UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2012

OR

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

For the transition period from              to             

Commission file number: 1-32953

ATLAS ENERGY, L.P.

(Exact name of registrant as specified in its charter)

Delaware	43-2094238
(State or other jurisdiction or incorporation or organization)	(I.R.S. Employer Identification No.)
Park Place Corporate Center One 1000 Commerce Drive, 4th Floor Pittsburgh, PA	15275
(Address of principal executive offices)	Zip code

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

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

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

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 the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if smaller reporting company)	Smaller reporting company	¨

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

The number of outstanding common units of the registrant on May 7, 2012 was 51,318,155.

ATLAS ENERGY, L.P. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

TABLE OF CONTENTS

			PAGE
PART I.	FINANCIAL INFORMATION			3
Item 1.		Financial Statements (Unaudited)		3
		Consolidated Combined Balance Sheets as of March 31, 2012 and December 31, 2011		3
		Consolidated Combined Statements of Operations for the Three Months Ended March 31, 2012 and 2011		4
		Consolidated Combined Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2012 and 2011		5
		Consolidated Combined Statement of Partners’ Capital for the Three Months Ended March 31, 2012		6
		Consolidated Combined Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011		7
		Notes to Consolidated Combined Financial Statements		8
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		44
Item 3.		Quantitative and Qualitative Disclosures About Market Risk		60
Item 4.		Controls and Procedures		64
PART II.	OTHER INFORMATION			65
Item 6.		Exhibits		65
SIGNATURES				69

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PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED BALANCE SHEETS

(in thousands)

(Unaudited)

	March 31,		December 31,
	2012		2011
ASSETS
Current assets:
Cash and cash equivalents	$	45,349	$	77,376
Accounts receivable		126,090		136,853
Current portion of derivative asset		26,154		15,447
Subscriptions receivable		—		34,455
Prepaid expenses and other		19,850		24,779
Total current assets		217,443		288,910
Property, plant and equipment, net		2,164,021		2,093,283
Intangible assets, net		109,524		104,777
Investment in joint venture		85,975		86,879
Goodwill, net		31,784		31,784
Long-term derivative asset		25,111		30,941
Other assets, net		47,563		48,197
	$	2,681,421	$	2,684,771
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current portion of long-term debt	$	4,011	$	2,085
Accounts payable		69,830		93,554
Liabilities associated with drilling contracts		27,998		71,719
Accrued producer liabilities		77,047		88,096
Current portion of derivative liability		1,642		—
Current portion of derivative payable to Drilling Partnerships		18,541		20,900
Accrued interest		9,760		1,629
Accrued well drilling and completion costs		20,404		17,585
Accrued liabilities		52,963		61,653
Total current liabilities		282,196		357,221
Long-term debt, less current portion		626,314		522,055
Long-term derivative payable to Drilling Partnerships		11,499		15,272
Asset retirement obligations and other		54,152		46,142
Commitments and contingencies
Partners’ Capital:
Common limited partners’ interests		442,700		554,999
Accumulated other comprehensive income		32,961		29,376
		475,661		584,375
Non-controlling interests		1,231,599		1,159,706
Total partners’ capital		1,707,260		1,744,081
	$	2,681,421	$	2,684,771

See accompanying notes to consolidated combined financial statements

3

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

	Three Months Ended March 31,
	2012			2011
Revenues:
Gas and oil production	$	17,164		$	17,626
Well construction and completion		43,719			17,725
Gathering and processing		305,220			280,218
Administration and oversight		2,831			1,361
Well services		5,006			5,286
Loss on mark-to-market derivatives		(12,035	)		(21,645	)
Other, net		2,801			4,353
Total revenues		364,706			304,924
Costs and expenses:
Gas and oil production		4,505			3,921
Well construction and completion		37,695			15,021
Gathering and processing		251,924			236,984
Well services		2,430			2,360
General and administrative		37,248			16,190
Depreciation, depletion and amortization		29,950			26,607
Total costs and expenses		363,752			301,083
Operating income		954			3,841
Gain (loss) on asset disposals		(7,005	)		255,947
Interest expense		(9,091	)		(18,078	)
Income (loss) from continuing operations		(15,142	)		241,710
Discontinued operations:
Loss from discontinued operations		—			(81	)
Net income (loss)		(15,142	)		241,629
Income attributable to non-controlling interests		(3,365	)		(211,378	)
Income (loss) after non-controlling interests		(18,507	)		30,251
Income not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition (see Note 2))		—			(4,711	)
Net income (loss) attributable to common limited partners	$	(18,507	)	$	25,540
Net income (loss) attributable to common limited partners per unit - basic and diluted:
Income (loss) from continuing operations attributable to common limited partners	$	(0.36	)	$	0.65
Loss from discontinued operations attributable to common limited partners		—			—
Net income (loss) attributable to common limited partners	$	(0.36	)	$	0.65
Weighted average common limited partner units outstanding:
Basic		51,294			39,010
Diluted		51,294			39,245
Income (loss) attributable to common limited partners:
Income (loss) from continuing operations	$	(18,507	)	$	25,550
Loss from discontinued operations		—			(10	)
Net income (loss) attributable to common limited partners	$	(18,507	)	$	25,540

See accompanying notes to consolidated combined financial statements

4

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)

	Three Months Ended March 31,
	2012			2011
Net income (loss)	$	(15,142	)	$	241,629
Income attributable to non-controlling interests		(3,365	)		(211,378	)
Income not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of the acquisition (see Note 2))		—			(4,711	)
Net income (loss) attributable to common unitholders		(18,507	)		25,540
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges		14,169			442
Less: reclassification adjustment for realized gains in net income (loss)		(1,454	)		(6,029	)
Changes in non-controlling interest related to items in other comprehensive income (loss)		(9,130	)		(1,465	)
Total other comprehensive income (loss)		3,585			(7,052	)
Comprehensive income (loss) attributable to common unitholders	$	(14,922	)	$	18,488

See accompanying notes to consolidated combined financial statements

5

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED STATEMENTS OF PARTNERS’ CAPITAL

(in thousands, except unit data)

(Unaudited)

						Accumulated
	Common Limited					Other		Non-			Total
	Partners’ Capital					Comprehensive		Controlling			Partners’
	Units		Amount			Income		Interests			Capital
Balance at January 1, 2012		51,278,362	$	554,999		$	29,376	$	1,159,706		$	1,744,081
Distribution of Atlas Resource Partners, L.P. units		—		(84,892	)		—		84,892			—
Distributions to non-controlling interests		—		—			—		(26,286	)		(26,286	)
Unissued common units under incentive plans		—		3,831			—		928			4,759
Issuance of units under incentive plans		28,917		32			—		77			109
Distributions paid to common limited partners		—		(12,310	)		—		—			(12,310	)
Distribution equivalent rights paid on unissued units under incentive plans		—		(453	)		—		(216	)		(669	)
Other comprehensive income		—		—			3,585		9,133			12,718
Net income (loss)		—		(18,507	)		—		3,365			(15,142	)
Balance at March 31, 2012		51,307,279	$	442,700		$	32,961	$	1,231,599		$	1,707,260

See accompanying notes to consolidated combined financial statements

6

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Three Months Ended March 31,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(15,142	)	$	241,629
Loss from discontinued operations		—			(81	)
Income (loss) from continuing operations		(15,142	)		241,710
Adjustments to reconcile net income (loss) from continuing operations to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		29,950			26,607
Amortization of deferred finance costs		1,359			6,199
Non-cash loss on derivative value, net		3,351			72,807
Non-cash compensation expense		4,759			1,678
(Gain) loss on asset disposals		7,005			(255,947	)
Distributions paid to non-controlling interests		(26,502	)		(19,251	)
Equity income in unconsolidated companies		(1,233	)		(1,613	)
Distributions received from unconsolidated companies		1,996			2,154
Changes in operating assets and liabilities:
Accounts receivable and prepaid expenses and other		50,810			(17,437	)
Accounts payable and accrued liabilities		(60,845	)		(34,572	)
Net cash provided by (used in) continuing operating activities		(4,492	)		22,335
Net cash used in discontinued operating activities		—			(81	)
Net cash provided by (used in) operating activities		(4,492	)		22,254
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(100,125	)		(26,065	)
Net cash paid for acquisitions		(17,235	)		—
Investments in unconsolidated companies		—			(12,250	)
Net proceeds from asset disposals		—			411,753
Other		(941	)		(1,480	)
Net cash provided by (used in) investing activities		(118,301	)		371,958
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facilities		336,500			178,000
Repayments under credit facilities		(231,500	)		(248,000	)
Repayments of long-term debt		—			(35,415	)
Distributions paid to unitholders		(12,310	)		(1,948	)
Cash placed in escrow (APL Senior Note Redemption)		—			(293,696	)
Net transaction adjustment related to the acquisition of the Transferred Business (see Note 3)		—			117,230
Deferred financing costs and other		(1,924	)		(4,700	)
Net cash provided by (used in) financing activities		90,766			(288,529	)
Net change in cash and cash equivalents		(32,027	)		105,683
Cash and cash equivalents, beginning of year		77,376			247
Cash and cash equivalents, end of period	$	45,349		$	105,930

See accompanying notes to consolidated combined financial statements

7

ATLAS ENERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED COMBINED FINANCIAL STATEMENTS

March 31, 2012

(Unaudited)

NOTE 1 — BASIS OF PRESENTATION

Atlas Energy, L.P., (the “Partnership” or “Atlas Energy”) is a publicly-traded Delaware master limited partnership, formerly known as Atlas Pipeline Holdings, L.P. (NYSE: ATLS).

At March 31, 2012, the Partnership’s operations primarily consisted of its ownership interests in the following entities:

• Atlas Resource Partners, L.P. (“ARP”), a publicly-traded Delaware master limited partnership (NYSE: ARP) and an independent developer and producer of natural gas and oil, with operations in basins across the United States. ARP sponsors and manages tax-advantaged investment partnerships, in which it coinvests, to finance a portion of its natural gas and oil production activities. At March 31, 2012, the Partnership owned 100% of the general partner Class A units and incentive distribution rights through which it manages and effectively controls ARP, and common units representing an approximate 78.4% limited partner interest in ARP;

• Atlas Pipeline Partners, L.P. (“APL”), a publicly traded Delaware master limited partnership (NYSE: APL) and midstream energy service provider engaged in the gathering and processing of natural gas in the Mid-Continent and Appalachia regions of the United States. At March 31, 2012, the Partnership owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate 10.5% common limited partner interest in APL; and

• Lightfoot Capital Partners, LP (“Lightfoot LP”) and Lightfoot Capital Partners GP, LLC (“Lightfoot GP”), the general partner of Lightfoot L.P. (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. At March 31, 2012, the Partnership had an approximate 16% general partner interest and 12% limited partner interest in Lightfoot (see Note 6).

In February 2012, the board of directors of the Partnership’s General Partner (“the Board”) approved the formation of ARP as a newly created exploration and production master limited partnership and the related transfer of substantially all of the Partnership’s exploration and production assets to ARP on March 5, 2012. The Board also approved the distribution of approximately 5.24 million ARP common units to the Partnership’s unitholders, which were distributed on March 13, 2012 using a ratio of 0.1021 ARP limited partner units for each of the Partnership’s common units owned on the record date of February 28, 2012. The distribution of ARP limited partner units represented approximately 20% of the common limited partner units outstanding at March 13, 2012.

The accompanying consolidated combined financial statements, which are unaudited except that the balance sheet at December 31, 2011 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated combined financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2011 (see Note 2). Certain amounts in the prior year’s consolidated combined financial statements have also been reclassified to conform to the current year presentation. The results of operations for the three month period ended March 31, 2012 may not necessarily be indicative of the results of operations for the full year ending December 31, 2012.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Combination

The consolidated combined financial statements include the accounts of the Partnership and its consolidated subsidiaries, all of which are wholly-owned at March 31, 2012 except for ARP and APL, which are controlled by the Partnership. Due to the structure of the Partnership’s ownership interests in ARP and APL, the Partnership consolidates the financial statements of ARP and APL into its consolidated combined financial statements rather than present its ownership

8

interest as equity investments. As such, the non-controlling interests in ARP and APL are reflected as income (loss) attributable to non-controlling interests in its consolidated combined statements of operations and as a component of partners’ capital on its consolidated combined balance sheets. All material intercompany transactions have been eliminated.

On February 17, 2011, the Partnership acquired certain producing natural gas and oil properties, a partnership management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, and other assets (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of the Partnership’s general partner (see Note 3). Management of the Partnership determined that the acquisition of the Transferred Business constituted a transaction between entities under common control. In comparison to the purchase method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable assets and liabilities of the Transferred Business based upon their fair values with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital on the Partnership’s consolidated combined balance sheets. Also, in comparison to the purchase method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in the Partnership’s consolidated combined financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect to the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, the Partnership reflected the impact of the acquisition of the Transferred Business on its consolidated combined financial statements in the following manner:

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

• Retrospectively adjusted its consolidated combined financial statements for any date prior to February 17, 2011, the date of acquisition, to reflect its results on a consolidated combined basis with the results of the Transferred Business as of or at the beginning of the respective period; and

• Adjusted the presentation of the Partnership’s consolidated combined statements of operations for the three months ended March 31, 2011 to reflect the results of operations attributable to the Transferred Business prior to the date of acquisition as a reduction of net income to determine income attributable to common limited partners. However, the Transferred Business’ historical financial statements prior to the date of acquisition do not reflect general and administrative expenses and interest expense. The Transferred Business was not managed by AEI as a separate business segment and did not have identifiable labor and other ancillary costs. The general and administrative and interest expenses of AEI prior to the date of acquisition, including the exploration and production business segment, related primarily to business activities associated with the business sold to Chevron Corporation in February 2011 and not activities related to the Transferred Business.

In accordance with established practice in the oil and gas industry, the Partnership’s consolidated combined financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the energy partnerships in which ARP has an interest (“the Drilling Partnerships”). Such interests typically range from 20% to 41%. The Partnership’s financial statements do not include proportional consolidation of the depletion or impairment expenses of ARP’s Drilling Partnerships. Rather, ARP calculates these items specific to its own economics as further explained under the heading “Property, Plant and Equipment” elsewhere within this note.

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

The West TX joint venture has a 72.8% undivided joint venture interest in the West TX system, of which the remaining 27.2% interest is owned by Pioneer Natural Resources Company (NYSE: PXD). Due to the West TX system’s

9

status as an undivided joint venture, the West TX joint venture proportionally consolidates its 72.8% ownership interest in the assets and liabilities and operating results of the West TX system.

Use of Estimates

The preparation of the Partnership’s consolidated combined financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated combined financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s consolidated combined financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. Such estimates included estimated allocations made from the historical accounting records of AEI in order to derive the historical financial statements of the Transferred Business prior to February 17, 2011, the date of acquisition (see “Principles of Consolidation and Combination”). Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three months ended March 31, 2012 and 2011 represent actual results in all material respects (see “Revenue Recognition”).

Receivables

Accounts receivable on the consolidated combined balance sheets consist solely of the trade accounts receivable associated with ARP’s and APL’s operations. In evaluating the realizability of its accounts receivable, management of ARP and 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 management’s review of ARP’s and APL’s customers’ credit information. ARP and APL extend credit on sales on an unsecured basis to many of its customers. At March 31, 2012 and December 31, 2011, ARP and APL had recorded no allowance for uncollectible accounts receivable on the Partnership’s consolidated combined 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. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Partnership’s results of operations. APL follows the composite method of depreciation and has determined the composite groups to be the major asset classes of its gathering and processing systems. Under the composite depreciation method, any gain or loss upon disposition or retirement of pipeline, gas gathering and processing components, is recorded to accumulated depreciation.

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

ARP’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include ARP’s costs of property interests in proportionately consolidated investment partnerships, joint venture wells, wells drilled solely by ARP for its interests, properties purchased and working interests with other outside operators.

10

Upon the sale or retirement of an ARP complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Partnership’s consolidated combined statements of operations. Upon the sale of an individual ARP well, ARP credits the proceeds to accumulated depreciation and depletion within the Partnership’s consolidated combined balance sheets. Upon ARP’s sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Partnership’s consolidated combined statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

Impairment of Long-Lived Assets

The Partnership and its subsidiaries review their long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of ARP’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on ARP’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. ARP estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, ARP’s reserve estimates for its investment in the Drilling Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include ARP’s actual capital contributions, an additional carried interest (generally 5% to 10%), a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

ARP’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to ARP their proportionate share of these expenses plus a profit margin. These assumptions could result in ARP’s calculation of depletion and impairment being different than its proportionate share of the Drilling Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. ARP cannot predict what reserve revisions may be required in future periods.

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

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate that ARP will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. There were no impairments of unproved gas and oil properties recorded by ARP for the three months ended March 31, 2012 and 2011.

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Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2011, the Partnership recognized $7.0 million of asset impairment related to ARP’s gas and oil properties within property, plant and equipment on its consolidated combined balance sheet for its shallow natural gas wells in the Niobrara Shale. This impairment related to the carrying amount of the gas and oil properties being in excess of ARP’s estimate of their fair value at December 31, 2011. The estimate of fair value of the gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

Capitalized Interest

ARP and APL capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP and APL in the aggregate were 6.7% and 5.9% for the three months ended March 31, 2012 and 2011, respectively. The aggregate amounts of interest capitalized by ARP and APL were $2.3 million and $0.4 million for the three months ended March 31, 2012 and 2011, respectively.

Intangible Assets

Customer contracts and relationships. APL amortizes intangible assets with finite lives in connection with natural gas gathering contracts and customer relationships assumed in certain consummated acquisitions, which APL amortizes over their estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset must be amortized over the best estimate of its useful life. At a minimum, APL will assess the useful lives of all intangible assets on an annual basis to determine if adjustments are required. The estimated useful life for APL’s customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition, adjusted for APL’s management’s estimate of whether the individual relationships will continue in excess or less than the average length. APL completed the acquisition of a gas gathering system in February 2012 and recognized $10.6 million related to customer contracts with an estimated useful life 14 years.

Partnership management and operating contracts. ARP has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. ARP amortizes contracts acquired on a declining balance over their respective estimated useful lives.

The following table reflects the components of intangible assets being amortized at March 31, 2012 and December 31, 2011 (in thousands):

	March 31, 2012			December 31, 2011			Estimated Useful Lives In Years
Gross Carrying Amount:
Customer contracts and relationships	$	215,946		$	205,313		7 – 14
Partnership management and operating contracts		14,344			14,344		1 – 13
	$	230,290		$	219,657
Accumulated Amortization:
Customer contracts and relationships	$	(107,876	)	$	(102,037	)
Partnership management and operating contracts		(12,890	)		(12,843	)
	$	(120,766	)	$	(114,880	)
Net Carrying Amount:
Customer contracts and relationships	$	108,070		$	103,276
Partnership management and operating contracts		1,454			1,501
	$	109,524		$	104,777

Amortization expense on intangible assets was $5.9 million and $6.0 million for the three months ended March 31 2012 and 2011, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2012 - $24.0 million; 2013 - $24.0 million; 2014 - $20.4 million; 2015 - $15.4 million; and 2016 - $15.4 million.

