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 June 30, 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 of incorporation or organization)	(I.R.S. Employer Identification No.)
Park Place Corporate Center One 1000 Commerce Drive, Suite 400 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 August 1, 2012 was 51,325,287.

ATLAS ENERGY, L.P. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

TABLE OF CONTENTS

	PAGE
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)		3
Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011		3
Consolidated Combined Statements of Operations for the Three and Six Months Ended June 30, 2012 and 2011		4
Consolidated Combined Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2012 and 2011		5
Consolidated Statement of Partners’ Capital for the Six Months Ended June 30, 2012		6
Consolidated Combined Statements of Cash Flows for the Six Months Ended June 30, 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		52
Item 3. Quantitative and Qualitative Disclosures About Market Risk		77
Item 4. Controls and Procedures		81
PART II. OTHER INFORMATION
Item 6. Exhibits		82
SIGNATURES		87

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PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

	June 30,		December 31,
	2012		2011
ASSETS
Current assets:
Cash and cash equivalents	$	32,697	$	77,376
Accounts receivable		117,427		136,853
Current portion of derivative asset		53,470		15,447
Subscriptions receivable		—		34,455
Prepaid expenses and other		19,004		24,779
Total current assets		222,598		288,910
Property, plant and equipment, net		2,457,539		2,093,283
Intangible assets, net		113,111		104,777
Investment in joint venture		86,092		86,879
Goodwill, net		31,784		31,784
Long-term derivative asset		49,233		30,941
Other assets, net		53,638		48,197
	$	3,013,995	$	2,684,771
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current portion of long-term debt	$	3,908	$	2,085
Accounts payable		64,437		93,554
Liabilities associated with drilling contracts		18,757		71,719
Accrued producer liabilities		56,494		88,096
Current portion of derivative payable to Drilling Partnerships		15,880		20,900
Accrued interest		2,186		1,629
Accrued well drilling and completion costs		34,936		17,585
Accrued liabilities		56,107		61,653
Total current liabilities		252,705		357,221
Long-term debt, less current portion		853,065		522,055
Long-term derivative payable to Drilling Partnerships		8,508		15,272
Asset retirement obligations and other		58,638		46,142
Commitments and contingencies
Partners’ Capital:
Common limited partners’ interests		438,011		554,999
Accumulated other comprehensive income		22,247		29,376
		460,258		584,375
Non-controlling interests		1,380,821		1,159,706
Total partners’ capital		1,841,079		1,744,081
	$	3,013,995	$	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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenues:
Gas and oil production	$	19,460		$	17,723		$	36,624		$	35,349
Well construction and completion		12,241			10,954			55,960			28,679
Gathering and processing		256,542			345,734			561,762			625,952
Administration and oversight		1,315			1,375			4,146			2,736
Well services		5,252			4,855			10,258			10,141
Gain (loss) on mark-to-market derivatives		67,847			6,837			55,812			(14,808	)
Other, net		504			21,414			3,305			25,767
Total revenues		363,161			408,892			727,867			713,816
Costs and expenses:
Gas and oil production		4,447			4,042			8,952			7,963
Well construction and completion		10,606			9,284			48,301			24,305
Gathering and processing		213,673			293,471			465,597			530,455
Well services		2,414			1,674			4,844			4,034
General and administrative		37,607			22,239			74,855			38,429
Depreciation, depletion and amortization		32,534			27,370			62,484			53,977
Total costs and expenses		301,281			358,080			665,033			659,163
Operating income		61,880			50,812			62,834			54,653
Gain (loss) on asset sales and disposal		(16	)		(233	)		(7,021	)		255,714
Interest expense		(10,294	)		(6,567	)		(19,385	)		(24,645	)
Loss on early extinguishment of debt		—			(19,574	)		—			(19,574	)
Income from continuing operations		51,570			24,438			36,428			266,148
Discontinued operations:
Loss from discontinued operations		—			—			—			(81	)
Net income		51,570			24,438			36,428			266,067
Income attributable to non-controlling interests		(59,191	)		(7,925	)		(62,556	)		(219,303	)
Income (loss) after non-controlling interests		(7,621	)		16,513			(26,128	)		46,764
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	$	(7,621	)	$	16,513		$	(26,128	)	$	42,053
Net income (loss) attributable to common limited partners per unit – basic:
Income (loss) from continuing operations attributable to common limited partners	$	(0.15	)	$	0.31		$	(0.51	)	$	0.91
Loss from discontinued operations attributable to common limited partners		—			—			—			—
Net income (loss) attributable to common limited partners	$	(0.15	)	$	0.31		$	(0.51	)	$	0.91
Net income (loss) attributable to common limited partners per unit – diluted:
Income (loss) from continuing operations attributable to common limited partners	$	(0.15	)	$	0.30		$	(0.51	)	$	0.89
Loss from discontinued operations attributable to common limited partners		—			—			—			—
Net income (loss) attributable to common limited partners	$	(0.15	)	$	0.30		$	(0.51	)	$	0.89
Weighted average common limited partner units outstanding:
Basic		51,318			51,235			51,306			45,156
Diluted		51,318			52,965			51,306			46,143
Income (loss) attributable to common limited partners:
Income (loss) from continuing operations	$	(7,621	)	$	16,513		$	(26,128	)	$	42,063
Loss from discontinued operations		—			—			—			(10	)
Net income (loss) attributable to common limited partners	$	(7,621	)	$	16,513		$	(26,128	)	$	42,053

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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Net income	$	51,570		$	24,438		$	36,428		$	266,067
Income attributable to non-controlling interests		(59,191	)		(7,925	)		(62,556	)		(219,303	)
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		(7,621	)		16,513			(26,128	)		42,053
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges		(514	)		6,407			13,655			6,849
Less: reclassification adjustment for realized gains in net income (loss)		(5,631	)		126			(7,085	)		(5,904	)
Changes in non-controlling interest related to items in other comprehensive income (loss)		(4,569	)		(1,490	)		(13,699	)		(2,954	)
Total other comprehensive income (loss)		(10,714	)		5,043			(7,129	)		(2,009	)
Comprehensive income (loss) attributable to common unitholders	$	(18,335	)	$	21,556		$	(33,257	)	$	40,044

See accompanying notes to consolidated combined financial statements

5

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in thousands, except unit data)

(Unaudited)

						Accumulated
	Common Limited Partners’ Capital					Other Comprehensive			Non- Controlling			Total Partners’
	Units		Amount			Income			Interest			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		—		—			—			(53,584	)		(53,584	)
Unissued common units under incentive plan		—		8,817			—			6,839			15,656
Issuance of units under incentive plans		45,232		97			—			77			174
Non-controlling interests’ capital contribution		—		—			—			119,389			119,389
Atlas Pipeline Partners L.P. purchase and retirement of treasury stock		—		—			—			(695	)		(695	)
Distributions paid to common limited partners		—		(25,140	)		—			—			(25,140	)
Distribution equivalent rights paid on unissued units under incentive plans		—		(977	)		—			(823	)		(1,800	)
Gain on sale of subsidiary units		—		11,235			—			(11,235	)		—
Other comprehensive income (loss)		—		—			(7,129	)		13,699			6,570
Net income (loss)		—		(26,128	)		—			62,556			36,428
Balance at June 30, 2012		51,323,594	$	438,011		$	22,247		$	1,380,821		$	1,841,079

See accompanying notes to consolidated combined financial statements

6

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Six Months Ended June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	36,428		$	266,067
Loss from discontinued operations		—			(81	)
Income from continuing operations		36,428			266,148
Adjustments to reconcile net income from continuing operations to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		62,484			53,977
Amortization of deferred finance costs		2,954			7,233
Non-cash (gain) loss on derivative value, net		(61,401	)		47,725
Non-cash compensation expense		15,835			6,130
(Gain) loss on asset sales and disposal		7,021			(255,714	)
Loss on early extinguishment of debt		—			19,574
Distributions paid to non-controlling interests		(54,407	)		(38,642	)
Equity income in unconsolidated companies		(3,330	)		(20,956	)
Distributions received from unconsolidated companies		3,992			16,083
Changes in operating assets and liabilities:
Accounts receivable and prepaid expenses and other		59,656			(33,337	)
Accounts payable and accrued liabilities		(93,917	)		(9,877	)
Net cash provided by (used in) continuing operating activities		(24,685	)		58,344
Net cash used in discontinued operating activities		—			(81	)
Net cash provided by (used in) operating activities		(24,685	)		58,263
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(192,040	)		(106,351	)
Net cash paid for acquisitions		(241,925	)		—
Investments in unconsolidated companies		—			(97,250	)
Net proceeds from asset disposals		—			411,520
Other		1,049			(1,903	)
Net cash provided by (used in) investing activities		(432,916	)		206,016
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facilities		648,500			457,000
Repayments under credit facilities		(316,000	)		(384,500	)
Repayments of long-term debt		—			(314,962	)
Payment of premium on early retirement of debt		—			(14,352	)
Net proceeds from subsidiary equity offerings		119,389			—
Redemption of Atlas Pipeline Partners, L.P.’s preferred units		—			(8,000	)
Distributions paid to unitholders		(25,140	)		(7,583	)
Net transaction adjustment related to the acquisition of the Transferred Business (see Note 3)		—			120,913
Deferred financing costs and other		(13,827	)		(4,350	)
Net cash provided by (used in) financing activities		412,922			(155,834	)
Net change in cash and cash equivalents		(44,679	)		108,445
Cash and cash equivalents, beginning of year		77,376			247
Cash and cash equivalents, end of period	$	32,697		$	108,692

See accompanying notes to consolidated combined financial statements

7

ATLAS ENERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED COMBINED FINANCIAL STATEMENTS

June 30, 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 June 30, 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 June 30, 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 63.7% limited partner interest in ARP (see Note 18);

• 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 June 30, 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 June 30, 2012, the Partnership had an approximate 16% general partner interest and 12% limited partner interest in Lightfoot (see Note 7).

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. 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 and six months ended June 30, 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 June 30, 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

8

financial statements of ARP and APL into its consolidated combined financial statements rather than present its ownership 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 acquisition method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable assets and liabilities of the Transferred Business based upon their fair values with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital on the Partnership’s consolidated combined balance sheets. Also, in comparison to the acquisition method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in 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 six months ended June 30, 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 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.

9

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 and six months ended June 30, 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 June 30, 2012 and December 31, 2011, ARP and APL had recorded no allowance for uncollectible accounts receivable on the Partnership’s consolidated combined balance sheets.

Inventory

ARP and APL had $11.0 million and $16.0 million of inventory at June 30, 2012 and December 31, 2011, respectively, which were included within prepaid expenses and other current assets on the Partnership’s consolidated combined balance sheets. ARP values inventories at the lower of cost or market. ARP’s inventories, which consist of materials, pipes, supplies and other inventories, were principally determined using the average cost method. APL’s crude oil and refined product inventory costs consists of APL’s natural gas liquids line fill, which represents amounts receivable for natural gas liquids (“NGL’s”) delivered to counterparties for which the counterparty will pay at a designated later period at a price determined by the then market price.

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements which generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in 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 are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas.

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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.

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

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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 and six months ended June 30, 2012 and 2011.

Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 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. There were no impairments of proved gas and oil properties recorded by ARP for the three and six months ended June 30, 2012 and 2011.

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 5.8% and 7.3% for the three months ended June 30, 2012 and 2011, respectively, and 6.2% and 7.1% for the six months ended June 30, 2012 and 2011, respectively. The aggregate amounts of interest capitalized by ARP and APL were $2.3 million and $1.1 million for the three months ended June 30, 2012 and 2011, respectively, and $4.6 million and $1.5 million for the six months ended June 30, 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 of 14 years. APL completed the acquisition of two gas gathering systems in June 2012 and recognized $9.6 million related to customer contracts with an estimated useful life of 10 years. The initial recording of these transactions was based upon preliminary valuation assessments and is subject to change.

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 method over their respective estimated useful lives.

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The following table reflects the components of intangible assets being amortized at June 30, 2012 and December 31, 2011 (in thousands):

	June 30, 2012			December 31, 2011			Estimated Useful Lives In Years
Gross Carrying Amount:
Customer contracts and relationships	$	225,543		$	205,313		2 – 14
Partnership management and operating contracts		14,344			14,344		13
	$	239,887		$	219,657
Accumulated Amortization:
Customer contracts and relationships	$	(113,841	)	$	(102,037	)
Partnership management and operating contracts		(12,935	)		(12,843	)
	$	(126,776	)	$	(114,880	)
Net Carrying Amount:
Customer contracts and relationships	$	111,702		$	103,276
Partnership management and operating contracts		1,409			1,501
	$	113,111		$	104,777

Amortization expense on intangible assets was $6.0 million for both the three months ended June 30, 2012 and 2011 and $11.9 million for both the six months ended June 30, 2012 and 2011. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2012—$24.4 million; 2013—$25.0 million; 2014—$21.4 million; 2015—$16.4 million; and 2016—$16.4 million.

Goodwill

At June 30, 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 and six months ended June 30, 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 and six months ended June 30, 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 9).

Derivative Instruments

ARP and APL enter into certain financial contracts to manage their exposure to movement in commodity prices and interest rates (see Note 10). The derivative instruments recorded in the consolidated combined balance sheets were measured as either an asset or liability at fair value. Changes in 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.

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Asset Retirement Obligations

ARP recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 8). 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 16).

Net Income (Loss) Per Common Unit

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

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

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Continuing operations:
Net income	$	51,570		$	24,438		$	36,428		$	266,148
Income attributable to non-controlling interests		(59,191	)		(7,925	)		(62,556	)		(219,374	)
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		(7,621	)		16,513			(26,128	)		42,063
Less: Net income attributable to participating securities – phantom units(1)		—			(512	)		—			(820	)
Net income (loss) utilized in the calculation of net income (loss) from continuing operations attributable to common limited partners per unit	$	(7,621	)	$	16,001		$	(26,128	)	$	41,243
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 and six months ended June 30, 2012, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 2,101,083 and 2,015,017 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.

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Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (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 16).

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

	Three Months Ended June  30,				Six Months Ended June 30,
	2012		2011		2012		2011
Weighted average number of common limited partners per unit—basic		51,318		51,235		51,306		45,156
Add effect of dilutive incentive awards(1)		—		1,730		—		987
Weighted average number of common limited partners per unit—diluted		51,318		52,965		51,306		46,143

⁽¹⁾ For the three and six months ended June 30, 2012, approximately 3,084,000 units and 2,673,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive.

Revenue Recognition

Atlas Resource. 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 and NGLs, 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:

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• 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 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 June 30, 2012 and December 31, 2011 of $69.1 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 include 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.

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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 (loss) 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 10). 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 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 11). The adoption had no material impact on the Partnership’s financial position or results of operations.

Recently Issued Accounting Standards

In July 2012, the FASB issued ASU 2012-02, Intangibles – Goodwill and Other (Topic 350): Testing Indefinite- Lived Intangible Assets for Impairment (“Update 2012-02”). The amendments in Update 2012-02 allow an entity to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. The “more likely than not” threshold is defined as having a likelihood of more than 50 percent. If, after assessing qualitative factors, an entity determines it is not likely that the indefinite-lived intangible asset is impaired, then no further action is required. If impairment is deemed more likely than not, the entity is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount of the asset. Additionally, under the amendments in Update 2012-02, an entity has the option to bypass the qualitative assessment for any indefinite-lived intangible asset in any period and proceed directly to performing the quantitative impairment test. An entity will be able to resume performing the qualitative assessment in any subsequent period. The amendments are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption being permitted. The Partnership will apply the requirements of Update 2012-02 upon its effective date of January 1, 2013, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

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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; and

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

In addition to the exploration and production assets, the Transferred Business also included all of the ownership interests in Atlas Energy GP, LLC, 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 June 30, 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 13). Including the cash transaction adjustment, the net book value of the Transferred Business was approximately $522.9 million.

Concurrent with the Partnership’s acquisition of the Transferred Business 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 5). 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 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

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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 – ARP ACQUISITION

On April 30, 2012, ARP acquired certain oil and natural gas assets from Carrizo Oil and Gas, Inc. (NASDAQ: CRZO; “Carrizo”) for approximately $187.0 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 was funded through borrowings under ARP’s credit facility and $119.5 million of net proceeds from the sale of 6.0 million of its common units at a negotiated purchase price per unit of $20.00, of which $5.0 million was purchased by certain executives of the Partnership. The common units were issued in a private placement exempt from registration under Section 4(2) of the Securities Act of 1933, as amended (see Note 14).

ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). All costs associated with the acquisition of assets were expensed as incurred. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as ARP continues to evaluate the facts and circumstances that existed as of the acquisition date.

