonus granted to the executive for the fiscal year in which the termination occurs in an amount equal to the bonus earned by Mr. Jones for the prior fiscal year multiplied by a fraction, the numerator of which is the number of days in the fiscal year in which the termination occurs through the date of termination, and the denominator of which is the total number of days in such fiscal year (the “Pro-Rata Bonus”). In addition, in the event of Mr. Jones’s death, his family is entitled to Company-paid health insurance for the one-year period after his death.

 

•

Upon a termination of employment by the Company without cause (which, for purposes of the “Acceleration of Equity Vesting” includes a non-renewal of the agreement) or by the executive for good reason, Mr. Jones will be entitled to either:

 

•

if Mr. Jones does not timely execute (or revokes) a release of claims against us, payment of the Accrued Obligations and payment of the Pro-Rata Bonus; or

 

•

in addition to payment of the Accrued Obligations and payment of the Pro-Rata Bonus, if Mr. Jones timely executes and does not revoke a release of claims against us:

 

•

a lump-sum cash severance payment in an amount equal to two years of his average compensation (which is the sum of his then-current base salary and the average of the cash bonuses earned for the three calendar years preceding the year in which the termination occurs);

 

•

healthcare continuation at active employee rates for two years; and

 

•

Acceleration of Equity Vesting.

“Good reason” is defined under the agreement as:

 

•

a material reduction in Mr. Jones’ base salary;

 

•

a demotion from his position;

 

•

a material reduction in Mr. Jones’ duties, it being deemed such a material reduction if we cease to be a public company unless we become a subsidiary of a public company and our CEO or the Chairman of our general partner’s board is not our CEO or the CEO of the acquiring entity;

 

•

Mr. Jones is required to relocate to a location more than 35 miles from his previous location; or

 

•

any material breach of the agreement.

“Cause” is defined as:

 

•

Mr. Jones has committed any demonstrable and material fraud;

 

•

illegal or gross misconduct by Mr. Jones that is willful and results in damage to our business or reputation;

 

•

Mr. Jones is convicted of a felony, or any crime involving fraud or embezzlement;

 

•

Mr. Jones fails to substantially perform his duties (other than as a result of disability) after written demand and a reasonable opportunity to cure; or

 

•

Mr. Jones fails to follow reasonable written instructions which are consistent with his duties.

 

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In connection with a change of control of the Company, any “excess parachute payments” (within the meaning of Section 280G of the Internal Revenue Code) otherwise payable to Mr. Jones will be reduced such that the total payments to the executive which are subject to Section 280G are no greater than the Section 280G “safe harbor amount” if Mr. Jones would be in a better after-tax position as a result of such reduction.

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, 2011.

 

Reason for Termination		Lump Sum Severance Payment				Benefits(1)				Accelerated vesting of stock awards and option awards(2)
Death		$	1,250,000			$	17,255			$	4,059,000
Disability			1,250,000				—				4,059,000
Termination by us without cause or by Mr. Jones for good reason			560,000	(3)			34,510				4,059,000

 

(1)	Dental and medical benefits were calculated using 2011 active employee rates.

(2)

Represents the value of unexercisable option and unvested unit awards disclosed in the “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, 2011. 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, 2011.

(3)	Calculated based on Mr. Jones’s 2011 base salary.

Eugene N. Dubay

2009 Employment Agreement

In January 2009, AEI entered into an employment agreement with Eugene N. Dubay, who currently serves as Senior Vice President of Midstream and President and Chief Executive Officer of Atlas Pipeline Partners GP. Mr. Dubay’s employment agreement terminated in February 2011 in connection with the Chevron Merger, and we entered into a new employment agreement with Mr. Dubay on November 4, 2011. AEI historically allocated all of Mr. Dubay’s compensation cost to Atlas Pipeline Partners.

The agreement provided for an initial base salary of $400,000 per year and a bonus of not less than $300,000 for the period ending December 31, 2009. After that, bonuses would be awarded solely at the discretion of AEI’s compensation committee. In addition to reimbursement of reasonable and necessary expenses incurred in carrying out his duties, Mr. Dubay was entitled to reimbursement of up to $40,000 for relocation costs and AEI agreed to purchase his residence in Michigan for $1,000,000. The agreement provided that if Mr. Dubay’s employment was terminated before June 30, 2011 by him without good reason or by AEI for cause, Mr. Dubay must repay an amount equal to the difference between the amount AEI paid for his residence and its fair market value on the date acquired by AEI. Upon execution of the agreement, Mr. Dubay was granted the following equity compensation:

 

•

Options to purchase 100,000 shares of AEI’s common stock, which vest 25% per year on each anniversary of the effective date of the agreement;

 

•

Options to purchase 100,000 of APL’s common units, which vest 25% per year on each anniversary of the effective date of the agreement; and

 

•

Options to purchase 100,000 of our common units, which vest 25% on the third anniversary, and 75% on the fourth anniversary, of the effective date of the agreement.

The agreement had a term of two years and, until notice to the contrary, his term was automatically renewed for one year renewal terms. AEI may terminate the agreement:

 

•

at any time for cause;

 

•

without cause upon 45 days’ prior written notice;

 

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if he is physically or mentally disabled for 180 days in the aggregate or 90 consecutive days during any 365-day period and our and Atlas Pipeline Holding’s board of directors determine, in good faith based upon medical evidence, that he is unable to perform his duties; or

 

•

in the event of Mr. Dubay’s death.

Mr. Dubay had the right to terminate the agreement for good reason, including a change of control. Mr. Dubay must provide notice of a termination by him for good reason within 30 days of the event constituting good reason. Termination by Mr. Dubay for good reason was only effective if such failure has not been cured within 90 days after notice is given to AEI. Mr. Dubay could also terminate the agreement without good reason upon 60 days’ notice. Termination amounts will not be paid until six months after the termination date, if such delay is required by Section 409A of the Internal Revenue Code.

“Cause” was defined as:

 

•

the commitment of a material act of fraud;

 

•

illegal or gross misconduct that is willful and results in damage to our business or reputation;

 

•

being charged with a felony;

 

•

continued failure by Mr. Dubay to perform his duties after notice other than as a result of physical or mental illness; or

 

•

Mr. Dubay’s failure to follow AEI’s reasonable written directions consistent with his duties.

“Good reason” is defined as any action or inaction that constitutes a material breach by AEI of the agreement or a change of control.

