ARKHAN 10-Q 2010 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2010

OR

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

For the transition period from            to            

Commission file number: 001-32169

ATLAS ENERGY, INC.

(Exact name of registrant as specified in its charter)

DELAWARE	51-0404430
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

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

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

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

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

Indicate by check mark 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 a 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 shares of the registrant’s common stock on May 4, 2010 was 78,325,295 shares.

ATLAS ENERGY, INC. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

		PAGE
PART I.            FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)	3
	Consolidated Balance Sheets as of March 31, 2010 and December 31, 2009	3
	Consolidated Statements of Operations for the Three Months Ended March 31, 2010 and 2009	4
	Consolidated Statement of Shareholders’ Equity for the Three Months Ended March 31, 2010	5
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2010 and 2009	6
	Notes to Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	45
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	59
Item 4.	Controls and Procedures	62
PART II.            OTHER INFORMATION
Item 1.	Legal Proceedings	63
Item 1A.	Risk Factors	63
Item 6.	Exhibits	64
SIGNATURES		67

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)

(Unaudited)

	March 31, 2010			December 31, 2009
ASSETS
Current assets:
Cash and cash equivalents	$	13,548		$	20,627
Accounts receivable		137,335			172,848
Current portion of derivative asset		118,433			74,064
Subscriptions receivable from Partnerships		—			47,275
Prepaid expenses and other		31,046			31,010
Prepaid and deferred taxes		1,128			1,559
Total current assets		301,490			347,383
Property, plant and equipment, net		3,586,735			3,555,802
Intangible assets, net		164,398			170,964
Goodwill, net		35,166			35,166
Long-term derivative asset		106,383			59,291
Investment in joint venture		130,461			132,990
Other assets, net		82,684			74,833
Deferred tax asset		11,445			29,734
	$	4,418,762		$	4,406,163
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	4,590		$	8,000
Accounts payable		82,451			99,748
Liabilities associated with drilling contracts		49,508			122,532
Accrued producer liabilities		65,621			66,211
Current portion of derivative payable to Partnerships		37,605			22,382
Current portion of derivative liability		17,732			38,485
Accrued interest		28,309			38,898
Accrued well drilling and completion costs		84,715			89,261
Current portion of deferred tax liability		33,052			26,415
Accrued liabilities		36,316			45,969
Advances from affiliate		143			173
Total current liabilities		440,042			558,074
Long-term debt, less current portion		2,070,133			2,040,572
Long-term derivative payable to Partnerships		39,187			22,380
Long-term derivative liability		38,629			25,441
Other long-term liabilities		58,988			56,180
Commitments and contingencies
Shareholders’ equity:
Preferred stock, $0.01 par value: 1,000,000 authorized shares		—			—
Common stock, $0.01 par value: 114,000,000 authorized shares		815			814
Additional paid-in capital		1,159,560			1,156,580
Treasury stock, at cost		(142,021	)		(142,848	)
Accumulated other comprehensive income		99,740			58,022
Retained earnings		48,643			50,744
		1,166,737			1,123,312
Non-controlling interests		605,046			580,204
Total shareholders’ equity		1,771,783			1,703,516
	$	4,418,762		$	4,406,163

See accompanying notes to consolidated financial statements

3

ATLAS ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(Unaudited)