The following table presents the preliminary values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands):

Assets:
Natural gas and oil properties	$	190,946
Liabilities:
Asset retirement obligation		3,903
Net assets acquired	$	187,043

The following data presents pro forma revenues, net income (loss) and basic and diluted net income (loss) per unit for the Partnership as if the Carrizo acquisition, including the borrowings under ARP’s credit facility and private placement of ARP’s common units, had occurred on January 1, 2011. The Partnership prepared these pro forma unaudited financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the acquisition had occurred on January 1, 2011 or the results that will be attained in future periods (in thousands, except per share data; unaudited):

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	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
Total revenues and other	$	364,352		$	422,445	$	734,745		$	739,272
Net income (loss)		47,062			27,672		29,444			271,412
Net income (loss) attributable to common limited partners		(9,911	)		19,747		(29,695	)		47,398
Net income (loss) attributable to common limited partners per unit:
Basic	$	(0.19	)	$	0.37	$	(0.58	)	$	1.03
Diluted	$	(0.19	)	$	0.36	$	(0.58	)	$	1.01

NOTE 5 – 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. The Partnership recognizes APL’s 20% interest in West Texas LPG as an investment in joint venture on its consolidated combined balance sheets. At the acquisition date, the carrying value of the 20% interest in West Texas LPG exceeded APL’s share of the underlying net assets of West Texas LPG by approximately $49.9 million, which related to the fair value of the property, plant and equipment in excess of book value. This excess will be depreciated over approximately 38 years. 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 and six months ended June 30, 2012, APL recognized $1.9 million and $2.8 million of equity income within other, net on the Partnership’s consolidated combined statements of operations related to its West Texas LPG interest. During the three and six months ended June 30, 2011, APL recognized $0.7 million of equity income 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, net on the Partnership’s consolidated combined statements of operations, APL did not reclassify the earnings or the gain on sale related to Laurel Mountain to discontinued operations upon the sale of its ownership interest. The Partnership recognized a loss of $0.3 million and a net gain of $255.7 million during the three and six months ended June 30, 2011, respectively, which is included in gain (loss) on asset sales and 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 June  30,				Six Months Ended June 30,
	2012		2011		2012		2011
Equity income in Laurel Mountain	$	—	$	—	$	—	$	462
Equity income in WTLPG		1,917		687		2,813		687
Equity income in joint ventures	$	1,917	$	687	$	2,813	$	1,149

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NOTE 6 – PROPERTY, PLANT AND EQUIPMENT

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

							Estimated
	June 30,			December 31,			Useful Lives
	2012			2011			in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	131,734		$	61,587
Pre-development costs		1,328			2,540
Wells and related equipment		1,003,930			828,780
Total proved properties		1,136,992			892,907
Unproved properties		40,805			43,253
Support equipment		10,714			9,413
Total natural gas and oil properties		1,188,511			945,573
Pipelines, processing and compression facilities		1,799,857			1,646,320			2 – 40
Rights of way		173,908			161,275			20 – 40
Land, buildings and improvements		23,820			23,416			3 – 40
Other		25,036			22,734			3 – 10
		3,211,132			2,799,318
Less – accumulated depreciation, depletion and amortization		(753,593	)		(706,035	)
	$	2,457,539		$	2,093,283

In March 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 during the six months ended June 30, 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 7 – OTHER ASSETS

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

	June 30,		December 31,
	2012		2011
Deferred financing costs, net of accumulated amortization of $22,285 and $19,331 at June 30, 2012 and December 31, 2011, respectively	$	29,154	$	23,426
Investment in Lightfoot		19,398		19,514
Security deposits		2,532		4,584
Other		2,554		673
	$	53,638	$	48,197

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 9). Amortization expense of deferred finance costs was $1.6 million and $1.3 million for the three months ended June 30, 2012 and 2011, respectively, and $3.0 million and $2.6 million for the six months ended June 30, 2012 and 2011, respectively, which is recorded within interest expense on the Partnership’s consolidated combined statements of operations. During the three and six months ended June 30, 2011, APL recognized $5.2 million of accelerated amortization of deferred financing costs associated with the retirement of its 8.125% Senior Notes and partial redemption of its 8.75% Senior Notes, which is recorded within loss on early extinguishment of debt on the Partnership’s consolidated combined statements of operations. In March 2011, the Partnership recognized an additional $4.9 million of accelerated amortization of its deferred financing costs associated with the retirement of its $70.0 million credit facility, which is recorded within interest expense on the Partnership’s consolidated combined statements of operations.

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At June 30, 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 and six months ended June 30, 2012, the Partnership recorded equity income of $0.2 million and $0.5 million, respectively. The equity income was recorded within other, net on the Partnership’s consolidated combined statements of operations. During the three and six months ended June 30, 2012, the Partnership received net cash distributions of $0.2 million and $0.4 million, respectively. During the three months ended June 30, 2011, the Partnership recognized a gain associated with its equity ownership interest in Lightfoot of $17.6 million pertaining to its share of Lightfoot LP’s gain recognized on the sale of International Resource Partners LP (“IRP”), its metallurgical and steam coal business, in March 2011. This gain was recorded within other, net on the Partnership’s consolidated combined statements of operations. Additionally, the Partnership received a net cash distribution of $13.7 million, representing its share of the cash distribution made to investors by Lightfoot LP with proceeds from the IRP sale.

NOTE 8 – ASSET RETIREMENT OBLIGATIONS

ARP recognized an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities. ARP also recognized 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 was 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 was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. 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 determined that there were 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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Asset retirement obligations, beginning of period	$	46,538		$	43,315		$	45,779		$	42,673
Liabilities incurred		3,911			—			4,092			93
Liabilities settled		(132	)		(33	)		(250	)		(132	)
Accretion expense		729			650			1,425			1,298
Asset retirement obligations, end of period	$	51,046		$	43,932		$	51,046		$	43,932

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. During the three and six months ended June 30, 2012, ARP incurred $3.9 million of future plugging and abandonment costs related to the acquisition of assets from Carrizo (see Note 4).

NOTE 9 – DEBT

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

	June 30,		December 31,
	2012		2011
ARP revolving credit facility	$	144,000	$	—
APL revolving credit facility		330,500		142,000
APL 8.75 % Senior Notes – due 2018		370,584		370,983

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APL capital leases		11,889			11,157
Total debt		856,973			524,140
Less current maturities		(3,908	)		(2,085	)
Total long-term debt	$	853,065		$	522,055

Partnership’s Credit Facility

In May 2012, the Partnership entered into a new credit facility with a syndicate of banks that matures in May 2016. The credit facility has maximum lender commitments of $50.0 million, and up to $5.0 million of the credit facility may be in the form of standby letters of credit. At June 30, 2012, no amounts were outstanding under the credit facility. The Partnership’s obligations under the credit facility are secured by substantially all of its assets, including its ownership interests in APL and ARP. Additionally, the Partnership’s obligations under the credit facility may be guaranteed by future subsidiaries. At the Partnership’s election, interest on borrowings under the credit facility is determined by reference to either LIBOR plus an applicable margin of between 3.50% and 4.50% per annum or the base rate plus an applicable margin of between 2.50% and 3.50% per annum. The applicable margin will fluctuate based on the utilization of the facility. The Partnership is required to pay a fee between 0.5% and 0.625% per annum on the unused portion of the borrowing base, which is included within interest expense on the Partnership’s consolidated combined statement of operations.

The credit agreement contains customary covenants that limit the Partnership’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a commitment deficiency exists or a default under the credit agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that 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 the Partnership’s assets.

The credit agreement also contains covenants that require the Partnership to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to EBITDA (as defined in the credit agreement) not greater than 3.25 to 1.0 as of the last day of any fiscal quarter and a ratio of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) not less than 2.75 to 1.0 as of the last day of any fiscal quarter.

At June 30, 2012, the Partnership has not guaranteed any of ARP’s or APL’s debt obligations.

ARP’s Credit Facility

At June 30, 2012, ARP had a senior secured credit facility with a syndicate of banks with a borrowing base of $250.0 million with $144.0 million outstanding (see Note 18). The credit facility matures in March 2016 and the borrowing base will be redetermined semi-annually in May and November. Up to $20.0 million of the credit facility may be in the form of standby letters of credit which would reduce ARP’s borrowing capacity, of which $0.6 million was outstanding at June 30, 2012, and 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 3.00% 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 2.00%. 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 June 30, 2012, the weighted average interest rate was 3.1%.

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 June 30, 2012. The credit agreement also requires ARP to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to four quarters (actual or annualized, as applicable) of EBITDA (as defined in the credit agreement) not greater than 3.75 to 1.0 as of the last day of any fiscal quarter, a ratio of current assets (as defined in the credit agreement) to current liabilities (as defined in the credit agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter, and a ratio of four quarters (actual or annualized, as applicable) of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) of not less than 2.5 to 1.0 as of the last day of any fiscal quarter. Based on the definitions contained in ARP’s credit facility, its ratio of current assets to current liabilities was 1.4 to 1.0, its ratio of Total Funded Debt to EBITDA was 1.6 to 1.0 and its ratio of EBITDA to Consolidated Interest Expense was 38.1 to 1.0 at June 30, 2012.

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APL Credit Facility

At June 30, 2012, APL had a $600.0 million senior secured revolving credit facility with a syndicate of banks, which matures in May 2017, of which $330.5 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 1.00%, or (ii) the LIBOR rate for the applicable period (each plus the applicable margin). The weighted average interest rate on APL’s outstanding revolving credit facility borrowings at June 30, 2012 was 2.7%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $0.1 million was outstanding at June 30, 2012. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated combined balance sheet at June 30, 2012. At June 30, 2012, APL had $269.4 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.

At May 31, 2012, APL entered into an amendment to its revolving credit facility agreement, which among other changes:

• increased the revolving credit facility from $450.0 million to $600.0 million;

• extended the maturity date from December 22, 2015 to May 31, 2017;

• reduced the applicable margin used to determine interest rates by 0.50%;

• revised the negative covenants to (i) permit investments in joint ventures equal to the greater of 20.0% of “Consolidated Net Tangible Assets” (as defined in APL’s credit agreement) or $340.0 million, provided APL meets certain requirements, and (ii) increased the general investment basket to 5.0% of “Consolidated Net Tangible Assets”;

• revised the definition of “Consolidated EBITDA” to provide for the inclusion of the first twelve months of projected revenues for identified capital expansion projects, upon completion of the projects and contingent upon prior approval by the administrative agent. The addition from any such projects, in the aggregate, may not exceed 15.0% of unadjusted Consolidated EBITDA; and

• provided for the option of additional revolving credit commitments of up to $200.0 million, upon request by APL.

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 June 30, 2012.

APL Senior Notes

At June 30, 2012, APL had $370.6 million principal amount outstanding of 8.75% senior unsecured notes, including a net $4.8 million unamortized premium, 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.

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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 5).

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 June 30, 2012.

APL Capital Leases

At June 30, 2012 and December 31, 2011, APL had $11.9 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 six months ended June 30, 2012, APL recognized $1.9 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 6) (in thousands):

	June 30, 2012			December 31, 2011
Pipelines, processing and compression facilities	$	14,512		$	12,507
Less – accumulated depreciation		(695	)		(199	)
	$	13,817		$	12,308

Depreciation expense for leased properties was $0.2 million and $0.4 million for the three and six months ended June 30, 2012, respectively. Depreciation expense for leased properties was not material for the three and six months ended June 30, 2011. Depreciation expense for leased properties is included within depreciation and amortization expense on the Partnership’s consolidated combined statements of operations.

As of June 30, 2012, future minimum lease payments related to the capital leases are as follows (in thousands):

	Capital Lease Minimum Payments
2012	$	1,665
2013		10,879
2014		64
2015		—
2016		—
Thereafter		—
Total minimum lease payments		12,608
Less amounts representing interest		(719	)
Present value of minimum lease payments		11,889
Less current capital lease obligations		(3,908	)
Long-term capital lease obligations	$	7,981

Cash payments for interest for the Partnership and its subsidiaries were $19.5 million and $18.6 million for the six months ended June 30, 2012 and 2011, respectively.

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NOTE 10 — 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, 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.

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 $102.6 million and $46.4 million at June 30, 2012 and December 31, 2011, respectively. Of the $22.2 million of net gain in accumulated other comprehensive income within partners’ capital on the Partnership’s consolidated combined balance sheet related to derivatives at June 30, 2012, if the fair values of the instruments remain at current market values, the Partnership will reclassify $8.1 million of gains to its consolidated combined statement of operations over the next twelve month period as these contracts expire, consisting of $8.4 million of gains to gas and oil production revenues and $0.3 million of losses to gathering and processing revenues. Aggregate gains of $14.1 million to gas and oil production revenues will be reclassified to the Partnership’s consolidated combined statements of operations in later periods as these remaining contracts expire. Actual amounts that will be reclassified will vary as a result of future price changes.

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 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):

26

Offsetting Derivative Assets	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
As of June 30, 2012
Current portion of derivative assets	$	17,098		$	(971	)	$	16,127
Long-term portion of derivative assets		24,177			(4,623	)		19,554
Long-term portion of derivative liabilities		26			(26	)		—
Total derivative assets	$	41,301		$	(5,620	)	$	35,681
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
Offsetting Derivative Liabilities	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
As of June 30, 2012
Current portion of derivative assets	$	(971	)	$	971		$	—
Long-term portion of derivative assets		(4,623	)		4,623			—
Long-term portion of derivative liabilities		(154	)		26			(128	)
Total derivative liabilities	$	(5,748	)	$	5,620		$	(128	)
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		$	—

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Gain (loss) recognized in accumulated OCI	$	(514	)	$	6,407		$	13,655		$	6,849
Gain reclassified from accumulated OCI into income	$	(6,739	)	$	(1,578	)	$	(9,339	)	$	(9,309	)

ARP enters into commodity future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. 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 provided the option to enter into swap contracts (“swaptions”) up through May 31, 2012 for production volumes related to wells acquired from Carrizo (see Note 4). In connection with the swaption contracts, ARP paid premiums of $4.6 million, which represented the fair value of contracts on the date of the transaction and was initially recorded as a derivative asset on the Partnership’s consolidated combined balance sheet and was fully amortized as of June 30, 2012. For the three and six months ended June 30, 2012, ARP recorded approximately $3.6 million and $4.6 million, respectively, of amortization expense in other, net on the Partnership’s consolidated combined statements of operations related to the swaption contracts.

27

In June 2012, ARP received approximately $3.9 million in net proceeds from the early termination of natural gas and oil derivative positions for production periods from 2015 through 2016. In conjunction with the early termination of these derivatives, ARP entered into new derivative positions at prevailing prices at the time of the transaction. The net proceeds from the early termination of these derivatives were used to reduce indebtedness under ARP’s credit facility (see Note 9). The gain recognized upon the early termination of these derivative positions will continue to be reported in accumulated other comprehensive income and will be reclassified into the Partnership’s consolidated statements of operations in the same periods in which the hedged production revenues would have been recognized in earnings.

ARP recognized gains of $6.7 million and $1.6 million for the three months ended June 30, 2012 and 2011, respectively, and $9.3 million for both the six months ended June 30, 2012 and 2011 on settled contracts covering commodity production. These gains were 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 and six months ended June 30, 2012 and 2011 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

At June 30, 2012, ARP had the following commodity derivatives:

Natural Gas Fixed Price Swaps

					Asset/(Liability)
Production Period Ending	Volumes		Average Fixed Price		Fair Value Asset
December 31,	(mmbtu)(1)		(per mmbtu)(1)		(in thousands)(2)
2012		9,060,000	$	3.550	$	5,347
2013		11,160,000	$	4.076		5,499
2014		10,800,000	$	4.373		4,569
2015		7,350,000	$	4.430		2,135
					$	17,550

Natural Gas Costless Collars

Production Period Ending	Option Type	Volumes		Average Floor and Cap		Fair Value Asset/(Liability)
December 31,		(mmbtu)(1)		(per mmbtu)(1)		(in thousands)(2)
2012	Puts purchased		2,160,000	$	4.074	$	2,506
2012	Calls sold		2,160,000	$	5.279		(22	)
2013	Puts purchased		5,520,000	$	4.395		5,768
2013	Calls sold		5,520,000	$	5.443		(538	)
2014	Puts purchased		3,840,000	$	4.221		3,004
2014	Calls sold		3,840,000	$	5.120		(1,072	)
2015	Puts purchased		3,480,000	$	4.234		2,903
2015	Calls sold		3,480,000	$	5.129		(1,594	)
						$	10,955

Natural Gas Put Options

						Asset/(Liability)
Production Period Ending	Option Type	Volumes		Average Fixed Price		Fair Value Asset
December 31,		(mmbtu)(1)		(per mmbtu)(1)		(in thousands)(2)
2012	Puts purchased		2,940,000	$	2.802	$	522
2013	Puts purchased		3,180,000	$	3.450		1,262
2014	Puts purchased		1,800,000	$	3.800		933
2015	Puts purchased		1,440,000	$	4.000		978
2016	Puts purchased		1,440,000	$	4.150		1,178
						$	4,873

28

Crude Oil Fixed Price Swaps

Production			Average		Fair Value
Period Ending	Volumes		Fixed Price		Asset
December 31,	(Bbl)(1)		(per Bbl)(1)		(in thousands)(3)
2012		13,500	$	103.804	$	286
2013		18,600	$	100.669		227
2014		36,000	$	97.693		355
2015		45,000	$	89.504		114
					$	982

Crude Oil Costless Collars

Production Period Ending		Volumes		Average Floor and  Cap		Fair Value Asset/(Liability)
December 31,	Option Type	(Bbl)(1)		(per Bbl)(1)		(in thousands)(3)
2012	Puts purchased		30,000	$	90.000	$	274
2012	Calls sold		30,000	$	117.912		(18	)
2013	Puts purchased		60,000	$	90.000		693
2013	Calls sold		60,000	$	116.396		(173	)
2014	Puts purchased		41,160	$	84.169		471
2014	Calls sold		41,160	$	113.308		(217	)
2015	Puts purchased		29,250	$	83.846		365
2015	Calls sold		29,250	$	110.654		(202	)
						$	1,193
Total ARP net asset						$	35,553

⁽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 with Chevron on February 17, 2011, AEI monetized 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 June 30, 2012, remaining hedge monetization cash proceeds of $20.2 million related to the amounts hedged on behalf of the Drilling Partnerships’ limited partners were included within cash and cash equivalents on the Partnership’s consolidated balance sheet, 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 Partnership reflected the remaining hedge monetization proceeds within current and long-term portion of derivative payable to Drilling Partnerships on its consolidated combined balance sheets as of June 30, 2012 and December 31, 2011.

