Targa Energy LP - FORM 10-K - February 25, 2011

Attached files

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

file	filename
EX-23.1 - CONSENT OF GRANT THORNTON LLP - Targa Energy LP	dex231.htm
EX-31.1 - SECTION 302 CEO CERTIFICATION - Targa Energy LP	dex311.htm
EX-31.2 - SECTION 302 CFO CERTIFICATION - Targa Energy LP	dex312.htm
EX-32.1 - SECTION 906 CEO CERTIFICATION - Targa Energy LP	dex321.htm
EX-32.2 - SECTION 906 CFO CERTIFICATION - Targa Energy LP	dex322.htm
EX-10.6(B) - AMENDMENT NO. 1 TO LONG-TERM INCENTIVE PLAN - Targa Energy LP	dex106b.htm
EX-21.1 - SUBSIDIARIES OF REGISTRANT - Targa Energy LP	dex211.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2010

¨	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: 1-32953

ATLAS ENERGY, L.P.

(Exact name of registrant as specified in its charter)


DELAWARE		43-2094238
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1550 Coraopolis Heights Road Moon Township, Pennsylvania		15108
(Address of principal executive office)		(Zip code)

Registrant’s telephone number, including area code: (412) 262-2830

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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

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

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

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

The aggregate market value of the equity securities held by non-affiliates of the registrant, based upon the closing price of $3.99 per common limited partner unit on June 30, 2010, was approximately $38.5 million.

The number of common units of the registrant outstanding on February 22, 2011 was 51,214,638.

DOCUMENTS INCORPORATED BY REFERENCE:

None

ATLAS ENERGY, L.P. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K


			Page
PART I

	Item 1:	Business		7
	Item 1A:	Risk Factors		30
	Item 1B:	Unresolved Staff Comments		65
	Item 2:	Properties		65
	Item 3:	Legal Proceedings		65
	Item 4:	[Removed and reserved]		65

PART II

	Item 5:	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities		66
	Item 6:	Selected Financial Data		68
	Item 7:	Management’s Discussion and Analysis of Financial Condition and Results of Operations		73
	Item 7A:	Quantitative and Qualitative Disclosures About Market Risk		100
	Item 8:	Financial Statements and Supplementary Data		102
	Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		151
	Item 9A:	Controls and Procedures		151
	Item 9B:	Other Information		154

PART III

	Item 10:	Directors, Executive Officers and Corporate Governance		155
	Item 11:	Executive Compensation		163
	Item 12:	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		180
	Item 13:	Certain Relationships and Related Transactions, and Director Independence		185
	Item 14:	Principal Accountant Fees and Services		187

PART IV

	Item 15:	Exhibits and Financial Statement Schedules		188

SIGNATURES				190

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:

•

the demand for natural gas and natural gas liquids;

•

the price volatility of natural gas and natural gas liquids;

•

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

•

our ability to operate the assets we recently acquired from Atlas Energy, Inc., which we refer to as the asset acquisition, and the costs of such operation;

•

our ability to operate without Atlas Energy, Inc., as our majority unitholder;

•

changes in the market price of our common units;

•

future financial and operating results;

•

resource potential;

•

realized natural gas and oil prices;

•

economic conditions and instability in the financial markets;

•

success in efficiently developing and exploiting the reserves we acquired in the asset acquisition and economically finding or acquiring additional recoverable reserves;

•

the accuracy of estimated natural gas and oil reserves;

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the financial and accounting impact of hedging transactions;

•

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, dispositions or similar transactions;

•

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

•

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

•

our lack of experience in drilling natural gas wells and the limited information available regarding reserves and decline rates in certain areas in which the assets acquired in the asset acquisition are located;

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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;

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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;

•

the potential introduction of Pennsylvania severance taxes;

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

•

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

•

general market, labor and economic conditions and related uncertainties;

•

the ability to retain certain key customers, including customers of the businesses acquired in the asset acquisition;

•

dependence on the gathering and transportation facilities of third parties, including Laurel Mountain;

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the availability of drilling rigs, equipment and crews;

•

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

•

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

•

expirations of undeveloped leasehold acreage;

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uncertainty regarding leasing operating expenses, general and administrative expenses and funding 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;

•

exposure to new and existing litigation;

•

risks of the business of APL to which we are exposed through our ownership interests in APL;

•

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

•

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.

Glossary of Terms

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


Bbl		Barrel - measurement for a standard US barrel is 42 gallons. Crude oil and condensate are generally reported in barrels.
BPD		Barrels per day
BTU		British thermal unit, a basic measure of heat energy
Condensate		Liquid hydrocarbons present in casinghead gas that condense within the gathering system and are removed prior to delivery to the gas plant. This product is generally sold on terms more closely tied to crude oil pricing.
Distributable Cash Flow (“DCF”)		Net income plus depreciation, amortization, other non-cash expenses and maintenance capital expenditures. Used to determine the amount of cash flow available to distribute to units holders.
EBITDA		Net income (loss) before net interest expense, income taxes, and depreciation and amortization. EBITDA is considered to be a non-GAAP measurement.
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
Fractionation		The process used to separate an NGL stream into its individual components.
GAAP		Generally Accepted Accounting Principles
G.P.		General Partner or General Partnership
Keep-Whole		Contract with producer whereby plant operator pays for or returns an equivalent BTU of the gas received at the well-head.
L.P.		Limited Partner or Limited Partnership
MCF		Thousand cubic feet
MCFD		Thousand cubic feet per day
MMBTU		Million British thermal units
MMCFD		Million cubic feet per day
NGL(s)		Natural Gas Liquid(s), primarily ethane, propane, normal butane, isobutane and natural gasoline
Percentage of Proceeds (“POP”)		Contract with natural gas producers whereby the plant operator retains a negotiated percentage of the sale proceeds.
PV-10		Present value of future pre-tax net revenues. See “standardized measure”.
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 of discounted future net cash flows relating to proved oil and gas reserve quantities, is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using constant prices and costs) 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.
Y-grade		A term utilized in the industry for the NGL stream prior to fractionation, also referred to as “raw mix.”

PART I

ITEM 1.

BUSINESS

Atlas Energy, L.P.

As of December 31, 2010, our cash generating assets consisted solely of our interests in APL. APL is a leading provider of natural gas gathering, processing and treating services in the Mid-Continent and Appalachia regions. Our interests in APL consist of a 100% ownership in Atlas Pipeline GP, its general partner, which together with us owned at December 31, 2010:

•

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

•

all of the incentive distribution rights in APL, which entitle it 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 adjusted as follows; and

•

In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see “—Atlas Pipeline Partners, L.P.”), Atlas Pipeline GP agreed to allocate up to $3.75 million of its incentive distribution rights per quarter back to APL after Atlas Pipeline GP receives the initial $7.0 million per quarter of incentive distribution rights (the “IDR Adjustment Agreement”);

•

5,754,253 common units of APL, representing approximately 10.8% of the outstanding common units of APL, or a 10.6% limited partner interest in APL.

While we, like APL, are structured as a limited partnership, our capital structure and cash distribution policy differ materially from those of APL. Most notably, our general partner, Atlas Pipeline Holdings GP, LLC (“Atlas Pipeline Holdings GP”) does not have an economic interest in us and is not entitled to receive any distributions from us, and our capital structure does not include incentive distribution rights. Therefore, all of our distributions are made on our common units, which is our only class of security outstanding.

Atlas Energy, Inc. (“Atlas Energy, Inc.” or “ATLS”), a formerly publicly-traded company, owned 64.0% of our common units and also had a direct 2.1% interest in APL plus 8,000 $1,000 par value 12% APL Class C cumulative preferred limited partner units at December 31, 2010.

Atlas Pipeline GP’s ownership of APL’s incentive distribution rights entitles it to receive an increasing percentage of cash distributed by APL as it reaches certain target distribution levels. The rights entitle Atlas Pipeline GP, subject to the IDR Adjustment Agreement, to receive the following:

•

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.

These amounts are partially offset by the IDR Adjustment Agreement.

We pay our unitholders, on a quarterly basis, distributions equal to the cash we received from APL and operations, less certain reserves for expenses and other uses of cash, including:

•

our general and administrative expenses, including expenses as a result of being a publicly traded partnership;

•

capital contributions to maintain or increase our ownership interest in APL; and

•

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

The following chart displays the corporate organizational structure as of December 31, 2010:

LOGO

Recent Developments

Atlas Energy, Inc. Asset Acquisition

On February 17, 2011, we completed the transactions, which we refer to as the “Asset Acquisition,” contemplated by our transaction agreement (the “AHD Transaction Agreement”), dated November 8, 2010, with ATLS and Atlas Energy Resources, LLC, a wholly-owned subsidiary of ATLS, pursuant to which we purchased from ATLS (1) its investment partnership business, including the operations of its investment partnerships in Michigan, Pennsylvania, Tennessee, Indiana and Colorado, (2) its oil and gas exploration, development and production activities conducted in Tennessee, Indiana and Colorado, certain shallow wells and leases in New York and Ohio and certain well interests in Pennsylvania, and (3) its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (we refer to the businesses described in (1) through (3), together, as the “transferred business”). The assets we purchased include certain ATLS subsidiaries (referred to as the “purchased entities”) and certain other assets relating to the transferred business, including the names and marks of ATLS and its subsidiaries (which we refer to as the “purchased assets”). ATLS also transferred certain current liabilities that were assumed by us in the Asset Acquisition, of which certain amounts are subject to post-closing.

As consideration for the Asset Acquisition, we paid to ATLS $30 million in cash, issued to it 23,379,384 new common units, and assumed all of the historical and future liabilities associated with the transferred business. In addition, we repaid the $36.0 million outstanding under our amended and consolidated note owed to ATLS.

In connection with the Asset Acquisition, ATLS contributed our general partner, Atlas Pipeline Holdings GP, LLC to us, so that Atlas Pipeline Holdings GP became our wholly-owned subsidiary, our limited partnership agreement was amended and restated, and our new long-term equity incentive plan for employees became effective. ATLS distributed to its stockholders all our common units that it held, including the newly issued common units that it received in the Asset Acquisition. As a result, ATLS no longer owns any of our common units. We refer to all of these transactions, along with the Asset Acquisition, as the “AHD Transactions.”

New Credit Facility

We financed the cash portion of Asset Acquisition consideration and the repayment of the ATLS note by drawing on a $70 million revolving credit facility, administered by Citibank, N.A., that we entered into at closing of the Asset Acquisition. Our credit facility matures in February 2012 and bears interest, at our option, at either (i) adjusted LIBOR (plus the applicable margin, as defined in the credit facility) or (ii) the higher of the federal funds rate plus 0.5% or the Citibank, N.A. prime rate (each plus the applicable margin). Borrowings under our credit facility are secured by a first-priority lien on a security interest in substantially all of our assets, including a pledge of 3,500,000 of our APL common units, and are guaranteed by Atlas Pipeline Holdings GP and our operating other subsidiaries (excluding Atlas Pipeline GP and APL and its subsidiaries). Our credit facility contains customary covenants, including restrictions on our ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to our unitholders if an event of default exists or would result from such distribution; or enter into a merger or sale of substantially all of our property or assets, including the sale or transfer of interests in our subsidiaries; and requirements that we maintain certain financial ratios. The events which constitute an event of default under our 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 us in excess of a specified amount, and a change of control. We may borrow under our credit facility for working capital and general business purposes.

Laurel Mountain Sale

Concurrently with our completion of the Asset Acquisition, APL completed its sale to Atlas Energy Resources of its 49% non-controlling interest in Laurel Mountain (the “Laurel Mountain Sale”) for $413.5 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.

Atlas Energy, Inc. Merger

Concurrently with our completion of the Asset Acquisition and APL’s completion of the Laurel Mountain Sale, ATLS completed its merger transaction with Chevron Corporation (“Chevron”), pursuant to which, among other things, ATLS became a wholly-owned subsidiary of Chevron (the “Chevron Merger”). The APL common units and 12% cumulative Class C preferred units held directly by ATLS were acquired by Chevron as part of the Chevron Merger.

Atlas Pipeline Holdings, L.P. Name Change

On February 18, 2011, subsequent to the Asset Acquisition and the Chevron Merger, we changed our name to Atlas Energy, L.P.

The following chart displays the corporate organizational structure subsequent to the AHD Transactions and related developments described above:

LOGO

Services Agreements

Concurrently with entering into the AHD Transaction Agreement, we entered into several services agreements with ATLS to allow for the continuation and transition of operations after closing. The following summarizes each of those agreements.

Transition Services Agreement. We entered into a transition services agreement with ATLS pursuant to which (1) ATLS will provide us a limited license to use certain of its facilities and (2) ATLS and we will provide each other certain services on a transitional basis including, among others, services related to operations, accounting, supply chain management, finance, human resources and information technology (the “Transition Services Agreement”). The recipient of each service listed in the Transition Services Agreement will be obligated to pay a fee specified in the Transition Services Agreement. Each service will be provided until the earlier of (1) the term specified for that service in the Transition Services Agreement, (2) two years from the closing of the AHD Transactions, (3) the termination of the Transition Services Agreement by ATLS or us following an uncured material breach by the other party or (4) the termination of the service by the recipient of the service (except that a recipient of any terminated service must continue to pay the relevant fee for that service for the remainder of the term specified in the transition services agreement). ATLS and we may request that the other party provide additional or different services, and the parties may negotiate the terms of the new service, although neither party has an obligation to provide any additional or different service.

The recipient of each service will generally assume the risks and liability arising in connection with its use of the service. The provider and recipient of each service will indemnify each other for any losses incurred in connection with the use of the service by the recipient, unless the loss is due to the provider’s gross negligence or willful misconduct.

Michigan Operating Agreement. We entered into an Operating Services Agreement (the “Michigan Operating Agreement”) with ATLS and Atlas Resources, LLC (“Resources”), a purchased entity, pursuant to which ATLS will provide Resources and us and our respective subsidiaries certain operational services including, among others, the superintendence and maintenance of wells in certain counties in Michigan and Indiana and the marketing and gathering of gas produced from those wells (the “Michigan Operational Services”). ATLS will also provide certain environmental project management services to us on a transitional basis (the “Michigan Environmental Services”). Resources, we or our subsidiaries are obligated to pay the fees specified in the Michigan Operating Agreement for the Michigan Operational Services and the Michigan Environmental Services. We may request that ATLS provide additional services under the Michigan Operating Agreement on a transitional basis, and we must negotiate in good faith regarding any such additional service, except that ATLS will not be obligated to provide any additional services if the provision of such service would be impracticable or would not be commercially reasonable, or if it is not of a type being provided by ATLS or its affiliates as of immediately prior to the closing of the AHD Transactions.

We will indemnify ATLS against all claims and liabilities arising out of its provision of services under the Michigan Operating Agreement.

ATLS will provide the Michigan Operational Services for three years from the closing date of the AHD Transactions and from month-to-month thereafter until cancelled by ATLS, Resources or us. ATLS will provide the Michigan Environmental Services for six months from the closing of the AHD Transactions and from month-to-month thereafter for an additional eighteen months. We may terminate any part of the Michigan Operational Services and the Michigan Environmental Services at any time. ATLS, Resources and we may agree to terminate the Michigan Operating Agreement at any time, and each of ATLS, on the one hand, or Resources or we, on the other hand, may terminate the Michigan Operating Agreement following an uncured material breach by such other party.

Pennsylvania Operating Agreement. We entered into an operating services agreement with ATLS and Resources (the “Pennsylvania Operating Agreement”), pursuant to which ATLS will provide Resources, us and

our respective subsidiaries certain operational services including, among others, gas volumetric control, measurement and balancing services and water disposal services with respect to certain wells in Pennsylvania ( the “Pennsylvania Services”). Resources, we or our subsidiaries are obligated to pay the fees specified in the Pennsylvania Operating Agreement for the Pennsylvania Services.

We will indemnify ATLS against all claims and liabilities arising out of its provision of services under the Pennsylvania Operating Agreement.

ATLS will provide the Pennsylvania Services for three years from the closing date of the AHD Transactions and from month-to-month thereafter until cancelled by ATLS, Resources or us. We may terminate any part of the Pennsylvania Services or terminate the Pennsylvania Operating Agreement at any time. ATLS, Resources and we may agree to terminate the Pennsylvania Operating Services Agreement at any time, and each of ATLS, on the one hand, or Resources or we, on the other hand, may terminate the Pennsylvania Operating Agreement following an uncured material breach by such other party.

Petro-Technical Services Agreement. We entered into a petro-technical services agreement with ATLS (the “Petro-Technical Services Agreement”), pursuant to which ATLS will perform for us certain consulting activities including, among others, planning, designing, drilling, stimulating, completing and equipping wells (the “Petro-Technical Services”). We are obligated to pay the actual costs incurred by ATLS in the performance of the Petro-Technical services, up to a maximum of the market rate for the same or similar services in Pittsburgh, Pennsylvania and Traverse City, Michigan.

We will indemnify ATLS against all claims and liabilities arising out of its provision of services under the Petro-Technical Services Agreement.

ATLS will provide the Petro-Technical Services for one year from the closing date of the AHD Transactions and from month-to-month thereafter until the earlier of (1) cancellation by ATLS, Resources or us; or (2) eighteen months after the closing date of the AHD Transactions. We may terminate any part of the Petro-Technical Services or terminate the Petro-Technical Services Agreement at any time. ATLS, Resources and we may agree to terminate the Petro-Technical Services Agreement at any time, and each of ATLS, on the one hand, or Resources or we, on the other hand, may terminate the Petro-Technical Services Agreement following an uncured material breach by such other party.

Gas Marketing Agreement. Certain of the purchased entities entered into a base contract for the sale and purchase of natural gas with a subsidiary of Chevron (which we refer to as the “Gas Marketing Agreement”) pursuant to which, following the closing of the AHD Transactions and the Chevron merger, the purchased entities will sell gas to the subsidiary of Chevron. Under the Gas Marketing Agreement, the subsidiaries are responsible for transporting the gas to specified delivery points, at which points the subsidiary of Chevron will assume responsibility for the purchased gas. The Gas Marketing Agreement will terminate upon the expiration of the latest period for which the parties have agreed to make deliveries or upon 30 days’ written notice of any party to the gas marketing agreement.

Employee Matters Agreement. We entered into an employee matters agreement with ATLS, pursuant to which certain current employees of ATLS will be transferred to us in connection with the AHD Transactions, and we will assume certain pre-closing liabilities attributable to such transferred employees. We will be required to establish benefit plans for such transferred employees, including a 401(k) plan and health and welfare benefit plans, as of the closing date for the AHD Transactions. Effective as of the closing date for the AHD Transactions, we will adopt the new equity plan, under which awards of options to purchase our common units, restricted units and phantom units may be granted to our employees, directors and other service providers. Pursuant to the employee matters agreement, we will also amend our long-term incentive plan to provide that outstanding awards granted under the plan will not vest in connection with the Chevron merger and the AHD transactions pursuant to the terms and conditions of the plan.

The remainder of this “Business” section discusses our business as it existed on December 31, 2010, without giving effect to the Asset Acquisition.

Atlas Pipeline Partners, L.P.

General

APL is a publicly-traded Delaware limited partnership formed in 1999 whose common units are listed on the New York Stock Exchange under the symbol “APL.” 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 and a provider of natural gas gathering services in the Appalachian Basin in the northeastern region of the United States. APL’s business is conducted in the midstream segment of the natural gas industry through two reportable segments: Mid-Continent and Appalachia.

In APL’s Mid-Continent operations, it owns and operates five natural gas processing plants with aggregate capacity of approximately 520 MMCFD. These facilities are connected to approximately 8,600 miles of active natural gas gathering systems located in Oklahoma, Kansas and Texas, which gathers gas from wells and central delivery points and delivers the natural gas to APL’s processing and treating plants, as well as third-party pipelines.

The Appalachia operations of APL are conducted principally through its 49% non-controlling ownership interest in the Laurel Mountain Midstream, LLC joint venture (“Laurel Mountain”), which owns and operates approximately 1,000 miles of natural gas gathering systems in the Appalachian Basin located in Pennsylvania. APL also owns and operates approximately 70 miles of active natural gas gathering pipelines located in Tennessee.

APL’s operations are all located in or near areas of abundant and long-lived natural gas production including the; Golden Trend; Woodford Shale; Hugoton field in the Anadarko basin; the Spraberry Trend, which is an oil play with associated natural gas in the Permian Basin and the Marcellus Shale in the Appalachian Basin. APL’s Mid-Continent gathering systems are connected to approximately 7,700 central delivery points or wells. In Appalachia, Laurel Mountain’s systems are connected to approximately 4,700 wells. Thus we believe APL has significant scale in its service areas. APL provides gathering and processing services to the wells connected to its systems, primarily under long-term contracts. As a result of the location and capacity of APL’s gathering and processing assets, APL management believes it is strategically positioned to capitalize on the drilling activity in its service areas. APL intends to continue to expand its business through strategic acquisitions and internal growth projects in efforts to increase distributable cash flow.

Laurel Mountain gathers the majority of the natural gas from wells operated by Atlas Energy Resources and its subsidiaries. Laurel Mountain has gas gathering agreements with Atlas Energy Resources under which Atlas Energy Resources is obligated to pay a gathering fee that is generally the greater of $0.35 per MCF or 16% of the realized sales price (except that a lower fee applies with respect to specific wells subject to certain existing contracts or in the event Laurel Mountain fails to perform specified obligations).

In July 2007, APL acquired control of Anadarko Petroleum Corporation’s (“Anadarko” – NYSE: APC) 100% interest in the Chaney Dell natural gas gathering systems and processing plants located in Oklahoma and its 72.8% undivided joint venture interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas.

APL’s Business Strategy

The primary business objective of APL’s management team is to provide stable long-term cash distributions to its unitholders. APL’s business strategies focus on creating value for its unitholders by providing efficient operations, focusing on prudent growth opportunities via organic growth projects and external acquisitions, and maintaining a commodity risk management program in an attempt to manage our commodity price exposure. APL intends to accomplish its primary business objectives by executing on the following:

•

Increasing the profitability of APL’s existing assets. In many cases, APL can expand gathering pipelines and processing plants and may have excess capacity, which provides it with opportunities to connect and process new supplies of natural gas with minimal additional capital requirements, also increasing plant efficiency and economics. APL plans to accomplish this goal by providing excellent service to its existing customers, aggressively marketing its services to new customers and prudently expanding its existing infrastructure to ensure its services can meet the needs of potential customers. APL’s recent construction of its Consolidator Plant in West Texas is an example of executing this strategy. Other opportunities include pursuing relationships with new producers, the elimination of pipeline bottlenecks, reducing operating line pressures and focusing on a reduction of pipeline losses along its gathering systems.

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Expanding operations through organic growth projects and pursuing strategic acquisitions. APL continues to explore opportunities to expand its existing infrastructure. APL also plans to pursue strategic acquisitions that are accretive to its unitholders, by seeking acquisition opportunities that leverage its existing asset base, employees and existing customer relationships. In the past, APL has pursued opportunities in certain regions outside of its current areas of operation and will continue to do so when these options make sense economically and strategically.

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Reducing the sensitivity of APL’s cash flows through prudent economic risk management and contract arrangements. APL attempts to structure its contracts in a manner that allows it to achieve its target rate of return goals while reducing its exposure to commodity price movements. APL actively reviews its contract mix and seeks to optimize a balance of cash flow stability with attractive economic returns. APL’s commodity risk management activities are designed to reduce the effect of commodity price volatility related to future sales of natural gas, NGLs and crude oil, while allowing APL to meet its debt service requirements, fund its maintenance capital program and meet its distribution objectives.

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Maintaining APL’s financial flexibility. APL intends to maintain a capital structure in which it does not significantly exceed equal amounts of debt and equity on a long-term basis, while not jeopardizing its ability to achieve its other business strategies. APL believes that its revolving credit facility, its ability to issue additional long-term debt or partnership units and its relationships with its partners provide APL with the ability to achieve this strategy. APL will also consider alternative financing, joint venture arrangements and other means that allow it to achieve its business strategies while continuing to maintain an acceptable capital structure.

The Midstream Natural Gas Gathering and Processing Industry

The midstream natural gas gathering and processing industry is characterized by regional competition based on the proximity of gathering systems and processing plants to producing natural gas wells.

The natural gas gathering process begins with the drilling of wells into natural gas or oil bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems generally consist of a network of pipelines that collect natural gas from points near producing wells and transport gas and other associated products to processing plants for processing and treating and to larger

pipelines for further transportation to end-user markets. Gathering systems are operated at design pressures via pipe size and compression that will maximize the total throughput from all connected wells.

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While natural gas produced in some areas does not require treatment or processing, natural gas produced in many other areas, such as APL’s Chaney Dell, Midkiff/Benedum and Velma operations in the Mid-Continent, are not suitable for long-haul pipeline transportation or commercial use and must be compressed, gathered via pipeline to a central processing facility, potentially treated and then processed to remove certain hydrocarbon components such as NGLs and other contaminants that would interfere with pipeline transportation or the end use of the natural gas. Natural gas processing plants generally treat (remove carbon dioxide and hydrogen sulfide) and extract the NGLs, enabling the treated, “dry” gas (low BTU content) to meet pipeline specification for long-haul transport to end users. After being separated from natural gas at the processing plant, the mixed NGL stream, commonly referred to as “y-grade” or “raw mix,” is typically transported in pipelines to a centralized facility for fractionation into discrete NGL purity products: ethane, propane, normal butane, isobutane, and natural gasoline.

Natural gas transportation pipelines receive natural gas from producers, other mainline transportation pipelines, shippers and gathering systems through system interconnects and redeliver the natural gas to processing facilities, local gas distribution companies, industrial end-users, utilities and other pipelines. Generally natural gas transportation agreements generate revenue for these systems based on a fee per unit of volume transported.

Contracts and Customer Relationships

APL’s principal revenue is generated from the gathering, processing and sale of natural gas, NGLs and condensate. Primary contracts are Fee-Based, Percentage of Proceeds (“POP”) and Keep-Whole (see “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual Revenue Arrangements”).

APL’s Mid-Continent Operations

APL owns and operates approximately 8,600 miles of intrastate natural gas gathering systems located in Oklahoma, Kansas, and Texas. APL also owns and operates five processing plants located in Oklahoma and Texas. APL’s gathering, processing and treating assets service long-lived natural gas regions, including the Permian and Anadarko Basins. APL’s systems gather natural gas from oil and natural gas wells and process the raw natural gas into residue gas by extracting NGLs and removing impurities. In the aggregate, APL’s Mid-Continent systems have approximately 7,700 receipt points, consisting primarily of individual well connections and, secondarily, central delivery points which are linked to multiple wells. APL’s gathering systems interconnect with interstate and intrastate pipelines operated by El Paso Natural Gas Company; Enogex LLC; Kinder Morgan Texas Pipeline; Natural Gas Pipeline Company of America; Northern Natural Gas Company;

ONEOK Gas Transportation, LLC; Panhandle Eastern Pipe Line Company, LP; and Southern Star Central Gas Pipeline, Inc. APL’s processing facilities are connected to NGL pipelines operated by ONEOK Hydrocarbon, L.P.

Mid-Continent Overview

APL considers the Mid-Continent region as running from Kansas through Oklahoma and Texas, branching into Louisiana, as well as southeastern New Mexico and western Arkansas (see the highlighted area of the map below). Two of the primary producing areas in the region include the Anadarko Basin and the Permian Basin, which is where APL’s Mid-Continent systems are located.

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Mid-Continent Gathering Systems

Chaney Dell. The Chaney Dell gathering system is located in north central Oklahoma and southern Kansas’ Anadarko Basin. As of December 31, 2010, the gathering systems had approximately 4,300 miles of active natural gas gathering pipelines with approximately 4,300 receipt points. The primary producers on the Chaney Dell gathering system include certain subsidiaries of Chesapeake Energy Corporation; Sandridge Exploration and Production, LLC; and Bluestem Marketing, LLC.

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Midkiff/Benedum. The Midkiff/Benedum gathering system, which APL operates and in which APL has an approximate 72.8% ownership, as of December 31, 2010, had approximately 3,100 miles of active natural gas gathering pipelines and approximately 2,800 receipt points located across seven counties within the Permian Basin in West Texas. Pioneer Natural Resources Company (NYSE: PXD) (“Pioneer”), the largest active driller in the Spraberry Trend and a major producer in the Permian Basin, owns the remaining interest in the Midkiff/Benedum system. The primary producers on the Midkiff/Benedum gathering system include Pioneer; COG Operating, LLC; and Endeavor Energy Resources, LP.

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Velma. The Velma gathering system is located in the Golden Trend and near the Woodford Shale areas of southern Oklahoma. As of December 31, 2010, the gathering system had approximately 1,200 miles of active pipelines with approximately 600 receipt points consisting primarily of individual well connections and, secondarily, central delivery points which are linked to multiple wells. The primary producers on the Velma gathering system include certain subsidiaries of Chesapeake Energy Corporation; Range Resources; and XTO Energy, Inc.

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Mid-Continent Processing and Treating Plants

Chaney Dell. The Chaney Dell system processes natural gas through the Waynoka and Chester plants, which are active cryogenic natural gas processing facilities. The Chaney Dell system’s processing operations have total capacity of approximately 228 MMCFD. The Waynoka processing plant, located in Woods County, Oklahoma began operations in December 2006 and became fully operational in July 2007. The Chaney Dell plant located in Major County is inactive. APL transports and sells natural gas to parties, including various marketing companies and pipelines, at the tailgate of the Waynoka and Chester plants and sells NGL production to ONEOK Hydrocarbon, L.P.

Midkiff/Benedum. The Midkiff/Benedum system processes natural gas through the Consolidator (located at Midkiff) and Benedum processing plants. The Consolidator plant is a 150 MMCFD cryogenic facility in Reagan County, Texas. The facility started operations in November 2009 and replaced the Midkiff plant. The Midkiff plant is currently inactive. The Benedum plant is a 45 MMCFD cryogenic facility in Upton County, Texas. APL’s Consolidator/Benedum processing operations have an aggregate processing capacity of approximately 195 MMCFD. APL transports and sells natural gas to parties, including various marketing companies and pipelines, at the tailgate of the Consolidator/Benedum plants and sells NGL production to ONEOK Hydrocarbon, L.P.

Velma. The Velma processing plant, located in Stephens County, Oklahoma, is a cryogenic facility with a natural gas capacity of approximately 100 MMCFD. The Velma plant is one of only two facilities in the area that is capable of treating both high-content hydrogen sulfide and carbon dioxide gases which are characteristic in this area. APL has made capital expenditures at the facility to improve its efficiency and competitiveness, including installing electric-powered compressors rather than natural gas-powered compressors used by many of its competitors. APL transports and sells natural gas to parties, including various marketing companies and pipelines, at the tailgate of the Velma plant and sells NGL production to ONEOK Hydrocarbon, L.P.

Natural Gas Supply

In the Mid-Continent, APL has natural gas purchase, gathering and/or processing agreements with approximately 560 producers. These agreements provide for the purchase or gathering of natural gas under Fee-Based, POP or Keep-Whole arrangements. Many of the agreements provide for compression, treating, processing and/or low volume fees. Producers generally provide, in-kind, their proportionate share of compressor and plant fuel required to gather the natural gas and to operate APL’s processing plants. In addition, the producers generally bear their proportionate share of gathering system line loss and, except for Keep-Whole arrangements, bear natural gas plant “shrinkage” for the gas consumed in the production of NGLs.

APL has long-term relationships with several of its Mid-Continent producers. For instance, APL has producer relationships going back over 20 years on its Velma System. Several of APL’s top producers, which accounted for a significant portion of the Velma volumes for the year ended December 31, 2010, have contracts with primary terms running into 2019 and beyond. At the end of the primary terms, most of the contracts with producers on APL’s gathering systems have evergreen term extensions. When APL acquired control of the Midkiff/Benedum system in July 2007, APL and Pioneer agreed to extend the existing gas sales and purchase agreement to 2022. The gas sales and purchase agreement requires that all Pioneer wells within an “area of mutual interest” be dedicated to that system’s gathering and processing operations in return for specified natural gas processing rates. Through this agreement, APL anticipates that it will continue to provide gathering and processing for the majority of Pioneer’s wells in the Spraberry Trend of the Permian Basin.

Natural Gas and NGL Marketing

APL typically sells natural gas to purchasers downstream of its processing plants priced at various first-of-month indices as published in Inside FERC. Additionally, swing gas, which is natural gas that is sold during the current month, is sold daily at various Platt’s Gas Daily midpoint pricing points. The Velma plant has

access to ONEOK Gas Transportation, LLC, an intrastate pipeline; Southern Star Central Gas Pipeline, Inc. and Natural Gas Pipeline Company of America, interstate pipelines. The Chester plant has access to Panhandle Eastern Pipe Line Company, LP and the Waynoka plant has access to Enogex LLC, Panhandle Eastern Pipe Line Company, LP and Southern Star Central Gas Pipeline, Inc. The Consolidator/Benedum plants have access to Kinder Morgan Texas Pipeline, Northern Natural Gas Company and El Paso Natural Gas Company. As negotiated in specific agreements, various producers are allowed to take their share of gas in-kind at various delivery points.

APL sells its NGL production to ONEOK Hydrocarbon, L.P. under three separate agreements. The Velma agreement has an initial term expiring in 2016, the Midkiff/Benedum agreement has an initial term expiring in 2013, and the Chaney Dell agreement has a term expiring in 2014. All NGL agreements are priced at the average daily Oil Price Information Service (or OPIS) price for the month for the selected market, subject to reduction by a “Base Differential” and quality adjustment fees.

Condensate is collected at the Velma gas plant and gathering system and currently sold to EnerWest Trading Company LLC. Condensate collected at the Chaney Dell plants and around the Chaney Dell gathering system is currently sold to Plains Marketing. Condensate collected at the Consolidator/Benedum plants and around the Midkiff/Benedum gathering system is currently sold to Plains Marketing, Occidental Energy Marketing, Inc. and Oasis Marketing and Transportation Corporation.

Commodity Risk Management

APL’s Mid-Continent operations are exposed to certain commodity price risks. These risks result from either taking title to natural gas and NGLs, including condensate, or being obligated to purchase natural gas to satisfy contractual obligations with certain producers. APL attempts to mitigate a portion of these risks through a commodity risk management program which employs a variety of financial tools. The resulting combination of the underlying physical business and the commodity risk management program attempts to convert a physical price environment that consists of floating prices to a risk-managed environment that is characterized by fixed prices; floor prices on products where APL is long the commodity price; and ceiling prices on products where APL is short the commodity price. There are also risks inherent within risk management programs, including among others (i) price relationship between the physical and financial instrument deteriorating or (ii) projected physical volumes changing.

APL (a) purchases natural gas and subsequently sells processed natural gas and the resulting NGLs, or (b) purchases natural gas and subsequently sells the unprocessed natural gas, or (c) gathers and/or processes the natural gas for a fee without taking title to the commodities. Scenario (b) exposes APL to a generally neutral price risk (long sales approximate short purchases), while scenario (c) does not expose APL to any price risk; in both scenarios, risk management is not required. Scenario (a) does involve commodity price risk.

APL is exposed to commodity price risks when natural gas is purchased for processing. The amount and character of this price risk is a function of APL’s contractual relationships with natural gas producers or, alternatively, a function of cost of sales. APL is therefore exposed to price risk at a gross profit level rather than at a revenue level. These cost-of-sales or contractual relationships are generally of two types:

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POP: requires APL to pay a percentage of revenue to the producer. This results in APL being net long physical natural gas and NGLs.

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Keep-Whole: generally requires APL to deliver the same quantity of natural gas (measured in BTU’s) at the delivery point as it received at the receipt point; any resulting NGLs produced belong to APL, resulting in APL being long physical NGLs and short physical natural gas.

APL manages a portion of these risks by using fixed-for-floating swaps, which result in a fixed price, or by utilizing the purchase or sale of options, which result in floor prices, ceiling prices. APL utilizes natural gas

swaps and options to manage its natural gas price risks. APL utilizes NGL and crude oil swaps and options to manage its NGL and condensate price risks.

APL generally realizes gains and losses from the settlement of its derivative instruments in other income at the same time it sells the associated physical residue gas or NGLs. APL determines gains or losses on open and closed derivative transactions as the difference between the derivative contract price and the physical price. This mark-to-market methodology uses daily closing New York Mercantile Exchange (“NYMEX”) prices when applicable and an internally-generated algorithm for commodities that are not traded on an open market. To ensure that these derivative instruments will be used solely for managing price risks and not for speculative purposes, APL has established a committee to review its derivative instruments for compliance with its policies and procedures.

For additional information on APL’s derivative activities and a summary of its outstanding derivative instruments as of December 31, 2010, please see “Item 7A: Quantitative and Qualitative Disclosures About Market Risk.”

APL’s Appalachia Operations

APL’s Appalachia operations are principally conducted through its 49% non-controlling interest in Laurel Mountain, which APL sold subsequent to December 31, 2010. Laurel Mountain owns and operates approximately 1,000 miles of intrastate gas gathering systems located in Pennsylvania, including substantial assets in the Marcellus Shale. APL also owns and operates approximately 70 miles of natural gas gathering pipelines in Tennessee. Laurel Mountain serves approximately 4,700 wells and experienced an average throughput of 109.5 MMCFD of natural gas for the year ended December 31, 2010. APL’s Tennessee systems serve approximately 180 receipt points and experienced an average throughput of 8.7 MMCFD of natural gas for the year ended December 31, 2010. APL’s gathering systems provide a means through which well owners and operators can transport the natural gas produced by their wells to interstate and public utility pipelines for delivery to customers. To a lesser extent, APL’s gathering systems transport natural gas directly to customers. Laurel Mountain’s systems are located in the Appalachian Basin, which encompasses the Marcellus Shale. The Marcellus Shale is a vast, newly developing shale play experiencing a significant increase in natural gas exploration and production. The Appalachian Basin is a region that has historically been characterized by long-lived, predictable natural gas reserves that are close to major eastern U.S. natural gas markets. Substantially all of the natural gas Laurel Mountain gathers in the Appalachian Basin is derived from wells operated by Atlas Energy Resources. Laurel Mountain has a gas gathering agreement with Atlas Energy Resources, which is intended to maximize the use and expansion of the gathering systems and the amount of natural gas which Laurel Mountain gathers in the region. In addition, other natural gas producers have acreage positions in relatively close proximity to Laurel Mountain’s current and planned assets, providing additional opportunities for expansion.

Appalachian Basin Overview

The Appalachian Basin includes the states of Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia. The Appalachian Basin is strategically located near the energy-consuming regions of the mid-Atlantic and northeastern United States.

Natural Gas Supply

Substantially all of the natural gas Laurel Mountain gathers in the Appalachian Basin is derived from wells operated by Atlas Energy Resources. Laurel Mountain’s ability to increase the flow of natural gas through its gathering systems will be determined primarily by the number of wells drilled by Atlas Energy Resources and connected to the gathering systems; and Laurel Mountain’s ability to acquire additional gathering assets and secure gathering contracts with other natural gas producers with acreage positions in the area and expand

existing systems. During the year ended December 31, 2010, approximately 90 wells were connected to the Laurel Mountain gathering system.

Natural Gas Revenue

APL’s Appalachia revenue is determined primarily by the amount of natural gas flowing through Laurel Mountain’s and its Tennessee gathering systems and the price received for this natural gas. Laurel Mountain has an agreement with Atlas Energy Resources under which Atlas Energy Resources is obligated to pay a gathering fee that is generally the greater of $0.35 per MCF or 16% of the realized sales price (except that a lower fee applies with respect to specific wells subject to certain existing contracts or in the event Laurel Mountain fails to perform specified obligations). For the year ended December 31, 2010, Laurel Mountain received gathering fees averaging $0.95 per MCF.

Because APL does not buy or sell gas in connection with its Appalachia operations, it does not engage in hedging activities. Atlas Energy Resources maintains a hedging program. Since Laurel Mountain receives gathering fees from Atlas Energy Resources generally based on the selling price received by Atlas Energy Resources, inclusive of the effects of financial and physical hedging, these financial and physical hedges mitigate the risk of Laurel Mountain’s arrangements.

APL’s Relationship with Atlas Energy, Inc.

APL began its operations in January 2000 by acquiring the Appalachia gathering systems of ATLS. In May, 2009, APL contributed the majority of its Appalachia gathering system assets to Laurel Mountain, a joint venture in which APL has a 49% non-controlling interest. ATLS owned 64.0% of us and had a direct 2.1% ownership interest in APL at December 31, 2010.

ATLS and its affiliates sponsor limited and general partnerships to raise funds from investors to explore for, develop and produce natural gas and, to a lesser extent, oil from locations in northeastern Appalachia. Laurel Mountain’s gathering systems are connected to approximately 4,600 wells developed and operated by Atlas Energy Resources in the Appalachian Basin. Laurel Mountain gathers substantially all of the natural gas from wells operated by Atlas Energy Resources.

Natural Gas Gathering Agreements

In connection with the formation of Laurel Mountain, on June 1, 2009, Laurel Mountain entered into the following natural gas gathering agreements with Atlas Energy Resources, Atlas Energy Operating Company, LLC, Atlas America, LLC, Atlas Noble, LLC, Resource Energy, LLC and Viking Resources, LLC: (1) a gas gathering agreement for natural gas on the Legacy Appalachia system with respect to the existing gathering systems and any 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 a specified area of mutual interest (the “Expansion Agreement” and collectively with the Legacy Agreement, the “Gathering Agreements”). Under these Gathering Agreements, Atlas Energy Resources will dedicate its natural gas production in 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 Atlas Energy Resources’ dedicated natural gas in the Appalachian Basin subject to certain conditions.

Under the Gathering Agreements, Atlas Energy Resources is obligated to pay a gathering fee that is generally the greater of $0.35 per MCF or 16% of the realized sales price (except that a lower fee applies with respect to specific wells subject to certain existing contracts or in the event Laurel Mountain fails to perform specified obligations).

The provisions in the Gathering Agreements regarding the allocation of responsibility for constructing additional gathering lines are that to the extent that Atlas Energy Resources own wells or propose wells that are within 2,500 feet of Laurel Mountain’s gathering system, Laurel Mountain must, at its own cost, construct up to 2,500 feet of the gathering lines as necessary to connect such wells to the gathering system. For wells more than 2,500 feet from Laurel Mountain’s gathering system, if Atlas Energy Resources construct a gathering 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 gathering lines.

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

APL’s Competition

Acquisitions. APL has encountered competition in acquiring midstream assets owned by third parties. In several instances APL submitted bids in auction situations and in direct negotiations for the acquisition of such assets and was either outbid by others or was unwilling to meet the sellers’ expectations. In the future, APL expects to encounter equal, if not greater, competition for midstream assets because as natural gas, crude oil and NGL prices increase the economic attractiveness of owning such assets increases.

Mid-Continent. In APL’s Mid-Continent service area, it competes for the acquisition of well connections with several other gathering/processing operations. These operations include plants and gathering systems operated by Carrera Gas Company, Copano Energy, LLC, DCP Midstream, Enogex, LLC, Hiland Partners, Mustang Fuel Corporation, ONEOK Field Services, Southern Union Company, Targa Resources and West Texas Gas.

APL believes that the principal factors upon which competition for new well connections is based are:

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the price received by an operator or producer for its production after deduction of allocable charges, principally the use of the natural gas to operate compressors; and

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the quality and efficiency of the gathering systems and processing plants that will be utilized in delivering the gas to market; and

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the access to various residue markets that provides flexibility for producers and ensures that the gas will make it to market; and

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the responsiveness to a well operator’s needs, particularly the speed at which a new well is connected by the gatherer to its system.

APL believes that its relationships with operators connected to its system are good and that APL presents an attractive alternative for producers. However, if APL cannot compete successfully, it may be unable to obtain new well connections.

Appalachia. The assets operated in the Appalachian Basin by APL and Laurel Mountain do not encounter direct competition in their service areas at this time, since Atlas Energy Resources controls the majority of the drillable acreage in the area. However, because these operations principally serve wells drilled by Atlas Energy Resources, APL and Laurel Mountain are affected by competitive factors affecting Atlas Energy Resources’ ability to obtain properties and drill wells, which affects APL’s and Laurel Mountain’s ability to expand gathering systems and to maintain or increase the volume of natural gas gathered and, thus, transportation revenues. Atlas Energy Resources also may encounter competition in obtaining drilling services from third-party providers. Any competition it encounters could delay Atlas Energy Resources in drilling wells, and thus delay the connection of wells to APL’s and Laurel Mountain’s gathering systems. These delays would

reduce the volume of natural gas that otherwise would have been gathered, thus reducing potential transportation revenues.

In addition to the connections to Atlas Energy Resources wells, Laurel Mountain and APL seek to connect wells operated by third parties. As of December 31, 2010, these systems are connected to approximately 250 third party wells.

Seasonality

APL’s business is affected by seasonal fluctuations in commodity prices. Sales volumes are also affected by various factors such as fluctuating and seasonal demands for products and variations in weather patterns from year to year. Generally, natural gas demand increases during the winter months and decreases during the summer months. Freezing conditions can disrupt APL’s gathering process, which could adversely affect APL’s operating results.