“Change of control” was defined as:

 

•

the acquisition of beneficial ownership, as defined in the Securities Exchange Act, of 50% or more of AEI’s voting securities or all or substantially all of AEI’s assets by a single person or entity or group of affiliated persons or entities, other than an entity affiliated with AEI or Mr. Dubay or any member of his immediate family;

 

•

AEI consummates a merger, consolidation, combination, share exchange, division or other reorganization or transaction of AEI other than with a related entity, in which either (a) AEI’s directors immediately before the transaction constitute less than a majority of the board of directors of the surviving entity, unless 1/2 of the surviving entity’s board were AEI directors immediately before the transaction and AEI’s Chief Executive Officer immediately before the transaction continues as the Chief Executive Officer of the surviving entity; or (b) AEI’s voting securities immediately before the transaction represent less than 60% of the combined voting power immediately after the transaction of AEI, the surviving entity or, in the case of a division, each entity resulting from the division;

 

•

during any period of 24 consecutive calendar months, individuals who were AEI board members at the beginning of the period cease for any reason to constitute a majority of AEI’s board, unless the election or nomination for the election by AEI’s stockholders of each new director was approved by a vote of at least 2/3 of the directors then still in office who were directors at the beginning of the period; or

 

•

AEI’s shareholders approve a plan of complete liquidation or winding-up, or agreement of sale of all or substantially all of AEI’s assets or all or substantially all of the assets of its primary subsidiaries other than to a related entity.

The agreement provided the following regarding termination and termination benefits:

 

•

Upon termination of employment due to death, Mr. Dubay’s designated beneficiaries will receive a lump sum cash payment within 60 days of the date of death of (a) any unpaid portion of his annual salary earned and not yet paid, (b) an amount representing the incentive compensation earned for the period up to the date of termination computed

 

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by assuming that all such incentive compensation would be equal to the amount of incentive compensation Mr. Dubay earned during the prior fiscal year, pro-rated through the date of termination; and (c) any accrued but unpaid incentive compensation and vacation pay.

 

•

Upon termination of employment by AEI other than for cause, including disability, or by Mr. Dubay for good reason, if Mr. Dubay executes and does not revoke a release, Mr. Dubay will receive (a) pro-rated cash incentive compensation for the year of termination, based on actual performance for the year; and (b) monthly severance pay for the remainder of the employment term in an amount equal to 1/12 of (x) his annual base salary and (y) the annual amount of cash incentive compensation paid to Mr. Dubay for the fiscal year prior to his year of termination; (c) monthly reimbursements of any COBRA premium paid by Mr. Dubay, less the monthly premium charge paid by employees for such coverage; and (d) automatic vesting of all equity awards.

 

•

Upon Mr. Dubay’s termination from employment by AEI for cause or by Mr. Dubay for any reason other than good reason, Mr. Dubay will receive his accrued but unpaid base salary.

Mr. Dubay is also subject to a non-solicitation covenant for two years after any termination of employment and, in the event his employment is terminated by AEI for cause, or terminated by him for any reason other than good reason, a non-competition covenant not to engage in any natural gas pipeline and/or processing business in the continental United States for 18 months.

Termination amounts will not be paid until 6 months after the termination date, if such delay is required by Section 409A. When Mr. Dubay’s employment agreement terminated in February 2011, in connection with the Chevron Merger, he received the following, all of which was paid by Chevron: $4,182,865 for the cash-out of the AEI equity he held and $879,712 in severance.

2011 Employment Agreement

On November 4, 2011, we entered into an employment agreement with Mr. Dubay. Under the agreement, Mr. Dubay has the title of Senior Vice-President of the Midstream Operations division of Atlas Energy GP, LLC. The agreement has an effective date of November 4, 2011 and has an initial term of two years, which automatically renews for successive one-year terms unless earlier terminated pursuant to the termination provisions of the agreement.

The agreement provides for an initial annual base salary of $500,000, and Mr. Dubay is entitled to participate in any short-term and long-term incentive programs and health and welfare plans and receive perquisites and reimbursement of business expenses, in each case as provided by us for our senior executives generally.

The agreement provides the following benefits in the event of a termination of Mr. Dubay’s employment:

 

•

Upon a termination by us for cause or by Mr. Dubay without good reason, he is entitled to receive payment of accrued but unpaid base salary and (to the extent required to be paid under company policy) amounts of accrued but unpaid vacation, in each case through the date of termination (together, the “Accrued Obligations”).

 

•

Upon a termination of employment due to death or disability (defined as Mr. Dubay being physically or mentally disabled for 180 days in the aggregate or 90 consecutive days during any 365-day period and the determination by our general partner’s board of directors, in good faith based upon medical evidence, that he is unable to perform his duties), all equity awards held by Mr. Dubay accelerate and vest in full upon such termination (“Acceleration of Equity Vesting”), and Mr. Dubay or his estate is entitled to receive, in addition to payment of all Accrued Obligations, an amount equal to the bonus earned by him for the prior fiscal year multiplied by a fraction, the numerator of which is the number of days in the fiscal year in which his termination occurs through the date of termination, and the denominator of which is the total number of days in such fiscal year (the “Pro-Rata Bonus”).

 

•

Upon a termination of employment by us without cause (which, for purposes of the “Acceleration of Equity Vesting” includes a non-renewal of the agreement) or by Mr. Dubay for good reason, he is entitled to either:

 

•

if he does not timely execute (or revokes) a release of claims against us, payment of the Accrued Obligations; or

 

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•

in addition to payment of the Accrued Obligations, if he timely executes and does not revoke a release of claims against us:

 

•

monthly cash severance installments each in an amount equal to one-twelfth of the sum of his then-current (i) annual base salary and (ii) the annual cash incentive bonus earned by him in respect of the fiscal year preceding the fiscal year in which his termination of employment occurs for the portion of the employment term remaining after the date of termination, payable for the then-remaining portion of the employment term (taking into account any applicable renewal term) assuming his termination had not occurred,

 

•

healthcare continuation at active employee rates for the then-remaining portion of the employment term (taking into account any applicable renewal term) assuming his termination had not occurred,

 

•

a prorated amount in respect of the bonus granted to him in respect of the fiscal year in which his termination of employment occurs based on actual performance for such year, calculated as the product of (x) the amount which would have been earned in respect of the award based on actual performance measured at the end of such fiscal year and (y) a fraction, the numerator of which is the number of days in such fiscal year through the date of termination, and the denominator of which is the total number of days in such fiscal year, paid in a lump sum in cash on the date payment would otherwise be made had he remained employed by the Company, and

 

•

Acceleration of Equity Vesting.