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Goodwill

At March 31, 2012 and December 31, 2011, the Partnership had $31.8 million of goodwill recorded in connection with prior ARP consummated acquisitions. There were no changes in the carrying amount of goodwill for the three months ended March 31, 2012 and 2011.

ARP tests its goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units. ARP’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including ARP’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, ARP also considers the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ARP’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in ARP’s industry to determine whether those valuations appear reasonable in management’s judgment. ARP’s management will continue to evaluate goodwill at least annually or when impairment indicators arise. During the three months ended March 31, 2012 and 2011, no impairment indicators arose, and no goodwill impairments were recognized by the Partnership.

Capital Leases

Leased property and equipment meeting capital lease criteria are capitalized based on the minimum payments required under the lease and are included within property, plant and equipment on the Partnership’s consolidated combined balance sheets. Obligations under capital leases are accounted for as current and noncurrent liabilities and are included within debt on the Partnership’s consolidated combined balance sheets. Amortization is calculated on a straight-line method based upon the estimated useful lives of the assets (see Note 8).

Derivative Instruments

ARP and APL enter into certain financial contracts to manage their exposure to movement in commodity prices and interest rates (see Note 9). The derivative instruments recorded in the consolidated combined balance sheets were measured as either an asset or liability at fair value. Changes in ARP’s and APL’s derivative instrument’s fair value are recognized currently in the Partnership’s consolidated combined statements of operations unless specific hedge accounting criteria are met.

Asset Retirement Obligations

ARP recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 7). ARP also recognizes a liability for its future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership and its subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

Stock-Based Compensation

The Partnership recognizes all share-based payments to employees, including grants of employee stock options, in the consolidated combined financial statements based on their fair values (see Note 15).

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.

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Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. The Partnership’s phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plans and incentive compensation agreements (see Note 15), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights result in a non-contingent transfer of value each time the Partnership declares a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis.

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

	Three Months Ended March 31,
	2012			2011
Continuing operations:
Net income (loss)	$	(15,142	)	$	241,710
Income attributable to non-controlling interests		(3,365	)		(211,449	)
Income not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition (see Note 2))		—			(4,711	)
Net income (loss) attributable to common limited partners		(18,507	)		25,550
Less: Net income attributable to participating securities - phantom units(1)		—			(98	)
Net income (loss) utilized in the calculation of net income (loss) from continuing operations attributable to common limited partners per unit	$	(18,507	)	$	25,452
Discontinued operations:
Net loss	$	—		$	(81	)
Loss attributable to non-controlling interests		—			71
Net loss utilized in the calculation of net income from discontinued operations attributable to common limited partners per unit	$	—		$	(10	)

⁽¹⁾  Net income attributable to common limited partners’ ownership interests is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the three months ended March 31, 2012, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 1,929,000 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, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, as calculated by the treasury stock method. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of the Partnership’s long-term incentive plans (see Note 15).

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):

	Three Months Ended March 31,
	2012		2011
Weighted average number of common limited partners per unit - basic		51,294		39,010
Add effect of dilutive incentive awards(1)		—		235
Weighted average number of common limited partners per unit - diluted		51,294		39,245

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⁽¹⁾  For the three months ended March 31, 2012, approximately 2,260,000 units 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.

Revenue Recognition

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

ARP generally sells natural gas, crude oil and NGLs at prevailing market prices. Generally, ARP’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed 2 business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil, in which ARP has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.

Atlas Pipeline. APL’s revenue primarily consists of the sale of natural gas and NGLs, along with the fees earned from its gathering, processing and transportation operations. Under certain agreements, APL purchases natural gas from producers, moves it into receipt points on its pipeline systems and then sells the natural gas, or produced NGLs, if any, at 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 and NGLs is recognized upon physical delivery. In connection with its gathering, processing and transportation operations, APL enters into the following types of contractual relationships with its producers and shippers:

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

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

• Keep-Whole Contracts. These contracts require APL, as the processor and gatherer, to gather or purchase raw natural gas at current market rates per MMBTU. The volume and energy content of gas gathered or purchased is based on the measurement at an agreed upon location (generally at the wellhead). The BTU quantity of gas redelivered or sold at the tailgate of APL’s processing facility may be lower than the BTU quantity purchased at the wellhead primarily due to the NGLs extracted from the natural gas when processed through a plant. APL must make up or “keep the producer whole” for this loss in BTU quantity. To offset the make-up obligation, APL retains the NGLs which are extracted and sells them for its own account. Therefore, APL bears the economic risk (the “processing margin risk”) that (i) the BTU quantity of residue gas available for redelivery to the producer may be less than APL received from the producer; and/or (ii) aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that it paid for the unprocessed natural gas. In order to help mitigate the risk associated with Keep-Whole contracts, APL generally imposes a fee to gather the gas that is settled under this arrangement. Also, because the natural gas volumes contracted under some Keep-Whole

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agreements are lower in BTU content and thus can meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants on these systems and delivered directly into downstream pipelines during periods when the processing margin is uneconomic.

ARP and APL accrue unbilled revenue due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from ARP’s and APL’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “- Use of Estimates” accounting policy for further description). ARP and APL had unbilled revenues at March 31, 2012 and December 31, 2011 of $76.0 million and $81.2 million, respectively, which were included in accounts receivable within the Partnership’s consolidated combined balance sheets.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” and for the Partnership includes changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.

Recently Adopted Accounting Standards

In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“Update 2011-12”). The amendments in this update effectively defer the implementation of the changes made in Update 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income (“Update 2011-05”), related to the presentation of reclassification adjustments out of accumulated other comprehensive income. Under Update 2011-05 which was issued by the FASB in June 2011, entities are provided the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. Under each methodology, an entity is required to present each component of net income along with a total net income, each component of other comprehensive income and a total amount for comprehensive income. Update 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. As a result of Update 2011-12, entities are required to disclose reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect prior to Update 2011-05. All other requirements in Update 2011-05 are not affected by Update 2011-12. These requirements are effective for interim and annual reporting periods beginning after December 15, 2011. Accordingly, entities are not required to comply with presentation requirements of Update 2011-05 related to the disclosure of reclassifications out of accumulated other comprehensive income. The Partnership included consolidated combined statements of comprehensive income within this Form 10-Q upon the adoption of these ASUs on January 1, 2012. The adoption had no material impact on the Partnership’s financial condition or results of operations.

In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosure about Offsetting Assets and Liabilities (“Update 2011-11”). The amendments in this update require an entity to disclose both gross and net information about both financial and derivative instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the statement of financial position. An entity shall disclose at the end of a reporting period certain quantitative information separately for assets and liabilities that are within the scope of Update 2011-11, as well as provide a description of the rights of setoff associated with an entity’s recognized assets and recognized liabilities subject to an enforceable master netting arrangement or similar agreement. Entities are required to implement the amendments for interim and annual reporting periods beginning after January 1, 2013 and shall be applied retrospectively for any period presented that begins before the date of initial application. The Partnership has elected to early adopt these requirements and updated its disclosures to meet these requirements effective January 1, 2012 (see Note 9). The adoption had no material impact on the Partnership’s financial position or results of operations.

In September 2011, the FASB issued ASU 2011-08, Intangibles-Goodwill and Other (Topic 350): Testing Goodwill for Impairment (“Update 2011-08”). The amendments in Update 2011-08 allow an entity to first assess qualitative factors in determining the necessity of performing the two-step quantitative goodwill impairment test. If, after assessing qualitative factors, an entity determines it is not likely that the fair value of a reporting unit is less than its carrying amount, performing the two-step impairment test is unnecessary. Under the amendments in Update 2011-08, an entity has the option to bypass the

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qualitative assessment and proceed directly to performing the first step of the two-step impairment test. The amendments are effective for interim and annual goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The Partnership adopted the amendments of Update 2011-08 upon its effective date of January 1, 2012. The adoption had no material impact on the Partnership’s financial position or results of operations.

In May 2011, the FASB issued ASU 2011-04, Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“Update 2011-04”). The amendments in Update 2011-04 revise the wording used to describe many of the requirements for measuring fair value and for disclosing information about fair value measurements in U.S. GAAP. For many of the amendments, the guidance is not necessarily intended to result in a change in the application of the requirements in Topic 820; rather it is intended to clarify the intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. As a result, Update 2011-04 aims to provide common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards. These requirements are effective for interim and annual reporting periods beginning after December 15, 2011. The Partnership updated its disclosures to meet these requirements upon the adoption of Update 2011-04 on January 1, 2012 (see Note 10). The adoption had no material impact on the Partnership’s financial position or results of operations.

NOTE 3 — ACQUISITION FROM ATLAS ENERGY, INC.

On February 17, 2011, the Partnership acquired the Transferred Business from AEI, including the following exploration and production assets that were transferred to ARP on March 5, 2012:

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

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

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

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

For the assets acquired and liabilities assumed, the Partnership issued approximately 23.4 million of its common limited partner units and paid $30.0 million in cash consideration. Based on the Partnership’s February 17, 2011 common unit closing price of $15.92, the common units issued to AEI were valued at approximately $372.2 million. In connection with the transaction, the Partnership also received $118.7 million with respect to a contractual cash transaction adjustment from AEI related to certain liabilities assumed by the Partnership, including certain amounts subject to a reconciliation period following the consummation of the transaction. The reconciliation period was assumed by ARP on March 5, 2012 and remains ongoing at March 31, 2012, and certain amounts included within the contractual cash transaction adjustment are in dispute between the parties. The resolution of the disputed amounts could result in ARP being required to repay a portion of the cash transaction adjustment (see Note 12). Including the cash transaction adjustment, the net book value of the Transferred Business was approximately $522.9 million.

Concurrent with the Partnership’s acquisition of the Transferred Business on February 17, 2011, including assets and liabilities transferred to ARP on March 5, 2012, AEI completed its merger with Chevron Corporation (“Chevron”), whereby AEI became a wholly owned subsidiary of Chevron. Also concurrent with the Partnership’s acquisition of the Transferred Business and immediately preceding AEI’s merger with Chevron, APL completed its sale to AEI of its 49% non-controlling interest in Laurel Mountain Midstream, LLC (“Laurel Mountain”; see Note 4). APL received $409.5 million in cash, including adjustments based on certain capital contributions APL made to and distributions it received from the Laurel Mountain joint venture after January 1, 2011. APL retained the preferred distribution rights under the limited liability company agreement of the Laurel Mountain joint venture entitling APL to receive all payments made under the note receivable issued to Laurel Mountain by Williams Laurel Mountain, LLC (“Williams”) in connection with the formation of the Laurel Mountain joint venture.

Management of the Partnership determined that the acquisition of the Transferred Business constituted a transaction between entities under common control. As such, the Partnership recognized the assets acquired and liabilities assumed at historical carrying value at the date of acquisition, with the difference between the purchase price and the net book value of

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the assets recognized as an adjustment to partners’ capital on its consolidated combined balance sheet. The Partnership recognized a non-cash decrease of $261.0 million in partners’ capital on its consolidated combined balance sheet based on the excess net book value above the value of the consideration paid to AEI. The following table presents the historical carrying value of the assets acquired and liabilities assumed by the Partnership, including the effect of cash transaction adjustments, as of February 17, 2011 (in thousands):

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

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

NOTE 4 — APL INVESTMENT IN JOINT VENTURES

West Texas LPG Pipeline Limited Partnership

On May 11, 2011, APL acquired a 20% interest in West Texas LPG Pipeline Limited Partnership (“West Texas LPG”) from Buckeye Partners, L.P. (NYSE: BPL) for $85.0 million. West Texas LPG owns a common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. West Texas LPG is operated by Chevron Pipeline Company, a subsidiary of Chevron, which owns the remaining 80% interest. APL has accounted for its ownership interest in West Texas LPG under the equity method of accounting, with recognition of its ownership interest in the income of West Texas LPG in other, net on the Partnership’s consolidated combined statements of operations. During the three months ended March 31, 2012, APL recognized $0.9 million of equity income within other, net on the Partnership’s consolidated combined statements of operations related to its West Texas LPG interest.

Laurel Mountain

On February 17, 2011, APL completed the sale of its 49% non-controlling interest in the Laurel Mountain joint venture to AEI (see Note 3). The Laurel Mountain joint venture was formed in May 2009 by APL and subsidiaries of the Williams Companies, Inc. (NYSE: WMB; “Williams”) to own and operate APL’s Appalachian Basin natural gas gathering system. APL used the proceeds from the sale to repay its indebtedness and for general corporate purposes. APL also retained its preferred distribution rights with respect to a remaining $8.5 million note receivable due from Williams, an investment grade rated entity, related to the formation of Laurel Mountain, including interest due on this note. Since APL accounted for its ownership of Laurel Mountain as an equity investment included within investment in joint venture on the Partnership’s consolidated combined balance sheet and recognition of its ownership interest in the income of Laurel Mountain as other income (loss) on the Partnership’s consolidated combined statements of operations, APL did not reclassify

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the earnings or the gain on sale related to Laurel Mountain to discontinued operations upon the sale of its ownership interest. The Partnership recognized a net gain of $255.9 million during the three months ended March 31, 2011, which is included in gain (loss) on asset disposal within the Partnership’s consolidated combined statements of operations. The Partnership also reclassified the $8.5 million note receivable previously recorded to investment in joint venture to prepaid expenses and other on the Partnership’s consolidated combined balance sheets. In December 2011, Williams made a cash payment to APL to settle the remaining $8.5 million balance on the note receivable plus accrued interest of $0.2 million.

The following tables summarize the components of equity income within other, net on the Partnership’s consolidated combined statements of operations (in thousands).

	Three Months Ended March 31,
	2012		2011
Equity income in Laurel Mountain	$	—	$	462
Equity income in WTLPG		896		—
Equity income in joint ventures	$	896	$	462

NOTE 5 — PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment at the dates indicated (in thousands):

	March 31, 2012			December 31, 2011			Estimated Useful Lives in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	67,151		$	61,587
Pre-development costs		1,367			2,540
Wells and related equipment		829,775			828,780
Total proved properties		898,293			892,907
Unproved properties		40,804			43,253
Support equipment		10,015			9,413
Total natural gas and oil properties		949,112			945,573
Pipelines, processing and compression facilities		1,726,498			1,646,320		2 – 40
Rights of way		168,894			161,275		20 – 40
Land, buildings and improvements		23,491			23,416		3 – 40
Other		24,169			22,734		3 – 10
		2,892,164			2,799,318
Less - accumulated depreciation, depletion and amortization		(728,143	)		(706,035	)
	$	2,164,021		$	2,093,283

During the three months ended March 31, 2012, ARP recognized a $7.0 million loss on asset disposal pertaining to its decision to terminate a farm out agreement with a third party for well drilling in the South Knox area of the New Albany Shale that was originally entered into in 2010. The farm out agreement contained certain well drilling targets for ARP to maintain ownership of the South Knox processing plant, which ARP’s management decided in 2012 to not achieve due to the current natural gas price environment. As a result, ARP forfeited its interest in the processing plant and related properties and recorded a loss related to the net book values of those assets as of March 31, 2012.

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

NOTE 6 — OTHER ASSETS

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

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	March 31, 2012		December 31, 2011
Deferred financing costs, net of accumulated amortization of $20,690 and $19,331 at March 31, 2012 and December 31, 2011, respectively	$	23,252	$	23,426
Investment in Lightfoot		19,415		19,514
Security deposits		2,658		4,584
Other		2,238		673
	$	47,563	$	48,197

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 8). Amortization expense of ARP’s and APL’s deferred finance costs was $1.4 million and $1.3 million for the three months ended March 31, 2012 and 2011, respectively, which is recorded within interest expense on the Partnership’s consolidated combined statements of operations. In March 2011, the Partnership recorded an additional $4.9 million of accelerated amortization of its deferred financing costs associated with the retirement of its $70 million credit facility.

At March 31, 2012, the Partnership owns an approximate 12% interest in Lightfoot LP and an approximate 16% interest in Lightfoot GP, the general partner of Lightfoot LP, an entity for which Jonathan Cohen, Chairman of the General Partner’s board of directors, is the Chairman of the Board. Lightfoot LP focuses its investments primarily on incubating new master limited partnerships and providing capital to existing MLPs in need of additional equity or structured debt. The Partnership accounts for its investment in Lightfoot under the equity method of accounting. During the three months ended March 31, 2012 and 2011, the Partnership recorded equity income of $0.3 million and $1.2 million, respectively. The equity income was recorded within other, net on the Partnership’s consolidated combined statements of operations. During the three months ended March 31, 2012 and 2011, the Partnership received net cash distributions of $0.2 million and $0.4 million, respectively.

NOTE 7 — ASSET RETIREMENT OBLIGATIONS

ARP recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities. ARP also recognizes a liability for its future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership and its subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability is based on ARP’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. ARP has no assets legally restricted for purposes of settling asset retirement obligations. Except for ARP’s gas and oil properties, the Partnership and its subsidiaries have determined that there are no other material retirement obligations associated with tangible long-lived assets.

A reconciliation of ARP’s liability for well plugging and abandonment costs recorded on the Partnership’s consolidated combined balance sheets for the periods indicated is as follows (in thousands):

	Three Months Ended March 31,
	2012			2011
Asset retirement obligations, beginning of year	$	45,779		$	42,673
Liabilities incurred		181			93
Liabilities settled		(118	)		(99	)
Accretion expense		696			648
Asset retirement obligations, end of period	$	46,538		$	43,315

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

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NOTE 8 — DEBT

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

	March 31, 2012			December 31, 2011
ARP revolving credit facility	$	17,000		$	—
APL revolving credit facility		230,000			142,000
APL 8.75 % Senior Notes - due 2018		370,783			370,983
APL capital leases		12,542			11,157
Total debt		630,325			524,140
Less current maturities		(4,011	)		(2,085	)
Total long-term debt	$	626,314		$	522,055

Partnership’s Credit Facility

At March 31, 2012, the Partnership’s debt consisted entirely of instruments entered into by ARP and APL, and it has not guaranteed any of its subsidiaries’ debt obligations. On March 5, 2012, in connection with the transfer of substantially all of the Partnership’s exploration and production assets to ARP (see Note 1 and “ARP’s Credit Facility”), the Partnership assigned its credit facility, which had maximum lender commitments of $300 million and a borrowing base of $138 million, to ARP.

ARP’s Credit Facility

On March 5, 2012, the Partnership’s credit facility was amended and restated such that it assigned, and ARP assumed, the Partnership’s rights, privileges and obligations under the credit facility. The transferred credit facility, which had $17.0 million outstanding at March 31, 2012, has maximum lender commitments of $300 million, a borrowing base of $138 million and matures in March 2016 (see Note 17). The borrowing base will be redetermined semi-annually with the first such redetermination to occur on May 1, 2012. Up to $20.0 million of the credit facility may be in the form of standby letters of credit, of which $0.8 million was outstanding at March 31, 2012, which was not reflected as borrowings on the Partnership’s consolidated combined balance sheet. ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by substantially all of ARP’s subsidiaries. Borrowings under the credit facility bear interest, at ARP’s election, at either LIBOR plus an applicable margin between 2.00% and 3.25% or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 1.00% and 2.25%. ARP is also required to pay a fee of 0.5% per annum on the unused portion of the borrowing base, which is included within interest expense on the Partnership’s consolidated combined statements of operations. At March 31, 2012, the weighted average interest rate was 4.25%.