	Three Months Ended
	March 31,
	2010			2009
Revenues:
Gas and oil production	$	63,909		$	71,943
Well construction and completion		72,642			112,368
Transmission, gathering and processing		279,666			163,667
Administration and oversight		2,047			3,853
Well services		5,312			5,093
Loss on asset sales		(3,009	)		—
Gain on mark-to-market derivatives		4,133			316
Other, net		4,257			4,881
Total revenues		428,957			362,121
Costs and expenses:
Gas and oil production		12,284			11,286
Well construction and completion		61,561			95,397
Transmission, gathering and processing		230,057			152,527
Well services		2,578			2,424
General and administrative		30,555			27,607
Net expense reimbursement – affiliate		256			289
Depreciation, depletion and amortization		49,254			50,695
Total costs and expenses		386,545			340,225
Operating income		42,412			21,896
Interest expense		(44,599	)		(34,620	)
Loss from continuing operations before income tax provision (benefit)		(2,187	)		(12,724	)
Income tax provision (benefit)		(1,408	)		2,594
Net loss from continuing operations		(779	)		(15,318	)
Discontinued operations:
Income from discontinued operations (net of income tax provision of $399 for the three months ended March 31, 2009)		—			8,477
Net loss		(779	)		(6,841	)
(Income) loss attributable to non-controlling interests		(1,322	)		11,484
Net income (loss) attributable to common shareholders	$	(2,101	)	$	4,643
Net income (loss) attributable to common shareholders per share – basic:
Income (loss) from continuing operations attributable to common shareholders	$	(0.03	)	$	0.10
Income from discontinued operations attributable to common shareholders		—			0.02
Net income (loss) attributable to common shareholders	$	(0.03	)	$	0.12
Net income (loss) attributable to common shareholders per share – diluted:
Income (loss) from continuing operations attributable to common shareholders	$	(0.03	)	$	0.10
Income from discontinued operations attributable to common shareholders		—			0.02
Net income (loss) attributable to common shareholders	$	(0.03	)	$	0.12
Weighted average common shares outstanding:
Basic		78,200			39,281
Diluted		78,200			39,751
Income (loss) attributable to common shareholders:
Income (loss) from continuing operations (net of income tax provision (benefit) of $(1,408) and $2,594 for the three months ended March 31, 2010 and 2009, respectively)	$	(2,101	)	$	4,020
Income from discontinued operations (net of income taxes of $399 for the three months ended March 31, 2009)		—			623
Net income (loss) attributable to common shareholders	$	(2,101	)	$	4,643

See accompanying notes to consolidated financial statements

4

ATLAS ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

FOR THE THREE MONTHS ENDED MARCH 31, 2010

(in thousands, except share data)

(Unaudited)

												Accumulated
				Additional								Other					Non-			Total
	Common Stock			Paid-In			Treasury Stock					Comprehensive		Retained			Controlling			Shareholders’
	Shares	Amount		Capital			Shares		Amount			Income		Earnings			Interests			Equity
Balance, January 1, 2010	81,290,492	$	814	$	1,156,580		(3,144,681	)	$	(142,848	)	$	58,022	$	50,744		$	580,204		$	1,703,516
Issuance of common shares	150,622		1		(197	)	19,632			827			—		—			—			631
Other comprehensive income	—		—		—		—			—			41,718		—			9,418			51,136
Stock compensation expense	—		—		3,177		—			—			—		—			—			3,177
Distributions to non-controlling interests	—		—		—		—			—			—		—			(1,703	)		(1,703	)
Non-controlling interests’ capital contributions	—		—		—		—			—			—		—			15,805			15,805
Net income (loss)	—		—		—		—			—			—		(2,101	)		1,322			(779	)
Balance, March 31, 2010	81,441,114	$	815	$	1,159,560		(3,125,049	)	$	(142,021	)	$	99,740	$	48,643		$	605,046		$	1,771,783

See accompanying notes to consolidated financial statements

5

ATLAS ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Three Months Ended March 31,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(779	)	$	(6,841	)
Income from discontinued operations		—			8,477
Loss from continuing operations		(779	)		(15,318	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		49,254			50,695
Amortization of deferred finance costs		2,752			1,713
Non-cash loss on derivative value, net		8,303			45,490
Non-cash compensation expense		5,008			2,270
Loss on asset sales and dispositions		3,009			—
Distributions paid to non-controlling interests		(1,703	)		(36,319	)
Equity (income) loss in unconsolidated companies		(1,695	)		188
Distributions received from unconsolidated companies		3,991			—
Deferred income taxes		(9,980	)		1,612
Changes in operating assets and liabilities:
Accounts receivable and prepaid expenses and other		80,477			32,935
Accounts payable and accrued liabilities		(100,428	)		(69,555	)
Net cash provided by continuing operations operating activities		38,209			13,711
Net cash provided by discontinued operations operating activities		—			12,012
Net cash provided by operating activities		38,209			25,723
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(80,913	)		(129,403	)
Investments in unconsolidated companies		(6,323	)		(2	)
Proceeds from asset sales		165			114
Other		(274	)		(104	)
Net cash used in continuing operations investing activities		(87,345	)		(129,395	)
Net cash used in discontinued operations investing activities		—			(651	)
Net cash used in investing activities		(87,345	)		(130,046	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under subsidiary credit facilities		252,000			310,000
Repayments under subsidiary credit facilities		(228,661	)		(217,000	)
Net proceeds from subsidiary equity offerings		15,331			—
Dividends paid		—			(1,968	)
Proceeds from employee share purchases		630			—
Deferred financing costs and other		2,757			(3,879	)
Net cash provided by financing activities		42,057			87,153
Net change in cash and cash equivalents		(7,079	)		(17,170	)
Cash and cash equivalents, beginning of period		20,627			104,496
Cash and cash equivalents, end of period	$	13,548		$	87,326