“Good reason” is defined under the agreement as:

 

•

a material reduction in Mr. Dubay’s base salary;

 

•

a demotion from his position;

 

•

a material reduction in Mr. Dubay’s duties, it being deemed such a material reduction if we cease to be a public company unless we become a subsidiary of a public company and our CEO or the Chairman of our general partner’s board is not our CEO or the CEO of the acquiring entity;

 

•

Mr. Dubay is required to relocate to a location more than 35 miles from his previous location; or

 

•

any material breach of the agreement.

“Cause” is defined as:

 

•

Mr. Dubay has committed any demonstrable and material fraud;

 

•

illegal or gross misconduct by Mr. Dubay that is willful and results in damage to our business or reputation;

 

•

Mr. Dubay is charged with a felony;

 

•

Mr. Dubay fails to substantially perform his duties (other than as a result of disability) after written demand and a reasonable opportunity to cure; or

 

•

Mr. Dubay fails to follow reasonable written instructions which are consistent with his duties.

In connection with a change of control of the Company, any “excess parachute payments” (within the meaning of Section 280G of the Internal Revenue Code) otherwise payable to Mr. Dubay will be reduced such that the total payments to him which are subject to Section 280G are no greater than the Section 280G “safe harbor amount” if he would be in a better after-tax position as a result of such reduction.

The following table provides an estimate of the value of the benefits to Mr. Dubay if a termination event had occurred as of December 31, 2011.

 

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Reason for Termination		Lump Sum Severance Payment				Benefits(1)				Accelerated vesting of stock awards and option awards(2)
Death		$	—			$	—			$	2,151,000
Disability			—				—				2,151,000
Termination by us without cause or by Mr. Dubay for good reason			1,916,667	(3)			31,634				2,151,000

 

(1)	Dental and medical benefits were calculated using 2011 active employee rates.

(2)

Represents the value of unexercisable option and unvested unit awards disclosed in the “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, 2011. 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, 2011.

(3)	Calculated based on Mr. Dubay’s 2011 base salary plus applicable bonus. Payment would be made in monthly installments for the remaining term of Mr. Dubay’s employment agreement.

Eric T. Kalamaras

In September 2009, AEI entered into a letter agreement with Eric Kalamaras, who served as our Chief Financial Officer until February 2011 and served as the Chief Financial Officer of Atlas Pipeline Partners GP until his resignation in October 2011. AEI historically allocated all of Mr. Kalamaras’ compensation cost to APL.

The agreement provided for an annual base salary of $250,000, a one-time cash signing bonus of $80,000 and a one-time award of 50,000 equity-indexed bonus units which entitled Mr. Kalamaras, upon vesting, to receive a cash payment equal to the fair market value of our common units. Mr. Kalamaras exchanged the bonus units for phantom units, effective June 1, 2010, in connection with the approval of the 2010 APL Plan, which vest 25% per year.

Mr. Kalamaras was also eligible for discretionary annual bonus compensation in an amount not to exceed 100% of his annual base salary and participation in all employee benefit plans in effect during his employment. The agreement provided that Mr. Kalamaras would serve as an at-will employee.

The agreement provided the following regarding termination and termination benefits:

 

•

AEI may terminate Mr. Kalamaras’ employment for any reason upon 30 days prior written notice, or immediately for cause.

 

•

Mr. Kalamaras may terminate his employment for any reason upon 60 days prior written notice.

 

•

Upon termination of employment for any reason, Mr. Kalamaras will receive his accrued but unpaid annual base salary through his date of termination and any accrued and unpaid vacation pay.

“Cause” is defined as having

 

•

committed an act of malfeasance or wrongdoing affecting the company or its affiliates;

 

•

breached any confidentiality, non-solicitation or non-competition covenant or employment agreement; or

 

•

otherwise engaged in conduct that would warrant discharge from employment or service because of his negative effect on the company or its affiliates.

Mr. Kalamaras is also subject to a confidentiality and non-solicitation agreement for 12 months after any termination of employment. Termination amounts will not be paid until six months after the termination date, if such delay is required by Section 409A of the Internal Revenue Code.

 

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Upon Mr. Kalamaras’s resignation in October 2011, he did not receive any payments other than accrued and unpaid vacation pay of $29,500. In addition, he forfeited all unvested equity awards.

Long-Term Incentive Plans

Our 2006 Plan

Our 2006 Plan provides equity incentive awards to officers, employees and board members and employees of our general partner and its affiliates, consultants and joint-venture partners who perform services for us. Our 2006 Plan is administered by the board or our general partner or the board of an affiliate appointed by our general partner’s board (the “Committee”). The Committee may grant awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units. Pursuant to the employee matters agreement we entered into in connection with the AHD Transactions, we amended our 2006 Plan to provide that outstanding awards granted under the 2006 Plan did not vest in connection with the Chevron Merger and the AHD Transactions pursuant to the terms and conditions of the 2006 Plan.

In connection with the distribution of 19.6% of ARP to our unitholders, as discussed further in “Item 1: Business – Subsequent Events”, our Compensation Committee has determined that such distribution qualifies under the Plans as the type of event necessitating an adjustment to the outstanding options and phantom units issued pursuant to our Plans. Accordingly, on or after March 13, 2012, the anticipated distribution date for the ARP units, the outstanding options will be 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. Outstanding phantom units will be adjusted to maintain the award’s pre-adjustment value. All other terms of these awards will remain unchanged.

Partnership Phantom Units. A phantom unit entitles a participant to receive a common unit upon vesting of the phantom unit. Beginning with the fiscal year 2010, non-employee directors receive an annual grant of phantom units having a fair market value of $25,000, which upon vesting entitles the grantee to receive the equivalent number of common units or the cash equivalent to the fair market value of the units. The phantom units 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. Phantom units granted under our Plan generally vest 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 vest 25% per year.

Partnership Unit Options. A unit option entitles a participant to receive a common unit upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of a common unit as determined by the Committee on the date of grant of the option. The Committee determines the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Unit options granted generally will vest 25% on the third anniversary of the date of grant, with the remaining 75% vesting on the fourth anniversary of the date of grant.

Our 2010 Plan

Our 2010 Plan provides equity incentive awards to officers, employees and board members and employees of our general partner and its affiliates, consultants and joint-venture partners who perform services for us. Our 2010 Plan is administered by the Committee and the Committee may grant awards of either phantom units, unit options or restricted units for an aggregate of 5,300,000 common limited partner units.

In connection with the distribution of 19.6% of ARP to our unitholders, as discussed further in “Item 1: Business – Subsequent Events”, our Compensation Committee has determined that such distribution qualifies under the Plans as the type of event necessitating an adjustment to the outstanding options and phantom units issued pursuant to our Plans. Accordingly, on or after March 13, 2012, the anticipated distribution date for the ARP units, the outstanding options will be 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. Outstanding phantom units will be adjusted to maintain the award’s pre-adjustment value. All other terms of these awards will remain unchanged.