The credit agreement contains customary covenants that limit ARP’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. ARP was in compliance with these covenants as of March 31, 2012. The credit agreement also requires ARP to maintain a ratio of its Total Funded Debt (as defined in the credit agreement) to four quarters (actual or annualized, as applicable) of its EBITDA (as defined in the credit agreement) not greater than 3.75 to 1.0 as of the last day of any fiscal quarter, a ratio of its current assets (as defined in the credit agreement) to its current liabilities (as defined in the credit agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter, and a ratio of four quarters (actual or annualized, as applicable) of its EBITDA to its Consolidated Interest Expense (as defined in the credit agreement) of not less than 2.5 to 1.0 as of the last day of any fiscal quarter. Based on the definitions contained in ARP’s credit facility, its ratio of current assets to current liabilities was 1.5 to 1.0, its ratio of Total Funded Debt to EBITDA was 0.3 to 1.0 and its ratio of EBITDA to Consolidated Interest Expense was 423.1 to 1.0 at March 31, 2012.

APL Credit Facility

At March 31, 2012, APL had a $450.0 million senior secured revolving credit facility with a syndicate of banks, which matures in December 2015, of which $230.0 million was outstanding. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) three-month LIBOR plus 1.0%, or (ii) the LIBOR rate for the applicable period (each plus the applicable margin). The weighted average

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interest rate on APL’s outstanding revolving credit facility borrowings at March 31, 2012 was 2.8%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $0.1 million was outstanding at March 31, 2012. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated combined balance sheet at March 31, 2012. At March 31, 2012, APL had $219.9 million of remaining committed capacity under its credit facility, subject to covenant limitations. The Partnership has not guaranteed any of the obligations under APL’s senior secured revolving credit facility.

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

The events which constitute an event of default for the revolving credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against APL in excess of a specified amount and a change of control of APL’s general partner. APL was in compliance with these covenants as of March 31, 2012.

APL Senior Notes

At March 31, 2012, APL had $370.8 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“APL 8.75% Senior Notes”). Interest on the APL 8.75% Senior Notes is payable semi-annually in arrears on June 15 and December 15. The APL 8.75% Senior Notes are redeemable at any time after June 15, 2013, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. The APL 8.75% Senior Notes are subject to repurchase by APL at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if APL does not reinvest the net proceeds within 360 days. The APL 8.75% Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its credit facility.

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

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

The indenture governing the APL 8.75% Senior Notes in the aggregate contains covenants, including limitations of APL’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. APL was in compliance with these covenants as of March 31, 2012.

APL Capital Leases

At March 31, 2012 and December 31, 2011, APL had $12.5 million and $11.2 million, respectively, of long-term debt related to capital leases. For leased property and equipment meeting capital lease criteria, APL recognizes an asset within property, plant and equipment with an offsetting liability recorded within long term debt on the Partnership’s consolidated combined balance sheets based on the minimum payments required under the lease and APL’s incremental borrowing rate. During the three months ended March 31, 2012, APL recognized $2.0 million of additional assets meeting capital lease criteria within property, plant and equipment and recognized an offsetting liability within long term debt on the Partnership’s consolidated combined balance sheets. The following is a summary of the leased property under capital leases, which are included within property, plant and equipment (see Note 5) (in thousands):

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	March 31, 2012			December 31, 2011
Pipelines, processing and compression facilities	$	14,512		$	12,507
Less - accumulated depreciation		(510	)		(199	)
	$	14,002		$	12,308

As of March 31, 2012, future minimum lease payments related to the capital leases are as follows (in thousands):

	Capital Lease Minimum Payments
2012	$	2,499
2013		10,879
2014		64
2015		—
2016		—
Thereafter		—
Total minimum lease payments		13,442
Less amounts representing interest		(900	)
Present value of minimum lease payments		12,542
Less current capital lease obligations		(4,011	)
Long-term capital lease obligations	$	8,531

Cash payments for interest for the Partnership and its subsidiaries were $1.4 million and $1.3 million for the three months ended March 31, 2012 and 2011, respectively.

NOTE 9 — DERIVATIVE INSTRUMENTS

ARP and APL use a number of different derivative instruments, principally swaps, collars, and options, in connection with their commodity and interest rate price risk management activities. ARP and APL enter into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold or interest payments on the underlying debt instrument are due. Under commodity-based swap agreements, ARP and APL receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.

ARP and APL formally document all relationships between hedging instruments and the items being hedged, including their risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity and interest derivative contracts to the forecasted transactions. ARP and APL assess, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, ARP and APL will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by management of ARP and APL through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated combined statements of operations. For derivatives qualifying as hedges, the ARP and APL recognize the effective portion of changes in fair value of derivative instruments in partners’ capital as accumulated other comprehensive income and reclassify the portion relating to ARP’s commodity derivatives to gas and oil production revenues and gathering and processing revenues for APL’s commodity derivatives and the portion relating to interest rate derivatives to interest expense within the Partnership’s consolidated combined statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, ARP and APL recognize changes in fair value within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated combined statements of operations as they occur.

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Derivatives are recorded on the Partnership’s consolidated combined balance sheets as assets or liabilities at fair value. The Partnership reflected net derivative assets on its consolidated combined balance sheets of $49.6 million and $46.4 million at March 31, 2012 and December 31, 2011, respectively. Of the $33.0 million of net gain in accumulated other comprehensive income within partners’ capital on the Partnership’s consolidated combined balance sheet related to derivatives at March 31, 2012, if the fair values of the instruments remain at current market values, the Partnership will reclassify $16.8 million of gains to its consolidated combined statement of operations over the next twelve month period as these contracts expire, consisting of $17.2 million of gains to gas and oil production revenues and $0.4 million of losses to gathering and processing revenues. Aggregate gains of $16.2 million to gas and oil production revenues will be reclassified to the Partnership’s consolidated combined statements of operations in later periods as these remaining contracts expire. Actual amounts that will be reclassified will vary as a result of future price changes.

Atlas Resource Partners

ARP enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s consolidated combined balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s consolidated combined balance sheets as the initial value of the options. The following table summarizes the gross fair values of ARP’s own derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s combined balance sheets for the periods indicated (in thousands):

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Combined Balance Sheets			Net Amount of Assets Presented in the Consolidated Combined Balance Sheets
Offsetting Derivative Assets
As of March 31, 2012
Current portion of derivative assets	$	26,579	$	(425	)	$	26,154
Long-term portion of derivative assets		24,714		(4,403	)		20,311
Total derivative assets	$	51,293	$	(4,828	)	$	46,465
As of December 31, 2011
Current portion of derivative assets	$	14,146	$	(345	)	$	13,801
Long-term portion of derivative assets		21,485		(5,357	)		16,128
Total derivative assets	$	35,631	$	(5,702	)	$	29,929

	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Combined Balance  Sheets		Net Amount of Liabilities Presented in the Consolidated Combined Balance Sheets
Offsetting Derivative Liabilities
As of March 31, 2012
Current portion of derivative liabilities	$	(425	)	$	425	$	—
Long-term portion of derivative liabilities		(4,403	)		4,403		—
Total derivative liabilities	$	(4,828	)	$	4,828	$	—
As of December 31, 2011
Current portion of derivative liabilities	$	(345	)	$	345	$	—
Long-term portion of derivative liabilities		(5,357	)		5,357		—
Total derivative liabilities	$	(5,702	)	$	5,702	$	—

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The following table summarizes ARP’s gain or loss recognized in the Partnership’s combined statements of operations for effective derivative instruments for the periods indicated (in thousands):

	Three Months Ended March 31,
	2012			2011
Gain recognized in accumulated OCI	$	14,169		$	442
Gain reclassified from accumulated OCI into income	$	(2,600	)	$	(7,731	)

ARP enters into commodities future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodities prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

In March 2012, ARP entered into contracts, which provides ARP with the option enter into swap contracts (“swaptions”) up through May 31, 2012 for production volumes related to wells acquired from Carrizo Oil & Gas, Inc. through acquisition (see Note 17). In connection with the swaption contracts, ARP paid a premium of $4.6 million, which represented the fair value of contracts on the date of the transaction and was recorded as a derivative asset on the Partnership’s consolidated combined balance sheet as of March 31, 2012. The premium will be amortized ratably over the term of the swaption. For the three months ended March 31, 2012, the Partnership recorded approximately $1.0 million of amortization expense in other, net on the Partnership’s consolidated combined statements of operations.

ARP recognized gains of $2.6 million and $7.7 million for the three months ended March 31, 2012 and 2011, respectively, on settled contracts covering commodity production. These gains are included within gas and oil production revenue in the Partnership’s consolidated combined statements of operations. As the underlying prices and terms in ARP’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three months ended March 31, 2012 and 2011 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

At March 31, 2012, ARP had the following commodity derivatives:

Natural Gas Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset/(Liability)
	(mmbtu)(1)		(per mmbtu)(1)		(in thousands)(2)
2012		5,490,000	$	4.477	$	10,761
2013		3,120,000	$	5.288		5,631
2014		3,960,000	$	5.121		4,541
2015		3,960,000	$	5.386		4,348
2016		1,080,000	$	4.383		(134	)
					$	25,147

Natural Gas Costless Collars

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Production Period Ending December 31,	Option Type	Volumes		Average Floor and  Cap		Fair Value Asset/(Liability)
		(mmbtu)(1)		(per mmbtu)(1)		(in thousands)(2)
2012	Puts purchased		3,240,000	$	4.074	$	5,194
2012	Calls sold		3,240,000	$	5.279		(29	)
2013	Puts purchased		5,520,000	$	4.395		6,354
2013	Calls sold		5,520,000	$	5.443		(570	)
2014	Puts purchased		3,840,000	$	4.221		2,970
2014	Calls sold		3,840,000	$	5.120		(1,099	)
2015	Puts purchased		3,840,000	$	4.296		2,801
2015	Calls sold		3,840,000	$	5.233		(1,631	)
						$	13,990

Natural Gas Put Options

Production Period Ending December 31,	Option Type	Volumes		Average Fixed  Price		Fair Value Asset
		(mmbtu)(1)		(per mmbtu)(1)		(in thousands)(3)
2012	Puts purchased		3,800,000	$	2.595	$	1,417
2013	Puts purchased		1,020,000	$	3.450		507
						$	1,924

Natural Gas Swaptions

Production Period Ending December 31,	Swaption Type	Volumes		Average Fixed Price		Fair Value Asset
		(mmbtu)(1)		(per mmbtu)(1)		(in thousands)(3)
2012	Swaptions purchased		4,680,000	$	2.850	$	1,758
2013	Swaptions purchased		8,040,000	$	3.550		1,771
2014	Swaptions purchased		6,840,000	$	4.000		1,192
2015	Swaptions purchased		3,000,000	$	4.250		409
2016	Swaptions purchased		2,760,000	$	4.500		378
						$	5,508

Crude Oil Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Liability
	(Bbl)(1)		(per Bbl)(1)		(in thousands)(3)
2012		15,750	$	103.986	$	(14	)
2013		15,000	$	100.570		(45	)
2014		36,000	$	97.693		(43	)
2015		36,000	$	93.973		(42	)
2016		33,000	$	92.082		(31	)
					$	(175	)

Crude Oil Costless Collars

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Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap		Fair Value Asset/(Liability)
		(Bbl)(1)		(per Bbl)(1)		(in thousands)(3)
2012	Puts purchased		45,000	$	90.000	$	115
2012	Calls sold		45,000	$	117.912		(125	)
2013	Puts purchased		60,000	$	90.000		414
2013	Calls sold		60,000	$	116.396		(398	)
2014	Puts purchased		24,000	$	80.000		160
2014	Calls sold		24,000	$	121.250		(144	)
2015	Puts purchased		24,000	$	80.000		210
2015	Calls sold		24,000	$	120.750		(161	)
						$	71
Total ARP net asset						$	46,465

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

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

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

Prior to its merger transaction with Chevron on February 17, 2011, AEI monetized all of its derivative instruments, including those related to the future natural gas and oil production of the Transferred Business (see Note 3). AEI also monetized derivative instruments which were specifically related to the future natural gas and oil production of the limited partners of the Drilling Partnerships. At March 31, 2012, remaining hedge monetization cash proceeds of $30.0 million related to the amounts hedged on behalf of the Drilling Partnerships’ limited partners were included within cash and cash equivalents, and ARP will allocate the monetization net proceeds to the Drilling Partnerships’ limited partners based on their natural gas and oil production generated over the period of the original derivative contracts. The derivative payable related to the hedge monetization proceeds at March 31, 2012 and December 31, 2011 were payable to the limited partners in the Drilling Partnerships and are included in the Partnership’s consolidated combined balance sheets as follows (in thousands):

	March 31, 2012			December 31, 2011
Current portion of derivative payable to Drilling Partnerships	$	(18,541	)	$	(20,900	)
Long-term portion of derivative payable to Drilling Partnerships		(11,499	)		(15,272	)
	$	(30,040	)	$	(36,172	)

On March 5, 2012, ARP entered into a secured hedge facility agreement with a syndicate of banks under which certain recently formed and future drilling partnerships will have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under its senior secured credit facility (see Note 8), ARP is required to utilize this secured hedge facility for future commodity risk management activity for its equity production volumes within the drilling partnerships. ARP, as general partner of the drilling partnerships, will administer the commodity price risk management activity for the investment partnerships under the secured hedge facility. The secured hedge facility agreement contains covenants that limit each of the participating investment partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets.

Atlas Pipeline Partners

For the three months ended March 31, 2012 and 2011, APL did not apply hedge accounting for derivatives. As such, changes in fair value of derivatives are recognized immediately within gain (loss) on mark-to-market derivatives on the Partnership’s consolidated combined statements of operations. The change in fair value of commodity-based derivative instruments entered into prior to the discontinuation of hedge accounting will be reclassified from within accumulated other comprehensive income on the Partnership’s consolidated combined balance sheets to gathering and processing revenue on the Partnership’s consolidated combined statements of operations at the time the originally hedged physical transactions settle.

The following table summarizes APL’s gross fair values of its derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s consolidated combined balance sheets for the periods indicated (in thousands):

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	Gross Amounts  of Recognized Assets		Gross Amounts Offset in the Consolidated Combined Balance Sheets			Net Amounts of Assets Presented in the Consolidated Combined Balance Sheets
Offsetting of Derivative Assets
As of March 31, 2012
Current portion of derivative assets	$	10,080	$	(10,080	)	$	—
Long-term portion of derivative assets		8,269		(3,469	)		4,800
Total derivative assets	$	18,349	$	(13,549	)	$	4,800
As of December 31, 2011
Current portion of derivative assets	$	11,603	$	(9,958	)	$	1,645
Long-term portion of derivative assets		17,011		(2,197	)		14,814
Total derivative assets	$	28,614	$	(12,155	)	$	16,459

	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Combined Balance Sheets		Net Amounts of Liabilities Presented in the Consolidated Combined Balance Sheets
Offsetting of Derivative Liabilities
As of March 31, 2012
Current portion of derivative liabilities	$	(11,722	)	$	10,080	$	(1,642	)
Long-term portion of derivative liabilities		(3,469	)		3,469		—
Total derivative liabilities	$	(15,191	)	$	13,549	$	(1,642	)
As of December 31, 2011
Current portion of derivative liabilities	$	(9,958	)	$	9,958	$	—
Long-term portion of derivative liabilities		(2,197	)		2,197		—
Total derivative liabilities	$	(12,155	)	$	12,155	$	—

As of March 31, 2012, APL had the following commodity derivatives:

Fixed Price Swaps

Production Period	Purchased/ Sold	Commodity	Volumes(2)		Average Fixed Price		Fair  Value(1) Asset/(Liability) (in thousands)
Natural Gas
2012	Sold	Natural Gas		3,420,000	$	3.019	$	1,736
NGLs
2012	Sold	Ethane		6,300,000	$	0.739		1,422
2012	Purchased	Ethane		6,300,000	$	0.710		(1,240	)
2012	Sold	Propane		14,868,000	$	1.280		175
2012	Sold	Normal Butane		3,906,000	$	1.712		(954	)
2012	Sold	Isobutane		2,142,000	$	1.584		(1,169	)
2012	Sold	Natural Gasoline		3,150,000	$	2.394		112
2013	Sold	Propane		41,328,000	$	1.281		(821	)
2013	Sold	Normal Butane		2,394,000	$	1.662		(597	)
2013	Sold	Isobutane		1,134,000	$	1.807		(305	)
Crude Oil
2012	Sold	Crude Oil		222,000	$	95.827		(1,912	)

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Production Period	Purchased/Sold	Commodity	Volumes(2)		Average Fixed Price		Fair Value(1) Asset/(Liability) (in thousands)
2013	Sold	Crude Oil		345,000	$	97.170		(2,291	)
2014	Sold	Crude Oil		60,000	$	98.425		(104	)
Total Fixed Price Swaps							$	(5,948	)

Options

Production Period	Purchased/ Sold	Type	Commodity	Volumes(2)		Average Strike Price		Fair  Value(1) Asset/(Liability) (in thousands)
NGLs
2012	Purchased	Put	Ethane		1,260,000	$	0.745	$	298
2012	Purchased	Put	Propane		22,176,000	$	1.361		2,987
2012	Purchased	Put	Normal Butane		5,166,000	$	1.552		132
2012	Purchased	Put	Isobutane		2,898,000	$	1.583		61
2012	Purchased	Put	Natural Gasoline		10,710,000	$	2.012		392
2013	Purchased	Put	Normal Butane		10,458,000	$	1.667		1,528
2013	Purchased	Put	Isobutane		4,158,000	$	1.687		579
2013	Purchased	Put	Natural Gasoline		23,940,000	$	2.108		4,083
Crude Oil
2012	Sold(3)	Call	Crude Oil		373,500	$	94.694		(4,926	)
2012	Purchased(3)	Call	Crude Oil		135,000	$	125.200		183
2012	Purchased	Put	Crude Oil		117,000	$	106.645		937
2013	Purchased	Put	Crude Oil		282,000	$	100.100		2,852
Total Options								$	9,106
Total APL net asset								$	3,158

⁽¹⁾  See Note 10 for discussion on fair value methodology.

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

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

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

	For the Three Months Ended March 31,
	2012			2011
Derivatives previously designated as cash flow hedges
Loss reclassified from accumulated other comprehensive loss into natural gas and liquids sales	$	(1,146	)	$	(1,702	)
Derivatives not designated as hedges
Loss recognized in derivative loss, net
Commodity contract - realized(1)		(763	)		(2,557	)
Commodity contract - unrealized(2)		(11,272	)		(19,088	)
Derivative loss, net	$	(12,035	)	$	(21,645	)

(1) Realized loss represents the loss incurred when the derivative contract expires and/or is cash settled.

(2) Unrealized loss represents the mark-to-market loss recognized on open derivative contracts, which have not yet been settled.

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

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	March 31, 2012			December 31, 2011
Current portion of derivative asset	$	26,154		$	15,447
Long-term derivative asset		25,111			30,941
Current portion of derivative liability		(1,642	)		—
Long-term derivative liability		—			—
Total Partnership net asset	$	49,623		$	46,388

NOTE 10 — FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership and its subsidiaries have established a hierarchy to measure their financial instruments at fair value which requires them to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect the Partnership and its subsidiaries own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1 - Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3 - Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

ARP and APL use a market approach fair value methodology to value the assets and liabilities for their outstanding derivative contracts (see Note 9). ARP and APL manage and report derivative assets and liabilities on the basis of their exposure to market risks and credit risks by counterparty. ARP’s and APL’s commodity derivative contracts, with the exception of APL’s NGL fixed price swaps and NGL options, are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing the NYMEX quoted prices for futures and options contracts traded on NYMEX that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument.