In June 2012, ARP entered into natural gas put option contracts which related to future natural gas production of the Drilling Partnerships. Therefore, a portion of any unrealized derivative gain or loss is allocable to the limited partners of the Drilling Partnerships based on their share of estimated gas production related to the derivatives not yet settled. At June 30, 2012, net unrealized derivative assets of $4.2 million were payable to the limited partners in the Drilling Partnerships related to these natural gas put option contracts.

The derivatives payable to the Drilling Partnerships related to both the hedge monetization proceeds and future natural gas production of the Drilling Partnerships at June 30, 2012 and December 31, 2011 were included in the Partnership’s consolidated combined balance sheets as follows (in thousands):

	June 30,			December 31,
	2012			2011
Current portion of derivative payable to Drilling Partnerships:
Hedge monetization proceeds	$	(15,210	)	$	(20,900	)
Hedge contracts covering future natural gas production		(670	)		—
Long-term portion of derivative payable to Drilling Partnerships:
Hedge monetization proceeds		(4,975	)		(15,272	)
Hedge contracts covering future natural gas production		(3,533	)		—
	$	(24,388	)	$	(36,172	)

29

At June 30, 2012, ARP had a secured hedge facility agreement with a syndicate of banks under which certain 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 9), ARP is required to utilize this secured hedge facility for future commodity risk management activity for its equity production volumes within the participating Drilling Partnerships. ARP, as general partner of the Drilling Partnerships, will administer the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnerships’ ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets.

Atlas Pipeline Partners

For the three and six months ended June 30, 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):

Offsetting of Derivative Assets	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
As of June 30, 2012
Current portion of derivative assets	$	38,366		$	(1,023	)	$	37,343
Long-term portion of derivative assets		30,098			(419	)		29,679
Total derivative assets	$	68,464		$	(1,442	)	$	67,022
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
Offsetting of Derivative Liabilities	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
As of June 30, 2012
Current portion of derivative liabilities	$	(1,023	)	$	1,023		$	—
Long-term portion of derivative liabilities		(419	)		419			—
Total derivative liabilities	$	(1,442	)	$	1,442		$	—
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		$	—

30

As of June 30, 2012, APL had the following commodity derivatives:

Fixed Price Swaps

	Purchased/					Average Fixed		Fair Value(1) Asset/(Liability)
Production Period	Sold		Commodity	Volumes(2)		Price		(in thousands)
Natural Gas
2012		Sold	Natural Gas		2,460,000	$	3.117	$	415
2013		Sold	Natural Gas		1,200,000	$	3.476		(59	)
2014		Sold	Natural Gas		5,400,000	$	3.903		(228	)
NGLs
2012		Sold	Propane		10,080,000	$	1.300		4,546
2012		Sold	Normal Butane		2,646,000	$	1.709		1,103
2012		Sold	Isobutane		1,512,000	$	1.577		203
2012		Sold	Natural Gasoline		2,142,000	$	2.393		1,598
2013		Sold	Propane		46,368,000	$	1.257		17,654
2013		Sold	Normal Butane		2,394,000	$	1.662		805
2013		Sold	Isobutane		1,134,000	$	1.807		370
2014		Sold	Propane		630,000	$	1.268		210
Crude Oil
2012		Sold	Crude Oil		144,000	$	96.093		1,447
2013		Sold	Crude Oil		345,000	$	97.170		3,032
2014		Sold	Crude Oil		60,000	$	98.425		626
Total Fixed Price Swaps								$	31,722

Options

Production	Purchased/								Average Strike		Fair Value(1) Asset/(Liability)
Period	Sold			Type		Commodity	Volumes(2)		Price		(in thousands)
NGLs
2012		Purchased			Put	Propane		15,750,000	$	1.362		8,070
2012		Purchased			Put	Normal Butane		4,032,000	$	1.550		1,094
2012		Purchased			Put	Isobutane		2,142,000	$	1.577		451
2012		Purchased			Put	Natural Gasoline		7,812,000	$	1.997		2,005
2013		Purchased			Put	Normal Butane		10,458,000	$	1.667		4,172
2013		Purchased			Put	Isobutane		4,158,000	$	1.687		1,529
2013		Purchased			Put	Natural Gasoline		23,940,000	$	2.108		9,156
Crude Oil
2012		Sold	(3)		Call	Crude Oil		249,000	$	94.694		(663	)
2012		Purchased	(3)		Call	Crude Oil		90,000	$	125.200		14
2012		Purchased			Put	Crude Oil		78,000	$	106.180		1,618
2013		Purchased			Put	Crude Oil		282,000	$	100.100		4,799
2014		Purchased			Put	Crude Oil		136,500	$	104.750		3,055
Total Options											$	35,300
Total APL net asset											$	67,022

31

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

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

⁽³⁾ Calls purchased for 2012 represent offsetting positions for calls sold as part of costless collars. 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):

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Derivatives previously designated as cash flow hedges
Loss reclassified from accumulated other comprehensive loss into natural gas and liquids sales	$	(1,108	)	$	(1,702	)	$	(2,254	)	$	(3,404	)
Derivatives not designated as hedges
Gain (loss) recognized in gain (loss) on mark-to-market derivatives
Commodity contract—realized(1)		3,685			(6,236	)		2,922			(8,793	)
Commodity contract—unrealized(2)		64,162			13,073			52,890			(6,015	)
Gain (loss) on mark-to-market derivatives	$	67,847		$	6,837		$	55,812		$	(14,808	)

(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):

	June 30,			December 31,
	2012			2011
Current portion of derivative asset	$	53,470		$	15,447
Long-term derivative asset		49,233			30,941
Current portion of derivative liability		—			—
Long-term derivative liability		(128	)		—
Total Partnership net asset	$	102,575		$	46,388

NOTE 11 – 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.

32

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 10). 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 propane, 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. A change in the relationship between these prices would have a direct impact upon the unobservable adjustment utilized to calculate the fair value of the NGL fixed price swaps. 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. These valuations are tested for reasonableness through the use of an internal valuation model.

Information for ARP’s and APL’s assets and liabilities measured at fair value at June 30, 2012 and December 31, 2011 was as follows (in thousands):

	Level 1		Level 2			Level 3		Total
As of June 30, 2012
Derivative assets, gross
ARP Commodity swaps	$	—	$	20,445		$	—	$	20,445
ARP Commodity puts		—		4,872			—		4,872
ARP Commodity options		—		15,984			—		15,984
APL Commodity swaps		—		6,012			26,489		32,501
APL Commodity options		—		9,486			26,477		35,963
Total derivative assets, gross		—		56,799			52,966		109,765
Derivative liabilities, gross
ARP Commodity swaps		—		(1,913	)		—		(1,913	)
ARP Commodity puts		—		—			—		—
ARP Commodity options		—		(3,835	)		—		(3,835	)
APL Commodity swaps		—		(779	)		—		(779	)
APL Commodity options		—		(663	)		—		(663	)
Total derivative liabilities, gross		—		(7,190	)		—		(7,190	)
Total derivatives, fair value, net	$	—	$	49,609		$	52,966	$	102,575
As of December 31, 2011
Derivative assets, gross
ARP Commodity swaps	$	—	$	20,908		$	—	$	20,908
ARP Commodity puts		—		—			—		—
ARP Commodity options		—		14,723			—		14,723
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

33

Derivative liabilities, gross
ARP Commodity swaps		—		—			—			—
ARP Commodity puts		—		—			—			—
ARP Commodity options		—		(5,702	)		—			(5,702	)
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 six months ended June 30, 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)		47,754			—			—			—			—
Cash settlements from unrealized gain (loss)(3)(4)		(30,492	)		(2,852	)		(24,318	)		108			(2,744	)
Net change in unrealized gain (loss)(3)		—			31,074			—			13,285			44,359
Option premium recognition(4)		—			—			—			(5,195	)		(5,195	)
Balance – June 30, 2012		66,906		$	26,489			68,292		$	26,477		$	52,966

⁽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 June 30, 2012 and December 31, 2011 (in thousands):

	Gallons		Third  Party Quotes(1)			Adjustments(2)			Total Amount
As of June 30, 2012
Propane swaps		57,078	$	22,755		$	(345	)	$	22,410
Isobutane swaps		2,646		174			399			573
Normal butane swaps		5,040		1,872			36			1,908
Natural gasoline swaps		2,142		1,893			(295	)		1,598
Total NGL swaps – June 30, 2012		66,906	$	26,694		$	(205	)	$	26,489
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.

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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):

	Level 3 Fair			Adjustment based upon Regression Coefficient
	Value Adjustments			Lower 95%		Upper 95%		Average Coefficient
As of June 30, 2012
Propane swaps	$	(345	)		0.9100		0.9204		0.9152
Isobutane swaps		399			1.1195		1.1285		1.1240
Normal butane swaps		36			0.9926		1.0194		1.0060
Natural gasoline swaps		(295	)		0.9028		0.9149		0.9089
Total NGL swaps – June 30, 2012	$	(205	)
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

APL had $6.3 million and $11.5 million of NGL linefill at June 30, 2012 and December 31, 2011, respectively, which was included within prepaid expenses and other on the Partnership’s consolidated combined balance sheets. The NGL linefill represents amounts receivable for NGLs delivered to counterparties for which the counterparty will pay at a designated later period at a price determined by the then market price. APL’s NGL linefill is defined as a Level 3 asset and is valued using the same forward price curve utilized to value APL’s NGL fixed price swaps. The product/location adjustment based upon the multiple regression analysis, which was included in the value of the linefill, was a reduction of $0.5 million and $0.8 million as of June 30, 2012 and December 31, 2011, respectively.

The following table provides a summary of changes in fair value of APL’s NGL linefill for the six months ended June 30, 2012 (in thousands):

	NGL Linefill
	Gallons			Amount
Balance – December 31, 2011		10,408		$	11,529
Cash settlements		(2,520	)		(2,698	)
Net change in NGL linefill valuation(1)		—			(2,495	)
Balance – June 30, 2012		7,888		$	6,336

(1) Included within gathering and processing revenues on the Partnership’s consolidated combined statements of operations.

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 subsidiaries 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 June 30, 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 $878.3 million and $537.3 million, respectively, compared with the carrying amounts of $857.0 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.

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

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 8). Information for assets that were measured at fair value on a nonrecurring basis for the three and six months ended June 30, 2012 and 2011 were as follows (in thousands):

	Three Months Ended June 30,
	2012				2011
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	3,911	$	3,911	$	—	$	—
Total	$	3,911	$	3,911	$	—	$	—
	Six Months Ended June 30,
	2012				2011
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	4,092	$	4,092	$	93	$	93
Total	$	4,092	$	4,092	$	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 and six months ended June 30, 2012 and 2011 (see Note 6).

In April 2012, ARP completed the acquisition of certain oil and gas assets from Carrizo (see Note 4). The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under ARP’s existing methodology for recognizing an estimated liability for the plugging and abandonment of its gas and oil wells (see Note 8). These inputs require significant judgments and estimates by ARP’s management at the time of the valuation and are subject to change.

In February 2012, APL acquired a gas gathering system and related assets for an initial net purchase price of $19.0 million. APL agreed to pay up to an additional $12.0 million, payable in two equal amounts (“Trigger Payments”), if certain volumes are achieved on the acquired gathering system within a specified time period. The fair value of the Trigger Payments recognized upon acquisition was a $6.0 million current liability, which was recorded within accrued liabilities on the Partnership’s consolidated combined balance sheets and a $6.0 million long-term liability, which was recorded within asset retirement obligations and other on the Partnership’s consolidated combined balance sheets. The initial recording of the transaction was based upon preliminary valuation assessments and is subject to change. The range of the undiscounted amounts APL could pay related to the Trigger Payments is between $0 and $12.0 million.

NOTE 12 – 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.

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ARP’s Joint Venture Agreement with Subsidiaries of Equal Energy, Ltd. In April 2012, ARP acquired a 50% interest in approximately 14,500 net undeveloped acres in the oil and NGL area of the Mississippi Lime play in northwestern Oklahoma for $18.0 million from subsidiaries of Equal Energy, Ltd. (“Equal”) (NYSE: EQU; TSX: EQU). The transaction was funded through borrowings under ARP’s revolving credit facility (see Note 9). Concurrent with the purchase of acreage, ARP and Equal entered into a participation and development agreement for future drilling in the Mississippi Lime play. ARP serves as the drilling and completion operator, while Equal will undertake production operations, including water disposal. Subsequent to the formation of the joint venture, each party can contribute acreage to the joint venture through the establishment of an area of mutual interest closely surrounding Equal’s existing acreage position. ARP proportionately consolidates its 50% ownership interest in the joint venture.

NOTE 13 – 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 June 30, 2012 and 2011, $1.4 million and $1.3 million, respectively, of ARP’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the Drilling Partnerships. For the six months ended June 30, 2012 and 2011, $1.8 million and $2.7 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 June 30, 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 June 30, 2012, the Partnership believes the range of loss associated with the disputed balances is between zero and $45.0 million.

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.

APL has certain long-term unconditional purchase obligations and commitments, consisting primarily of transportation contracts. These agreements provide for transportation services to be used in the ordinary course of APL’s operations. Transportation fees paid related to these contracts were $2.5 million and $2.4 million for three months ended June 30, 2012 and 2011, respectively, and $5.0 million and $4.9 million for six months ended June 30, 2012 and 2011, respectively. The future fixed and determinable portion of APL’s obligations as of June 30, 2012 was as follows: remainder of 2012—$4.1 million; 2013—$8.2 million; and 2014—$6.1 million.

As of June 30, 2012, ARP and APL are committed to expend approximately $108.7 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.

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NOTE 14 – 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

On April 30, 2012, ARP completed the acquisition of certain oil and gas assets from Carrizo (see Note 4). To partially fund the acquisition, ARP sold 6.0 million of its common units in a private placement at a negotiated 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 issued by ARP are subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement stipulated that ARP would (a) file a registration statement with the Securities and Exchange Commission by October 30, 2012 and (b) cause the registration statement to be declared effective by the Securities and Exchange Commission by December 31, 2012. If ARP does not meet the aforementioned deadline for the common units to be declared effective, the common unit holders subject to the registration rights agreement will receive liquidated damages of 0.50% of the gross proceeds from the private placement, or $0.6 million, for the first 30-day period after December 31, 2012, increasing by an additional 0.50% per 30-day period thereafter, up to a maximum of 2.0% of the gross proceeds of the private placement per 30-day period. On July 11, 2012, ARP filed a registration statement with the Securities and Exchange Commission for the common units subject to the registration rights agreement in satisfaction of one of the requirements of the registration rights agreement noted previously. In connection with the private placement of common units, the Partnership recorded an $11.2 million gain within partners’ capital and a corresponding decrease in non-controlling interests on its consolidated combined balance sheet at June 30, 2012.

In February 2012, the board of directors of the Partnership’s general partner approved the distribution of approximately 5.24 million ARP common units which were distributed on March 13, 2012 to the Partnership’s unitholders using a ratio of 0.1021 ARP limited partner units for each of the Partnership’s common units owned on the record date of February 28, 2012. The distribution of these limited partner units represented approximately 20.0% of the common limited partner units outstanding (see Note 1).

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 15 – CASH DISTRIBUTIONS

The Partnership has a cash distribution policy under which it distributes, within 50 days after the end of each quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders. Distributions declared by the Partnership for the period from January 1, 2011 through June 30, 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 Partners
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
May 18, 2012	March 31, 2012	$	0.25	$	12,830

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On July 17, 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 June 30, 2012. The $12.8 million distribution will be paid on August 17, 2012 to unitholders of record at the close of business on August 7, 2012.

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.

Distributions declared by ARP from its formation through June 30, 2012 were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid	For Quarter Ended	ARP Cash Distribution per Common Limited Partner Unit			Total ARP  Cash Distribution to Common Limited Partners		Total ARP  Cash Distribution to the General Partner
							(in thousands)
May 15, 2012	March 31, 2012	$	0.12	(1)	$	3,144	$	64

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

On June 28, 2012, ARP declared a cash distribution of $0.40 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended June 30, 2012. The $13.2 million distribution, including $0.3 million to the Partnership, as general partner, will be paid on August 14, 2012 to unitholders of record at the close of business on July 12, 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 June 30, 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	$	439
August 12, 2011	June 30, 2011	$	0.47	$	25,184	$	967
November 14, 2011	September 30, 2011	$	0.54	$	28,953	$	1,844
February 14, 2012	December 31, 2011	$	0.55	$	29,489	$	2,031
May 15, 2012	March 31, 2012	$	0.56	$	30,030	$	2,217

On July 17, 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 June 30, 2012. The $32.3 million distribution, including $2.2 million to the Partnership, as general partner, will be paid on August 14, 2012 to unitholders of record at the close of business on August 7, 2012.