Partnership Phantom Units. A phantom unit entitles a participant to receive a common unit upon vesting of the phantom unit. Beginning in fiscal year 2010, non-employee directors receive an annual grant of phantom units having a market value of $25,000, which, upon vesting, entitle the grantee to receive the equivalent number of common units or the cash equivalent to the fair market value of the units. The phantom units 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.

 

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Partnership Unit Options. A unit option entitles a participant to receive a common unit upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of a common unit as determined by the Committee on the date of grant of the option. The Committee determines the vesting and exercise period for unit options.

Partnership Restricted Units. A restricted unit is a common unit issued that entitles a participant to receive it upon vesting of the restricted unit. Prior to or upon grant of an award of restricted units, the Committee will condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals or both.

Upon a change in control, as defined in the 2010 Plan, all unvested awards held by directors will immediately vest in full. In the case of awards held by eligible employees, upon the eligible employee’s termination of employment without “cause”, as defined in the 2010 Plan, 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.

APL Plans

The APL 2004 Long-Term Incentive Plan (the “2004 APL Plan”) and the 2010 Long-Term Incentive Plan, which was modified in April 2011 (the “2010 APL Plan” and collectively with the 2004 APL Plan the “APL Plans”) provide incentive awards to officers, employees and non-employee managers of Atlas Pipeline GP and officers and employees of its affiliates, consultants and joint venture partners who perform services for APL or in furtherance of its business. The APL Plans are administered by Atlas Pipeline GP’s managing board or the board of an affiliate appointed by it (the “APL Committee”). Under the APL Plans, the APL Committee may make awards of either phantom units or options covering an aggregate of 435,000 common units under the 2004 APL Plan and 3,000,000 common units under the 2010 APL Plan.

APL Phantom Units. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit. In addition, the compensation committee may grant a participant the right, which is referred to as a DER, to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions are made on an APL common unit during the period the phantom unit is outstanding.

APL Unit Options. An option entitles the grantee to purchase APL common units at an exercise price determined by the compensation committee, which may be less than, equal to or more than the fair market value of APL common units on the date of grant. The compensation committee will also have discretion to determine how the exercise price may be paid.

Except for phantom units awarded to non-employee managers of Atlas Pipeline GP, the APL Committee will determine the vesting period for phantom units and the exercise period for options. Phantom units awarded to non-employee managers will generally vest over a 4-year period at the rate of 25% per year. Both types of awards will automatically vest upon a change of control, as defined in the APL Plans.

2011 Outstanding Equity Awards at Fiscal Year-End Table

 

		Option Awards																Stock 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			500,000	(1)			—				22.56				11/10/2016				—				—
			—				700,000	(2)			22.23				3/25/2021				300,000	(3)			7,290,000
Eugene N. Dubay			48,614	(1)			—				3.24				1/15/2019				—				—
			—				100,000	(4)			22.23				3/25/2021				80,000	(5)			1,944,000

 

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		Option Awards																Stock Awards
Name		Exercisable				Unexercisable				Option Exercise price ($)				Option Expiration Date				Number of Units that have not Vested (#)				Market Value of Units that have not Vested ($)
Sean P. McGrath			15,000	(1)			—				22.56				11/10/2016				—				—
			—				—				N/A				N/A				250	(6)			9,288
			—				35,000	(7)			22.23				3/25/2021				30,000	(8)			729,000
Eric Kalamaras			—				—				N/A				N/A				—				—
Jonathan Z. Cohen			200,000	(1)			—				22.56				11/10/2016				—				—
			—				500,000	(9)			22.23				3/25/2021				250,000	(10)			6,075,000
Matthew A. Jones			100,000	(1)			—				22.56				11/10/2016				—				—
			—				200,000	(11)			22.23				3/25/2021				150,000	(12)			3,645,000
Freddie M. Kotek			—				70,000	(13)			22.23				3/25/2021				30,000	(14)			729,000
			—				—				N/A				N/A				20,000	(15)			486,000

 

(1)	Represents options to purchase our units.

(2)	Represents options to purchase our units, which vest as follows: 3/25/2014 - 175,000 and 3/25/2015 - 525,000.

(3)	Represents our phantom units, which vests as follows: 3/25/2014 - 75,000 and 3/25/2015 - 225,000.

(4)	Represents options to purchase our units, which vest as follows: 3/25/2014 - 25,000 and 3/25/2015 - 75,000.

(5)	Represents our phantom units, which vests as follows: 3/25/2014 - 20,000 and 3/25/2015 - 60,000.

(6)	Represents Atlas Pipeline Partners phantom units, which vests on 2/13/2012.

(7)	Represents options to purchase our units, which vest as follows: 3/25/2014 - 8,750 and 3/25/2015 - 26,250.

(8)	Represents our phantom units, which vests as follows: 3/25/2014 - 7,500 and 3/25/2015 - 22,500.

(9)	Represents options to purchase our units, which vest as follows: 3/25/2014 - 125,000 and 3/25/2015 - 375,000.

(10)	Represents our phantom units, which vest as follows: 3/25/2014 - 62,500 and 3/25/2015 - 187,500.

(11)	Represents options to purchase our units, which vest as follows: 3/25/2014 - 50,000 and 3/25/2015 - 150,000.

(12)	Represents our phantom units, which vests as follows: 3/25/2014 - 37,500 and 3/25/2015 - 112,500.

(13)	Represents options to purchase our units, which vest as follows: 3/25/2014 - 17,500 and 3/25/2015 - 52,500.

(14)	Represents our phantom units, which vests as follows: 3/25/2014 - 7,500 and 3/25/2015 - 22,500.

(15)	Represents our phantom units, which vest as follows: 4/27/2014 - 5,000 and 4/27/2015 - 15,000.