Valuations for APL’s NGL fixed price swaps are based on forward price curves provided by a third party, which is considered to be a Level 3 input. The prices for isobutene, normal butane and natural gasoline are adjusted based upon the relationship between the prices for the product/locations quoted by the third party and the underlying product/locations utilized for the swap contracts, as determined by a regression model of the historical settlement prices for the different product/locations. The regression model is recalculated on a quarterly basis. This adjustment is an unobservable Level 3 input. The NGL fixed price swaps are over the counter instruments which are not actively traded in an open market. However, the prices for the underlying products and locations do have a direct correlation to the prices for the products and locations provided by the third party, which are based upon trading activity for the products and locations quoted. Valuations for APL’s NGL options are based on forward price curves developed by financial institutions, and therefore are defined as Level 3. The NGL options are over the counter instruments that are not actively traded in an open market, thus APL utilizes the valuations provided by the financial institutions that provide the NGL options for trade.

Information for ARP’s and APL’s assets and liabilities measured at fair value at March 31, 2012 and December 31, 2011 was as follows (in thousands):

	Level 1		Level 2		Level 3		Total
As of March 31, 2012
Derivative assets, gross
ARP Commodity swaps		—	$	25,643	$	—	$	25,643
ARP Commodity options		—		20,142		—		20,142
ARP Commodity swaptions		—		5,508		—		5,508
APL Commodity swaps		—		2,200		2,117		4,317
APL Commodity options		—		3,972		10,060		14,032

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	Level 1		Level 2			Level 3			Total
Total derivative assets, gross		—		57,465			12,177			69,642
Derivative liabilities, gross
ARP Commodity swaps		—		(671	)		—			(671	)
ARP Commodity options		—		(4,157	)		—			(4,157	)
ARP Commodity swaptions		—		—			—			—
APL Commodity swaps		—		(4,771	)		(5,494	)		(10,265	)
APL Commodity options		—		(4,926	)		—			(4,926	)
Total derivative liabilities, gross		—		(14,525	)		(5,494	)		(20,019	)
Total derivatives, fair value, net	$	—	$	42,940		$	6,683		$	49,623
As of December 31, 2011
Derivative assets, gross
ARP Commodity swaps	$	—	$	20,908		$	—		$	20,908
ARP Commodity options		—		14,723			—			14,723
ARP Commodity swaptions		—		—			—			—
APL Commodity swaps		—		1,270			1,836			3,106
APL Commodity options		—		7,229			18,279			25,508
Total derivative assets, gross		—		44,130			20,115			64,245
Derivative liabilities, gross
ARP Commodity swaps		—		—			—			—
ARP Commodity options		—		(5,702	)		—			(5,702	)
ARP Commodity swaptions		—		—			—			—
APL Commodity swaps		—		(2,766	)		(3,569	)		(6,335	)
APL Commodity options		—		(5,820	)		—			(5,820	)
Total derivative liabilities, gross		—		(14,288	)		(3,569	)		(17,857	)
Total derivatives, fair value, net	$	—	$	29,842		$	16,546		$	46,388

APL’s Level 3 fair value amounts 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 three months ended March 31, 2012 (in thousands):

	NGL Fixed Price Swaps						NGL Put Options						Total
	Volume(1)			Amount			Volume(1)			Amount			Amount
Balance - January 1, 2012		49,644		$	(1,733	)		92,610		$	18,279		$	16,546
New contracts(2)		42,084			—			—			—			—
Cash settlements from unrealized gain (loss)(3)(4)		(10,206	)		(1,032	)		(11,844	)		696			(336	)
Net change in unrealized loss(3)		—			(612	)		—			(6,529	)		(7,141	)
Option premium recognition(4)		—			—			—			(2,386	)		(2,386	)
Balance - March 31, 2012		81,522		$	(3,377	)		80,766		$	10,060		$	6,683

⁽¹⁾  Volumes are stated in thousand gallons.

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

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

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

The following table provides a summary of the unobservable inputs used in the fair value measurement of APL’s NGL fixed price swaps at March 31, 2012 and December 31, 2011 (in thousands):

	Gallons		Third  Party Quotes(1)			Adjustments(2)		Total Amount(3)
As of March 31, 2012
Ethane swaps		12,600	$	182		$	—	$	182
Propane swaps		56,196		(646	)		—		(646	)
Isobutane swaps		3,276		(2,188	)		714		(1,474	)
Normal butane swaps		6,300		(1,917	)		366		(1,551	)

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	Gallons		Third Party Quotes(1)			Adjustments(2)			Total Amount(3)
Natural gasoline swaps		3,150		216			(104	)		112
Total NGL swaps - March 31, 2012		81,522	$	(4,353	)	$	976		$	(3,377	)
As of December 31, 2011
Ethane swaps		6,678	$	31		$	—		$	31
Propane swaps		29,358		(1,322	)		—			(1,322	)
Isobutane swaps		2,646		(1,590	)		570			(1,020	)
Normal butane swaps		6,804		(1,074	)		343			(731	)
Natural gasoline swaps		4,158		1,824			(515	)		1,309
Total NGL swaps - December 31, 2011		49,644	$	(2,131	)	$	398		$	(1,733	)

(1) Based upon the difference between the quoted market price provided by the third party and the fixed price of the swap.

(2) Based upon the price adjustment to the price provided by the third party to adjust for product and location differentials. The adjustment is calculated through a regression model comparing settlement prices of the different products and locations over a three year historical period.

The following table provides a summary of the regression coefficient utilized in the calculation of the unobservable inputs for the Level 3 fair value measurements for APL’s NGL swaps for the periods indicated (in thousands):

				Adjustment based upon Regression Coefficient
	Level 3 Fair Value Adjustments			Lower 95%		Upper 95%		Average Coefficient
As of March 31, 2012
Isobutane swaps	$	714			1.1192		1.1285		1.1239
Normal butane swaps		366			1.0312		1.0354		1.0333
Natural gasoline swaps		(104	)		0.9831		0.9859		0.9845
Total NGL swaps - March 31, 2012	$	976
As of December 31, 2011
Isobutane swaps	$	570			1.1239		1.1333		1.1286
Normal butane swaps		343			1.0311		1.0355		1.0333
Natural gasoline swaps		(515	)		0.9351		0.9426		0.9389
Total NGL swaps - December 31, 2011	$	398

Other Financial Instruments

The estimated fair value of the Partnership and its subsidiaries’ 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 and its subsisidaries could realize upon the sale or refinancing of such financial instruments.

The Partnership and its subsidiaries’ other current assets and liabilities on its consolidated combined balance sheets are financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1. The estimated fair values of the Partnership and its subsidiaries’ debt at March 31, 2012 and December 31, 2011, which consist principally of APL’s Senior Notes and borrowings under ARP’s and APL’s revolving credit facilities, were $647.3 million and $537.3 million, respectively, compared with the carrying amounts of $630.3 million and $524.1 million, respectively. The carrying value of outstanding borrowings under the respective credit facilities, which bear interest at a variable interest rate, approximates their estimated fair value and thus are categorized as Level 1. The fair value of the APL Senior Notes is provided by financial institutions based on its recent trading activity and is therefore categorized as Level 3.

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

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ARP estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of ARP and estimated inflation rates (see Note 7). Information for assets that were measured at fair value on a nonrecurring basis for the three months ended March 31, 2012 and 2011 were as follows (in thousands):

	Three Months Ended March 31,
	2012				2011
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	181	$	181	$	93	$	93
Total	$	181	$	181	$	93	$	93

ARP and APL estimate the fair value of their long-lived assets by reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances. For the year ended December 31, 2011, ARP recognized a $7.0 million impairment of long-lived assets, which was defined as a Level 3 fair value measurement (see Note 2 - Impairment of Long-Lived Assets). No impairments were recognized for the three months ended March 31, 2012 and 2011 (see Note 5).

NOTE 11 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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

NOTE 12 — COMMITMENTS AND CONTINGENCIES

General Commitments

ARP is the managing general partner of the Drilling Partnerships, and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. Subject to certain conditions, investor partners in certain Drilling Partnerships have the right to present their interests for purchase by ARP, as managing general partner. ARP is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on its historical experience, the management of ARP believes that any liability incurred would not be material. Also, ARP has agreed to subordinate a portion of its share of net partnership revenues from the Drilling Partnerships to the benefit of the investor partners until they have received specified returns, typically 10% per year determined on a cumulative basis, over a specific period, typically the first five to seven years, in accordance with the terms of the partnership agreements. For the three months ended March 31, 2012 and 2011, $0.4 million and $1.4 million, respectively, of ARP’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the Drilling Partnerships.

Immediately following the acquisition of the Transferred Business, the Partnership received from Chevron $118.7 million related to a contractual cash transaction adjustment related to certain liabilities of the Transferred Business at February 17, 2011. Following the closing of the acquisition of the Transferred Business, the Partnership entered into a reconciliation process with Chevron to determine the final cash adjustment amount pursuant to the transaction agreement. The reconciliation process was assumed by ARP on March 5, 2012 and remains ongoing at March 31, 2012, as certain amounts included within the contractual cash transaction adjustment are in dispute between the parties. ARP believes the amounts included within the contractual cash transaction adjustment are appropriate and is currently engaged in an on-going reconciliation process with Chevron. The resolution of the disputed amounts could result in ARP being required to repay a portion of the cash transaction adjustment (see Note 3). According to the transaction agreement, should ARP and Chevron not be able to come to an agreement during the reconciliation process, the two parties will enter into arbitration with a neutral public accounting firm. At March 31, 2012, the Partnership believes the range of loss associated with the disputed balances is between zero and $45.0 million.

33

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

As of March 31, 2012, ARP and APL are committed to expend approximately $70.0 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

Legal Proceedings

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

NOTE 13 — ISSUANCES OF UNITS

The Partnership recognizes gains on ARP’s and APL’s equity transactions as credits to partners’ capital on its consolidated combined balance sheets rather than as income on its consolidated combined statements of operations. These gains represent the Partnership’s portion of the excess net offering price per unit of each of ARP’s and APL’s common units over the book carrying amount per unit.

In February 2011, the Partnership paid $30.0 million in cash and issued approximately 23.4 million newly issued common limited partner units for the Transferred Business acquired from AEI. Based on the Partnership’s common limited partner unit’s February 17, 2011 closing price on the NYSE, the common units issued to AEI were valued approximately at $372.2 million (see Note 3).

Atlas Resource Partners

In February 2012, the Board approved the distribution of approximately 5.24 million ARP common units which were distributed on March 13, 2012 to Atlas Energy’s unitholders using a ratio of 0.1021 ARP limited partner units for each Atlas Energy common unit owned on the record date of February 28, 2012. The distribution of ARP’s limited partner units represented approximately 19.6% of its outstanding limited partner interests. Subsequent to the distribution, the Partnership owned 100% of the general partner Class A units and incentive distribution rights through which it manages and effectively controls ARP, and common units representing an approximate 78.4% limited partner interest in ARP.

Atlas Pipeline Partners

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

NOTE 14 — 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, 2011 through March 31, 2012 were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid	For Quarter Ended	Cash Distribution per Common Limited Partner Unit		Total Cash Distributions Paid to Common Limited Partner
May 20, 2011	March 31, 2011	$	0.11	$	5,635
August 19, 2011	June 30, 2011	$	0.22	$	11,276
November 18, 2011	September 30, 2011	$	0.24	$	12,303
February 17, 2012	December 31, 2011	$	0.24	$	12,307

On April 26, 2012, the Partnership declared a cash distribution of $0.25 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2012. The $12.8 million distribution will be paid on May 18, 2012 to unitholders of record at the close of business on May 8, 2012.

34

ARP Cash Distributions. ARP has a cash distribution policy under which it distributes, within 45 days following the end of each calendar quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders and general partner. If ARP’s common unit distributions in any quarter exceed specified target levels, the Partnership will receive between 13% and 48% of such distributions in excess of the specified target levels. On April 17, 2012, ARP declared a prorated cash distribution of $0.12 per unit on its outstanding common limited partner units, representing the cash distribution for the partial quarter beginning on March 5, 2012 and ended on March 31, 2012. The $3.2 million distribution will be paid on May 15, 2012 to unitholders of record at the close of business on April 27, 2012.

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, 2011 through March 31, 2012 were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid	For Quarter Ended	APL Cash Distribution per Common Limited Partner Unit		Total APL  Cash Distribution to Common Limited Partners		Total APL  Cash Distribution to the General Partner
May 13, 2011	March 31, 2011	$	0.40	$	21,400	$	2,730
August 12, 2011	June 30, 2011	$	0.47	$	25,184	$	3,687
November 14, 2011	September 30, 2011	$	0.54	$	28,953	$	4,946
February 14, 2012	December 31, 2011	$	0.55	$	29,489	$	5,195

On April 25, 2012, APL declared a cash distribution of $0.56 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2012. The $32.2 million distribution, including $5.4 million to the Partnership, will be paid on May 15, 2012 to unitholders of record at the close of business on May 8, 2012.

NOTE 15 — BENEFIT PLANS

2010 Long-Term Incentive Plan

The Board of Directors of the General Partner approved and adopted the Partnership’s 2010 Long-Term Incentive Plan (“2010 LTIP”) effective February 2011. The 2010 LTIP provides equity incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for the Partnership. The 2010 LTIP is administered by a committee consisting of the Board or committee of the Board or board of an affiliate appointed by the Board (the “LTIP Committee”), which is the Compensation Committee of the General Partner’s board of directors. Under the 2010 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 5,763,781 common limited partner units. At March 31, 2012, the Partnership had 4,633,028 phantom units and unit options outstanding under the 2010 LTIP, with 1,123,527 phantom units and unit options available for grant.

Upon a change in control, as defined in the 2010 LTIP, all unvested awards held by directors will immediately vest in full. In the case of awards held by eligible employees, upon the eligible employee’s termination of employment without “cause”, as defined in the 2010 LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), in any case following a change in control, any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option.

In connection with a change in control, the committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which our general partner (or any affiliate) and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason):

• cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity);

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• accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to our common units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction;

• provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards);

• terminate all or some awards upon the consummation of the change-in-control transaction, but only if the committee provides for full vesting of awards immediately prior to the consummation of such transaction; and

• make such other modifications, adjustments or amendments to outstanding awards or the new equity plan as the committee deems necessary or appropriate.

2010 Phantom Units. A phantom unit entitles a Participant to receive a Partnership common unit upon vesting of the phantom unit. In tandem with phantom unit grants, the LTIP Committee may grant Participant Distribution Equivalent Rights (“DERs”), which are the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions the Partnership makes on a common unit during the period such phantom unit is outstanding. Through March 31, 2012, phantom units granted under the 2010 LTIP generally will vest 25% on the third anniversary of the date of grant and the remaining 75% on the fourth anniversary of the date of grant. Of the phantom units outstanding under the 2010 LTIP at March 31, 2012, there are 4,078 units that will vest within the following twelve months. All phantom units outstanding under the 2010 LTIP at March 31, 2012 include DERs granted to the Participants by the LTIP Committee. During the three months ended March 31, 2012, the Partnership paid $0.4 million with respect to the 2010 LTIP DERs. There were no amounts paid with respect to the 2010 LTIP DERs for the three months ended March 31, 2011.

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

	Three Months Ended March 31,
	2012					2011
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units		Weighted Average Grant Date Fair Value
Outstanding, beginning of year		1,838,164		$	22.11		—	$	—
Granted		55,300			26.66		1,566,000		22.23
Vested (1)		(7,226	)		20.67		—		—
Forfeited		—			—		—		—
ARP Anti-Dilution Adjustment(2)		165,468			—		—		—
Outstanding, end of period(3)		2,051,706		$	20.46		1,566,000	$	22.23
Non-cash compensation expense recognized (in thousands)				$	3,002			$	176

(1) The aggregate intrinsic value of phantom unit awards vested during the three months ended March 31, 2012 was $0.2 million. No phantom unit awards vested during the three months ended March 31, 2011.

(2) The number of 2010 phantom units was adjusted concurrently with the distribution of ARP common units.

(3) The aggregate intrinsic value of phantom unit awards outstanding at March 31, 2012 was $67.7 million.

At March 31, 2012, the Partnership had approximately $31.4 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2010 LTIP based upon the fair value of the awards.

2010 Unit Options. A unit option entitles a Participant to receive a common unit of the Partnership upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option is equal to the fair market value of the Partnership’s common unit on the date of grant of the option. The LTIP Committee also shall determine how the exercise price may be paid by the Participant. The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through March 31, 2012, unit options granted under the 2010 LTIP generally will vest 25% of the original granted amount three years from the date of grant and the remaining 75% of the original granted amount four years from the date of grant. Awards will automatically

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vest upon a change of control of the Partnership, as defined in the 2010 LTIP. There are 3,399 unit options outstanding under the 2010 LTIP at March 31, 2012 that will vest within the following twelve months.

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

	Three Months Ended March 31,
	2012				2011
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of year		2,304,300	$	22.12		—	$	—
Granted		69,229		26.27		2,226,000		22.23
Forfeited		—		—		—		—
ARP Anti-Dilution Adjustment(1)		207,793		—		—		—
Outstanding, end of period(2)(3)		2,581,322	$	20.45		2,226,000	$	22.23
Options exercisable, end of period(4)		—	$	—		—	$	—
Non-cash compensation expense recognized (in thousands)			$	1,561			$	112

⁽¹⁾ The number of 2010 unit options and exercise price was adjusted concurrently with the distribution of ARP common units.

⁽²⁾ The weighted average remaining contractual life for outstanding options at March 31, 2012 was 9.0 years.

⁽³⁾ The options outstanding at March 31, 2012 had an aggregate intrinsic value of $32.3 million.

⁽⁴⁾ No options were exercisable at March 31, 2012 or 2011. No options vested during the three months ended March 31, 2012 and 2011.

At March 31, 2012, the Partnership had approximately $17.0 million in unrecognized compensation expense related to unvested unit options outstanding under the 2010 LTIP based upon the fair value of the awards. The Partnership used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the periods indicated:

	Three Months Ended March 31,
	2012			2011
Expected dividend yield		3.7	%		1.5	%
Expected unit price volatility		47.0	%		48.0	%
Risk-free interest rate		1.4	%		2.8	%
Expected term (in years)		6.88			6.88
Fair value of unit options granted	$	8.50		$	9.93

2006 Long-Term Incentive Plan

The Board of Directors of the General Partner approved and adopted the Partnership’s 2006 Long-Term Incentive Plan (“2006 LTIP”), which provides equity incentive awards to Participants who perform services for the Partnership. The 2006 LTIP is administered by the LTIP Committee. The LTIP Committee may grant such awards of either phantom units or unit options for an aggregate of 2,261,516 common limited partner units. At March 31, 2012, the Partnership had 1,003,552 phantom units and unit options outstanding under the 2006 LTIP, with 995,399 phantom units and unit options available for grant. Share based payments to non-employees, which have a cash settlement option, are recognized within liabilities in the financial statements based upon their current fair market value.