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NOTE 16 – BENEFIT PLANS

2010 Long-Term Incentive Plan

The Board of Directors of the General Partner approved and adopted the Partnership’s 2010 Long-Term Incentive Plan (“2010 LTIP”) effective February 2011. The 2010 LTIP provides equity incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for the Partnership. The 2010 LTIP is administered by a committee consisting of the Board or committee of the Board or board of an affiliate appointed by the Board (the “LTIP Committee”), which is the Compensation Committee of the General Partner’s board of directors. Under the 2010 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 5,763,781 common limited partner units. At June 30, 2012, the Partnership had 4,646,139 phantom units and unit options outstanding under the 2010 LTIP, with 1,110,416 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 the Partnership’s 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 the Partnership’s common units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction;

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

• terminate all or some awards upon the consummation of the change-in-control transaction, but only if the 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 June 30, 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 June 30, 2012, there are 4,078 units that will vest within the following twelve months. All phantom units outstanding under the 2010 LTIP at June 30, 2012 include DERs. During the three and six months ended June 30, 2012, the Partnership paid $0.5 million and $1.0 million, respectively, with respect to the 2010 LTIP DERs. There was $0.2 million paid with respect to the 2010 LTIP DERs for the three and six months ended June 30, 2011.

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

	Three Months Ended June 30,
	2012					2011
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units		Weighted Average Grant Date Fair Value
Outstanding, beginning of period		2,051,706		$	20.46		1,566,000	$	22.23
Granted		17,650			34.23		153,949		22.84
Vested (1)		—			—		—		—
Forfeited		(3,997	)		17.47		—		—
Outstanding, end of period(3)		2,065,359		$	20.58		1,719,949	$	22.28
Non-cash compensation expense recognized (in thousands)				$	2,884			$	2,526

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	Six Months Ended June 30,
	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		72,950			28.49		1,719,949		22.28
Vested (1)		(7,226	)		20.67		—		—
Forfeited		(3,997	)		17.47		—		—
ARP anti-dilution adjustment(2)		165,468			—		—		—
Outstanding, end of period(3)		2,065,359		$	20.58		1,719,949	$	22.28
Non-cash compensation expense recognized (in thousands)				$	5,886			$	2,702

(1) The aggregate intrinsic values of phantom unit awards vested during the six months ended June 30, 2012 was $0.2 million. No phantom unit awards vested during the three months ended June 30, 2012 and 2011 and the six months ended June 30, 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 June 30, 2012 was $63.0 million.

At June 30, 2012, the Partnership had approximately $29.0 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 June 30, 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. There are 3,399 unit options outstanding under the 2010 LTIP at June 30, 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 June 30,
	2012					2011
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of period		2,581,322		$	20.45		2,226,000		$	22.23
Granted		(271	)		17.47		26,500			25.45
Forfeited		(271	)		17.47		(10,000	)		22.23
Outstanding, end of period(2)(3)		2,580,780		$	20.45		2,242,500		$	22.27
Options exercisable, end of period(4)		—		$	—		—		$	—
Non-cash compensation expense recognized (in thousands)				$	1,573				$	1,505

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	Six Months Ended June 30,
	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		68,958			26.31		2,252,500			22.27
Forfeited		(271	)		17.47		(10,000	)		22.23
ARP anti-dilution adjustment(1)		207,793			—		—			—
Outstanding, end of period(2)(3)		2,580,780		$	20.45		2,242,500		$	22.27
Options exercisable, end of period(4)		—		$	—		—		$	—
Non-cash compensation expense recognized (in thousands)				$	3,134				$	1,617

⁽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 June 30, 2012 was 8.8 years.

⁽³⁾ The options outstanding at June 30, 2012 had an aggregate intrinsic value of $25.9 million.

⁽⁴⁾ No options were exercisable at June 30, 2012 or 2011. No options vested during the three and six months ended June 30, 2012 and 2011.

At June 30, 2012, the Partnership had approximately $15.4 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 June 30,			Six Months Ended June 30,
	2011			2012			2011
Expected dividend yield		1.5	%		3.7	%		1.5	%
Expected unit price volatility		48.0	%		47.0	%		48.0	%
Risk-free interest rate		2.5	%		1.4	%		2.8	%
Expected term (in years)		6.88			6.88			6.88
Fair value of unit options granted	$	11.01		$	8.50		$	9.94

2006 Long-Term Incentive Plan

The Board of Directors 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 June 30, 2012, the Partnership had 997,233 phantom units and unit options outstanding under the 2006 LTIP, with 985,403 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 June 30, 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 June 30, 2012, 13,489 units will vest within the following twelve months. All phantom units outstanding under the 2006 LTIP at June 30, 2012 include DERs. During the three months ended June 30, 2012 and 2011, respectively, the Partnership paid $9,000 and $3,000 with respect to 2006 LTIP’s DERs. During the six months ended June 30, 2012 and 2011, respectively, the Partnership paid $17,000 and $5,000 with respect to 2006 LTIP’s DERs. These amounts were recorded as reductions of partners’ capital on the Partnership’s consolidated combined balance sheet.

42

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

	Three Months Ended June 30,
	2012					2011
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of period		37,053		$	15.42		31,025		$	7.85
Granted		9,996			30.01		—			—
Vested (1)		—			—		—			—
Forfeited		—			—		—			—
Outstanding, end of period(3)(4)		47,049		$	18.52		31,025		$	7.85
Non-cash compensation expense recognized (in thousands)				$	111				$	70
	Six Months Ended June 30,
	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		17,684			28.27		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)		47,049		$	18.52		31,025		$	7.85
Non-cash compensation expense recognized (in thousands)				$	278				$	255

(1) The intrinsic value for phantom unit awards vested during the six months ended June 30, 2012 and 2011 was $0.2 million. No phantom unit awards vested during the three months ended June 30, 2012 and 2011.

(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 June 30, 2012 was $1.4 million.

(4) There were 40,524 units at June 30, 2012 classified under accrued liabilities on the Partnership’s consolidated combined balance sheets of $0.4 million due to the option of the participants 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 $20.55 as of June 30, 2012.

At June 30, 2012, the Partnership had approximately $0.8 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 June 30, 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 June 30, 2012 that will vest within the following twelve months. For the three and six months ended June 30, 2012, the Partnership received cash of $0.1 million and $0.1 million, respectively, from the exercise of options. For the three and six months ended June 30, 2011, the Partnership received cash of $0.1 million for the exercise of options.

43

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

	Three Months Ended June 30,
	2012					2011
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of period		966,499		$	20.08		955,000		$	20.54
Granted		—			—		—			—
Exercised(1)		(16,315	)		2.98		(31,386	)		3.24
Forfeited		—			—		—			—
Outstanding, end of period(3)(4)		950,184		$	20.07		923,614		$	21.12
Options exercisable, end of period(5)		950,184		$	20.07		923,614		$	21.12
Non-cash compensation expense recognized (in thousands)				$	—				$	—
	Six Months Ended June 30,
	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)		(31,753	)		2.98		(31,386	)		3.24
Forfeited		—			—		—			—
ARP anti-dilution adjustment(2)		78,323			—		—			—
Outstanding, end of period(3)(4)		950,184		$	20.07		923,614		$	21.12
Options exercisable, end of period(5)		950,184		$	20.07		923,614		$	21.12
Non-cash compensation expense recognized (in thousands)				$	—				$	28

⁽¹⁾ The intrinsic values of options exercised during the three and six months ended June 30, 2012 were $0.5 million and $0.9 million, respectively. During the three and six months ended June 30, 2011, the intrinsic value of options exercised was $0.6 million.

⁽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 June 30, 2012 was 4.4 years.

⁽⁴⁾ The aggregate intrinsic value of options outstanding at June 30, 2012 was approximately $9.6 million.

⁽⁵⁾ The weighted average remaining contractual life for options exercisable at June 30, 2012 was 4.4 years.

At June 30, 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 and six months ended June 30, 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.

44

ARP Long-Term Incentive Plan

On March 12, 2012, the Partnership, as the sole limited partner of ARP, and the Board of Directors 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 ARP GP Board, a committee of the ARP GP Board or the board (or committee of the board) of an affiliate (the “ARP LTIP Committee”), which is the Compensation Committee of the board. At June 30, 2012, ARP had 2,309,976 phantom units, restricted units and unit options outstanding under the ARP LTIP, with 590,024 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 ARP LTIP Committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which the Partnership, as general partner, (or any affiliate) and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason):

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

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

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

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

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

ARP Phantom Units.

Through June 30, 2012, phantom units granted under the ARP LTIP generally will vest 25% of the original granted amount on each of the next four anniversaries of the date of grant. Of the phantom units outstanding under the ARP LTIP at June 30, 2012, 202,619 units will vest within the following twelve months. All phantom units outstanding under the ARP LTIP at June 30, 2012 include DERs. During the three and six months ended June 30, 2012, respectively, ARP paid $400 with respect to ARP LTIP’s DERs. No amounts were paid during the three and six months ended June 30, 2011, respectively, with respect to DERs. These amounts were recorded as reductions of partners’ capital on the Partnership’s consolidated combined balance sheet.

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

	Three and Six Months Ended June 30,
	2012				2011
	Number of Units		Weighted Average Grant Date Fair Value		Number of Units		Weighted Average Grant Date Fair Value
Outstanding, beginning of period		—	$	—		—	$	—
Granted		810,476		24.69		—		—
Vested (1)		—		—		—		—
Forfeited		—		—		—		—
Outstanding, end of period(2)(3)		810,476	$	24.69		—	$	—
Non-cash compensation expense recognized (in thousands)			$	1,740			$	—

45

(1) No phantom unit awards vested during the three and six months ended June 30, 2012 and 2011.

(2) The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2012 was $21.9 million.

(3) There was $12,000 classified within accrued liabilities on the Partnership’s consolidated combined balance sheets at June 30, 2012, representing 3,476 units, due to the option of the participants to settle in cash instead of units. No amounts were classified within accrued liabilities on the partnership’s consolidated combined balance sheet at December 31, 2011. The respective weighted average grant date fair value for these units was $28.75 at June 30, 2012.

ARP Unit Options.

The exercise price of the unit option may be equal to or more than the fair market value of ARP’s common unit on the date of grant of the option. Unit option awards expire 10 years from the date of grant. Through June 30, 2012, unit options granted under the ARP LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. There were 374,875 unit options outstanding under the ARP LTIP at June 30, 2012 that will vest within the following twelve months. No cash was received from the exercise of options for the three and six months ended June 30, 2012 and 2011.

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

	Three and Six Months Ended June 30,
	2012				2011
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of period		—	$	—		—	$	—
Granted		1,499,500		24.67		—		—
Exercised(1)		—		—		—		—
Forfeited		—		—		—		—
Outstanding, end of period(2)(3)		1,499,500	$	24.67		—	$	—
Options exercisable, end of period(4)		—	$	—		—	$	—
Non-cash compensation expense recognized (in thousands)			$	1,274			$	—

⁽¹⁾  No options were exercised during the three and six months ended June 30, 2012 and 2011.

⁽²⁾  The weighted average remaining contractual life for outstanding options at June 30, 2012 was 9.9 years.

⁽³⁾  The aggregate intrinsic value of options outstanding at June 30, 2012 was approximately $3.5 million.

⁽⁴⁾  No options were exercisable at June 30, 2012.

At June 30, 2012, ARP had approximately $13.4 million in unrecognized compensation expense related to unvested unit options outstanding under the ARP LTIP based upon the fair value of the awards. ARP used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the periods indicated:

	Three and Six Months Ended June 30, 2012
Expected dividend yield		1.5	%
Expected unit price volatility		47.0	%
Risk-free interest rate		1.0	%
Expected term (in years)		6.25
Fair value of unit options granted	$	9.79

46

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 June 30, 2012, APL had 972,402 phantom units outstanding under the APL LTIPs, with 1,670,145 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 June 30, 2012, phantom units granted under the APL LTIPs generally had vesting periods of four years. In conjunction with the approval of the APL 2010 LTIP, the holders of 300,000 of the 375,000 equity indexed bonus units (“APL Bonus Units”) under APL’s subsidiary’s plan discussed below agreed to exchange their APL Bonus Units for an equivalent number of 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 June 30, 2012, 253,138 units will vest within the following twelve months. APL is authorized to repurchase common units to cover employee-related taxes on certain phantom units, when they have vested. APL repurchased and retired 23,345 common units for a cost of $0.8 million during the three and six months ended June 30, 2011, which was recorded as a reduction of non-controlling interest on the Partnership’s consolidated balance sheet. On February 17, 2011, the employment agreement with APL’s Chief Executive Officer (“CEO”) was terminated in connection with AEI’s merger with Chevron and 75,250 outstanding phantom units, which represents all outstanding phantom units held by APL’s CEO, automatically vested and were issued.

All phantom units outstanding under the APL LTIPs at June 30, 2012 include DERs. The amounts paid with respect to APL LTIP DERs were $0.6 million and $0.1 million, respectively, for the three months ended June 30, 2012 and 2011. For the six months ended June 30, 2012 and 2011, the amounts paid with respect to APL LTIP DERs were $0.8 million and $0.3 million, respectively. These amounts were recorded as reductions of non-controlling interest on the Partnership’s consolidated combined balance sheet.

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

	Three Months Ended June 30,
	2012					2011
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of period		390,567		$	21.41		414,716		$	11.65
Granted		693,952			34.97		125,123			33.03
Vested and issued(1)		(108,167	)		11.35		(103,414	)		11.36
Forfeited		(3,950	)		24.66		—			—
Outstanding, end of period(2)(3)		972,402		$	32.19		436,425		$	17.84
Matured and not issued(4)		48,647		$	24.12		28,750		$	11.41
Non-cash compensation expense recognized (in thousands)				$	2,940				$	502

47

	Six Months Ended June 30,
	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		698,084			34.98		130,853			32.93
Vested and issued(1)		(116,221	)		13.32		(185,314	)		12.35
Forfeited		(3,950	)		24.66		—			—
Outstanding, end of period(2)(3)		972,402		$	32.19		436,425		$	17.84
Matured and not issued(4)		48,647		$	24.12		28,750		$	11.41
Non-cash compensation expense recognized (in thousands)(5)				$	3,918				$	1,676

(1) The intrinsic values for phantom unit awards vested and issued during the three months ended June 30, 2012 and 2011 were $3.2 million and $3.5 million, respectively, and during the six months ended June 30, 2012 and 2011, the intrinsic values were $3.5 million and $5.9 million, respectively.

(2) The aggregate intrinsic values for phantom unit awards outstanding at June 30, 2012 and 2011 were $30.3 million and $14.4 million, respectively.

(3) There were 17,852 and 14,311 outstanding phantom unit awards at June 30, 2012 and 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 June 30, 2012 and 2011 was $1.5 million and $0.9 million, respectively.

(5) Non-cash compensation expense for the six months ended June 30, 2011 includes incremental compensation expense of $0.5 million, related to the accelerated vesting of phantom units held by APL’s CEO.

At June 30, 2012, APL had approximately $25.6 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 2.3 years.

APL Unit Options. The exercise price of the unit option is equal to the fair market value of APL’s common unit on the date of grant of the option. The APL LTIP Committee also shall determine how the exercise price may be paid by the Participant. The APL LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through June 30, 2012, unit options granted under the APL LTIPs generally have vested 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 June 30, 2012, all unit options were exercised. There are no unit options outstanding under APL LTIPs at June 30, 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 June 30,
	2012				2011
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of period		—	$	—		—	$	—
Exercised(1)(2)		—		—		—		—
Outstanding, end of period(2)		—	$	—		—	$	—
Non-cash compensation expense recognized (in thousands)(3)			$	—			$	—

48

	Six Months Ended June 30,
	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 six months ended June 30, 2011, was $1.8 million. Approximately $0.5 million was received from the exercise of unit option awards during the six months ended June 30, 2011.

(2) No options are outstanding or exercisable.

(3) Incremental expense of $2,000, related to the accelerated vesting of options held by APL’s CEO, was recognized during the six months ended June 30, 2011.

At June 30, 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 and six months ended June 30, 2012 and 2011 under the APL LTIPs.

APL Employee Incentive Compensation Plan and Agreement

At June 30, 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 June 30, 2012, APL had no outstanding APL Bonus Units. 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. During the three and six month periods ended June 30, 2012 and the three and six month periods ended June 30, 2011, 25,500 APL Bonus Units and 24,750 APL Bonus Units, respectively, vested and cash payments were made for $0.7 million and $0.9 million, respectively. APL recognized income of $0.1 million and expense of $0.1 million during the three months ended June 30, 2012 and 2011, respectively and income of $0.1 million and expense of $0.6 million during the six months ended June 31, 2012 and 2011, respectively, which was recorded within general and administrative expense on the Partnership’s consolidated combined statements of operations. APL had $0.8 million at 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 that date.