Regulation

Gathering Pipeline Regulation. Section 1(b) of the Natural Gas Act of 1938, 15 U.S.C. § 717(b), exempts natural gas gathering facilities from the jurisdiction of the Federal Energy Regulatory Commission (“FERC”). APL owns a number of intrastate natural gas gathering lines in Kansas, Oklahoma and Texas that APL believes meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated natural gas transportation facilities and federally unregulated natural gas gathering facilities is the subject of regular litigation, so the classification and regulation of some of APL’s or Laurel Mountain’s gathering facilities may be subject to change based on future determinations by FERC and the courts.

Laurel Mountain’s operations in Pennsylvania currently are not subject to the Pennsylvania Public Utility Commission’s regulatory authority since Laurel Mountain does not provide service to the public generally and, accordingly, its activities do not constitute the operation of a public utility. In the event the Pennsylvania authorities seek to regulate Laurel Mountain’s operations, APL’s operating costs could increase and its transportation fees could be adversely affected, thereby reducing its net revenues and ability to fund its operations, pay required debt service on its credit facilities and make distributions to its General Partner and common unitholders.

APL is currently subject to state ratable, take common purchaser and/or similar statutes in one or more jurisdictions in which it operates. Common purchaser statutes generally require gatherers to purchase without discrimination as to source of supply or producer, while ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. In particular, Kansas, Oklahoma and Texas have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and discrimination with respect to rates or terms of service. Should a complaint be filed or regulation by the Kansas Corporation Commission, the Oklahoma Corporation Commission or the Texas Railroad Commission become more active, APL’s revenues could decrease. Collectively, any of these laws may restrict APL’s right as an owner of gathering facilities to decide with whom it contracts to purchase or gather natural gas.

APL’s gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. APL’s gathering operations also may be or may become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered and adopted from time to time. We cannot predict what effect, if any, such changes might have on APL’s operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Sales of Natural Gas and NGLs. A portion of APL’s revenue is tied to the price of natural gas and NGLs. The wholesale price of natural gas and NGLs is not currently subject to federal regulation and, for the most part, is not subject to state regulation. Sales of natural gas and NGLs are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation of natural gas and NGLs are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting the segments of the natural gas industry, most notably interstate natural gas transportation companies that remain subject to FERC’s jurisdiction. While FERC is less active in proposing changes in the manner in which it regulates the transportation of NGLs under the Interstate Commerce Act, it does nevertheless have authority to address the rates, terms and conditions under which NGLs are transported. FERC initiatives could, therefore, affect the intrastate transportation of natural gas and NGLs under certain circumstances. We cannot predict the ultimate impact of any regulatory changes that could result from FERC initiatives on APL’s operations.

Energy Policy Act of 2005. The Energy Policy Act contains numerous provisions relevant to the natural gas industry and to interstate natural gas pipelines in particular. Overall, the legislation attempts to increase supply sources by calling for various studies of the overall resource base and attempting to advantage deep water production on the Outer Continental Shelf in the Gulf of Mexico. However, the provisions of primary interest to APL as an operator of natural gas gathering lines and sellers of natural gas focus on two areas: (1) infrastructure development; and (2) market transparency and enhanced enforcement. Regarding infrastructure development, the Energy Policy Act includes provisions; confirming that FERC has exclusive jurisdiction over the siting of liquefied natural gas (“LNG”) terminals; provides for market-based rates for certain new underground natural gas storage facilities placed into service after the date of enactment; shortens depreciable life for gathering facilities; statutorily designates FERC as the lead agency for federal authorizations and permits relating to interstate natural gas pipelines and LNG terminals; provides for the assembly of a consolidated record for all federal decisions relating to necessary authorizations and permits with respect to interstate natural gas pipelines and LNG terminals; and provides for expedited judicial review of any agency action involving the permitting of such facilities and review by only the D.C. Circuit Court of Appeals of any alleged failure of a federal agency to act on a permit relating to an interstate natural gas pipeline or LNG terminal by a deadline set by FERC as lead agency. Such provisions, however, do not apply to review and authorization under the Coastal Zone Management Act of 1972. Regarding market transparency and manipulation, the Natural Gas Act has been amended to prohibit market manipulation and directs FERC to prescribe rules designed to encourage the public provision of data and reports regarding the price of natural gas in wholesale markets. The Natural Gas Act and the Natural Gas Policy Act were also amended to increase monetary criminal penalties to $1,000,000 from the $5,000 amount specified under prior law and to add and increase civil penalty authority to be administered by FERC to $1,000,000 per day per violation without any limitation as to total amount.

At present, APL believes none of its gathering lines qualify as interstate natural gas transmission systems subject to FERC regulation under the Natural Gas Act. Accordingly, the provisions of the Energy Policy Act have only limited applicability to APL, primarily in its capacity as a seller of natural gas.

Environmental Matters

The operation of pipelines, plant and other facilities for gathering, compressing, treating, processing, or transporting natural gas, natural gas liquids and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, APL must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact APL’s business activities in many ways, such as:

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restricting the way APL can handle or dispose of its wastes;

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limiting or prohibiting construction and operating activities in sensitive areas such as wetlands, coastal regions, non-attainment areas, tribal lands or areas inhabited by endangered species;

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requiring remedial action to mitigate pollution conditions caused by APL’s operations or attributable to former operators; and

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enjoining some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where pollutants or wastes have been disposed or otherwise released. Neighboring landowners and other third parties can file claims for personal injury or property damage allegedly caused by noise and/or the release of pollutants or wastes into the environment.

We believe that APL’s operations are in substantial compliance with applicable environmental laws and regulations and that compliance with existing federal, state and local environmental laws and regulations will not have a material adverse effect on its business, financial position or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, we cannot assure you that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause APL to incur significant costs.

Hazardous Waste. APL’s operations generate wastes, including some hazardous wastes that are subject to the federal Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas exploration and production wastes may still be regulated under state law or the solid waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.

We believe that APL’s operations are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that APL’s 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 exploration and production wastes could increase APL’s costs to manage and dispose of such wastes.

Site Remediation. The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, or CERCLA, also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations such as landfills. Although petroleum and natural gas are excluded from CERCLA’s definition of “hazardous substance,” in the course of APL’s ordinary operations it may generate wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the Environmental Protection Agency, or EPA, and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs

they incur. Under CERCLA, APL could be subject to joint and several, strict liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for the costs of certain health studies.

APL currently owns or leases, and have in the past owned or leased, numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas. Although APL used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by APL or on or under other locations where such substances have been taken for disposal. There is evidence that petroleum spills or releases have occurred at some of the properties owned or leased by APL. However, none of these spills or releases were material and APL believes all of them have been remediated. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of petroleum hydrocarbons or wastes 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, APL could be required to remove previously disposed wastes (including waste disposed of by prior owners or operators), remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills), or perform operations to prevent future contamination.

Air Emissions. APL’s operations are subject to the federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including APL’s processing plants, certain storage vessels and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that APL obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. APL’s failure to comply with these requirements could subject it to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. APL likely will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that APL’s operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to APL than to any other similarly situated companies.

Water Discharges. APL’s operations are subject to the Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and federal waters. The discharge of pollutants is prohibited unless authorized by a permit or other agency approval. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by a permit. Any unpermitted release of pollutants from APL’s pipelines or facilities could result in administrative, civil or criminal penalties as well as significant remedial obligations. Further, natural gas extraction activities utilize 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 regulatory and legislative attention at both the federal and state levels and it is possible that the permitting and compliance requirements applicable to hydraulic fracturing activity may become more stringent. Such requirements could have an adverse impact on APL’s operations.

Pipeline Safety. APL’s pipelines are subject to regulation by the U.S. Department of Transportation, or DOT, under the Natural Gas Pipeline Safety Act of 1968, as amended, or the NGPSA. The NGPSA authorizes the DOT to regulate pipeline transportation of natural (flammable, toxic, or corrosive) gas and other gases, and requires any entity that owns or operates pipeline facilities to comply with the regulations. The DOT’s Pipeline and Hazardous Material Safety Administration, or PHMSA, acting through the Office of Pipeline Safety, or OPS, administers the national regulatory program to assure safe transportation of natural gas, petroleum, and other hazardous materials by pipeline. The OPS administers the federal pipeline safety regulations to (1) ensure

safety in design, construction, inspection, testing, operation, and maintenance of pipeline facilities and (2) set out parameters for administering the pipeline safety program.

APL’s operations are required to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that APL’s pipeline operations are in substantial compliance with existing PHMSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, future compliance with the PHMSA could result in additional requirements and costs.

PHMSA recently finalized a series of rules intended to require pipeline operators to develop integrity management programs for gas transportation pipelines (including gathering lines) that, in the event of a failure, could affect “high consequence areas.” “High consequence areas” are currently defined as areas with specified population densities, buildings containing populations of limited mobility, and areas where people gather that are located along the route of a pipeline. To ensure uniform implementation of the pipeline safety program nationwide, Federal/State partnerships including the Texas Railroad Commission, the Oklahoma Corporation Commission and other state agencies have adopted similar regulations applicable to intrastate gathering and transportation lines. Compliance with these rules has not had a materially adverse effect on our operations but there is no assurance that this will continue in the future.

Employee Health and Safety. APL is subject to the requirements of the Occupational Safety and Health Act, as amended, or OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in APL’s operations and that this information be provided to employees, state and local government authorities and citizens.

Hydrogen Sulfide. Exposure to gas containing high levels of hydrogen sulfide, referred to as sour gas, is harmful to humans, and prolonged exposure can result in death. The gas produced at APL’s Velma gas plant contains high levels of hydrogen sulfide, and APL employs numerous safety precautions at the system to ensure the safety of its employees. There are various federal and state environmental and safety requirements for handling sour gas, and APL is in substantial compliance with all such requirements.

Chemicals of Interest. APL operates several facilities that are registered with the U.S. Department of Homeland Security, or DHS, in order to identify the quantities of various chemicals that are stored at the sites. These facilities are the Velma, Chaney Dell, Waynoka and Chester gas processing plants in Oklahoma; and the Midkiff and Benedum gas processing plants in Texas. The liquid hydrocarbons that are recovered and stored as a result of facility processing activities, and various chemicals utilized within the processes, have been identified and registered with DHS. These registration requirements for Chemical of Interest were first promulgated by DHS in 2008 and APL is currently in compliance with the Department’s requirements. None of APL’s affected facilities are considered high security risks by DHS at this time and no specific security plans for such per DHS regulations are required.

Greenhouse Gases. In October 2009, the EPA published rules in Title 40 of the Code of Federal Regulations, part 98 (40 CFR 98) requiring mandatory reporting of greenhouse gases. The rule specifies methods by which entities that produce these gases, which include Carbon Dioxide (CO₂) and Methane (CH₄), must inventory, monitor and report such gases. Compliance with this rule has resulted, and will continue to result, in higher costs of doing business. Additionally the United States Congress is also considering legislation to address the production and reduction of greenhouse gases primarily through the planned development of a greenhouse gas cap and trade program. As an alternative to the cap and trade program, the EPA may implement greenhouse gas reduction through traditional construction and operating permit programs, which would effectively circumvent the need for congressional action. The cap and trade programs could require major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or gas processing plants, to acquire and surrender emission allowances. APL could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from its operations or from combustion of

fuels it processes. In addition, APL’s operations could face additional costs for emissions control and higher costs of doing business. Although APL would not be impacted to a greater degree than other similarly situated gatherers and processors of natural gas or NGLs, a stringent greenhouse gas control program could result in a significant effect on APL’s cost of doing business. However, we are currently unable to assess the timing and effect of the pending legislation.

APL Properties

As of December 31, 2010, our assets consisted principally of our ownership interests in APL. As of December 31, 2010, APL’s principal facilities in the Mid-Continent consist of five natural gas processing plants and approximately 8,600 miles of active 2 to 30 inch diameter pipeline. Substantially all of APL’s gathering systems are constructed within rights-of-way granted by property owners named in the appropriate land records. As of December 31, 2010, APL’s principal facilities in Appalachia include approximately 70 miles of 2 to 12 inch diameter pipeline operated by its Tennessee gathering systems and approximately 1,000 miles of 2 to 12 inch diameter pipeline operated by Laurel Mountain. In a few cases, property for gathering system purposes was purchased in fee. All of APL’s compressor stations are located on property owned in fee or on property obtained via long-term leases or surface easements.

The following tables set forth certain information relating to APL’s gas processing facilities and natural gas gathering systems:

Gas Processing Facilities


Facility	Location	Year Constructed	Design Throughput Capacity (MMCFD)		2010 Average Througput (MMCFD)		2010 Average Utilization Rate

Velma plant	Stephens County, OK	Updated 2003		100		78		78	%


Waynoka plant	Woods County, OK	2006		200
Chester plant	Woodward County, OK	1981		28

Total Chaney Dell				228		214		94	%


Consolidator plant⁽¹⁾	Reagan County, TX	2009		150
Benedum plant	Upton County, TX	Updated 1981		45

Total Midkiff/Benedum				195		163		84	%

(1)	Replaced 110 MMCFD Midkiff plant, which has been shut down. Midkiff plant is available for processing if natural gas supply increases beyond the Consolidator plant capacity.

Natural Gas Gathering Systems


System	Location	Approximate Active Miles of Pipe		Receipt Points
Chaney Dell	North Central Oklahoma and Southern Kansas		4,300		4,300
Velma	Southern Oklahoma and Northern Texas		1,200		600
Midkiff/Benedum	West Texas		3,100		2,800
Laurel Mountain	Pennsylvania		1,000		4,700
Tennessee	Tennessee		70		180

APL’s property or rights-of-way are subject to encumbrances, restrictions and other imperfections. These imperfections have not materially interfered, and we do not expect that they will materially interfere, with the conduct of APL’s business. In many instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the rights-of-way grants. In a few instances, APL’s rights-of-way are revocable at the election of the land owners. In some cases, not all of the owners named in the appropriate land records have joined in the rights-of-way grants, but in substantially all such cases signatures of the owners of majority interests have been obtained. Substantially all permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets,

and state highways, where necessary, although in some instances these permits are revocable at the election of the grantor. Substantially all permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election.

Certain of APL’s rights to lay and maintain pipelines are derived from recorded gas well leases, with respect to wells that are currently in production; however, the leases are subject to termination if the wells cease to produce. In some of these cases, the right to maintain existing pipelines continues in perpetuity, even if the well associated with the lease ceases to be productive. Because many of these leases affect wells at the end of lines, these rights-of-way will not be used for any other purpose once the related wells cease to produce.

Employees

As is commonly the case with publicly-traded limited partnerships, we do not directly employ any of the persons responsible for our management, nor does APL directly employ any of the persons responsible for its operations. In general, employees of ATLS and its affiliates manage APL’s gathering systems and operate its business. ATLS employed approximately 270 people at December 31, 2010 who provided direct support to APL’s operations.

ATLS and its affiliates will conduct business and activities of their own in which we and APL will have no economic interest. If these separate activities are significantly greater than our and APL’s activities, there could be material competition between us, APL, ATLS and affiliates of ATLS for the time and effort of the officers and employees who provide services to us or APL. Apart from our Chairman and Vice Chairman, our officers who provide services to APL are generally assigned solely to our or APL’s operations. However, they are not required to work full time on our or APL’s affairs. These officers may also devote time to the affairs of ATLS and its affiliates and be compensated by these affiliates for the services rendered to them. There may be conflicts between us and APL and affiliates of our general partner regarding the availability of these officers to manage us and APL.

On February 17, 2011, ATLS consummated its merger with Chevron pursuant to the Chevron Merger Agreement whereby ATLS became a wholly-owned subsidiary of Chevron. Additionally, on February 17, 2011, we consummated the AHD Transactions with ATLS and Atlas Energy Resources and subsequent to such transaction, we or one of our subsidiaries employs all of the persons responsible for our management and operations. See “–Recent Developments” for further discussion.

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 and our current reports on Form 8-K, available through our website at www.atlasenergy.com. 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 1550 Coraopolis Heights Road, Moon Township, Pennsylvania 15108, telephone number (412) 262-2830. A complete list of our filings is available on the Securities and Exchange Commission’s website at www.sec.gov. Any of our filings are also available at the Securities and Exchange Commission’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The Public Reference Room may be contacted at telephone number (800) 732-0330 for further information.

ITEM 1A.

RISK FACTORS

Partnership interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected.

Risks Relating to the Recent AHD Transactions

Our historical results are not necessarily representative of the results that we would have achieved without ATLS as our majority unitholder, as the owner of the transferred business or otherwise as an operating entity and may not be a reliable indicator of our future results.

Our historical results do not reflect the financial condition, results of operations or cash flows that we would have achieved without ATLS as our majority unitholder, if we were the owner and operator of the transferred business on a stand-alone basis or otherwise as an operating entity, primarily due to the following factors:

•

Our historical financial results do not reflect the AHD Transactions or the disposition by APL of its 49% non-controlling ownership interest in Laurel Mountain;

•

Since our formation, ATLS has been our majority unitholder, has provided us with management and other services, and has managed or performed certain of our corporate functions at no cost to us. In addition, following the AHD Transactions, our financial results will reflect certain corporate expenses for which we became solely responsible and certain additional corporate expenses which were previously inapplicable to us, including management compensation, financial reporting, tax administration, human resources administration, information technology, legal and other services;

•

We will incur significant increases in our cost structure following the AHD Transactions. Prior to the AHD Transactions, we did not have any significant stand-alone operations. Following the AHD Transactions, our operations may require a significant number of additional operational, technical and other personnel whose costs are not reflected in our historical financial data. Our operations following the AHD Transactions also require us to newly implement or expand our current capabilities in areas including operations, maintenance, geophysical, geotechnical, land acquisition and management, sales and marketing, legal and regulatory compliance, treasury, accounting, auditing, risk management, information technology, human resources, corporate affairs, tax administration, governance and external reporting. We also became responsible for the significant field-related capital and operating expenditures required in connection with the exploration for and production of hydrocarbons and all of the attendant risks associated with such activities. These requirements, among others, will materially increase the cost of our operations and our businesses above historical levels;

•

Our cost of funds is likely to change following the AHD Transactions, including due to the fact that our former parent, ATLS no longer exists to guarantee any of our indebtedness or provide any financing to us; and

•

the AHD Transactions and the fact that we are no longer controlled by ATLS may adversely affect client and other business relationships of ours and of the transferred business, which effects may be material, and may result in the loss of certain preferred pricing previously available to us or to the transferred business by virtue of our relationship with ATLS.

Our financial condition and future results of operations, after giving effect to the AHD Transactions and the Laurel Mountain Sale, will be materially different from the amounts reflected in our historical financial information. As a result of the AHD Transactions and the disposition of APL’s 49% non-controlling ownership interest in Laurel Mountain, it may be difficult for investors to compare our future results to historical results or to evaluate our relative performance or trends in our business, which may adversely affect the trading market for, and price of, our common units.

We may not be successful in transitioning to a company not controlled by ATLS and may be unable to obtain all of the services and resources we need to operate independently of ATLS and to operate the transferred business.

Historically, ATLS has provided us with certain services essential to our business, including managing the business of APL, the direct and indirect interests which prior to the AHD Transactions, were our only significant cash-generating assets. Following the recent consummation of the AHD Transactions, other than as provided in the Transition Services Agreement, the Michigan Operating Agreement, the Pennsylvania Operating Agreement, the Petro-Technical Services Agreement and the Gas Marketing Agreement, ATLS and Chevron have no obligation to provide us with financial, operational or organizational assistance. Furthermore, the services to be provided by ATLS and Chevron under such agreements are limited in scope and duration. We may need to develop our own capabilities or otherwise supplement the services contemplated by these agreements, and the other services historically provided to us by ATLS, and may need to hire and train personnel to undertake some or all of the services following the termination or expiration of these agreements or to otherwise provide certain services historically provided by ATLS or historically inapplicable to us, any of which could adversely affect the operation of our business and financial results. We may need to hire additional personnel, upgrade our systems and infrastructure and make other changes necessary to operate independently and to conduct the transferred business. We cannot guarantee that the services historically provided by ATLS will continue or be replaced without disruption or at a cost comparable to that provided by ATLS or that we will be able to implement successfully the changes necessary to operate independently.

Our costs to operate the transferred business may be significantly higher than ATLS’s historical costs.

The costs of operating the transferred business cannot be estimated with certainty, and may be materially higher than historical costs to ATLS for such operations, primarily due to the following factors:

•

the loss of certain economies of scope and scale;

•

the need to replace certain contracts associated with the transferred business that are being retained by ATLS in the AHD Transactions;

•

our lack of experience in operating assets of this type;

•

the likely increase in hedging costs associated with the transferred business, including hedging relating to the oil, gas and liquids production of the transferred business, relative to the analogous hedging costs incurred by ATLS’s historical hedging activities;

•

the need to rely on ATLS for certain transitional and operating services for some period of time following closing (see “Item 1: Business –Services Agreements”), and the need to hire and train personnel to undertake some or all of those services following the termination or expiration of those transition and operating services agreements; and

•

potential increases in regulatory, compliance, severance and tax liabilities associated with the operations of the transferred business (see “–Changes in tax laws may impair our ability to obtain capital funds through investment partnerships,” “–Potential introduction of severance taxes in Pennsylvania could materially increase our liabilities,” and “–We are subject to comprehensive

federal, state, local and other laws and regulations that could increase the cost and alter the manner or feasibility of doing business”).

Any increase in the operational costs of conducting the transferred business could adversely affect our results of operations and financial condition, which could limit the amount of cash available for distribution and could adversely affect the trading market for our common units.

Our business is now substantially different following the consummation of the AHD Transactions and the Laurel Mountain Sale, and management may not be able to operate the transferred business to achieve the anticipated results.

As a result of the AHD Transactions and the Laurel Mountain Sale, we now own ATLS’s investment partnership business and certain producing oil and gas assets and assumed certain of the historical and future liabilities associated with such businesses, and we no longer derive revenue from the gas gathering business of Laurel Mountain. Our business is substantially different following the AHD Transactions and our results of operations and the market price of our common units following the AHD Transactions may be affected by factors different from those historically affecting our results of operations and the market price of our common units. Although our management includes individuals that have historically managed the transferred business, we may not be able to retain all of these employees and we cannot guarantee that we will be able to operate the transferred business in a profitable manner or will be able to achieve the projected benefits from the AHD Transactions.

After the AHD Transactions, we are no longer able to obtain financing from ATLS

Our plans to operate, expand and improve our business may require funds in excess of our cash flow and may require us to seek financing from third parties. In the past, ATLS has provided us with capital. After the AHD Transactions, however, ATLS will not provide funds to us. Without the opportunity to obtain financing from ATLS, we will need to obtain additional financing from banks, or through public offerings or private placements of debt or equity securities, strategic relationships or other arrangements. We cannot give assurances at this time that we will be able to obtain such funding. In addition, the terms, interest rates, costs and fees of new credit facilities may not be as favorable as those historically provided by ATLS. If financing is not available when needed, or is available on unfavorable terms, we may be unable to meet our capital needs, maintain our existing businesses, develop new businesses or enhance our existing businesses, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our business, financial condition and results of operations.

APL’s ability to make distributions to its partners, including us, and the amount of any such distributions may be affected by APL’s sale of its 49% non-controlling ownership interest in Laurel Mountain, by APL’s use of proceeds from such sale, and by APL’s conduct of its business following such sale. The amount and timing of such distributions by APL, if any, will have an impact on our ability to make distributions and the amount of any such distributions.

Our direct and indirect ownership interests in APL historically represented our only cash-generating assets and they continue to represent a significant source of operating cash for us following the completion of the AHD Transactions. APL’s ability to make distributions to its partners, including us, may be affected by APL’s sale of its 49% non-controlling ownership interest in Laurel Mountain and APL’s use of the proceeds from such sale. APL’s use of proceeds from the sale of its 49% non-controlling ownership interest in Laurel Mountain may be different from the use that holders of our common units would prefer, and may be limited in whole or in part by the terms of APL’s outstanding indebtedness. For example, holders of our common units might prefer that APL distributes all or a portion of such proceeds to APL’s partners, or to use such proceeds to make one or more acquisitions, but APL may, subject to the terms of its outstanding indebtedness, use such proceeds for the repayment of debt or for acquisitions or capital investments or for other purposes. In addition, cash flows from APL to us continue to be subject to the various regulatory, commercial, operating and other

risks arising in connection with APL’s conduct of its business, some of which may differ from the risks associated with the assets and liabilities acquired in the AHD Transactions.

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, and will continue to do so following the AHD Transactions. 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, on APL’s business and on each of our and APL’s 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 the domestic and foreign supply and demand;

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the price and level of foreign imports;

•

the level of consumer product demand;

•

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;

•

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

•

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, 2010, the NYMEX Henry Hub natural gas index price ranged from a high of $6.01 per MMBTU to a low of $3.29 per MMBTU, and West Texas Intermediate oil prices ranged from a high of $91.51 per Bbl to a low of $68.01 per Bbl.

Unless we replace the oil and gas reserves that we acquired in the AHD Transactions, 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. Following the AHD Transactions, our natural gas reserves and production and, therefore, our cash flow and income became highly dependent on our success in

efficiently developing and exploiting the reserves that we acquired in the AHD Transactions 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.

Estimates of the 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, the actual future net cash flows we derive from such properties also will be affected by factors such as:

•

actual prices we receive for natural gas;

•

the amount and timing of actual production;

•

the amount and timing of our capital expenditures;

•

supply of and demand for natural gas; and

•

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 our 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.

A decrease in natural gas prices could subject our oil and gas properties to a non-cash impairment loss.

Oil and gas properties and other long-lived assets are 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 will 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 was less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on our own 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 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.

In connection with the AHD Transactions, we entered into hedging arrangements intended to benefit from or reduce the risk of fluctuations in the price of natural gas and oil or other commodities produced by the transferred business, including the investment partnership business. With this new hedging arrangement in place, we will reduce, but 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. Under circumstances in which, among other things, production is substantially less than expected, the counterparties to our futures contracts fail to perform under the contracts or a sudden, unexpected event materially impacts 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.

Our operations will require substantial capital expenditures to increase our asset base. If we are unable to obtain needed capital or financing on satisfactory terms, our revenues may decline.

The natural gas and oil industry is capital intensive. If we are unable to obtain sufficient capital funds with capital raised through equity and debt offerings, cash flow from operations, bank borrowings and the investment partnerships on satisfactory terms, we may be unable to increase or maintain our inventory of properties and reserve base, or be forced to curtail drilling or other activities. As a result, our revenues will decline and our ability to service debt may be diminished. 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.

The scope and costs of the risks involved in making acquisitions, including the AHD Transactions, 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;

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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;

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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;

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customer or key employee losses at the acquired businesses; and

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the failure to realize expected growth or profitability.

The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition. Further, our future acquisition costs may be higher than those we have achieved historically, or in connection with the AHD Transactions. Any of these factors could adversely affect our growth.

We may be unsuccessful in integrating the operations from the AHD Transactions or any future acquisitions with our operations.

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:

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operating a significantly larger combined entity;

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

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integrating personnel with diverse business backgrounds and organizational cultures;

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consolidating operational and administrative functions;

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

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

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customer or key employee loss from the acquired businesses;

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a significant increase in its indebtedness; and

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potential environmental or regulatory liabilities and title problems.

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

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 such as those we sponsor following the AHD Transactions, including deductions for intangible drilling costs and depletion deductions. However, President Obama’s 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.

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

A significant portion of our natural gas extraction activity will utilize a process called hydraulic fracturing, which results in water discharges 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 affect on our operations and financial performance. Our ability to remove and dispose of water will affect our production, and the cost of water treatment and disposal may affect our profitability. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct hydraulic fracturing or disposal of produced water, drilling fluids and other substances associated with the exploration, development and production of gas and oil.

Potential introduction of severance taxes in Pennsylvania could materially increase our liabilities.

In 2010, charges for severance taxes (relating to the extraction of natural gas) incurred by ATLS in the states in which ATLS operated, other than Pennsylvania, were approximately $6.0 million. While Pennsylvania has historically not imposed a severance tax, with a focus on its budget deficit and the increasing exploration of the Marcellus shale, various legislation has been proposed since 2008 to implement such a tax, the most recent of which would have imposed a tax of 5% of the value of natural gas at the wellhead plus $0.047 per MCF. Although that proposal was not adopted, lawmakers may propose similar taxes in the future. If adopted, these taxes may materially increase our operating costs in Pennsylvania relative to historical operating costs for the assets acquired in the AHD Transactions located in Pennsylvania.

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

ATLS had sponsored partnerships to raise funds from investors to finance certain of its development drilling activities. We expect that we will continue this practice. 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. ATLS raised $149.3 million, $353.4 million and $438.4 million for such partnerships in calendar years 2010, 2009 and 2008, respectively. In the future, we may not be successful in raising funds through these investment partnerships at the same levels that ATLS had recently experienced, and we also may

not be successful in increasing the amount of funds we raise. Our ability to raise funds through 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 ATLS’s historical track record of generating returns and tax benefits to the investors in ATLS’s former investment partnerships.

Investors may be less willing to rely on ATLS’s historical results in light of the AHD Transactions, in which case we may have difficulty in maintaining or increasing the level of funds ATLS had recently raised through investment partnerships. In this event, we may need to obtain financing for our drilling activities on a less attractive basis than the financing ATLS realized through these investment partnerships or we may determine to reduce drilling activity.

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.

Revenues from the investment partnerships may decrease if investors in the investment partnerships do not receive a minimum return.

ATLS had agreed to subordinate up to 50% of its share of production revenues, net of corresponding production costs, to specified returns to the investor partners in its investment partnerships, typically 10% per year for the first five years of distributions, and we are bound by this agreement following the AHD Transactions. Our revenues from a particular investment partnership will therefore decrease if the investment partnership does not achieve the specified minimum return.

Competition in the natural gas and oil industry is intense, which may hinder our ability to acquire 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 the investment partnership business that we acquired in the AHD Transactions, 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. 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 better connections in the securities industry segment that markets oil and gas investment partnerships. 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 us.

We may depend on certain key customers for sales of our natural gas. To the extent these customers reduce the volumes of natural gas they purchase following the AHD Transactions, our revenues could be negatively affected.

In Appalachia, ATLS’s natural gas was sold under contracts with various purchasers. During the year ended December 31, 2010, natural gas sales to Equitable Gas Company, Sequient Energy Management and South Jersey Resources Group accounted for approximately 14%, 14% and 12%, of its total Appalachian oil and gas revenues, respectively. Following the closing of the AHD Transactions and the Chevron Merger, certain purchased entities sell gas produced in four key counties in southwest Pennsylvania to a subsidiary of Chevron pursuant to the gas marketing agreement, which has a term of three years. In Michigan, during the year ended December 31, 2010, gas under contracts to DTE Energy, Conoco Phillips, BP Energy and Total Gas and Power accounted for approximately 30%, 26%, 19% and 14% of its total Michigan oil and gas revenues, respectively. Following the closing of the AHD Transactions and the Chevron Merger, all of the gas produced by the wells in Michigan indirectly owned by us through our ownership of the investment partnership business will be marketed by a subsidiary of Chevron pursuant to the Michigan Operating Agreement. To the extent these and other key customers are less willing to purchase natural gas from us, the Gas Marketing Agreement terminates, or the gas marketing services provided under the Michigan Operating Agreement are no longer provided, our revenues could be harmed in the event we are unable to sell to additional purchasers at similar prices.

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.

Higher natural gas and oil prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Over the past three years, ATLS and other natural gas and oil companies have experienced higher drilling and operating costs. 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 which are currently planned. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues.

Because we 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 wells and other facilities that we acquired in the AHD Transactions are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:

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

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

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Resource Conservation and Recovery Act (“RCRA”) and comparable state laws that impose requirements for the handling and disposal of waste, including produced waters, from facilities acquired in the AHD Transactions; and

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Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties previously owned or operated by ATLS, or at locations to which ATLS has sent waste for disposal, in each case that relate to assets acquired in connection with the AHD Transactions.

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

Many of the leases that we acquired in the AHD Transactions are in areas that have been partially depleted or drained by offset wells.

Many of the leases that we acquired in the AHD Transactions are in areas in the Appalachian Basin 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.

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;

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unexpected operational events and drilling conditions;

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adverse weather conditions, including the delay of drilling and/or the freeze-off of existing wells;

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facility or equipment malfunctions;

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title problems;

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pipeline ruptures or spills;

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compliance with environmental and other governmental requirements;

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unusual or unexpected geological formations;

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formations with abnormal pressures;

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injury or loss of life;

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unavailability or costs of gathering, processing and/or transportation services;

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limitations on or disruptions in gathering or transmission capacity;

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

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fires, blowouts, craterings and explosions; and

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uncontrollable flows of natural gas or well fluids.

Any one or more of 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 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.

Properties that we acquired in the AHD Transactions or that we subsequently 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 necessarily incomplete, because it generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well 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.

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. ATLS 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 AHD Transactions.

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

Our 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 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 operations and subject us 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 operate following the AHD Transactions includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of natural gas we may produce and sell. A major risk inherent in our drilling plans will be the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could inhibit our ability to develop our 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 profitability. Furthermore, we may be put at a competitive disadvantage to larger companies in its industry who can spread these additional costs over a greater number of wells and larger operating staff.

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 following the Limited Partnership Agreement Amendment (“the LPA Amendment”) discussed below 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.

The LPA Amendment changed the rights of holders of our common units under our limited partnership agreement.

In connection with the consummation of the AHD Transactions, the LPA Amendment was effected, and the rights of our unitholders are now governed by our limited partnership agreement as amended and restated by the LPA Amendment. The changes effected by the LPA Amendment, among other things, (1) permit our unitholders to elect our general partner’s board of directors, (2) classify our general partner’s board of directors into three classes and (3) eliminate our general partner’s right to call all of our common units for redemption if less than 12.5% of the common units are held by persons other than our general partner and its affiliates. These changes will affect our governance, and may affect the market for our common units.

Risks Relating to Our Business

We may not have sufficient cash to pay distributions.

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

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

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

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

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

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

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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

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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:

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our unitholders’ proportionate ownership interest in us will decrease;

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

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

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the ratio of taxable income to distributions may increase; and

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the market price of the common units may decline.

If the market price of our common units 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 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 common units; and

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changes in general conditions in the United States 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.

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:

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an increase in our operating expenses;

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an increase in general and administrative expenses;

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

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an increase in working capital requirements.

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

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

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

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pay distributions or redeem or repurchase our securities;

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prepay, redeem or repurchase debt;

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make loans, investments and acquisitions;

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enter into hedging arrangements;

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sell assets;

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enter into certain transactions with affiliates; and

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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.

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:

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We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including increases in our general and administrative expenses, principal or interest payments on our 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;

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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;

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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;

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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;

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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

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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.

Our and APL’s cash distribution policies limit our ability to grow.

Consistent with the terms of our partnership agreements, we and APL 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 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.

Our unitholders’ liability as a limited partner may not be limited and they may have to repay distributions or make additional contributions under certain circumstances.

Under Delaware law, our unitholders could be held liable for our obligations if a court determined that the right, or the exercise of the right, by our unitholders as a group to approve some amendments to the limited partnership agreement, or to take other action under our limited partnership agreement, constituted participation in the “control” of our business.

In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

Reduced APL distributions 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. Furthermore, as described in the immediately following risk factor, in the IDR Adjustment Agreement, 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 with 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.

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 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.

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 and the market for such interests is illiquid.

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 its 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.

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.

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.

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 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.

Risks Relating to APL’s Business

Because our cash flow relies upon distributions from APL, risks to APL’s business are also risks to us. We have set forth below the material risks to APL’s business or results of operations, the occurrence of which could negatively impact APL’s financial performance and decrease the amount of cash it is able to distribute to us, thereby decreasing the amount of cash we have available for funding our operations, paying required debt service on our credit facility or making distributions to our unitholders.

The amount of cash APL generates depends, in part, on factors beyond APL’s control.

The amounts of cash that APL generates may not be sufficient for APL to pay distributions in the future. APL’s ability to make cash distributions depends primarily on APL’s cash flow. Cash distributions do not depend directly on APL’s profitability, which is affected by non-cash items. Therefore, cash distributions may be made during periods when APL records losses and may not be made during periods when APL records profits. The actual amounts of cash APL generates will depend upon numerous factors relating to APL’s business which may be beyond APL’s control, including:

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

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the price of natural gas, NGLs, crude oil and condensate (including the volatility of such prices);

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the amount of NGL content in the natural gas APL processes;

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the volume of natural gas APL gathers;

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efficiency of APL’s gathering systems and processing plants;

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expiration of significant contracts;

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continued development of wells for connection to APL’s gathering systems;

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APL’s ability to connect new wells to its gathering systems;

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APL’s ability to integrate newly formed ventures or acquired businesses with its existing operations;

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the availability of local, intrastate and interstate transportation systems;

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the availability of fractionation capacity;

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the expenses APL incurs in providing its gathering services;

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the cost of acquisitions and capital improvements;

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APL’s issuance of equity securities;

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required principal and interest payments on APL’s debt;

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fluctuations in working capital;

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prevailing economic conditions;

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fuel conservation measures;

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alternate fuel requirements;

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the strength and financial resources of APL’s competitors;

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the effectiveness of APL’s hedging program and the creditworthiness of APL’s hedging counterparties;

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governmental (including environmental and tax) laws and regulations; and

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technical advances in fuel economy and energy generation devices.

In addition, the actual amount of cash that APL will have available for distribution will depend on other factors, including:

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the level of capital expenditures it makes;

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the sources of cash used to fund its acquisitions;

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limitations on its access to capital or the market for APL’s common units or notes;

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its debt service requirements; and

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the amount of cash reserves established by us, as APL’s general partner, for the conduct of APL’s business.

APL’s financial and operating performance may fluctuate significantly from quarter to quarter. APL may be unable to continue to generate sufficient cash flow to fund its operations, pay required debt service and make distributions to its unitholders. If APL is unable to do so, it may be required to sell assets or equity, reduce capital expenditures, reduce or eliminate distributions to unit holders, refinance all or a portion of its existing indebtedness or obtain additional financing. APL may be unable to do so on acceptable terms, or at all.

APL cannot borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” under its partnership agreement. Because APL cannot borrow money to pay distributions unless it establishes a facility that meets the definition contained in its partnership agreement, APL’s ability to pay a distribution in any quarter solely depends on its ability to generate sufficient operating surplus with respect to that quarter.

APL’s debt level and restrictions in its credit facility could limit its ability to fund operations, pay required debt service on its credit facility and make future distributions to its unitholders.

APL will need a portion of its cash flow to make principal and interest payments on its indebtedness, which will reduce the funds that would otherwise be available for operations, future business opportunities and distributions to its unitholders. If APL’s operating results are not sufficient to service its current or future indebtedness, it will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing its indebtedness, seeking additional equity capital or other alternatives. APL may not be able to affect any of these remedies on satisfactory terms, or at all. Therefore, APL’s ability to make distributions to us and consequently, our ability to fund our operations and pay required debt service could be impacted, which could force us to sell some or all of our interest in APL, seek additional equity capital, incur additional indebtedness or bankruptcy protection.

APL’s credit facility contains covenants limiting the ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions to unitholders. APL’s credit facility also contains covenants requiring APL to maintain certain financial ratios.

Due to APL’s lack of asset diversification, negative developments in its operations would reduce its ability to fund its operations, pay required debt service on its credit facilities and make distributions to its common unitholders.

APL relies exclusively on the revenues generated from its gathering and processing operations, and as a result, its financial condition depends upon prices of, and continued demand for, natural gas, NGLs and crude oil. Due to APL’s lack of asset-type diversification, a negative development in one of these businesses would have a significantly greater impact on its financial condition and results of operations than if APL maintained more diverse assets.

APL is exposed to the credit risks of its key customers, and any material nonpayment or nonperformance by its key customers could negatively impact APL’s business.

APL has historically experienced minimal collection issues with its counterparties; however APL’s revenue and receivables are highly concentrated in a few key customers and therefore APL is subject to risks of loss resulting from nonpayment or nonperformance by these key customers. In an attempt to reduce this risk, credit limits have been established for each customer and APL attempts to limit its credit risk by obtaining letters of credit, guarantees or other appropriate forms of security. Nonetheless, APL has key customers whose credit risk cannot realistically be otherwise mitigated.

APL is affected by the volatility of prices for natural gas and NGL products.

APL derives a majority of its gross margin from POP and Keep-Whole contracts. As a result, APL’s income depends to a significant extent upon the prices at which it buys and sells natural gas and at which it sells NGLs and condensate. Average estimated unhedged 2011 market prices for NGLs, natural gas and condensate, based upon NYMEX forward price curves as of January 11, 2011, are $1.14 per gallon, $4.54 per MMBTU and $92.77 per barrel, respectively. A 10% change in these prices would change our forecasted gross margin, excluding the effect of non-controlling interest in APL net income (loss), for the twelve-month period ended December 31, 2011 by approximately $13.5 million. Additionally, changes in natural gas prices may indirectly impact APL’s profitability since prices can influence drilling activity and well operations, and could cause operators of wells currently connected to APL’s pipeline system or that it expects will be connected to its system to shut in their production until prices improve, thereby affecting the volume of gas APL gathers and processes. Historically, the price of natural gas, NGLs and crude oil have been subject to significant volatility in response to relatively minor changes in the supply and demand for these products, market uncertainty and a variety of additional factors beyond APL’s control. Oil prices have traded in a range of $68.01 per barrel to $91.51 per barrel in 2010, while natural gas prices have traded in a range of $3.29 per MMBTU to $6.01 per MMBTU

during the same time period. APL expects this volatility to continue. This volatility may cause APL’s gross margin and cash flows to vary widely from period to period. APL’s risk management strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of the throughput volumes. Moreover, derivative instruments are subject to inherent risks, which we describe in “— APL’s price risk management strategies may fail to protect it and could reduce its gross margin and cash flow.”

APL’s price risk management strategies may fail to protect it and could reduce its gross margin and cash flow.

APL’s operations expose it to fluctuations in commodity prices. APL utilizes derivative contracts related to the future price of crude oil, natural gas and NGLs with the intent of reducing the volatility of its cash flows due to fluctuations in commodity prices. To the extent APL protects its commodity price using certain derivative contracts it may forego the benefits it would otherwise experience if commodity prices were to change in APL’s favor. APL’s commodity price risk management activity may fail to protect or could harm it because, among other things:

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entering into derivative instruments can be expensive, particularly during periods of volatile prices;

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available derivative instruments may not correspond directly with the risks against which APL seeks protection;

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price relationship between the physical transaction and the derivative transaction could change;

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the anticipated physical transaction could be different than projected due to changes in contracts, lower production volumes or other operational impacts, resulting in possible losses on the derivative instrument which is not offset by income on the anticipated physical transaction; and

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the party owing money in the derivative transaction may default on its obligation to pay.

We cannot predict at this time the outcome of the ongoing efforts by the Commodities Futures Trading Commission (“CFTC”) to implement the Dodd-Frank Act and to increase the regulation of over-the-counter derivatives including those related to energy commodities. The CFTC efforts are seeking, among other things, increased clearing of such derivatives through clearing organizations and the increased standardization of contracts, products, and collateral requirements. Such changes could negatively impact our ability to hedge our portfolio in an efficient, cost-effective manner by, among other things, increasing the cost of entering into derivative contracts and decreasing liquidity in the forward commodity markets.

The amount of natural gas APL gathers will decline over time unless it is able to attract new wells to connect to its gathering systems.

Production of natural gas from a well generally declines over time until the well can no longer economically produce natural gas and is plugged and abandoned. Failure to connect new wells to APL’s gathering systems could, therefore, result in the amount of natural gas APL gathers declining substantially over time and could, upon exhaustion of the current wells, cause it to abandon one or more of its gathering systems and, possibly, cease operations. The primary factors affecting APL’s ability to connect new supplies of natural gas to its gathering systems include APL’s success in contracting for existing wells that are not committed to other systems, the level of drilling activity near its gathering systems and, in the Mid-Continent region, APL’s ability to attract natural gas producers away from its competitors’ gathering systems.

Over time, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. A decrease in exploration and development activities in the fields served by APL’s gathering and processing facilities could result if there is a sustained decline in natural gas prices which, in turn,

would lead to a reduced utilization of those assets. The decline in the credit markets, the lack of availability of credit, debt or equity financing and the decline in natural gas prices may result in a reduction of producers’ exploratory drilling. APL has no control over the level of drilling activity in its service areas, the amount of reserves underlying wells that connect to its systems and the rate at which production from a well will decline. In addition, APL has no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, drilling costs, geological considerations, governmental regulation and the availability and cost of capital. In a low price environment, producers may determine to shut in wells already connected to APL’s systems until prices improve. Because APL’s operating costs are fixed to a significant degree, a reduction in the natural gas volumes it gathers or processes would result in a reduction in its gross margin and cash flows.

The amount of natural gas APL gathers or processes may be reduced if the natural gas liquids pipelines or fractionation facilities to which it delivers NGLs cannot or will not accept the NGLs.

If one or more of the pipelines or fractionation facilities to which APL delivers NGLs has service interruptions, capacity limitations or otherwise does not accept the NGLs APL sells to or transports on, and APL cannot arrange for delivery to other pipelines, the amount of NGLs APL processes, sells or transport may be reduced. Since APL’s revenues depend upon the volumes of NGLs it sells or transports, this could result in a material reduction in its gross margin and cash flows.

The amount of natural gas APL gathers or processes may be reduced if the intrastate and interstate pipelines to which APL delivers gas cannot or will not accept the gas.