2006 Phantom Units. Through March 31, 2012, phantom units granted under the 2006 LTIP generally will vest 25% of the original granted amount three years from the date of grant and the remaining 75% of the original granted amount four years from the date of grant. Awards will automatically vest upon a change of control of the Partnership, as defined in the 2006 LTIP. Of the phantom units outstanding under the 2006 LTIP at March 31, 2012, 9,359 units will vest within the following twelve months. All phantom units outstanding under the 2006 LTIP at March 31, 2012 include DERs granted to the Participants by the LTIP Committee. During the three months ended March 31, 2012 and 2011, respectively, the Partnership paid $8,000 and $1,000 with respect to 2006 LTIP’s DERs. This amount was recorded as a reduction of partners’ capital on the Partnership’s consolidated combined balance sheet.

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The following table sets forth the 2006 LTIP phantom unit activity for the periods indicated:

	Three Months Ended March 31,
	2012					2011
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		32,641		$	15.99		27,294		$	5.98
Granted		7,688			26.01		13,395			15.92
Vested (1)		(6,253	)		24.06		(9,664	)		13.75
Forfeited		—			—		—			—
ARP anti-dilution adjustment(2)		2,977			—		—			—
Outstanding, end of period(3)(4)		37,053		$	15.42		31,025		$	7.85
Non-cash compensation expense recognized (in thousands)				$	167				$	185

(1) The intrinsic values for phantom unit awards vested during the three months ended March 31, 2012 and 2011 were $0.2 million and $0.2 million, respectively.

(2) The number of 2006 phantom units was adjusted concurrently with the distribution of ARP common units.

(3) The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2012 was $1.2 million.

(4) There were 30,528 units at March 31, 2012 classified under accrued liabilities on the Partnership’s consolidated combined balance sheets of $0.9 million due to the option of the participant to settle in cash instead of units. No units were classified under accrued liabilities at December 31, 2011. The respective weighted average grant date fair value for these units is $17.45 as of March 31, 2012.

At March 31, 2012, the Partnership had approximately $0.7 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2006 LTIP based upon the fair value of the awards.

2006 Unit Options. The exercise price of the unit option may be equal to or more than the fair market value of the Partnership’s common unit on the date of grant of the option. Unit option awards expire 10 years from the date of grant. Through March 31, 2012, unit options granted under the 2006 LTIP generally will vest 25% on the third anniversary of the date of grant and the remaining 75% on the fourth anniversary of the date of grant. Awards will automatically vest upon a change of control of the Partnership, as defined in the 2006 LTIP. There are no unit options outstanding under the 2006 LTIP at March 31, 2012 that will vest within the following twelve months. For the three months ended March 31, 2012, the Partnership received cash of $32,000 from the exercise of options.

The following table sets forth the 2006 LTIP unit option activity for the periods indicated:

	Three Months Ended March 31,
	2012					2011
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of year		903,614		$	21.52		955,000	$	20.54
Granted		—			—		—		—
Exercised(1)		(15,438	)		3.24		—		—
Forfeited		—			—		—		—
ARP anti-dilution adjustment(2)		78,323			—		—		—
Outstanding, end of period(3)(4)		966,499		$	20.08		955,000	$	20.54
Options exercisable, end of period(5)		966,499		$	20.08		955,000	$	20.54
Non-cash compensation expense recognized (in thousands)				$	—			$	28

⁽¹⁾ The intrinsic value of options exercised during the three months ended March 31, 2012 was $0.4 million. No options were exercised during the three months ended March 31, 2011.

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⁽²⁾ The number of 2006 unit options and exercise price was adjusted concurrently with the distribution of ARP common units.

⁽³⁾ The weighted average remaining contractual life for outstanding options at March 31, 2012 was 4.7 years.

⁽⁴⁾ The aggregate intrinsic value of options outstanding at March 31, 2012 was approximately $12.5 million.

⁽⁵⁾ The weighted average remaining contractual life for options exercisable at March 31, 2012 was 4.7 years.

At March 31, 2012, the Partnership had no unrecognized compensation expense related to unvested unit options outstanding under the 2006 LTIP based upon the fair value of the awards. The Partnership uses the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. No options were granted during the three months ended March 31, 2012 and 2011 under the 2006 Plan.

The transfer of assets to ARP on March 5, 2012 and the subsequent distribution of ARP common units on March 13, 2012 resulted in an adjustment to the Partnership’s 2010 and 2006 long-term incentive plans. Concurrent with the distribution of ARP common units, the number of the phantom units, restricted units and options in the plans were increased in an amount equivalent to the percentage change in the Partnership’s publicly traded unit price from the closing price on March 13, 2012 to the opening price on March 14, 2012. In addition, the strike price of unit option awards was decreased by the same percentage change.

ARP Long-Term Incentive Plan

On March 12, 2012, the Partnership, as the sole limited partner of ARP, and the Board of Directors (the “Board”) of Atlas Resource Partners GP, LLC, the general partner of ARP (“ARP GP”), approved the 2012 Atlas Resource Partners Long-Term Incentive Plan (the “ARP LTIP”). Awards of options to purchase units, restricted units and phantom units may be granted to officers, employees and directors of ARP GP (collectively, the “Participants”) under the ARP LTIP, and such awards may be subject to vesting terms and conditions in the discretion of the administrator of the ARP LTIP. Up to 2,900,000 common units of ARP, subject to adjustment as provided for under the ARP LTIP, may be issued pursuant to awards granted under the ARP LTIP. The ARP LTIP is administered by the Board, a committee of the Board or the board (or committee of the board) of an affiliate (the “LTIP Committee”), which is the Compensation Committee of the General Partner’s board of directors. At March 31, 2012, ARP had no phantom units, restricted units and unit options outstanding under the ARP LTIP, with 2,900,000 phantom units, restricted units and unit options available for grant.

Upon a change in control, as defined in the ARP LTIP, all unvested awards held by directors will immediately vest in full. In the case of awards held by eligible employees, upon the eligible employee’s termination of employment without “cause”, as defined in the ARP LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), in any case following a change in control, any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option.

In connection with a change in control, the committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which our general partner (or any affiliate) and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason):

• cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity);

• accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to our common units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction;

• provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards);

• terminate all or some awards upon the consummation of the change-in-control transaction, but only if the committee provides for full vesting of awards immediately prior to the consummation of such transaction; and

• make such other modifications, adjustments or amendments to outstanding awards or the new equity plan as the committee deems necessary or appropriate.

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APL Long-Term Incentive Plans

APL has a 2004 Long-Term Incentive Plan (“APL 2004 LTIP”), and a 2010 Long-Term Incentive Plan, which was modified on April 26, 2011 (“APL 2010 LTIP” and collectively with the APL 2004 LTIP, the “APL LTIPs”), in which officers, employees and non-employee managing board members of APL’s general partner and employees of APL’s general partner’s affiliates and consultants are eligible to participate. The APL LTIPs are administered by a committee (the “APL LTIP Committee”) appointed by APL’s general partner. Under the 2010 APL LTIP, the APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 3,000,000 common units, in addition to the 435,000 common units authorized in previous plans. At March 31, 2012, APL had 390,567 phantom units outstanding under the APL LTIPs, with 2,360,147 phantom units and unit options available for grant. APL generally issues new common units for phantom units and unit options, which have vested and have been exercised. Share based payments to non-employees, which have a cash settlement option, are recognized within liabilities in the consolidated combined financial statements based upon their current fair market value.

APL Phantom Units. Through March 31, 2012, phantom units granted under the APL LTIPs generally had vesting periods of four years. In conjunction with the approval of the 2010 LTIP, the holders of 300,000 of the 375,000 equity indexed bonus units (“APL Bonus Units”) under APL’s subsidiary’s plan discussed below agreed to exchange their APL Bonus Units for an equivalent number of phantom units, effective as of June 1, 2010. These phantom units will vest over a two year period. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards may automatically vest upon a change of control, as defined in the APL LTIPs. Of the units outstanding under the APL LTIPs at March 31, 2012, 171,534 units will vest within the following twelve months. APL is authorized to repurchase common units to cover employee-related taxes on certain phantom units, when they have vested. On February 17, 2011, the employment agreement with APL’s Chief Executive Officer (“CEO”) was terminated in connection with AEI’s merger with Chevron and 75,250 outstanding phantom units, which represents all outstanding phantom units held by APL’s CEO, automatically vested and were issued.

All phantom units outstanding under the APL LTIPs at March 31, 2012 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL LTIP DERs were $0.2 million for the three months ended March 31, 2012 and 2011. These amounts were recorded as reductions of non-controlling interest on the Partnership’s consolidated combined balance sheet.

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

	Three Months Ended March 31,
	2012					2011
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of period		394,489		$	21.63		490,886		$	11.75
Granted		4,132			36.29		5,730			30.63
Vested and issued(1)		(8,054	)		39.78		(81,900	)		13.60
Outstanding, end of period(2)(3)		390,567		$	21.41		414,716		$	11.65
Matured and not issued(4)		4,125		$	44.51		4,500		$	44.51
Non-cash compensation expense recognized (in thousands)				$	978				$	1,174

(1) The intrinsic values for phantom unit awards vested and issued during the three months ended March 31, 2012 and 2011 were $0.3 million and $2.4 million, respectively.

(2) The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2012 and 2011 was $13.8 million and $14.3 million, respectively.

(3) There were 16,692 and 12,902 outstanding phantom unit awards at March 31, 2012 and December 31, 2011, respectively, which were classified as liabilities due to a cash option available on the related phantom unit awards.

(4) The aggregate intrinsic value for phantom unit awards vested but not issued at both March 31, 2012 and 2011 was $0.2 million.

At March 31, 2012, APL had approximately $4.5 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIPs based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 2.1 years.

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APL Unit Options. The exercise price of the unit option is equal to the fair market value of APL’s common unit on the date of grant of the option. The APL LTIP Committee also shall determine how the exercise price may be paid by the Participant. The APL LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through March 31, 2012, unit options granted under the APL LTIPs generally will vest 25% on each of the next four anniversaries of the date of grant. Awards will automatically vest upon a change of control of APL, as defined in the APL LTIPs. On February 17, 2011, the employment agreement with the CEO of APL’s General Partner was terminated in connection with AEI’s merger with Chevron, and 50,000 outstanding unit options held by the CEO automatically vested. As of March 31, 2012, all unit options were exercised. There are no unit options outstanding under APL LTIPs at March 31, 2012 that will vest within the following twelve months.

The following table sets forth the APL LTIPs’ unit option activity for the periods indicated:

	Three Months Ended March 31,
	2012				2011
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of period		—	$	—		75,000		$	6.24
Exercised(1)(2)		—		—		(75,000	)		6.24
Outstanding, end of period(2)		—	$	—		—		$	—
Non-cash compensation expense recognized (in thousands)(3)			$	—				$	3

(1) The intrinsic value for the options exercised during the three months ended March 31, 2011, was $1.8 million. Approximately $0.5 million was received from the exercise of unit option awards during the three months ended March 31, 2011.

At March 31, 2012, APL had no unrecognized compensation expense related to unvested unit options outstanding under APL’s LTIPs based upon the fair value of the awards.

APL uses the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. No options were granted during the three months ended March 31, 2012 and 2011 under the APL LTIPs.

APL Employee Incentive Compensation Plan and Agreement

At March 31, 2012, a wholly-owned subsidiary of APL had an incentive plan (the “Cash Plan”), which allows for equity-indexed cash incentive awards to employees of APL (the “Participants”). The Cash Plan is administered by a committee appointed by the CEO of APL’s General Partner. Under the Cash Plan, cash bonus units may be awarded to Participants at the discretion of the committee. An APL Bonus Unit entitles the employee to receive the cash equivalent of the then-fair market value of a common limited partner unit, without payment of an exercise price, upon vesting of the APL Bonus Unit. APL Bonus Units vest ratably over a three year period from the date of grant and will automatically vest upon a change of control, death, or termination without cause, each as defined in the governing document. Vesting will terminate upon termination of employment with cause.

At March 31, 2012, APL had 25,500 outstanding APL Bonus Units, which will all vest within the following twelve months. APL recognizes compensation expense related to these awards based upon the fair value, which is re-measured each reporting period based upon the current fair value of the underlying common units. APL recognized compensation expense related to the re-measurement of the outstanding Bonus Units of $0.5 million during the three months ended March 31, 2011, which was recorded within general and administrative expense on the Partnership’s consolidated combined statements of operations. APL had $0.8 million at March 31, 2012 and December 31, 2011 included within accrued liabilities on the Partnership’s consolidated combined balance sheet with regard to these awards, which represents their fair value as of those dates.

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NOTE 16 — OPERATING SEGMENT INFORMATION

The Partnership’s operations include four reportable operating segments. These operating segments reflect the way the Partnership manages its operations and makes business decisions. Operating segment data for the periods indicated are as follows (in thousands):

	Three Months Ended March 31,
	2012			2011
Gas and oil production:
Revenues	$	17,164		$	17,626
Operating costs and expenses		(4,505	)		(3,921	)
Depreciation, depletion and amortization expense		(7,567	)		(6,566	)
Segment income	$	5,092		$	7,139
Well construction and completion:
Revenues	$	43,719		$	17,725
Operating costs and expenses		(37,695	)		(15,021	)
Segment income	$	6,024		$	2,704
Other partnership management:(1)
Revenues	$	10,608		$	12,249
Operating costs and expenses		(7,104	)		(8,094	)
Depreciation, depletion and amortization expense		(1,541	)		(1,135	)
Segment income	$	1,963		$	3,020
Atlas Pipeline:
Revenues	$	293,215		$	257,324
Operating costs and expenses		(247,250	)		(231,250	)
Depreciation and amortization expense		(20,842	)		(18,906	)
Segment income	$	25,123		$	7,168
Reconciliation of segment income to net income (loss) from continuing operations:
Segment income:
Gas and oil production	$	5,092		$	7,139
Well construction and completion		6,024			2,704
Other partnership management		1,963			3,020
Atlas Pipeline		25,123			7,168
Total segment income		38,202			20,031
General and administrative expenses(2)		(37,248	)		(16,190	)
Gain (loss) on asset disposal(2)		(7,005	)		255,947
Interest expense(2)		(9,091	)		(18,078	)
Net income (loss) from continuing operations	$	(15,142	)	$	241,710
Capital expenditures:
Gas and oil production	$	17,166		$	4,738
Other partnership management		327			1,152
Atlas Pipeline		81,167			18,333
Corporate and other		1,465			1,842
Total capital expenditures	$	100,125		$	26,065

	March 31, 2012		December 31, 2011
Balance sheet:
Goodwill:
Gas and oil production	$	18,145	$	18,145
Well construction and completion		6,389		6,389

42

Other partnership management		7,250		7,250
Atlas Pipeline		—		—
	$	31,784	$	31,784
Total assets:
Gas and oil production	$	571,742	$	593,320
Well construction and completion		6,957		6,987
Other partnership management		44,956		45,991
Atlas Pipeline		1,977,817		1,930,813
Corporate and other		79,949		107,660
	$	2,681,421	$	2,684,771

⁽¹⁾  Includes revenues and expenses from well services, gathering and processing, administration and oversight, and other that do not meet the quantitative threshold for reporting segment information.

⁽²⁾  The Partnership notes that interest expense, gain (loss) on asset disposal and general and administrative expenses have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.

NOTE 17 — SUBSEQUENT EVENTS

Partnership Cash Distribution. On April 26, 2012, the Partnership declared a cash distribution of $0.25 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2012. The $12.8 million distribution will be paid on May 18, 2012 to unitholders of record at the close of business on May 8, 2012.

ARP Cash Distribution. On April 17, 2012, ARP declared a prorated cash distribution of $0.12 per unit on its outstanding common limited partner units, representing the cash distribution for the partial quarter beginning on March 5, 2012 and ended on March 31, 2012. The $3.2 million distribution will be paid on May 15, 2012 to unitholders of record at the close of business on April 27, 2012.

APL Cash Distribution. On April 25, 2012, APL declared a cash distribution of $0.56 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2012. The $32.2 million distribution, including $5.4 million to the Partnership, will be paid on May 15, 2012 to unitholders of record at the close of business on May 8, 2012.

ARP’s Joint Venture Agreement with Subsidiaries of Equal Energy, Ltd. On April 26, 2012, ARP acquired a 50% interest in approximately 14,500 net undeveloped acres in the oil and natural gas liquids area of the Mississippi Lime play in northwestern Oklahoma for $18.0 million from subsidiaries of Equal Energy, Ltd. (“Equal”) (NYSE: EQU; TSX: EQU). The transaction was funded through borrowings under ARP’s revolving credit facility.

ARP’s Acquisition of Assets from Carrizo Oil & Gas, Inc. On April 30, 2012, ARP acquired certain assets from Carrizo Oil & Gas, Inc. (NASDAQ: CRZO; “Carrizo”) for $190 million in cash. The assets acquired include interests in approximately 200 producing natural gas wells from the Barnett Shale, located in Bend Arch-Fort Worth Basin in North Texas, proved undeveloped acres also in the Barnett Shale and gathering pipelines and associated gathering facilities that service certain of the acquired wells. The purchase price is subject to certain post-closing adjustments based on, among other things, environmental and title defects, if any.

To partially fund the acquisition of assets from Carrizo, ARP executed a unit purchase agreement with several purchasers for the sale of 6.0 million of its common units at a negotiated purchase price per unit of $20.00, for gross proceeds of $120.6 million, of which $5.0 million was purchased by certain executives of the Partnership. The common units were issued and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.

In connection with its acquisition of certain assets from Carrizo, ARP also amended its credit facility to, among other items, increase the borrowing base to $250.0 million and the maximum lender commitment to $500.0 million, which was contingent upon the closing of the acquisition of assets from Carrizo.

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ITEM 2: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

When used in this Form 10-Q, the words “believes,” “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties more particularly described in “Item 1A. Risk Factors”, in our annual report on Form 10-K for the year ended December 31, 2011. These risks and uncertainties could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

BUSINESS OVERVIEW

We are a publicly-traded Delaware master limited partnership, formerly known as Atlas Pipeline Holdings, L.P. (NYSE: ATLS).

At March 31, 2012, our operations primarily consisted of our ownership interests in the following entities:

• Atlas Resource Partners, L.P. (“ARP”), a publicly-traded Delaware master limited partnership (NYSE: ARP), and an independent developer and producer of natural gas and oil, with operations in basins across the United States. ARP sponsors and manages tax-advantaged investment partnerships, in which it coinvests, to finance a portion of its natural gas and oil production activities. At March 31, 2012, we owned 100% of the general partner Class A units and incentive distribution rights, and common units representing an approximate 78.4% limited partner interest in ARP;

• Atlas Pipeline Partners, L.P. (“APL”), a publicly traded Delaware master limited partnership (NYSE: APL) and midstream energy service provider engaged in the gathering and processing of natural gas in the Mid-Continent and Appalachia regions of the United States. At March 31, 2012, we owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate 10.5% common limited partner interest; and

• Lightfoot Capital Partners, LP (“Lightfoot LP”) and Lightfoot Capital Partners GP, LLC (“Lightfoot GP”), the general partner of Lightfoot L.P. (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. At March 31, 2012, we had an approximate 16% general partner interest and 12% limited partner interest in Lightfoot.