NOTE 17 – OPERATING SEGMENT INFORMATION

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Gas and oil production:
Revenues	$	19,460		$	17,723		$	36,624		$	35,349
Operating costs and expenses		(4,447	)		(4,042	)		(8,952	)		(7,963	)
Depreciation, depletion and amortization expense		(9,520	)		(7,178	)		(17,087	)		(13,744	)
Segment income	$	5,493		$	6,503		$	10,585		$	13,642

49

Well construction and completion:
Revenues	$	12,241		$	10,954		$	55,960		$	28,679
Operating costs and expenses		(10,606	)		(9,284	)		(48,301	)		(24,305	)
Segment income	$	1,635		$	1,670		$	7,659		$	4,374
Other partnership management:(1)
Revenues	$	5,462		$	29,994		$	16,070		$	42,243
Operating costs and expenses		(6,367	)		(7,437	)		(13,471	)		(15,531	)
Depreciation, depletion and amortization expense		(1,302	)		(1,069	)		(2,843	)		(2,204	)
Segment income (loss)	$	(2,207	)	$	21,488		$	(244	)	$	24,508
Atlas Pipeline:
Revenues	$	325,998		$	350,221		$	619,213		$	607,545
Operating costs and expenses		(209,720	)		(287,708	)		(456,970	)		(518,958	)
Depreciation and amortization expense		(21,712	)		(19,123	)		(42,554	)		(38,029	)
Segment income	$	94,566		$	43,390		$	119,689		$	50,558
Reconciliation of segment income (loss) to net income (loss) from continuing operations:
Segment income (loss):
Gas and oil production	$	5,493		$	6,503		$	10,585		$	13,642
Well construction and completion		1,635			1,670			7,659			4,374
Other partnership management		(2,207	)		21,488			(244	)		24,508
Atlas Pipeline		94,566			43,390			119,689			50,558
Total segment income		99,487			73,051			137,689			93,082
General and administrative expenses(2)		(37,607	)		(22,239	)		(74,855	)		(38,429	)
Gain (loss) on asset sales and disposal(2)		(16	)		(233	)		(7,021	)		255,714
Interest expense(2)		(10,294	)		(6,567	)		(19,385	)		(24,645	)
Loss on extinguishment of debt(2)		—			(19,574	)		—			(19,574	)
Net income from continuing operations	$	51,570		$	24,438		$	36,428		$	266,148
Capital expenditures:
Gas and oil production	$	23,260		$	3,734		$	40,179		$	8,472
Other partnership management		691			1,279			1,018			2,431
Atlas Pipeline		65,221			73,636			146,388			91,969
Corporate and other		2,743			1,637			4,455			3,479
Total capital expenditures	$	91,915		$	80,286		$	192,040		$	106,351

	June 30,		December 31,
	2012		2011
Balance sheet:
Goodwill:
Gas and oil production	$	18,145	$	18,145
Well construction and completion		6,389		6,389
Other partnership management		7,250		7,250
Atlas Pipeline		—		—
	$	31,784	$	31,784
Total assets:
Gas and oil production	$	792,026	$	593,320
Well construction and completion		6,988		6,987
Other partnership management		45,617		45,991
Atlas Pipeline		2,100,402		1,930,813
Corporate and other		68,962		107,660
	$	3,013,995	$	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 sales and disposal, general and administrative expenses and loss on early extinguishment of debt have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.

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NOTE 18 – SUBSEQUENT EVENTS

Partnership Cash Distribution. On July 17, 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 June 30, 2012. The $12.8 million distribution will be paid on August 17, 2012 to unitholders of record at the close of business on August 7, 2012.

APL Cash Distribution. On July 17, 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 June 30, 2012. The $32.3 million distribution, including $2.2 million to the Partnership, as general partner, will be paid on August 14, 2012 to unitholders of record at the close of business on August 7, 2012.

ARP’s Acquisition of Titan Operating, L.L.C. On July 25, 2012, ARP acquired certain proved reserves and associated assets in the Barnett Shale from Titan Operating, L.L.C. (“Titan”) for 3.8 million ARP common units and 3.8 million newly-created convertible Class B preferred units (which have a collective value of $193.2 million, based upon the fair value of the units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments. The preferred units are voluntarily convertible to common units on a one-for-one basis within three years of the acquisition closing date at a strike price of $26.03 plus all unpaid preferred distributions per unit, and will be mandatorily converted to common units on the third anniversary of the issuance. While outstanding, the preferred units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. The initial accounting for the business combination is not complete pending detailed analyses of the facts and circumstances that existed as of the acquisition date. Also, ARP entered into an amendment to its senior secured revolving credit facility (see Note 9) on July 26, 2012 to increase the borrowing base from $250.0 million to $310.0 million.

ARP entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the Securities and Exchange Commission by January 25, 2013 to register the resale of the common units issued on the acquisition closing date and those issuable upon conversion of the preferred units. ARP agreed to use its commercially reasonable efforts to have the registration statement declared effective by March 31, 2013, and to cause the registration statement to be continuously effective until the earlier of (i) the date as of which all such common units registered thereunder are sold by the holders and (ii) one year after the date of effectiveness. If ARP does not meet the aforementioned deadline for the registration statement to be declared effective, the common unit holders subject to the registration rights agreement will receive liquidated damages of 0.50% of the gross proceeds from the private placement determined based on a per unit price of $26.03, or $1.0 million, for the first 30-day period after March 31, 2013, increasing by an additional 0.50% per 30-day period thereafter, up to a maximum of 2.0% of the gross proceeds of the private placement per 30-day period.

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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 June 30, 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 June 30, 2012, we owned 100% of the general partner Class A units and incentive distribution rights, and common units representing an approximate 63.7% limited partner interest in ARP (see “Subsequent Events”);

• 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 June 30, 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 June 30, 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 June 30, 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 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.

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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 acquisition method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable assets and liabilities of the Transferred Business based upon their fair values with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital on our consolidated combined balance sheet. Also, in comparison to the acquisition method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in 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 six months ended June 30, 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 July 17, 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 June 30, 2012. The $12.8 million distribution will be paid on August 17, 2012 to unitholders of record at the close of business on August 7, 2012.

APL Cash Distribution. On July 17, 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 June 30, 2012. The $32.3 million distribution, including $2.2 million to us, as general partner, will be paid on August 14, 2012 to unitholders of record at the close of business on August 7, 2012.

ARP’s Acquisition of Titan Operating, L.L.C. On July 25, 2012, ARP acquired certain proved reserves and associated assets in the Barnett Shale from Titan Operating, L.L.C. (“Titan”) for 3.8 million of ARP’s common units and 3.8 million newly-created convertible Class B preferred units (which have a collective value of $193.2 million, based upon the fair value of the units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments. The preferred units are voluntarily convertible to common units on a one-for-one basis within three years of the acquisition closing date at a strike price of $26.03 plus all unpaid preferred distributions per unit, and will be mandatorily converted to common units on the third anniversary of the issuance. While outstanding, the preferred units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. Also, ARP entered into an amendment to its senior secured revolving credit facility (see “ARP Credit Facility”) on July 26, 2012 to increase the borrowing base from $250.0 million to $310.0 million.

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ARP entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the Securities and Exchange Commission by January 25, 2013 to register the resale of the common units issued on the acquisition closing date and those issuable upon conversion of the preferred units. ARP agreed to use its commercially reasonable efforts to have the registration statement declared effective by March 31, 2013, and to cause the registration statement to be continuously effective until the earlier of (i) the date as of which all such common units registered thereunder are sold by the holders and (ii) one year after the date of effectiveness. If ARP does not meet the aforementioned deadline for the registration statement to be declared effective, the common unit holders subject to the registration rights agreement will receive liquidated damages of 0.50% of the gross proceeds from the private placement determined based on a per unit price of $26.03, or $1.0 million, for the first 30-day period after March 31, 2013, increasing by an additional 0.50% per 30-day period thereafter, up to a maximum of 2.0% of the gross proceeds of the private placement per 30-day period.

RECENT DEVELOPMENTS

ARP Cash Distribution. On June 28, 2012, the ARP declared a cash distribution of $0.40 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended June 30, 2012. The $13.2 million distribution, including $0.3 million to us, as general partner, will be paid on August 14, 2012 to unitholders of record at the close of business on July 12, 2012.

APL’s Expansion Project. In June 2012, APL completed construction of, and started processing through, a 60 MMCFD cryogenic facility at its Velma gas plant, increasing capacity at Velma to 160 million cubic feet per day (“MMCFD”). This expansion supports APL’s long-term fee-based agreement with XTO Energy, Inc., a subsidiary of ExxonMobil, to provide natural gas gathering and processing services for up to an incremental 60 MMCFD from the Woodford Shale.

APL’s Acquisition of Gas Gathering Systems and Related Assets. In June 2012, APL acquired a gas gathering system and related assets in the Barnett Shale play in Tarrant County, Texas for an initial net purchase price of $18.0 million. The system consists of 19 miles of gathering pipeline that is used to facilitate gathering some of the newly acquired production for ARP. In February 2012, APL acquired a gas gathering system and related assets, within their WestOK system, for an initial net purchase price of $19.0 million. APL agreed to pay up to an additional $12.0 million, payable in two equal amounts, if certain volumes are achieved on the acquired gathering system within a specified time period. In connection with this acquisition, APL received assignment of gas purchase agreements for gas currently gathered on the acquired system. APL accounted for these acquisitions as business combinations.

New Credit Facility. In May 2012, we entered into a new credit facility with a syndicate of banks that matures in May 2016. The credit facility has maximum lender commitments of $50.0 million, and up to $5.0 million of the credit facility may be in the form of standby letters of credit. Our obligations under the credit facility are secured by substantially all of our assets, including our ownership interests in APL and ARP. Additionally, our obligations under the credit facility may be guaranteed by future subsidiaries. The credit agreement contains customary covenants that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a commitment deficiency exists or a default under the credit agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of our assets. The credit agreement also contains covenants that require us to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to EBITDA (as defined in the credit agreement) not greater than 3.25 to 1.0 as of the last day of any fiscal quarter and a ratio of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) not less than 2.75 to 1.0 as of the last day of any fiscal quarter (see “Credit Facility”).

APL’s Amended Credit Facility. In May 2012, APL entered into an amendment to their revolving credit facility agreement that increased the facility from $450.0 million to $600.0 million (see “APL Credit Facility”).

ARP’s Acquisition of Assets from Carrizo Oil & Gas, Inc. On April 30, 2012, ARP acquired certain oil and natural gas assets from Carrizo Oil & Gas, Inc. (NASDAQ: CRZO; “Carrizo”) for approximately $187.0 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 was funded through borrowing under ARP’s credit facility and $119.5 million of net proceeds from the sale of 6.0 million of ARP’s common units at a negotiated purchase price per unit of $20.00, of which $5.0 million was purchased by certain of our executives. ARP’s common units issued in the private placement are subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement stipulated that ARP would (a) file a registration statement with the Securities and Exchange Commission by October 30, 2012 and (b) cause the registration statement to be declared effective by the Securities and Exchange Commission by December 31, 2012. If ARP does not meet the aforementioned deadline for the common units to

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be declared effective, the common unit holders subject to the registration rights agreement will receive liquidated damages of 0.50% of the gross proceeds from the private placement, or $0.6 million, for the first 30-day period after December 31, 2012, increasing by an additional 0.50% per 30-day period thereafter, up to a maximum of 2.0% of the gross proceeds of the private placement per 30-day period.

ARP’s Joint Venture Agreement with Subsidiaries of Equal Energy, Ltd. In April 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 (see “ARP Credit Facility”). Concurrent with the closing of the acquisition, ARP entered into a participation and development agreement with Equal for future drilling in the Mississippi Lime play and both parties can contribute acreage to the joint venture through the establishment of an area of mutual interest closely surrounding Equal’s existing acreage position.

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 and industrial or other end-users. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The production area and pricing indexes are as follows: Appalachian Basin and Mississippi Lime, primarily the NYMEX spot market price; Barnett Shale, primarily the Waha spot market price; New Albany Shale and Antrim Shale, primarily the Texas Gas Zone SL and Chicago Hub spot market prices; and Niobrara formation, primarily the Cheyenne Hub spot market price.

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 at the prevailing spot market price in each region.

Natural Gas Liquids. Natural gas liquids (“NGL’s”) are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas (low BTU content) to meet pipeline specifications for long-haul transport to end users. ARP sells its NGL production 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 between $15,000 and $400,000, 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 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%.

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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 Resource

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, 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.

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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 throughout the 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 June 30, 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; the Utica Shale, which lies several thousand feet below the Marcellus Shale, is much thicker than the Marcellus Shale and trends primarily towards wet natural gas in the central region and dry gas in the eastern region; 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 Barnett Shale in the Bend Arch Fort Worth Basin in northern Texas, a hydro-carbon producing shale in which ARP established a position following its acquisition of assets from Carrizo in April 2012 (see “Recent Developments”);

• the Mississippi Lime play in northwestern Oklahoma, an oil and natural gas liquids rich area, in which ARP acquired a 50% joint venture interest in 14,500 net undeveloped acres in April 2012 (see “Recent Developments”);

• 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 and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Gross wells drilled:
Appalachia		5		—		14		3
Mississippi Lime		2		—		2		—
Niobrara		—		—		51		17
		7		—		67		20
Our share of gross wells drilled(1):
Appalachia		2		—		4		1
Mississippi Lime		1		—		1		—
Niobrara		—		—		15		5
		3		—		20		6

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Gross wells turned in line:
Appalachia	12	—	33	1
New Albany/Antrim	—	1	—	13
Niobrara	23	12	72	30
	35	13	105	44

⁽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 natural gas liquids production volumes and production per day for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June  30,				Six Months Ended June 30,
	2012		2011		2012		2011
Production:(1)(2)
Appalachia:(3)
Natural gas (MMcf)		3,163		2,567		6,020		5,197
Oil (000’s Bbls)		26		30		54		54
Natural gas liquids (000’s Bbls)		39		43		78		85
Total (MMcfe)		3,557		3,007		6,810		6,030
Barnett:(4)
Natural gas (MMcf)		1,775		—		1,775		—
Oil (000’s Bbls)		—		—		—		—
Natural gas liquids (000’s Bbls)		3		—		3		—
Total (MMcfe)		1,793		—		1,793		—
New Albany/Antrim:
Natural gas (MMcf)		275		291		550		582
Total (MMcfe)		275		291		550		582
Niobrara:
Natural gas (MMcf)		67		36		125		53
Total (MMcfe)		67		36		125		53
Total:
Natural gas (MMcf)		5,280		2,894		8,470		5,833
Oil (000’s Bbls)		26		30		54		54
Natural gas liquids (000’s Bbls)		42		43		81		85
Total (MMcfe)		5,691		3,334		9,278		6,665
Production per day: (1)(2)
Appalachia:(3)
Natural gas (Mcfd)		34,760		28,208		33,075		28,714
Oil (Bpd)		290		334		297		298
Natural gas liquids (Bpd)		431		472		427		469
Total (Mcfed)		39,086		33,042		37,419		33,314
Barnett:(4)
Natural gas (Mcfd)		28,629		—		28,629		—
Oil (Bpd)		—		—		—		—
Natural gas liquids (Bpd)		47		—		47		—
Total (Mcfed)		28,912		—		28,912		—
New Albany/Antrim:
Natural gas (Mcfd)		3,023		3,192		3,025		3,218
Total (Mcfed)		3,023		3,192		3,025		3,218
Niobrara:
Natural gas (Mcfd)		734		399		688		293
Total (Mcfed)		734		399		688		293
Total: (4)
Natural gas (Mcfd)		58,022		31,799		46,541		32,225
Oil (Bpd)		290		334		297		298
Natural gas liquids (Bpd)		463		472		443		469
Total (Mcfed)		62,541		36,633		50,981		36,825

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⁽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 our production located in Pennsylvania, Ohio, New York, West Virginia and Tennessee.

⁽⁴⁾  Volumetric data for Barnett for the three and six months ended June 30, 2012 represents average volumes recognized for the 62-day period from April 30, 2012, the date of acquisition, through June 30, 2012. Total production per day for ARP represents total production volume over the 91 and 182 days within the three and six months ended June 30, 2012, respectively.