2011 Option Exercises and Units Vested Table

 

		Option Awards												Unit Awards
Name		Number of Units Acquired on Exercise				Value Realized on Exercise ($)				Value from Cash Payout ($)				Number of Units Acquired on Vesting				Value Realized on Vesting ($)				Value from Cash Payout ($)				Total Value ($)
Edward E. Cohen			—	(1)			—				57,398,850				195,514	(2)			2,729,066				2,955,731				63,083,647
Eugene N. Dubay			126,386	(3)			2,686,579				3,591,750				79,553	(4)			2,253,781				591,116				9,123,226
Sean P. McGrath			—	(5)			—				903,051				8,950				128,017				—				1,031,068
Eric Kalamaras			—	(6)			—				316,350				22,000				752,125				—				1,068,475
Jonathan Z. Cohen			—	(7)			—				34,473,307				104,211	(8)			1,457,148				2,364,576				38,295,031
Matthew A. Jones			—	(9)			—				13,526,060				24,284	(10)			340,819				945,846				14,812,725
Freddie M. Kotek			—	(11)			—				8,094,560				21,703	(12)			303,782				591,116				8,989,458

 

(1)	Pursuant to the terms of the Chevron Merger agreement, 2,112,500 AEI options were cancelled before the effective time of the Chevron Merger and converted into a right to receive the merger consideration less the exercise price, which amount is shown in the “Value from Cash Payout” column.

(2)	Does not include 77,274 units that, pursuant to the terms of the Chevron Merger agreement, were cancelled before the effective time of the Chevron Merger and converted into a right to receive the merger consideration, which amount is shown in the “Value from Cash Payout” column.

(3)	Pursuant to the terms of the Chevron Merger agreement, 145,000 AEI options were cancelled before the effective time of the Chevron Merger and converted into a right to receive the merger consideration less the exercise price, which amount is shown in the “Value from Cash Payout” column.

(4)	Does not include 15,454 units that, pursuant to the terms of the Chevron Merger agreement, were cancelled before the effective time of the Chevron Merger and converted into a right to receive the merger consideration, which amount is shown in the “Value from Cash Payout” column.

(5)	Pursuant to the terms of the Chevron Merger agreement, 47,050 AEI options were cancelled before the effective time of the Chevron Merger and converted into a right to receive the merger consideration less the exercise price, which amount is shown in the “Value from Cash Payout” column.

 

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(6)	Pursuant to the terms of the Chevron Merger agreement, 19,000 AEI options were cancelled before the effective time of the Chevron Merger and converted into a right to receive the merger consideration less the exercise price, which amount is shown in the “Value from Cash Payout” column.

(7)	Pursuant to the terms of the Chevron Merger agreement, 1,322,000 AEI options were cancelled before the effective time of the Chevron Merger and converted into a right to receive the merger consideration less the exercise price, which amount is shown in the “Value from Cash Payout” column.

(8)	Does not include 61,819 units that, pursuant to the terms of the Chevron Merger agreement, were cancelled before the effective time of the Chevron Merger and converted into a right to receive the merger consideration, which amount is shown in the “Value from Cash Payout” column.

(9)	Pursuant to the terms of the Chevron Merger agreement, 518,000 AEI options were cancelled before the effective time of the Chevron Merger and converted into a right to receive the merger consideration less the exercise price, which amount is shown in the “Value from Cash Payout” column.

(10)	Does not include 24,728 units that, pursuant to the terms of the Chevron Merger agreement, were cancelled before the effective time of the Chevron Merger and converted into a right to receive the merger consideration, which amount is shown in the “Value from Cash Payout” column.

(11)	Pursuant to the terms of the Chevron Merger agreement, 323,000 AEI options were cancelled before the effective time of the Chevron Merger and converted into a right to receive the merger consideration less the exercise price, which amount is shown in the “Value from Cash Payout” column.

(12)	Does not include 15,454 units that, pursuant to the terms of the Chevron Merger agreement, were cancelled before the effective time of the Chevron Merger and converted into a right to receive the merger consideration, which amount is shown in the “Value from Cash Payout” column.

2011 Non-Qualified Deferred Compensation

 

Name		Executive Contributions in the Last FY ($)				Registrant Contributions in the Last FY ($)				Aggregate Earnings in the Last FY ($)				Aggregate Balance at Last FYE ($)
Edward E. Cohen			350,000	(1)			350,000	(3)			561				700,561
Jonathan Z. Cohen			250,000	(2)			250,000	(4)			400				500,400

 

(1)	This amount is included within the Summary Compensation Table for 2011 reflecting $70,000 in the salary column and $280,000 in the non-equity incentive plan compensation column.

(2)	This amount is included within the Summary Compensation Table for 2011 reflecting $50,000 in the salary column and $200,000 in the non-equity incentive plan compensation column.

(3)	This amount is included within the Summary Compensation Table for 2011 reflecting our $350,000 matching contribution in the All Other Compensation column.

(4)	This amount is included within the Summary Compensation Table for 2011 reflecting our $250,000 matching contribution in the All Other Compensation column.

Effective July 1, 2011, we established the Excess 401(k) Plan, an unfunded nonqualified deferred compensation plan for certain highly compensated employees. The Excess 401(k) Plan provides Messrs. E. 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 Excess 401(k) Plan. Messrs. E. 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 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. We established a “rabbi” trust to serve as the funding vehicle for the Excess 401(k) 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, our obligation to pay the amounts due under the Excess 401(k) Plan constitutes a general, unsecured obligation, payable out of our general assets, and Messrs. E. and J. Cohen do not have any rights to any specific asset of the company.

The Excess 401(k) 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.

 

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•

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.

2011 Director Compensation Table

 

Name		Fees Earned or Paid in Cash ($)				Stock Awards ($)				All Other Compensation ($)(1)				Total ($)
Carlton M. Arrendell			43,333				49,989	(2)			1,790				95,112
William R. Bagnell			6,667				13,293	(3)			218				20,178
Mark C. Biderman			43,333				49,989	(2)			1,790				95,112
Dennis A. Holtz			47,667				49,989	(2)			1,790				99,445
William Karis			54,333				49,979	(4)			2,993				107,305
Jeffrey C. Key			6,667				—				327				6,994
Harvey Magarick			60,667				49,979	(4)			2,993				113,638
Ellen F. Warren			52,000				49,989	(2)			1,790				103,779

 

(1)	Represents DERs for phantom units.

(2)	For Messrs. Arrendell, Biderman, Holtz and Ms. Warren, represents 3,140 phantom units granted under our Plans, having a grant date fair value of $15.92. The phantom units vest 25% on the anniversary of the date of grant as follows: 2/17/12—785, 2/17/13—785, 2/17/14—785 and 2/17/15—785.

(3)	Represents 835 phantom units as a make-up grant for the underpayment of a 2009 phantom unit grant, having a grant date fair value of $15.92, granted under our 2006 Plan. The phantom units vested on 2/17/11, upon Mr. Bagnell’s departure.

(4)	For Messrs. Karis and Magarick, represents 2,145 phantom units granted under our Plans, having a grant date fair value of $23.30. The phantom units vest 25% on the anniversary of the date of grant as follows: 11/10/12—536, 11/10/13—536, 11/10/14—536 and 11/10/15—536.