APL’s gathering systems principally serve as intermediate transportation facilities between wells connected to APL’s systems and the intrastate or interstate pipelines to which APL delivers natural gas. If one or more of these pipelines has service interruptions, capacity limitations or otherwise does not accept the natural gas APL gathers, and APL cannot arrange for delivery to other pipelines, local distribution companies or end users, the amount of natural gas APL gathers may be reduced. Since APL’s revenues depend upon the volumes of natural gas it gathers, this could result in a material reduction in APL’s gross margin and cash flows.

If APL is unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, then its cash flows could be reduced.

The construction of additions to APL’s existing gathering assets may require it to obtain new rights-of-way before constructing new pipelines. APL may be unable to obtain rights-of-way to connect new natural gas supplies to its existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for APL to obtain new rights-of-way or to renew existing rights-of-way. If the cost of obtaining new rights-of-way or renewing existing rights-of-way increases, then its cash flows could be reduced.

The success of APL’s Mid-Continent operations depends upon its ability to continually find and contract for new sources of natural gas supply.

APL’s agreements with most of the producers with which its Mid-Continent operations do business generally do not require them to dedicate significant amounts of undeveloped acreage to APL’s systems. While APL does have some undeveloped acreage dedicated on its systems, most notably with its partner Pioneer on its Midkiff/Benedum system, APL does not have assured sources to provide it with new wells to connect to its Mid-Continent gathering systems. Failure to connect new wells to APL’s Mid-Continent operations will, as described in “—The amount of natural gas APL gathers will decline over time unless it is able to attract new wells to connect to its gathering systems,” above, will reduce APL’s gross margin and cash flows.

APL’s Mid-Continent operations currently depend on certain key producers for their supply of natural gas; the loss of any of these key producers could reduce its revenues.

During 2010, Apache, Inc., Bluestem Gas Marketing, Chesapeake Energy Corporation, COG Operating LLC, Endeavor Energy Resources LP, Pioneer, Prime Operating Company, Range Resources, Sandridge Exploration and Production, LLC and XTO Energy Inc. accounted for a significant amount of APL’s Mid-Continent operations natural gas supply. If these producers reduce the volumes of natural gas that they supply to APL, APL’s gross margin and cash flows would be reduced unless it obtains comparable supplies of natural gas from other producers.

The curtailment of operations at, or closure of, any of APL’s processing plants could harm its business.

If operations at any of APL’s processing plants were to be curtailed, or closed, whether due to accident, natural catastrophe, environmental regulation or for any other reason, APL’s ability to process natural gas from the relevant gathering system and, as a result, its ability to extract and sell NGLs, would be harmed. If this curtailment or stoppage were to extend for more than a short period, APL’s gross margin and cash flows would be materially reduced.

APL may face increased competition in the future in its Mid-Continent operations.

APL’s Mid-Continent operations face competition for well connections. Carrera Gas Company, Copano Energy, LLC, DCP Midstream, LLC, Enogex, LLC and ONEOK, Inc., operate competing gathering systems and processing plants in APL’s Velma service area. DCP Midstream, Hiland Partners, Mustang Fuel Corporation, ONEOK Partners and SemGas, L P operate competing gathering systems and processing plants APL’s Chaney Dell service area. DCP Midstream, Southern Union Company, Targa Resources and West Texas Gas operate competing gathering systems and processing plants in APL’s Midkiff/Benedum service area. Some of APL’s competitors have greater financial and other resources than APL does. If these companies become more active in APL’s Mid-Continent service areas, it may not be able to compete successfully with them in securing new well connections or retaining current well connections. If APL does not compete successfully, the amount of natural gas APL gathers, processes and treats will decrease, reducing its gross margin and 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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the risk that reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

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mistaken assumptions about revenues and costs, including synergies;

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significant increases in APL’s indebtedness and working capital requirements;

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delays in obtaining any required regulatory approvals or third party consents;

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the imposition of conditions on any acquisition by a regulatory authority;

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

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the assumption of unknown liabilities;

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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;

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customer or key employee losses at the acquired businesses; and

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the failure to realize expected growth or profitability.

The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition. Further, APL’s future acquisition costs may be higher than those it has achieved historically. Any of these factors could adversely impact APL’s future growth and its ability to make or increase distributions.

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

APL has an active, on-going program to identify potential acquisitions. APL’s integration of previously independent operations with its own can be a complex, costly and time-consuming process. The difficulties of combining these systems with its existing systems include, among other things:

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operating a significantly larger combined entity;

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

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integrating personnel with diverse business backgrounds and organizational cultures;

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consolidating operational and administrative functions;

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integrating pipeline safety-related records and procedures;

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

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

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customer or key employee loss from the acquired businesses;

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a significant increase in our indebtedness; and

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potential environmental or regulatory liabilities and title problems.

APL’s investment and the additional overhead costs it incurs to grow its NGL business may not deliver the expected incremental volume or cash flow. Costs incurred and liabilities assumed in connection with the acquisition and increased capital expenditures and overhead costs incurred to expand its operations could harm its business or future prospects, and result in significant decreases in its gross margin and cash flows.

APL’s construction of new assets may not result in revenue increases and is subject to regulatory, environmental, political, legal and economic risks, which could impair its results of operations and financial condition.

One of the ways APL may grow its business is through the construction of new assets. The construction of additions or modifications to its existing systems and facilities, and the construction of new assets, involve numerous regulatory, environmental, political and legal uncertainties beyond APL’s control and require the expenditure of significant amounts of capital. Any projects APL undertakes may not be completed on schedule at the budgeted cost, or at all. Moreover, APL’s revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if APL expands a gathering system, the construction may occur over an extended period of time, and it will not receive any material increases in revenues until the project is completed. Moreover, APL may construct facilities to capture anticipated future growth in production in a region in which growth does not materialize. Since APL is not engaged in the exploration for, and development of, natural gas reserves, it often does not have access to estimates of potential reserves in an area before

constructing facilities in the area. To the extent APL relies on estimates of future production in its decision to construct additions to its systems, the estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve APL’s expected investment return, which could impair its results of operations and financial condition. In addition, APL’s actual revenues from a project could materially differ from expectations as a result of the price of natural gas, the NGL content of the natural gas processed and other economic factors described in this section.

APL continues to expand the natural gas gathering systems surrounding its facilities in order to maximize plant throughput. In addition to the risks discussed above, expected incremental revenue from recent projects could be reduced or delayed due to the following reasons:

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difficulties in obtaining capital for additional construction and operating costs;

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difficulties in obtaining permits or other regulatory or third-party consents;

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additional construction and operating costs exceeding budget estimates;

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revenue being less than expected due to lower commodity prices or lower demand;

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difficulties in obtaining consistent supplies of natural gas; and

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terms in operating agreements that are not favorable to APL.

APL may not be able to execute its growth strategy successfully.

APL’s strategy contemplates substantial growth through both the acquisition of other gathering systems and processing assets and the expansion of its existing gathering systems and processing assets. APL’s growth strategy involves numerous risks, including:

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APL may not be able to identify suitable acquisition candidates;

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APL may not be able to make acquisitions on economically acceptable terms for various reasons, including limitations on access to capital and increased competition for a limited pool of suitable assets;

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APL’s costs in seeking to make acquisitions may be material, even if it cannot complete any acquisition it has pursued;

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irrespective of estimates at the time it makes an acquisition, the acquisition may prove to be dilutive to earnings and operating surplus;

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APL may encounter delays in receiving regulatory approvals or may receive approvals that are subject to material conditions;

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APL may encounter difficulties in integrating operations and systems; and

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any additional debt APL incurs to finance an acquisition may impair its ability to service its existing debt.

Limitations on APL’s access to capital or the market for its common units will impair APL’s ability to execute its growth strategy.

APL’s ability to raise capital for acquisitions and other capital expenditures depends upon ready access to the capital markets. Historically, APL has financed its acquisitions, and to a much lesser extent, expansions of its gathering systems by bank credit facilities and the proceeds of public and private debt and equity offerings of its common units and preferred units of its operating partnership. If APL is unable to access the capital markets, it may be unable to execute its strategy of growth through acquisitions.

Regulation of APL’s gathering operations could increase its operating costs, decrease its revenues, or both.

Currently APL believes its gathering and processing of natural gas is exempt from FERC regulation under the Natural Gas Act of 1938. However, the implementation of new laws or policies, or changed interpretations of existing laws, could subject APL’s gathering and processing operations to regulation by FERC under the Natural Gas Act, the Natural Gas Policy Act, or other laws. APL expects that any such regulation could increase its costs, decrease its gross margin and cash flows, or both.

Even if APL’s gathering and processing operations are not generally subject to regulation under the Natural Gas Act, FERC regulation will still affect APL’s business and the market for its products. FERC’s policies and practices affect a range of natural gas pipeline activities. Among these are FERC policies on interstate natural gas pipeline open access transportation, ratemaking, capacity release, environmental protection and market center promotion, which indirectly affect intrastate markets. FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. We cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.

Since federal law generally leaves any economic regulation of natural gas gathering to the states, state and local regulations may also affect APL’s business. Matters subject to regulation include conditions of access, rates, terms of service and safety. For example, APL’s gathering lines are subject to ratable take, common purchaser and similar statutes in one or more jurisdictions in which APL operates. Common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer, while ratable take statutes generally require gatherers to take, without discrimination, natural gas production that may be tendered to the gatherer for handling. Kansas, Oklahoma and Texas have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and discrimination with respect to rates or terms of service. Should a complaint be filed or regulation by the Texas Railroad Commission, Oklahoma Corporation Commission or Kansas Corporation Commission become more active, APL’s revenues could decrease. Collectively, all of these statutes restrict APL’s right as an owner of gathering facilities to decide with whom it contracts to purchase or gathers natural gas.

Compliance with pipeline integrity regulations issued by the DOT and state agencies could result in substantial expenditures for testing, repairs and replacement.

DOT and state agency regulations require pipeline operators to develop integrity management programs for transportation pipelines located in “high consequence areas.” The regulations require operators to:

•

perform ongoing assessments of pipeline integrity;

•

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

•

improve data collection, integration and analysis;

•

repair and remediate the pipeline as necessary; and

•

implement preventative and mitigating actions.

The cost of implementing integrity management program testing along certain segments of APL’s pipeline should not have a material effect on its results of operations. This does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be necessary as a result of the testing program. Such costs could be substantial.

APL’s midstream natural gas operations may incur significant costs and liabilities resulting from a failure to comply with new or existing environmental regulations or a release of hazardous substances into the environment.

The operations of APL’s gathering systems, plant and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. These laws and regulations may restrict or impact APL’s business activities in many ways, including restricting the manner in which it disposes of substances, requiring remedial action to remove or mitigate contamination, or requiring capital expenditures to comply with control requirements. Failure to comply with these laws and regulations may trigger a variety of administrative, civil or 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 impose strict, joint and several liability for costs required to clean up and restore sites where substances and wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury or property damage allegedly caused by the release of pollutants or wastes into the environment.

There is inherent risk of the incurrence of environmental costs and liabilities in APL’s business due to its handling of natural gas and other petroleum products, air emissions related to our operations, historical industry operations including releases of substances into the environment, and waste disposal practices. For example, an accidental release from one of APL’s pipelines or processing facilities could subject it to substantial liabilities arising from environmental cleanup, restoration costs and natural resource damages, 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, it is possible that more stringent laws, regulations or enforcement policies could significantly increase APL’s compliance costs, and the cost of any necessary remediation. APL may not be able to recover some or any of these costs from insurance.

APL’s midstream natural gas operations may incur significant costs and liabilities resulting from new environmental regulations related to climate change.

Federal and state governments are considering and/or implementing measures to reduce emissions of greenhouse gases, primarily through the planned development of a greenhouse gas cap and trade program. As an alternative to the cap and trade program, the EPA may implement greenhouse gas reduction through traditional construction and operating permit programs. APL could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from its operations or from combustion of fuels APL processes. In addition, APL’s operations could face additional taxes and higher costs of doing business. Although APL would not be impacted to a greater degree than other similarly situated gatherers and processors of natural gas or NGLs, a stringent greenhouse gas control program could result in a significant effect on our cost of doing business.

Litigation or governmental regulation relating to environmental protection and operational safety may result in substantial costs and liabilities.

APL’s operations are subject to federal and state environmental laws under which owners of natural gas pipelines can be liable for clean-up costs and penalties in connection with any pollution caused by their

pipelines. APL may also be held liable for clean-up costs resulting from pollution which occurred before its acquisition of a gathering system. In addition, APL is subject to federal and state safety laws that dictate the type of pipeline, quality of pipe protection, depth of pipelines, methods of welding and other construction-related standards. Any violation of environmental, construction or safety laws could impose substantial liabilities and costs on APL.

APL is also subject to the requirements of OSHA and comparable state statutes. Any violation of OSHA could impose substantial costs on APL.

We cannot predict whether or in what form any new legislation or regulatory requirements might be enacted or adopted, nor can we predict APL’s future costs of compliance. In general, we expect that new regulations would increase APL’s operating costs and, possibly, require it to obtain additional capital to pay for improvements or other compliance action necessitated by those regulations.

APL is subject to operating and litigation risks that may not be covered by insurance.

APL’s operations are subject to all operating hazards and risks incidental to gathering and processing natural gas and NGLs. These hazards include:

•

damage to pipelines, plants, related equipment and surrounding properties caused by floods and other natural disasters;

•

inadvertent damage from construction and farm equipment;

•

leakage of natural gas, NGLs and other hydrocarbons;

•

fires and explosions;

•

other hazards, including those associated with high-sulfur content, or sour gas, that could also result in personal injury and loss of life, pollution and suspension of operations; and

•

acts of terrorism directed at APL’s pipeline infrastructure, production facilities and surrounding properties.

As a result, APL may be a defendant in various legal proceedings and litigation arising from its operations. APL may not be able to maintain or obtain insurance of the type and amount desired at reasonable rates. As a result of market conditions, premiums and deductibles for some of APL’s insurance policies have increased substantially, and could escalate further. In some instances, insurance could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers are now requiring broad exclusions for losses due to war risk and terrorist acts. If APL were to incur a significant liability for which it was not fully insured, its gross margin and cash flows would be materially reduced.

APL’s control of the Chaney Dell and Midkiff/Benedum systems is limited by provisions of the limited liability company operating agreements with Anadarko and, with respect to the Midkiff/Benedum system, the operation and expansion agreement with Pioneer.

The managing member of each of the limited liability companies which owns the interests in the Chaney Dell and Midkiff/Benedum systems is APL’s subsidiary. However, the consent of Anadarko is required for specified extraordinary transactions, such as admission of new members, engaging in transactions with APL’s affiliates not approved by the company conflicts committee, incurring debt outside the ordinary course of business and disposing of company assets above specified thresholds. The Midkiff/Benedum system is also governed by an operation and expansion agreement with Pioneer which gives system owners having at least a 60% interest in the system the right to approve the annual operating budget and capital investment budget and to

impose other limitations on the operation of the system. Thus, a holder of a greater than 40% interest in the system would effectively have a veto right over the operation of the system. Pioneer currently owns an approximate 27% interest in the system.

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:

•

the allocation of shared overhead expenses to APL and us;

•

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

•

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;

•

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

•

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

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 of Unit Ownership

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.

APL or we may no longer be qualified as a partnership or the current law may change causing APL or us to be treated as a corporation for tax purposes.

The value of our investment in APL depends largely on it being treated as a partnership for federal income tax purposes, which requires that 90% or more of APL’s gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code. Qualifying income is defined as income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil, or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy, and timber). APL may not meet this requirement or current law may change so as to cause, in either event, APL to be treated as a corporation for federal income tax purposes or otherwise subject to federal income tax. Moreover, the anticipated after-tax benefit of an investment in our common units depends largely on us 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 matter affecting us.

If APL were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to us would generally be taxed again as corporate dividends, and no income, gains, losses, deductions or credits would flow through to us. As a result, there would be a material reduction in our anticipated cash flow, likely causing a substantial reduction in the value of our units.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate. Distributions to our unit holders would generally be taxed again as corporate dividends, and no income, gains, losses, deductions or credits would flow through to our unit holders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unit holders would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in our anticipated cash flow, likely causing a substantial reduction in the value of our units.

Current law may change, causing us or APL to be treated as a corporation for federal and/or state income tax purposes or otherwise subjecting us or APL to entity level taxation. For example, 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 or APL as an entity, the cash available for distribution to our unit holders 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 may be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the tax liability, which results from the taxation of 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.

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.

We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect 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.

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 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 jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, 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. Each of those states, except Texas, currently imposes a personal income tax. We or APL may do business or own property in other states in the future. It is the responsibility of each unitholder to file all United States federal, 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 Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely affected, and the costs of any such contest will reduce cash available for distributions to our unitholders.

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 our positions. A court may not agree with some or all of our positions. Any contest with the IRS may materially and adversely impact the market for our common units and the prices at which they trade. In addition, we will bear the costs of any contest with the IRS thereby reducing the cash available for distribution to our unitholders.

APL has adopted certain valuation methodologies that may result in a shift of income, gain, loss or 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 or APL’s unitholders. It also could affect the amount of gain on the sale of common units by our unitholders or APL’s unitholders and could have a negative impact on the value of our common units or those of APL or result in audit adjustments to the tax returns of our or APL’s 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.

ITEM 2.

PROPERTIES

A description of our properties is contained within Item 1, “Business.”

ITEM 3.

LEGAL PROCEEDINGS

Following the November 9, 2010 announcement (the “Announcement”) that ATLS had entered into a definitive agreement to be acquired by Chevron Corporation (the “Merger”) and that we and APL agreed to enter into separate transactions with ATLS relating to certain ATLS natural gas reserves and other assets and fee revenues, and APL’s interest in Laurel Mountain (the “Transactions”), with each of the Transactions and the Merger to be cross-conditioned on the completion of the others, a purported class action was filed on November 15, 2010, in Delaware Chancery Court on behalf of a class of ATLS shareholders, Katsman v. ATLS, et al., C.A. No. 5990-VCL. The complaint named us and APL and alleges that the ATLS directors violated their fiduciary duties in connection with the proposed Merger and that we, APL, and Chevron aided and abetted the alleged breaches of fiduciary duty, and requested, among other relief, injunctive relief and damages. This lawsuit was consolidated in Delaware Chancery with other class actions that have been filed against ATLS and its directors, among others. On December 28, 2010, the plaintiffs filed an amended complaint in which all claims against us and APL were dropped.

Additionally, following the Announcement, a purported shareholder derivative case was filed on November 16, 2010, in the Western District of Pennsylvania federal court, Ussach v. ATLS, et al., C.A. No. 2:10-cv-1533. The complaint is asserted derivatively on behalf of APL and names ATLS, Atlas Pipeline GP, and members of the Managing Board of Atlas Pipeline GP as defendants (“Defendants”) and alleges that Defendants have violated their fiduciary duties in connection with the proposed sale to ATLS of APL’s interest in Laurel Mountain and that ATLS has been unjustly enriched. In the complaint, among other relief, the plaintiff requests damages and equitable and injunctive relief, as well as restitution and disgorgement from the individual defendants. On February 22, 2011, the plaintiff voluntarily dismissed its complaint without prejudice. We have not received an indication whether the plaintiff intends to reassert its claim in another forum. In any event, the defendants believe the claims are without merit.

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 are listed on the New York Stock Exchange under the symbol “AHD.” At the close of business on February 22, 2011, the closing price for the common units was $14.90 and there were 215 record holders, one of which is the holder for all beneficial owners who hold in street name.

The following table sets forth the range of high and low sales prices of our common units and distributions declared by quarter per unit on our common limited partner units for the years ended December 31, 2010 and 2009:


	High		Low		Distributions Declared
2010
Fourth Quarter	$	15.44	$	8.86	$	0.07
Third Quarter		9.88		3.76		0.05
Second Quarter		6.80		3.67		0.00
First Quarter		7.45		5.14		0.00
2009
Fourth Quarter	$	7.00	$	3.11	$	0.00
Third Quarter		4.78		2.88		0.00
Second Quarter		5.56		1.46		0.00
First Quarter		7.03		0.77		0.00

Our Cash Distribution Policy

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:

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provide for the proper conduct of our business;

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

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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. We make distributions of available cash to common unitholders regardless of whether the amount distributed is less than the minimum quarterly distribution. 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.

For information concerning units authorized for issuance under our long-term incentive plan, see “Item 12: Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.”

APL’s Cash Distribution Policy

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, rate refunds 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.


APL Minimum Distributions Per Unit Per Quarter		Percent of APL Available Cash in Excess of Minimum Allocated to APL’s General Partner⁽¹⁾
$	0.42		15	%
$	0.52		25	%
$	0.60		50	%

(1)	Percent allocated to APL’s General Partner includes 2% general partner interest in addition to incentive distributions.

APL makes distributions of available cash to common unitholders regardless of whether the amount distributed is less than the minimum quarterly distribution. 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. In July 2007, Atlas Pipeline GP, as general partner and the holder of all of APL’s incentive distribution rights, agreed to allocate a portion of its incentive distribution rights back to APL as set forth in the IDR Adjustment Agreement. APL declared no general partner’s incentive distributions for the years ended December 31, 2010 and 2009.

For information concerning units authorized for issuance under APL’s long-term incentive plan, see “Item 12: Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.”

ITEM 6.

SELECTED FINANCIAL DATA

On July 26, 2006, ATLS contributed its ownership interests in Atlas Pipeline GP, its then wholly-owned subsidiary and APL’s general partner, to us. Concurrent with this transaction, we issued 3,600,000 common units, representing a then 17.1% ownership interest in us, in an initial public offering at a price of $23.00 per unit, with substantially all of the net proceeds from this offering distributed to ATLS. As of December 31, 2010, we had no separate operating activities apart from those conducted by APL, and our cash flows consisted of distributions from APL on our partnership interests in it, including the incentive distribution rights that we own.

Prior to our initial public offering, the consolidated financial statements include only the results of Atlas Pipeline GP, which are presented on a consolidated basis including the financial statements of APL and are adjusted for the non-controlling limited partners’ interest in APL. Subsequent to our initial public offering, the consolidated financial statements contain our consolidated financial results including the accounts of Atlas Pipeline GP and APL. The non-controlling limited partner interest in APL is reflected as an expense or income in our consolidated results of operations and as a liability on our consolidated balance sheets. Throughout this section, when we refer to “our” consolidated financial statements, we are referring to the consolidated results for us and Atlas Pipeline GP, including APL’s financial results, adjusted for non-controlling partners’ interest in APL’s net income (loss).

The following table should be read together with our consolidated financial statements and notes thereto included within “Item 8: Financial Statements and Supplementary Data” and “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report. We have derived the selected financial data set forth in the table for each of the years ended December 31, 2010, 2009 and 2008 and at December 31, 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, 2007 and 2006 from our consolidated financial statements, which were audited by Grant Thornton LLP and are not included within this report.

The selected financial data set forth in the table include our historical consolidated financial statements, which have been adjusted to reflect the following:

•

On September 16, 2010, APL completed the sale of its Elk City and Sweetwater, Oklahoma natural gas gathering systems (collectively “APL’s Elk City”). We have retrospectively adjusted our prior period consolidated financial statements to reflect the amounts related to the operations of APL’s Elk City as discontinued operations.

•

We reclassified a portion of our historical income, within our consolidated statements of operations, to “Transportation, Processing and Other Fees” for fee-based revenues which were previously reported within “Natural Gas and Liquids” and “Other income (loss), net.” This reclassification was made in order to provide clarity between commodity-based and fee-based revenue.

•

We reclassified “Equity income in joint venture” and “Gain (loss) on asset sales and other” to line items separate from total revenue and other income (loss) net. Additionally, we reclassified unrecognized economic impact of APL’s Chaney Dell and Midkiff/Benedum acquisition, long-lived asset impairment loss and goodwill impairment loss, net of associated non-controlling interest from reconciliation of EBITDA to reconciliation to adjusted EBITDA.


	Years Ended December 31,
	2010			2009⁽¹⁾			2008⁽¹⁾			2007⁽¹⁾⁽²⁾			2006⁽¹⁾
	(in thousands, except per unit data)
Statements of operations data:
Revenue:
Natural gas and liquids	$	890,048		$	636,231		$	1,078,714		$	527,094		$	174,221
Transportation, compression and other fees		41,093			59,075			87,442			50,695			31,263
Other income (loss), net		4,422			(23,061	)		36,602			(99,253	)		6,490

Total revenue and other income (loss), net		935,563			672,245			1,202,758			478,536			211,974

Costs and expenses:
Natural gas and liquids		720,215			527,730			900,460			407,994			147,583
Plant operating		48,670			45,566			47,371			22,974			6,484
Transportation and compression		1,061			6,657			11,249			6,235			4,946
General and administrative⁽³⁾		36,394			38,931			633			63,175			20,032
Depreciation and amortization		74,897			75,684			71,764			34,453			9,495
Goodwill and other asset impairment loss		—			10,325			615,724			—			—
Gain on early extinguishment of debt		—			—			(19,867	)		—			—
Acquisition costs		1,167			—			—			—			—
Interest		94,807			106,531			91,731			65,092			25,675

Total costs and expenses		977,211			811,424			1,719,065			599,923			214,215

Equity income in joint venture		4,920			4,043			—			—			—
Gain (loss) on asset sales and other		(10,729	)		108,947			—			—			—

Income (loss) from continuing operations		(47,457	)		(26,189	)		(516,307	)		(121,387	)		(2,241	)
Income (loss) from discontinued operations		321,155			84,148			(93,802	)		(23,641	)		35,334

Net income (loss)		273,698			57,959			(610,109	)		(145,028	)		33,093
(Income) loss attributable to non-controlling interests⁽⁴⁾		(4,738	)		(3,176	)		22,781			(3,940	)		(118	)
(Income) loss attributable to non-controlling interest in Atlas Pipeline Partners, L.P.⁽⁵⁾		(241,026	)		(50,748	)		513,675			133,321			(16,335	)

Net income (loss) attributable to common limited partners/owners	$	27,934		$	4,035		$	(73,653	)	$	(15,647	)	$	16,640


Allocation of net income (loss) attributable to common limited partners/owners:
Portion applicable to owners’ interest (period prior to the initial public offering on July 26, 2006)	$	—		$	—		$	—		$	—		$	10,236
Portion applicable to common limited partners’ interest (period subsequent to the initial public offering on July 26, 2006)		27,934			4,035			(73,653	)		(15,647	)		6,404

Net income (loss) attributable to common limited partners/owners	$	27,934		$	4,035		$	(73,653	)	$	(15,647	)	$	16,640


Allocation of net income (loss) attributable to common limited partners/owners:
Continuing operations	$	(11,994	)	$	(7,768	)	$	(61,165	)	$	(12,940	)	$	(202	)
Discontinued operations		39,928			11,803			(12,488	)		(2,707	)		6,606

	$	27,934		$	4,035		$	(73,653	)	$	(15,647	)	$	6,404

Net income (loss) attributable to common limited partners per unit:
Basic
Continuing operations	$	(0.43	)	$	(0.28	)	$	(2.23	)	$	(0.55	)	$	(0.01	)
Discontinued operations		1.44			0.43			(0.45	)		(0.11	)		0.31

	$	1.01		$	0.15		$	(2.68	)	$	(0.66	)	$	0.30

Diluted
Continuing operations	$	(0.43	)	$	(0.28	)	$	(2.23	)	$	(0.55	)	$	(0.01	)
Discontinued operations		1.44			0.43			(0.45	)		(0.11	)		0.31

	$	1.01		$	0.15		$	(2.68	)	$	(0.66	)	$	0.30


		Years Ended December 31,
		2010			2009⁽¹⁾			2008⁽¹⁾			2007⁽¹⁾⁽²⁾			2006⁽¹⁾
		(in thousands, except operating data)
Balance sheet data (at period end):
Property, plant and equipment, net		$	1,341,002		$	1,327,704		$	1,415,517		$	1,258,602		$	204,362
Total assets			1,767,118			2,138,118			2,418,984			2,875,351			787,134
Total debt, including current portion			601,389			1,286,438			1,539,427			1,254,426			324,083
Total Equity/owners’ equity			1,005,329			690,679			609,852			1,246,525			379,121

Cash flow data:
Net cash provided by (used in):
Operating activities		$	106,574		$	53,507		$	(54,837	)	$	104,586		$	61,087
Investing activities			594,753			241,030			(292,970	)		(2,024,676	)		(104,499	)
Financing activities			(702,183	)		(300,719	)		342,602			1,930,696			27,264

Other financial data (unaudited):
Gross margin from continuing operations⁽⁶⁾		$	210,580		$	163,677		$	273,493		$	167,525		$	59,811
EBITDA ⁽⁷⁾			451,577			257,000			(410,499	)		(35,357	)		81,785
Adjusted EBITDA ⁽⁷⁾			207,504			173,900			321,631			182,600			87,039

Maintenance capital expenditures		$	10,921		$	3,750		$	4,787		$	6,383		$	1,886
Expansion capital expenditures			35,715			106,524			176,869			40,268			24,498

Total capital expenditures		$	46,636		$	110,274		$	181,656		$	46,651		$	26,384


Operating data (unaudited):
Appalachia:
Laurel Mountain system:
Average throughput volume – (MCFD)	109,480					96,975			85,348			68,715			61,892
Tennessee system
Average throughput volume – (MCFD)	8,740					7,907			1,951			—			—
Mid-Continent:
Velma system:
Gathered gas volume (MCFD)	84,455					76,378			63,196			62,497			60,682
Processed gas volume (MCFD)	78,606					73,940			60,147			60,549			58,132
Residue Gas volume (MCFD)	64,138					58,350			47,497			47,234			45,466
NGL volume (BPD)	9,218					8,232			6,689			6,451			6,423
Condensate volume (BPD)	416					377			280			225			193
Chaney Dell system⁽⁸⁾:
Gathered gas volume (MCFD)	228,684					270,703			276,715			259,270			—
Processed gas volume (MCFD)	214,695					215,374			245,592			253,523			—
Residue Gas volume (MCFD)	193,200					228,261			239,498			221,066			—
NGL volume (BPD)	12,395					13,418			13,263			12,900			—
Condensate volume (BPD)	697					824			791			572			—
Midkiff/Benedum system⁽⁸⁾:
Gathered gas volume (MCFD)	178,111					159,568			144,081			147,240			—
Processed gas volume (MCFD)	163,475					149,656			135,496			141,568			—
Residue Gas volume (MCFD)	105,982					101,788			92,019			94,281			—
NGL volume (BPD)	26,678					21,261			19,538			20,618			—
Condensate volume (BPD)	1,289					1,265			1,142			1,346			—

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City.

(2)

Includes APL’s acquisition of control of a 100% interest in the Chaney Dell natural gas gathering system and processing plants and a 72.8% undivided joint interest in the Midkiff/Benedum natural gas gathering system and processing plants on July 27, 2007, representing approximately five months’ operations for the year ended December 31, 2007. Operating data for the Chaney Dell and Midkiff/Benedum systems represent 100% of its operating activity.

(3)	Includes non-cash compensation (income) expense of $4.9 million, $1.3 million, ($31.3) million, $39.0 million, and $6.8 million for the years ended December 31, 2010, 2009, 2008, 2007, and 2006, respectively.

(4)	For the years ended December 31, 2010, 2009, 2008 and 2007, this represents Anadarko’s non-controlling interest in the operating results of the Chaney Dell and Midkiff/Benedum systems, which APL acquired on July 27, 2007.

(5)	Represents the non-controlling interests in the net income (loss) of APL associated with the third-party unitholders of APL.

(6)

We define gross margin from continuing operations as natural gas and liquids revenue and transportation, compression and other fees less purchased product costs. Product costs include the cost of natural gas and NGLs that APL purchases from third parties, subject to certain non-cash adjustments. Gross margin, as we define it, does not include plant operating expenses; transportation and compression expenses; and hedge gain/(losses) related to ineffective or undesignated hedges, as movements in gross margin generally do not result in directly correlated movements in these categories. Plant operating and transportation and compression expenses generally include the costs required to operate and maintain our pipelines and processing facilities, including salaries and wages, repair and maintenance expense, real estate taxes and other overhead costs. Our management views gross margin as an important performance measure of core profitability for our operations and as a key component of our internal financial reporting. We believe that investors benefit from having access to the same financial measures that our management uses. The following table reconciles our revenues and costs to gross margin from continuing operations (in thousands):

RECONCILIATION OF GROSS MARGIN FROM CONTINUING OPERATIONS


	Years Ended December 31,
	2010			2009⁽¹⁾			2008⁽¹⁾			2007^{(1) (2)}			2006⁽¹⁾
	(in thousands)
Revenue:
Natural gas and liquids	$	890,048		$	636,231		$	1,078,714		$	527,094		$	174,221
Transportation, compression and other fees		41,093			59,075			87,442			50,695			31,263

Total revenue for gross margin		931,141			695,306			1,166,156			577,789			205,484
Natural gas and liquids costs:		(720,215	)		(527,730	)		(900,460	)		(407,994	)		(147,583	)
Adjustments:
Effect of prior period items⁽⁹⁾		—			—			—			—			1,090
Non-cash linefill loss (gain)⁽¹⁰⁾		(346	)		(3,899	)		7,797			(2,270	)		820

Gross margin	$	210,580		$	163,677		$	273,493		$	167,525		$	59,811

(7)

EBITDA represents net income (loss) before net interest expense, income taxes, and depreciation and amortization. Adjusted EBITDA is calculated by adding to EBITDA other non-cash items such as compensation expenses associated with unit issuances, principally to directors and employees, impairment charges and other cash items such as the non-recurring cash derivative early termination expense (see “Item 8: Financial Statements and Supplementary Data –Note 11). EBITDA and Adjusted EBITDA are not intended to represent cash flow and do not represent the measure of cash available for distribution. Our method of computing EBITDA and Adjusted EBITDA may not be the same method used to compute similar measures reported by other companies. The Adjusted EBITDA calculation below is similar to the Consolidated EBITDA (see “Item 8: Financial Statements and Supplementary Data –Note 13) calculation that is utilized within financial covenants under APL’s credit facility, with the exception that Adjusted EBITDA includes (i) EBITDA from the discontinued operations related to the sale of APL’s Elk City; (ii) the unrecognized economic impact of APL’s Chaney Dell and Midkiff/Benedum acquisition, and (iii) other non-cash items specifically excluded under APL’s credit facility.

Certain items excluded from EBITDA and Adjusted EBITDA are significant components in understanding and assessing an entity’s financial performance, such as their cost of capital and its tax structure, as well as historic costs of depreciable assets. We have included information concerning EBITDA and Adjusted EBITDA because they provide investors and management with additional information to better understand our operating performance and are presented solely as a supplemental financial measure. EBITDA and Adjusted EBITDA should not be considered as alternatives to, or more meaningful than, net income or cash flow as determined in accordance with generally accepted accounting principles or as indicators of our operating performance or liquidity. The following table reconciles net income (loss) to EBITDA and EBITDA to Adjusted EBITDA (in thousands):

RECONCILIATION OF EBITDA AND ADJUSTED EBITDA


	Years Ended December 31,
	2010			2009⁽¹⁾			2008⁽¹⁾			2007^{(1) (2)}			2006⁽¹⁾
	(in thousands)
Net income (loss)	$	273,698		$	57,959		$	(610,109	)	$	(145,028	)	$	33,093
Adjustments:
Effect of prior period items⁽⁹⁾		—			—			—			—			1,090
(Income) loss attributable to non-controlling interests from continuing operations⁽⁴⁾		(4,738	)		(3,176	)		22,781			(3,940	)		—
Interest expense		94,807			106,531			91,731			65,092			25,675
Other interest		844			608			—			—			—
Depreciation and amortization		74,897			75,684			71,764			34,453			9,495
Discontinued operations interest expense, depreciation, and amortization		12,069			19,394			13,334			14,066			12,432

EBITDA	$	451,577		$	257,000		$	(410,499	)	$	(35,357	)	$	81,785


Adjustments:
Equity income in joint venture		(4,920	)		(4,043	)		—			—			—
Distributions from joint venture		11,066			4,310			—			—			—
Unrecognized economic impact of Chaney Dell and Midkiff/Benedum acquisition⁽¹¹⁾		—			—			—			10,423			—
Long-lived asset impairment loss		—			10,325			—			—			—
Goodwill impairment loss, net of associated non-controlling interest		—			—			585,053			—			—
Gain on asset sales and other⁽¹²⁾		(301,373	)		(162,518	)		—			—			—
Non-cash (gain) loss on derivatives		(10,381	)		75,018			(113,640	)		99,543			163
Non-recurring net cash derivative early termination expense⁽¹³⁾		22,401			2,260			102,146			—			—
Premium expense on derivative instruments		21,123			9,693			3,736			—			—
Non-cash compensation (income) expense		4,729			1,265			(31,345	)		38,966			6,750
Non-cash line fill loss (gain)⁽¹⁰⁾		(346	)		(3,899	)		7,797			(2,270	)		820
Other non-cash items⁽¹⁴⁾		—			—			—			1,414			—
Discontinued operations adjustments⁽¹⁵⁾		13,628			(15,511	)		178,383			69,881			(2,479	)

Adjusted EBITDA	$	207,504		$	173,900		$	321,631		$	182,600		$	87,039

(8)	Volumetric data for APL’s Chaney Dell and Midkiff/Benedum systems for the year ended December 31, 2007 represents volumes recorded for the 158-day period from July 27, 2007, the date of APL’s acquisition, through December 31, 2007.

(9)	During 2006, APL identified measurement reporting inaccuracies on three newly installed pipeline meters. To adjust for such inaccuracies, which relate to natural gas volume gathered during 2005, APL recorded an adjustment to increase natural gas and liquids cost of goods sold.

(10)	Includes the non-cash impact of commodity price movements on APL’s pipeline linefill.

(11)

The acquisition of APL’s Chaney Dell and Midkiff/Benedum systems was consummated on July 27, 2007, although the acquisition’s effective date was July 1, 2007. As such, APL receives the economic benefits of ownership of the assets as of July 1, 2007. However, in accordance with generally accepted accounting principles, APL has only recorded the results of the acquired assets commencing on the closing date of the acquisition. The economic benefits of ownership APL received from the acquired assets from July 1 to July 27, 2007 were recorded as a reduction of the consideration paid for the assets.

(12)

For the year ended December 31, 2010, includes the gain on the sale of APL’s Elk City and expenses related to the pending sale of APL’s non-controlling interest in Laurel Mountain. For the year ended December 31, 2009, includes the APL’s gain on the sale of assets to the Laurel Mountain joint venture and the gain on sale of APL’s NOARK gas gathering and interstate pipeline system.

(13)

During the years ended December 31, 2010, 2009 and 2008, APL made net payments of $33.7 million, $5.0 million and $274.0 million, respectively, which resulted in a net cash expense recognized of $33.7 million, $5.0 million and $197.6 million, respectively, related to the early termination of derivative contracts that were principally entered into as proxy hedges for the prices received on the ethane and propane portion of our NGL equity volume. These derivative contracts were put into place simultaneously with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007. The 2008 settlements were funded through APL’s June 2008 issuance of 5.75 million common limited partner units in a public offering and issuance of 1.39 million common limited partner units to us and ATLS in a private placement. In connection with this transaction, APL also entered into an amendment to its credit facility to revise the definition of Consolidated EBITDA to allow for the add-back of charges relating to the early termination of certain derivative contracts for debt covenant calculation purposes when the early termination of derivative contracts is funded through the issuance of common equity.

(14)	Includes the cash proceeds received from the sale of APL’s Enville plant and the non-cash loss recognized within our statements of operations.

(15)	Includes non-cash (gain) loss on derivatives, non-recurring cash derivative early termination and premium expense on derivative instruments recorded in discontinued operations.

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 our consolidated financial statements and related notes thereto appearing elsewhere in this report.

General

Overview

We are a publicly-traded Delaware limited partnership, formerly known as Atlas Pipeline Holdings, L.P. (NYSE: AHD). Our wholly-owned subsidiary, Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP”), a Delaware limited liability company, is the general partner of Atlas Pipeline Partners, L.P. (“APL” – NYSE: APL). APL is a midstream energy service provider engaged in the gathering, processing and treating of natural gas in the Mid-Continent and Appalachia regions. Our cash generating assets at December 31, 2010 consisted solely of our interests in APL, a publicly traded Delaware limited partnership. Our interests in APL consist of a 100% ownership in Atlas Pipeline GP which together with us, owns at December 31, 2010:

•

a 2.0% general partner interest in APL, which entitles it to receive 2.0% of the cash distributed by APL; and

•

In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see “—Atlas Pipeline Partners, L.P.”), Atlas Pipeline GP agreed to allocate up to $3.75 million per quarter after it receives the initial $7.0 million per quarter of incentive distribution rights (the “IDR Adjustment Agreement”); and

•

5,754,253 common units of APL, representing approximately 10.8% of the outstanding common units of APL, or a 10.6% limited partner interest in APL.

While we, like APL, are structured as a limited partnership, our capital structure and cash distribution policy differ materially from those of APL. Most notably, our general partner does not have an economic interest in us and is not entitled to receive any distributions from us, and our capital structure does not include incentive distribution rights. Therefore, all of our distributions are made on our common units, which is our only class of security outstanding.

•

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

•

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

•

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

We pay to our unitholders, on a quarterly basis, distributions equal to the cash we receive from APL and operations, less certain reserves for expenses and other uses of cash, including:

•

our general and administrative expenses, including expenses as a result of being a publicly traded partnership;

•

capital contributions to maintain or increase our ownership interest in APL; and

•

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

Atlas Pipeline Partners, L.P.

APL’s business is conducted in the midstream segment of the natural gas industry through two reportable segments: Mid-Continent and Appalachia.

APL’s Mid-Continent operations, as of December 31, 2010, owns, has interests in and operates five natural gas processing plants with aggregate capacity of approximately 520 MMCFD. These facilities are connected to approximately 8,600 miles of active natural gas gathering systems located in Oklahoma, Kansas and Texas, which gathers gas from wells and central delivery points to APL’s natural gas processing and treating plants, as well as third-party pipelines.

Laurel Mountain has natural gas gathering agreements with Atlas Energy Resources, LLC (“Atlas Energy Resources”), a wholly-owned subsidiary of Atlas Energy, Inc. (“Atlas Energy, Inc.” or “ATLS”), a formerly publicly-traded company, under which Atlas Energy Resources is obligated to pay a gathering fee that is generally the greater of $0.35 per MCF or 16% of the realized sales price (except that a lower fee applies with respect to specific wells subject to certain existing contracts or in the event Laurel Mountain fails to perform specified obligations).

Financial Presentation

As of December 31, 2010, we had no separate operating activities apart from those conducted by APL, and our cash flows consisted of distributions from APL on our partnership interests in it, including the incentive distribution rights that we own. The non-controlling limited partner interest in APL is reflected as an expense in our consolidated results of operations and as a component of equity on our consolidated balance sheets. Throughout this section, when we refer to “our” consolidated financial statements, we are referring to the consolidated results for us and Atlas Pipeline GP, including APL’s financial results, adjusted for non-controlling partners’ interest in APL’s net income (loss).

Recent Events

On January 7, 2010, APL executed amendments to warrants previously issued, along with its common units, in connection with a private placement to institutional investors that closed on August 20, 2009. The common units and warrants were issued and sold in a transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended. 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 per unit from $6.35 per unit. In connection with the amendments, the holders of the warrants exercised all of the warrants for cash, which resulted in the issuance of 2,689,765 APL common units and net cash proceeds to APL 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 (see “–APL Term Loan and Revolving Credit Facility”) and to fund the early termination of certain derivative agreements (see “Item 8. Financial Statements and Supplementary Data –Note 11”).

On March 31, 2010, APL and Atlas Pipeline Operating Partnership, L.P. amended their respective partnership agreements to temporarily waive the requirement that Atlas Pipeline GP make aggregate cash contributions of approximately $0.3 million, which was required in connection with its issuance of an aggregate of 2,689,765 of its common units upon the exercise of certain warrants in January 2010. The waiver remained in effect until we received aggregate distributions from APL sufficient to fund the required capital contribution. During the waiver period, the aggregate ownership percentage attributable to our general partner interest in APL was reduced to 1.9%. Both amendments were approved by APL’s conflicts committee and managing board, and were effective as of January 11, 2010. On November 30, 2010, we made capital contribution of $0.3 million to APL to increase our general partner interest in APL back to 2.0%.

On June 15, 2010, APL’s unitholders approved the terms of the APL 2010 Long Term Incentive Plan (“2010 LTIP”), which provides for the grant of options, phantom units, unit awards, unit appreciation rights and distribution equivalents. The total number of APL common units that may be issued under the APL 2010 LTIP is 3,000,000 (see “Item 8. Financial Statements and Supplementary Data –Note 16”).

On June 30, 2010, APL sold 8,000 newly created 12% Cumulative Class C Preferred Units of limited partner interest (the “APL Class C Preferred Units”) to ATLS for cash consideration of $1,000 per APL Class C Preferred Unit resulting in total proceeds of $8.0 million (see “–APL Preferred Units”).

On July 19, 2010, we entered into an amended and consolidated note with ATLS. The note consolidated in one instrument the debt we owed to ATLS under our $15 million subordinate note and the guaranty note, both dated June 1, 2009, and ATLS’s advance of $16 million under its guaranty of our credit facility, which facility was repaid in full on April 13, 2010. The original principal amount of the note was $33.4 million. The interest rate is 12% per annum which, prior to demand by ATLS for cash payment, will be payable, at our option, by accruing such interest and adding the amount to the principal amount of the note on a quarterly basis. The note is payable on demand (See “Item 8: Financial Statements and Supplementary Data –Note 8”).