See accompanying notes to consolidated financial statements

6

ATLAS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2010

(Unaudited)

NOTE 1 – BASIS OF PRESENTATION

Atlas Energy, Inc. (the “Company”) is a publicly traded Delaware corporation (NASDAQ: ATLS) which is an independent developer and producer of natural gas and oil, with operations in the Appalachian, Michigan, and Illinois Basins. On September 29, 2009, the Company completed its merger with Atlas Energy Resources, LLC (“ATN”), the Company’s formerly publicly traded subsidiary and a Delaware limited liability company, pursuant to the definitive merger agreement previously executed, with ATN surviving as the Company’s wholly-owned subsidiary (the “Merger”) (see Note 3). Additionally, Atlas America, Inc. changed its name to Atlas Energy, Inc. upon completion of the Merger.

In addition to its natural gas development and production operations, the Company also maintains ownership interests in the following entities:

• Atlas Pipeline Partners, L.P. (“Atlas Pipeline Partners” or “APL”), a publicly traded Delaware limited partnership (NYSE: APL) and midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachia regions. At March 31, 2010, the Company had a 2.1% direct ownership interest in APL;

• Atlas Pipeline Holdings, L.P. (“Atlas Pipeline Holdings” or “AHD”), a publicly traded Delaware limited partnership (NYSE: AHD) and owner of the general partner of APL. Through the Company’s ownership of AHD’s general partner, it manages AHD. AHD’s cash generating assets currently consist solely of its interests in APL. At March 31, 2010, the Company owned approximately 64.3% of the outstanding common units of AHD. At March 31, 2010, AHD owned a 1.9% general partner interest, all of the incentive distribution rights, an approximate 10.8% common limited partner interest, and 15,000 $1,000 par value 12.0% Class B cumulative preferred limited partner units in APL; and

• Lightfoot Capital Partners, LP (“Lightfoot LP”) and Lightfoot Capital Partners GP LLC, (“Lightfoot GP”), the general partner of Lightfoot (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. The Company has an approximate direct and indirect 18% ownership interest in Lightfoot GP. At March 31, 2010, the Company has satisfied its commitment to invest a total of $19.7 million in Lightfoot. The Company also has direct and indirect ownership interest in Lightfoot LP.

The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2009, 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 Company’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. Certain amounts in the prior year’s consolidated financial statements have also been reclassified to conform to the current year presentation, including amounts related to APL’s NOARK system, which have been reclassified to discontinued operations following the sale of that system (see Note 5). The results of operations for the three month period ended March 31, 2010 may not necessarily be indicative of the results of operations for the full year ending December 31, 2010.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Non-Controlling Interest

The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly-owned at March 31, 2010 except for AHD, which is controlled by the Company, and APL, which is controlled by AHD. The financial statements of AHD include its accounts and the accounts of its subsidiaries, all of which are wholly-owned except for APL. Prior to ATN’s merger with the Company’s wholly-owned subsidiary on September 29, 2009, ATN was a controlled subsidiary of the Company but was not wholly-owned (see Note 3). The non-controlling ownership interests in the net income (loss) of ATN prior to the Merger, AHD and APL are reflected within non-controlling interests on the Company’s consolidated statements of operations. The non-controlling interests in the assets and liabilities of AHD and APL are reflected as a component of shareholders’ equity on the Company’s consolidated balance sheets. All material intercompany transactions have been eliminated.

7

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

The Company’s consolidated financial statements also include APL’s 95% ownership interest in joint ventures which individually own a 100% ownership interest in the Chaney Dell natural gas gathering system and processing plants and a 72.8% undivided interest in the Midkiff/Benedum natural gas gathering system and processing plants. APL consolidates 100% of these joint ventures. The Company reflects the non-controlling 5% ownership interest in the joint ventures as non-controlling interests on its statements of operations. The Company also reflects the 5% ownership interest in the net assets of the joint ventures as non-controlling interests as a component of shareholders’ equity on its consolidated 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 is reflected within non-controlling interests on the Company’s consolidated balance sheets.

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

Use of Estimates

The preparation of the Company’s consolidated 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 Company’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Company’s consolidated financial statements are based on a number of significant estimates, including the revenue and expense accruals, deferred tax assets and liabilities, 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. Actual results could differ from those estimates.

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

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired (see Note 6). 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. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.