In February 2012, the board of directors of our General Partner (“the Board”) approved the formation of ARP as a newly created exploration and production master limited partnership and the related transfer of substantially all of our natural gas and oil development and production assets and the partnership management business to ARP on March 5, 2012. The Board also approved the distribution of approximately 5.24 million ARP common units to our unitholders, which were distributed on March 13, 2012 using a ratio of 0.1021 ARP limited partner units for each of our common units owned on the record date of February 28, 2012. The distribution of ARP limited partner units represented approximately 20% of the common limited partner units outstanding at March 13, 2012.

FINANCIAL PRESENTATION

Our consolidated combined financial statements contain our accounts and those of our consolidated subsidiaries, all of which are wholly-owned at March 31, 2012 except for ARP and APL, which we control. Due to the structure of our ownership interests in ARP and APL, in accordance with generally accepted accounting principles, we consolidate the financial statements of ARP and APL into our financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in ARP and APL are reflected as income attributable to non-controlling interests in our consolidated combined statements of operations and as a component of partners’ capital on our consolidated combined balance sheets. Throughout this section, when we refer to “our” consolidated combined financial statements, we are referring to the consolidated combined results for us, our wholly-owned subsidiaries and the consolidated results of ARP

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and APL, adjusted for non-controlling interests in ARP and APL. All significant intercompany transactions and balances have been eliminated in the consolidation of our financial statements.

On February 17, 2011, we acquired certain producing natural gas and oil properties, a partnership management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, and other assets (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of our general partner. Our management determined that the acquisition of the Transferred Business constituted a transaction between entities under common control. In comparison to the purchase method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable assets and liabilities of the Transferred Business based upon their fair values with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital on our consolidated combined balance sheet. Also, in comparison to the purchase method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in our consolidated combined financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect to the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, we reflected the impact of the acquisition of the Transferred Business on our consolidated combined financial statements in the following manner:

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

• Retrospectively adjusted our consolidated combined financial statements for any date prior to February 17, 2011, the date of acquisition, to reflect our results on a consolidated combined basis with the results of the Transferred Business as of or at the beginning of the respective period; and

• Adjusted the presentation of our consolidated combined statements of operations for the three months ended March 31, 2011 to reflect the results of operations attributable to the Transferred Business prior to the date of acquisition as a reduction of net income to determine income attributable to common limited partners. However, the Transferred Business’ historical financial statements prior to the date of acquisition do not reflect general and administrative expenses and interest expense. The Transferred Business was not managed by AEI as a separate business segment and did not have identifiable labor and other ancillary costs. The general and administrative and interest expenses of AEI prior to the date of acquisition, including the exploration and production business segment, related primarily to business activities associated with the business sold to Chevron Corporation in February 2011 and not activities related to the Transferred Business.

SUBSEQUENT EVENTS

Cash Distribution. On April 26, 2012, we declared a cash distribution of $0.25 per unit on our outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2012. The $12.8 million distribution will be paid on May 18, 2012 to unitholders of record at the close of business on May 8, 2012.

ARP Cash Distribution. On April 17, 2012, the ARP declared a pro-rated cash distribution of $0.12 per unit on its outstanding common limited partner units, representing the cash distribution for the partial quarter beginning on March 5, 2012 and ended on March 31, 2012. The $3.2 million distribution will be paid on May 15, 2012 to unitholders of record at the close of business on April 27, 2012.

APL Cash Distribution. On April 25, 2012, APL declared a cash distribution of $0.56 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2012. The $32.2 million distribution, including $5.4 million to us, will be paid on May 15, 2012 to unitholders of record at the close of business on May 8, 2012.

ARP’s Joint Venture Agreement with Subsidiaries of Equal Energy, Ltd. On April 26, 2012, ARP acquired a 50% interest in approximately 14,500 net undeveloped acres in the oil and natural gas liquids area of the Mississippi Lime play in northwestern Oklahoma for $18.0 million from subsidiaries of Equal Energy, Ltd. (“Equal”) (NYSE: EQU; TSX: EQU). The transaction was funded through borrowings under ARP’s revolving credit facility.

ARP’s Acquisition of Assets from Carrizo Oil & Gas, Inc. On April 30, 2012, ARP acquired certain assets from

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Carrizo Oil & Gas, Inc. (NASDAQ: CRZO; “Carrizo”) for $190 million in cash. The assets acquired include interests in approximately 200 producing natural gas wells from the Barnett Shale, located in Bend Arch–Fort Worth Basin in North Texas, proved undeveloped acres also in the Barnett Shale and gathering pipelines and associated gathering facilities that service certain of the acquired wells. The purchase price is subject to certain post-closing adjustments based on, among other things, environmental and title defects, if any.

To partially fund the acquisition of assets from Carrizo, ARP executed a unit purchase agreement with several purchasers for the sale of 6.0 million of its common units at a negotiated purchase price per unit of $20.00, for gross proceeds of $120.6 million, of which $5.0 million was purchased by certain of our executives. The common units were issued and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.

In connection with its acquisition of certain assets from Carrizo, ARP also amended its credit facility to, among other items, increase the borrowing base to $250.0 million and the maximum lender commitment to $500.0 million, contingent upon the closing of the acquisition of assets from Carrizo.

CONTRACTUAL REVENUE ARRANGEMENTS

Atlas Resources

Natural Gas. ARP markets the majority of its natural gas production to gas utility companies, gas marketers, local distribution companies, industrial or other end-users, and companies generating electricity. The sales price of natural gas produced in the Appalachian Basin has been primarily based upon the NYMEX spot market price, the natural gas produced in the New Albany Shale and Antrim Shale has been primarily based upon the Texas Gas Zone SL and Chicago spot market prices, and the gas produced in the Niobrara formation has been primarily based upon the Cheyenne Index.

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

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

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

Investment Partnerships. ARP generally has funded a portion of its drilling activities through sponsorship of tax-advantaged investment drilling partnerships. In addition to providing capital for its drilling activities, its investment partnerships are a source of fee-based revenues, which are not directly dependent on commodity prices. As managing general partner of the investment partnerships, ARP receives the following fees:

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

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

• Well services. Each partnership pays ARP a monthly per well operating fee, currently $100 to $1,500, for the life of the well. Because ARP coinvests in the partnerships, the net fee that ARP receives is reduced by its proportionate interest in the wells; and

• Gathering. Each royalty owner, partnership and certain other working interest owners pay ARP a gathering fee, which generally ranges from $0.35 per Mcf to the amount of the competitive gathering fee, currently defined as 13% of the gross sales price of the natural gas. In general, pursuant to gathering agreements, ARP has with a third-party gathering system, which gathers the majority of our natural gas, ARP must also pay an additional amount equal to the excess of the gathering fees collected from the investment partnerships up to an amount equal to approximately

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16% of the realized natural gas sales price (adjusted for the settlement of natural gas derivative instruments). As a result, some of its gathering expenses within our partnership management segment, specifically those in the Appalachian Basin, will generally exceed the revenues collected from investment partnerships by approximately 3%.

Atlas Pipeline

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.

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

GENERAL TRENDS AND OUTLOOK

Atlas Resources

The areas in which ARP operates are experiencing a significant increase in natural gas, oil and NGL production related to new and increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques, including horizontal and multiple fracturing techniques. The increase in the supply of natural gas has put a downward pressure on domestic prices. While ARP anticipates continued high levels of exploration and production activities over the long-term in the areas in which it operates, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas, oil and NGL reserves.

ARP’s future gas and oil reserves, production, cash flow, its ability to make payments on its revolving credit facility and its ability to make distributions to its unitholders, including us, depend on ARP’s success in producing its current reserves efficiently, developing its existing acreage and acquiring additional proved reserves economically. ARP faces the challenge of natural production declines and volatile natural gas and oil prices. As initial reservoir pressures are depleted, natural gas production from particular wells decreases. ARP attempts to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than it produces.

Atlas Pipeline

APL faces competition 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, its own. Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than APL’s. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. APL management believes 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. APL management believes offering an integrated package of services,

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while remaining flexible in the types of contractual arrangements that APL offers producers, allows it to compete more effectively for new natural gas supplies in its regions of operations.

As a result of APL’s Percentage of Proceeds (“POP”) and Keep-Whole contracts, its results of operations and financial condition substantially depend upon the price of natural gas, NGLs and crude oil. APL management believes 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 management generally expects NGL prices to follow changes in crude oil prices over the long term, which management 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 past. Lower drilling levels and shut-in wells over a sustained period would have a negative effect on natural gas volumes gathered and processed.

RESULTS OF OPERATIONS

GAS AND OIL PRODUCTION

Production Profile. Currently, ARP has focused its natural gas and oil production operations in various shale plays in the northeastern and midwestern United States. As part of our agreement with AEI to acquire the Transferred Business on February 17, 2011, ARP has certain agreements which restrict its ability to drill additional wells in certain areas of Pennsylvania, New York and West Virginia, including portions of the Marcellus Shale. Through March 31, 2012, ARP has established production positions in the following areas:

• the Appalachia basin, including the Marcellus Shale, a rich, organic shale that generally contains dry, pipeline-quality natural gas, and the Chattanooga Shale in northeastern Tennessee, which enables ARP to access other formations in that region such as the Monteagle and Ft. Payne Limestone;

• the Niobrara Shale in northeastern Colorado, a predominantly biogenic shale play that produces dry gas;

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

• the Antrim Shale in Michigan, where ARP produces out of the biogenic region of the shale similar to the New Albany Shale.

The following table presents the number of wells ARP drilled, both gross and for its interest, and the number of gross wells it turned in line during the three months ended March 31, 2012 and 2011:

	Three Months Ended March  31,
	2012		2011
Gross wells drilled:
Appalachia		9		3
Niobrara		51		17
		60		20
Our share of gross wells drilled(1):
Appalachia		2		1
Niobrara		34		5
		36		6
Gross wells turned in line:
Appalachia		21		1
New Albany/Antrim		—		12
Niobrara		49		18
		70		31

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

Production Volumes. The following table presents ARP’s total net natural gas, oil, and NGL production volumes and production per day for the three months ended March 31, 2012 and 2011:

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	Three Months Ended March  31,
	2012		2011
Production:(1)(2)
Appalachia:(3)
Natural gas (MMcf)		2,857		2,630
Oil (000’s Bbls)		28		23
Natural gas liquids (000s Bbls)		38		42
Total (MMcfe)		3,253		3,023
New Albany/Antrim:
Natural gas (MMcf)		275		292
Total (MMcfe)		275		292
Niobrara:
Natural gas (MMcf)		58		17
Total (MMcfe)		58		17
Total:
Natural gas (MMcf)		3,190		2,939
Oil (000’s Bbls)		28		23
Natural gas liquids (000’s Bbls)		38		42
Total (MMcfe)		3,587		3,332
Production per day: (1)(2)
Appalachia:(3)
Natural gas (Mcfd)		31,391		29,226
Oil (Bpd)		305		262
Natural gas liquids (Bpd)		422		465
Total (Mcfed)		35,751		33,589
New Albany/Antrim:
Natural gas (Mcfd)		3,026		3,244
Total (Mcfed)		3,026		3,244
Niobrara:
Natural gas (Mcfd)		642		185
Total (Mcfed)		642		185
Total:
Natural gas (Mcfd)		35,060		32,655
Oil (Bpd)		305		262
Natural gas liquids (Bpd)		422		465
Total (Mcfed)		39,420		37,019

⁽¹⁾  Production quantities consist of the sum of (i) ARP’s proportionate share of production from wells in which it has a direct interest, based on its proportionate net revenue interest in such wells, and (ii) ARP’s proportionate share of production from wells owned by the investment partnerships in which it has an interest, based on its equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells.

⁽²⁾  “MMcf” represents million cubic feet; “MMcfe” represent million cubic feet equivalents; “Mcfd” represents thousand cubic feet per day; “Mcfed” represents thousand cubic feet equivalents per day; and “Bbls” and “Bpd” represent barrels and barrels per day. Barrels are converted to Mcfe using the ratio of approximately six Mcf’s to one barrel.

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

Production Revenues, Prices and Costs. ARP’s production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised 94% of its proved reserves on an energy equivalent basis at December 31, 2011. The following table presents ARP’s production revenues and average sales prices for its natural gas, oil, and natural gas liquids production for the three months ended March 31, 2012 and 2011, along with its average production costs, taxes, and transportation and compression costs in each of the reported periods:

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	Three Months Ended March 31,
	2012		2011
Production revenues (in thousands):
Appalachia:(1)
Natural gas revenue	$	11,490	$	12,215
Oil revenue		2,787		2,059
Natural gas liquids revenue		1,678		1,845
Total revenues	$	15,955	$	16,119
New Albany/Antrim:
Natural gas revenue	$	1,060	$	1,439
Total revenues	$	1,060	$	1,439
Niobrara:
Natural gas revenue	$	149	$	68
Total revenues	$	149	$	68
Total:
Natural gas revenue	$	12,699	$	13,722
Oil revenue		2,787		2,059
Natural gas liquids revenue		1,678		1,845
Total revenues	$	17,164	$	17,626
Average sales price:(2)
Natural gas (per Mcf):
Total realized price, after hedge(3)	$	4.33	$	5.46
Total realized price, before hedge(3)	$	2.88	$	4.47
Oil (per Bbl):
Total realized price, after hedge	$	100.41	$	87.39
Total realized price, before hedge	$	100.41	$	87.39
Natural gas liquids (per Bbl) total realized price:	$	43.73	$	44.04
Production costs (per Mcfe):(2)
Appalachia:(1)
Lease operating expenses(4)	$	1.03	$	0.97
Production taxes		0.11		0.06
Transportation and compression		0.33		0.46
	$	1.47	$	1.49
New Albany/Antrim:
Lease operating expenses	$	1.19	$	1.12
Production taxes		0.07		0.08
Transportation and compression		0.03		0.09
	$	1.30	$	1.28
Niobrara:
Lease operating expenses	$	1.49	$	0.66
Production taxes		0.07		—
Transportation and compression		0.34		0.30
	$	1.90	$	0.96
Total:
Lease operating expenses(4)	$	1.05	$	0.98
Production taxes		0.11		0.06
Transportation and compression		0.30		0.43
	$	1.46	$	1.47

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

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

⁽³⁾  Excludes the impact of subordination of ARP’s production revenue to investor partners within its investment partnerships for the three months ended March 31, 2012 and 2011. Including the effect of this subordination, the average realized gas sales price was $3.98 per Mcf ($2.53 per Mcf before the effects of financial hedging) and $4.67 per Mcf ($3.68 per Mcf before the effects of financial hedging) for the three months ended March 31, 2012 and 2011, respectively.

⁽⁴⁾  Excludes the effects of ARP’s proportionate share of lease operating expenses associated with subordination of ARP’s production revenue to investor partners within its investment partnerships for the three months ended March 31, 2012 and 2011. Including the effects of these costs, Appalachia lease operating expenses per Mcfe were $0.80 per Mcfe ($1.24 per Mcfe for total production costs) and $0.65 per Mcfe ($1.17 per Mcfe for total production costs) for the three months ended March 31, 2012 and 2011, respectively. Including the effects of these costs, total lease operating expenses per Mcfe were $0.84 per Mcfe ($1.26 per Mcfe for total production costs) and $0.69 per Mcfe ($1.18 per Mcfe for total production costs) for three months ended March 31, 2012 and 2011, respectively.

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Three Months Ended March 31, 2012 Compared with the Three Months Ended March 31, 2011. Total natural gas revenues were $12.7 million for the three months ended March 31, 2012, a decrease of $1.0 million from $13.7 million for the three months ended March 31, 2011. This decrease consisted of a $3.1 million decrease attributable to lower realized natural gas prices, partially offset by a $0.9 million increase attributable to higher production volumes and a $1.2 million decrease in gas revenues subordinated to the investor partners within ARP’s investment partnerships for the three months ended March 31, 2012 compared with the prior year period. The decrease in gas revenues subordinated to the investor partners within ARP’s investment partnerships was related to the overall decrease in natural gas revenue. Total oil and natural gas liquids revenues were $4.5 million for the three months ended March 31, 2012, an increase of $0.6 million from $3.9 million for the comparable prior year period. This increase resulted from a $0.4 million increase associated with higher oil production volumes and a $0.3 million increase associated with higher average oil realized prices, partially offset by a $0.1 million decrease from the sale of natural gas liquids.

Appalachia production costs were $4.0 million for the three months ended March 31, 2012, an increase of $0.5 million from $3.5 million for the three months ended March 31, 2011. This increase was principally due to a $0.2 million increase in water hauling and disposal costs, a $0.1 million increase in labor-related costs and a $0.2 million increase associated with a reduction in ARP’s net credit received against lease operating expenses from the subordination of our revenue within ARP’s investment partnerships. The increases in water hauling and disposal costs were primarily due to an increase in natural gas volumes between the periods. New Albany/Antrim production costs were $0.4 million for the three months ended March 31, 2012, which was consistent with the comparable prior year period.

PARTNERSHIP MANAGEMENT

Well Construction and Completion

Drilling Program Results. The number of wells ARP drills will vary within the partnership management segment depending on the amount of capital it raises through its investment partnerships, the cost of each well, the depth or type of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. The following table presents the amounts of drilling partnership investor capital raised and deployed (in thousands), as well as the number of gross and net development wells ARP drilled for its investment partnerships during the three months ended March 31, 2012 and 2011. There were no exploratory wells drilled during the three months ended March 31, 2012 and 2011:

	Three Months Ended March 31,
	2012		2011
Drilling partnership investor capital:
Raised	$	—	$	—
Deployed	$	43,719	$	17,725
Gross partnership wells drilled:
Appalachia		9		3
New Albany/Antrim		—		—
Niobrara		51		17
Total		60		20
Net partnership wells drilled:
Appalachia		9		3
New Albany/Antrim		—		—
Niobrara		51		17
Total		60		20

Well construction and completion revenues and costs and expenses incurred represent the billings and costs associated with the completion of wells for investment partnerships ARP sponsors. The following table sets forth information relating to these revenues and the related costs and number of net wells associated with these revenues during the periods indicated (dollars in thousands):

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	Three Months Ended March  31,
	2012		2011
Average construction and completion:
Revenue per well	$	688	$	635
Cost per well		593		538
Gross profit per well	$	95	$	97
Gross profit margin	$	6,024	$	2,704
Partnership net wells associated with revenue recognized(1):
Appalachia		9		1
New Albany/Antrim		—		2
Niobrara		55		25
		64		28

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

Three Months Ended March 31, 2012 Compared with the Three Months Ended March 31, 2011. Well construction and completion segment margin was $6.0 million for the three months ended March 31, 2012, an increase of $3.3 million from $2.7 million for the three months ended March 31, 2011. This increase consisted of a $3.4 million increase related to an increased number of wells recognized for revenue within the ARP investment partnerships, partially offset by a $0.1 million decrease associated with lower gross profit margin per well. Average revenue and cost per well increased between periods due to higher capital deployed for Marcellus Shale wells within the drilling partnerships during first quarter 2012. Since ARP’s drilling contracts with the investment partnerships are on a “cost-plus” basis, an increase or decrease in its average cost per well also results in a proportionate increase or decrease in its average revenue per well, which directly affects the number of wells ARP drills. In addition, the increase in well construction and completion margin was due to the deployment of funds raised from ARP’s Fall 2011 drilling program. The planned Fall 2010 drilling program was cancelled following AEI’s announcement of the acquisition of the Transferred Business in November 2010.