Director Compensation

Our general partner does not pay additional remuneration to officers or employees of the Company who also serve as board members. In 2011, the annual retainer for non-employee directors was comprised of an annual retainer of $50,000 in cash and an annual grant of phantom units with DERs issued under our Plans having a fair market value of $50,000. The new non-employee directors received a pro-rated portion of the cash retainer reflecting their mid-February appointment to the board. Chairs of the compensation committee and audit committee receive an additional retainer of $10,000, and chairs of the nominating and governance committee and the investment committee receive an additional retainer of $5,000.

Compensation Committee Report

The compensation committee has reviewed and discussed the Compensation Discussion and Analysis with management and, based upon its review and discussions, the compensation committee recommended to the board of directors that the Compensation Discussion and Analysis be included in this annual report on Form 10-K for the year ended December 31, 2011.

This report has been provided by the compensation committee of the Board of Directors of Atlas Energy GP, LLC.

Ellen F. Warren, Chair

Carlton M. Arrendell

Dennis A. Holtz

 

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ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the number and percentage of common units owned, as of February 22, 2012, 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 2011 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.

 

		Common unit amount and nature of beneficial ownership				Percent of class
Beneficial owner
Directors (1)
Carlton M. Arrendell			3,414				*
Mark C. Biderman			17,112				*
Edward E. Cohen			1,963,222	(2)(4)			3.79	%
Jonathan Z. Cohen			1,540,340	(3)(4)			2.99	%
Dennis A. Holtz			5,752				*
William G. Karis			2,512				*
Harvey G. Magarick			2,813				*
Ellen F. Warren			1,313				*
Non-director principal officers(1)
Eugene N. Dubay			39,534	(4)			*
Freddie M. Kotek			16,651				*
Matthew A. Jones			132,052	(4)			*
Sean P. McGrath			25,479	(4)			*
Jeffrey M. Slotterback			300				*
Lisa Washington			13,581	(4)			*
All executive officers, directors and nominees as a group (14 persons)			2,518,133	(5)			4.83	%
Other owners of more than 5% of outstanding common units
Omega Advisors, Inc./Leon G. Cooperman			3,863,517	(6)			7.53	%
MSDC Management, L.P./MSD Energy Partners, L.P			3,713,497	(7)			7.24	%
Credit Suisse AG			2,722,433	(8)			5.31	%

 

*	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.

(2)

Includes (i) 26,251 common units held in an individual retirement account of Betsy Z. Cohen, Mr. E. Cohen’s spouse, (ii) 1,178,670 common units held by a charitable foundation of which Mr. E. Cohen, his spouse and their children serve as co-trustees; and (iii) 67,272 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. 67,272 and 1,178,670 common units are also included in the common units referred to in footnote 3 below.

(3)

Includes (i) 67,272 common units held in a trust of which Mr. J. Cohen is a co-trustee and co-beneficiary and (ii) 1,178,670 common units held by a charitable foundation of which Mr. J. Cohen, his parents and his sibling serve as co-trustees. These common units are also included in the common units referred to in footnote 2 above. Mr. J. Cohen disclaims beneficial ownership of the above referenced common units.

(4)	Includes common units issuable on exercise of options granted under our Plans in the following amounts: Mr. E. Cohen — 500,000 common units; Mr. J. Cohen — 200,000 common units; Mr. Dubay — 38,614 common units; Mr. Jones — 100,000 common units; Mr. McGrath—15,000; and Ms. Washington—10,000.

(5)	This number has been adjusted to exclude 67,272 common units and 1,178,670 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 Schedule 13G/A filed with the SEC on February 1, 2012. The address for Mr. Cooperman and Omega Advisors, Inc. is 88 Pine Street, Wall Street Plaza, 31st Floor, New York, New York 10005.

(7)	This information is based on a Schedule 13G filed with the SEC on February 14, 2012. The address for MSDC Management, L.P./MSD Energy Partners, L.P. is 645 Fifth Avenue, 21st Floor, New York, New York 10022.

(8)	This information is based on a Schedule 13G filed with the SEC on February 8, 2012. The address for Credit Suisse AG is Uetlibergstrasse 231, P.O. Box 900, CH 8070, Zurich, Switzerland.

 

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Equity Compensation Plan Information

The following table contains information about our 2006 Plan as of December 31, 2011:

 

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 – restricted units

32,641

n/a

Equity compensation plans approved by security holders – options

903,614

$

21.52

Equity compensation plans approved by security holders – Total

936,255

922,871

The following table contains information about our 2010 Plan as of December 31, 2011:

 

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

1,838,164

n/a

Equity compensation plans approved by security holders – unit options

2,304,300

$

22.12

Equity compensation plans approved by security holders – Total

4,142,464

1,157,536

The following table contains information about the APL’s 2004 Plan as of December 31, 2011:

 

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

12,585

n/a

Equity compensation plans approved by security holders – unit options

—

n/a

Equity compensation plans approved by security holders – Total

12,585

66,709

The following table contains information about the APL’s 2010 Plan as of December 31, 2011:

 

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

381,904

n/a

Equity compensation plans approved by security holders – unit options

—

n/a

Equity compensation plans approved by security holders – Total

381,904

2,297,570

 

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ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The board of directors of our general partner has determined that Ms. Warren and Messrs. Arrendell, Biderman, Holtz, Karis and Magarick 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 Partnership Governance Guidelines. In making these determinations, the managing board reviewed information from each of these non-management board members concerning all their respective relationships with us and analyzed the materiality of those relationships.

Effective as of April 30, 2009, our general partner adopted a written policy governing related party transactions. For purposes of this policy, a related party includes: (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. With certain exceptions outlined below, any transaction between us and a related party that is anticipated to exceed $120,000 in any calendar year must be approved, in advance, by the Conflicts Committee of our general partner. If approval in advance is not feasible, the related party transaction must be ratified by the Conflicts Committee. In approving a related party transaction the Conflicts Committee will take into account, in addition to such other factors as the Conflicts Committee deems appropriate, the extent of the related party’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 party transactions are 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); (ii) compensation paid to directors for serving on the board of our general partner or any committee thereof; (iii) transactions where the related party’s interest arises solely as a holder of our common units and such interest is proportional to all other owners of common units or a transaction (e.g. participation in health plans) that are available to all employees generally; (iv) a transaction at another company where the related party 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 $1,000,000 or 2% of that firm’s total annual revenues; and (v) any charitable contribution, grant or endowment by us or our general partner to a charitable organization, foundation or university at which the related party’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 greater of $5,000 or 2% of that organization’s total receipts.