On September 1, 2010, APL entered into an amendment to its credit facility agreement, which, among other things, revised the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to premiums associated with hedging agreements and to exclude the net gains or losses attributable to a disposition of assets other than in the ordinary course of business (see “–APL Term Loan and Revolving Credit Facility”).

On September 16, 2010, APL completed the sale of its Elk City and Sweetwater, Oklahoma natural gas gathering systems, the related processing and treating facilities (including the Prentiss treating facility and the Nine Mile processing plant, collectively “Elk City”) to a subsidiary of Enbridge Energy Partners, L.P. (NYSE: EEP) for $682 million in cash, excluding working capital adjustments and transaction costs (See “Item 8. Financial Statements and Supplementary Data –Note 4”). APL utilized the proceeds from the sale to repay its

senior secured term loan and a portion of its indebtedness under its revolving credit facility (see “–APL Term Loan and Revolving Credit Facility”).

On November 8, 2010, we entered into a Transaction Agreement (the “AHD Transaction Agreement”), with ATLS and Atlas Energy Resources pursuant to which, among other things (1) we agreed to acquire ATLS’s investment partnership business and certain other assets and assume certain liabilities in exchange for our newly issued common units and cash (the “Asset Acquisition”); (2) ATLS will contribute our general partner, Atlas Pipeline Holdings GP to us, so that Atlas Pipeline Holdings GP becomes our wholly-owned subsidiary; (3) our limited partnership agreement will be amended and restated; (4) we will repay all amounts outstanding under our amended and consolidated note to ATLS and (5) ATLS will distribute to its stockholders all our common units that it holds, including the newly issued common units that it receives in the Asset Acquisition.

On November 8, 2010, concurrently with entering into the AHD Transaction Agreement and the Laurel Mountain Purchase Agreement (referenced below), ATLS entered into an Agreement and Plan of Merger with Chevron Corporation, a Delaware corporation (“Chevron”), pursuant to which, among other things ATLS will become a wholly-owned subsidiary of Chevron.

On November 8, 2010, APL entered into a definitive agreement with ATLS and Atlas Energy Resources (the “Laurel Mountain Sales Agreement”), pursuant to which APL agreed to sell its 49% non-controlling interest in Laurel Mountain to Atlas Energy Resources for $403 million in cash, subject to certain closing adjustments. APL intends to utilize the proceeds from the sale to repay its indebtedness, to fund future capital expenditures, and for general corporate purposes.

On November 8, 2010, ATLS, our majority unitholder, delivered a written consent approving the adoption of a new equity plan. This action by ATLS is sufficient for our unitholders to approve the adoption of the new equity plan without the vote of any other unitholder. The new equity plan will become effective upon the closing of the AHD Transactions. The new equity plan is intended to promote our interests by providing to officers, employees and directors of our general partner, and employees of its affiliates, consultants and joint venture partners who perform services for our general partner or us, incentive awards for superior performance that are based on our common units. The new equity plan is intended to enhance the ability of our general partner and its affiliates to attract and retain the services of individuals who are essential for the growth and profitability of our general partner and us and to encourage them to devote their best efforts to the businesses of our general partner and us and advancing the interests of our general partner and us. Grants made under the new equity plan will be determined by our board of directors or a committee of our board of directors or equivalent. An aggregate of 3,500,000 common units may be issued under this plan in the form of options, restricted units and phantom units.

On November 15, 2010, Atlas Pipeline Holdings II, LLC (“AHD Sub”) exercised its option to redeem its 15,000 12.0% cumulative preferred units for cash at the liquidation value of $1,000 per unit, or $15.0 million, plus $0.2 million accrued dividends. Concurrently, APL redeemed its 15,000 units of Class B Preferred Units held by us for cash at the liquidation value of $1,000 per unit, or $15.0 million plus $0.2 million accrued dividends, in accordance with the terms of the amended preferred units’ certificate. There are no longer any APL Class B Preferred Units outstanding (See “–APL Preferred Units”).

On November 22, 2010, APL completed its consent solicitation to amend certain provisions of the Indenture governing APL’s 8.125% Senior Notes, dated as of December 20, 2005, by and among APL, Atlas Pipeline Finance Corporation, the Subsidiary Guarantors party thereto and U.S. Bank National Association. After receiving the requisite consents, APL entered into a Supplemental Indenture to the Indenture, dated as of November 22, 2010, which amended and restated the definition of “Permitted Investments” under Section 1.01 of the Indenture to permit APL, or its subsidiaries, to make capital contributions to Laurel Mountain through December 31, 2011.

On December 22, 2010, APL entered into an amended and restated credit agreement (see “–APL Term Loan and Revolving Credit Facility”) which, among other changes:

•

set the maturity date of APL’s revolving credit facility to December 22, 2015;

•

reduced APL’s revolving credit facility from $380.0 million to $350.0 million;

•

eliminated the 2.0% per annum floor previously applied to adjusted LIBOR;

•

removed restrictions on APL making investments in the Laurel Mountain joint venture if specified financial thresholds are not met;

•

eliminated the requirements that APL meet specified financial thresholds in order to be permitted to make distributions to its unitholders;

•

eliminated the limits on APL’s annual capital expenditures if specified financial thresholds are not met; and

•

adjusted the maximum Consolidated Funded Debt Ratio (“leverage ratio”) to 5.0 to 1.0; the maximum Consolidated Senior Secured Funded Debt Ratio (“senior secured leverage ratio”) to 3.0 to 1.0; and the minimum Interest Coverage Ratio to 2.5 to 1.0.

Subsequent Events

Atlas Energy, Inc. Asset Acquisition

On February 17, 2011, we completed the Asset Acquisition contemplated by the AHD Transaction Agreement, pursuant to which we purchased from ATLS (1) its investment partnership business, including the operations of its investment partnerships in Michigan, Pennsylvania, Tennessee, Indiana and Colorado, (2) its oil and gas exploration, development and production activities conducted in Tennessee, Indiana and Colorado, certain shallow wells and leases in New York and Ohio and certain well interests in Pennsylvania, and (3) its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (we refer to the businesses described in (1) through (3), together, as the “transferred business”). The assets we purchased include certain ATLS subsidiaries (referred to as the “purchased entities”) and certain other assets relating to the transferred business, including the names and marks of ATLS and its subsidiaries (which we refer to as the “purchased assets”). ATLS also transferred certain current liabilities that were assumed by us in the Asset Acquisition subject to post-closing.

As consideration for the Asset Acquisition, we paid to ATLS $30 million in cash, issued 23,379,384 new common units and assumed all of the historical and future liabilities associated with the transferred business. In addition, we repaid the $36.0 million outstanding under our amended and consolidated note owed to ATLS.

New Credit Facility

We financed the cash portion of Asset Acquisition consideration and the repayment of the ATLS note by drawing on a $70 million revolving credit facility, administered by Citibank, N.A. that we entered into at closing. Our credit facility matures in February 2012 and bears interest, at our option, at either (i) adjusted LIBOR (plus the applicable margin, as defined in the credit facility) or (ii) the higher of the federal funds rate plus 0.5% or the Citibank, N.A. prime rate (each plus the applicable margin). Borrowings under our credit facility are secured by a first-priority lien on a security interest in substantially all of our other assets, including a pledge of 3,500,000 of our APL common units, and are guaranteed by Atlas Pipeline Holdings GP and our operating subsidiaries (excluding Atlas Pipeline GP and APL and its subsidiaries). Our credit facility contains customary covenants, including restrictions on our ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to our unitholders if an event of default exists or would result from such distribution; or enter into a merger or sale of substantially all of our property or assets, including the sale or transfer of interests in our subsidiaries; and requirements that we maintain certain financial ratios. The events which constitute an event of default under our 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 us in excess of a specified amount, and a change of control. We may borrow under our credit facility for working capital and general business purposes.

Laurel Mountain Sale

Concurrently with our completion of the Asset Acquisition, APL completed its sale to Atlas Energy Resources of its 49% non-controlling interest in Laurel Mountain (the “Laurel Mountain Sale”) for $413.5 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 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.

Atlas Energy, Inc. Merger

Concurrently with our completion of the Asset Acquisition and APL’s completion of the Laurel Mountain Sale, ATLS completed its merger transaction with Chevron Corporation, pursuant to which, among other things, ATLS became a wholly-owned subsidiary of Chevron (the “Chevron Merger”).

Atlas Pipeline Holdings, L.P. Name Change

On February 18, 2011, subsequent to the Asset Acquisition and the Chevron Merger, we changed our name to Atlas Energy, L.P.

Significant Acquisitions

Contractual Revenue Arrangements

APL’s principal revenue is generated from the gathering and sale of natural gas, NGLs 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.

APL’s revenue consists of the sale of natural gas and liquids and the fees earned from its gathering and processing operations. 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 (See “Item 8. Financial Statements and Supplementary Data –Note 2 -Revenue Recognition” for further discussion of contractual revenue arrangements).

In APL’s Appalachia segment, substantially all of the natural gas Laurel Mountain gathers is for Atlas Energy Resources under contracts in which Laurel Mountain earns a fee equal to a percentage, generally 16%, of the gross sales price for natural gas, inclusive of the effects of financial and physical hedging, subject, in most cases, to a minimum of $0.35 per MCF, depending on the ownership of the well. The balance of the natural gas gathered by Laurel Mountain is for third-party operators generally under fixed-fee contracts.

Recent Trends and Uncertainties

The midstream natural gas industry links the exploration and production of natural gas and the delivery of its components to end-use markets and provides natural gas gathering, compression, dehydration, treating, conditioning, processing, fractionation and transportation services. This industry group is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

APL faces competition for in obtaining natural gas supplies for its processing and related services operations. Competition for natural gas supplies is based primarily on the location of gas-gathering facilities and gas-processing plants, operating efficiency and reliability, and the ability to obtain a satisfactory price for products recovered. Competition for customers is based primarily on price, delivery capabilities, quality of assets, flexibility, service history and maintenance of high-quality customer relationships. Many of APL’s competitors operate as master limited partnerships and enjoy a cost of capital comparable to and, in some cases lower than, APL. Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than APL. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. We believe the primary difference between APL and some of its competitors is that APL provides an integrated and responsive package of midstream services, while some of its competitors provide only certain services. We believe that offering an integrated package of services, while remaining flexible in the types of contractual arrangements that APL offers producers, allows APL to compete more effectively for new natural gas supplies in its regions of operations.

As a result of APL’s POP and Keep-Whole contracts, its results of operations and financial condition substantially depend upon the price of natural gas, NGLs and crude oil (see “Item 8. Financial Statements and Supplementary Data –Note 2 –Revenue Recognition”). APL believes that future natural gas prices will be

influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. Based on historical trends, APL generally expects NGL prices to follow changes in crude oil prices over the long term, which APL believes will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. However, energy market uncertainty has negatively impacted North American drilling activity in the recent past. Lower drilling levels and shut in wells over a sustained period would have a negative effect on natural gas volumes gathered and processed.

APL is exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. APL closely monitors the risks associated with commodity price changes on APL’s future operations and, where appropriate, uses various commodity-based derivative instruments such as natural gas, crude oil and NGL contracts to hedge a portion of the value of APL’s assets and operations from such price risks. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk -Commodity Price Risk” for further discussion of commodity price risk.

Currently, there is a significant level of uncertainty in the financial markets. This uncertainty presents additional potential risks to us and APL. These risks include the availability and costs associated with our and APL’s borrowing capabilities and APL’s ability to raise additional capital, and an increase in the volatility of the price of our and APL’s common units. While we and APL have no definitive plans to access the capital markets, should we or APL decide to do so in the near future, the terms, size, and cost of new debt or equity could be less favorable than in previous transactions.

Results of Operations

The following table illustrates selected pricing and volumetric information related to APL’s reportable segments for the periods indicated:


	Years Ended December 31,
	2010		2009		2008
Pricing:

Mid-Continent Weighted Average Prices:
NGL price per gallon – Conway hub	$	0.92	$	0.68	$	1.19
NGL price per gallon – Mt. Belvieu hub		1.03		0.77		1.29

Natural gas sales ($/Mcf):
Velma		4.14		3.24		7.38
Chaney Dell		4.13		3.25		6.98
Midkiff/Benedum		4.10		3.35		7.44
Weighted Average		4.12		3.28		7.19

NGL sales ($/gallon):
Velma		0.90		0.69		1.23
Chaney Dell		0.94		0.69		1.23
Midkiff/Benedum		1.02		0.83		1.27
Weighted Average		0.97		0.73		1.25

Condensate sales ($/barrel):
Velma		78.28		59.80		100.65
Chaney Dell		72.67		55.07		97.29
Midkiff/Benedum		75.57		60.35		105.44
Weighted Average		75.08		58.21		100.85


	Years Ended December 31,
	2010		2009		2008
Operating data:

Appalachia:
Laurel Mountain system:
Average throughput volumes (MCFD)		109,480		96,975		85,348
Tennessee system:
Average throughput volumes (MCFD)		8,740		7,907		1,951

Mid-Continent:
Velma system:
Gathered gas volume (MCFD)		84,455		76,378		63,196
Processed gas volume (MCFD)		78,606		73,940		60,147
Residue Gas volume (MCFD)		64,138		58,350		47,497
NGL volume (BPD)		9,218		8,232		6,689
Condensate volume (BPD)		416		377		280
Chaney Dell system:
Gathered gas volume (MCFD)		228,684		270,703		276,715
Processed gas volume (MCFD)		214,695		215,374		245,592
Residue Gas volume (MCFD)		193,200		228,261		239,498
NGL volume (BPD)		12,395		13,418		13,263
Condensate volume (BPD)		697		824		791
Midkiff/Benedum system:
Gathered gas volume (MCFD)		178,111		159,568		144,081
Processed gas volume (MCFD)		163,475		149,656		135,496
Residue Gas volume (MCFD)		105,982		101,788		92,019
NGL volume (BPD)		26,678		21,261		19,538
Condensate volume (BPD)		1,289		1,265		1,142

Financial Presentation

On September 16, 2010, APL completed the sale of APL’s Elk City (see “–Recent Events”). As such, we have adjusted the prior period consolidated financial information presented to reflect the amounts related to the operations of APL’s Elk City as discontinued operations.

We have reclassified a portion of our historical income, within our consolidated statements of operations, to “Transportation, Processing and Other Fees” for fee-based revenues which were previously reported within “Natural Gas and Liquids” and “Other income (loss), net. This reclassification was made in order to provide clarity between commodity-based and fee-based revenues.

We have reclassified “Equity income in joint venture” and “Gain (loss) on asset sales and other” to line items separate from “Total revenue and other income (loss) net.”

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Revenue. The following table details the variances between the years ended 2010 and 2009 for revenues (in thousands):


	Years Ended December 31,
	2010		2009⁽¹⁾			Variance			Percent Variance
Revenue:
Natural gas and liquids	$	890,048	$	636,231		$	253,817			39.9	%
Transportation, compression and other fee revenue		41,093		59,075			(17,982	)		(30.4	)%
Other income (loss), net		4,422		(23,061	)		27,483			119.2	%

Total Revenue and other income (loss), net	$	935,563	$	672,245		$	263,318			39.2	%

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City.

Natural gas and liquids revenue for the year ended December 31, 2010 increased primarily due to a favorable price change as a result of higher realized commodity prices, combined with lower qualified hedge losses. Gains and losses within other comprehensive income (loss), related to previously designated hedges, are recorded within natural gas and liquids revenue, while all other gains and losses related to derivative instruments are recorded within other income (loss), net. APL enters into derivative instruments solely to hedge its forecasted natural gas, NGLs and condensate sales and natural gas purchases against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under “Item 7A: Quantitative and Qualitative Disclosures About Market Risk.”

APL’s Midkiff/Benedum system’s NGL production volume for the year ended December 31, 2010 increased when compared to the prior year period, representing an increase in production efficiency primarily due to the start-up of the new Consolidator plant, which provides greater recoveries increasing the liquid volumes extracted from the natural gas stream. NGL production volume on APL’s Chaney Dell system decreased for the year ended December 31, 2010 compared to the prior year due to a decreased number of well connects over the past year, resulting from lower capital spending. NGL production on APL’s Velma system increased for the year ended December 31, 2010 when compared to the prior year period primarily due to increased gathered gas volume resulting from the completion of the Madill-to-Velma gas gathering pipeline.

Transportation, processing and other fee revenue decreased primarily due to a $16.9 million decrease from APL’s Appalachia system as a result of APL’s May 2009 contribution of the majority of the system to Laurel Mountain, a joint venture in which APL has a 49% non-controlling ownership interest. After the contribution, we recognized APL’s ownership interest in the net income of Laurel Mountain as equity income on our consolidated statements of operations.

Other income (loss), net, including the impact of certain gains and losses recognized on derivatives, had a favorable movement for the year ended December 31, 2010 due primarily to a $63.6 million favorable variance in non-cash mark-to-market adjustments on derivatives, offset by $32.3 million unfavorable variance of net cash derivative expense related to the early termination of a portion of APL’s derivative contracts (see “Item 8: “Financial Statements and Supplementary Data –Note 11”).

Costs and Expenses. The following table details the variances between the years ended 2010 and 2009 for costs and expenses (in thousands):


	Years Ended December 31,
	2010		2009⁽¹⁾		Variance			Percent Variance
Costs and Expenses:
Natural gas and liquids	$	720,215	$	527,730	$	192,485			36.5	%
Plant operating		48,670		45,566		3,104			6.8	%
Transportation and compression		1,061		6,657		(5,596	)		(84.1	)%
General and administrative		36,394		38,931		(2,537	)		(6.5	)%
Depreciation and amortization		74,897		75,684		(787	)		(1.0	)%
Goodwill and other asset impairment loss		—		10,325		(10,325	)		(100.0	)%
Acquisition costs		1,167		—		1,167			100.0	%
Interest expense		94,807		106,531		(11,724	)		(11.0	)%

Total Costs and Expenses	$	977,211	$	811,424	$	165,787			20.4	%

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City.

Natural gas and liquids cost of goods sold for the year ended December 31, 2010 increased primarily due to an increase in average commodity prices in comparison to the prior year period, as discussed above in revenues.

Transportation and compression expenses for the year ended December 31, 2010 decreased due to APL’s contribution of the Appalachia system to Laurel Mountain.

Goodwill and other asset impairment loss for the year ended December 31, 2009 was due to an impairment of certain gas plant and gathering assets as a result of APL’s annual review of long-lived assets.

Acquisition costs for the year ended December, 31, 2010 represents costs related to the pending acquisition of assets from ATLS. (see “–Subsequent Events”).

Interest expense for the year ended December 31, 2010 decreased primarily due to a $9.5 million decrease in APL’s interest rate swap expense due to the interest rate swaps expiring in April 2010 and due to a $5.8 million decrease in interest expense associated with APL’s term loan, partially offset by a $2.6 million higher amortization of deferred finance costs. 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 APL’s Elk City (see “–Recent Events”). The increased amortization of deferred finance costs was due principally to accelerated amortization associated with the retirement of APL’s term loan.

Other income items. The following table details the variances between the years ended 2010 and 2009 for other income items (in thousands):


	Years Ended December 31,
	2010			2009⁽¹⁾			Variance			Percent Variance
Equity income in joint venture	$	4,920		$	4,043		$	877			21.7	%
Gain (loss) on asset sales and other		(10,729	)		108,947			(119,676	)		(109.8	)%
Income from discontinued operations		321,155			84,148			237,007			281.7	%
Income attributable to non-controlling interests		(4,738	)		(3,176	)		(1,562	)		(49.2	)%
Income attributable to non-controlling interests in APL		(241,026	)		(50,748	)		(190,278	)		(374.9	)%

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City.

Equity income represents APL’s ownership interest in the net income of Laurel Mountain and it increased for the year ended December 31, 2010 as a result of the prior year including only seven months of operations.

Gain (loss) on asset sales and other for the years ended December 31, 2010 and 2009 includes amounts associated with APL’s contribution of a 51% ownership interest in its Appalachia natural gas gathering system in 2009 and the pending sale of APL’s 49% interest in Laurel Mountain in 2010 (See “–Subsequent Events”).

Income from discontinued operations increased for the year ended December 31, 2010 primarily due to the $312.1 million gain on sale of APL’s Elk City in the current year period compared to the $51.1 million gain on sale of APL’s NOARK gas gathering and interstate pipeline which was sold in May 2009.

Income attributable to non-controlling interests increased for the year ended December 31, 2010 primarily due to higher net income for APL’s Chaney Dell and Midkiff/Benedum joint ventures, which were formed to accomplish APL’s acquisition of control of the respective systems. The increase in net income of the Chaney Dell and Midkiff/Benedum joint ventures was principally due to higher gross margins on the sale of commodities resulting from higher prices. The non-controlling interest expense represents Anadarko Petroleum Corporation’s interest in the net income of the Chaney Dell and Midkiff/Benedum joint ventures.

Income attributable to non-controlling interest in APL, which represents the allocation of APL’s earnings to its non-affiliated limited partners, increased for the year ended December 31, 2010 due to an increase in APL’s net earnings between periods.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Revenue. The following table details the variances between the years ended 2009 and 2008 for revenues (in thousands):


	Years Ended December 31,
	2009⁽¹⁾			2008⁽¹⁾		Variance			Percent Variance
Revenue:
Natural gas and liquids	$	636,231		$	1,078,714	$	(442,483	)		(41.0	)%
Transportation, compression and other fee revenue		59,075			87,442		(28,367	)		(32.4	)%
Other income (loss), net		(23,061	)		36,602		(59,663	)		(163.0	)%

Total Revenue and other income (loss),net	$	672,245		$	1,202,758	$	(530,513	)		(44.1	)%

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City.

Natural gas and liquids revenue for the year ended December 31, 2009 decreased primarily due to decreases in production revenue from APL’s Chaney Dell system of $234.0 million, APL’s Midkiff/Benedum system of $148.9 million, and APL’s Velma system of $95.0 million, which were all impacted by lower average commodity prices and changes in volumes in comparison to the prior year.

Processed natural gas volume on the Chaney Dell system decreased for the year ended December 31, 2009 compared to the prior year partially due to shut-in wells as a result of lower gas prices. The Chaney Dell system increased its NGL production volume for the year ended December 31, 2009 compared to the prior year, representing an increase in production efficiency. The Midkiff/Benedum system’s processed natural gas volume and NGL production volume for the year ended December 31, 2009 increased compared to the prior year, representing an increase in production efficiency partially due to the start-up of the new Consolidator plant. Processed natural gas volume and NGL production volume on the Velma system increased for the year ended December 31, 2009 from the prior year mainly due to the new gathering line from the Madill area.

Transportation, compression and other fee revenue for the year ended December 31, 2009 decreased

primarily due to a $26.2 million decrease from APL’s Appalachia system as a result of APL’s May 2009 contribution of the majority of the system to Laurel Mountain, after which we recognized APL’s ownership interest in the net income of Laurel Mountain as equity income on our consolidated statements of operations.

Other loss, net, including the impact of certain gains and losses recognized on derivatives for the year ended December 31, 2009, had an unfavorable movement due primarily to a $219.5 million unfavorable variance in non-cash mark-to-market adjustments on APL’s derivatives offset by $101.6 million favorable variance of net cash derivative expense related to the early termination of a portion of APL’s derivative contracts (see “Item 8: “Financial Statements and Supplementary Data –Note 11”) and an $55.2 million favorable movement in non-cash derivative gains related to the early termination of a portion of APL’s derivative contracts.

Costs and Expenses. The following table details the variances between the years ended 2009 and 2008 for costs and expenses (in thousands):


	Years Ended December 31,
	2009⁽¹⁾		2008⁽¹⁾			Variance			Percent Variance
Costs and Expenses:
Natural gas and liquids	$	527,730	$	900,460		$	(372,730	)		(41.4	)%
Plant operating		45,566		47,371			(1,805	)		(3.8	)%
Transportation and compression		6,657		11,249			(4,592	)		(40.8	)%
General and administrative		38,931		633			38,298			6050.2	%
Depreciation and amortization		75,684		71,764			3,920			5.5	%
Goodwill and other asset impairment loss		10,325		615,724			(605,399	)		(98.3	)%
Interest expense		106,531		91,731			14,800			16.1	%
Gain on early extinguishment of debt		—		(19,867	)		19,867			100.0	%

Total Costs and Expenses	$	811,424	$	1,719,065		$	(907,641	)		(52.8	)%

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City.

Natural gas and liquids cost of goods sold for the year ended December 31, 2009 decreased primarily due to a decrease in average commodity prices and changes in volumes in comparison to the prior year as discussed above in revenues. Transportation and compression expenses decreased due to APL’s contribution of its Appalachia system to Laurel Mountain.

General and administrative expense, including amounts reimbursed to affiliates, for the year ended December 31, 2009 increased primarily as a result of a $32.6 million increase in non-cash compensation expense primarily due to a $36.3 million net mark-to-market gain recognized during the year ended December 31, 2008 principally associated with the vesting of certain APL common unit awards that were based on the financial performance of certain assets during 2008. The mark-to-market gain was the result of a significant change in APL’s common unit market price at December 31, 2008 when compared with the December 31, 2007 price, which was utilized in the estimate of the non-cash compensation expense for these awards. These common unit awards were issued during the year ended December 31, 2009.

Interest expense for the year ended December 31, 2009 increased mainly due to an $9.1 million increase in interest expense associated with outstanding borrowings on APL’s revolving credit facility, an $8.5 million increase in interest expense related to APL’s additional senior notes issued during June 2008 (see “–APL Senior Notes”) and a $2.1 million increase in the amortization of deferred finance costs due principally to accelerated amortization associated with the retirement of a portion of APL’s term loan with the proceeds from the sale of APL’s NOARK system, partially offset by a $5.9 million decrease in interest expense associated with APL’s senior secured term loan primarily due to the repayment of $273.7 million of indebtedness since December 2008 (see “–APL Term Loan and Revolving Credit Facility”) and lower unhedged interest rates.

Goodwill and other asset impairment loss for the year ended December 31, 2009 decreased compared to

the prior year. The asset impairment loss for the year ended December 31, 2009 was due to an impairment of certain APL gas plant and gathering assets as a result of APL’s annual review of long-lived assets. The impairment loss for the year ended December 31, 2008 was due to an impairment charge to APL’s goodwill from the reduction of APL’s estimate of the fair value of goodwill in comparison to its carrying amount at December 31, 2008. The estimate of fair value of goodwill was impacted by many factors, including the significant deterioration of commodity prices and global economic conditions during the fourth quarter of 2008. There were no goodwill impairments for the year ended December 31, 2009.

Gain on early extinguishment of debt for the year ended December 31, 2008 resulted from APL’s repurchase of approximately $60.0 million of its Senior Notes for an aggregate purchase price of approximately $40.1 million plus accrued interest of approximately $2.0 million. The notes repurchased were comprised of $33.0 million of APL’s 8.125% Senior Notes and approximately $27.0 million of APL’s 8.75% Senior Notes. All of the APL Senior Notes repurchased have been retired and are not available for re-issue.

Other income items. The following table details the variances between the years ended 2009 and 2008 for other income items (in thousands):


	Years Ended December 31,
	2009⁽¹⁾			2008⁽¹⁾			Variance			Percent Variance
Equity income in joint venture	$	4,043		$	—		$	4,043			100.0	%
Gain on asset sales and other		108,947			—			108,947			100.0	%
Income (loss) from discontinued operations		84,148			(93,802	)		177,950			189.7	%
(Income) loss attributable to non-controlling interests		(3,176	)		22,781			(25,957	)		(113.9	)%
(Income) loss attributable to non-controlling interests in APL		(50,748	)		513,675			(564,423	)		(109.9	)%

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City.

Equity income of $4.0 million for the year ended December 31, 2009 represents APL’s ownership interest in the net income of Laurel Mountain for the period from its formation on May 31, 2009 through December 31, 2009.

Gain on asset sales and other of $108.9 million for the year ended December 31, 2009 represents the gain recognized on APL’s contributions of a 51% ownership interest in its Appalachia natural gas gathering system to Laurel Mountain.

Income from discontinued operations consists of amounts associated with APL’s NOARK gas gathering and interstate pipeline system APL sold on May 4, 2009 and APL’s Elk City sold on September 16, 2010 (see “–Recent Events”). For the year ended December 31, 2009, income from discontinued operations increased due to a $114.3 million loss on APL’s Elk City operations in the prior year, primarily due to a $123.6 million dollar loss related to the early termination of certain derivatives in the prior year, and a $51.1 million gain recognized on the sale of APL’s NOARK system in 2009.

Income attributable to non-controlling interests for the year ended December 31, 2009 changed as a result of higher net income for APL’s Chaney Dell and Midkiff/Benedum joint ventures, which were formed to accomplish APL’s acquisition of control of the respective systems. The increase in net income of the Chaney Dell and Midkiff/Benedum joint ventures was principally due to the goodwill impairment charge in 2008 of $613.4 million for the goodwill originally recognized upon acquisition of these systems. The non-controlling interest expense represents Anadarko’s 5% interest in the net income of the Chaney Dell and Midkiff/Benedum joint ventures.

Income (loss) attributable to non-controlling interest in APL, which represents the allocation of APL’s

earnings to its non-affiliated limited partners, increased for the year ended December 31, 2009 compared with the prior year due to an increase in APL’s net earnings between periods.

Liquidity and Capital Resources

General

As of December 31, 2010, our primary sources of liquidity are distributions received with respect to our ownership interests in APL and cash on hand. Our primary cash requirements are for our general and administrative expenses, including expenses as a result of being a publicly traded partnership, capital contributions to APL to maintain or increase our ownership interest and quarterly distributions to our common unitholders. We expect to fund our general and administrative expenses through the retention of cash and we expect to fund our capital contributions to APL through the retention of cash from distributions received from APL. We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Our credit facility terminated on April 13, 2010 (see “–Our Credit Facility”). In connection with our June 1, 2009 amendment to our credit facility, we were required to immediately repay $30.0 million of then-outstanding $46.0 million of borrowings under the credit facility and were required to repay the balance of our outstanding borrowings by April 13, 2010. Payments were timely made by funding from ATLS under its guaranty of our obligations (see “–Our Demand Note with Atlas Energy, Inc.”). (See “Our Credit Facility” for a description of our new credit facility).

At December 31, 2010, we had a working capital deficit of $75.0 million compared with a working capital deficit of $63.5 million at December 31, 2009. We believe that we will have sufficient liquid assets, including our ownership of 5.8 million limited partner units in APL, to meet our financial commitments, debt service obligations, and possible contingencies for at least the next twelve-month period. However, we are subject to business and other risks that could adversely affect our cash flow. We may need to supplement our cash generation with proceeds from financing activities, including other borrowings and the issuance of additional limited partner units and the sale of our ownership interests in APL.

APL’s primary sources of liquidity are cash generated from operations and borrowings under its credit facility. APL’s primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures and quarterly distributions to its common unitholders and general partner. In general, we expect APL 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 the retention of cash and additional capital raising; and

•

debt principal payments through operating cash flows and refinancings as they become due, or by the issuance of additional limited partner units or APL asset sales.

At December 31, 2010, APL had $70.0 million of outstanding borrowings under its $350.0 million senior secured credit facility and $3.2 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheets, with $276.8 million of remaining committed capacity under the credit facility, subject to covenant limitations (see “–APL Term Loan and Revolving Credit Facility”). APL was in compliance with its credit facility’s covenants at December 31, 2010. At December 31, 2010, APL had a working capital deficit of $36.6 million compared with a $30.6 million working capital deficit at December 31,

2009. We believe that APL 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, APL is subject to business, operational and other risks that could adversely affect its cash flow. APL may need to supplement its cash generation with proceeds from financing activities, including borrowings under its credit facility and other borrowings, the issuance of additional limited partner units and sales of its assets.

Instability in the financial markets, as a result of recession or otherwise, may cause volatility in the markets and may impact the availability of funds from those markets. This may affect our and APL’s ability to raise capital and reduce the amount of cash available to fund our and APL’s operations. APL relies on its cash flow from operations and its credit facility to execute its growth strategy and to meet its financial commitments and other short-term liquidity needs. We or APL cannot be certain that additional capital will be available to the extent required and on acceptable terms.

Cash Flows – Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

The following table details the variances between the years ended 2010 and 2009 for cash flows (in thousands):


	Years Ended December 31,
	2010			2009			Variance			Percent Variance
Net cash provided by (used in):
Operating activities	$	106,574		$	53,507		$	53,067			99.2	%
Investing activities		594,753			241,030			353,723			146.8	%
Financing activities		(702,183	)		(300,719	)		(401,464	)		(133.5	)%

Net change in cash and cash equivalents	$	(856	)	$	(6,182	)	$	5,326			86.2	%

Net cash provided by operating activities for the year ended December 31, 2010 increased primarily due to a $47.0 million increase in net earnings from continuing operations, excluding non-cash charges, and a $24.9 million increase in cash flows from working capital changes, partially offset by an $18.8 million decrease in cash provided by discontinued operations. Net earnings from continuing operation, excluding non-cash charges, increased primarily due to a favorable gross margin in continuing operations of $46.9 million, mainly as a result of higher commodity prices.

Net cash provided by investing activities for the year ended December 31, 2010 increased as a result of the net proceeds of $676.8 million received from the sale of APL’s Elk City in 2010 compared to $292.0 million received from the sale of APL’s NOARK gas gathering and interstate pipeline system in the prior year period combined with the $89.5 million received from the sale of APL’s 51% interest in the Appalachia assets in the prior year period. Additionally, there was a $64.5 million decrease in capital expenditures compared to the prior year period (see further discussion of capital expenditures under “–Capital Requirements”).

Net cash used in financing activities for the year ended December 31, 2010 increased mainly due to a $280.0 million net increase in repayments of the outstanding principal balance on APL’s revolving credit facility and a $159.8 million increase in repayments of APL’s term loan. The increase in repayments of on APL’s term loan and revolving credit facility is principally due to the retirement of the term loan and a portion of APL’s revolving credit facility with proceeds from the sale of APL’s Elk City.

Cash Flows - Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

The following table details the variances between the years ended 2009 and 2008 for cash flows (in thousands):


	Years Ended December 31,
	2009			2008			Variance			Percent Variance
Net cash provided by (used in)
Operating activities	$	53,507		$	(54,837	)	$	108,344			197.6	%
Investing activities		241,030			(292,970	)		534,000			182.3	%
Financing activities		(300,719	)		342,602			(643,321	)		(187.8	)%

Net change in cash and cash equivalents	$	(6,182	)	$	(5,205	)	$	(977	)		(18.8	)%

Net cash provided by operating activities for the year ended December 31, 2009 increased due to a $256.6 million favorable movement in net earnings from continuing operations excluding non-cash charges, partially offset by a $127.7 million decrease in cash provided by discontinued operations and a $20.6 million decrease in cash flows from working capital changes. The increase in net earnings from continuing operations excluding non-cash charges was principally due to a $161.7 million decrease of net cash derivative expense including expenses related to the early termination of a portion of APL’s derivative contracts (see “Item 8: Financial Statements and Supplementary Data –Note 11”).

Net cash provided by investing activities for the year ended December 31, 2009 increased principally due to a $409.2 million increase in cash provided by discontinued operations, the net proceeds of $89.5 million received from the sale of APL’s Appalachia system assets and a $71.4 million decrease in capital expenditures, partially offset by a 2008 receipt of a $30.2 million cash reimbursement for state sales tax paid on APL’s 2007 transaction to acquire the Chaney Dell and Midkiff/Benedum systems and a 2008 period receipt of $1.3 million in connection with a post-closing purchase price adjustment of APL’s 2007 acquisition of the Chaney Dell and Midkiff/Benedum systems (see further discussion of capital expenditures under “–Capital Requirements”).

Net cash used in financing activities for the year ended December 31, 2009 decreased principally due to $244.9 million of net proceeds from APL’s issuance of 8.75% Senior Notes in 2008 (see “–APL Senior Notes”), a decrease of $235.8 million of net proceeds from the issuance of APL’s common units and a $232.0 million net decrease in borrowings under our and APL’s credit facilities.

Capital Requirements

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 APL’s maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented (in thousands):


	Years Ended December 31,
	2010		2009⁽¹⁾		2008⁽¹⁾
Maintenance capital expenditures	$	10,921	$	3,750	$	4,787
Expansion capital expenditures		35,715		106,524		176,869

Total	$	46,636		110,274	$	181,656

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City.

Expansion capital expenditures decreased for the year ended December 31, 2010, primarily due to the completion of APL’s Madill to Velma pipeline and the construction of the APL’s Consolidator gas plant in the prior year, compounded by a reduction of well connects in the current period. The increase in maintenance capital expenditures for the year ended December 31, 2010, was partially due to planned maintenance expense at the Waynoka plant plus fluctuations in the timing of other scheduled maintenance activity. As of December 31, 2010, APL has approved expenditures of approximately $32.4 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

Expansion capital expenditures decreased for the year ended December 31, 2009, due principally to the construction of the Madill to Velma pipeline during the year ended December 31, 2008 and decreases in capital expenditures related to the sale of APL’s 51% ownership interest in the Appalachia system. The decrease in maintenance capital expenditures for the year ended December 31, 2009 compared with the prior year was due to fluctuations in the timing of APL’s scheduled maintenance activity.

Our Credit Facility

On April 13, 2010, our credit facility was terminated. On June 1, 2009, we entered into an amendment to our credit facility agreement which, among other changes required us to immediately repay $30 million of the borrowings under the credit facility with scheduled payments on July 13, 2009, October 13, 2009, January 13, 2010 and the balance of the indebtedness to be paid on April 13, 2010. All payments were made by funding from ATLS under its guaranty of our obligations.

Our June 1, 2009 $30.0 million repayment was funded from the proceeds of (i) a loan from ATLS in the amount of $15.0 million (see “ –Our Demand Note with Atlas Energy, Inc.”) and (ii) the purchase by APL of $15.0 million of preferred equity in a newly created, wholly-owned subsidiary of ours, Atlas Pipeline Holdings II, LLC (“AHD Sub”). Additionally, ATLS guaranteed the remaining balance outstanding under the credit facility pursuant to a guarantee agreement with the administrative agent of the credit facility. In consideration for this guarantee, we issued to ATLS a promissory note (see “–Our Demand Note with Atlas Energy, Inc.”).

On February 17, 2011, we entered into a credit facility with Citibank, N.A., as administrative agent, in connection with the closing of the AHD Transactions (see “–Subsequent Events”). The credit facility provides for an initial borrowing base of $70 million and a maturity of February 2012. The credit facility also provides for the issuance of letters of credit, which would reduce our borrowing capacity. The borrowing base will be redetermined semi-annually, with the first redetermination to occur on May 1, 2011. In connection with each redetermination of the borrowing base, the administrative agent will propose a new borrowing base based upon, among other things, reserve reports and such other information as the administrative agent deems appropriate in its reasonable discretion and consistent with its normal oil and gas lending criteria as they exist at the particular time. If at any time the amount of loans and other extensions of credit outstanding under the credit facility exceeds the borrowing base, we may be required, among other things, to prepay loans under the credit facility and/or mortgage additional oil and gas properties. The borrowing base will be automatically reduced by a specified percentage of the proceeds from our issuance of senior notes, the incurrence of debt by certain subsidiary partnerships in excess of amounts set forth in the credit agreement or the sale of oil and gas properties with a value exceeding 10% of the then effective borrowing base.

Our obligations under the credit facility are secured by mortgages on our oil and gas properties and first priority security interests in substantially all of our assets, including all of our ownership interests in a majority of our material operating subsidiaries, other than Atlas Pipeline GP. Additionally, our obligations are guaranteed by certain of our material subsidiaries and may be guaranteed by our future material subsidiaries.

At our election, interest on borrowings under the credit facility is determined by reference to either LIBOR plus an applicable margin between 2.25% and 3.00% per annum or the alternate base rate (“ABR”) plus an applicable margin between 1.25% and 2.00% per annum. These margins will fluctuate based on the utilization of the facility. Interest is generally payable quarterly for ABR loans and at the applicable maturity date for LIBOR loans. We must pay a fee of 0.5% per annum on the unused portion of the borrowing base. We may borrow under the credit facility for, among other things, payments in connection with the AHD Transactions and working capital and general corporate purposes.

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 exists or an event of default under the credit agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that exceed specified terms or amounts or engage in certain asset dispositions including a sale of all or substantially all of our assets. The credit agreement also contains covenants that require us to maintain the following financial ratios:

•

a ratio of total debt (as defined in the credit agreement) to EBITDA (as defined in the credit agreement) greater than 3.5 to 1.0 as of the last day of any fiscal quarter ending on or after June 30, 2011; and

•

a ratio of consolidated current assets to consolidated current liabilities not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

Our Demand Note with Atlas Energy, Inc.

On June 1, 2009, in connection with our amendment of the credit facility, we borrowed $15.0 million from ATLS under a 12% per annum subordinate loan. We incurred interest expense of $1.0 million and $1.1 million on the subordinate loan during the years ended December 31, 2010 and 2009, respectively, which was included in interest expense on our statements of operations. The interest was added to the balance of the subordinate loan.

Also, on June 1, 2009, in consideration of ATLS’s guaranty of the indebtedness under our credit facility, we entered into a guaranty note with ATLS. ATLS funded $8.0 million in both the years ended December 31, 2010 and 2009, under its guaranty of our obligations. We incurred $0.1 million and $0.2 million in fees and interest under the guaranty note during the years ended December 31, 2010 and 2009, respectively, which was included in interest expense on our statements of operations. The interest and fees were added to the balance of the guaranty note.

The subordinate loan and guaranty note matured on April 14, 2010, the day following the date that we repaid all outstanding borrowings under our credit facility. On July 19, 2010, we entered into an amended and consolidated demand note (the “Note”) with ATLS to consolidate in one instrument the debt owed to ATLS under the $15.0 million subordinate loan, the $0.3 million guaranty note and the $16.0 million advance under ATLS’s guaranty of our credit facility, plus accrued interest. The initial principal of the Note is $33.4 million; the interest rate on the Note is 12% per annum, which, prior to demand by ATLS for cash payment, will be payable by accruing such interest and adding the amount to the principal amount of the Note on a quarterly basis; and the Note is payable on demand. During the year ended December 31, 2010, we accrued $2.0 million in interest expense, which was added to the principal amount of the Note. As of December 31, 2010, we reflected $35.4 million in the current portion of long term debt on our consolidated balance sheets related to our obligations to ATLS. On February 17, 2011, we paid the outstanding balance of the Note as part of the Asset

Acquisition (See “–Subsequent Events”).

Our Partnership Distributions

•

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.

APL’s Partnership Distributions

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. During July 2007, Atlas Pipeline GP agreed to allocate a portion of its incentive distribution rights back to APL as set forth in the IDR Adjustment Agreement. No incentive distributions were declared for the years ended December 31, 2010 and 2009.

Off Balance Sheet Arrangements

As of December 31, 2010, our off balance sheet arrangements are limited to APL’s letters of credit, issued under the provisions of APL’s revolving credit facility, totaling $3.2 million. These are in place to

support various performance obligations as required by (i) statutes within the regulatory jurisdictions where APL operates, (ii) surety and (iii) counterparty support.

Contractual Obligations and Commercial Commitments

The following table summarizes our and APL’s contractual obligations and commercial commitments at December 31, 2010 (in thousands):


			Payments Due By Period
Contractual cash obligations:	Total		Less than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
Total debt	$	603,944	$	35,415	$	—	$	345,479	$	223,050
Interest on total debt⁽¹⁾		274,858		48,789		89,078		89,012		47,979
Derivative-based obligations		10,172		4,564		5,608		—		—
Capital leases		838		258		516		64		—
Operating leases		10,156		4,737		5,295		124		—

Total contractual cash obligations	$	899,968	$	93,763	$	100,497	$	434,679	$	271,029

(1) Based on the interest rates of our respective debt components as of December 31, 2010.
			Amount of Commitment Expiration Per Period
Other commercial commitments:	Total		Less than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
Standby letters of credit	$	3,217	$	3,217	$	—	$	—	$	—

Total commercial commitments	$	3,217	$	3,217	$	—	$	—	$	—

Our Equity Offerings

On June 1, 2009, AHD Sub issued $15.0 million of $1,000 par value 12.0% cumulative Class B preferred equity (“AHD Sub Preferred Units”) to APL for cash. We utilized the net proceeds from the issuance to reduce borrowings under our senior secured credit facility (see “-Our Credit Facility”). Distributions on the AHD Sub Preferred Units were payable quarterly on the same date as the distribution payment date for our common units. AHD Sub had the option of redeeming some or all of the AHD Sub Preferred Units. On November 15, 2010, AHD Sub exercised its option to redeem the AHD Sub Preferred Units for cash at the liquidation value of $1,000 per unit, or $15.0 million plus $0.2 million accrued dividends.

In June 2008, we sold 308,109 common units through a private placement to ATLS at a price of $32.50 per unit, for net proceeds of approximately $10.0 million. We utilized the net proceeds from the sale to purchase 278,000 common units of APL, which in turn utilized the proceeds to partially fund the early termination of certain derivative agreements. Following our private placement, ATLS had a 64.4% ownership interest in our common units.

APL Common Equity Offerings

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 us of $0.4 million for us to maintain our 2.0% general partner interest in APL. In addition, APL issued warrants granting investors in its 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 and revolving credit facility (see “–APL Term Loan and Revolving Credit Facility”).