The Company 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, delay rentals and unsuccessful exploratory wells are expensed. Oil is converted to gas equivalent basis (“Mcfe”) at the rate of one barrel equals 6 Mcf.

8

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

Upon the sale or retirement of a complete field of a proved property, the Company eliminates the cost from the property accounts, and the resultant gain or loss is reclassified to the Company’s consolidated statements of operations. Upon the sale of an individual well, the Company credits the proceeds to accumulated depreciation and depletion within its consolidated balance sheets. Upon the Company’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 Company’s consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

Impairment of Long-Lived Assets

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

The review of the Company’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company 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, the Company’s reserve estimates for its investment in the Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include the Company’s actual capital contributions, an additional carried interest (generally 7% to 10%), a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

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

The Company’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Partnerships, which the Company sponsors and owns an interest in but does not control. The Company’s reserve quantities include reserves in excess of its proportionate share of reserves in a Partnership which the Company may be unable to recover due to the Partnership legal structure. The Company may have to pay additional consideration in the future as a well or Partnership becomes uneconomic under the terms of the partnership agreement in order to recover these excess reserves and to acquire any additional residual interests in the wells held by other partnership investors. The acquisition of any well interest from the Partnership by the Company is governed under the partnership agreement and must be at fair market value supported by an appraisal of an independent expert selected by the Company. There were no impairments of proved oil and gas properties recorded by the Company for the three months ended March 31, 2010 and 2009.

9

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate the Company 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 oil and gas properties recorded by the Company for the three months ended March 31, 2010 and 2009.

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

Capitalized Interest

The Company and its subsidiaries 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 rate used to capitalize interest on combined borrowed funds by the Company in the aggregate was 9.6% and 5.9% for the three months ended March 31, 2010 and 2009, respectively. The aggregate amount of interest capitalized by the Company was $3.0 million and $3.4 million for the three months ended March 31, 2010 and 2009, respectively.

Intangible Assets

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

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

The following table reflects the components of intangible assets being amortized at March 31, 2010 and December 31, 2009 (in thousands):

	March 31,			December 31,			Estimated Useful Lives
	2010			2009			In Years
Gross Carrying Amount:
Customer contracts and relationships	$	235,382		$	235,382		3 – 15
Partnership management and operating contracts		14,343			14,343		2 – 13
	$	249,725		$	249,725
Accumulated Amortization:
Customer contracts and relationships	$	(73,680	)	$	(67,291	)
Partnership management and operating contracts		(11,647	)		(11,470	)
	$	(85,327	)	$	(78,761	)
Net Carrying Amount:
Customer contracts and relationships	$	161,702		$	168,091
Partnership management and operating contracts		2,696			2,873
	$	164,398		$	170,964

10

Amortization expense on intangible assets was $6.6 million and $6.7 million for the three months ended March 31, 2010 and 2009, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2010-$26.3 million; 2011-$26.2 million; 2012-$25.7 million; 2013-$24.6 million; and 2014-$20.6 million.

Goodwill

At March 31, 2010 and December 31, 2009, the Company had $35.2 million of goodwill recorded in connection with consummated acquisitions. There were no changes in the carrying amount of goodwill for the three months ended March 31, 2010 and 2009.

The Company and its subsidiaries test their goodwill for impairment at each year end by comparing their reporting unit estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, the Company’s and subsidiaries’ management must apply judgment in determining the estimated fair value of these reporting units. The Company’s and subsidiaries’ 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 the Company’s and subsidiaries’ market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including the Company’s and its subsidiaries’, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, the Company’s and its subsidiaries’ management also consider the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in the Company’s and its subsidiaries’ industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in the Company’s and its subsidiaries’ industry to determine whether those valuations appear reasonable in management’s judgment. The Company and its subsidiaries will continue to evaluate goodwill at least annually or when impairment indicators arise. There were no goodwill impairments recognized by the Company and its subsidiaries during the three months ended March 31, 2010 and 2009.

Net Income (Loss) Per Share

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted net income (loss) per share is calculated by dividing net income (loss) by the sum of the weighted average number of common shares outstanding and the dilutive effect of potential shares issuable during the period, as calculated by the treasury stock method. Dilutive potential shares of common shares consist of the excess of shares issuable under the terms of the Company’s stock incentive plan over the number of such shares that could have been reacquired (at the weighted average market price of shares during the period) with the proceeds received from the exercise of the stock options (see Note 17). The following table sets forth the reconciliation of the Company’s weighted average number of common shares used to compute basic net income (loss) per share with those used to compute diluted net income (loss) per share (in thousands):

	Three Months Ended March 31,
	2010(1)	2009
Weighted average number of shares – basic	78,200	39,281
Add: effect of dilutive incentive awards	—	470
Weighted average number of common shares – diluted	78,200	39,751

(1) During the three months ended March 31, 2010, approximately 2,900,000 shares were excluded from the calculation of diluted net income (loss) per share because the inclusion of such shares would have been anti-dilutive.