Our consolidated combined balance sheet at March 31, 2012 includes $28.0 million of “liabilities associated with drilling contracts” for funds raised by ARP’s investment partnerships that have not been applied to the completion of wells due to the timing of drilling operations, and thus had not been recognized as well construction and completion revenue on our consolidated combined statements of operations. We and ARP expect to recognize this amount as revenue during the remainder of 2012.

Administration and Oversight

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

Three Months Ended March 31, 2012 Compared with the Three Months Ended March 31, 2011. Administration and oversight fee revenues were $2.8 million for the three months ended March 31, 2012, an increase of $1.4 million from $1.4 million for the three months ended March 31, 2011. This increase was primarily due to an increase in the number of Marcellus Shale and Niobrara Shale wells drilled during the current year period in comparison to the prior year period, primarily as a result of the wells drilled as part of ARP’s Fall 2011 drilling program. The planned Fall 2010 drilling program was cancelled following AEI’s announcement of the acquisition of the Transferred Business in November 2010.

Well Services

Well service revenue and expenses represent the monthly operating fees ARP charges and the work ARP’s service company performs for its investment partnership wells during the drilling and completing phase as well as ongoing maintenance of these wells and other wells in which ARP serves as operator.

Three Months Ended March 31, 2012 Compared with the Three Months Ended March 31, 2011. Well services revenues were $5.0 million for the three months ended March 31, 2012, a decrease of $0.3 million from $5.3 million for three months ended March 31, 2011. Well services expenses were $2.4 million for the three months ended March 31, 2012, which was consistent with the comparable prior year period. The decrease in well services revenue is primarily related to a temporary reduction in repairs and maintenance projects during the three months ended March 31, 2012 as compared with the comparable prior year period.

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Gathering and Processing

Gathering and processing margin includes gathering fees ARP charges to its investment partnership wells and the related expenses and gross margin for its processing plants in the New Albany Shale and the Chattanooga Shale, and the operating revenues and expenses of APL. The gathering fees charged to ARP’s investment partnership wells generally range from $0.35 per Mcf to the amount of the competitive gathering fee, currently defined as 13% of the gross sales price of the natural gas. In general, pursuant to gathering agreements ARP has with a third-party gathering system which gathers the majority of its natural gas, ARP must also pay an additional amount equal to the excess of the gathering fees collected from the investment partnerships up to an amount equal to approximately 16% of the realized natural gas sales price (adjusted for the settlement of natural gas derivative instruments). However, in most of ARP’s direct investment partnerships, it collects a gathering fee of 13% of the realized natural gas sales price per the respective partnership agreement. As a result, some of ARP’s gathering expenses within our partnership management segment, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the investment partnerships by approximately 3%.

The following table presents ARP’s and APL’s gathering and processing revenues and expenses for each of the respective periods:

	Three Months Ended March 31,
Gathering and Processing:	2012			2011
Atlas Resource:
Revenue	$	3,314		$	4,499
Expense		(4,674	)		(5,734	)
Gross Margin	$	(1,360	)	$	(1,235	)
Atlas Pipeline:
Revenue	$	301,906		$	275,719
Expense		(247,250	)		(231,250	)
Gross Margin	$	54,656		$	44,469
Total:
Revenue	$	305,220		$	280,218
Expense		(251,924	)		(236,984	)
Gross Margin	$	53,296		$	43,234

Three Months Ended March 31, 2012 Compared with the Three Months Ended March 31, 2011. ARP’s net gathering and processing expense for the three months ended March 31, 2012 was $1.4 million compared with $1.2 million for the three months ended March 31, 2011. This unfavorable movement was principally due to an increase in natural gas volume between the periods.

Gathering and processing margin for APL was $54.7 million for the three months ended March 31, 2012 compared with $44.5 million for the three months ended March 31, 2011. This increase was due principally to higher production volumes related to on-going capacity expansion projects, partially offset by lower natural gas and NGL sales prices.

Loss on Mark-to-Market Derivatives

Three Months Ended March 31, 2012 Compared with the Three Months Ended March 31, 2011. Loss on mark-to-market derivatives was $12.0 million for the three months ended March 31, 2012 as compared with $21.6 million for the three months ended March 31, 2011. This favorable movement was due primarily due to a $7.8 million favorable variance in non-cash mark-to-market adjustments on APL’s commodity derivatives and a $1.8 million favorable movement in cash settlements on net cash derivative expense related to APL’s commodity derivatives.

Other, Net

Three Months Ended March 31, 2012 Compared with the Three Months Ended March 31, 2011. Other, net was $2.8 million for the three months ended March 31, 2012 as compared with $4.4 million for the comparable prior year period. This decrease was primarily due to the $1.0 million amortization of ARP’s premium on derivative contracts which provide ARP with the option to enter into swap contracts up through May 31, 2012 for production volumes related to wells recently acquired (see “Subsequent Events”) and a $0.6 million decrease in income from equity investments.

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OTHER COSTS AND EXPENSES

General and Administrative Expenses

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

	Three Months Ended March 31,
	2012		2011
General and Administrative expenses:
Atlas Energy	$	15,561	$	2,931
Atlas Resource		11,742		4,242
Atlas Pipeline		9,945		9,017
Total	$	37,248	$	16,190

Total general and administrative expenses increased to $37.2 million for the three months ended March 31, 2012 compared with $16.2 million for the three months ended March 31, 2011. Our $15.6 million of general and administrative expenses for the three months ended March 31, 2012 represents a $12.7 million increase from the comparable period primarily due to an $8.4 million increase resulting from costs incurred in the formation of ARP and the related distribution of its common units and a $4.2 million increase of non-cash compensation expense. ARP’s $11.7 million of general and administrative expenses for the three months ended March 31, 2012 represents a $7.5 million increase from the comparable period primarily due to a $2.6 million increase related to the expiration of its transition services agreement with Chevron, a $2.5 million increase in acquisition and other related costs primarily resulting from costs incurred for the acquisition of certain assets from Carrizo (see “Subsequent Events”), a $1.9 million increase in salary and wages expenses related to the growth of ARP’s business and $0.5 million increase related to consulting and other outside services. APL’s $9.9 million of general and administrative expense for the three months ended March 31, 2012 represents an increase of $0.9 million from the comparable prior year period, which was principally due to an increase in salaries and wages resulting from the expansion of its business.

Depreciation, Depletion and Amortization

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

	Three Months Ended March 31,
	2012		2011
Depreciation, depletion and amortization:
Atlas Resource	$	9,108	$	7,701
Atlas Pipeline		20,842		18,906
Total	$	29,950	$	26,607

Total depreciation, depletion and amortization increased to $30.0 million for the three months ended March 31, 2012 compared with $26.6 million for the comparable prior year period primarily due to a $1.0 million increase in ARP’s depletion expense and a $1.9 million increase in APL’s depreciation expenses, principally associated with APL’s expansion capital expenditures incurred subsequent to March 31, 2011. The following table presents ARP’s depletion expense per Mcfe for its operations for the respective periods:

	Three Months Ended March  31,
	2012			2011
Depletion expense (in thousands):
Total	$	7,568		$	6,566
Depletion expense as a percentage of gas and oil production revenue		44	%		37	%
Depletion per Mcfe	$	2.11		$	1.97

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Depletion expense varies from period to period and is directly affected by changes in ARP’s gas and oil reserve quantities, production levels, product prices and changes in the depletable cost basis of ARP’s gas and oil properties. For the three months ended March 31, 2012, depletion expense increased $1.0 million to $7.6 million compared with $6.6 million for the three months ended March 31, 2011. ARP’s depletion expense of gas and oil properties as a percentage of gas and oil revenues was 44% for the three months ended March 31, 2012, compared with 37% for the three months ended March 31, 2011, which was primarily due to a decrease in realized natural gas prices between periods. Depletion expense per Mcfe was $2.11 for the three months ended March 31, 2012, an increase of $0.14 per Mcfe from $1.97 for the three months ended March 31, 2011, primarily related to increased Marcellus Shale well costs and additional capitalized costs related to ARP’s 2011 drilling partnership fundraising. Depletion expense increased between periods principally due to an overall increase in production volumes.

Gain (Loss) on Asset Disposals

During the three months ended March 31, 2012, the loss on asset disposals was $7.0 million, compared to a gain of $255.9 million for the three months ended March 31, 2011. The $7.0 million loss on asset disposals for the three months ended March 31, 2012 pertained to ARP’s decision to terminate a farm out agreement with a third party for well drilling in the South Knox area of the New Albany Shale that was originally entered into in 2010. The farm out agreement contained certain well drilling targets for ARP to maintain ownership of the South Knox processing plant, which ARP’s management decided in 2012 to not achieve due to the current natural gas price environment. As a result, ARP forfeited its interest in the processing plant and recorded a loss related to the net book values of those assets as of March 31, 2012. The $255.9 million gain on asset disposals for the three months ended March 31, 2011 is principally due to APL’s gain on the sale of its 49% non- controlling interest in the Laurel Mountain joint venture which was finalized and recorded in February 2011.

Interest Expense

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

	Three Months Ended March 31,
	2012		2011
Interest Expense:
Atlas Energy	$	233	$	5,633
Atlas Resource		150		—
Atlas Pipeline		8,708		12,445
Total	$	9,091	$	18,078

Total interest expense decreased to $9.1 million for the three months ended March 31, 2012 as compared with $18.1 million for the three months ended March 31, 2011. This $9.0 million decrease was primarily due to our $5.4 million decrease and a $3.7 million decrease related to APL. Our $5.4 million decrease in interest expense was primarily due to $4.9 million of accelerated amortization of deferred financing costs for our bridge credit facility that was entered into in connection with our closing of the acquisition of the Transferred Business. The bridge credit facility was replaced in March 2011. The $3.7 million decrease in interest expense for APL was primarily due to a $5.6 million decrease in interest expense associated with APL’s 8.125% senior unsecured notes due on December 15, 2015 (“8.125% Senior Notes”) and a $2.0 million increase in APL’s capitalized interest, partially offset by a $2.9 million increase in interest expense associated with APL’s 8.75% senior unsecured notes due on June 15, 2018 (“8.75% Senior Notes”) and a $1.0 million increase in interest associated with APL’s revolving credit facility. The lower interest expense on APL’s 8.125% Senior Notes is due to the redemption of APL’s 8.125% Senior Notes in April 2011 with proceeds from the sale of its 49% non-controlling interest in Laurel Mountain. The increased capitalized interest is due to APL’s increased capital expenditures in the current period. The increased interest on APL’s 8.75% Senior Notes is due to the issuance of additional 8.75% Senior Notes in November 2011. The increased interest on APL’s revolving credit facility is due to additional borrowings in the current period to cover APL’s current capital expenditures.

Income Not Attributable to Common Limited Partners

For the three months ended March 31, 2011, income not attributable to common limited partners was $4.7 million, which consisted of income not attributable to common limited partners related to the results of operations of the Transferred Business prior to our acquisition on February 17, 2011 (see “Financial Presentation”).

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Income Attributable to Non-Controlling Interests

Income attributable to non-controlling interests was $3.4 million for the three months ended March 31, 2012 as compared with $211.4 million for the comparable prior year period. Income attributable to non-controlling interests includes an allocation of APL’s net income and ARP’s net loss to non-controlling interest holders. The decrease between the three months ended March 31, 2012 and the prior year comparable period was primarily due to the decrease in APL’s net earnings between periods, as a result of the gain from the sale of its investment in Laurel Mountain in 2011.

LIQUIDITY AND CAPITAL RESOURCES

General

Our primary sources of liquidity are cash distributions received with respect to our ownership interests in ARP and APL. Our primary cash requirements are for our general and administrative expenses and other expenditures and quarterly distributions to our common unitholders, which we expect to fund through cash distributions received and cash on hand. Our operations principally occur through our subsidiaries, whose sources of liquidity are discussed in more detail below.

Atlas Resource. ARP’s primary sources of liquidity are cash generated from operations, capital raised through investment partnerships, and borrowings under its credit facility. ARP’s primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures, and quarterly distributions to its common unitholders and us as general partner. In general, ARP expects to fund:

• cash distributions and maintenance capital expenditures through existing cash and cash flows from operating activities;

• expansion capital expenditures and working capital deficits through cash generated from operations, additional borrowings and capital raised through investment partnerships; and

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

Atlas Pipeline. 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 us as general partner. In general, APL expects to fund:

• cash distributions and maintenance capital expenditures through existing cash and cash flows from operating activities;

• expansion capital expenditures and working capital deficits through 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 asset sales.

ARP and APL rely on cash flow from operations and their credit facilities to execute their growth strategy and to meet their financial commitments and other short-term liquidity needs. ARP and APL cannot be certain that additional capital will be available to the extent required and on acceptable terms. We and our subsidiaries believe that we will have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve month period. However, we and our subsidiaries are subject to business, operational and other risks that could adversely affect our cash flow. We and our subsidiaries may supplement our cash generation with proceeds from financing activities, including borrowings under ARP’s and APL’s credit facilities and other borrowings, the issuance of additional common units, the sale of assets and other transactions.

Cash Flows - Three Months Ended March 31, 2012 Compared with the Three Months Ended March 31, 2011

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Net cash used in operating activities of $4.5 million for the three months ended March 31, 2012 represented an unfavorable movement of $26.8 million from net cash provided by operating activities of $22.3 million for the comparable prior year period. The $26.8 million decrease was derived principally from a $69.5 million unfavorable movement in non-cash loss on derivatives and a $7.3 million unfavorable movement in distributions paid to non-controlling interests, partially offset by a $42.0 million favorable movement in working capital and an $8.0 million increase in net income excluding non-cash items. The non-cash charges which impacted net income included $263.0 million favorable movement in gain (loss) on asset disposals and a $1.9 million favorable movement in non-cash expenses including depreciation, depletion and amortization, amortization of deferred financing costs, equity income and distributions from unconsolidated companies, and compensation expense; partially offset by a $256.9 million decrease in net income (loss) from continuing operations. The decrease in net income from continuing operations was primarily due to a $255.9 million net gain on the sale of APL’s interest in Laurel Mountain in the first quarter of 2011. The movement in cash distributions to non-controlling interest holders was due principally to increases in the cash distributions of APL. The movement in working capital was principally due to a $68.2 million favorable movement in accounts receivable and other current assets, due to a decrease in subscriptions receivable for funds raised for ARP’s new drilling program in the fourth quarter of 2011, partially offset by a $26.2 million unfavorable movement in accounts payable and other current liabilities.

Net cash used in investing activities of $118.3 million for the three months ended March 31, 2012 represented an unfavorable movement of $490.3 million from net cash provided by investing activities of $372.0 million for the comparable prior year period. This unfavorable movement was principally due to a $411.8 million decrease in net proceeds from asset sales, a $74.1 million unfavorable movement in capital expenditures and a $17.2 million unfavorable movement in APL’s net cash paid for acquisitions, partially offset by a $12.3 million favorable movement in APL’s investments in unconsolidated companies and a $0.5 million favorable movement in other assets. See further discussion of capital expenditures under “- Capital Requirements”.

Net cash provided by financing activities of $90.8 million for the three months ended March 31, 2012 represented a change of $379.3 million from net cash used in financing activities of $288.5 million for the comparable prior year period. This movement was principally due to a $293.7 million favorable movement in cash in escrow relating to the 8.125% APL Senior Note redemption in the first quarter of 2011, a net $175.0 million increase in ARP’s and APL’s net borrowings under their respective credit facilities, a $35.4 million favorable movement in repayments of long-term debt and a $2.8 million favorable movement in deferred financing costs and other, partially offset by a $117.2 million unfavorable movement in the non-cash transaction adjustment related to the acquisition of the Transferred Business on February 17, 2011 and a $10.4 million increase in distributions paid to unitholders.

Capital Requirements

Our principal assets consist of our ownership interests in ARP and APL, through which our operating activities occur. As such, we do not currently have any separate capital requirements apart from those entities. A more detailed discussion of ARP’s and APL’s capital requirements is provided below.

Atlas Resource Partners. ARP’s capital requirements consist primarily of:

• maintenance capital expenditures - capital expenditures ARP makes on an ongoing basis to maintain its current levels of production over the long term; and

• expansion capital expenditures - capital expenditures ARP makes to increase its current levels of production for longer than the short-term and includes new leasehold interests and the development and exploitation of existing leasehold interests through acquisitions and investments in its drilling partnerships.

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

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

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

The following table summarizes consolidated maintenance and expansion capital expenditures, excluding amounts

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paid for acquisitions, for the periods presented (in thousands):

	Three Months Ended March 31,
	2012		2011
Atlas Resource
Maintenance capital expenditures	$	1,750	$	1,666
Expansion capital expenditures		17,208		6,066
Total	$	18,958	$	7,732
Atlas Pipeline
Maintenance capital expenditures	$	4,510	$	3,260
Expansion capital expenditures		76,657		15,073
Total	$	81,167	$	18,333
Consolidated Combined
Maintenance capital expenditures	$	6,260	$	4,926
Expansion capital expenditures		93,865		21,139
Total	$	100,125	$	26,065

During the three months ended March 31, 2012, ARP’s $19.0 million of total capital expenditures consisted primarily of $13.1 million of well costs, principally its investments in the investment partnerships, compared with $4.0 million for the prior year comparable period, $4.0 million of leasehold acquisition costs compared with $0.7 million for the prior year comparable period, $0.3 million of gathering and processing costs compared with $1.2 million for the prior year comparable period and $1.6 million of corporate and other compared with $1.8 million for the prior year comparable period. The net increase in investments in its investment partnerships was the result of the cancellation of ARP’s Fall 2010 drilling program and the resulting reduction of investment partnership capital deployed in 2011. The net increase in leasehold acquisition costs relates to ARP’s acquisition of additional Marcellus Shale acreage during the three months ended March 31, 2012.

ARP continuously evaluates acquisitions of gas and oil assets. In order to make any acquisition, ARP believes it will be required to access outside capital either through debt or equity placements or through joint venture operations with other energy companies. There can be no assurance that ARP will be successful in its efforts to obtain outside capital.

Atlas Pipeline Partners. APL’s capital expenditures increased to $81.2 million for the three months ended March 31, 2012 compared with $18.3 million for the comparable prior year period. The increase was due principally to costs incurred related to APL’s processing facility expansions, compressor upgrades and pipeline projects as well as fluctuations in the timing of scheduled maintenance activity.

As of March 31, 2012, ARP and APL are committed to expend approximately $70.0 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

OFF BALANCE SHEET ARRANGEMENTS

As of March 31, 2012, our off-balance sheet arrangements are limited to ARP’s letters of credit outstanding of $0.8 million, APL’s letters of credit outstanding of $0.1 million and ARP’s and APL’s commitments to spend $70.0 million related to ARP’s drilling and completion expenditures, and ARP’s and APL’s capital expenditures.

CASH DISTRIBUTIONS

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

• provide for the proper conduct of our business;

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

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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. 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.