On January 7, 2010, APL executed amendments to its warrants which were originally issued 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 per unit from $6.35 per unit. In connection with the amendments,

the holders of the warrants exercised all of the warrants for cash, which resulted in net cash proceeds of approximately $15.3 million. On November 30, 2010, APL also received a capital contribution from us of $0.3 million for us to maintain our 2.0% general partner interest in APL. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under APL’s senior secured term loan and credit facility (see “-APL Term Loan and Credit Facility”) and to fund the early termination of certain derivative agreements See “Item 8. Financial Statements and Supplementary Data –Note 11”.

In June 2008, APL sold 5,750,000 common units in a public offering at a price of $37.52 per unit, yielding net proceeds of approximately $206.6 million. Also in June 2008, APL sold 1,112,000 common units to ATLS and 278,000 common units to us in a private placement at a net price of $36.02 per unit, resulting in net proceeds of approximately $50.1 million. APL also received a capital contribution from us of $5.4 million for us to maintain our 2.0% general partner interest in APL. APL utilized the net proceeds from both sales and the capital contribution to fund the early termination of certain derivative agreements.

APL Preferred Units

APL Class A Preferred Units

In December 2008, APL redeemed 10,000 of the then-outstanding 40,000 cumulative convertible preferred units (“APL Class A Preferred Units”) owned by Sunlight Capital Partners, LLC (“Sunlight Capital”), an affiliate of Elliott & Associates, for $10.0 million in cash under the terms of the agreement. The redemption was classified as a reduction of non-controlling interest in APL within our consolidated balance sheets.

In January 2009, APL and Sunlight Capital amended certain terms of the APL Class A Preferred Units. The amendment (a) increased the dividend yield from 6.5% to 12.0% per annum, effective January 1, 2009, and (b) required that APL issue Sunlight Capital $15.0 million of its 8.125% senior unsecured notes due 2015 (see “–APL Senior Notes”) to redeem 10,000 APL 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 APL Class A Preferred Units was approximately $10.0 million at the date of redemption based upon the market price of the publicly-traded APL senior notes. As such, APL recorded the redemption by recognizing a $10.0 million reduction of APL Class A Preferred equity within Equity, $15.0 million of additional long-term debt for the face value of the APL senior unsecured notes issued, and a $5.0 million discount on the issuance of the APL senior unsecured notes that is presented as a reduction of long-term debt on our consolidated balance sheets. The discount recognized upon issuance of the APL senior unsecured notes will be amortized to interest expense in our consolidated statements of operations over the term of the notes based upon the effective interest rate method.

In April 2009, APL redeemed 10,000 of the APL Class A Preferred Units for cash, at the liquidation value of $1,000 per unit, or $10.0 million and converted 5,000 of the APL Class A Preferred Units into 1,465,653 APL common units, reclassifying $5.0 million from APL Class A preferred limited partner equity to APL common limited partner equity within Equity. In May 2009, APL redeemed the remaining 5,000 APL 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 APL Class A Preferred Units prior to APL’s redemption. There are no longer any APL Class A Preferred Units outstanding.

APL Class B Preferred Units

In December 2008, APL sold 10,000 12.0% cumulative convertible Class B preferred units of limited partner interests (the “APL Class B Preferred Units”) to us for cash consideration of $1,000 per Class B Preferred Unit (the “Face Value”) pursuant to a certificate of designation (the “APL Class B Preferred Units Certificate of Designation”).

In March 2009, we purchased an additional 5,000 APL Class B Preferred Units at Face Value. APL used the proceeds from the sale of the APL Class B Preferred Units for general partnership purposes.

Additionally, in March 2009, we and APL agreed to amend the terms of the APL Class B Preferred Units Certificate of Designation to remove the conversion feature, thus the APL Class B Preferred Units were not convertible into APL common units. The cumulative sale of the APL Class B Preferred Units to us was exempt from the registration requirements of the Securities Act of 1933.

In November 2010, APL redeemed the 15,000 units of APL 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 APL Class B Preferred Units prior to APL’s redemption. There are no longer any APL Class B Preferred Units outstanding. See “Item 8. Financial Statements and Supplementary Data –Note 7”.

APL Class C Preferred Units

The sale of the APL Class C Preferred Units to ATLS was exempt from the registration requirements of the Securities Act of 1933 by reason of Section 4(2) thereunder and pursuant to SEC staff positions. The APL Class C Preferred Units receive distributions of 12% per annum, paid quarterly on the same date as the distribution payment date for APL’s common units. The record date for the determination of holders entitled to receive distributions will be the same as the record date for determination of common unit holders entitled to receive quarterly distributions. APL has the right to redeem some or all of the APL Class C Preferred Units (but not less than 2,500 APL Class C Preferred Units) for an amount equal to the face value of the APL Class C Preferred Units being redeemed plus all accrued but unpaid dividends. See “Item 8. Financial Statements and Supplementary Data –Note 7”.

APL Term Loan and Revolving Credit Facility

At December 31, 2010, APL had a senior secured credit facility with a syndicate of banks which consisted of a $350.0 million revolving credit facility which matures in December 2015. APL’s term loan, which was a part of the credit facility, was paid in full in September 2010. Borrowings under APL’s revolving 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% or (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 the outstanding APL revolving credit facility borrowings at December 31, 2010 was 3.8%. Up to $50.0 million of APL’s revolving credit facility may be utilized for letters of credit, of which $3.2 million was outstanding at December 31, 2010. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheets.

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 APL’s Chaney Dell and Midkiff/Benedum joint ventures. Borrowings are also secured by the guaranty of each of APL’s consolidated subsidiaries other than the joint venture companies. APL’s revolving credit facility contains customary covenants, including restrictions on APL’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or 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. APL is in compliance with these covenants as of December 31, 2010.

The events which constitute an event of default for the APL credit facility include 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. As of December 31, 2010, APL was in compliance with all covenants under the credit facility.

APL Senior Notes

At December 31, 2010, APL had $223.1 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“APL 8.75% Senior Notes”) and $275.5 million principal amount outstanding of 8.125% senior unsecured notes due on December 15, 2015 (“APL 8.125% Senior Notes”; collectively, the “APL Senior Notes”). The APL 8.125% Senior Notes are presented combined with a net $3.4 million of unamortized discount as of December 31, 2010. Interest on the APL Senior Notes in the aggregate 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, and the APL 8.125% Senior Notes are redeemable at any time after December 31, 2010, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. Prior to June 15, 2011, APL may redeem up to 35% of the aggregate principal amount of the APL 8.75% Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The Senior Notes in the aggregate are also 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 Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its credit facility.

In December 2008, APL repurchased approximately $60.0 million in face amount of APL Senior Notes for an aggregate purchase price of approximately $40.1 million plus accrued interest of approximately $2.0 million. The notes repurchased were comprised of $33.0 million in face amount of APL’s 8.125% Senior Notes and approximately $27.0 million in face amount of APL’s 8.75% Senior Notes. All of the APL Senior Notes repurchased have been retired and are not available for re-issue.

In January 2009, APL issued Sunlight Capital $15.0 million of its 8.125% Senior Notes to redeem 10,000 APL Class A Preferred Units (see “–APL Preferred Units”). APL’s management estimated that the fair value of the $15.0 million 8.125% Senior Notes issued was approximately $10.0 million at the date of issuance based upon the market price of the publicly-traded Senior Notes. As such, APL recognized a $5.0 million discount on the issuance of the Senior Notes, which is presented as a reduction of long-term debt on our consolidated balance sheets. The discount recognized upon issuance of the Senior Notes will be amortized to interest expense in our consolidated statements of operations over the term of the 8.125% Senior Notes based upon the effective interest rate method.

Indentures governing the APL Senior Notes in the aggregate contain 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 is in compliance with these covenants as of December 31, 2010.

In November 2010, APL paid $1.3 million to the holders of the APL 8.125% Senior Notes in connection with a solicited consent received from the majority of holders of those notes to amend certain provisions of the Indenture governing the APL 8.125% Senior Notes. The amendment allows APL to make capital contributions to Laurel Mountain Midstream, LLC through December 31, 2011.

Environmental Regulation

APL’s 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. We believe that APL’s 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 APL’s operations, or other measures. Risks of accidental leaks or spills are associated with the gathering of natural gas. There can be no assurance that APL 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 its business. Moreover, it is possible that other developments, such as increasingly stringent environmental laws and regulations and enforcement policies, could result in increased costs and liabilities to APL.

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. Related to greenhouse gas emissions, cap and trade programs or greenhouse gas permitting programs are being considered by Congress. Depending on the program, APL could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from its operations or from combustion of fuels it processes. In addition, APL could face additional taxes and higher costs of doing business. Although APL would not be impacted to a greater degree than other similarly situated gatherers and processors of natural gas or NGLs, a stringent greenhouse gas control program could result in a significant effect on APL’s cost of doing business. However, we are currently unable to assess the timing and effect of the pending legislation.

APL continues to monitor regulatory and legislative activities regarding greenhouse gas production, detection, reporting and mitigation issues. APL recognizes that greenhouse gas issues continue to be very dynamic topics of discussion within the scientific, business and political communities, and APL is committed to staying abreast of developing rules and mandates that will affect its operations and business activities. APL participates within industry organizations in order to contribute to consolidated initiatives that are continuously monitoring, addressing and contributing to these greenhouse gas issues both during and following their development.

Other increasingly stringent environmental restrictions and limitations have resulted in increased operating costs for APL 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. APL will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly, but there can be no assurance that APL will identify and properly anticipate each such charge, or that APL’s efforts will prevent material costs, if any, from rising.

Inflation and Changes in Prices

Inflation affects the operating expenses of our operations due to the increase in costs of labor and supplies. While inflation did not have a material impact on our results of operations for the years ended December 31, 2010, 2009 and 2008, the energy sector realized increased costs during 2008, caused by the demand in energy equipment and services due to the increase in commodity prices. Commodity prices have decreased from their highs in 2008 and the related costs have also declined. 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 expense accruals, depreciation and amortization, asset impairment, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. We summarize our significant accounting policies within our consolidated financial statements included in Item 8, “Financial Statements and Supplementary Data.” 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 properties, plants 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 “Forward Looking Statements” elsewhere in this document.

As discussed below, we recognized an impairment of goodwill at December 31, 2008. We believe this impairment of goodwill was an event that warranted assessment of APL’s long-lived assets for possible impairment. During the year ended December 31, 2009, APL completed an evaluation of certain assets based on the current operating conditions and business plans for those assets, including idle and inactive pipelines and equipment. Based on the results of this review, we recognized an impairment charge within goodwill and other asset impairments on our consolidated statements of operations of approximately $10.3 million for the year ended December 31, 2009. There were no long-lived asset impairments recognized by APL during the years ended December 31, 2010 and 2008.

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.

As a result of APL’s impairment evaluation at December 31, 2008, we recognized a $615.7 million non-cash impairment charge within our consolidated statements of operations for the year ended December 31, 2008. The goodwill impairment resulted from the reduction in APL’s estimated fair value of reporting units in comparison to their carrying amounts at December 31, 2008. APL’s estimated fair value of the reporting units was impacted by many factors, including the significant deterioration of commodity prices and global economic conditions during the fourth quarter of 2008. There were no goodwill impairments recognized by APL during the years ended December 31, 2010 and 2009. See “Goodwill” in “Item 8: Financial Statements and Supplementary Data –Note 2” for information regarding APL’s impairment of goodwill and other assets.

Fair Value of Financial Instruments

We use a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect our own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following hierarchy:

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 assumption 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 and APL use a fair value methodology to value the assets and liabilities for our respective outstanding derivative contracts (see “Item 8: Financial Statements and Supplementary Data –Note 12”). At December 31, 2010, all of APL’s derivative contracts are defined as Level 2, with the exception of APL’s NGL fixed price swaps and NGL options. APL’s Level 2 commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity. 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. Valuations for APL’s NGL options are based on forward price curves developed by financial institutions, and therefore are defined as Level 3.

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. Our assets as of December 31, 2010 consisted solely of our ownership interests in APL. Therefore, the following information principally encompasses APL’s exposure to market risks unless otherwise noted. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and oil and natural gas 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 in connection with APL. All of APL’s market risk sensitive instruments were entered into for purposes other than trading.

General

All of our and APL’s assets and liabilities are denominated in U.S. dollars, and as a result, we do not have exposure to currency exchange risks.

We and APL 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 APL manage these risks through regular operating and financing activities and periodical use of derivative instruments. 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, 2010. Only the potential impact of hypothetical assumptions is analyzed. The analysis does not consider other possible effects that could impact our and APL’s business.

Current market conditions elevate our and APL’s concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us and APL, if any. The counterparties to APL’s commodity-based derivatives are banking institutions currently participating in APL’s revolving credit facility. We and APL may choose to do business with counterparties outside of APL’s credit facility in the future. The creditworthiness of our and APL’s counterparties is constantly monitored, and we and APL are not aware of any inability on the part of our respective counterparties to perform under our contracts.

Interest Rate Risk. At December 31, 2010, APL had a $350.0 million senior secured revolving credit facility with $70.0 million 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% or (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 for APL’s revolving credit facility borrowings was 3.8% at December 31, 2010. At December 31, 2010, we and APL had no interest rate derivative contracts. Holding all other variables constant, a 100 basis-point, or 1%, change in interest rates would change our and APL’s annual interest expense by approximately $3.5 million.

Commodity Price Risk. APL is exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. For gathering services, APL receives fees or commodities from the producers to bring the raw natural gas from the wellhead to the processing plant. For processing services, APL either receives fees or commodities as payment for these services, based on the type of contractual agreement. APL uses a number of different derivative instruments in connection with its commodity price risk management activities. APL enters into financial swap and option instruments to hedge its forecasted natural gas, NGLs 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 and condensate are sold. Under swap agreements, APL receives or pays a fixed price and receives or remits 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

100

indices for the relevant contract period. See “Item 8. Financial Statements and Supplementary Data –Note 11” for further discussion of APL’s derivative instruments. Average estimated 2011 market prices for NGLs, natural gas and condensate, based upon New York Mercantile Exchange (“NYMEX”) forward price curves as of January 11, 2011, are $1.14 per gallon, $4.54 per million BTU and $92.77 per barrel. A 10% change in these prices would change our forecasted gross margin for the twelve-month period ended December 31, 2011 by approximately $13.5 million.

During the years ended December 31, 2010, 2009 and 2008, APL made net payments of $25.3 million, $5.0 million and $274.0 million, respectively, related to the early termination of derivative contracts. The terminated derivative contracts were to expire at various times through 2012. During the years ended December 31, 2010, 2009 and 2008, we recognized the following derivative activity related to APL’s early termination of these derivative instruments within our consolidated statements of operations (in thousands):


Early termination of derivative contracts	For the Years Ended December 31,
	2010			2009⁽¹⁾			2008⁽¹⁾
Cash paid for early termination	$	(25,315	)	$	(5,000	)	$	(273,987	)
Deferred recognition of loss on early termination⁽²⁾		—			—			76,345
Equity applied to prior period early termination		(8,421	)		—			—

Total realized loss at early termination⁽³⁾	$	(33,736	)	$	(5,000	)	$	(197,642	)

Net cash derivative expense included within natural gas and liquids revenue	$	12,198		$	—		$	1,762
Net cash derivative expense included within other loss, net		(34,599	)		(2,260	)		(103,909	)
Net cash derivative expense included within discontinued operations		(11,335	)		(2,740	)		(95,495	)

Total realized loss at early termination⁽³⁾		(33,736	)		(5,000	)		(197,642	)
Recognition of deferred hedge loss from prior periods included within natural gas and liquids revenue⁽⁴⁾		(25,726	)		(43,112	)		(19,764	)
Recognition of deferred hedge gain (loss) from prior periods included within other income (loss), net⁽⁴⁾		35,342			31,488			(23,716	)
Recognition of deferred hedge gain (loss) from prior periods included within discontinued operations⁽⁴⁾		4,137			(11,994	)		(28,127	)

Total realized loss from early termination recognized in current period⁽³⁾	$	(19,983	)	$	(28,618	)	$	(269,249	)

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City.

(2)	Deferred recognition based upon effective portion of hedges deferred to other comprehensive income, plus theoretical premium related to unwound options which had previously been purchased or sold as part of costless collars.

(3)

Realized gain (loss) represents the gain/loss recognized when the derivative contract is settled. A portion of realized gain (loss) recognized in other income (loss), net is a reclassification of unrealized gain (loss) previously recognized as a factor of recording the changes in the fair value of the derivatives prior to settlement.

(4)

Non-cash recognition of deferred hedge gain (loss) includes (i) theoretical premiums related to calls sold in conjunction with puts purchased in costless collars in which the puts were sold as part of the equity unwinds in 2008 and (ii) the effective portion of hedges deferred to other comprehensive income.

In addition, we will recognize a total of $5.1 million of net income, relating to derivative contracts terminated in 2008. This income will be recognized in our consolidated statements of operations during the periods for which the hedged physical transactions are forecasted to be settled, with $2.8 million and $2.3 million of net income to be recognized during the years ending December 31, 2011 and 2012, respectively.

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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 balance sheets of Atlas Energy, L.P. (a Delaware limited partnership) as of December 31, 2010 and 2009, and the related consolidated statements of operations, comprehensive income (loss), equity and cash flows for each of the three years in the period ended December 31, 2010. 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 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, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 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), Atlas Energy, L.P.’s internal control over financial reporting as of December 31, 2010, 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 25, 2011 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 25, 2011

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)


	December 31,
	2010			2009
ASSETS
Current assets:
Cash and cash equivalents	$	247		$	1,103
Accounts receivable		99,759			80,019
Current portion of derivative asset		—			998
Prepaid expenses and other		15,205			13,360
Current assets of discontinued operations		—			22,746

Total current assets		115,211			118,226

Property, plant and equipment, net		1,341,002			1,327,704
Intangible assets, net		126,379			149,481
Investment in joint venture		153,358			132,990
Long-term portion of derivative asset		—			361
Other assets, net		31,168			30,326
Long-term assets of discontinued operations		—			379,030

Total assets	$	1,767,118		$	2,138,118


LIABILITIES AND EQUITY

Current liabilities:
Current portion of long-term debt	$	210		$	8,000
Current portion of long-term debt - affiliates		35,415			24,255
Accounts payable – affiliates		14,335			2,304
Accounts payable		29,382			19,556
Accrued liabilities		31,131			13,521
Accrued interest payable		1,921			9,652
Current portion of derivative liability		4,564			33,833
Accrued producer liabilities		72,996			57,430
Distribution payable		240			—
Current liabilities of discontinued operations		—			13,181

Total current liabilities		190,194			181,732

Long-term portion of derivative liability		5,608			11,126
Long-term debt, less current portion		565,764			1,254,183
Other long-term liability		223			398

Commitments and contingencies

Equity:
Common limited partners’ interests		17,575			(7,756	)
Accumulated other comprehensive loss		(1,433	)		(6,551	)

Total partners’ capital		16,142			(14,307	)
Non-controlling interests		(32,537	)		(30,925	)
Non-controlling interest in Atlas Pipeline Partners, L.P.		1,021,724			735,911

Total equity		1,005,329			690,679

Total liabilities and equity	$	1,767,118		$	2,138,118

See accompanying notes to consolidated financial statements

103

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)


	Years Ended December 31,
	2010			2009			2008
Revenue:
Natural gas and liquids	$	890,048		$	636,231		$	1,078,714
Transportation, compression and other fees – third parties		40,474			41,539			44,149
Transportation, compression and other fees – affiliates		619			17,536			43,293
Other income (loss), net		4,422			(23,061	)		36,602

Total revenue and other income (loss), net		935,563			672,245			1,202,758


Costs and expenses:
Natural gas and liquids		720,215			527,730			900,460
Plant operating		48,670			45,566			47,371
Transportation and compression		1,061			6,657			11,249
General and administrative		34,894			36,200			(854	)
Compensation reimbursement – affiliates		1,500			2,731			1,487
Depreciation and amortization		74,897			75,684			71,764
Goodwill and other asset impairment loss		—			10,325			615,724
Acquisition costs		1,167			—			—
Interest		94,807			106,531			91,731
Gain on early extinguishment of debt		—			—			(19,867	)

Total costs and expenses		977,211			811,424			1,719,065


Equity income in joint venture		4,920			4,043			—
Gain (loss) on asset sales and other		(10,729	)		108,947			—

Loss from continuing operations		(47,457	)		(26,189	)		(516,307	)

Discontinued operations:
Gain on sale of discontinued operations		312,102			53,571			—
Earnings (loss) of discontinued operations		9,053			30,577			(93,802	)

Income (loss) from discontinued operations		321,155			84,148			(93,802	)

Net income (loss)	$	273,698		$	57,959		$	(610,109	)

(Income) loss attributable to non-controlling interests		(4,738	)		(3,176	)		22,781
(Income) loss attributable to non-controlling interest in Atlas Pipeline Partners, L.P.		(241,026	)		(50,748	)		513,675

Net income (loss) attributable to common limited partners	$	27,934		$	4,035		$	(73,653	)

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)


Amounts attributable to common limited partners:
Continuing operations	$	(11,994	)	$	(7,768	)	$	(61,165	)
Discontinued operations		39,928			11,803			(12,488	)

Net income (loss) attributable to common limited partners	$	27,934		$	4,035		$	(73,653	)


Net income (loss) attributable to common limited partners per unit:
Basic:
Continuing operations	$	(0.43	)	$	(0.28	)	$	(2.23	)
Discontinued operations		1.44			0.43			(0.45	)

	$	1.01		$	0.15		$	(2.68	)


Diluted:
Continuing operations	$	(0.43	)	$	(0.28	)	$	(2.23	)
Discontinued operations		1.44			0.43			(0.45	)

	$	1.01		$	0.15		$	(2.68	)


Weighted average common limited partner units outstanding:
Basic		27,718			27,663			27,511

Diluted		27,718			27,663			27,511

See accompanying notes to consolidated financial statements

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)


	Years Ended December 31,
	2010			2009			2008

Net income (loss)	$	273,698		$	57,959		$	(610,109	)
(Income) loss attributable to non-controlling interests		(4,738	)		(3,176	)		22,781
(Income) loss attributable to non-controlling interests - Atlas Pipeline Partners, L.P.		(241,026	)		(50,748	)		513,675

Net income (loss) attributable to common limited partners		27,934			4,035			(73,653	)


Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges		—			(2,412	)		(98,223	)
Changes in non-controlling interest – Atlas Pipeline Partners, L.P. related to items in other comprehensive income (loss)		(32,918	)		(47,171	)		35,499
Add: adjustment for realized losses reclassified to net income (loss)		38,036			58,820			54,603

Total other comprehensive income (loss)		5,118			9,237			(8,121	)

Comprehensive income (loss)	$	33,052		$	13,272		$	(81,774	)

See accompanying notes to consolidated financial statements

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(in thousands, except unit data)


	Common Limited Partners’ Capital					Accumulated Other Comprehensive Income (Loss)			Non- Controlling Interests			Non-Controlling Interest in Atlas Pipeline Partners L.P.			Total


	Units		$
Balance at January 1, 2008		27,350,370	$	101,785		$	(7,667	)	$	(2,163	)	$	1,154,570		$	1,246,525
Issuance of common limited partner units		308,109		10,001			—			—			246,862			256,863
Unissued common units under incentive plans		—		2,665			—			—			—			2,665
Issuance of units under incentive plans		675		—			—			—			—			—
Distributions paid		—		(49,674	)		—			(7,393	)		(188,819	)		(245,886	)
Net loss on purchase and sale of subsidiary equity		—		3,413			—			—			—			3,413
Other comprehensive gain		—		—			(8,121	)		—			(35,498	)		(43,619	)
Net loss		—		(73,653	)		—			(22,781	)		(513,675	)		(610,109	)

Balance at December 31, 2008		27,659,154	$	(5,463	)	$	(15,788	)	$	(32,337	)	$	663,440		$	609,852
Issuance of common limited partner units		—		(45	)		—			—			16,074			16,029
Distributions to non-controlling interests		—		—			—			(1,764	)		(21,693	)		(23,457	)
Redemption of subsidiary preferred units		—		—			—			—			(25,000	)		(25,000	)
Unissued common units under incentive plans		—		562			—			—			—			562
Issuance of units under incentive plans		44,425		—			—			—			—			—
Distributions paid to common limited partners		—		(1,660	)		—			—			—			(1,660	)
Distributions equivalent rights paid on unissued units under incentive plans		—		(14	)		—			—			—			(14	)
Other comprehensive loss		—		—			9,237			—			47,171			56,408
Net loss on purchase and sale of subsidiary equity		—		(5,171	)		—			—			5,171			—
Net income		—		4,035			—			3,176			50,748			57,959

Balance at December 31, 2009		27,703,579	$	(7,756	)	$	(6,551	)	$	(30,925	)	$	735,911		$	690,679
Issuance of common limited partner units		—		—			—			—			15,319			15,319
Issuance of subsidiary preferred units		—		—			—			—			8,000			8,000
Distributions to non-controlling interests		—		—			—			(6,350	)		(16,886	)		(23,236	)
Unissued common units under incentive plans		—		1,245			—			—			3,484			4,729
Issuance of units under incentive plans		131,675		—			—			—			156			156
Repurchase and retirement of common limited partner units		—		—			—			—			(246	)		(246	)
Distributions paid to common limited partners		—		(1,385	)		—			—			—			(1,385	)
Distributions equivalent rights paid on unissued units under incentive plans		—		(7	)		—			—			(174	)		(181	)
Distributions payable		—		—			—			—			(240	)		(240	)
Other comprehensive loss		—		—			5,118			—			32,918			38,036
Net loss on purchase and sale of subsidiary equity		—		(2,456	)		—			—			2,456			—
Net income		—		27,934			—			4,738			241,026			273,698

Balance at December 31, 2010		27,835,254	$	17,575		$	(1,433	)	$	(32,537	)	$	1,021,724		$	1,005,329

See accompanying notes to consolidated financial statements

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Years Ended December 31,
	2010			2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	273,698		$	57,959		$	(610,109	)
Less: Income (loss) from discontinued operations		321,155			84,148			(93,802	)

Net loss from continuing operations		(47,457	)		(26,189	)		(516,307	)
Adjustments to reconcile net loss from continuing operations to net cash provided by (used in) operating activities:
Depreciation and amortization		74,897			75,684			71,764
Goodwill and other asset impairment loss		—			10,325			615,724
Gain on early extinguishment of debt		—			—			(19,867	)
Equity income in joint venture		(4,920	)		(4,043	)		—
Distributions received from joint venture		11,066			4,310			—
(Gain) loss on asset sales		2,229			(108,947	)		—
Non-cash compensation expense (income)		4,729			1,265			(31,345	)
Amortization of deferred finance costs		10,618			8,178			6,070
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable and prepaid expenses and other		(21,585	)		(2,684	)		35,563
Accounts payable and accrued liabilities		36,983			2,600			(14,804	)
Accounts payable and accounts receivable – affiliates		12,031			2,644			2,401
Derivative accounts payable and accounts receivable		4,609			48,222			(373,833	)

Net cash provided by (used in) continuing operating activities		83,200			11,365			(224,634	)
Net cash provided by discontinued operating activities		23,374			42,142			169,797

Net cash provided by (used in) operating activities		106,574			53,507			(54,837	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Net cash received related to acquisitions		—			—			31,429
Capital contribution to joint venture		(26,514	)		(1,680	)		—
Capital expenditures		(45,752	)		(110,274	)		(181,656	)
Net proceeds (expenditures) related to asset sales		(2,229	)		89,472			—
Other		56			(1,875	)		1,099

Net cash used in continuing investing activities		(74,439	)		(24,357	)		(149,128	)
Net cash provided by (used in) discontinued investing activities		669,192			265,387			(143,842	)

Net cash provided by (used in) investing activities		594,753			241,030			(292,970	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facilities		482,000			694,000			808,400
Repayments under credit facilities		(746,000	)		(708,000	)		(590,400	)
Repayment of Atlas Pipeline Partners, L.P. debt		(433,505	)		(273,675	)		(162,938	)
Principal payments on Atlas Pipeline Partners, L.P. capital lease		(142	)		—			—
Net proceeds from issuance of Atlas Pipeline Partners, L.P. debt		—			—			244,854
Net proceeds from subordinate loan and guaranty note with Atlas Energy, Inc.		8,000			23,000			—
Net proceeds from issuance of common limited partner units		—			—			10,001
Net proceeds from issuance of Atlas Pipeline Partners, L.P. units		23,475			16,074			246,915
Redemption of Atlas Pipeline Partners, L.P. Class A preferred limited partner units		—			(15,000	)		(10,053	)
Net distributions paid to non-controlling interests		(6,350	)		(1,764	)		(7,393	)
Distributions paid to non-controlling interest in Atlas Pipeline Partners, L.P.		(17,060	)		(22,337	)		(140,850	)
Distributions paid to common limited partners		(1,385	)		(1,660	)		(49,272	)
Other		(11,216	)		(11,357	)		(6,662	)

Net cash provided by (used in) financing activities		(702,183	)		(300,719	)		342,602

Net change in cash and cash equivalents		(856	)		(6,182	)		(5,205	)
Cash and cash equivalents, beginning of year		1,103			7,285			12,490

Cash and cash equivalents, end of year	$	247		$	1,103		$	7,285

See accompanying notes to consolidated financial statements

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – NATURE OF OPERATIONS

Atlas Energy, L.P. (“Atlas Energy, L.P.” or the “Partnership”) is a publicly-traded Delaware limited partnership, formerly known as Atlas Pipeline Holdings, L.P. (NYSE: AHD). The Partnership’s wholly-owned subsidiary, Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP” or “General Partner”), a Delaware limited liability company, is the general partner of Atlas Pipeline Partners, L.P. (“APL” – NYSE: APL). The Partnership’s general partner, Atlas Pipeline Holdings GP, LLC (“Atlas Pipeline Holdings GP”), which does not have an economic interest in the Partnership and is not entitled to receive any distributions from the Partnership, manages the operations and activities of the Partnership and owes a fiduciary duty to the Partnership’s common unitholders. At December 31, 2010, the Partnership had 27,835,254 common limited partnership units outstanding.

APL is a publicly-traded Delaware limited partnership and a midstream energy service provider engaged in the gathering and processing of natural gas in the Mid-Continent and Appalachia regions. APL’s operations are conducted through subsidiary entities whose equity interests are owned by Atlas Pipeline Operating Partnership, L.P. (the “Operating Partnership”), a wholly-owned subsidiary of APL. At December 31, 2010, the Partnership, through its general partner interests in APL and the Operating Partnership, owned a 2.0% general partner interest in the consolidated operations of APL, through which it manages and effectively controls both APL and the Operating Partnership. The remaining 98.0% ownership interest in the consolidated operations consists of limited partner interests in APL. The Partnership also owned 5,754,253 common units in APL. At December 31, 2010, APL had 53,338,010 common units outstanding, including the 5,754,253 common units held by the Partnership, plus 8,000 $1,000 par value 12% cumulative Class C preferred limited partner units held by Atlas Energy, Inc. (“Atlas Energy, Inc.” or “ATLS”), a formerly publicly-traded company (see Note 7).

On March 31, 2010, APL’s limited partnership agreement was amended to provide a temporary waiver of a capital contribution required for Atlas Pipeline GP to maintain its 2.0% general partner interest in APL, relative to the January 2010 issuance of APL common units for warrants exercised. Atlas Pipeline GP was not required to make such capital contribution until it had received aggregate distributions from APL sufficient to fund the required capital contribution. On November 30, 2010, Atlas Pipeline GP made the required capital contribution, terminating the waiver period. During the waiver period, Atlas Pipeline GP’s interest in APL and the Operating Partnership was reduced by approximately 0.1% to 1.9% (see Note 6).

The Partnership’s assets consist principally of 100% ownership interest in Atlas Pipeline GP, which as of December 31, 2010, together with the Partnership, owns:

•

a 2.0% general partner interest in APL, which entitles it to receive 2.0% of the cash distributed by APL; and

•

In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems, Atlas Pipeline GP agreed to allocate up to $3.75 million of its incentive distribution rights per quarter back to APL after it receives the initial $7.0 million per quarter of incentive distribution rights (the “IDR Adjustment Agreement”).

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•

5,754,253 common units of APL, representing approximately 10.8% of the 53,338,010 outstanding common limited partnership units of APL (see Note 6).

The Partnership, as general partner, manages the operations and activities of APL and owes a fiduciary duty to APL’s common unitholders. The Partnership is liable, as general partner, for all of APL’s debts (to the extent not paid from APL’s assets), except for indebtedness or other obligations that are made specifically non-recourse to the Partnership. The Partnership does not receive any management fee or other compensation for its management of APL. The Partnership and its affiliates are reimbursed for expenses incurred on APL’s behalf. These expenses include the costs of employee, officer, and managing board member compensation and benefits properly allocable to APL and all other expenses necessary or appropriate to conduct the business of, and allocable to, APL. The APL partnership agreement provides that the Partnership, as general partner, will determine the expenses that are allocable to APL in any reasonable manner in its sole discretion.

ATLS owned 100% of Atlas Pipeline Holdings GP, the general partner of the Partnership, and a 64.0% ownership interest in the common units of the Partnership at December 31, 2010. In addition to its ownership interest in the Partnership, ATLS also owned, at December 31, 2010, 1,112,000 of APL’s common limited partnership units, representing a 2.1% ownership interest in APL and 8,000 APL $1,000 par value 12% cumulative Class C preferred limited partner units (see Note 7).

On February 17, 2011, the Partnership completed a transaction agreement (the “AHD Transaction Agreement”) with ATLS and Atlas Energy Resources, LLC (“Atlas Energy Resources”) pursuant to which, among other things (1) the Partnership acquired certain assets from ATLS (the “Asset Acquisition”); (2) ATLS contributed the Partnership’s general partner, Atlas Pipeline Holdings GP to the Partnership, so that Atlas Pipeline Holdings GP became the Partnership’s wholly-owned subsidiary; (3) the Partnership’s limited partnership agreement was amended and restated; (4) the Partnership repaid all amounts outstanding under its amended and consolidated note to ATLS and (5) ATLS distributed to its stockholders all the Partnership’s common units that it held, including the newly issued common units that it received in the Asset Acquisition (see Note 20). On February 18, 2011, the Partnership changed its name to Atlas Energy, L.P. (see Note 20).

The Asset Acquisition qualifies as a transfer between entities under common control. 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 cost 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 shareholders’ equity. The assets of the transferred business include intangible assets, which are amortized over their useful lives and will cause the Partnership to incur accounting charges from the Asset Acquisition, and goodwill. In addition, intangible assets and goodwill are both subject to periodic impairment tests and could result in potential write-down charges in future periods.

The majority of the natural gas that APL and its affiliates, including Laurel Mountain Midstream, LLC (“Laurel Mountain”), gather in Appalachia is derived from wells operated by Atlas Energy Resources and its subsidiaries. Laurel Mountain, which was formed in May 2009, is a joint venture between the Partnership and The Williams Companies, Inc. (NYSE: WMB) (“Williams”) in which APL has a 49% non-controlling ownership interest and Williams holds the remaining 51% ownership interest (see Note 3).

Concurrently with the Asset Acquisition, APL completed its sale to Atlas Energy Resources of its 49% non-controlling interest in Laurel Mountain (the “Laurel Mountain Sale”) for $413.5 million in cash, which included adjustments based on capital contributions APL made to and distributions it received from Laurel Mountain after January 1, 2011 (See Note 20).

The Partnership has adjusted its consolidated financial statements and related footnote disclosures

110

presented within this Form 10-K from the amounts previously presented to reflect the following items:

•

The Partnership reclassified a portion of its historical income, within its consolidated statements of operations, to “Transportation, Processing and Other Fees” for fee-based revenues which were previously reported within “Natural Gas and Liquids” and “Other income (loss), net”. This reclassification was made in order to provide clarity between commodity-based and fee-based revenue.

•

The Partnership reclassified “Equity income in joint venture” and “Gain (loss) on asset sales and other” to line items separate from “Total revenue and other income (loss) net”.

•

On September 16, 2010, APL completed the sale of its Elk City and Sweetwater, Oklahoma natural gas gathering systems (collectively “APL’s Elk City”) (see Note 4). The Partnership has retrospectively adjusted its prior period consolidated financial statements to reflect the amounts related to the operations of APL’s Elk City as discontinued operations.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Non-Controlling Interest

The consolidated financial statements include the accounts of the Partnership, the General Partner, APL, the Operating Partnership and the Operating Partnership’s wholly-owned and majority-owned subsidiaries. All material intercompany transactions have been eliminated.

The Partnership’s consolidated financial statements also include APL’s 95% interest in joint ventures which individually own a 100% interest in the Chaney Dell natural gas gathering system and processing plants and a 72.8% undivided interest in the Midkiff/Benedum natural gas gathering system and processing plants. APL consolidates 100% of these joint ventures. The Partnership reflects the non-controlling interest in the joint ventures on its statements of operations. The Partnership also reflects the non-controlling interest in the net assets of the joint ventures as a component of equity on its consolidated balance sheets. The joint ventures have a $1.9 billion note receivable from the holder of the non-controlling interest in the joint ventures, which is reflected within non-controlling interests on the Partnership’s consolidated balance sheets.

The Midkiff/Benedum joint venture has a 72.8% undivided joint venture interest in the Midkiff/Benedum system, of which the remaining 27.2% interest is owned by Pioneer Natural Resources Company (NYSE: PXD) (“Pioneer”). Due to the ownership of the Midkiff/Benedum system being in the form of an undivided interest, the Midkiff/Benedum joint venture proportionally consolidates its 72.8% ownership interest in the assets and liabilities and operating results of the Midkiff/Benedum system.

Non-Controlling Interest in Atlas Pipeline Partners, L.P.

The non-controlling interest in APL on the Partnership’s consolidated financial statements reflects the outside ownership interests in APL, which was 87.8% and 86.8% at December 31, 2010 and 2009, respectively. The non-controlling interests in APL in the Partnership’s consolidated statements of operations is calculated quarterly by multiplying (i) the weighted average APL common limited partner units outstanding held by non-affiliated third parties by (ii) the consolidated net income (loss) per APL common limited partner unit for the respective quarter. The net income (loss) per APL common limited partner unit is calculated by dividing the net income (loss) allocated to common limited partners, after the allocation of net income (loss) to the Partnership as general partner in accordance with the terms of the APL partnership agreement, by the total weighted average APL common limited partner units outstanding. The Partnership’s general partner interest in the net income (loss) of APL is based upon its 2% general partner ownership interest and incentive distributions, with a priority allocation of APL’s net income (loss) in an amount equal to the incentive distributions (see Note 8), in accordance with the APL partnership agreement, and the remaining APL net

111

income (loss) allocated with respect to the general partner’s and APL’s limited partners’ ownership interests. The non-controlling interest in APL on the Partnership’s consolidated balance sheets principally reflects the sum of the allocation of APL’s consolidated net income (loss) to the non-controlling interest in APL and the contributed capital of non-controlling interests through the sale of limited partner units in APL, partially offset by APL quarterly cash distributions to the non-controlling interest owners.

During the year ended December 31, 2010, APL’s warrant holders exercised their warrants to purchase 2,689,765 common units (see Note 6). In addition, APL employees exercised their options to purchase 25,000 common units under incentive compensation agreements (see Note 16). As a result of these transactions, the Partnership’s ownership percentage in APL, including its 2.0% interest as general partner (see Note 1), was temporarily reduced. During the year ended December 31, 2010, the Partnership recorded a $2.5 million increase to non-controlling interest in APL with a corresponding decrease to its Equity, which represents the difference between the Partnership’s share of the underlying book value in APL before and after the respective common unit transactions, on its consolidated balance sheets.

During the year ended December 31, 2009, APL issued 348,620 common units to certain key employees covered under incentive compensation agreements (see Note 16). Additionally, APL issued 1,465,653 of its common units upon conversion of 5,000 preferred units previously held by Sunlight Capital Partners, LLC (see Note 7). In addition, APL executed a private placement of 2,689,765 of its common units (see Note 6). As a result of these transactions, the Partnership’s ownership percentage in APL, including its 2% interest as general partner, was reduced. During the year ended December 31, 2009, the Partnership recorded a $5.2 million increase to non-controlling interest in APL with a corresponding decrease to its limited Equity, which represents the difference between the Partnership’s share of the underlying book value in APL before and after the respective common unit transactions, on its consolidated balance sheets.

APL’s preferred units are reflected on the Partnership’s consolidated balance sheets as non-controlling interest in APL of $8.0 million at December 31, 2010.

Equity Method Investments

The Partnership’s consolidated financial statements include APL’s 49% non-controlling ownership interest in Laurel Mountain, a joint venture which owns and operates APL’s former Appalachia Basin natural gas gathering systems, excluding APL’s Tennessee operations. The Partnership accounts for APL’s investment in the joint venture under the equity method of accounting. Under this method, the Partnership records APL’s proportionate share of the joint venture’s net income (loss) as equity income (loss) on its consolidated statements of operations.

Use of Estimates

The preparation of the Partnership’s consolidated financial statements 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 financial statements, as well as the reported amounts of revenue and expense during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depreciation and amortization, asset impairment, the fair value of the Partnership’s and APL’s derivative instruments, the probability of forecasted transactions, APL’s allocation of purchase price to the fair value of assets acquired and other items. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results were recorded using estimated volumes and commodity market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented represent actual results in all material respects (see “Revenue Recognition” accounting

112

policy for further description).

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

The amounts included within accounts receivable on the Partnership’s consolidated balance sheets at December 31, 2010 and 2009 are associated entirely with APL’s operating activities. In evaluating the realizability of its accounts receivable, APL performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by APL’s review of its customers’ credit information. APL extends credit on an unsecured basis to many of its customers. At December 31, 2010 and 2009, APL recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets.

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. Assets acquired through a transfer between entities under common control require that assets be recognized by the acquirer at historical cost at the date of transfer. 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. The Partnership 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. 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. During the year ended December 31, 2010, APL entered into capital lease arrangements having obligations of $0.9 million at inception. Leased property and equipment meeting capital lease criteria are capitalized at the original cost of the equipment and are included within property plant and equipment on the Partnership’s consolidated balance sheets. Obligations under capital leases are accounted for as current and noncurrent liabilities and are included within debt on the Partnership’s consolidated balance sheets (see Note 13). Amortization is calculated on a straight-line method based upon the estimated useful lives of the assets. APL did not enter into any capital lease arrangements during the year ended December 31, 2009, and had no capital lease obligations as of December 31, 2009.

Impairment of Long-Lived Assets

The Partnership, including APL, reviews its long-lived assets for impairment whenever events or 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.

During the year ended December 31, 2009, APL completed an evaluation of certain assets based on the current operating conditions and business plans for those assets, including idle and inactive pipelines and equipment. Based on the results of this review, APL recognized an impairment charge of approximately $10.3 million for the year ended December 31, 2009, within goodwill and other asset impairments on the Partnership’s consolidated statements of operations. No impairment charges were recognized for the year ended December 31, 2010.

113

Capitalized Interest

APL capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds by APL was 7.5%, 6.4% and 6.3% for the years ended December 31, 2010, 2009 and 2008, respectively. The amount of interest capitalized was $0.8 million, $2.6 million and $3.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Derivative Instruments

The Partnership and APL enters into certain financial contracts to manage its exposure to movement in commodity prices and interest rates. The Partnership and APL record each derivative instrument in the balance sheet as either an asset or liability measured at fair value. Changes in a derivative instrument’s fair value are recognized currently in the consolidated statements of operations. On July 1, 2008, APL discontinued hedge accounting for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value of these derivatives are recognized immediately within other income (loss), net in the Partnership’s consolidated statements of operations. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive loss within Equity on the Partnership’s consolidated balance sheets and reclassified to the Partnership’s consolidated statements of operations at the time the originally hedged physical transactions affect earnings.

Intangible Assets

APL has recorded intangible assets with finite lives in connection with certain consummated acquisitions. The following table reflects the components of intangible assets being amortized at December 31, 2010 and 2009 (in thousands):


	December 31, 2010			December 31, 2009⁽¹⁾			Estimated Useful Lives In Years
Customer relationships:
Gross carrying amount	$	205,313		$	205,313			7–10
Accumulated amortization		(78,934	)		(55,832	)

Net carrying amount	$	126,379		$	149,481

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City (see Note 4).

APL amortizes intangible assets with finite useful lives 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 management’s estimate of whether these individual relationships will continue in excess or less than the average length. Amortization expense on intangible assets was $23.1 million for each of the years ended December 31, 2010, 2009 and 2008. Amortization expense related to APL’s intangible assets is estimated to be as follows for each of the next five calendar years: 2011 to 2013 - $23.1 million; 2014 - $19.5 million; 2015 - $14.5 million.

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Goodwill

The changes in the carrying amount of goodwill for the years ended December 31, 2010, 2009 and 2008 were as follows (in thousands):


	Years Ended December 31,
	2010		2009		2008⁽¹⁾
Balance, beginning of year	$	—	$	—	$	648,147
Post-closing purchase price adjustment with seller and purchase price allocation adjustment-Chaney Dell and Midkiff/Benedum acquisition		—		—		(2,217	)
Recovery of state sales tax initially paid on transaction – Chaney Dell and Midkiff/Benedum acquisition		—		—		(30,206	)
Impairment loss		—		—		(615,724	)

Balance, end of year	$	—	$	—	$	—

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City (see Note 4).