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 our 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 and six months ended June 30, 2012 and 2011, along with its average production costs, taxes, and transportation and compression costs in each of the reported periods:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Production revenues (in thousands):
Appalachia:(1)
Natural gas revenue	$	9,727	$	10,947	$	21,217	$	23,162
Oil revenue		2,591		3,027		5,378		5,086
Natural gas liquids revenue		1,575		2,224		3,253		4,069
Total revenues	$	13,893	$	16,198	$	29,848	$	32,317
Barnett:
Natural gas revenue	$	3,940	$	—	$	3,940	$	—
Oil revenue		2		—		2		—
Natural gas liquids revenue		147		—		147		—
Total revenues	$	4,089	$	—	$	4,089	$	—
New Albany/Antrim:
Natural gas revenue	$	1,230	$	1,330	$	2,290	$	2,769
Total revenues	$	1,230	$	1,330	$	2,290	$	2,769
Niobrara:
Natural gas revenue	$	248	$	195	$	397	$	263
Total revenues	$	248	$	195	$	397	$	263
Total:
Natural gas revenue	$	15,145	$	12,472	$	27,844	$	26,194
Oil revenue		2,593		3,027		5,380		5,086
Natural gas liquids revenue		1,722		2,224		3,400		4,069
Total revenues	$	19,460	$	17,723	$	36,624	$	35,349
Average sales price:(2)
Natural gas (per Mcf):
Total realized price, after hedge(3)	$	3.49	$	5.15	$	3.81	$	5.31
Total realized price, before hedge(3)	$	2.03	$	5.05	$	2.76	$	4.64
Oil (per Bbl):
Total realized price, after hedge	$	98.31	$	99.70	$	99.89	$	94.32
Total realized price, before hedge	$	94.39	$	99.70	$	97.60	$	92.25
Natural gas liquids (per Bbl) total realized price:	$	40.85	$	51.77	$	42.22	$	47.95

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Production costs (per Mcfe):(2)
Appalachia:(1)
Lease operating expenses(4)	$	0.83	$	1.03	$	0.93	$	1.00
Production taxes		0.06		0.03		0.09		0.05
Transportation and compression		0.30		0.50		0.31		0.48
	$	1.19	$	1.55	$	1.32	$	1.52
Barnett:
Lease operating expenses	$	0.41	$	—	$	0.41	$	—
Production taxes		0.19		—		0.19		—
Transportation and compression		0.30		—		0.30		—
	$	0.90	$	—	$	0.90	$	—
New Albany/Antrim:
Lease operating expenses	$	1.04	$	1.33	$	1.12	$	1.22
Production taxes		0.13		0.15		0.10		0.12
Transportation and compression		0.03		0.12		0.03		0.10
	$	1.20	$	1.61	$	1.25	$	1.44
Niobrara:
Lease operating expenses	$	0.99	$	0.61	$	1.22	$	0.62
Production taxes		0.27		0.03		0.18		0.02
Transportation and compression		0.43		0.22		0.39		0.25
	$	1.69	$	0.85	$	1.79	$	0.89
Total:
Lease operating expenses(4)	$	0.71	$	1.05	$	0.84	$	1.01
Production taxes		0.11		0.04		0.11		0.05
Transportation and compression		0.29		0.46		0.29		0.45
	$	1.11	$	1.55	$	1.24	$	1.51

⁽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 and six months ended June 30, 2012 and 2011. Including the effect of this subordination, the average realized gas sales price was $2.87 per Mcf ($1.40 per Mcf before the effects of financial hedging) and $4.31 per Mcf ($4.20 per Mcf before the effects of financial hedging) for the three months ended June 30, 2012 and 2011, respectively, and $3.29 per Mcf ($2.24 per Mcf before the effects of financial hedging) and $4.49 per Mcf ($3.82 per Mcf before the effects of financial hedging) for the six months ended June 30, 2012 and 2011, respectively.

⁽⁴⁾  Excludes the effects of ARP’s proportionate share of lease operating expenses associated with subordination of its production revenue to investor partners within its investment partnerships for the three and six months ended June 30, 2012 and 2011. Including the effects of these costs, Appalachia lease operating expenses per Mcfe were $0.31 per Mcfe ($0.67 per Mcfe for total production costs) and $0.65 per Mcfe ($1.18 per Mcfe for total production costs) for the three months ended June 30, 2012 and 2011, respectively, and $0.54 per Mcfe ($0.94 per Mcfe for total production costs) and $0.65 per Mcfe ($1.17 per Mcfe for total production costs) for the six months ended June 30, 2012 and 2011, respectively. Including the effects of these costs, total lease operating expenses per Mcfe were $0.38 per Mcfe ($0.78 per Mcfe for total production costs) and $0.71 per Mcfe ($1.21 per Mcfe for total production costs) for three months ended June 30, 2012 and 2011, respectively, and were $0.56 per Mcfe ($0.96 per Mcfe for total production costs) and $0.70 per Mcfe ($1.19 per Mcfe for total production costs) for the six months ended June 30, 2012, respectively.

Three Months Ended June 30, 2012 Compared with the Three Months Ended June 30, 2011. Total natural gas revenues were $15.1 million for the three months ended June 30, 2012, an increase of $2.6 million from $12.5 million for the three months ended June 30, 2011. This increase consisted of a $3.9 million increase attributable to production associated with the newly acquired Barnett Shale assets and a $2.5 million increase attributable to higher production volumes for legacy systems’ wells, partially offset by a $2.9 million decrease attributable to lower realized natural gas prices for production volume on legacy systems’ wells and a $0.9 million increase in gas revenues subordinated to the investor partners within ARP’s investment partnerships for the three months ended June 30, 2012 compared with the prior year period. Total oil revenues were $2.6 million for the three months ended June 30, 2012, a decrease of $0.4 million from $3.0 million for the comparable prior year period due primarily to lower production volumes during the current year period. Total natural gas liquids revenues were $1.7 million for the three months ended June 30, 2012, a decrease of $0.5 million from $2.2 million for the comparable prior year period due primarily to lower average natural gas liquids realized prices.

Appalachia production costs were $2.4 million for the three months ended June 30, 2012, a decrease of $1.1 million from $3.5 million for the three months ended June 30, 2011. This decrease was principally due to a $0.7 million increase in ARP’s net credit received against lease operating expenses from the subordination of ARP’s revenue within its investment partnerships and a $0.4 million decrease in water hauling and disposal costs due to timing of costs incurred.

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Six Months Ended June 30, 2012 Compared with the Six Months Ended June 30, 2011. Total natural gas revenues were $27.8 million for the six months ended June 30, 2012, an increase of $1.6 million from $26.2 million for the six months ended June 30, 2011. This increase consisted of a $3.9 million increase attributable to production associated with the newly acquired Barnett Shale assets, a $3.5 million increase attributable to higher production volumes for legacy systems’ wells and a $0.4 million decrease in gas revenues subordinated to the investor partners within ARP’s investment partnerships for the six months ended June 30, 2012 compared with the prior year period, partially offset by a $6.2 million decrease attributable to lower realized natural gas prices for production volume on legacy systems’ wells. Total oil revenues were $5.4 million for the six months ended June 30, 2012, an increase of $0.3 million from $5.1 million for the comparable prior year period due primarily to higher average oil realized prices during the current year period. Total natural gas liquids revenues were $3.4 million for the six months ended June 30, 2012, a decrease of $0.7 million from $4.1 million for the comparable prior year period due primarily to lower average natural gas liquids realized prices.

Appalachia production costs were $6.4 million for the six months ended June 30, 2012, a decrease of $0.7 million from $7.1 million for the six months ended June 30, 2011. This decrease was principally due to a $0.5 million increase in ARP’s net credit received against lease operating expenses from the subordination of ARP’s revenue within its investment partnerships and a $0.4 million decrease in water hauling and disposal costs due to timing of costs incurred, partially offset by a $0.2 million increase in labor and other costs.

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 and six months ended June 30, 2012 and 2011. There were no exploratory wells drilled during the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Drilling partnership investor capital:
Raised	$	3,000	$	—	$	3,000	$	—
Deployed	$	12,241	$	10,954	$	55,960	$	28,679
Gross partnership wells drilled:
Appalachia		5		—		14		3
Mississippi Lime		2		—		2		—
Niobrara		—		—		51		17
Total		7		—		67		20
Net partnership wells drilled:
Appalachia		5		—		14		3
Mississippi Lime		1		—		1		—
Niobrara		—		—		51		17
Total		6		—		66		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):

	Three Months Ended June  30,				Six Months Ended June 30,
	2012		2011		2012		2011
Average construction and completion:
Revenue per well	$	817	$	5,160	$	712	$	954
Cost per well		708		4,373		615		809
Gross profit per well	$	109	$	787	$	97	$	145
Gross profit margin	$	1,635	$	1,670	$	7,659	$	4,374

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Partnership net wells associated with revenue recognized(1):
Appalachia	6	1	15	2
Mississippi Lime	1	—	1	—
New Albany/Antrim	—	1	—	3
Niobrara	8	—	63	25
	15	2	79	30

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

Three Months Ended June 30, 2012 Compared with the Three Months Ended June 30, 2011. Well construction and completion segment margin was $1.6 million for the three months ended June 30, 2012, a decrease of $0.1 million from $1.7 million for the three months ended June 30, 2011. This decrease consisted of a $1.5 million decrease associated with lower gross profit margin per well, partially offset by a $1.4 million increase related to an increased number of wells recognized for revenue within the ARP investment partnerships. Average revenue and cost per well decreased between periods due primarily to lower capital deployed for Marcellus Shale wells within the drilling partnerships during second quarter 2012, but an increase in capital deployed for Niobrara wells, which have a lower cost per well in comparison to the Marcellus Shale wells. As 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.

Six Months Ended June 30, 2012 Compared with the Six Months Ended June 30, 2011. Well construction and completion segment margin was $7.7 million for the six months ended June 30, 2012, an increase of $3.3 million from $4.4 million for the six months ended June 30, 2011. This increase consisted of a $4.7 million increase related to an increased number of wells recognized for revenue within the ARP investment partnerships, partially offset by a $1.4 million decrease associated with lower gross profit margin per well. Average revenue and cost per well decreased between periods due to higher capital deployed for Niobrara Shale wells, which have a lower cost per well in comparison to Marcellus Shale wells, within the drilling partnerships during first six months of 2012. 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 in comparison to the Fall 2010 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 June 30, 2012 includes $18.8 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 and beginning of 2013.

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 June 30, 2012 Compared with the Three Months Ended June 30, 2011. Administration and oversight fee revenues were $1.3 million for the three months ended June 30, 2012, which was consistent with $1.4 million for the three months ended June 30, 2011.

Six Months Ended June 30, 2012 Compared with the Six Months Ended June 30, 2011. Administration and oversight fee revenues were $4.1 million for the six months ended June 30, 2012, an increase of $1.4 million from $2.7 million for the six months ended June 30, 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 compared with the Fall 2010 drilling program. The planned Fall 2010 drilling program was cancelled following AEI’s announcement of the acquisition of the Transferred Business in November 2010.

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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 June 30, 2012 Compared with the Three Months Ended June 30, 2011. Well services revenues were $5.3 million for the three months ended June 30, 2012, an increase of $0.4 million from $4.9 million for three months ended June 30, 2011. Well services expenses were $2.4 million for the three months ended June 30, 2012, an increase of $0.7 million from $1.7 million for the three months ended June 30, 2011. The increase in well services revenue is primarily related to higher equipment rental revenue during the three months ended June 30, 2012 as compared with the comparable prior year period. The increase in well services expenses is primarily related to higher well labor costs.

Six Months Ended June 30, 2012 Compared with the Six Months Ended June 30, 2011. Well services revenues were $10.3 million for the six months ended June 30, 2012, an increase of $0.2 million from $10.1 million for the six months ended June 30, 2011. Well services expenses were $4.8 million for the six months ended June 30, 2012, an increase of $0.8 million from $4.0 million for the six months ended June 30, 2011. The increase in well services revenue is primarily related to higher equipment rental revenue during the six months ended June 30, 2012 as compared with the comparable prior year period. The increase in well services expenses is primarily related to higher well labor costs.

Gathering and Processing

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 June 30,						Six Months Ended June 30,
Gathering and Processing:	2012			2011			2012			2011
Atlas Resource:
Revenue	$	2,863		$	5,118		$	6,177		$	9,617
Expense		(3,953	)		(5,763	)		(8,627	)		(11,497	)
Gross Margin	$	(1,090	)	$	(645	)	$	(2,450	)	$	(1,880	)
Atlas Pipeline:
Revenue	$	253,679		$	340,616		$	555,585		$	616,335
Expense		(209,720	)		(287,708	)		(456,970	)		(518,958	)
Gross Margin	$	43,959		$	52,908		$	98,615		$	97,377
Total:
Revenue	$	256,542		$	345,734		$	561,762		$	625,952
Expense		(213,673	)		(293,471	)		(465,597	)		(530,455	)
Gross Margin	$	42,869		$	52,263		$	96,165		$	95,497

Three Months Ended June 30, 2012 Compared with the Three Months Ended June 30, 2011. ARP’s net gathering and processing expense for the three months ended June 30, 2012 was $1.1 million compared with $0.6 million for the three months ended June 30, 2011. This increase was principally due to an increase in natural gas volume in the Appalachian Basin between the periods, partially offset by a decrease in ARP’s average realized natural gas price.

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Gathering and processing margin for APL was $44.0 million for the three months ended June 30, 2012 compared with $52.9 million for the three months ended June 30, 2011. This decrease was due principally to lower natural gas and NGL sales prices, partially offset by higher production volumes.

Six Months Ended June 30, 2012 Compared with the Six Months Ended June 30, 2011. ARP’s net gathering and processing expense for the six months ended June 30, 2012 was $2.5 million compared with $1.9 million for the six months ended June 30, 2011. This increase was principally due to an increase in natural gas volume in the Appalachian Basin between the periods, partially offset by a decrease in ARP’s average realized natural gas price.

Gathering and processing margin for APL was $98.6 million for the six months ended June 30, 2012 compared with $97.4 million for the six months ended June 30, 2011. This increase was due principally to higher production volumes, partially offset by lower natural gas and NGL sales prices.

Gain (Loss) on Mark-to-Market Derivatives

Gain (loss) on mark-to-market derivatives principally reflects the change in fair value of APL’s commodity derivatives that will settle in future periods, as APL does not apply hedge accounting to its derivatives. While APL utilizes either quoted market prices or observable market data to calculate the fair value of its natural gas and crude oil derivatives, valuations of APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGL’s for similar geographic locations, and valuations of its NGL options are based on forward price curves developed by third-party financial institutions. The use of unobservable market data for APL’s fixed price swaps and NGL options has no impact on the settlement of these derivatives. However, a change in management’s estimated fair values for these derivatives could impact our net income, though it would have no impact on our liquidity or capital resources. We recognized gains of $67.8 million and $55.8 million for the three and six months ended June 30, 2012, respectively, and a gain of $6.8 million and a loss of $14.8 million for the three and six months ended June 30, 2011, respectively, of APL’s mark-to-market gain (loss) on derivatives valued upon unobservable inputs.

Three Months Ended June 30, 2012 Compared with the Three Months Ended June 30, 2011. Gain on mark-to-market derivatives was $67.8 million for the three months ended June 30, 2012 as compared with a $6.8 million gain for the three months ended June 30, 2011. This favorable movement was primarily due to a $51.1 million favorable variance in non-cash mark-to-market adjustments on APL’s commodity derivatives and a $9.9 million favorable movement in realized settlements on net cash derivative expense related to APL’s commodity derivatives, mainly as a result of lower NGL prices.

Six Months Ended June 30, 2012 Compared with the Six Months Ended June 30, 2011. Gain on mark-to-market derivatives was $55.8 million for the six months ended June 30, 2012 as compared with a $14.8 million loss for the six months ended June 30, 2011. This favorable movement was primarily due to a $58.9 million favorable variance in non-cash mark-to-market adjustments on APL’s commodity derivatives and an $11.7 million favorable movement in realized settlements on net cash derivative expense related to APL’s commodity derivatives, mainly as a result of lower NGL prices.

Other, Net

Three Months Ended June 30, 2012 Compared with the Three Months Ended June 30, 2011. Other, net was $0.5 million for the three months ended June 30, 2012 as compared with $21.4 million for the comparable prior year period. This decrease was primarily due to an $18.6 million decrease in our equity earnings from Lightfoot, a $3.6 million premium amortization associated with ARP’s derivative contracts which provided ARP with the option to enter into swap contracts up through May 31, 2012 (“swaptions”) for production volumes related to wells recently acquired from Carrizo (see “Recent Developments”) and lower interest income, partially due to APL’s December 2011 settlement of a note receivable from The Williams Companies, Inc. (NYSE: WMB; “Williams”) related to APL’s 49% non-controlling ownership interest in Laurel Mountain, which was sold in February 2011. These unfavorable movements were partially offset by a $1.2 million increase in income from APL’s equity investments. During the three months ended June 30, 2011, we recorded a gain of $17.6 million pertaining to our share of Lightfoot LP’s gain recognized on the sale of International Resource Partners LP, its metallurgical and steam coal business in March 2011. At June 30, 2012, the premium associated with ARP’s swaption contracts was fully amortized.

Six Months Ended June 30, 2012 Compared with the Six Months Ended June 30, 2011. Other, net was $3.3 million for the six months ended June 30, 2012 as compared with $25.8 million for the comparable prior year period. This decrease was primarily due to a $19.8 million decrease in our equity earnings from Lightfoot, the $4.6 million premium amortization associated with ARP’s derivative contracts for production volumes related to wells recently acquired from Carrizo (see “Recent Developments”) and lower interest income, partially due to APL’s December 2011 settlement of a note receivable

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from Williams related to APL’s 49% non-controlling ownership interest in Laurel Mountain, which was sold in February 2011. These unfavorable movements were partially offset by the $1.7 million increase in income from equity investments. During the six months ended June 30, 2011, we recorded a gain of $17.6 million pertaining to our share of Lightfoot LP’s gain recognized on the sale of International Resource Partners LP, its metallurgical and steam coal business in March 2011.