The February 17, 2011 acquisition of the Transferred Business and Laurel Mountain Sale, as described in “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations—Business Overview” and “—Recent Developments,” were components of the overall Chevron Merger. Aside from their interests as AEI stockholders generally, some of the officers of our general partner had material interests in the merger because of employment agreements that they had with AEI and/or because of equity awards they had received. The Chevron Merger constituted a ‘Change in Control’ and termination without cause under the employment agreements, and resulted in cash payments, and accelerated vesting of equity awards granted by us, AEI and APL, to Messrs. E. Cohen, J. Cohen, Dubay and Jones as well as continuation of certain benefits. The merger was also a “change in control” under AEI’s equity compensation plans and resulted in accelerated vesting and cashing-out of vested and unvested awards under the plans, affecting awards granted to Messrs. McGrath, Kalamaras and Kotek and Ms. Washington (in addition to those granted to Messrs. E. Cohen, J. Cohen, Dubay and Jones). In addition, we awarded Messrs. E. Cohen, J. Cohen and Jones cash bonuses shortly after the closing of the Chevron Merger. For more information about amounts paid as a result of the Chevron Merger, see “Item 11. Executive Compensation – Annual and Transaction Incentives” and “— Employment Agreements and Potential Payments Upon Termination or Change of Control.”

 

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Because of the interests in the Chevron Merger transactions set forth above, the Conflicts Committee determined that each of Messrs. E. Cohen, J. Cohen, Dubay and Jones were related persons with respect to them. Accordingly, none of them participated in the approval of the transaction on our or APL’s behalf.

In the ordinary course of our business operations, we and our affiliates have ongoing relationships with several related entities:

Relationship with Drilling Partnerships. We conduct certain activities through, and a substantial portion of our revenues are attributable to, energy limited partnerships. Our wholly-owned subsidiary serves as general partner of these partnerships and assumes customary rights and obligations for them. As the general partner, our subsidiary is liable for the partnerships’ liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the partnerships. Our subsidiary is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the partnerships’ revenue, and costs and expenses according to the respective partnership agreements.

Relationship with Resource America. We have the following agreements with Resource America, the former parent of AEI, for which Edward E. Cohen, our general partner’s Chief Executive Officer and President, serves as Chairman and is a greater than 10% shareholder, and Jonathan Z. Cohen, our Chairman, serves as Chief Executive Officer and President.

Transition Services Agreement

Also in connection with AEI’s initial public offering, it entered into a transition services agreement with Resource America which governs the provision support services between us, such as:

 

•

cash management and debt service administration;

 

•

accounting and tax;

 

•

investor relations;

 

•

payroll and human resources administration;

 

•

legal;

 

•

information technology;

 

•

data processing;

 

•

real estate management; and

 

•

other general administrative functions.

We and Resource America will pay each other a fee for these services equal to their fair market value. The fee is payable monthly in arrears, 15 days after the close of each month. We have also agreed to pay or reimburse each other for any out-of-pocket payments, costs and expenses associated with these services. During fiscal 2011, we reimbursed Resource America $0.8 million pursuant to this agreement. Certain operating expenditures totaling $0.1 million that remain to be settled between are reflected in our consolidated balance sheets as accounts payable.

 

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

For the years ended December 31, 2011 and 2010, the accounting fees and services (in thousands) charged by Grant Thornton, LLP, our independent auditors, were as follows:

 

		Years Ended December 31,
		2011				2010
Audit fees(1)		$	2,286			$	1,674
Audit-related fees(2)			373				—
Tax fees(3)			156				140
All other fees			—				—
Total accounting fees and services		$	2,815			$	1,814

 

(1)

Represents the aggregate fees recognized in each of the last two years for professional services rendered by Grant Thornton LLP principally for the audit of our annual financial statements and the review of financial statements included in Form 10-Qs and also for services related to registration statements and Form 8-Ks. The fees are for services that are normally provided by Grant Thornton LLP in connection with statutory or regulatory filings or engagements.

 

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(2)

Represents the aggregate fees recognized in each of the last two years for professional services rendered by Grant Thornton LLP substantially related to the carve out audits of the historical financial statements of our Production and Partnership Management operating units in connection with its planned spin-off.

(3)	The fees for tax services rendered related to tax compliance.

Audit Committee Pre-Approval Policies and Procedures

The audit committee of our general partner, on at least an annual basis, reviews 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 2011 and 2010.

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.

 

(2)

Financial Statement Schedules

None

 

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(3)

Exhibits:

 

Exhibit No.		Description
2.1		Transaction Agreement, by and among Atlas Energy, Inc., Atlas Energy Resources, LLC, Atlas Pipeline Holdings, L.P. and Atlas Pipeline Holdings GP, LLC, dated November 8, 2010. (11)
2.2		Purchase and Sale Agreement, by and among Atlas Pipeline Partners, L.P., APL Laurel Mountain, LLC, Atlas Energy, Inc., and Atlas Energy Resources, LLC, dated November 8, 2010. (11)
2.3		Employee Matters Agreement, by and among Atlas Energy, Inc., Atlas Pipeline Holdings, L.P. and Atlas Pipeline Holdings GP, LLC, dated November 8, 2010. (11)
2.4		Separation and Distribution Agreement, dated February 23, 2012, by and among Atlas Energy, L.P., Atlas Energy GP, LLC, Atlas Resource Partners, L.P. and Atlas Resource Partners GP, LLC. (The schedules to the Separation and Distribution Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request.) (27)
3.1(a)		Certificate of Limited Partnership of Atlas Pipeline Holdings, L.P.(1)
3.1(b)		Certificate of Amendment of Limited Partnership of Atlas Pipeline Holdings, L.P.(13)
3.1(c)		Amendment to Certificate of Limited Partnership of Atlas Energy, L.P. (5)
3.2(a)		Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Holdings, L.P.(13)
3.2(b)		Amendment No. 1 to Second Amended and Restated Limited Partnership Agreement of Atlas Pipeline Holdings, L.P.(13)
3.2(c)		Amendment No. 2 to Second Amended and Restated Limited Partnership Agreement of Atlas Energy, L.P. (5)
4.1		Specimen Certificate Representing Common Units(1)
10.1		Second Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Holdings GP, LLC. (13)
10.2		Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Partners GP, LLC(1)
10.3(a)		Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(1)
10.3(b)		Amendment No. 2 to Second Amendment and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(4)
10.3(c)		Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6)
10.3(d)		Amendment No. 4 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6)
10.3(e)		Amendment No. 5 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6)
10.3(f)		Amendment No. 6 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(7)
10.3(g)		Amendment No. 7 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(8)
10.3(h)		Amendment No. 8 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(9)
10.3(i)		Amendment No. 9 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(14)
10.4(a)		Long-Term Incentive Plan(6)
10.4(b)		Amendment No. 1 to Long-Term Incentive Plan(15)