APL tests its goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. As a result of its impairment evaluation at December 31, 2008, APL recognized a $615.7 million non-cash impairment charge within the Partnership’s consolidated statements of operations for the year ended December 31, 2008. The goodwill impairment resulted from the reduction in APL’s estimated fair value of reporting units in comparison to their carrying amounts at December 31, 2008. APL’s estimated fair value of reporting units was impacted by many factors, including the significant deterioration of commodity prices and global economic conditions during the fourth quarter of 2008.

APL had adjusted its preliminary purchase price allocation for the acquisition of its Chaney Dell and Midkiff/Benedum systems since its July 2007 acquisition date by adjusting the estimated amounts allocated to goodwill, intangible assets and property, plant and equipment. Also, in April 2008, APL received a $30.2 million cash reimbursement for sales tax initially paid on its transaction to acquire the Chaney Dell and Midkiff/Benedum systems in July 2007. The $30.2 million was initially capitalized as an acquisition cost and allocated to the assets acquired, including goodwill, based upon their estimated fair values at the date of acquisition. Based upon the reimbursement of the sales tax paid in April 2008, the Partnership reduced goodwill recognized in connection with the acquisition.

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 (loss) reported in the accompanying consolidated 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 Partnership and these corporate subsidiaries were immaterial to the consolidated 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 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 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. The Partnership has not recognized any potential interest or penalties in its consolidated financial statements as of December 31, 2010.

The Partnership files income tax returns in the U.S. and various state jurisdictions. With few exceptions, the

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Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2007. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2010.

Stock-Based Compensation

All share-based payments to employees, including grants of employee stock options, are to be recognized in the financial statements based on their fair values. Compensation expense associated with share-based payments is recognized within general and administrative expenses on the Partnership’s statements of operations from the date of the grant through the date of vesting amortized on a straight-line method. Generally, no expense is recorded for awards that do not vest due to forfeiture.

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 2006 long-term incentive plan 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 (loss) 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 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):

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	Years Ended December 31,
	2010			2009⁽¹⁾			2008⁽¹⁾
Continuing operations:
Net income (loss)	$	(47,457	)	$	(26,189	)	$	(516,307	)
(Income) loss attributable to non-controlling interests		(4,738	)		(3,176	)		22,781
Loss attributable to non-controlling interests – Atlas Pipeline Partners, L.P.		40,201			21,597			432,361

Net loss attributable to common limited partners		(11,994	)		(7,768	)		(61,165	)
Less: Net income attributable to participating securities – phantom units⁽²⁾		—			—			—

Net loss utilized in the calculation of net loss from continuing operations attributable to common limited partners per unit	$	(11,994	)	$	(7,768	)	$	(61,165	)


Discontinued operations:
Net income (loss)	$	321,155		$	84,148		$	(93,802	)
(Income) loss attributable to non-controlling interests – Atlas Pipeline Partners, L.P.		(281,227	)		(72,345	)		81,314

Net income (loss) utilized in the calculation of net income from discontinued operations attributable to common limited partners per unit	$	39,928		$	11,803		$	(12,488	)

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City (see Note 4).

(2)

For the years ended December 31, 2010, 2009 and 2008, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 130,000, 185,000 and 438,000 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.

Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners by the sum of the weighted average number of common limited partner units outstanding, including participating securities, plus 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 2006 long-term incentive plan (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,
	2010		2009		2008
Weighted average number of common limited partner units – basic		27,718		27,663		27,511
Add effect of participating securities – phantom units⁽¹⁾		—		—		—
Add: effect of dilutive unit incentive awards⁽²⁾		—		—		—

Weighted average number of common limited partner units – diluted		27,718		27,663		27,511

(1)	For the years ended December 31, 2010, 2009 and 2008 approximately 130,000, 185,000 and 225,000 phantom units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such phantom units would have been anti-dilutive.

(2)

For the years ended December 31, 2010, 2009 and 2008 approximately 1.0 million unit options, 1.0 million unit options and 1.2 million option units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such unit options would have been anti-dilutive.

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Environmental Matters

APL’s operations are subject to various federal, state and local laws and regulations relating to the protection of the environment. APL has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures, including legislation related to greenhouse gas emissions. 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. At this time, APL is unable to assess the timing and/or effect of potential cap and trade programs or traditional permitting programs related to greenhouse gas emissions. APL maintains insurance which may cover in whole or in part certain environmental expenditures. At December 31, 2010 and 2009, the Partnership and APL had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

Segment Information

The Partnership’s assets primarily consist of its ownership interests in APL. APL has two reportable segments. The Mid-Continent segment consists of APL’s Chaney Dell, Velma and Midkiff/Benedum operations, which are comprised of natural gas gathering and processing assets located in Oklahoma, Texas, and southern Kansas. The Appalachia segment is comprised of natural gas transportation, gathering and processing assets located in the Appalachian Basin area in northeastern United States. Mid-Continent revenues are primarily derived from the sale of residue gas and NGLs and gathering of natural gas. Appalachia revenues are principally based on contractual arrangements with ATLS and its affiliates. These reportable segments reflect the way APL manages its operations.

Revenue Recognition

APL’s revenue primarily consists of the sale of natural gas and liquids along with fees earned from its gathering and processing operations. 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, or produced natural gas liquids (“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 of the natural gas. In connection with its gathering and processing 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. APL’s revenue is a function of the volume of natural gas that it gathers and processes and is not directly dependent on the value of the natural gas. APL also is paid a separate compression fee on many of its systems. The fee is dependent upon the volume of gas flowing through APL’s 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 natural gas and NGLs APL 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. The volume of gas gathered or purchased is based on the measured volume at an agreed upon location (generally at the wellhead). The volume of gas redelivered or

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sold at the tailgate of APL’s processing facility will be lower than the volume purchased at the wellhead primarily due to NGLs extracted when processed through a plant. APL must make up or “keep the producer whole” for this loss in volume. 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 (the “processing margin risk”) that (i) the volume of residue gas available for redelivery to the producer may be less than APL received from the producer; or (ii) the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that APL 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 Keep-Whole agreements is often 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 of margin risk.

APL accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, and condensate and the receipt of a delivery statement. This revenue is recorded based upon volumetric data from APL’s records and management estimates of the related gathering and compression fees which are, in turn, based upon applicable product prices (see “–Use of Estimates” accounting policy for further description). APL had unbilled revenues at December 31, 2010 and 2009 of $57.8 million and $61.2 million, respectively, which are included in accounts receivable and accounts receivable-affiliates within the Partnership’s consolidated balance sheets.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources. These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” or “OCI” and for the Partnership only include changes in the fair value of unsettled APL derivative contracts which are accounted for as cash flow hedges (see Note 11).

Recently Adopted Accounting Standards

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-06, “Fair Value Measurements and Disclosures - Improving Disclosures about Fair Value Measurements,” which provides enhanced disclosure requirements for activity in Levels 1, 2 and 3 fair value measurements. The update requires significant transfers in and out of Levels 1 and 2 fair value measurements to be reported separately and the reasons for such transfers to be disclosed. The update also requires information regarding purchases, sales, issuances, and settlements to be disclosed separately on a gross basis in the reconciliation of fair value measurements using unobservable inputs for all activity in Level 3 fair value measurements. Additionally, the update clarifies that fair value measurement for each class of assets and liabilities must be disclosed as well as disclosures pertaining to the inputs and valuation techniques for both recurring and nonrecurring fair value measurements in Levels 2 and 3. These requirements are effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those requirements are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The Partnership adopted these requirements on January 1, 2010 and it did not have a material impact on its financial position, results of operations or related disclosures.

NOTE 3 – APL INVESTMENT IN JOINT VENTURE

On May 31, 2009, APL and subsidiaries of Williams completed the formation of Laurel Mountain, a joint venture which owns and operates the Appalachia natural gas gathering system previously owned by APL, excluding APL’s Tennessee operations. 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

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receivable of $25.5 million. APL contributed the Appalachia natural gas gathering system and retained a 49% non-controlling ownership interest in Laurel Mountain. APL is also entitled to preferred distribution rights relating to all payments on the note receivable. Williams obtained the remaining 51% ownership interest in Laurel Mountain.

Upon completion of the transaction, the Partnership recognized APL’s 49% non-controlling ownership interest in Laurel Mountain as an investment in joint venture on its consolidated balance sheets at fair value. During the year ended December 31, 2009, APL recognized a gain on sale of $108.9 million, including $54.2 million associated with the revaluation of APL’s investment in Laurel Mountain to fair value. The revaluation of the retained investment was determined based upon the value received for the 51% contributed to the Laurel Mountain joint venture. APL used the net proceeds from the transaction to reduce borrowings under its senior secured credit facility (see Note 13).

In connection with the formation of Laurel Mountain, Laurel Mountain entered into natural gas gathering agreements with Atlas Energy Resources which superseded the existing natural gas gathering agreements and omnibus agreement between the Partnership and Atlas Energy Resources. Under the new gas gathering agreement, Atlas Energy Resources is obligated to pay a gathering fee that is generally the same as the gathering fee required under the terminated agreements, the greater of $0.35 per MCF or 16% of the realized sales price (except that a lower fee applies with respect to specific wells subject to certain existing contracts or in the event Laurel Mountain fails to perform specified obligations). The Partnership has accounted for APL’s ownership interest in Laurel Mountain under the equity method of accounting, with recognition of APL’s ownership interest in the income of Laurel Mountain as equity income on its consolidated statements of operations. 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. As of December 31, 2010, APL had $8.5 million of the $25.5 million note receivable remaining to fund capital contributions, which is included in investment in joint ventures on the consolidated balance sheets. Any amount that remains outstanding on this note after June 1, 2012 will be paid to APL in cash.

On February 17, 2011, APL completed the sale of its 49% non-controlling interest in Laurel Mountain to Atlas Energy Resources for $413.5 million in cash, including certain closing adjustments (see Note 20). APL retained its preferred distribution rights with respect to the remaining $8.5 million note receivable, due from Williams, related to formation of Laurel Mountain in 2009. During the year ended December 31, 2010, APL incurred expenses related to the pending sale of Laurel Mountain, which are included in gain (loss) on sale of assets and other within the Partnership’s consolidated statements of operations. APL intends to utilize the proceeds from the sale to repay its indebtedness, to fund future capital expenditures, and for general corporate purposes.

NOTE 4 – DISCONTINUED OPERATIONS

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 adjustments. APL used the net proceeds from the transaction to reduce borrowings under its senior secured term loan and revolving credit facility (see Note 13). The Partnership accounted for the sale of the NOARK system assets as discontinued operations within its consolidated 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 statements of operations during the year ended December 31, 2009. The NOARK system was previously reported within APL’s Mid-Continent segment of operations.

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L.P. (NYSE: EEP) for cash proceeds of $682.0 million, exclusive of working capital adjustments and transaction costs. The Partnership accounted for the earnings of APL’s Elk City as discontinued operations within its consolidated financial statements and recorded a gain of $312.1 million on the sale of APL’s Elk City within income from discontinued operations on its consolidated statements of operations during the year ended December 31, 2010. APL’s Elk City was previously reported within APL’s Mid-Continent segment of operations.

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


	Years Ended December 31,
	2010			2009			2008
NOARK
Total revenue and other income (loss), net	$	—		$	21,274		$	62,423
Total costs and expenses		—			(9,857	)		(41,877	)
Gain on asset sales and other		—			51,078			—

Income from NOARK discontinued operations		—			62,495			20,546


Elk City
Total revenue and other income (loss), net		129,908			167,543			180,366
Total costs and expenses		(120,855	)		(148,383	)		(294,714	)
Gain on asset sales and other		312,102			2,493			—

Income (loss) from Elk City discontinued operations		321,155			21,653			(114,348	)


Total income (loss) from discontinued operations	$	321,155		$	84,148		$	(93,802	)

During the year ended December 31, 2008, the Partnership recognized on its consolidated statements of operations, within income from discontinued operations, $61.1 million of goodwill impairment charges related to APL’s Elk City and impairment charges totaling $21.6 million in connection with a write-off of costs related to APL’s NOARK pipeline expansion project. The costs incurred for the pipeline expansion consisted of preliminary construction and engineering costs incurred as well as a vendor deposit for the manufacture of pipeline which expired in accordance with APL’s contractual arrangement.

The following table summarizes the components included within total assets and liabilities of discontinued operations, all of which relate to APL’s Elk City, within the Partnership’s consolidated balance sheets for the year ended December 31, 2009 (in thousands):


	December 31, 2009
Cash and cash equivalents	$	—
Accounts receivable		20,702
Prepaid expenses and other		2,044

Total current assets of discontinued operations		22,746

Property, plant and equipment, net		356,680
Intangible assets, net		18,610
Other assets, net		3,740

Total assets of discontinued operations	$	401,776


Accounts payable	$	3,372
Accrued liabilities		1,028
Accrued producer liabilities		8,781

Total current liabilities of discontinued operations	$	13,181

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NOTE 5 – ATLAS ENERGY, L.P. EQUITY OFFERINGS

On June 1, 2009, a newly created, wholly-owned subsidiary of the Partnership, Atlas Pipeline Holdings II, LLC (“AHD Sub”), issued $15.0 million of $1,000 par value 12.0% Class B preferred equity (“AHD Sub Preferred Units”) to APL for cash pursuant to a certificate of designation. The Partnership utilized the net proceeds from the issuance to reduce borrowings under its senior secured credit facility (see Note 13). Distributions on the AHD Sub Preferred Units were payable quarterly on the same date as the distribution payment date for the Partnership’s common units. On November 15, 2010, AHD Sub exercised its option to redeem its 15,000 12.0% cumulative preferred units for cash at the liquidation value of $1,000 per unit, or $15.0 million plus $0.2 million accrued dividends. Concurrently, APL redeemed its 15,000 units of APL Class B Preferred Units held by the Partnership for cash at the liquidation value of $1,000 per unit, or $15.0 million plus $0.2 million accrued dividends. APL owned all of the outstanding AHD Sub Preferred Units in an amount equal to the APL Class B Preferred Units that the Partnership owned (see Note 7), thus the amounts were eliminated in consolidation of the Partnership’s consolidated balance sheets as of December 31, 2009. There were no AHD Sub Preferred Units outstanding as of December 31, 2010.

In June 2008, the Partnership sold 308,109 common units through a private placement to ATLS at a price of $32.50 per unit, for net proceeds of approximately $10.0 million. The Partnership utilized the net proceeds from the sale to purchase 278,000 common units of APL (see Note 6), which in turn utilized the proceeds to partially fund the early termination of certain derivative agreements (see Note 11). Following the Partnership’s private placement, ATLS had a 64.4% ownership interest in the Partnership.

NOTE 6 – APL COMMON UNIT EQUITY OFFERINGS

In June 2008, APL sold 5,750,000 common units in a public offering at a price of $37.52 per unit, yielding net proceeds of approximately $206.6 million. Also in June 2008, APL sold 1,112,000 common units to ATLS and 278,000 common units to the Partnership in a private placement at a net price of $36.02 per unit, resulting in net proceeds of approximately $50.1 million. APL also received a capital contribution from the Partnership of $5.4 million for it to maintain its 2.0% general partner interest in APL. APL utilized the net proceeds from both sales and the capital contribution to fund the early termination of certain derivative agreements (see Note 11).

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 its 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 (see Note 13).

On January 7, 2010, APL executed amendments to the warrants originally issued 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 per unit from $6.35 per unit. In connection with the amendments, the holders of the warrants exercised all of the warrants for cash, which resulted in net cash proceeds of approximately $15.3 million to APL. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan (see Note 13) and to fund the early termination of certain derivative agreements (see Note 11).

On March 31, 2010, APL and its Operating Partnership amended their respective partnership agreements to temporarily waive the requirement that Atlas Pipeline GP make aggregate cash contributions of approximately $0.3 million, which was required in connection with APL’s issuance of 2,689,765 of its common units upon the exercise of warrants in January 2010. During the waiver period, the aggregate ownership percentage attributable to Atlas Pipeline GP’s general partner interest in APL was reduced to 1.9%.

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The waiver remained in effect until Atlas Pipeline GP made the required capital contribution on November 30, 2010.

NOTE 7 – APL PREFERRED UNIT EQUITY OFFERINGS

APL Class A Preferred Units

In December 2008, APL redeemed 10,000 of the then-outstanding 40,000 6.5% cumulative convertible preferred units (“APL Class A Preferred Units”), held by Sunlight Capital Partners, LLC (“Sunlight Capital”), an affiliate of Elliott & Associates, for $10.0 million in cash under the terms of the agreement. The redemption was classified as a reduction of non-controlling interest in APL within the Partnership’s consolidated balance sheets.

In January, 2009, APL and Sunlight Capital amended certain terms of the APL Class A Preferred Units. The amendment (a) increased the dividend yield from 6.5% to 12.0% per annum, effective January 1, 2009, and (b) required that APL issue Sunlight Capital $15.0 million of its 8.125% senior unsecured notes due 2015 (see Note 13) to redeem 10,000 APL Class A Preferred Units. Management of APL estimated that the fair value of the $15.0 million 8.125% APL senior unsecured notes issued to redeem the APL Class A Preferred Units was approximately $10.0 million at the date of redemption based upon the market price of the publicly-traded APL senior notes. As such, APL recorded the redemption by recognizing a $10.0 million reduction of APL Class A Preferred equity within Equity, $15.0 million of additional long-term debt for the face value of the senior unsecured notes issued, and a $5.0 million discount on the issuance of the APL senior unsecured notes which is presented as a reduction of long-term debt on the Partnership’s consolidated balance sheets. The discount recognized upon issuance of the APL senior unsecured notes will be amortized to interest expense within the Partnership’s consolidated statements of operations over the term of the notes based upon the effective interest rate method.

On April 1, 2009, APL redeemed 10,000 of the APL Class A Preferred Units for cash at the liquidation value of $1,000 per unit, or $10.0 million, plus $0.3 million, representing the quarterly dividend on the 10,000 preferred units prior to APL’s redemption. On April 13, 2009, APL converted 5,000 of the APL Class A Preferred Units into 1,465,653 Partnership common units, reclassifying $5.0 million from Class A preferred limited partner equity to common limited partner equity within Equity. On May 5, 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 APL Class A Preferred Units prior to APL’s redemption. There are no longer any APL Class A Preferred Units outstanding.

APL recognized $0.4 million of preferred dividend cost for the year ended December 31, 2009 for dividends paid to the APL Class A preferred units, which is presented as a reduction of net income (loss) to determine net income (loss) attributable to common limited partners and the general partner on APL’s consolidated statements of operations.

The initial issuances of the 40,000 APL Class A Preferred Units were recorded on the consolidated balance sheets at the amount of net proceeds received less an imputed dividend cost. As a result of an amendment to the preferred units certificate of designation in March 2007, APL, in lieu of dividend payments to Sunlight Capital, recognized an imputed dividend cost of $2.5 million that was amortized over a twelve-month period commencing March 2007 and was based upon the present value of the net proceeds received using the then 6.5% stated dividend yield. During the twelve months ended December 31, 2008, APL amortized the remaining $0.5 million of this imputed dividend cost, which is presented as an additional adjustment of net income (loss) to determine net income (loss) attributable to common limited partners and the general partner on APL’s consolidated statements of operations for the year ended December 31, 2008.

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APL Class B Preferred Units

In December 2008, APL sold 10,000 Class B Preferred Units (the “APL Class B Preferred Units”) to the Partnership for cash consideration of $1,000 per APL Class B Preferred Unit (the “Face Value”) pursuant to a certificate of designation (the “APL Class B Preferred Units Certificate of Designation”). On March 30, 2009, the Partnership purchased an additional 5,000 Class B Preferred Units at Face Value for net cost of $5.0 million. APL used the proceeds from the sale of the Class B Preferred Units for general partnership purposes. As holders of the APL Class B Preferred Units, the Partnership received distributions of 12.0% per annum. Additionally, on March 30, 2009, APL and the Partnership agreed to amend the terms of the APL Class B Preferred Units Certificate of Designation to remove the conversion feature, thus the APL Class B Preferred Units were not convertible into APL common units. The cumulative sale of the APL Class B Preferred Units to the Partnership was exempt from the registration requirements of the Securities Act of 1933.

On November 15, 2010, APL redeemed the 15,000 units of APL Class B Preferred Units for cash at the liquidation value of $1,000 per unit, or $15.0 million. Additionally, on November 15, 2010, APL paid the Partnership a preferred dividend of $0.2 million, representing the quarterly dividend on the 15,000 APL Class B Preferred Units prior to the APL’s redemption. There are no longer any APL Class B Preferred Units outstanding. The Partnership received $2.9 million and $0.5 million in preferred dividends for the years ended December 31, 2010 and 2009, respectively.

APL Class C Preferred Units

On June 30, 2010, APL sold 8,000 newly-created 12% Cumulative Class C Preferred Units of limited partner interest (the “APL Class C Preferred Units”) to ATLS for cash consideration of $1,000 per APL Class C Preferred Unit (the “APL Class C Preferred Unit Face Value”). APL used the proceeds from the sale of the APL Class C Preferred Units for general partnership purposes. The APL Class C Preferred Units are entitled to receive distributions of 12.0% per annum, paid quarterly on the same date as the distribution payment date for APL’s common units. The APL Class C Preferred Units are not convertible into common units of APL. APL has the right at any time to redeem some or all of the outstanding APL Class C Preferred Units (but not less than 2,500 APL Class C Preferred Units) for cash at an amount equal to the APL Class C Preferred Face Value being redeemed plus accrued but unpaid dividends.

The sale of the APL Class C Preferred Units to ATLS was exempt from the registration requirements of the Securities Act of 1933.

APL recognized $0.5 million of preferred dividend cost for the year ended December 31, 2010, which is presented as a reduction of net income (loss) to determine net income (loss) attributable to common limited partners and the General Partner on its consolidated statements of operations.

NOTE 8 – CASH DISTRIBUTIONS

Atlas Energy, L.P. 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, 2008 through December 31, 2010 were as follows:

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For Quarter Ended	Date Cash Distribution Paid	Cash Distribution per Common Limited Partner Unit		Total Cash Distribution to Common Limited Partners
				(in thousands)

December 31, 2007	February 19, 2008	$	0.34	$	9,299
March 31, 2008	May 20, 2008		0.43		11,761
June 30, 2008	August 19, 2008		0.51		14,106
September 30, 2008	November 19, 2008		0.51		14,106

December 31, 2008	February 19, 2009		0.06		1,660
March 31, 2009	None		0.00		—
June 30, 2009	None		0.00		—
September 30, 2009	None		0.00		—

December 31, 2009	None		0.00		—
March 31, 2010	None		0.00		—
June 30, 2010	None		0.00		—
September 30, 2010	November 16, 2010		0.05		1,385

On January 25, 2011, the Partnership declared a cash distribution of $0.07 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2010. The $1.9 million distribution was paid on February 18, 2011 to unitholders of record at the close of business on February 7, 2011.

APL 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, 2008 through December 31, 2010 were as follows:


For Quarter Ended	Date Cash Distribution Paid	Cash Distribution Per Common Limited Partner Unit		Total Cash Distribution to Common Limited Partners		Total Cash Distribution to the General Partner
				(in thousands)		(in thousands)

December 31, 2007	February 14, 2008	$	0.93	$	36,051	$	5,092
March 31, 2008	May 15, 2008		0.94		36,450		7,891
June 30, 2008	August 14, 2008		0.96		44,096		9,308
September 30, 2008	November 14, 2008		0.96		44,105		9,312

December 31, 2008	February 13, 2009		0.38		17,463		358
March 31, 2009	May 15, 2009		0.15		7,149		147
June 30, 2009	None		0.00		—		—
September 30, 2009	None		0.00		—		—

December 31, 2009	None		0.00		—		—
March 31, 2010	None		0.00		—		—
June 30, 2010	None		0.00		—		—
September 30, 2010	November 14, 2010		0.35		18,660		363

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In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems, Atlas Pipeline GP, which holds all of the incentive distribution rights in APL, agreed to allocate a portion of its incentive distribution rights back to APL, as set forth in the IDR Adjustment Agreement.

On January 25, 2011, APL declared a cash distribution of $0.37 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2010. The $20.1 million distribution, including $0.4 million to the General Partner for its general partner interest, was paid on February 14, 2011 to unitholders of record at the close of business on February 7, 2011.

NOTE 9 – PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment (in thousands):


	December 31,						Estimated Useful Lives in Years
	December 31,
	2010			2009⁽¹⁾
Pipelines, processing and compression facilities	$	1,340,944		$	1,281,366			2 – 40
Rights of way		156,713			152,908			20 – 40
Buildings		8,047			8,047			40
Furniture and equipment		8,981			8,848			3 – 7
Other		12,659			11,633			3 – 10

		1,527,344			1,462,802
Less – accumulated depreciation		(186,342	)		(135,098	)

	$	1,341,002		$	1,327,704

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City (see Note 4).

NOTE 10 – OTHER ASSETS

The following is a summary of other assets (in thousands):


	December 31,
	2010		2009⁽¹⁾
Deferred finance costs, net of accumulated amortization of $24,436 and $25,752 at December 31, 2010 and 2009, respectively	$	28,327	$	27,404
Security deposits		2,841		2,922

	$	31,168	$	30,326

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City (see Note 4).

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (see Note 13). During the years ended December 31, 2010, 2009 and 2008, APL recorded $4.4 million, $2.5 million and $2.5 million, respectively, related to accelerated amortization of deferred financing costs associated with the retirement of its term loan. Total amortization expense of deferred finance costs for the Partnership and APL was $10.6 million, $8.0 million and $5.9 million for the years ended December 31, 2010, 2009 and 2008, respectively, which is recorded within interest expense on the Partnership’s consolidated statements of operations. Amortization expense related to deferred finance costs is estimated to be as follows for each of the next five calendar years: 2011 to 2014 - $5.0 million; 2015 - $4.7 million.

NOTE 11 – DERIVATIVE INSTRUMENTS

The Partnership and APL use derivative instruments, principally swaps and options, in connection with its commodity price and interest rate risk management activities. APL enters into financial swap and option instruments to hedge its forecasted natural gas, NGLs and condensate sales and natural gas purchases against the variability in expected future cash flows attributable to changes in market prices. The Partnership and APL also previously entered into financial swap instruments to hedge certain portions of its floating

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interest rate debt against the variability in market interest rates. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate are sold or interest payments on the underlying debt instrument are due. Under its swap agreements, APL receives or pays a fixed price and receives or remits 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.

On July 1, 2008, APL discontinued hedge accounting for certain existing qualified crude oil derivatives, utilized to hedge forecasted NGL production, due to significant ineffectiveness. APL also discontinued hedge accounting for all of its other qualified commodity derivatives for consistency in reporting of all commodity-based derivatives. As such, subsequent changes in fair value of these derivatives are recognized immediately within other income (loss), net in the Partnership’s consolidated statements of operations. The fair value of these commodity derivative instruments at June 30, 2008, which was recognized in non-controlling interests and accumulated other comprehensive loss within Equity on the Partnership’s consolidated balance sheets, will be reclassified to the Partnership’s consolidated statements of operations in the future at the time the originally hedged physical transactions affect earnings.

The portion of any gain or loss in other comprehensive income related to originally forecasted transactions that are no longer expected to occur are removed from other comprehensive income and recognized within the statements of operations. In September 2010, APL sold its Elk City assets (see Note 4), thus the Partnership recognized a loss of $10.6 million within discontinued operations in the Partnership’s statements of operations with a corresponding decrease in non-controlling interests and accumulated other comprehensive loss within Equity on the Partnership’s consolidated balance sheets, since the related originally forecasted transactions related to the APL’s Elk City operations are no longer expected to occur. The $10.6 million loss reclassed from other comprehensive income includes $1.4 million related to derivatives which were settled early and $9.2 million related to derivatives which will settle in future periods.

The Partnership’s and APL’s derivatives are recorded on the Partnership’s consolidated balance sheets as assets or liabilities at fair value. Premium costs for purchased options are recorded on the Partnership’s consolidated balance sheets as the initial value of the options. Changes in the fair value of the options are recognized within other income (loss), net as unrealized gain (loss) on the Partnership’s consolidated statements of operations. Premium costs are reclassified to realized gain (loss) within other income (loss), net at the time the option expires or is exercised. The Partnership reflected net derivative liabilities on its consolidated balance sheets of $10.2 million and $43.6 million at December 31, 2010 and 2009, respectively. The Partnership will reclassify $0.8 million of the $1.4 million net loss in accumulated other comprehensive loss within Equity on the Partnership’s consolidated balance sheets at December 31, 2010, to natural gas and liquids revenue on the Partnership’s consolidated statements of operations over the next twelve month period. Aggregate losses of $0.6 million will be reclassified to natural gas and liquids revenue on the Partnership’s consolidated statements of operations in later periods. At December 31, 2010, no derivative instruments are designated as hedges for hedge accounting purposes.

The fair value of the Partnership’s and APL’s derivative instruments was included in the Partnership’s consolidated balance sheets as follows (in thousands):


	December 31, 2010			December 31, 2009
Current portion of derivative asset	$	—		$	998
Long-term derivative asset		—			361
Current portion of derivative liability		(4,564	)		(33,833	)
Long-term derivative liability		(5,608	)		(11,126	)

	$	(10,172	)	$	(43,600	)

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


Contract Type	Balance Sheet Location	December 31, 2010			December 31, 2009

Asset Derivatives
Commodity contracts	Current portion of derivative asset	$	—		$	1,591
Commodity contracts	Long-term derivative asset		—			361
Commodity contracts	Current portion of derivative liability		2,624			6,562
Commodity contracts	Long-term derivative liability		1,052			3,435

			3,676			11,949


Liability Derivatives
Interest rate contracts	Current portion of derivative liability		—			(2,533	)
Interest rate contracts	Current portion of derivative asset		—			(593	)
Commodity contracts	Current portion of derivative liability		(7,188	)		(37,862	)
Commodity contracts	Long-term derivative liability		(6,660	)		(14,561	)

			(13,848	)		(55,549	)

Total Derivatives		$	(10,172	)	$	(43,600	)

The following table summarizes APL’s commodity derivatives as of December 31, 2010, none of which are designated for hedge accounting (dollars and volumes in thousands):

Fixed Price Swaps


Production Period	Purchased/ Sold		Commodity	Volumes⁽²⁾		Average Fixed Price			Fair Value⁽¹⁾ Asset/ (Liability)

Natural Gas
2011		Sold	Natural Gas Basis		1,920		(0.728	)	$	(886	)
2011		Purchased	Natural Gas Basis		1,920		(0.758	)		944
2011		Sold	Natural Gas		2,100		4.481			(66	)

Natural Gas Liquids
2011		Sold	Ethane		10,458		0.496			(788	)
2011		Sold	Propane		16,758		1.161			(1,022	)
2011		Sold	Isobutane		1,008		1.618			124
2011		Sold	Normal Butane		2,772		1.580			(23	)
2011		Sold	Natural Gasoline		1,764		1.990			(81	)

Crude Oil
2011		Sold	Crude Oil		138		91.92			(227	)

Total Fixed Price Swaps									$	(2,025	)

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Options


Production Period	Purchased/ Sold		Type		Commodity		Volumes⁽²⁾		Average Strike Price		Fair Value⁽¹⁾ Asset/ (Liability)

Crude Oil
2011		Purchased		Put		Crude Oil		420		89.00		1,357
2011		Sold		Call		Crude Oil		678		94.68		(4,797	)
2011		Purchased⁽³⁾		Call		Crude Oil		252		120.00		278
2012		Sold		Call		Crude Oil		498		95.83		(5,677	)
2012		Purchased⁽³⁾		Call		Crude Oil		180		120.00		692

Total Options											$	(8,147	)


Total Fair Value											$	(10,172	)

(1)	See Note 12 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 2011 and 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 continue to rise.

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


	For the Years ended December 31,
	2010		2009⁽¹⁾			2008⁽¹⁾
Gain (Loss) Recognized in Accumulated Other Comprehensive Income

Contract Type
Interest rate contracts⁽²⁾	$	—	$	(2,412	)	$	(13,741	)
Commodity contracts⁽²⁾		—		—			(112,824	)

	$	—	$	(2,412	)	$	(126,565	)


		For the Years ended December 31,
		2010			2009⁽¹⁾			2008⁽¹⁾
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income

Contract Type	Location
Interest rate contracts⁽²⁾	Interest expense	$	(2,312	)	$	(12,260	)	$	(1,289	)
Interest rate contracts⁽²⁾	Other income (loss), net		—			(292	)		—
Commodity contracts⁽²⁾	Natural gas and liquids revenue		(15,570	)		(31,000	)		(45,866	)
Commodity contracts⁽²⁾	Discontinued operations		(20,154	)		(15,268	)		(35,791	)

		$	(38,036	)	$	(58,820	)	$	(82,946	)


Gain (Loss) Recognized in Income (Ineffective portion and derivatives not designated as hedges)

Contract Type	Location
Interest rate contracts⁽²⁾	Other income (loss), net	$	(6	)	$	(1,288	)	$	—
Commodity contracts⁽²⁾	Natural gas and liquids revenue		—			273			(23,359	)
Commodity contracts⁽²⁾	Other income (loss), net		—			—			(270,999	)
Commodity contracts⁽²⁾	Discontinued operations		—			(396	)		7,022
Commodity contracts⁽³⁾	Other income (loss), net		(5,939	)		(34,774	)		300,740
Commodity contracts⁽³⁾	Discontinued operations		665			(1,190	)		(100,243	)

		$	(5,280	)	$	(37,375	)	$	(86,839	)

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City (see Note 4).

(2)	Hedges previously designated as cash flow hedges.

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

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NOTE 12 – FAIR VALUE OF FINANCIAL INSTRUMENTS

Derivative Instruments

The Partnership uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following hierarchy:

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 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumption 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.

The Partnership uses a fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 11). At December 31, 2010, all of APL’s derivative contracts are defined as Level 2, with the exception of APL’s NGL fixed price swaps and NGL options. APL’s Level 2 commodity derivatives include natural gas and crude oil swaps and options which are calculated based upon observable market data related to the change in price of the underlying commodity. These swaps and options are calculated by utilizing the New York Mercantile Exchange (“NYMEX”) quoted price for futures and option contracts traded on NYMEX that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula. 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. Valuations for APL’s NGL options are based on forward price curves developed by financial institutions, and therefore are defined as Level 3.

On June 30, 2009, APL changed the basis for its valuation of crude oil options. Previously, APL utilized forward price curves developed by its derivative counterparties. Effective June 30, 2009, APL utilized crude oil option prices quoted from a public commodity exchange. With this change in valuation basis, APL reclassified the inputs for the valuation of its crude oil options from a Level 3 input to a Level 2 input. The change in valuation basis did not materially impact the fair value of APL’s derivative instruments on its consolidated statements of operations.

The following table represents the Partnership’s and APL’s derivative assets and liabilities recorded at fair value as of December 31, 2010 and 2009 (in thousands):

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	Level 1		Level 2			Level 3			Total
December 31, 2010
Assets
Commodity swaps	$	—	$	1,225		$	124		$	1,349
Commodity options		—		2,327			—			2,327

Total assets		—		3,552			124			3,676

Liabilities
Commodity swaps		—		(1,461	)		(1,914	)		(3,375	)
Commodity options		—		(10,473	)		—			(10,473	)

Total liabilities		—		(11,934	)		(1,914	)		(13,848	)


Total derivatives	$	—	$	(8,382	)	$	(1,790	)	$	(10,172	)

December 31, 2009
Assets
Commodity swaps	$	—	$	4,540		$	—		$	4,540
Commodity options		—		6,141			1,268			7,409

Total assets		—		10,681			1,268			11,949

Liabilities
Interest rate swaps		—		(3,126	)		—			(3,126	)
Commodity swaps		—		(16,355	)		—			(16,355	)
Commodity options		—		(36,068	)		—			(36,068	)

Total liabilities		—		(55,549	)		—			(55,549	)


Total derivatives	$	—	$	(44,868	)	$	1,268		$	(43,600	)

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 for the years ended December 31, 2010 and 2009 (in thousands):


	NGL Fixed Price Swaps						NGL Put Options						Crude Oil Options						Total
	Volume⁽¹⁾			Amount			Volume⁽¹⁾			Amount			Volume⁽¹⁾			Amount			Amount
Balance – December 31, 2008		8,568		$	1,509			28,904		$	12,316			6,372		$	(23,436	)	$	(9,611	)
New contracts		6,804			—			93,870			—			—			—			—
Cash settlements from unrealized gain (loss)⁽²⁾⁽⁴⁾		(15,372	)		(5,527	)		(79,304	)		(7,065	)		1,434			(37,671	)		(50,263	)
Cash settlements from other comprehensive income⁽³⁾		—			7,153			—			—			—			11,618			18,771
Net change in unrealized loss⁽²⁾		—			(3,135	)		—			(10,552	)		—			14,886			1,199
Option premium recognition⁽⁴⁾		—			—			—			6,569			—			2,239			8,808
Transfer to Level 2		—			—			—			—			(7,806	)		32,364			32,364

Balance – December 31, 2009		—		$	—			43,470		$	1,268			—		$	—		$	1,268

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Balance – December 31, 2009	—		$	—		43,470		$	1,268		—	$	—	$	1,268
New contracts	57,246			—		8,820			—		—		—		—
Cash settlements⁽²⁾⁽⁴⁾	(24,486	)		1,634		(52,290	)		7,246		—		—		8,880
Net change in unrealized loss⁽²⁾	—			(3,424	)	—			(2,005	)	—		—		(5,429	)
Option premium recognition⁽⁴⁾	—			—		—			(6,509	)	—		—		(6,509	)

Balance – December 31, 2010	32,760		$	(1,790	)	—		$	—		—	$	—	$	(1,790	)

(1)	Volumes for NGLs are stated in gallons; volumes for crude oil are stated in barrels.

(2)	Included within other income (loss), net on the Partnership’s consolidated statements of operations.

(3)	Included within natural gas and liquids revenue on the Partnership’s consolidated 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 and APL’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 or APL could realize upon the sale or refinancing of such financial instruments.

The Partnership’s current assets and liabilities on its consolidated balance sheets, other than the derivatives discussed above, are considered to be financial instruments for which 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 total debt at December 31, 2010 and 2009, which consists principally of borrowings under the Partnership’s and APL’s credit facilities, APL’s term loan (repaid in September 2010) and APL’s Senior Notes, was $567.7 million and $1,226.5 million, respectively, compared with the carrying amounts of $601.4 million and $1,286.4 million, respectively. The APL term loan and APL Senior Notes were valued based upon available market data for similar issues. The carrying value of outstanding borrowings under APL’s revolving credit facility, which bear interest at a variable interest rate, approximates their estimated fair value.

NOTE 13 – DEBT

Total debt consists of the following (in thousands):


	December 31, 2010			December 31, 2009
Credit facility	$	—		$	8,000
Amended and consolidated demand note with ATLS		35,415			24,255
APL revolving credit facility		70,000			326,000
APL term loan		—			433,505
APL 8.125% Senior notes – due 2015		272,181			271,628
APL 8.75% Senior notes – due 2018		223,050			223,050
APL capital lease obligations		743			—

Total debt		601,389			1,286,438
Less current maturities		(35,625	)		(32,255	)

Total long term debt	$	565,764		$	1,254,183

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Atlas Energy, L.P. Credit Facility

On June 1, 2009, the Partnership entered into an amendment to its credit facility agreement which required the Partnership to immediately repay $30.0 million of the then-outstanding $46.0 million of borrowings under the credit facility and to repay $4.0 million of the remaining $16.0 million outstanding on each of July 13, 2009, October 13, 2009 and January 13, 2010, with the balance of the indebtedness being due on the original maturity date of the credit facility of April 13, 2010. All payments were timely made by funding from ATLS under its guaranty of the Partnership’s obligations. The Partnership may not borrow additional amounts under the credit facility or issue letters of credit. On April 13, 2010, the Partnership’s credit facility with a syndicate of banks was paid in full. On February 17, 2011, the Partnership entered into a new credit facility agreement (See Note 20).

Demand Note with Atlas Energy, Inc.

On June 1, 2009, in connection with its amendment of the credit facility, the Partnership borrowed $15.0 million from ATLS under a 12% per annum subordinate loan. The Partnership incurred interest expense of $1.0 million and $1.1 million on the subordinate loan during the years ended December 31, 2010 and 2009, respectively, which was included in interest expense on the Partnership’s statements of operations. The interest was added to the principal of the subordinate loan.

Also, on June 1, 2009, in consideration of ATLS’s guaranty of the indebtedness under the Partnership’s credit facility, the Partnership entered into a guaranty note with ATLS. ATLS funded $8.0 million in both the years ended December 31, 2010 and 2009, respectively, under its guaranty of the Partnership’s obligations. The Partnership incurred $0.1 million and $0.2 million in fees and interest under the guaranty note during the years ended December 31, 2010 and 2009, respectively, which was included in interest expense on the Partnership’s statements of operations. The interest and fees were added to the principal of the guaranty note.

The subordinate loan and guaranty note matured on April 14, 2010, the day following the date that the Partnership repaid all outstanding borrowings under its credit facility. On July 19, 2010, the Partnership entered into an amended and consolidated demand note (the “Note”) with ATLS to consolidate in one instrument the debt owed to ATLS under the $15.0 million subordinate loan, the $0.3 million guaranty note and the $16.0 million advance under ATLS’s guaranty of the Partnership’s credit facility, plus accrued interest. The initial principal of the Note was $33.4 million; the interest rate on the Note is 12% per annum, which, prior to demand by ATLS for cash payment, will be payable by accruing such interest and adding the amount to the principal amount of the Note on a quarterly basis; and the Note is payable on demand. During the year ended December 31, 2010, the Partnership accrued $2.0 million in interest expense, which was added to the principal amount of the Note. As of December 31, 2010, the Partnership reflected $35.4 million in the current portion of long term debt on the Partnership’s consolidated balance sheets related to its obligations to ATLS On February 17, 2011, the Partnership paid in full the outstanding balance of the Note (see Note 20).

APL Term Loan and Revolving Credit Facility

At December 31, 2010, APL had a senior secured credit facility with a syndicate of banks, which consisted of a $350.0 million revolving credit facility that matures in December 2015. A $425.8 million term loan, scheduled to mature in July 2014, was paid in full in September 2010 with proceeds APL received from its Elk City asset sale (see Note 4). Borrowings under APL’s revolving 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 the outstanding APL revolving credit facility borrowings at December 31, 2010 was 3.8%. Up to $50.0 million of APL’s credit facility may be utilized for letters of credit, of which $3.2 million was outstanding at December 31, 2010. These outstanding letter of credit amounts were not

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reflected as borrowings on the Partnership’s consolidated balance sheets. At December 31, 2010, APL had $276.8 million of remaining committed capacity under its credit facility, subject to covenant limitations.

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 Chaney Dell and Midkiff/Benedum joint ventures and Laurel Mountain; and by the guaranty of each of APL’s consolidated subsidiaries other than the joint venture companies. APL’s credit facility contains customary covenants, including restrictions on APL’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or 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. APL is in compliance with these covenants as of December 31, 2010.

The events which constitute an event of default for APL’s 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.

On September 1, 2010, APL entered into an amendment to its credit facility agreement, which, among other changes revised the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to premiums associated with hedging agreements and to exclude the net gains or losses attributable to a disposition of assets other than in the ordinary course of business.

On December 22, 2010, APL entered into an amended and restated credit facility agreement which, among other changes:

•

set the maturity date of APL’s revolving credit facility to December 22, 2015;

•

reduced APL’s revolving credit facility from $380.0 million to $350.0 million;

•

eliminated the 2.0% per annum floor previously applied to adjusted LIBOR;

•

revised the Applicable Margin used to determine interest rates;

•

removed restrictions on APL making investments in the Laurel Mountain joint venture if specified financial thresholds are not met;

•

eliminated the requirements that APL meet specified financial thresholds in order to be permitted to make distributions to its unitholders;

•

eliminated the limits on APL’s annual capital expenditures if specified financial thresholds are not met; and

•

As of December 31, 2010, APL was in compliance with all covenants under the credit facility.

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APL Senior Notes

In January 2009, APL issued Sunlight Capital $15.0 million of its 8.125% Senior Notes to redeem 10,000 APL Class A Preferred Units (see Note 7). Management of APL estimated that the fair value of the $15.0 million 8.125% Senior Notes issued was approximately $10.0 million at the date of issuance based upon the market price of the publicly-traded Senior Notes. As such, APL recognized a $5.0 million discount on the issuance of the Senior Notes, which is presented as a reduction of long-term debt on the Partnership’s consolidated balance sheets. The discount recognized upon issuance of the Senior Notes will be amortized to interest expense within the Partnership’s consolidated statements of operations over the term of the 8.125% Senior Notes based upon the effective interest rate method.

In November 2010, APL paid $1.3 million to the holders of the APL 8.125% Senior Notes in connection with a solicited consent received from the majority of holders of the APL 8.125% Senior Notes to amend certain provisions of the Indenture governing the APL 8.125% Senior Notes. The amendment allows APL to make certain capital contributions to Laurel Mountain Midstream, LLC. The $1.3 million was recorded as deferred financing costs within other assets on the Partnership’s consolidated balance sheets and will be amortized over the remaining life of the APL 8.125% Senior Notes.