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 June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
General and Administrative expenses:
Atlas Energy	$	6,624	$	10,393	$	22,185	$	13,324
Atlas Resource		20,538		3,276		32,280		7,518
Atlas Pipeline		10,445		8,570		20,390		17,587
Total	$	37,607	$	22,239	$	74,855	$	38,429

Total general and administrative expenses increased to $37.6 million for the three months ended June 30, 2012 compared with $22.2 million for the three months ended June 30, 2011. Our $6.6 million of general and administrative expenses for the three months ended June 30, 2012 represents a $3.8 million decrease from the comparable period primarily related to the transfer of assets to ARP on March 5, 2012, as ARP is now responsible for these costs. ARP’s $20.5 million of general and administrative expenses for the three months ended June 30, 2012 represents a $17.3 million increase from the comparable period primarily due to an $8.8 million increase in non-recurring transaction costs principally associated with the acquisition of certain assets from Carrizo (see “Recent Developments”), a $5.4 million increase related to a decrease in reimbursements associated with the expiration of our transition services agreement with Chevron, a $3.0 million increase in non-cash compensation expense and a $0.1 million increase related to consulting and other outside services. APL’s $10.4 million of general and administrative expense for the three months ended June 30, 2012 represents an increase of $1.9 million from the comparable prior year period, which was principally due to a $2.9 million increase of non-cash compensation expense, a $0.4 million increase related to insurance and a $0.2 million increase in outside services, partially offset by a $1.6 million decrease in salaries and wages.

Total general and administrative expenses increased to $74.9 million for the six months ended June 30, 2012 compared with $38.4 million for the six months ended June 30, 2011. Our $22.2 million of general and administrative expenses for the six months ended June 30, 2012 represents an $8.9 million increase from the comparable period primarily due to a $6.3 million increase resulting from costs incurred in the formation of ARP and the related distribution of its common units a $4.7 million increase of non-cash compensation expense, and a $2.3 million increase in outside services, partially offset by a $4.4 million decrease related to the transfer of assets to ARP on March 5, 2012, as ARP is now responsible for these costs. ARP’s $32.3 million of general and administrative expenses for the six months ended June 30, 2012 represents a $24.8 million increase from the comparable period primarily due to an $11.2 million increase in non-recurring transaction costs associated with the Carrizo acquisition (see “Recent Developments”), an $8.8 million increase related to a decrease in reimbursements associated with the expiration of our transition services agreement with Chevron, a $3.0 million increase in non-cash compensation expense and a $1.8 million increase in salary and wages expenses related to the growth of our business. APL’s $20.4 million of general and administrative expense for the six months ended June 30, 2012 represents an increase of $2.8 million from the comparable prior year period, which was principally due to a $3.9 million increase of non-cash compensation expense and a $0.8 million increase related to insurance, partially offset by a $1.6 million decrease in salaries and wages and a $0.3 million decrease in outside services.

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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 June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Depreciation, depletion and amortization:
Atlas Resource	$	10,822	$	8,247	$	19,930	$	15,948
Atlas Pipeline		21,712		19,123		42,554		38,029
Total	$	32,534	$	27,370	$	62,484	$	53,977

Total depreciation, depletion and amortization increased to $32.5 million for the three months ended June 30, 2012 compared with $27.4 million for the comparable prior year period primarily due to a $2.3 million increase in ARP’s depletion expense and a $2.6 million increase in APL’s depreciation expenses, principally associated with APL’s expansion capital expenditures incurred subsequent to June 30, 2011.

Total depreciation, depletion and amortization increased to $62.5 million for the six months ended June 30, 2012 compared with $54.0 million for the comparable prior year period primarily due to a $3.4 million increase in ARP’s depletion expense and a $4.5 million increase in APL’s depreciation expenses, principally associated with APL’s expansion capital expenditures incurred subsequent to June 30, 2011.

The following table presents ARP’s depletion expense per Mcfe for its operations for the respective periods:

	Three Months Ended June  30,						Six Months Ended June 30,
	2012			2011			2012			2011
Depletion expense (in thousands):
Total	$	9,520		$	7,178		$	17,087		$	13,744
Depletion expense as a percentage of gas and oil production revenue		49	%		41	%		47	%		39	%
Depletion per Mcfe	$	1.67		$	2.15		$	1.84		$	2.06

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 June 30, 2012, depletion expense increased $2.3 million to $9.5 million compared with $7.2 million for the three months ended June 30, 2011. ARP’s depletion expense of gas and oil properties as a percentage of gas and oil revenues was 49% for the three months ended June 30, 2012, compared with 41% for the three months ended June 30, 2011, which was primarily due to a decrease in realized natural gas prices and an increase in production volumes between periods. Depletion expense per Mcfe was $1.67 for the three months ended June 30, 2012, a decrease of $0.48 per Mcfe from $2.15 for the three months ended June 30, 2011, primarily related to lower depletion expense per Mcfe for the assets acquired from Carrizo (see “Recent Developments”) and the addition of reserves for Marcellus Shale wells, which began production during March 2012. Depletion expense increased between periods principally due to an overall increase in production volume.

For the six months ended June 30, 2012, depletion expense increased $3.4 million to $17.1 million compared with $13.7 million for the six months ended June 30, 2011. ARP’s depletion expense of gas and oil properties as a percentage of gas and oil revenues was 47% for the six months ended June 30, 2012, compared with 39% for the six months ended June 30, 2011, which was primarily due to a decrease in realized natural gas prices and an increase in production volumes between periods. Depletion expense per Mcfe was $1.84 for the six months ended June 30, 2012, a decrease of $0.22 per Mcfe from $2.06 for the six months ended June 30, 2011, primarily related to lower depletion expense per Mcfe for the assets acquired from Carrizo (see “Recent Developments”) and the addition of reserves for Marcellus Shale wells, which began production during March 2012. Depletion expense increased between periods principally due to an overall increase in production volume.

Gain (Loss) on Asset Sales and Disposals

Gain (loss) on asset sales and disposals were consistent for the three months ended June 30, 2012 and 2011, respectively.

During the six months ended June 30, 2012, the loss on asset sales and disposal was $7.0 million, compared to a gain of $255.7 million for the six months ended June 30, 2011. The $7.0 million loss on asset sales and disposal for the six months ended June 30, 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

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contained certain well drilling targets for ARP to maintain ownership of the South Knox processing plant, which ARP’s management decided in 2012 not to 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 during the first six months of 2012. The $255.7 million gain on asset sales and disposal for the six months ended June 30, 2011 primarily related to APL’s gain of $255.9 million 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 June  30,				Six Months Ended June 30,
	2012		2011		2012		2011
Interest Expense:
Atlas Energy	$	69	$	423	$	302	$	6,056
Atlas Resource		956		—		1,106		—
Atlas Pipeline		9,269		6,144		17,977		18,589
Total	$	10,294	$	6,567	$	19,385	$	24,645

Total interest expense increased to $10.3 million for the three months ended June 30, 2012 as compared with $6.6 million for the three months ended June 30, 2011. This $3.7 million increase was due to a $3.1 million increase related to APL and a $1.0 million increase related to ARP, partially offset by our $0.4 million decrease. Our $0.4 million decrease in interest expense was primarily due to $0.2 million of commitment fees in the prior year period related to the unused portion of our previous credit facility and $0.2 million in amortization of deferred financing costs in the prior year period. Our previous credit facility was assigned to ARP on March 5, 2012 (see “ARP Credit Facility”). The $1.0 million increase in ARP’s interest expense was associated with outstanding borrowings under the transferred credit facility and amortization of deferred financing costs associated with the credit facility. The $3.1 million increase in interest expense for APL was primarily due to a $3.1 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 $1.2 million increase in interest associated with APL’s revolving credit facility, partially offset by a $0.9 million increase in APL’s capitalized interest. 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.

Total interest expense decreased to $19.4 million for the six months ended June 30, 2012 as compared with $24.6 million for the six months ended June 30, 2011. This $5.2 million decrease was due to our $5.8 million decrease and a $0.6 million decrease related to APL, partially offset by a $1.1 million increase related to ARP. Our $5.8 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 and $0.6 million in interest expense related to borrowings from affiliates during the prior year period. The bridge credit facility was replaced in March 2011 by our previous credit facility, which was transferred to ARP in March 2012 (see “ARP Credit Facility”). The $1.1 million increase in ARP’s interest expense was associated with outstanding borrowings under the transferred credit facility and amortization of deferred financing costs associated with the credit facility. The $0.6 million decrease in interest expense for APL was primarily due to a $6.0 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 $2.9 million increase in APL’s capitalized interest, partially offset by a $6.0 million increase in interest expense associated with APL’s 8.75% Senior Notes and a $2.1 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.

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Loss on Early Extinguishment of Debt

Loss on early extinguishment of debt for the three and six months ended June 30, 2011 represents the premium paid for the redemption of the APL 8.125% Senior Notes and APL’s recognition of deferred finance costs related to the redemption.

Income Not Attributable to Common Limited Partners

For the six months ended June 30, 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”).

Income Attributable to Non-Controlling Interests

Income attributable to non-controlling interests was $59.2 million for the three months ended June 30, 2012 as compared with $7.9 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 increase between the three months ended June 30, 2012 and the prior year comparable period was primarily due to the increase in APL’s net earnings between periods, as a result of the gain on mark- to-market derivatives in the current year period.

Income attributable to non-controlling interests was $62.6 million for the six months ended June 30, 2012 as compared with $219.3 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 six months ended June 30, 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, partially offset by the gain on mark-to-market derivatives in the current year period.

LIQUIDITY AND CAPITAL RESOURCES

General

Our primary sources of liquidity are cash distributions received with respect to our ownership interests in ARP and APL and borrowings under our credit facility. 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.

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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 our, 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 – Six Months Ended June 30, 2012 Compared with the Six Months Ended June 30, 2011

Net cash used in operating activities of $24.7 million for the six months ended June 30, 2012 represented an unfavorable movement of $83.0 million from net cash provided by operating activities of $58.3 million for the comparable prior year period. The $83.0 million decrease was derived principally from a $109.1 million unfavorable movement in non-cash loss on derivatives and a $15.8 million unfavorable movement in distributions paid to non-controlling interests, partially offset by a $9.0 million favorable movement in working capital and a $32.9 million increase in net income excluding non-cash items. The non-cash charges which impacted net income included a $262.7 million favorable movement in gain (loss) on asset disposals, partially offset by a $0.1 million unfavorable movement in non-cash expenses including loss on early extinguishment of debt, depreciation, depletion and amortization, amortization of deferred financing costs, equity income and distributions from unconsolidated companies and compensation expense and a $229.7 million decrease in net income 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 $93.0 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 an $84.0 million unfavorable movement in accounts payable and other current liabilities.

Net cash used in investing activities of $432.8 million for the six months ended June 30, 2012 represented an unfavorable movement of $638.8 million from net cash provided by investing activities of $206.0 million for the comparable prior year period. This unfavorable movement was principally due to a $411.5 million decrease in net proceeds from asset disposals, an $85.7 million unfavorable movement in capital expenditures and a $241.9 million unfavorable movement in net cash paid for acquisitions, partially offset by a $97.2 million favorable movement in APL’s investments in unconsolidated companies and a $3.1 million favorable movement in other assets. The net cash paid for acquisitions included cash paid for ARP’s acquisition of Carrizo and the formation of its joint venture with Equal (see “Recent Developments”) and APL’s acquisitions. See further discussion of capital expenditures under “- Capital Requirements”.

Net cash provided by financing activities of $414.0 million for the six months ended June 30, 2012 represented a favorable movement of $569.8 million from net cash used in financing activities of $155.8 million for the comparable prior year period. This movement was principally due to a $315.0 million favorable movement in repayments of long-term debt, a $191.5 million increase in ARP’s and APL’s borrowings under their respective credit facilities, a $119.4 million favorable movement in net proceeds from ARP’s equity offering related to the Carrizo acquisition, a $68.5 million favorable movement in repayments of ARP’s and APL’s respective credit facilities, a $14.4 million favorable movement in APL’s payments of premiums on the early retirement of debt and an $8.0 million favorable movement due to the redemption of APL’s preferred equity, partially offset by a $121.0 million unfavorable movement in the non-cash transaction adjustment related to the acquisition of the Transferred Business on February 17, 2011, a $17.6 million increase in distributions paid to unitholders and an $8.4 million unfavorable movement in deferred financing costs and other. The gross amount of borrowings and repayments under the credit facilities included within net cash used in financing activities in the consolidated combined statements of cash flows, which are generally in excess of net borrowings or repayments during the period or at period end, reflect the timing of cash receipts, which generally occur at specific intervals during the period and are utilized to reduce borrowings under the credit facilities, and payments, which generally occur throughout the period and increase borrowings under the credit facilities, for ARP and APL, which is generally common practice for their industries.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Atlas Resource
Maintenance capital expenditures	$	1,750	$	3,567	$	3,500	$	5,233
Expansion capital expenditures		24,944		3,083		42,152		9,149
Total	$	26,694	$	6,650	$	45,652	$	14,382
Atlas Pipeline
Maintenance capital expenditures	$	4,000	$	5,211	$	8,510	$	8,471
Expansion capital expenditures		61,221		68,425		137,878		83,498
Total	$	65,221	$	73,636	$	146,388	$	91,969
Consolidated Combined
Maintenance capital expenditures	$	5,750	$	8,778	$	12,010	$	13,704
Expansion capital expenditures		86,165		71,508		180,030		92,647
Total	$	91,915	$	80,286	$	192,040	$	106,351

During the three months ended June 30, 2012, ARP’s $26.7 million of total capital expenditures consisted primarily of $4.4 million for well costs, which consist principally of ARP’s investments in the investment partnerships, compared with $3.1 million for the prior year comparable period, $18.9 million of leasehold acquisition costs compared with $0.7 million for the prior year comparable period, $0.7 million of gathering and processing costs compared with $1.3 million for the prior year comparable period and $2.7 million of corporate and other compared with $1.6 million for the prior year comparable period. The increase in investments in the investment partnerships was the result of the cancellation of ARP’s Fall 2010 drilling program and the resulting reduction of partnership capital deployed during 2011. The net increase in leasehold acquisition costs principally related to additional Mississippi Lime acreage acquired subsequent to the formation of ARP’s joint venture with Equal during the three months ended June 30, 2012.

During the six months ended June 30, 2012, ARP’s $45.7 million of total capital expenditures consisted primarily of $17.5 million for well costs, compared with $7.1 million for the prior year comparable period, $22.7 million of leasehold acquisition costs compared with $1.4 million for the prior year comparable period, $1.0 million of gathering and processing costs compared with $2.4 million for the prior year comparable period and $4.5 million of corporate and other compared with

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$3.5 million for the prior year comparable period. The increase in well costs was principally the result of the cancellation of ARP’s Fall 2010 drilling program and the resulting reduction of partnership capital deployed during 2011. The net increase in leasehold acquisition costs principally related to additional Mississippi Lime acreage acquired subsequent to the formation of ARP’s joint venture with Equal during the six months ended June 30, 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 decreased to $65.2 million for the three months ended June 30, 2012 compared with $73.6 million for the comparable prior year period. The decrease was due principally to timing of expenditures related to certain processing facilities and pipeline expansion projects.

APL’s capital expenditures increased to $146.4 million for the six months ended June 30, 2012 compared with $92.0 million for the comparable prior year period. The increase was primarily due to current major processing facility expansions, compressor upgrades and pipeline projects, including a 60 MMCFD expansion at the Velma system, which was placed in service in June 2012; a 200 MMCFD expansion at the WestOK system scheduled to be placed in service in the second half of 2012; and construction of a 100 MMCFD plant in the WestTX system scheduled to be placed in service in the first half of 2013.

As of June 30, 2012, ARP and APL are committed to expend approximately $108.7 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

OFF BALANCE SHEET ARRANGEMENTS

As of June 30, 2012, our off-balance sheet arrangements are limited to ARP’s letters of credit outstanding of $0.6 million, APL’s letters of credit outstanding of $0.1 million and ARP’s and APL’s commitments to spend $108.7 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

• 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.

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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. During the three and six months ended June 30, 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 $1.6 million and $3.0 million were paid during the three and six months ended June 30, 2012, respectively. No incentive distributions were paid during the three and six months ended June 30, 2011.

CREDIT FACILITY

In May 2012, we entered into a new credit facility with a syndicate of banks that matures in May 2016. The credit facility has maximum lender commitments of $50.0 million, and up to $5.0 million of the credit facility may be in the form of standby letters of credit. At June 30, 2012, no amounts were outstanding under the credit facility. Our obligations under the credit facility are secured by substantially all of our assets, including our ownership interests in APL and ARP. Additionally, our obligations under the credit facility may be guaranteed by future subsidiaries. At our election, interest on borrowings under the credit facility is determined by reference to either LIBOR plus an applicable margin of between 3.50% and 4.50% per annum or the base rate plus an applicable margin of between 2.50% and 3.50% per annum. The applicable margin will fluctuate based on the utilization of the facility. We are required to pay a fee between 0.5% and 0.625% per annum on the unused portion of the borrowing base, which is included within interest expense on our consolidated combined statement of operations.

The credit agreement contains customary covenants that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a commitment deficiency exists or a default under the credit agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of our assets.

The credit agreement also contains covenants that require us to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to EBITDA (as defined in the credit agreement) not greater than 3.25 to 1.0 as of the last day of any fiscal quarter and a ratio of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) not less than 2.75 to 1.0 as of the last day of any fiscal quarter.