Atlas Resource Partners’ Cash Distribution Policy: ARP’s partnership agreement requires that it distribute 100% of available cash to its common unitholders and general partner, our wholly-owned subsidiary, within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all of ARP’s cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments. We, as ARP’s general partner, are granted discretion under the partnership agreement to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated.

Available cash will initially be distributed 98% to ARP’s common limited partners and 2% to its general partner. These distribution percentages are modified to provide for incentive distributions to be paid to us, as ARP’s general partner, if quarterly distributions to common limited partners exceed specified targets. Incentive distributions are generally defined as all cash distributions paid to ARP’s general partner that are in excess of 2% of the aggregate amount of cash being distributed. The incentive distribution rights will entitle us to receive an increasing percentage of cash distributed by ARP as it reaches specified targets. Incentive distributions are generally defined as all cash distributions paid to ARP’s general partner that are in excess of 2% of the aggregate amount of cash being distributed. During the three months ended March 31, 2012, we did not receive any incentive distributions from ARP.

Atlas Pipeline Partners’ 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, and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When APL’s general partner determines its quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Available cash is initially distributed 98% to APL’s common limited partners and 2% to its general partner. These distribution percentages are modified to provide for incentive distributions to be paid to APL’s general partner if quarterly distributions to common limited partners exceed specified targets. Incentive distributions are generally defined as all cash distributions paid to APL’s general partner that are in excess of 2% of the aggregate amount of cash being distributed. Atlas Pipeline GP agreed to allocate up to $3.75 million of incentive distribution rights per quarter back to APL after Atlas Pipeline GP receives the initial $7.0 million per quarter of incentive distribution rights as set forth in the IDR Adjustment Agreement. Incentive distributions of $1.4 million were paid during the three months ended March 31, 2012. No incentive distributions were paid during the three months ended March 31, 2011.

CREDIT FACILITY

At March 31, 2012, our debt consisted entirely of instruments entered into by ARP and APL, and we have not guaranteed any of our subsidiaries’ debt obligations. On March 5, 2012, in connection with the transfer of substantially all of our exploration and production assets to ARP (see “Business Overview”), we assigned our credit facility, which had maximum lender commitments of $300 million and a borrowing base of $138 million, to ARP.

ISSUANCE OF UNITS

We recognize gains on ARP’s and APL’s equity transactions as credits to partners’ capital rather than as income. These gains represent our portion of the excess net offering price per unit of each of ARP’s and APL’s common units over the book carrying amount per unit.

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

Atlas Resource Partners

In February 2012, the Board approved the distribution of approximately 5.24 million ARP common units which were distributed on March 13, 2012 to our unitholders using a ratio of 0.1021 ARP limited partner units for each of our common units owned on the record date of February 28, 2012. The distribution of ARP’s common units represented approximately 19.6% of its outstanding limited partner interests. Subsequent to the distribution, we owned 100% of the general partner Class A units and incentive distribution rights, and common units representing an approximate 78.4% limited partner interest in ARP. For a further description of ARP’s cash distribution policy, please see “Atlas Resource Partners’ Cash Distribution Policy”.

Atlas Pipeline Partners

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

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 and our subsidiaries 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, depletion, depreciation and amortization, asset impairment, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. A discussion of our significant accounting policies we have adopted and followed in the preparation of our consolidated combined financial statements was included with our Audit Report on Form 10-K for the year ended December 31, 2011 and in Note 2 under “Item 1. Financial Statements” included in this report, and there have been no material changes to these policies through March 31, 2012.

ITEM 3: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our and our subsidiaries’ potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and commodity prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we and our subsidiaries view and manage our ongoing market risk exposures. All of the market risk sensitive instruments were entered into for purposes other than trading.

General

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

We and our subsidiaries are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We and our subsidiaries manage these risks through regular operating and financing activities and periodic use of derivative financial instruments such as forward contracts and interest rate cap and swap agreements. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on March 31, 2012. Only the potential impact of hypothetical assumptions was analyzed. The analysis does not consider other possible effects that could impact our and our subsidiaries’ business.

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

Interest Rate Risk. At March 31, 2012, ARP had $17.0 million of outstanding borrowings under its revolving credit facility. At March 31, 2012, APL had $230.0 outstanding borrowings under its senior secured revolving credit facility. Holding all other variables constant, a hypothetical 100 basis-point or 1% change in variable interest rates would change our consolidated combined interest expense, excluding the effect of non-controlling interests, by $2.5 million.

Commodity Price Risk. ARP’s and APL’s market risk exposures to commodities are due to the fluctuations in the commodity prices and the impact those price movements have on our and our subsidiaries’ financial results. To limit their exposure to changing commodity prices, ARP and APL use financial derivative instruments, including financial swap and option instruments, to hedge portions of their future production. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under these swap agreements, ARP and APL receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, but not the obligation, to purchase or sell commodities at a fixed price for the relevant period.

Holding all other variables constant, including the effect of commodity derivatives, a 10% change in the average commodity prices would result in a change to our consolidated combined operating income from continuing operations for the twelve-month period ending March 31, 2013 of approximately $12.1 million, net of non-controlling interests.

At March 31, 2012, ARP had the following commodity derivatives:

Natural Gas Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(mmbtu)(1)		(per mmbtu)(1)
2012		5,490,000	$	4.477
2013		3,120,000	$	5.288
2014		3,960,000	$	5.121
2015		3,960,000	$	5.386
2016		1,080,000	$	4.383

Natural Gas Costless Collars

Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap
		(mmbtu)(1)		(per mmbtu)(1)
2012	Puts purchased		3,240,000	$	4.074
2012	Calls sold		3,240,000	$	5.279
2013	Puts purchased		5,520,000	$	4.395
2013	Calls sold		5,520,000	$	5.443
2014	Puts purchased		3,840,000	$	4.221
2014	Calls sold		3,840,000	$	5.120
2015	Puts purchased		3,840,000	$	4.296
2015	Calls sold		3,840,000	$	5.233

Natural Gas Put Options

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Production Period Ending December 31,	Option Type	Volumes		Average Fixed Price
		(mmbtu)(1)		(per mmbtu)(1)
2012	Puts purchased		3,800,000	$	2.595
2013	Puts purchased		1,020,000	$	3.450

Natural Gas Swaptions

Production Period Ending December 31,	Swaption Type	Volumes		Average Fixed Price
		(mmbtu)(1)		(per mmbtu)(1)
2012	Swaptions purchased		4,680,000	$	2.850
2013	Swaptions purchased		8,040,000	$	3.550
2014	Swaptions purchased		6,840,000	$	4.000
2015	Swaptions purchased		3,000,000	$	4.250
2016	Swaptions purchased		2,760,000	$	4.500

Crude Oil Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(Bbl)(1)		(per Bbl)(1)
2012		15,750	$	103.986
2013		15,000	$	100.570
2014		36,000	$	97.693
2015		36,000	$	93.973
2016		33,000	$	92.082

Crude Oil Costless Collars

Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap
		(Bbl)(1)		(per Bbl)(1)
2012	Puts purchased		45,000	$	90.000
2012	Calls sold		45,000	$	117.912
2013	Puts purchased		60,000	$	90.000
2013	Calls sold		60,000	$	116.396
2014	Puts purchased		24,000	$	80.000
2014	Calls sold		24,000	$	121.250
2015	Puts purchased		24,000	$	80.000
2015	Calls sold		24,000	$	120.750

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

As of March 31, 2012, APL had the following commodity derivatives:

Fixed Price Swaps

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Production Period	Purchased/ Sold	Commodity	Volumes(1)		Average Fixed Price
Natural Gas
2012	Sold	Natural Gasoline		3,420,000	$	3.019
NGLs
2012	Sold	Ethane		6,300,000	$	0.739
2012	Purchased	Ethane		6,300,000	$	0.710
2012	Sold	Propane		14,868,000	$	1.280
2012	Sold	Normal Butane		3,906,000	$	1.712
2012	Sold	Isobutane		2,142,000	$	1.584
2012	Sold	Natural Gasoline		3,150,000	$	2.394
2013	Sold	Propane		41,328,000	$	1.281
2013	Sold	Normal Butane		2,394,000	$	1.662
2013	Sold	Isobutane		1,134,000	$	1.807
Crude Oil
2012	Sold	Crude Oil		222,000	$	95.827
2013	Sold	Crude Oil		345,000	$	97.170
2014	Sold	Crude Oil		60,000	$	98.425

Options

Production Period	Purchased/ Sold	Type	Commodity	Volumes(1)		Average Strike Price
NGLs
2012	Purchased	Put	Ethane		1,260,000	$	0.745
2012	Purchased	Put	Propane		22,176,000	$	1.361
2012	Purchased	Put	Normal Butane		5,166,000	$	1.552
2012	Purchased	Put	Isobutane		2,898,000	$	1.583
2012	Purchased	Put	Natural Gasoline		10,710,000	$	2.012
2013	Purchased	Put	Normal Butane		10,458,000	$	1.667
2013	Purchased	Put	Isobutane		4,158,000	$	1.687
2013	Purchased	Put	Natural Gasoline		23,940,000	$	2.108
Crude Oil
2012	Sold(2)	Call	Crude Oil		373,500	$	94.694
2012	Purchased(2)	Call	Crude Oil		135,000	$	125.200
2012	Purchased	Put	Crude Oil		117,000	$	106.645
2013	Purchased	Put	Crude Oil		282,000	$	100.100
Total Options

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

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

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ITEM 4. 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 March 31, 2012, our disclosure controls and procedures were effective at the reasonable assurance level.

In February 2012, the board of directors of our General Partner approved the formation of a newly created exploration and production master limited partnership named Atlas Resource Partners, L.P. (“ARP”). In March 2012, we transferred substantially all of our current natural gas and oil development and production assets and the partnership management business to ARP. As of March 31, 2012, we maintained a 2% general partner interest and 78.4% limited partner interest in ARP.

Other than the previously mentioned item, there have been no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 6. EXHIBITS

Exhibit No.	Description
2.1	Transaction Agreement, by and among Atlas Energy, Inc., Atlas Energy Resources, LLC, Atlas Pipeline Holdings, L.P. and Atlas Pipeline Holdings GP, LLC, dated November 8, 2010. (11)
2.2	Purchase and Sale Agreement, by and among Atlas Pipeline Partners, L.P., APL Laurel Mountain, LLC, Atlas Energy, Inc., and Atlas Energy Resources, LLC, dated November 8, 2010. (11)
2.3	Employee Matters Agreement, by and among Atlas Energy, Inc., Atlas Pipeline Holdings, L.P. and Atlas Pipeline Holdings GP, LLC, dated November 8, 2010. (11)
2.4	Separation and Distribution Agreement, dated February 23, 2012, by and among Atlas Energy, L.P., Atlas Energy GP, LLC, Atlas Resource Partners, L.P. and Atlas Resource Partners GP, LLC. (The schedules to the Separation and Distribution Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request.) (27)
3.1(a)	Certificate of Limited Partnership of Atlas Pipeline Holdings, L.P.(1)
3.1(b)	Certificate of Amendment of Limited Partnership of Atlas Pipeline Holdings, L.P.(13)
3.1(c)	Amendment to Certificate of Limited Partnership of Atlas Energy, L.P. (5)
3.2(a)	Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Holdings, L.P.(13)
3.2(b)	Amendment No. 1 to Second Amended and Restated Limited Partnership Agreement of Atlas Pipeline Holdings, L.P.(13)
3.2(c)	Amendment No. 2 to Second Amended and Restated Limited Partnership Agreement of Atlas Energy, L.P. (5)
4.1	Specimen Certificate Representing Common Units(1)
10.1	Second Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Holdings GP, LLC. (13)
10.2	Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Partners GP, LLC(1)
10.3(a)	Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(1)
10.3(b)	Amendment No. 2 to Second Amendment and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(4)
10.3(c)	Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6)
10.3(d)	Amendment No. 4 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6)
10.3(e)	Amendment No. 5 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6)
10.3(f)	Amendment No. 6 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(7)
10.3(g)	Amendment No. 7 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(8)
10.3(h)	Amendment No. 8 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(9)
10.3(i)	Amendment No. 9 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(14)
10.4	Amended and Restated Limited Liability Company Agreement of Atlas Resource Partners GP, LLC

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Exhibit No.	Description
10.5	Amended and Restated Limited Partnership Agreement of Atlas Resource Partners, L.P.(28)
10.6(a)	Long-Term Incentive Plan(6)
10.6(b)	Amendment No. 1 to Long-Term Incentive Plan(15)
10.7	2010 Long-Term Incentive Plan(16)
10.8	Form of Phantom Unit Grant under 2010 Long-Term Incentive Plan(32)
10.9	Form of Stock Option Grant under 2010 Long-Term Incentive Plan(32)
10.10(a)	Amended and Restated Credit Agreement, dated July 27, 2007, amended and restated as of December 22, 2010, among Atlas Pipeline Partners, L.P., the guarantors therein, Wells Fargo Bank, National Association, and other banks party thereto(23)
10.10(b)	Amendment No. 1 to the Amended and Restated Credit Agreement, dated as of April 19, 2011 (25)
10.10(c)	Incremental Joinder Agreement to the Amended and Restated Credit Agreement, dated as of July 8, 2011 (26)
10.11	Pennsylvania Operating Services Agreement dated as of February 17, 2011 between Atlas Energy, Inc., Atlas Pipeline Holdings, L.P. and Atlas Resources, LLC. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.(12)
10.12	Petro-Technical Services Agreement, dated as of February 17, 2011 between Atlas Energy, Inc. and Atlas Pipeline Holdings, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission. (12)
10.13(a)	Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission. (12)
10.13(b)	Amendment No. 1 to the Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated as of January 6, 2011. (12)
10.13(c)	Amendment No. 2 to the Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated as of February 2, 2011. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission. (12)
10.14	Transaction Confirmation, Supply Contract No. 0001, under Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated February 17, 2011. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission. (12)
10.15	Gas Gathering Agreement for Natural Gas on the Legacy Appalachian System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble, LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.(12)
10.16	Gas Gathering Agreement for Natural Gas on the Expansion Appalachian System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble, LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P. Specific terms in this exhibit have been

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Exhibit No.	Description
	redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.(12)
10.17	Employment Agreement between Atlas Energy, L.P. and Edward E. Cohen dated as of May 13, 2011(12)
10.18	Employment Agreement between Atlas Energy, L.P. and Jonathan Z. Cohen dated as of May 13, 2011(12)
10.19	Employment Agreement between Atlas Energy, L.P. and Eugene N. Dubay dated as of November 4, 2011(21)
10.20	Employment Agreement between Atlas Energy, L.P. and Matthew A. Jones dated as of November 4, 2011(32)
10.21	Form of Grant of Phantom Units to Non-Employee Managers (20)
10.22	Letter Agreement, by and between Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P., dated November 8, 2010(21)
10.23	Non-Competition and Non-Solicitation Agreement, by and between Chevron Corporation and Edward E. Cohen, dated as of November 8, 2010(22)
10.24	Non-Competition and Non-Solicitation Agreement, by and between Chevron Corporation and Jonathan Z. Cohen, dated as of November 8, 2010(22)
10.25(a)	Credit Agreement, dated as of March 5, 2012, among Atlas Resource Partners, L.P. and Wells Fargo Bank, N.A., as administrative agent for the Lenders (30)
10.25(b)	First Amendment to Credit Agreement, dated as of April 30, 2012, between Atlas Resource Partners, L.P. and Wells Fargo Bank, N.A., as administrative agent for the Lenders (31)
10.25(c)	Joinder Agreement dated April 18, 2012 between ARP Barnett, LLC, ARP Oklahoma, LLC and Wells Fargo Bank, N.A.(31)
10.25(d)	Joinder Agreement dated April 30, 2012 between ARP Barnett, LLC and Wells Fargo Bank, N.A.(31)
10.26	Secured Hedge Facility Agreement dated as of March 5, 2012 among Atlas Resources, LLC, the participating partnerships from time to time party thereto, the hedge providers from time to time party thereto and Wells Fargo Bank, N.A., as collateral agent for the hedge providers(30)
10.27	Atlas Resource Partners, L.P. 2012 Long-Term Incentive Plan(28)
10.28	Purchase and Sale Agreement, dated as of March 15, 2012, among ARP Barnett, LLC, Carrizo Oil & Gas, Inc., CLLR, Inc., Hondo Pipeline, Inc. and Mescalero Pipeline, Inc. (29)
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
101.INS	XBRL Instance Document(33)
101.SCH	XBRL Schema Document(33)
101.CAL	XBRL Calculation Linkbase Document(33)
101.LAB	XBRL Label Linkbase Document(33)
101.PRE	XBRL Presentation Linkbase Document(33)
101.DEF	XBRL Definition Linkbase Document(33)

(1) Previously filed as an exhibit to the registration statement on Form S-1 (File No. 333-130999).

(2) [Intentionally omitted]

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(3) [Intentionally omitted]

(4) Previously filed as an exhibit to current report on Form 8-K filed July 30, 2007.

(5) Previously filed as an exhibit to current report on Form 8-K filed December 13, 2011.

(6) Previously filed as an exhibit to annual report on Form 10-K for the year ended December 31, 2008.

(7) Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended March 31, 2009.

(8) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on April 2, 2010.

(9) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on July 7, 2010.

(10) Previously filed as an exhibit to current report on Form 8-K filed June 1, 2009.

(11) Previously filed as an exhibit to current report on Form 8-K filed November 12, 2010.

(12) Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended March 31, 2011.

(13) Previously filed as an exhibit to current report on Form 8-K filed on February 24, 2011.

(14) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on December 13, 2011.

(15) Previously filed as an exhibit to annual report on Form 10-K for the year ended December 31, 2010.

(16) Previously filed as an exhibit to current report on Form 8-K filed on November 12, 2010.

(17) [Intentionally omitted]

(18) [Intentionally omitted]

(19) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on September 1, 2010.

(20) Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended September 30, 2010.

(21) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended September 30, 2011.

(22) Previously filed as an exhibit to Atlas Energy, Inc.’s current report on Form 8-K filed on November 12, 2010.

(23) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on December 23, 2010.

(24) Previously filed as an exhibit to current report on Form 8-K filed on March 25, 2011.

(25) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended March 31, 2011.

(26) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on July 11, 2011.

(27) Previously filed as an exhibit to current report on Form 8-K filed on February 24, 2012.

(28) Previously filed as an exhibit to current report on Form 8-K filed on March 14, 2012.

(29) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on March 21, 2012.

(30) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on March 7, 2012

(31) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on May 1, 2012

(32) Previously filed as an exhibit to annual report on Form 10-K for the year ended December 31, 2011

(33) Attached as Exhibit 101 to this report are documents formatted in XBRL (Extensible Business Reporting Language). Users of this data are advised pursuant to Rule 406T of Regulation S-T that the interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of section 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise not subject to liability under these sections. The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	ATLAS ENERGY, L.P.
	By:	Atlas Energy GP, LLC, its General Partner
Date: May 9, 2012	By:	/s/ EDWARD E. COHEN
		Edward E. Cohen
		Chief Executive Officer and President of the General Partner
Date: May 9, 2012	By:	/s/ SEAN P. MCGRATH
		Sean P. McGrath
		Chief Financial Officer of the General Partner
Date: May 9, 2012	By:	/s/ JEFFREY M. SLOTTERBACK
		Jeffrey M. Slotterback
		Chief Accounting Officer of the General Partner

69