In connection with the issuance of the APL 8.75% Senior Notes, APL entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission for the APL 8.75% Senior Notes, (b) cause the exchange offer registration statement to be declared effective by the Securities and Exchange Commission, and (c) cause the exchange offer to be consummated by February 23, 2009. If APL did not meet the aforementioned deadline, the APL 8.75% Senior Notes would have been subject to additional interest, up to 1% per annum, until such time that APL had caused the exchange offer to be consummated. On November 21, 2008, APL filed an exchange offer registration statement for the APL 8.75% Senior Notes with the Securities and Exchange Commission, which was declared effective on December 16, 2008. The exchange offer was consummated on January 21, 2009, thereby fulfilling all of the requirements of the 8.75% Senior Notes registration rights agreement by the specified dates.

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

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Years Ended December 31:
2011	$	35,625
2012		226
2013		243
2014		64
2015		345,479
Thereafter		223,050

Total principle maturities		604,687
Net unamortized discount		(3,298	)

Total debt	$	601,389

Cash payments for interest related to the Partnership’s and APL’s debt were $91.9 million, $92.2 million and $87.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.

NOTE 14 – COMMITMENTS AND CONTINGENCIES

APL has noncancelable operating leases for equipment and office space that expire at various dates. Certain operating leases provide APL with the option to renew for additional periods. Where operating leases contain escalation clauses, rent abatements, and/or concessions, APL applies them in the determination of straight-line rent expense over the lease term. Leasehold improvements are amortized over the shorter of the lease term or asset life, which may include renewal periods where the renewal is reasonably assured, and is included in the determination of straight-line rent expense. Total rental expense for the years ended December 31, 2010, 2009 and 2008 was $6.4 million, $6.8 million and $7.0 million, respectively.

The aggregate amount of remaining future minimum annual lease payments as of December 31, 2010 is as follows (in thousands):


Years Ended December 31:
2011	$	4,737
2012		3,651
2013		1,644
2014		77
2015		47
Thereafter		—

	$	10,156

APL is a party to various routine legal proceedings arising out of the ordinary course of its business. Management of the Partnership believes that the ultimate resolution of these actions, individually or in the aggregate, will not have a material adverse effect on its financial condition or results of operations.

On February 26, 2010, APL received notice from Williams, its joint venture partner in Laurel Mountain, alleging that certain title defects exist with respect to the real property contributed by the Partnership to Laurel Mountain. Under the Formation and Exchange Agreement with Williams (“Formation Agreement”) : (i) Williams had nine months after closing (the “Claim Date”) to assert any alleged title defects, and (ii) APL had 30 days following the Claim Date to contest the title defects asserted by Williams and 180 days following the Claim Date to cure those title defects. On March 26, 2010, APL delivered notice, disputing Williams’ alleged title defects as well as the amounts claimed. By agreement dated December 22, 2010, Williams agreed to extend the cure period until March 31, 2011. ATLS has delivered a proposed assignment to Laurel Mountain that should resolve some of the alleged deficiencies. At the end of the cure period, with respect to any remaining title defects, APL may elect, at its option, to pay Williams for the cost of such defects, up to a total of $3.5 million, or indemnify Williams with respect to such title defects. Williams also claims, in a letter dated August 26, 2010, that the alleged title defects violate APL’s

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representation with respect to sufficiency of the assets contributed to Laurel Mountain. If valid, this would make Williams’ title defect claims subject to a higher deductible (which is noted below). APL believes its representations with respect to title are Williams’ sole and exclusive remedy with respect to title matters.

In August 2010, Williams asserted additional indemnity claims under the Formation Agreement totaling approximately $19.8 million. Williams’ claims are generally based on APL’s alleged failure to construct and maintain the assets contributed to Laurel Mountain in accordance with “standard industry practice” or applicable law. As a preliminary matter, APL believes Williams has overstated its claim by forty-nine percent (49%), because, under the Formation Agreement, these claims are reduced on a pro-rata basis to equal Williams’ percentage ownership interest in Laurel Mountain. APL has received some additional information from Williams and, based on APL’s analysis of that information, APL believes that an adverse outcome is probable with respect to some portion of Williams’ claims. APL has established an accrual with respect to the portion of Williams’ claims that it deems probable, which is less that 51% of the amounts asserted by Williams. Under the Formation Agreement, Williams’ indemnity claims are capped, in the aggregate, at $27.5 million. In addition, APL is entitled to indemnification from ATLS with respect to some of Williams’ claims.

Following the November 9, 2010 announcement (the “Announcement”) that ATLS had entered into a definitive agreement to be acquired by Chevron Corporation (the “Merger”) and that the Partnership and APL agreed to enter into separate transactions with ATLS relating to certain ATLS natural gas reserves and other assets and fee revenues, and APL’s interest in Laurel Mountain (the “Transactions”), with each of the Transactions and the Merger to be cross-conditioned on the completion of the others, a purported class action was filed on November 15, 2010, in Delaware Chancery Court on behalf of a class of ATLS shareholders, Katsman v. ATLS, et al., C.A. No. 5990-VCL. The complaint named the Partnership and APL and alleges that the ATLS directors violated their fiduciary duties in connection with the proposed Merger and that the Partnership, APL, and Chevron aided and abetted the alleged breaches of fiduciary duty, and requested, among other relief, injunctive relief and damages. This lawsuit was consolidated in Delaware Chancery with other class actions that have been filed against ATLS and its directors, among others. On December 28, 2010, the plaintiffs filed an amended complaint in which all claims against the Partnership and APL were dropped.

Additionally, following the Announcement, a purported shareholder derivative case was filed on November 16, 2010, in the Western District of Pennsylvania federal court, Ussach v. ATLS, et al., C.A. No. 2:10-cv-1533. The complaint is asserted derivatively on behalf of APL and names ATLS, the General Partner, and members of the Managing Board of the General Partner as defendants (“Defendants”) and alleges that Defendants have violated their fiduciary duties in connection with the proposed sale to ATLS of APL’s interest in Laurel Mountain and that ATLS has been unjustly enriched. In the complaint, among other relief, the plaintiff requests damages and equitable and injunctive relief, as well as restitution and disgorgement from the individual defendants. On February 22, 2011, the plaintiff voluntarily dismissed its complaint without prejudice. The Partnership has not received an indication whether the plaintiff intends to reassert its claim in another forum. In any event, the defendants believe the claims are without merit.

NOTE 15 – CONCENTRATIONS OF CREDIT RISK

APL sells natural gas and NGLs under contract to various purchasers in the normal course of business. For the year ended December 31, 2010, APL had two customers that individually accounted for approximately 58% and 17%, respectively, of the Partnership’s consolidated total third party revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2009, APL had two customers that individually accounted for approximately 56% and 16%, respectively, of the Partnership’s consolidated total third party revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2008, APL had two customers that individually accounted for approximately 48% and 16%, respectively, of the Partnership’s consolidated total third party revenues, excluding the impact of all financial derivative activity. Additionally, APL had two customers that individually accounted for approximately 55% and 17%, respectively, of the Partnership’s consolidated accounts receivable at December

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31, 2010, and two customers that individually accounted for approximately 42% and 14%, respectively, of the Partnership’s consolidated accounts receivable at December 31, 2009.

APL has certain producers which supply a majority of the natural gas to its Mid-Continent gathering systems and processing facilities. A reduction in the volume of natural gas that any one of these producers supply to APL could adversely affect its operating results unless comparable volume could be obtained from other producers in the surrounding region.

The Partnership places its temporary cash investments in high quality short-term money market instruments and deposits with high quality financial institutions. At December 31, 2010, the Partnership and its subsidiaries, including APL, had $2.4 million in deposits at banks, of which $1.5 million was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.

NOTE 16 – BENEFIT PLANS

Generally, all share-based payments to employees, including grants of unit options and phantom units, which are not cash settled, are recognized in the financial statements based on their fair values on the date of the grant.

A phantom unit entitles a grantee to receive a common limited partner unit upon vesting of the phantom unit. In tandem with phantom unit grants, participants may be granted a distribution equivalent right (“DER”), which is 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 the phantom unit is outstanding. Except for phantom units awarded to non-employee managing board members of the general partner, a committee (the “LTIP Committee”) appointed by the general partner’s managing board determines the vesting period for phantom units.

A unit option entitles a grantee to purchase a common limited partner 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 is equal to the fair market value of the common unit on the date of grant of the option. The LTIP Committee shall determine how the exercise price may be paid by the grantee. The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant.

Partnership’s Long-Term Incentive Plans.

In November 2006, the Board of Directors approved and adopted the Partnership’s Long-Term Incentive Plan (“2006 LTIP”), which provides performance incentive awards to officers, employees, board members, employees of its affiliates, consultants, and joint-venture partners (collectively, the “Participants”) who perform services for the Partnership. The 2006 LTIP is administered by the LTIP Committee. Under the LTIP, phantom units and/or unit options may be granted, at the discretion of the LTIP Committee, to all or designated Participants, at the discretion of 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, 2010, the Partnership had 982,294 phantom units and unit options outstanding under the Partnership’s 2006 LTIP, with 940,556 phantom units and unit options available for grant.

In November 2010, ATLS, the majority unitholder of the Partnership, delivered a written consent approving the adoption of a new equity plan. This action by ATLS is sufficient for the unitholder approval of the adoption of the new equity plan without the vote of any other unitholder of the Partnership. The new equity plan will become effective upon the closing of the AHD Transactions. Grants made under the new equity plan will be determined by the Partnership’s board of directors or the LTIP Committee. An aggregate of 3,500,000 common limited partner units may be issued under this plan in the form of options, restricted

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units and phantom units.

Partnership Phantom Units. Through December 31, 2010, phantom units granted to employees under the 2006 LTIP generally will vest 25% three years from the date of grant and 100% four years from the date of grant. Awards will automatically vest upon a change of control of the Partnership, as defined in the Partnership’s 2006 LTIP. Phantom units outstanding under the Partnership’s 2006 LTIP at December 31, 2010, include 5,859 units which will vest within the following twelve months. All phantom units outstanding under the Partnership’s LTIP at December 31, 2010 include DERs granted to the Participants by the 2006 LTIP Committee. The amounts paid with respect to the Partnership’s DERs were approximately $7,000, $14,000 and $0.4 million for the years ended December 31, 2010, 2009 and 2008, respectively. This amount was recorded as a reduction of Equity on the Partnership’s consolidated balance sheets.

The following table sets forth the Partnership’s phantom unit activity for the periods indicated:


	Years Ended December 31,
	2010					2009					2008
	Number of Units			Fair Value⁽¹⁾		Number of Units			Fair Value⁽¹⁾		Number of Units			Fair Value⁽¹⁾
Outstanding, beginning of period		138,875		$	22.18		226,300		$	22.73		220,825		$	22.64
Granted		20,594			10.68		2,000			3.60		6,150			26.51
Matured⁽²⁾		(131,675	)		23.70		(44,425	)		23.75		(675	)		29.18
Forfeited		(500	)		32.28		(45,000	)		22.56		—			—

Outstanding, end of period⁽³⁾		27,294		$	5.98		138,875		$	22.18		226,300		$	22.73


Non-cash compensation expense recognized (in thousands)				$	726				$	515				$	1,427

(1)	Fair value based upon weighted average grant date price, which is utilized in the calculation of compensation expense.

(2)	The intrinsic values for phantom unit awards exercised during the years ended December 31, 2010, 2009 and 2008 were $1.8 million, $0.2 million and $6,000, respectively.

(3)	The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2010 and 2009 was $0.4 million and $0.9 million, respectively.

At December 31, 2010, the Partnership had approximately $0.3 million of unrecognized compensation expense related to unvested phantom units outstanding under its 2006 LTIP based upon the fair value of the awards.

Partnership Unit Options. Through December 31, 2010, unit options granted under the Partnership’s 2006 LTIP generally will vest 25% three years from the date of grant and 100% four years from the date of grant. There are no unit options outstanding under the Partnership’s 2006 LTIP at December 31, 2010 that will vest within the following twelve months. Awards will automatically vest upon a change of control of the Partnership, as defined in the Partnership’s 2006 LTIP.

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The following table sets forth the Partnership’s unit option activity for the periods indicated:


	Years Ended December 31,
	2010				2009					2008
	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		1,215,000		$	22.56		1,215,000	$	22.56
Granted		—		—		100,000			3.24		—		—
Matured		—		—		—			—		—		—
Forfeited		—		—		(360,000	)		22.56		—		—

Outstanding, end of period⁽¹⁾⁽²⁾		955,000	$	20.54		955,000		$	20.54		1,215,000	$	22.56

Options exercisable, end of period⁽³⁾		855,000	$	22.56		213,750			—		—		—


Weighted average fair value of unit options per unit granted during the year	$	—			$	0.61				$	—

Non-cash compensation expense recognized (in thousands)	$	519			$	48				$	1,237

(1)	The weighted average remaining contractual lives for outstanding options at December 31, 2010, 2009 and 2008 were 6.1 years, 7.1 years and 7.9 years, respectively.

(2)	The aggregate intrinsic values of options outstanding at December 31, 2010 and 2009 were approximately $1.2 million and $0.4 million, respectively. There was no intrinsic value of options outstanding at December 31, 2008.

(3)	There were no options exercised during the years ended December 31, 2010, 2009 and 2008, respectively.

At December 31, 2010, the Partnership had approximately $28,000 of unrecognized compensation expense related to unvested unit options outstanding under the Partnership’s 2006 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, 2009
Expected dividend yield		7.0	%
Expected stock price volatility		40	%
Risk-free interest rate		2.3	%
Expected term (in years)		6.9

APL Long-Term Incentive Plans

APL has a 2004 Long-Term Incentive Plan (“APL 2004 LTIP”) and a 2010 Long-Term Incentive Plan (“APL 2010 LTIP” and collectively with the APL 2004 LTIP, the “APL LTIPs”), in which officers, employees and non-employee managing board members of the General Partner and employees of the General Partner’s affiliates and consultants are eligible to participate. The APL LTIPs are administered by a committee (the “APL LTIP Committee”) appointed by the Partnership’s managing board. On June 15, 2010, APL unitholders approved the terms of the APL 2010 LTIP, which provides for the grant of options, phantom units, unit awards, unit appreciation rights and DERs. Under the APL 2010 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 APL’s 2004 LTIP. At December 31, 2010, APL had 565,886 phantom units and unit options outstanding under the APL LTIPs, with 2,501,347 phantom units and unit options available for grant.

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APL Phantom Units. Through December 31, 2010, phantom units granted to employees under the APL LTIPs generally had vesting periods of four years. Except for phantom units awarded to non-employee managing board members of the General Partner, the LTIP Committee determines the vesting period for phantom units. In conjunction with the approval of the APL 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 APL phantom units, effective as of June 1, 2010. These APL phantom units will vest over a two year period, including the first tranche, which vested on June 1, 2010. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards will automatically vest upon a change of control, as defined in the APL LTIPs. At December 31, 2010, there were 174,687 units outstanding under the APL LTIPs that will vest within the following twelve months. All phantom units outstanding under the APL LTIPs at December 31, 2010 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL LTIP DERs were $0.2 million and $0.1 million and $0.5 million for the years ended December 31, 2010, 2009 and 2008, respectively. These amounts were recorded as a reduction of non-controlling interest in APL on the Partnership’s consolidated balance sheets.

The following table sets forth APL’s phantom unit activity for the periods indicated:


	Years Ended December 31,
	2010					2009					2008
	Number of Units			Fair Value⁽¹⁾		Number of Units			Fair Value⁽¹⁾		Number of Units			Fair Value⁽¹⁾
Outstanding, beginning of period		52,233		$	39.72		126,565		$	44.22		129,746		$	45.75
Granted		575,112			10.49		2,000			4.75		54,796			44.28
Matured⁽²⁾		(126,584	)		17.11		(58,257	)		45.68		(56,227	)		44.65
Forfeited		(9,875	)		17.39		(18,075	)		48.17		(1,750	)		43.88

Outstanding, end of period⁽³⁾		490,886		$	11.75		52,233		$	39.72		126,565		$	44.22


Non-cash compensation expense recognized (in thousands)⁽⁴⁾				$	3,480				$	694				$	2,313

(1)	Fair value based upon weighted average grant date price, which is utilized in the calculation of compensation expense.

(2)	The intrinsic values for phantom unit awards exercised during the years ended December 31, 2010, 2009 and 2008 were $1.5 million, $0.3 million and $2.0 million, respectively.

(3)	The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2010 and 2009 was $12.1 million and $0.5 million, respectively.

(4)	Non-cash compensation expense includes $2.2 million related to APL Bonus Units converted to phantom units during the year ended December 31, 2010.

At December 31, 2010, APL had approximately $2.3 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIPs based upon the fair value of the awards.

APL Unit Options Through December 31, 2010, 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. There are 25,000 unit options outstanding under the APL LTIPs at December 31, 2010 that will vest within the following twelve months.

The following table sets forth the APL LTIPs unit option activity for the periods indicated (There were no outstanding unit options for the year ended December 31, 2008):

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	Years Ended December 31,
	2010					2009
				Weighted				Weighted
	Number			Average		Number		Average
	of Unit			Exercise		of Unit		Exercise
	Options			Price		Options		Price
Outstanding, beginning of period		100,000		$	6.24		—	$	—
Granted		—			—		100,000		6.24
Exercised⁽¹⁾		(25,000	)		6.24		—		—

Outstanding, end of period⁽²⁾⁽³⁾		75,000		$	6.24		100,000	$	6.24

Options exercisable, end of period		—			—		—		—


Weighted average fair value of unit options per unit granted during the period		—		$	—		100,000	$	0.14


Non-cash compensation expense recognized (in thousands)				$	4			$	7

(1)	The intrinsic values for option unit awards exercised during the year ended December 31, 2010 were $0.5 million. Approximately $0.2 million was received from exercise of option unit awards during the year ended December 31, 2010.

(2)	The weighted average remaining contractual life for outstanding and exercisable options at December 31, 2010 and 2009 was 8.0 years and 9.0 years, respectively.

(3)	The aggregate intrinsic value of options outstanding at December 31, 2010 and 2009 was $1.4 million and $0.4 million, respectively.

APL 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, 2009
Expected dividend yield	11.0	%
Expected stock price volatility	20.0	%
Risk-free interest rate	2.2	%
Expected term (in years)	6.3

APL Incentive Compensation Agreements

APL had incentive compensation agreements which granted awards to certain key employees retained from previously consummated acquisitions. These individuals were entitled to receive APL common units upon the vesting of the awards, which was dependent upon the achievement of certain predetermined performance targets through September 30, 2007. At September 30, 2007, the predetermined performance targets were achieved and all of the awards under the incentive compensation agreements vested.

Compensation expense is recognized on a straight-line basis over the vesting period. As of December 31, 2008, APL recognized in full within its consolidated statements of operations the compensation expense associated with the vesting of awards issued under these incentive compensation agreements, therefore no compensation expense was recognized during the years ended December 31, 2010 and 2009. APL recognized a reduction of compensation expense of $36.3 million for the year ended December 31, 2008 related to the vesting of awards under these incentive compensation agreements. The non-cash compensation expense adjustments for the year ended December 31, 2008 were principally attributable to changes in APL’s common unit market price, which was utilized in the calculation of the non-cash compensation expense for these awards, at December 31, 2008 when compared with the APL common unit market price at earlier periods and adjustments based upon the achievement of actual financial performance targets through December 31, 2008. APL recognized compensation expense related to these awards based upon the fair value method. During the year ended December 31, 2009, APL issued 348,620 APL common units to the certain key employees covered under the incentive compensation agreements. No additional APL common units will be issued with regard to these agreements.

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Employee Incentive Compensation Plan and Agreement

In June 2009, a wholly-owned subsidiary of APL adopted an incentive plan (the “APL Cash Plan”) which allows for equity-indexed cash incentive awards to employees of APL (the “Participants”), but expressly excludes as an eligible Participant any person that, at the time of the grant, is a “Named Executive Officer” of APL (as such term is defined under the rules of the Securities and Exchange Commission). The Cash Plan is administered by a committee appointed by the president and chief executive officer of the General Partner. Under the APL Cash Plan, cash bonus units may be awarded to Participants at the discretion of the committee, which granted 325,000 bonus units during 2009. In addition, the APL subsidiary granted an award of 50,000 bonus units to an executive officer on substantially the same terms as the bonus units available under the APL Cash Plan (the bonus units issued under the APL Cash Plan and under the separate agreement are, for purposes hereof, referred to as “APL Bonus Units”). An APL Bonus Unit entitles the employee to receive the cash equivalent of the then-fair market value of an APL 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 APL 2010 LTIP, the holders of 300,000 of the 375,000 APL Bonus Units outstanding at June 16, 2010 agreed to exchange their APL Bonus Units for APL phantom units, effective as of June 1, 2010.

A total of 24,750 of the remaining 75,000 APL Bonus Units vested on June 1, 2010. Of the APL Bonus Units outstanding at December 31, 2010, 24,750 APL Bonus Units will 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 APL common units. The Partnership recognized 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 was recorded within general and administrative expense on its consolidated statements of operations. The Partnership had $0.8 million and $1.2 million, at December 31, 2010 and 2009, respectively, included within accrued liabilities on its consolidated balance sheets with regard to these awards, which represents their fair value as of those dates.

NOTE 17 – RELATED PARTY TRANSACTIONS

Neither the Partnership nor APL directly employs any persons to manage or operate their businesses. These functions are provided by employees of ATLS. Atlas Pipeline Holdings GP, the Partnership’s general partner, does not receive a management fee in connection with its management of APL, nor does Atlas Pipeline GP, the general partner of APL, receive a management fee in connection with its management of APL apart from its interest as general partner and its right to receive incentive distributions. APL reimburses the Partnership and its affiliates for compensation and benefits related to their employees who perform services for it based upon an estimate of the time spent by such persons on activities for APL. Other indirect costs, such as rent for offices, are allocated to APL by ATLS based on the number of its employees who devote their time to activities on APL’s behalf.

APL’s partnership agreement provides that the Partnership will determine the costs and expenses that are allocable to APL in any reasonable manner determined by the Partnership at its sole discretion. APL reimbursed the Partnership and its affiliates $1.5 million, $2.7 million and $1.5 million for the years ended December 31, 2010, 2009 and 2008, respectively, for compensation and benefits related to their employees. There were no reimbursements by APL for direct expenses incurred by the Partnership and its affiliates for the years ended December 31, 2010, 2009 and 2008.

On July 19, 2010, the Partnership entered into a note with ATLS to consolidate in one instrument the debt owed to ATLS under a $15.0 million subordinate loan, a $0.3 million guaranty note and a $16.0 million advance under ATLS’s guaranty of the Partnership’s credit facility, plus accrued interest. The initial principal

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of the note was $33.4 million and the interest rate on the note is 12% per annum, which will be payable by accruing such interest and adding the amount to the principal amount of the Note. The Note is payable on demand (see Note 13 “–Atlas Energy, L.P. Demand Note with Atlas Energy, Inc.”).

On February 17, 2011, the Partnership completed the Asset Acquisition contemplated by the AHD Transaction Agreement with ATLS, Atlas Energy Resources and the Partnership’s general partner, pursuant to which the Partnership acquired certain assets relating to ATLS’s investment partnership business and certain other assets and assumed certain liabilities in exchange for 23,379,384 newly issued common units of the Partnership and $30 million in cash; and ATLS contributed the Partnership’s general partner to the Partnership, so that the general partner became a wholly-owned subsidiary of the Partnership.

Concurrently, APL completed the sale of its 49% interest in Laurel Mountain Midstream, LLC, a Delaware limited liability company to Atlas Energy Resources for $413.5 million, which included certain adjustments (See Note 20).

NOTE 18 – SEGMENT INFORMATION

The Partnership’s assets primarily consist of its ownership interests in APL. APL has two reportable segments. These reportable segments reflect the way APL manages its operations.

APL’s Mid-Continent segment consists of APL’s Chaney Dell, Velma and Midkiff/Benedum operations, which are comprised of natural gas gathering and processing assets servicing drilling activity in the Anadarko and Permian Basins. APL’s Mid-Continent revenues are primarily derived from the sale of residue gas and NGLs and gathering of natural gas.

APL’s Appalachia segment is comprised of natural gas transportation, gathering and processing assets located in the Appalachian Basin and services drilling activity in the Marcellus Shale. APL’s Appalachia revenues are principally based on contractual arrangements with ATLS and its affiliates.

The following summarizes the Partnership’s reportable segment data for the periods indicated (in thousands):


	Appalachia			Mid- Continent		Corporate and Other			Consolidated
Year Ended December 31, 2010:
Revenue:
Revenues – third party⁽²⁾	$	544		$	955,939	$	(21,539	)	$	934,944
Revenues – affiliates		619			—		—			619

Total revenue and other income (loss), net		1,163			955,939		(21,539	)		935,563


Costs and Expenses:
Operating costs and expenses		1,061			768,885		—			769,946
General and administrative⁽²⁾		—			—		36,394			36,394
Depreciation and amortization		609			74,288		—			74,897
Acquisition costs		—			—		1,167			1,167
Interest expense⁽²⁾		—			—		94,807			94,807

Total costs and expenses		1,670			843,173		132,368			977,211


Equity income		4,920			—		—			4,920
Loss on asset sales and other		(10,729	)		—		—			(10,729	)

Net income (loss) from continuing operations		(6,316	)		112,766		(153,907	)		(47,457	)
Income from discontinued operations		—			—		321,155			321,155

Net income (loss)	$	(6,316	)	$	112,766	$	167,248		$	273,698

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	Appalachia		Mid- Continent			Corporate and Other			Consolidated
Year Ended December 31, 2009⁽¹⁾:
Revenue:
Revenues – third party⁽²⁾	$	1,779	$	719,832		$	(66,902	)	$	654,709
Revenues – affiliates		17,536		—			—			17,536

Total revenue and other income (loss), net		19,315		719,832			(66,902	)		672,245


Costs and expenses:
Operating costs and expenses		6,917		573,036			—			579,953
General and administrative⁽²⁾		—		—			38,931			38,931
Depreciation and amortization		3,591		72,093			—			75,684
Goodwill and other asset impairment loss		—		10,325			—			10,325
Interest expense⁽²⁾		—		—			106,531			106,531

Total costs and expenses		10,508		655,454			145,462			811,424


Equity income		4,043		—			—			4,043
Gain on asset sales and other		108,947		—			—			108,947

Net income (loss) from continuing operation		121,797		64,378			(212,364	)		(26,189	)
Income from discontinued operations		—		—			84,148			84,148

Net income (loss)	$	121,797	$	64,378		$	(128,216	)	$	57,959


Year Ended December 31, 2008⁽¹⁾:
Revenue:
Revenues – third party⁽²⁾	$	5,456	$	1,193,478		$	(39,469	)	$	1,159,465
Revenues – affiliates		43,293		—			—			43,293

Total revenue and other income (loss), net		48,749		1,193,478			(39,469	)		1,202,758

Costs and expenses:
Operating costs and expenses		13,073		946,007			—			959,080
General and administrative⁽²⁾		—		—			633			633
Depreciation and amortization		6,430		65,334			—			71,764
Goodwill and other asset impairment loss		2,304		613,420			—			615,724
Interest expense⁽²⁾		—		—			91,731			91,731
Gain on extinguishment of debt							(19,867	)		(19,867	)

Total costs and expenses		21,807		1,624,761			72,497			1,719,065


Net income (loss) from continuing operations		26,942		(431,283	)		(111,966	)		(516,307	)
Loss from discontinued operations		—		—			(93,802	)		(93,802	)

Net income (loss)	$	26,942	$	(431,283	)	$	(205,768	)	$	(610,109	)


	Years Ended December 31,
	2010		2009⁽¹⁾		2008⁽¹⁾
Capital Expenditures:
Mid-Continent	$	46,636	$	100,712	$	140,154
Appalachia		—		9,562		41,502

	$	46,636	$	110,274	$	181,656


	December 31,
Balance Sheets	2010		2009⁽¹⁾
Total assets:
Mid-Continent	$	1,574,635	$	1,563,443
Appalachia		163,858		170,905
Discontinued operations		—		401,776
Corporate and other		28,625		1,994

	$	1,767,118	$	2,138,118

The following tables summarize the Partnership’s total natural gas and liquids revenues by product or service for the periods indicated (in thousands):

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	Years Ended December 31,
	2010		2009⁽¹⁾⁽³⁾		2008⁽¹⁾⁽³⁾
Natural gas and liquids:
Natural gas	$	299,461	$	257,297	$	504,768
NGLs		548,308		351,410		528,048
Condensate		41,933		23,626		48,694
Other⁽²⁾		346		3,898		(2,796	)

Total	$	890,048	$	636,231	$	1,078,714

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City (see Note 4).

(2)	The Partnership notes that derivative contracts, interest and general and administrative expenses have not been allocated to its reportable segments as it would be unfeasible to reasonably do so for the periods presented.

(3)	Restated to reflect amount reclassified from natural gas and liquids revenue to transportation, processing and other fees (see Note 1).

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NOTE 19 – QUARTERLY FINANCIAL DATA (Unaudited)


	Fourth Quarter⁽¹⁾			Third Quarter⁽²⁾			Second Quarter⁽³⁾			First Quarter⁽⁴⁾
	(in thousands, except per unit data)
Year ended December 31, 2010:
Revenue and other income (loss), net	$	253,090		$	226,119		$	216,228		$	240,126
Costs and expenses		(256,918	)		(246,823	)		(225,544	)		(247,926	)
Equity income in joint venture		783			1,787			888			1,462
Loss on sale of asset		(10,729	)		—			—			—

Loss from continuing operations		(13,774	)		(18,917	)		(8,428	)		(6,338	)
Income from discontinued operations		471			305,927			7,976			6,781

Net income (loss)		(13,303	)		287,010			(452	)		443
Income attributable to non-controlling interests		(1,400	)		(1,076	)		(945	)		(1,317	)
(Income) loss attributable to non-controlling interests – Atlas Pipeline Partners, L.P.		10,695			(251,488	)		257			(490	)

Net income (loss) attributable to common limited partners	$	(4,008	)	$	34,446		$	(1,140	)	$	(1,364	)


Net income (loss) attributable to common limited partners per unit – basic:
Loss from continuing operations attributable to common limited partners	$	(0.14	)	$	(0.13	)	$	(0.08	)	$	(0.08	)
Income from discontinued operations attributable to common limited partners		—			1.37			0.04			0.03

Net income (loss) attributable to common limited partners	$	(0.14	)	$	1.24		$	(0.04	)	$	(0.05	)


Net income (loss) attributable to common limited partners per unit – diluted:⁽⁵⁾⁽⁶⁾
Loss from continuing operations attributable to common limited partners	$	(0.14	)	$	(0.13	)	$	(0.08	)	$	(0.08	)
Income from discontinued operations attributable to common limited partners		—			1.37			0.04			0.03

Net income (loss) attributable to common limited partners	$	(0.14	)	$	1.24		$	(0.04	)	$	(0.05	)

(1)	Net loss includes APL’s $6.0 million non-cash derivative loss and a $10.7 million loss related to the sale of Laurel Mountain (see Note 21).

(2)	Net income includes APL’s $18.6 million non-cash derivative loss and a $311.5 million gain on the sale of APL’s Elk City (see Note 4).

(3)	Net loss includes APL’s $19.1 million non-cash derivative gain and a $20.4 million net cash derivative expense from APL’s early termination of certain derivative instruments.

(4)	Net income includes APL’s $20.6 million non-cash derivative gain and a $13.4 million cash derivative expense from APL’s early termination of certain derivative instruments.

(5)

For the first, second, third and fourth quarters of the year ended December 31, 2010, approximately 138,000, 141,000, 144,000 and 95,000 phantom units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such phantom units would have been anti-dilutive.

(6)	For all quarters of the year ended December 31, 2010, approximately 1.0 million unit options 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.

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	Fourth Quarter⁽²⁾			Third Quarter⁽³⁾			Second Quarter⁽⁴⁾			First Quarter⁽⁵⁾
	(in thousands, except per unit data)
Year ended December 31, 2009⁽¹⁾:
Revenue and other income (loss), net	$	201,939		$	176,213		$	145,981		$	148,112
Costs and expenses		(243,368	)		(199,998	)		(185,226	)		(182,832	)
Equity income in joint venture		1,903			1,430			710			—
Gain (loss) on sale of asset		—			(994	)		109,941			—

Income (loss) from continuing operations		(39,526	)		(23,349	)		71,406			(34,720	)
Income from discontinued operations		2,907			9,215			60,562			11,464

Net income (loss)		(36,619	)		(14,134	)		131,968			(23,256	)
Income attributable to non-controlling interests		(1,101	)		(954	)		(652	)		(469	)
(Income) loss attributable to non-controlling interests – Atlas Pipeline Partners, L.P.		31,453			11,487			(114,330	)		20,642

Net income (loss) attributable to common limited partners	$	(6,267	)	$	(3,601	)	$	16,986		$	(3,083	)


Net income (loss) attributable to common limited partners per unit – basic:
Income (loss) from continuing operations attributable to common limited partners	$	(0.24	)	$	(0.18	)	$	0.31		$	(0.16	)
Income from discontinued operations attributable to common limited partners		0.01			0.04			0.30			0.05

Net income (loss) attributable to common limited partners	$	(0.23	)	$	(0.14	)	$	0.61		$	(0.11	)


Net income (loss) attributable to common limited partners per unit – diluted:⁽⁶⁾
Income (loss) from continuing operations attributable to common limited partners	$	(0.24	)	$	(0.18	)	$	0.31		$	(0.16	)
Income from discontinued operations attributable to common limited partners		0.01			0.04			0.30			0.05

Net income (loss) attributable to common limited partners	$	(0.23	)	$	(0.14	)	$	0.61		$	(0.11	)

(1)	Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City (see Note 4).

(2)	Net loss includes APL’s $11.7 million non-cash derivative loss and $10.3 million non-cash impairment charge for goodwill and other assets.

(3)	Net loss includes APL’s $7.5 million non-cash derivative gain.

(4)	Net income includes APL’s $2.5 million non-cash derivative loss and a $79.8 million non-cash gain of the total $111.4 million gain on sale of APL’s assets.

(5)	Net loss includes APL’s $44.0 million non-cash derivative loss and a $5.0 million cash derivative expense from the APL’s termination of certain derivative instruments.

(6)	For all quarters of the year ended December 31, 2009, approximately 1.0 million unit options 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.

NOTE 20 – SUBSEQUENT EVENTS

Atlas Energy, Inc. Asset Acquisition

On February 17, 2011, the Partnership completed the Asset Acquisition contemplated by the AHD Transaction Agreement, pursuant to which the Partnership purchased from ATLS (1) its investment partnership business, including the operations of its investment partnerships in Michigan, Pennsylvania, Tennessee, Indiana and Colorado, (2) its oil and gas exploration, development and production activities conducted in Tennessee, Indiana and Colorado, certain shallow wells and leases in New York and Ohio and certain well interests in Pennsylvania, and (3) its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (the businesses described in (1) through (3), together, referred to as the “transferred business”). The assets the Partnership purchased include certain ATLS subsidiaries (referred

148

to as the “purchased entities”) and certain other assets relating to the transferred business, including the names and marks of ATLS and its subsidiaries (referred to as the “purchased assets”). ATLS also transferred certain current liabilities that were assumed by the Partnership in the Asset Acquisition subject to post-closing.

As consideration for the Asset Acquisition, the Partnership paid to ATLS $30 million in cash, issued to it 23,379,384 new common units, and assumed certain of the historical and future liabilities associated with the transferred business. In addition, the Partnership repaid the $36.0 million outstanding under its amended and consolidated note owed to ATLS.

In connection with the Asset Acquisition, ATLS contributed the Partnership’s general partner, Atlas Pipeline Holdings GP, LLC to the Partnership, so that Atlas Pipeline Holdings GP became the Partnership’s wholly-owned subsidiary. The Partnership’s limited partnership agreement was amended and restated and the Partnership’s new long-term equity incentive plan for employees became effective. The Partnership also acquired certain management team members and employees associated with these assets.

ATLS distributed to its stockholders all the Partnership’s common units that it held, including the newly issued common units that it received in the Asset Acquisition. As a result, ATLS no longer owns any of the Partnership’s common units.

New Credit Facility

The Partnership financed the cash portion of Asset Acquisition consideration and the repayment of the ATLS note by drawing on a $70 million revolving credit facility, administered by Citibank, N.A. that the Partnership entered into at closing. The Partnership’s credit facility matures in February 2012 and bears interest, at the Partnership’s option, at either (i) adjusted LIBOR (plus the applicable margin, as defined in the credit facility) or (ii) the higher of the federal funds rate plus 0.5% or the Citibank, N.A. prime rate (each plus the applicable margin). Borrowings under the Partnership’s credit facility are secured by a first-priority lien on a security interest in substantially all of the Partnership’s assets, including a pledge of 3,500,000 of the Partnership’s APL common units, and are guaranteed by Atlas Pipeline Holdings GP and the Partnership’s other operating subsidiaries (excluding Atlas Pipeline GP and APL and its subsidiaries). The Partnership’s credit facility contains customary covenants, including restrictions on the Partnership’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to the Partnership’s unitholders if an event of default exists or would result from such distribution; or enter into a merger or sale of substantially all of the Partnership’s property or assets, including the sale or transfer of interests in the Partnership’s subsidiaries; and requirements that the Partnership maintain certain financial ratios. The events which constitute an event of default under the Partnership’s 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 the Partnership in excess of a specified amount, and a change of control. The Partnership may borrow under its credit facility for working capital and general business purposes.

Laurel Mountain Sale

Concurrently with the Partnership’s completion of the Asset Acquisition, APL completed its sale to Atlas Energy Resources of its 49% non-controlling interest in Laurel Mountain (the “Laurel Mountain Sale”) for $413.5 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 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.

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Atlas Energy, Inc. Merger

Concurrently with the Partnership’s completion of the Asset Acquisition and APL’s completion of the Laurel Mountain Sale, ATLS completed its merger transaction with Chevron Corporation, pursuant to which, among other things, ATLS became a wholly-owned subsidiary of Chevron (the “Chevron Merger”).

Atlas Pipeline Holdings, L.P. Name Change

On February 18, 2011, subsequent to the Asset Acquisition and the Chevron Merger, the Partnership changed its name to Atlas Energy, L.P.

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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, 2010, 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 Rules 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).

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 internal control over financial reporting was effective at the reasonable assurance level as of December 31, 2010. Grant Thornton LLP, an independent registered public accounting firm and auditors of our consolidated financial statements, has issued its report on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2010, which is included herein.

151

There have been no changes in our internal control over financial reporting during the fourth quarter of 2010 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, 2010, 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, 2010, 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 balance sheets of Atlas Energy, L.P. and subsidiaries as of December 31, 2010 and 2009 and the related consolidated statements of operations, comprehensive income (loss), equity and cash flows for each of the three years in the period ended December 31, 2010, and our report dated February 25, 2011 expressed an unqualified opinion thereon.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 25, 2011

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ITEM 9B.

OTHER INFORMATION

None.

154

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 NYSE listing standards, the non-management members of our general partner’s board of directors will meet in executive session regularly without management. The managing board member who presides at these meetings will rotate each meeting. The purpose of these executive sessions 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, 10^th 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 ATLS 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, ATLS personnel managed and operated our business. With the completion of the Chevron Merger, we are no longer affiliated with ATLS. We now employ certain former ATLS employees, including the members of our senior management. In addition, as a result of the AHD Transactions, we now own our general partner, and our unitholders will elect our general partner’s board of directors, rather than ATLS.

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:

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Name	Age		Position with the general partner	Year in which service began		Term expires
Edward E. Cohen		72	Chief Executive Officer, President and Director		2006		2014
Sean P. McGrath		39	Chief Financial Officer		2011		—
Jonathan Z. Cohen		40	Chairman of the Board		2006		2013
Matthew A. Jones		49	Senior Vice President and President and Chief Operating Officer of E&P Division		2011		—
Eugene N. Dubay		62	Senior Vice President of Midstream		2011		—
Lisa Washington		43	Vice President, Chief Legal Officer and Secretary		2011		—
Robert W. Karlovich, III		33	Chief Accounting Officer		2009		—
Carlton M. Arrendell		49	Director		2011		2013
Mark C. Biderman		65	Director		2011		2013
Dennis A. Holtz		70	Director		2011		2012
William G. Karis		62	Director		2006		2012
Harvey G. Magarick		71	Director		2006		2012
Ellen F. Warren		54	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 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 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 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 Atlas Energy and the Chief Accounting Officer of Atlas Energy Resources from December 2008 until February 2011. Mr. McGrath served as the Chief Accounting Officer of Atlas Pipeline

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Holdings GP 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 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 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 our Senior Vice President and President and Chief Operating Officer of E&P 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 Atlas Energy. 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 Atlas Pipeline Holdings GP 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 has served as a director of Atlas Pipeline Holdings GP since February 2006. 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.

Robert W. Karlovich, III has been the Chief Accounting Officer of our general partner since November 2009. Mr. Karlovich has been the Chief Accounting Officer of Atlas Pipeline GP since November 2009. Before that, he was the Controller of Atlas Pipeline Mid-Continent, LLC, our wholly-owned subsidiary, since September 2006. Mr. Karlovich was the Controller for Syntroleum Corporation, a publicly-traded energy company, from April 2005 until September 2006, and Accounting Manager from February 2004. Mr. Karlovich also worked as a public accountant with Arthur Andersen LLP and Grant Thornton LLP where he served numerous public clients and energy companies. Mr. Karlovich is a certified public accountant.

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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 Atlas Energy, Inc. 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.

Carlton M. Arrendell has been a director since February 2011. Before that, he was a director of Atlas Energy 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.

Mark C. Biderman has been a director since February 2011. Before that, he was a director of Atlas Energy 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 of Full Circle Capital Corporation, a publicly-traded investment company, since August 2010 and as a director and chairman of the compensation committee of Apollo Commercial Real Estate Finance, Inc., a publicly-traded commercial real estate finance company, since November 2010. 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 Atlas Energy 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. Mr. Holtz served on the Atlas Energy board for six years, since its spin-off from Resource America and his length of service on Atlas Energy’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 APL’s 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.

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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 Atlas Energy 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 from December 2006 until September 2009. Ms. Warren is a seasoned director, having previously served on the board of Atlas Energy Resources 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, 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.

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 oversight of management is an important component of an effective board of directors. 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 board of directors believes that because the chief executive officer is ultimately responsible for our day-to-day operations and for executing our strategy, we are best served to have a separate role of chairman of the board of directors of our general partner as it allows for proper oversight, guidance and accountability. 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.

We administer our risk oversight function through our risk oversight committee which was appointed by the board of directors of our general partner to assist with its oversight duties for risk management. The members of our risk oversight committee are Messrs. Magarick, Karis, and until February 2011, Mr. Dubay with Mr. Magarick acting as the chairman. Our risk oversight committee reports both to the audit committee and to the board of directors of our general partner periodically on its activities and is generally responsible for overseeing the guidelines and policies that govern our enterprise risk management program. Our risk oversight committee provides oversight for a management-level risk management committee comprised of members of senior management that is tasked with monitoring material enterprise risks, overseeing the framework for management of risks and reporting any significant changes or updates to our key risks to the risk oversight committee. The management-level risk management committee reports to the CEO and the risk oversight committee. Additionally, individuals who oversee risk management in liquidity and credit areas, along with environmental, litigation and other operational areas periodically provide reports to the board of our general partner during regular board meetings.

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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 all of our executive officers, managing board members of our general partner and persons who beneficially owned more than 10% of our common units complied with all applicable filing requirements during fiscal year 2010.

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 or not such

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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.

•

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

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director or that could be material to a reasonable unitholder’s understanding of the independence, or lack thereof, of such nominee.

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. 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

Neither we nor the board of directors of our general partner had a compensation committee for the year ended December 31, 2010. Compensation of the personnel of ATLS and its affiliates who provided us with services was set by ATLS and such affiliates. There was no allocation of the salaries of such personnel to us; however, ATLS allocated the salaries of such personnel for reimbursement by APL.

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., Westpointe Corporate Center, 1550 Coraopolis Heights Road, Moon Township, Pennsylvania 15108, 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.

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ITEM 11.

EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

We are required to provide information regarding the compensation program in place as of December 31, 2010, for Atlas Pipeline GP’s CEO, CFO and the three other most highly-compensated executive officers. In this report, we refer to Atlas Pipeline GP’s CEO, CFO and the other three most highly-compensated executive officers as our “named executive officers” or “NEOs.” This section should be read in conjunction with the detailed tables and narrative descriptions below.

For fiscal year 2010, ATLS allocated the compensation of our executive officers between activities on behalf of us and APL and activities on behalf of itself and its other affiliates based upon an estimate of the time spent by such persons on activities for us and APL and for ATLS and its affiliates. Because Messrs. Dubay, Kalamaras and Shrader devoted all of their time to us and APL, all of their compensation costs were allocated to APL. APL reimbursed ATLS for the compensation allocated to it for its and our executive officers. ATLS did not make a separate allocation to us. Because ATLS employed our NEOs, its compensation committee, comprised solely of independent directors, was responsible for formulating and presenting recommendations to its board of directors with respect to the compensation of our NEOs. The ATLS compensation committee was also responsible for administering our employee benefit plans, including our and APL’s incentive plans.