At June 30, 2012, we have not guaranteed any of ARP’s or APL’s debt obligations.

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ARP Credit Facility

At June 30, 2012, ARP had a senior secured credit facility with a syndicate of banks with a borrowing base of $250.0 million and with $144.0 million outstanding. The credit facility matures in March 2016 and the borrowing base will be redetermined semi-annually in May and November. Up to $20.0 million of the credit facility may be in the form of standby letters of credit which would reduce ARP’s borrowing base, of which $0.6 million was outstanding at June 30, 2012, and was not reflected as borrowings on our 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, including all of its ownership interests in a majority of its material operating subsidiaries. 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 3.00% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 1.00% and 2.00% per annum. The applicable margin will fluctuate based on the utilization of the facility. Interest is generally payable quarterly for ABR loans and at the applicable maturity date for LIBOR loans. 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 our consolidated combined statements of operations. At June 30, 2012, the weighted average interest rate was 3.1%.

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, 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 ARP’s assets. ARP was in compliance with these covenants as of June 30, 2012. The credit agreement also requires ARP to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to four quarters (actual or annualized, as applicable) of EBITDA (as defined in the credit agreement) not greater than 3.75 to 1.0 as of the last day of any fiscal quarter, a ratio of current assets (as defined in the credit agreement) to current liabilities (as defined in the credit agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter, and a ratio of four quarters (actual or annualized, as applicable) of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) of not less than 2.5 to 1.0 as of the last day of any fiscal quarter.

APL Credit Facility

At June 30, 2012, APL had a $600.0 million senior secured revolving credit facility with a syndicate of banks, which matures in May 2017, of which $330.5 million was outstanding. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) three-month LIBOR plus 1.0%, or (ii) the LIBOR rate for the applicable period (each plus the applicable margin). The weighted average interest rate on APL’s outstanding revolving credit facility borrowings at June 30, 2012 was 2.7%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $0.1 million was outstanding at June 30, 2012. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated combined balance sheet at June 30, 2012. At June 30, 2012, APL had $269.4 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.

On May 31, 2012, APL entered into an amendment to the revolving credit facility agreement, which among other changes: 1) increased the revolving credit facility from $450.0 million to $600.0 million; 2) extended the maturity date from December 22, 2015 to May 31, 2017; 3) reduced the applicable margin used to determine interest rates by 0.50%; (4) revised the negative covenants to (i) permit investments in joint ventures equal to the greater of 20% of Consolidated Net Tangible Assets (as defined in the Credit Agreement) or $340.0 million, provided APL meets certain requirements, and (ii) increased the general investment basket to 5.0% of Consolidated Net Tangible Assets; (5) revised the definition of “Consolidated EBITDA” to provide for the inclusion of the first twelve months of projected revenues for identified capital expansion projects with a cost in excess of $20.0 million, upon completion of the projects and; (6) provided for the potential increase of revolving credit commitments up to an additional $200.0 million.

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.

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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 June 30, 2012.

ARP Secured Hedge Facility

At June 30, 2012, ARP had a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships will have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under ARP’s senior secured credit facility, 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 Drilling Partnerships under the secured hedge facility. Before executing any hedge transaction, a participating Drilling Partnership is required to, among other things, provide mortgages on its oil and gas properties and first priority security interests in substantially all of its assets to the collateral agent for the benefit of the counterparty. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets.

In addition, it will be an event of default under ARP’s credit facility if ARP, as general partner of the Drilling Partnerships, breach an obligation governed by the secured hedge facility and the effect of such breach is to cause amounts owing under swap agreements governed by the secured hedge facility to become immediately due and payable.

ISSUANCE OF UNITS

We recognize gains on ARP’s and APL’s equity transactions as credits to partners’ capital on our consolidated combined balance sheets rather than as income on our consolidated combined statements of operations. 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.

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

On April 30, 2012, ARP completed the acquisition of certain oil and gas assets from Carrizo (see “Recent Developments”). To partially fund the acquisition, ARP sold 6.0 million of its common units in a private placement at a negotiated purchase price per unit of $20.00, for gross proceeds of $120.6 million, of which $5.0 million was purchased by certain of our executives. The common units issued by ARP are subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement stipulated that ARP would (a) file a registration statement with the Securities and Exchange Commission by October 30, 2012 and (b) cause the registration statement to be declared effective by the Securities and Exchange Commission by December 31, 2012. If ARP does not meet the aforementioned deadline for the common units to be declared effective, the common unit holders subject to the registration rights agreement will receive liquidated damages of 0.50% of the gross proceeds from the private placement, or $0.6 million, for the first 30-day period after December 31, 2012, increasing by an additional 0.50% per 30-day period thereafter, up to a maximum of 2.0% of the gross proceeds of the private placement per 30-day period. On July 11, 2012, ARP filed a registration statement with the Securities and Exchange Commission for the common units subject to the registration rights agreement in satisfaction of one of the requirements of the registration rights agreement noted previously. In connection with the private placement of common units, we recorded an $11.2 million gain within partners’ capital and a corresponding decrease in non-controlling interests on our consolidated combined balance sheet at June 30, 2012.

In February 2012, the board of directors of our general partner 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 these limited partner units represented approximately 20.0% of the common limited partner units outstanding (see “Business Overview”).

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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 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 Annual Report on Form 10-K for the year ended December 31, 2011 and we summarize our significant accounting policies within our consolidated combined financial statements included in Note 2 under “Item 1: Financial Statements” included in this report. The critical accounting policies and estimates we have identified are discussed below.

Depreciation and Impairment of Long-Lived Assets and Goodwill

Long-Lived Assets. The cost of property, plant and equipment, less estimated salvage value, is generally depreciated on a straight-line basis over the estimated useful lives of the assets. Useful lives are based on historical experience and are adjusted when changes in planned use, technological advances or other factors indicate that a different life would be more appropriate. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively.

Long-lived assets, other than goodwill and intangibles with infinite lives, generally consist of natural gas and oil properties and pipeline, processing and compression facilities and are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. A long-lived asset, other than goodwill and intangibles with infinite lives, is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. The undiscounted net cash flows expected to be generated by the asset are based upon our estimates that rely on various assumptions, including natural gas and oil prices, production and operating expenses. Any significant variance in these assumptions could materially affect the estimated net cash flows expected to be generated by the asset. As discussed in General Trends and Outlook within this section, recent increases in natural gas drilling has driven an increase in the supply of natural gas and put a downward pressure on domestic prices. Further declines in natural gas prices may result in additional impairment charges in future periods.

There were no impairments of proved or unproved properties recorded for the three and six months ended June 30, 2012 or 2011. During the year ended December 31, 2011, ARP recognized $7.0 million of asset impairment related to gas and oil properties within property, plant and equipment on our consolidated combined balance sheet for its shallow natural gas wells in the Niobrara Shale. This impairment related to the carrying amount of these gas and oil properties being in excess of 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.

Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. Additional factors impacting the economic viability of long-lived assets are discussed under “Item 1A: Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2011.

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

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There were no goodwill impairments recognized by us for the three and six months ended June 30, 2012 and 2011, respectively.

Fair Value of Financial Instruments

We and our subsidiaries have established a hierarchy to measure our financial instruments at fair value which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

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

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

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

We use a fair value methodology to value the assets and liabilities for ARP’s and APL’s outstanding derivative contracts. ARP’s and APL’s commodity hedges, with the exception of APL’s NGL fixed price swaps and NGL options, are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of natural gas, crude oil and propane prices and therefore are defined as Level 3 fair value measurements. Valuations for APL’s NGL options are based on forward price curves developed by the related financial institution and therefore are defined as Level 3 fair value measurements.

Of the $102.6 million and $46.4 million of net derivative assets at June 30, 2012 and December 31, 2011, respectively, APL had a net asset of $53.0 million and $16.5 million at June 30, 2012 and December 31, 2011, respectively, that were classified as Level 3 fair value measurements which rely on subjective forward developed price curves. Holding all other variables constant, a 10% change in the prices APL utilized in calculating the fair value of derivatives at June 30, 2012 would have resulted in an $8.4 million non-cash change to net income for the six months ended June 30, 2012.

Liabilities that are required to be measured at fair value on a nonrecurring basis include our asset retirement obligations (“ARO’s”) that are defined as Level 3. Estimates of the fair value of ARO’s are based on discounted cash flows using numerous estimates, assumptions, and judgments regarding the cost, timing of settlement, our credit-adjusted risk-free rate and inflation rates.

Reserve Estimates

Our estimates of ARP’s proved natural gas and oil reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas and oil prices, drilling and operating expenses, capital expenditures and availability of funds. The accuracy of these reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates. As discussed in “Item 2: Properties” within our Annual Report on Form 10-K for the year ended December 31, 2011, we engaged Wright and Company, Inc., an independent third-party reserve engineer, to prepare a report of our proved reserves.

Any significant variance in the assumptions utilized in the calculation of ARP’s reserve estimates could materially affect the estimated quantity of ARP’s reserves. As a result, our estimates of ARP’s proved natural gas and oil reserves are inherently imprecise. Actual future production, natural gas and oil prices, revenues, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves may vary substantially from our estimates or estimates contained in the reserve reports and may affect our and ARP’s ability to pay amounts due under our and ARP’s credit facility or cause a reduction in our or ARP’s credit facility. In addition, ARP’s proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing natural gas and oil prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control. ARP’s reserves and their relation to estimated future net cash flows impact the calculation of impairment and depletion of oil and gas properties. Adjustments to quarterly depletion rates, which are based upon a units of production method, are made concurrently with changes to reserve estimates. Generally, an increase or decrease in reserves without a corresponding change in capitalized costs will have a corresponding inverse impact to depletion expense.

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Asset Retirement Obligations

On an annual basis, we and our subsidiaries estimate the cost of future dismantlement, restoration, reclamation and abandonment of our operating assets. We and our subsidiaries also estimate the salvage value of equipment recoverable upon abandonment. For the three and six months ended June 30, 2012 and 2011, the estimate of salvage values was greater than or equal to our estimate of the costs of future dismantlement, restoration, reclamation and abandonment. Projecting future retirement cost estimates is difficult as it involves the estimation of many variables such as economic recoveries of reserves, future labor and equipment rates, future inflation rates and our subsidiaries’ credit adjusted risk free rate. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Since there are many variables in estimating asset retirement obligations, we attempt to limit the impact of management’s judgment on certain of these variables by developing a standard cost estimate based on historical costs and industry quotes updated annually. To the extent future revisions to these assumptions impact the fair value of our existing asset retirement obligation, a corresponding adjustment is made to our gas and oil properties and other property, plant and equipment. A decrease in salvage values or an increase in dismantlement, restoration, reclamation and abandonment costs from those we and our subsidiaries have estimated, or changes in their estimates or costs, could reduce our gross profit from operations.

ITEM 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 June 30, 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.

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 June 30, 2012, we had no outstanding borrowings and ARP had $144.0 million of outstanding borrowings under its revolving credit facility. At June 30, 2012, APL had $330.5 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 for the twelve-month period ending June 30, 2013 by $4.7 million, excluding the effect of non-controlling interests.

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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 June 30, 2013 of approximately $4.6 million, net of non-controlling interests.

At June 30, 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		9,060,000	$	3.550
2013		11,160,000	$	4.076
2014		10,800,000	$	4.373
2015		7,350,000	$	4.430

Natural Gas Costless Collars

Production Period Ending December 31,	Option Type	Volumes		Average Floor and  Cap
		(mmbtu)(1)		(per mmbtu)(1)
2012	Puts purchased		2,160,000	$	4.074
2012	Calls sold		2,160,000	$	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		3,480,000	$	4.234
2015	Calls sold		3,480,000	$	5.129

Natural Gas Put Options

Production Period Ending December 31,	Option Type		Volumes		Average Fixed Price
			(mmbtu)(1)		(per mmbtu)(1)
2012		Puts purchased		2,940,000	$	2.802
2013		Puts purchased		3,180,000	$	3.450
2014		Puts purchased		1,800,000	$	3.800
2015		Puts purchased		1,440,000	$	4.000
2016		Puts purchased		1,440,000	$	4.150

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Crude Oil Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(Bbl)(1)		(per Bbl)(1)
2012		13,500	$	103.804
2013		18,600	$	100.669
2014		36,000	$	97.693
2015		45,000	$	89.504

Crude Oil Costless Collars

Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap
		(Bbl)(1)		(per Bbl)(1)
2012	Puts purchased		30,000	$	90.000
2012	Calls sold		30,000	$	117.912
2013	Puts purchased		60,000	$	90.000
2013	Calls sold		60,000	$	116.396
2014	Puts purchased		41,160	$	84.169
2014	Calls sold		41,160	$	113.308
2015	Puts purchased		29,250	$	83.846
2015	Calls sold		29,250	$	110.654

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

As of June 30, 2012, APL had the following commodity derivatives:

Fixed Price Swaps

Production Period	Purchased/ Sold		Commodity	Volumes(1)		Average Fixed Price
Natural Gas
2012		Sold	Natural Gas		2,460,000	$	3.117
2013		Sold	Natural Gas		1,200,000	$	3.476
2014		Sold	Natural Gas		5,400,000	$	3.903
NGLs
2012		Sold	Propane		10,080,000	$	1.300
2012		Sold	Normal Butane		2,646,000	$	1.709
2012		Sold	Isobutane		1,512,000	$	1.577
2012		Sold	Natural Gasoline		2,142,000	$	2.393
2013		Sold	Propane		46,368,000	$	1.257
2013		Sold	Normal Butane		2,394,000	$	1.662
2013		Sold	Isobutane		1,134,000	$	1.807
2014		Sold	Propane		630,000	$	1.268
Crude Oil
2012		Sold	Crude Oil		144,000	$	96.093
2013		Sold	Crude Oil		345,000	$	97.170
2014		Sold	Crude Oil		60,000	$	98.425

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Options

Production Period	Purchased/ Sold	Type		Commodity	Volumes(1)		Average Strike Price
NGLs
2012	Purchased		Put	Propane		15,750,000	$	1.362
2012	Purchased		Put	Normal Butane		4,032,000	$	1.550
2012	Purchased		Put	Isobutane		2,142,000	$	1.577
2012	Purchased		Put	Natural Gasoline		7,812,000	$	1.997
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		249,000	$	94.694
2012	Purchased(2)		Call	Crude Oil		90,000	$	125.200
2012	Purchased		Put	Crude Oil		78,000	$	106.180
2013	Purchased		Put	Crude Oil		282,000	$	100.100
2014	Purchased		Put	Crude Oil		136,500	$	104.750

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

⁽²⁾  Calls purchased for 2012 represent offsetting positions for calls sold as part of costless collars. 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 June 30, 2012, our disclosure controls and procedures were effective at the reasonable assurance level.

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.

On April 30, 2012, ARP acquired certain assets from Carrizo (see Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—“Recent Developments”). We are continuing to integrate these systems’ historical internal controls over financial reporting with our existing internal controls over financial reporting. This integration may lead to changes in our or the acquired systems’ historical internal controls over financial reporting in future fiscal reporting periods.

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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)

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Exhibit No.	Description
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 (33)
10.5(a)	Amended and Restated Limited Partnership Agreement of Atlas Resource Partners, L.P.(28)
10.5(b)	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Atlas Resource Partners, L.P. dated as of July 25, 2012(17)
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)
10.10(d)	Amendment No. 2 to the Amended and Restated Credit Agreement, dated as of May 31, 2012(18)
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)

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Exhibit No.	Description
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 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)	Amended and Restated 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 Amended and Restated 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 Pipeline, LLC and Wells Fargo Bank, N.A.(31)
10.25(e)	Second Amendment to Amended and Restated Credit Agreement, dated as of July 26, 2012, between Atlas Resource Partners, L.P. and Wells Fargo Bank, N.A., as administrative agent for the Lenders (17)

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Exhibit No.	Description
10.25(f)	Joinder Agreement dated as of July 26, 2012 between Atlas Barnett, LLC and Wells Fargo Bank, N.A. (17)
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)
10.29	Credit Agreement, dated as of May 16, 2012, among Atlas Energy, L.P. and Wells Fargo Bank, N.A., as administrative agent for the Lenders (2)
10.30	Merger Agreement dated as of May 17, 2012 among Atlas Resource Partners, L.P., Titan Merger Sub, LLC and Titan Operating, LLC. (3)
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(34)
101.SCH	XBRL Schema Document(34)
101.CAL	XBRL Calculation Linkbase Document(34)
101.LAB	XBRL Label Linkbase Document(34)
101.PRE	XBRL Presentation Linkbase Document(34)
101.DEF	XBRL Definition Linkbase Document(34)

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

(2) Previously filed as an exhibit to current report on Form 8-K filed May 21, 2012.

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

(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) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on July 26, 2012.

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

(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.

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(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) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended March 31, 2012.

(34) 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: August 9, 2012	By:	/s/ EDWARD E. COHEN
		Edward E. Cohen
		Chief Executive Officer and President of the General Partner
Date: August 9, 2012	By:	/s/ SEAN P. MCGRATH
		Sean P. McGrath
		Chief Financial Officer of the General Partner
Date: August 9, 2012	By:	/s/ JEFFREY M. SLOTTERBACK
		Jeffrey M. Slotterback
		Chief Accounting Officer of the General Partner

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