 

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Exhibit No.		Description
10.5		2010 Long-Term Incentive Plan(16)
10.6		Form of Phantom Unit Grant under 2010 Long-Term Incentive Plan
10.7		Form of Stock Option Grant under 2010 Long-Term Incentive Plan
10.8(a)		Amended and Restated Credit Agreement, dated July 27, 2007, amended and restated as of December 22, 2010, among Atlas Pipeline Partners, L.P., the guarantors therein, Wells Fargo Bank, National Association, and other banks party thereto(23)
10.8(b)		Amendment No. 1 to the Amended and Restated Credit Agreement, dated as of April 19, 2011 (25)
10.8(c)		Incremental Joinder Agreement to the Amended and Restated Credit Agreement, dated as of July 8, 2011 (26)
10.9		Pennsylvania Operating Services Agreement dated as of February 17, 2011 between Atlas Energy, Inc., Atlas Pipeline Holdings, L.P. and Atlas Resources, LLC. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.(12)
10.10		Petro-Technical Services Agreement, dated as of February 17, 2011 between Atlas Energy, Inc. and Atlas Pipeline Holdings, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission. (12)
10.11(a)		Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission. (12)
10.11(b)		Amendment No. 1 to the Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated as of January 6, 2011. (12)
10.11(c)		Amendment No. 2 to the Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated as of February 2, 2011. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission. (12)
10.12		Transaction Confirmation, Supply Contract No. 0001, under Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated February 17, 2011. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission. (12)
10.13		Gas Gathering Agreement for Natural Gas on the Legacy Appalachian System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble, LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.(12)
10.14		Gas Gathering Agreement for Natural Gas on the Expansion Appalachian System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble, LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.(12)

 

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Exhibit No.		Description
10.15		Employment Agreement between Atlas Energy, L.P. and Edward E. Cohen dated as of May 13, 2011(12)
10.16		Employment Agreement between Atlas Energy, L.P. and Jonathan Z. Cohen dated as of May 13, 2011(12)
10.17		Employment Agreement between Atlas Energy, L.P. and Eugene N. Dubay dated as of November 4, 2011(21)
10.18		Employment Agreement between Atlas Energy, L.P. and Matthew A. Jones dated as of November 4, 2011
10.19		Form of Grant of Phantom Units to Non-Employee Managers (20)
10.20		Letter Agreement, by and between Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P., dated November 8, 2010(21)
10.21		Non-Competition and Non-Solicitation Agreement, by and between Chevron Corporation and Edward E. Cohen, dated as of November 8, 2010(22)
10.22		Non-Competition and Non-Solicitation Agreement, by and between Chevron Corporation and Jonathan Z. Cohen, dated as of November 8, 2010(22)
10.23		Credit Agreement, dated as of March 22, 2011, among Atlas Energy, L.P. as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto(24)
21.1		Subsidiaries of Registrant
23.1		Consent of Grant Thornton LLP
23.2		Consent of Wright & Company, Inc.
31.1		Rule 13(a)-14(a)/15(d)-14(a) Certification
31.2		Rule 13(a)-14(a)/14(d)-14(a) Certification
32.1		Section 1350 Certification
32.2		Section 1350 Certification
99.1		Summary Reserve Report

 

(1)	Previously filed as an exhibit to the registration statement on Form S-1 (File No. 333-130999).

(2)	[Intentionally omitted]

(3)	[Intentionally omitted]

(4)	Previously filed as an exhibit to current report on Form 8-K filed July 30, 2007.

(5)	Previously filed as an exhibit to current report on Form 8-K filed December 13, 2011.

(6)	Previously filed as an exhibit to annual report on Form 10-K for the year ended December 31, 2008.

(7)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended March 31, 2009.

 

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(8)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on April 2, 2010.

(9)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on July 7, 2010.

(10)	Previously filed as an exhibit to current report on Form 8-K filed June 1, 2009.

(11)	Previously filed as an exhibit to current report on Form 8-K filed November 12, 2010.

(12)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended March 31, 2011.

(13)	Previously filed as an exhibit to current report on Form 8-K filed on February 24, 2011.

(14)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on December 13, 2011.

(15)	Previously filed as an exhibit to annual report on Form 10-K for the year ended December 31, 2010.

(16)	Previously filed as an exhibit to current report on Form 8-K filed on November 12, 2010.

(17)	[Intentionally omitted]

(18)	[Intentionally omitted]

(19)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on September 1, 2010.

(20)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended September 30, 2010.

(21)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended September 30, 2011.

(22)	Previously filed as an exhibit to Atlas Energy, Inc.’s current report on Form 8-K filed on November 12, 2010.

(23)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on December 23, 2010.

(24)	Previously filed as an exhibit to current report on Form 8-K filed on March 25, 2011.

(25)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended March 31, 2011.

(26)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on July 11, 2011.

(27)	Previously filed as an exhibit to current report on Form 8-K filed on February 24, 2012.

 

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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.

 

				ATLAS ENERGY, L.P.
				By: Atlas Energy GP, LLC, its General Partner
Date: February 28, 2012				By:		/s/ EDWARD E. COHEN
						Edward E. Cohen Chief Executive Officer and President

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 February 28, 2012.

 

/s/ EDWARD E. COHEN		Chief Executive Officer, President and Director of the General Partner
Edward E. Cohen
/s/ JONATHAN Z. COHEN		Chairman of the Board of the General Partner
Jonathan Z. Cohen
/s/ SEAN P. MCGRATH		Chief Financial Officer of the General Partner
Sean P. McGrath
/s/ JEFFREY M. SLOTTERBACK		Chief Accounting Officer
Jeffrey M. Slotterback
/s/ CARLTON M. ARRENDELL		Director of the General Partner
Carlton M. Arrendell
/s/ MARK C. BIDERMAN		Director of the General Partner
Mark C. Biderman
/s/ DENNIS A. HOLTZ		Director of the General Partner
Dennis A. Holtz
/s/ WILLIAM G. KARIS		Director of the General Partner
William G. Karis
/s/ HARVEY G. MAGARICK		Director of the General Partner
Harvey G. Magarick
/s/ ELLEN F. WARREN		Director of the General Partner
Ellen F. Warren

 

167