As a result of recent transactions, our general partner now employs our NEOs and our compensation committee will be responsible for formulating and presenting recommendations to our general partner’s Board of Directors with respect to the compensation of our NEOs effective February 2011. See “Item 1: Business –Recent Developments” for further discussion. While the discussion that follows regarding our compensation program reflects the compensation program in place by the ATLS compensation committee, we anticipate that our compensation program going forward will be substantially the same, except that our NEOs will not receive stock-based awards from ATLS.

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

The ATLS compensation committee generally made recommendations to the ATLS board on compensation amounts shortly after the close of its (and our) fiscal year. In the case of base salaries, it recommended the amounts to be paid for the new fiscal year. In the case of annual bonus and long-term incentive compensation, the committee recommended the amount of awards based on the then concluded fiscal year. ATLS and we typically paid cash awards in February, although the ATLS compensation committee had the discretion to recommend salary adjustments and the issuance of equity awards at other times during the fiscal year. In addition, some of our NEOs who also performed services for ATLS and its other subsidiaries received stock-based awards from ATLS and these subsidiaries, each of which had delegated compensation decisions to the ATLS compensation committee because they, like us, did not have their own employees. Our compensation committee was formed in February 2011 and, at its initial meeting, it recommended base salaries to be paid to some of our executive officers for our 2011 fiscal year and annual bonuses based on our 2010 fiscal year.

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Prior to February 2011, each year, the Chairman of our general partner, who served as ATLS’s Chief Executive Officer and Chairman, provided the ATLS compensation committee with key elements of ATLS’s, our and our NEOs’ performance during the year. The Chairman made recommendations to the compensation committee regarding the salary, bonus, and incentive compensation components of each NEO’s total compensation. The Chairman, at the compensation committee’s request, may have attended compensation committee meetings; however, his role during the meetings was to provide insight into ATLS’s and our company’s performance, as well as the performance of other comparable companies in the same industry.

Elements of our Compensation Program

Our executive officer compensation package includes a combination of annual cash and long-term incentive compensation. Annual cash compensation is comprised of an allocation of base salary plus cash bonus awarded by ATLS. 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 the success of ATLS and us. Base salaries are not intended to compensate individuals for 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 ATLS’s annual performance and /or that of one of ATLS’s subsidiaries or divisions for which the officer is responsible. Generally, the higher the level of responsibility of the executive within ATLS, the greater is the incentive component of that executive’s target total cash compensation. The ATLS compensation committee would recommend awards of performance-based bonuses and discretionary bonuses.

Performance-Based Bonuses—The ATLS Annual Incentive Plan for Senior Executives, which we refer to as the Senior Executive Plan, provides awards for the achievement of predetermined, objective performance measures over a specified 12-month performance period, generally ATLS’s fiscal year. Awards under the Senior Executive Plan may be paid in cash or in shares of ATLS’s common stock under its stock incentive plan. The Senior Executive Plan is designed to permit ATLS to qualify for an exemption from the $1,000,000 deduction limit under Section 162(m) of the Internal Revenue Code for compensation paid to the NEOs. Notwithstanding the existence of the Senior Executive Plan, the ATLS compensation committee believed that the interests of ATLS’s stockholders and our unitholders were best served by not restricting its discretion and flexibility in crafting compensation, even if the compensation amounts result in non-deductible compensation expense. Therefore, the committee reserved the right to approve compensation that is not fully deductible.

In February 2010, the compensation committee approved 2010 target bonus awards to be paid from a bonus pool. The bonus pool was equal to 18.3% of ATLS’s adjusted distributable cash flow, unless the adjusted 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 adjusted distributable cash flow did not equal at least 75% of the average adjusted distributable cash flow for the previous 3 years, no bonuses would be paid. Adjusted distributable cash flow means the sum of (i) cash available for distribution to ATLS by any of its subsidiaries (regardless of whether such cash is actually distributed), plus (ii) interest income during the year, plus (iii) to the extent not otherwise included in adjusted distributable cash flow, any realized gain on the sale of securities, including securities of a subsidiary, less (iv) ATLS’s stand-alone general and administrative expenses for the year excluding any bonus expense (other than non-cash bonus compensation included in general and administrative expenses), and less (v) to the extent not otherwise included in adjusted distributable cash flow, any loss on the sale of securities, including securities of a subsidiary. A return of

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ATLS’s capital investment in a subsidiary was not intended to be included and, accordingly, if adjusted 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 adjusted distributable cash flow would be reduced by its basis in the subsidiary. The maximum award payable, expressed as a percentage of ATLS’s estimated 2010 adjusted distributable cash flow, for our NEO participants was as follows: Edward E. Cohen 6.14% and Jonathan Z. Cohen, 4.37%. Pursuant to the terms of the Senior Executive Plan, the ATLS compensation committee had the discretion to recommend reductions, but not increases, in awards under the 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, ATLS provides 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 were also eligible to receive awards under the ATLS Stock Incentive Plans, which we refer to as the Atlas Plans, and the Atlas Pipeline Partners Long-Term Incentive Plans, which we refer to as the APL Plans, as appropriate.

Grants under our Plans: Under the 2006 Plan, the ATLS compensation committee and under the 2010 Plan, our Board, or committee of the Board, 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 one or more of ATLS’s subsidiaries were eligible to receive stock-based awards under the ATLS Plans or the APL Plans.

Supplemental Benefits, Deferred Compensation and Perquisites

We do not provide supplemental benefits for executives and perquisites are discouraged. ATLS did provide a Supplemental Executive Retirement Plan for Messrs. E. Cohen and J. Cohen pursuant to their employment agreements, but none of those benefits or related costs are allocated to us. None of our NEOs have deferred any portion of their compensation.

Employment Agreements

ATLS entered into employment agreements with Messrs. E. Cohen, J. Cohen, E. Dubay and E. Kalamaras. These employment agreements terminated with the Chevron Merger.

Determination of 2010 Compensation Amounts

At the end of ATLS’s 2010 fiscal year, the ATLS compensation committee recommended incentive awards based on the prior year’s performance for Messrs. E. and J. Cohen. The ATLS compensation committee had already approved our 2010 NEO’s base salaries in February 2010. In February 2011, our newly formed compensation committee approved the base salaries for our NEOs and approved the base salaries and bonuses for APL’s NEOs.

In determining the actual amounts to be paid to the NEOs, the ATLS compensation committee and our compensation committee considered both individual and company performance. Our CEO made recommendations of award amounts based upon the NEOs’ individual performances as well as the performance of ATLS’s subsidiaries for which each NEO provided service; however, the ATLS

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compensation committee had, and our compensation committee has, the discretion to approve, reject, or modify the recommendations.

Base Salary.

Our compensation committee set 2011 salaries for our NEOs as follows: Mr. Dubay–$500,000, Mr. Kalamaras–$295,000 and Mr. Shrader-$290,000. These amounts represent a 0%, 7% and 5% increase from the 2010 base salaries for each of Messrs. Dubay, Kalamaras and Shrader, respectively. Following their replacement in February 2011, Mr. Kalamaras and Mr. Shrader continue to serve as officers of APL.

Annual Incentives.

Performance-Based Bonuses. The ATLS compensation committee noted, among other accomplishments, Atlas Energy Resource, LLC’s joint venture with Reliance Industries Limited and the Chevron merger. ATLS substantially outperformed the incentive goals that had been set under the Senior Executive Plan. Based upon this performance, the ATLS compensation committee recommended that ATLS award cash incentive bonuses to our NEOs as follows: Edward E. Cohen, $5,000,000 and Jonathan Z. Cohen, $4,000,000. The aggregate annual incentive awards were less than the maximum amount payable to each of the NEOs pursuant to the predetermined percentages established under the Senior Executive Plan, which were as follows: Edward E. Cohen, $28,818,000 and Jonathan Z. Cohen, $20,510,000.

Discretionary Bonuses. Messrs. Dubay, Kalamaras and Shrader are not participants in the Senior Executive Plan. Our compensation committee awarded them discretionary bonuses as follows: Mr. Dubay-$1,000,000, Mr. Kalamaras-$180,000 and Mr. Shrader-$215,000. Among other factors, the discretionary bonuses were awarded based on performance in connection with the sale of APL’s Elk City and the execution of APL’s new credit facility.

APLMC Plan Awards. The Atlas Pipeline Mid-Continent Plan (the “APLMC Plan”) specifically prohibits awards to anyone who is an NEO at the time of the grant. Mr. Shrader received awards under the APLMC Plan, but was granted those awards prior to becoming a NEO. In addition, upon execution of his employment agreement with ATLS in September 2009, Mr. Kalamaras was awarded 50,000 bonus units on substantially the same terms as the bonus units under the APLMC Plan. No additional grants to our NEOs can be made under the APLMC Plan. Each of Messrs. Shrader and Kalamaras exchanged their bonus units for phantom units, effective June 1, 2010, in connection with the approval of the 2010 APL Plan.

The following table sets forth the compensation allocation for fiscal years 2010, 2009 and 2008 for our General Partner’s Chief Executive Officer and Chief Financial Officer and each of our other most highly compensated executive officers whose allocated aggregate salary and bonus (including amounts of salary and bonus foregone to receive non-cash compensation) exceeded $100,000. As required by SEC guidance, the table also discloses awards under the APL Plans and the ATLS Plans.

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Summary Compensation Table


Name and Principal Position	Year		Salary		Bonus		Stock Awards⁽¹⁾		Option Awards⁽¹⁾		Non-Equity Incentive Plan Compensation		All Other Compensation			Total
Eugene N. Dubay, Chief Executive Officer and President		2010	$	500,000	$	1,000,000	$	1,334,009	$	1,008,700	$	—	$	26,338	⁽²⁾	$	3,869,047
Eugene N. Dubay, Chief Executive Officer and President		2009		438,847		500,000		—		564,000		—		555,805			2,058,652

Eric T. Kalamaras, Chief Financial Officer		2010		274,519		180,000		244,640		273,790		—		49,425	⁽³⁾		1,022,374
Eric T. Kalamaras, Chief Financial Officer		2009		157,000		152,917		66,620		—		—		—			376,537

Edward E. Cohen, Chairman of the Board		2010		150,000		—		—		—		750,000		3,375	⁽⁴⁾		903,375
		2009		147,577		—		—		—		375,000		12,600			535,177
		2008		135,000		—		—		—		—		257,938			392,938

Jonathan Z. Cohen, Vice Chairman of Atlas Pipeline GP		2010		105,000		—		—		—		600,000		1,688	⁽⁴⁾		706,688
		2009		101,539		—		—		—		300,000		7,863			409,402
		2008		90,000		—		—		—		—		113,488			203,488

Gerald R. Shrader, Chief Legal Officer		2010		274,519		215,000		244,640		—		—		19,600	⁽²⁾		753,759
Gerald R. Shrader, Chief Legal Officer		2009		224,616		300,000		96,000		—		—		—			620,616

(1)	See “Item 8. Financial Statements and Supplementary Data –Note 16” for further discussion regarding assumptions made in valuation of fair value on grant date.

(2)	Includes payments of DERs with respect to the phantom units awarded under APL’s 2004 and 2010 Plans.

(3)	Includes (i) relocation expense of $30,000 and (ii) payments of DERs with respect to phantom units awarded under APL’s 2010 Plan.

(4)	Includes payments of DERs with respect to phantom units awarded under our 2006 Plan.

Employment Agreements and Potential Payments Upon Termination or Change of Control

Edward E. Cohen

In May 2004, ATLS 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,” ATLS 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. ATLS 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. The following discussion of Mr. Cohen’s employment agreement summarizes those elements of Mr. Cohen’s compensation that were allocated in part to APL.

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 employment agreement was entered into in 2004, around the time that ATLS was preparing to launch its initial public offering in connection with its spin-off from Resource America, Inc. At that time, it

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was important to establish a long-term commitment to and from Mr. Cohen as the Chief Executive Officer and then-current President of ATLS. 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.

•

ATLS 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 ATLS’s employees, during the three years following his termination, (c) a lump sum amount equal to the cost ATLS 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 ATLS’s long-term disability plan.

•

ATLS 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 ATLS’s Board of Directors or ATLS’s material breach of the agreement. Mr. Cohen must provide ATLS with 30 days’ notice of a termination by him for good reason within 60 days of the event constituting good reason. ATLS 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 ATLS 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 ATLS’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 ATLS’s employees, during the three years following his termination, (iii) a lump sum amount equal to the cost ATLS would incur for life, disability and accident insurance coverage during the three-year period, less the premium charge that is paid by ATLS’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 ATLS, 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 is defined as:

•

the acquisition of beneficial ownership, as defined in the Securities Exchange Act of 1933, of 25% or more of ATLS’s voting securities or all or substantially all of ATLS’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;

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•

ATLS consummates a merger, consolidation, combination, share exchange, division or other reorganization or transaction with an unaffiliated entity in which either (a) ATLS’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 ATLS’s directors immediately before the transaction and ATLS’s chief executive officer immediately before the transaction continues as the chief executive officer of the surviving entity; or (b) ATLS’s voting securities immediately prior to the transaction represent less than 60% of the combined voting power immediately after the transaction of ATLS, the surviving entity or, in the case of a division, each entity resulting from the division;

•

during any period of 24 consecutive months, individuals who were ATLS Board members at the beginning of the period cease for any reason to constitute a majority of the ATLS Board, unless the election or nomination for election by ATLS’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

•

ATLS’s stockholders approve a plan of complete liquidation or winding up of ATLS, or agreement of sale of all or substantially all of ATLS’s assets or all or substantially all of the assets of ATLS’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, ATLS 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.

We anticipate that lump sum termination amounts paid to Mr. Cohen would be allocated to APL consistent with past practice and, with respect to payments based on three years’ of compensation, would be allocated to APL based on the average amount of time Mr. Cohen devoted to our and APL’s activities during the prior three-year period. 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, 2010.


Reason for Termination	Lump Sum Severance Payment			Benefits⁽¹⁾		Accelerated Vesting of option awards⁽²⁾		Tax Gross- up⁽³⁾
Death	$	450,000	⁽⁴⁾	$	—	$	—	$	—
Disability		450,000	⁽⁴⁾		6,576		—		—
Termination by us without cause or by Mr. Cohen for good reason		3,432,577	⁽⁵⁾		6,576		—		—
Change of control		3,432,577	⁽⁵⁾		6,576		—		984,005
Termination by Mr. Cohen without cause		75,000	⁽⁴⁾		—		—		—

(1)	Represents rates currently in effect for COBRA insurance benefits for 36 months.

(2)	Mr. Cohen had no outstanding unexercisable options or unvested unit awards under the APL Plans or our Plans as of the year ended December 31, 2010.

(3)	Calculated after deduction of any excise tax imposed under section 4999 of the Code, and any federal, state and local income tax, FICA and Medicare withholding taxes, taking into account the 20% excess parachute payment rate and a 36.45% combined effective tax rate.

(4)	Calculated based on Mr. Cohen’s 2010 base salary.

(5)	Calculated based on Mr. Cohen’s average 2010, 2009 and 2007 base salary and bonus.

Jonathan Z. Cohen

In January 2009, ATLS entered into an employment agreement with Jonathan Z. Cohen, who

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currently serves as our Chairman. As discussed above under “Compensation Discussion and Analysis,” ATLS 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. The following discussion of Mr. Cohen’s employment agreement summarizes those elements of Mr. Cohen’s compensation that were allocated in part to APL.

Mr. Cohen’s employment agreement required him to devote such time to ATLS 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 ATLS 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.

•

ATLS 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 ATLS’s board determines, in good faith based upon medical evidence, that he is unable to perform his duties. Upon termination by ATLS 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 ATLS 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.

•

ATLS 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 ATLS 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 is defined as:

•

the acquisition of beneficial ownership, as defined in the Securities Exchange Act, of 25% or more of ATLS’s voting securities or all or substantially all of ATLS’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;

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•

ATLS consummates a merger, consolidation, combination, share exchange, division or other reorganization or transaction with an unaffiliated entity in which either (a) ATLS’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 ATLS’s Chief Executive Officer immediately before the transaction continues as the Chief Executive Officer of the surviving entity; or (b) ATLS’s voting securities immediately prior to the transaction represent less than 60% of the combined voting power immediately after the transaction of ATLS, the surviving entity or, in the case of a division, each entity resulting from the division;

•

during any period of 24 consecutive months, individuals who were ATLS board members at the beginning of the period cease for any reason to constitute a majority of ATLS’s board, unless the election or nomination for election by ATLS’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

•

ATLS’s stockholders approve a plan of complete liquidation or winding up, or agreement of sale of all or substantially all of ATLS’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. We anticipate that lump sum termination amounts paid to Mr. Cohen would be allocated to APL consistent with past practice and, with respect to payments based on three years’ of compensation, would be allocated to APL based on the average amount of time Mr. Cohen devoted to our and APL’s activities during the prior three-year period. 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, 2010.


Reason for Termination	Lump Sum Severance Payment			Benefits⁽¹⁾		Accelerated Vesting of unit and option awards⁽²⁾
Death	$	—		$	—	$	—
Termination by us other than for cause (including disability) or by Mr. Cohen for good reason (including a change of control)		1,290,000	⁽³⁾		—		—
Termination by us for cause or by Mr. Cohen for other than good reason		—			—		—

(1)	Mr. J. Cohen did not receive benefits from ATLS.

(2)	Mr. J. Cohen had no outstanding unexercisable options or unvested unit awards under our Plans or the APL Plans as of the year ended December 31, 2010.

(3)	Calculated based on Mr. J. Cohen’s average 2010 base salary and cash bonus for 2010, 2009 and 2008.

Eugene N. Dubay

In January 2009, ATLS 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. As discussed above under “Compensation Discussion and Analysis,” ATLS allocated all of Mr. Dubay’s compensation cost to us and 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 ATLS’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

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relocation costs and ATLS agreed to purchase his residence in Michigan for $1,000,000. If Mr. Dubay’s employment is terminated before June 30, 2011 by him without good reason or by ATLS for cause, Mr. Dubay must repay an amount equal to the difference between the amount ATLS paid for his residence and its fair market value on the date acquired by ATLS. Upon execution of the agreement, Mr. Dubay was granted the following equity compensation:

•

Options to purchase 100,000 shares of ATLS’s common stock, which vest 25% per year on each anniversary of the effective date of the agreement;

•

Options to purchase 100,000 of our common units, which vest 25% per year on each anniversary of the effective date of the agreement; and

•

Options to purchase 100,000 AHD 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. ATLS may terminate the agreement:

•

at any time for cause;

•

without cause upon 45 days’ prior written notice;

•

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;

•

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 ATLS. 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 is defined as (a) the commitment of a material act of fraud, (b) illegal or gross misconduct that is willful and results in damage to our business or reputation, (c) being charged with a felony, (d) continued failure by Mr. Dubay to perform his duties after notice other than as a result of physical or mental illness, or (e) Mr. Dubay’s failure to follow ATLS’s reasonable written directions consistent with his duties. Good reason is defined as any action or inaction that constitutes a material breach by ATLS of the agreement or a change of control. Change of control is defined as:

•

the acquisition of beneficial ownership, as defined in the Securities Exchange Act, of 50% or more of ATLS’s voting securities or all or substantially all of ATLS’s assets by a single person or entity or group of affiliated persons or entities, other than an entity affiliated with ATLS or Mr. Dubay or any member of his immediate family;

•

ATLS consummates a merger, consolidation, combination, share exchange, division or other reorganization or transaction of ATLS other than with a related entity, in which either (a) ATLS’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 ATLS directors immediately before the transaction and ATLS’s Chief Executive Officer immediately before the transaction continues as the Chief Executive Officer of the surviving entity; or (b) ATLS’s

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voting securities immediately before the transaction represent less than 60% of the combined voting power immediately after the transaction of ATLS, 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 ATLS board members at the beginning of the period cease for any reason to constitute a majority of ATLS’s board, unless the election or nomination for the election by ATLS’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

•

ATLS’s shareholders approve a plan of complete liquidation or winding-up, or agreement of sale of all or substantially all of ATLS’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 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 ATLS 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 ATLS 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 ATLS 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. We anticipate that lump sum termination amounts paid to Mr. Dubay would be allocated to us consistent with past practice. 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, 2010.

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Reason for Termination	Lump Sum Severance Payment			Benefits		Accelerated Vesting of unit and option awards⁽¹⁾
Death	$	—		$	—	$	8,512,379
Termination by ATLS other than for cause (including disability) or by Mr. Dubay for good reason (including a change of control)		1,083,333	⁽²⁾		18,442		8,512,379

(1)

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, 2010. 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, 2010.

(2)	Calculated based on Mr. Dubay’s average 2010 base salary and bonus.

Eric T. Kalamaras

In September 2009, ATLS entered into a letter agreement with Eric Kalamaras, who served as our Chief Financial Officer until February 2011 and currently serves as the Chief Financial Officer of Atlas Pipeline Partners GP. Mr. Kalamaras’ employment agreement terminated in February 2011, in connection with the Chevron Merger. As discussed above under “Compensation Discussion and Analysis,” ATLS allocated all of Mr. Kalamaras’ compensation cost to us and 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:

•

ATLS 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 (a) committed an act of malfeasance or wrongdoing affecting the company or its affiliates, (ii) breached any confidentiality, non-solicitation or non-competition covenant or employment agreement or (iii) otherwise engaged in conduct that would warrant discharge from employment or service because of his negative effect on the company or its affiliates. Change of control means the acquisition by a person or group of (i) more than 50% of the total value of ownership interests or voting interests in Atlas Pipeline Mid-Continent, LLC or APL or (ii) during any 12 month period, assets of either company having a total gross fair market value equal to more than 50% of the total gross fair market value of the assets of the affected company.

174

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.

Our 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.

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.

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.

175

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 (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.

Similar to our non-employee directors prior to October 2010, each non-employee manager of Atlas Pipeline GP received an annual grant of a maximum of 500 phantom units 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 2004 APL Plan was amended by its managing board in February 2010 to increase the pool of phantom units that may be awarded to non-employee managers from 10,000 to 15,000. The total amount of common units that can be awarded under the 2004 APL Plan was not amended. In October 2010, compensation to each non-employee manager of Atlas Pipeline GP was increased, effective January 1, 2010, for them to receive an annual grant of phantom units having a fair market value of $25,000. 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.

176

APL Employee Incentive Compensation Plan and Agreement

The APLMC Plan, adopted in June 2009, allows for equity-indexed cash incentive awards to personnel who perform services for APL (the “Participants”), but expressly excludes as an eligible Participant any of APL’s NEO’s (as such term is defined under the rules of the Securities and Exchange Commission) at the time of the award. The APLMC Plan is administered by a committee appointed by APL’s chief executive officer. Under the APLMC Plan, cash bonus units may be awarded Participants at the discretion of the committee. Bonus units totaling 325,000 were awarded under the Incentive Plan during the year ended December 31, 2009. In September 2009, Mr. Kalamaras was separately awarded 50,000 bonus units on substantially the same terms as the bonus units available under the APLMC Plan (the bonus units issued under the Incentive Plan and under the separate agreement are, for purposes hereof, referred to as “bonus units”). A 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 bonus unit. 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. Each of Messrs. Shrader and Kalamaras exchanged their bonus units for phantom units, effective June 1, 2010, in connection with the approval of the 2010 APL Plan.

As required by SEC guidelines, the following tables disclose awards under our Plans as well as under the APL Plans and the Atlas Plans.

GRANTS OF PLAN-BASED AWARDS


Name	Grant Date		All Other Stock Awards: Number of Shares of Stock or Units			All Other Option Awards: Number of Securities Under-lying Options			Exercise or Base Price of Option Awards ($/Sh)		Grant Date Fair Value of Unit and Option Awards
Eugene N. Dubay		02/08/2010		17,212	⁽¹⁾		—		$	—	$	500,009
		02/08/2010		—			70,000	⁽²⁾		29.05		1,008,700
		06/22/2010		75,000	⁽³⁾⁽⁴⁾		—			—		834,000

Eric T. Kalamaras		02/08/2010		—			19,000	⁽²⁾		29.05		273,790
		06/22/2010		22,000	⁽³⁾		—			—		244,640

Gerald R. Shrader		06/22/2010		22,000	⁽³⁾		—			—		244,640

(1)	Represents restricted units granted under the 2009 ATLS Plan, which vested upon the Chevron Merger. The weighted average price for restricted unit awards on the date of grant, which is utilized in the calculation of compensation expense, was $29.05.

(2)	Represents options granted under the 2009 ATLS Plan, which vested upon the Chevron Merger. The weighted average fair value of unit options granted during the period, based upon a Black-Scholes option pricing model on the date of grant, was $14.41.

(3)	Represents phantom units granted under the 2010 APL Plan. The weighted average price for phantom unit awards on the date of grant, which is utilized in the calculation of compensation expense, was $11.12.

(4)	Vested upon the Chevron Merger.

177

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END TABLE


	Option Awards										Stock Awards
Name	Number of Securities Underlying Unexercised Options						Option Exercise Price		Option Expiration Date		Number of Units that have not Vested			Market Value of Units that have not Vested
	Exercisable			Unexercisable

Eugene N. Dubay		—			75,000	⁽¹⁾	$	6.24		01/15/2019		75,250	⁽²⁾	$	1,856,417	⁽³⁾
		—			100,000	⁽⁴⁾		3.24		01/15/2019		—			—
		—			75,000	⁽⁵⁾		13.35		01/15/2019		—			—
		—			70,000	⁽⁶⁾		29.05		02/08/2020		17,212	⁽⁷⁾		756,812	⁽⁸⁾

Eric T. Kalamaras		—			19,000	⁽⁹⁾		29.05		02/08/2020		55,500	⁽¹⁰⁾		1,369,185	⁽³⁾

Edward E. Cohen		500,000	⁽¹¹⁾		—			22.56		11/10/2016		—			—

Jonathan Z. Cohen		200,000	⁽¹¹⁾		—			22.56		11/10/2016		—			—

Gerald R. Shrader		—			—			—		—		56,000	⁽¹²⁾		1,381,520	⁽³⁾

(1)	Represents options to purchase APL’s common units, which vested as follows: 01/15/11–25,000; 02/17/11–50,000.

(2)	Represents APL’s phantom units, which vested on 02/17/11.

(3)	Based on closing market price of APL’s common units on December 31, 2010 of $24.67.

(4)	Represents options to purchase our common units, which vested on 02/17/11.

(5)	Represents options to purchase ATLS common stock, which vested as follows: 01/15/11–25,000; and 2/17/11–50,000.

(6)	Represents options to purchase ATLS common stock, which vested as follows: 02/08/11–17,500; and 2/17/11–52,500.

(7)	Represents ATLS phantom units, which vested as follows: 02/08/11–4,303; and 2/17/11–12,909.

(8)	Based on closing market price of ATLS’s common stock on December 31, 2010 of $43.97.

(9)	Represents options to purchase ATLS common stock, which vested as follows: 02/08/11–4,750; and 2/17/11–14,250.

(10)	Represents APL’s phantom units, which vest as follows: 06/22/11–5,500; 09/14/11–16,500; 06/22/12–5,500; 09/14/12–17,000; 06/22/13–5,500 and 06/22/14–5,500.

(11)	Represents options to purchase our common units.

(12)	Represents APL’s phantom units, which vest as follows: 03/03/11–250; 06/01/11–16,500; 06/22/11–5,500; 03/03/12–250; 06/01/12–17,000; 06/22/12–5,500; 06/22/13–5,500 and 06/22/14–5,500.

2010 OPTION EXERCISES AND STOCK VESTED TABLE


	Option Awards					Stock Awards
	Number of Units Acquired on Exercise			Value Realized on Exercise		Number of Units Acquired on Vesting			Value Realized on Vesting⁽¹⁾

Eugene E. Dubay		50,000	⁽²⁾	$	941,484		125	⁽³⁾	$	2,436

Eric T. Kalamaras		—			—		16,500	⁽³⁾		305,580

Edward E. Cohen		—			—		72,500	⁽⁴⁾		997,050

Jonathan Z. Cohen		—			—		37,500	⁽⁵⁾		523,350

Gerald R. Shrader		—			—		16,750	⁽³⁾		162,418

(1)	Value realized on vesting is based upon market price on date of vesting.

(2)	Represents 25,000 shares of ATLS common stock with an intrinsic value of $486,564 and 25,000 APL common units with an intrinsic value of $454,920 (See “Item 8. Financial Statements and Supplementary Data–Note 16”).

(3)	Represents APL’s common units.

(4)	Represents 67,500 of our common units and 5,000 of APL’s common units.

(5)	Represents 33,750 of our common units and 3,750 of APL’s common units.

178

DIRECTOR COMPENSATION TABLE


Name	Fees Earned or Paid in Cash			Stock Awards			All Other Compensation⁽¹⁾		Total
William Bagnell	$	80,000	⁽²⁾	$	24,997	⁽³⁾	$	156	$	105,153

Matthew A. Jones⁽⁴⁾		—			—			—		—

William G. Karis		100,000	⁽⁵⁾		52,548	⁽⁶⁾		60		152,608

Jeffrey C. Key		80,000	⁽²⁾		52,548	⁽⁷⁾		60		132,608

Harvey G. Magarick		95,000	⁽⁷⁾		52,548	⁽⁶⁾		60		147,608

(1)	Represents payments on DERs for phantom units.

(2)	Includes $30,000 for service on the special committee regarding the AHD Transactions.

(3)	Represents 500 phantom units having a grant date fair value of $8.94 and 2,241 phantom units having a grant date fair value of $9.16, granted under our 2006 Plan. The phantom units vested on 02/17/2011, upon Mr. Bagnell’s departure.

(4)	Mr. Jones does not receive compensation for his service as a director as compensation is only paid to independent directors.

(5)	Includes $50,000 for service as chairman of the special committee regarding the AHD Transactions.

(6)	Represents 3,951 phantom units having a grant date fair value of $13.30, granted under our 2006 Plan. The phantom units vest 25% on each anniversary of the date of grant as follows: 11/10/11–987; 11/10/12–987; 11/10/13–987; and 11/10/11–990.

(7)	Represents 3,951 phantom units having a grant date fair value of $13.30, granted under our 2006 Plan. The phantom units vested on 02/17/2011, upon Mr. Key’s departure.

(8)	Includes $30,000 for service on the special committee regarding the AHD Transactions and $15,000 for serving as Audit Committee Chairman.

Our general partner did not pay additional remuneration to officers or employees of ATLS who also served as board members. In fiscal year 2010, each non-employee director received an annual retainer of $50,000 in cash (which was increased from $35,000 in October 2010 effective January 1, 2010), and an annual grant of phantom units pursuant to our Long-Term Incentive Plans having a market value of $25,000 (which was increased in October 2010 effective January 1, 2010 from an award of phantom units with DERs in an amount equal to the lesser of 500 units or $15,000 worth of units (based upon the market price of our common units)). In October 2010, the general partner authorized the grant of additional phantom units under the 2006 Plan to each non-employee director for the 2006, 2008 and 2009 calendar years because, due to the previous limitation of each award to a maximum of 500 phantom units, the target of $15,000 in phantom unit awards for the 2006, 2008 and 2009 calendar years was not achieved. The additional make-up grants for the 2006, 2008 and 2009 calendar years vest over four years and were made to the non-employee directors on the next annual vesting date occurring after November 1, 2010. In addition, in April 2010, the Board authorized payment to the Chairman of the Audit Committee in the amount of $15,000 in cash (effective January 1, 2010).

In addition, our general partner reimburses each non-employee director for out-of-pocket expenses in connection with attending meetings of the board or committees. We reimburse our general partner for these expenses and indemnify our general partner’s directors for actions associated with serving as directors to the extent permitted under Delaware law.

Compensation Committee Report

The compensation committee has reviewed and discussed the Compensation Discussion and Analysis with management and, based on 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, 2010.

This report has been provided by the compensation committee of the Board of Directors of Atlas Pipeline Holdings GP, LLC.

Ellen F. Warren, Chairman

Carlton M. Arrendell

Dennis A. Holtz

179

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

The following table sets forth the number and percentage of shares of common stock owned, as of February 22, 2011, by (a) each person who, to our knowledge, is the beneficial owner of more than 5% of the outstanding shares of common stock, (b) each of the members of the board of directors of our general partner, (c) each of the executive officers named in the Summary Compensation Table in Item 11, and (d) all of the named executive officers and directors as a group. This information is reported in accordance with the beneficial ownership rules of the Securities and Exchange Commission under which a person is deemed to be the beneficial owner of a security if that person has or shares voting power or investment power with respect to such security or has the right to acquire such ownership within 60 days. Unless otherwise indicated in footnotes to the table, each person listed has sole voting and dispositive power with respect to the securities owned by such person. The address of our general partner, its executive officers and directors is Westpointe Corporate Center One, 1550 Coraopolis Heights Road—2^nd Floor, Moon Township, Pennsylvania 15108.

180


Name of Beneficial Owner	Common Unit Amounts and Nature of Beneficial Ownership			Percent of Class
Members of the Board of Directors

Carlton M. Arrendell		2,629			*
Mark C. Biderman		6,243			*
Edward E. Cohen		717,813	⁽¹⁾		1.4	%
Jonathan Z. Cohen		339,398	⁽²⁾
Dennis A. Holtz		4,967			*
William G. Karis		1,175			*
Harvey G. Magarick		1,476			*
Ellen F. Warren		528			*

Non-Director Executive Officers

Eugene N. Dubay		115,401	⁽³⁾		*
Matthew A. Jones		132,052	⁽⁴⁾		*
Robert W. Karlovich, III		—			*
Freddie M. Kotek		16,651			*
Sean McGrath		25,479	⁽⁵⁾		*

Executive officers and board of directors as a group (13 persons)		1,363,812			2.6	%

Other Owners of More than 5% of Outstanding Units
FMR LLC		2,803,427	⁽⁶⁾		10.1	%
MSD Capital, L.P.		4,000,000	⁽⁷⁾		7.8	%

*	Less than 1%.

(1)	Represents 217,813 common units and 500,000 vested unit options. Each unit option represents the right to purchase one common unit.

(2)	Represents 139,398 common units and 200,000 vested unit options. Each unit option represents the right to purchase one common unit.

(3)	Represents 15,401 common units and 100,000 vested unit options. Each unit option represents the right to purchase one common unit.

(4)	Represents 32,052 common units and 100,000 vested unit options. Each unit option represents the right to purchase one common unit.

(5)	Represents 10,479 common units and 15,000 vested unit options. Each unit option represents the right to purchase one common unit.

(6)	This information is based upon a Schedule 13G/A which was filed with the SEC on February 14, 2011. The address for FMR LLC is 82 Devonshire Street, Boston, MA 02109.

(7)	This information is based upon a Schedule 13G which was filed with the SEC on February 22, 2011. The address for MSD Capital, LP is 645 Fifth Avenue, 21st Floor, New York, New York 10022.

181

Equity Compensation Plan Information

The following table contains information about our 2006 Plan as of December 31, 2010:

Plan category

Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights

Weighted-
average
exercise price
of outstanding
options,
warrants and
rights

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

27,294

n/a

Equity compensation plans approved by security holders – unit options

955,000

20.54

Equity compensation plans approved by security holders – Total

982,294

940,556

The following table contains information about our 2010 Plan as of December 31, 2010:

Plan category

Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights

Weighted-
average
exercise price
of outstanding
options,
warrants and
rights

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

—

n/a

Equity compensation plans approved by security holders – unit options

—

Equity compensation plans approved by security holders – Total

—

3,500,000

182

The following table contains information about the APL 2004 Plan as of December 31, 2010:

Plan category

Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights

Weighted-
average
exercise price
of outstanding
options,
warrants and
rights

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

24,774

n/a

Equity compensation plans approved by security holders – unit options

75,000

6.24

Equity compensation plans approved by security holders – Total

99,774

66,459

The following table contains information about the APL 2010 Plan as of December 31, 2010:

Plan category

Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights

Weighted-
average
exercise price
of outstanding
options,
warrants and
rights

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

466,112

n/a

Equity compensation plans approved by security holders – Total

466,112

2,434,888

The following table contains information about ATLS’s Plans as of December 31, 2010:

Plan category

Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights

Weighted-
average
exercise price
of outstanding
options,
warrants and
rights

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

579,189

n/a

Equity compensation plans approved by security holders – unit options

4,536,670

21.04

Equity compensation plans approved by security holders – Total

5,115,859

3,664,188

183

The following table contains information about ATLS’s Assumed Long-Term Incentive Plan from Atlas Energy Resources as of December 31, 2010:

Plan category

Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights

Weighted-
average
exercise price
of outstanding
options,
warrants and
rights

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

674,598

n/a

Equity compensation plans approved by security holders – unit options

1,990,151

20.35

Equity compensation plans approved by security holders – Total

2,664,749

n/a

184

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Neither we nor APL directly employ any persons to manage or operate our businesses. These functions are provided by our general partner and employees of ATLS. Our general partner does not receive a management fee in connection with its management of our operations, nor does Atlas Pipeline GP receive a management fee in connection with its management of APL’s operations, but APL reimburses Atlas Pipeline GP and its affiliates for compensation and benefits related to ATLS employees who perform services to it, based upon an estimate of the time spent by such persons on APL’s activities. Other indirect costs, such as rent for offices, are allocated to APL by ATLS based on the number of its employees who devote substantially all of their time to APL’s activities. APL’s partnership agreement provides that Atlas Pipeline GP will determine the costs and expenses that are allocable to APL in any reasonable manner determined at its sole discretion. APL reimbursed Atlas Pipeline GP and its affiliates $1.5 million for the year ended December 31, 2010 for compensation and benefits related to their employees. Atlas Pipeline GP believes that the method utilized in allocating costs to APL is reasonable.

Effective as of April 30, 2009, Atlas Holdings GP 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 stepchildren, siblings and brothers and sisters in law and anyone residing in the 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 Atlas Holdings GP. 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 Atlas Holdings GP 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 Atlas Holdings GP to a charitable organization, foundation or university at which the related party’s only relationship is as 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.

Each of Messrs. E. Cohen, J. Cohen, Dubay and Matthew A. Jones were determined to be related parties with respect to the Asset Acquisition contemplated by the AHD Transaction Agreement (See “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations –Subsequent Events”). None of Messrs. E. Cohen, J. Cohen, Dubay or Jones participated in approval of the Asset Acquisition on our behalf.

The board of directors of our general partner has determined that Messrs. Arrendell, Biderman, Holtz, Karis and Magarick and Ms. Warren each satisfy the requirement for independence set out in Section

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303A.02 of the rules of the New York Stock Exchange (the “NYSE”) 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 board of directors reviewed information from each of these non-management directors concerning all their respective relationships with us and analyzed the materiality of those relationships.

On February 17, 2011, ATLS consummated its merger with Chevron pursuant to the Chevron Merger Agreement whereby ATLS became a wholly-owned subsidiary of Chevron. Additionally, on February 17, 2011, we consummated the AHD Transactions with ATLS and Atlas Energy Resources. Subsequent to these transactions, our general partner will employ the individuals who manage and operate our business. See “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations –Subsequent Events” for further discussion.

See “Item 10. Directors, Executive Officers and Corporate Governance” for a discussion of board member independence.

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ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Aggregate fees recognized by us during the years ended December 31, 2010 and 2009 by our principal accounting firm, Grant Thornton LLP, are set forth below:


	2010		2009
Audit fees ⁽¹⁾	$	1,673,484	$	1,816,725
Audit related fees⁽²⁾		—		100,500
Tax fees ⁽³⁾		140,492		159,557
All other fees		—		—

Total aggregate fees billed	$	1,813,976	$	2,076,782

(1)	Represents the aggregate fees recognized in 2010 and 2009 for professional services rendered by Grant Thornton LLP for the audit of our annual financial statements, the review of financial statements included in Form 10-Q and the review of registration statements and Form 8-Ks.

(2)	The fees are for services that are normally provided by Grant Thornton LLP in connection with statutory or regulatory filings or engagements.

(3)	Represents the fees recognized in each 2010 and 2009 for professional services rendered by Grant Thornton LLP for tax compliance, tax advice, and tax planning.

Audit Committee Pre-Approval Policies and Procedures

Pursuant to its charter, the audit committee of the board of our general partner is responsible for reviewing and approving, in advance, any audit and any permissible non-audit engagement or relationship between us and our independent auditors. All of such services and fees were pre-approved during 2010 and 2009.

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PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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

No schedules are required to be presented.

(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.⁽²¹⁾

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.⁽²¹⁾

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.⁽²¹⁾

3.1		Certificate of Limited Partnership of Atlas Pipeline Holdings, L.P.⁽¹⁾

3.2		Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Holdings, L.P.⁽¹³⁾

3.3		Certificate of Amendment of Limited Partnership of Atlas Pipeline Holdings, L.P.⁽¹³⁾

3.4		Amendment No. 1 to Second Amended and Restated Limited Partnership Agreement of Atlas Pipeline Holdings, L.P.⁽¹³⁾

4.1		Specimen Certificate Representing Common Units⁽¹⁾

10.1		Certificate of Formation of Atlas Pipeline Holdings GP, LLC⁽¹⁾

10.2		Second Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Holdings GP, LLC.⁽¹³⁾

10.3(a)		Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Partners GP, LLC⁽¹⁾

10.3(b)		Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽¹⁾

10.3(c)		Amendment No. 2 to Second Amendment and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁴⁾

10.3(d)		Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁶⁾

10.3(e)		Amendment No. 4 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁶⁾

10.3(f)		Amendment No. 5 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁶⁾

10.3(g)		Amendment No. 6 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁷⁾

10.3(h)		Amendment No. 7 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽¹⁴⁾

10.3(i)		Amendment No. 8 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽¹⁵⁾

10.4		Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Operating Partnership, L.P.⁽¹⁴⁾

10.5		Certificate of Designation for 12% Cumulative Class C Preferred Units of Atlas Pipeline Partners, L.P.⁽¹⁵⁾

10.6(a)		Long-Term Incentive Plan⁽⁶⁾

10.6(b)		Amendment No. 1 to Long-Term Incentive Plan

10.7		2010 Long-Term Incentive Plan⁽¹⁶⁾


10.8		Amended, Restated and Consolidated Promissory Note to Atlas Energy, Inc., dated July 19, 2010⁽¹⁷⁾

10.9		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⁾

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Exhibit No.		Description

10.10		Securities Purchase Agreement, dated July 27, 2010, by and among Atlas Pipeline Mid-Continent, LLC, Atlas Pipeline Partners, L.P., Enbridge Pipelines (Texas Gathering) L.P. and Enbridge Energy Partners, L.P.⁽¹⁸⁾

10.11		Letter Agreement, dated as of August 31, 2009, between Atlas America, Inc. and Eric Kalamaras⁽¹²⁾

10.12		Phantom Unit Grant Agreement between Atlas Pipeline Mid-Continent, LLC and Eric Kalamaras, dated September 14, 2009⁽¹²⁾

10.13		Form of Grant of Phantom Units to Non-Employee Managers ⁽ ²⁰⁾

10.14		Letter Agreement, by and between Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P., dated November 8, 2010⁽²¹⁾

10.15		Non-Competition and Non-Solicitation Agreement, by and between Chevron Corporation and Edward E. Cohen, dated as of November 8, 2010⁽²²⁾

10.16		Non-Competition and Non-Solicitation Agreement, by and between Chevron Corporation and Jonathan Z. Cohen, dated as of November 8, 2010⁽²²⁾

10.17		Credit Agreement dated as of February 17, 2011, among Atlas Pipeline Holdings, L.P. as borrower, Citibank, N.A., as administrative agent, and the lenders party thereto⁽¹³⁾

21.1		Subsidiaries of Registrant

23.1		Consent of Grant Thornton LLP

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

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.	[Intentionally Omitted]

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.

8.	[Intentionally Omitted]

9.	[Intentionally Omitted]

10.	Previously filed as an exhibit to current report on Form 8-K filed June 1, 2009.

11.	[Intentionally Omitted]

12.	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended September 30, 2009.

13.	Previously filed as an exhibit to current report on Form 8-K filed on February 24, 2010.

14.	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on April 2, 2010.

15.	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on July 7, 2010.

16.	Previously filed as an exhibit to current report on Form 8-K filed on November 12, 2010.

17.	Previously filed as an exhibit to current report on Form 8-K filed July 23, 2010.

18.	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on July 29, 2010.

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 current report on Form 8-K filed November 12, 2010.

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.

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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 Pipeline Holdings GP, LLC, its General Partner

February 25, 2011	By:	/s/ EDWARD E. COHEN
		Chief Executive Officer & 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 and in the capacities indicated as of February 25, 2011.


/s/ EDWARD E. COHEN Edward E. Cohen		Chief Executive Officer, President and Director of the General Partner

/s/ JONATHAN Z. COHEN Jonathan Z. Cohen		Chairman of the Board of the General Partner

/s/ SEAN P. MCGRATH Sean P. McGrath		Chief Financial Officer of the General Partner

/s/ ROBERT W. KARLOVICH III Robert W. Karlovich III		Chief Accounting Officer of the General Partner

/s/ CARLTON M. ARRENDELL Carlton M. Arrendell		Director of the General Partner

/s/ MARK C. BIDERMAN Mark C. Biderman		Director of the General Partner

/s/ DENNIS A. HOLTZ Dennis A. Holtz		Director of the General Partner

/s/ WILLIAM G. KARIS William G. Karis		Director of the General Partner

/s/ HARVEY G. MAGARICK Harvey G. Magarick		Director of the General Partner

/s/ ELLEN F. WARREN Ellen F. Warren		Director of the General Partner

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