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Revenue Recognition

Certain energy activities are conducted by the Company through, and a portion of its revenues are attributable to, sponsored investment partnerships. The Company contracts with the Partnerships to drill partnership wells. The contracts require that the Partnerships must pay the Company 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 180 days. On an uncompleted contract, the Company 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 Company’s consolidated balance sheets. The Company recognizes well services revenues at the time the services are performed. The Company is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned and includes them in administration and oversight revenues.

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

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

• Fee-Based Contracts. These contracts provide for a set fee for gathering and processing raw natural gas. APL’s revenue is a function of the volume of natural gas that it gathers and processes and is not directly dependent on the value of the natural gas.

• POP Contracts. These contracts provide for APL to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this situation, APL and the producer are directly dependent on the volume of the commodity and its value; APL owns a percentage of that commodity and is directly subject to its market value.

• Keep-Whole Contracts. These contracts require APL, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, APL bears the economic risk (the “processing margin risk”) that the 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. However, because the natural gas purchases contracted under keep-whole agreements are generally low in liquids content and meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants and delivered directly into downstream pipelines during periods of margin risk. Therefore, the processing margin risk associated with a portion of APL’s keep-whole contracts is minimized.

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The Company accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s and APL’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “–Use of Estimates” accounting policy for further description). The Company had unbilled revenues at March 31, 2010 and December 31, 2009 of $65.8 million and $94.9 million, respectively, which are included in accounts receivable within the Company’s consolidated balance sheets.

Comprehensive Income

Comprehensive income includes net income and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States, have not been recognized in the calculation of net income. These changes, other than net income, are referred to as “other comprehensive income” and for the Company includes changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges and post-retirement plan liabilities (which are presented net of income taxes). The following table sets forth the calculation of the Company’s comprehensive income (loss) (in thousands):

	Three Months Ended March 31,
	2010			2009
Net loss	$	(779	)	$	(6,841	)
(Income) loss attributable to non-controlling interests		(1,322	)		11,484
Net income (loss) attributable to common shareholders		(2,101	)		4,643
Other comprehensive income:
Changes in fair value of derivative instruments accounted for as cash flow hedges, net of taxes of $35,429 and $17,225 for the three months ended March 31, 2010 and 2009, respectively		55,191			73,450
Less: reclassification adjustment for realized losses (gains) in net income (loss), net of taxes of $8,302 and 2,247 for the three months ended March 31, 2010 and 2009, respectively		(3,342	)		646
Changes in non-controlling interest related to items in other comprehensive income		(9,418	)		(50,670	)
Plus: amortization of additional post-retirement liability, net of tax provision (benefit) of ($392) and $13 for the three months ended March 31, 2010 and 2009, respectively		(713	)		22
Total other comprehensive income		41,718			23,448
Comprehensive income attributable to common shareholders	$	39,617		$	28,091

Recently Adopted Accounting Standards

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-02, “Fair Value Measurement and Disclosures (Topic (820) – Improving Disclosures about Fair Value Measurement” (“Update 2010-06”). Update 2010-06 clarifies and requires new disclosures about the transfer of amounts between Level 1 and Level 2, as well as significant transfers in and out of Level 3. In addition, for Level 2 and Level 3 measurements, Update 2010-06 requires additional disclosure about the valuation technique used or any changes in technique. Update 2010-06 also clarifies that entities must disclose fair value measurements by classes of assets and liabilities, based on the nature and risks of the assets and liabilities. The requirements of Update 2010-06 are effective at the start of a reporting entity’s first fiscal year beginning after December 15, 2009 (January 1, 2010 for the Company). The Company applied the requirements of Update 2010-06 upon its adoption on January 1, 2010, and it did not have a material impact on its financial position, results of operations or related disclosures.

In January 2010, the FASB issued Accounting Standards Update 2010-02, “Consolidation (Topic (810)—Accounting and Reporting for Decreases in Ownership of a Subsidiary – A Scope Clarification” (“Update 2010-02”). Subtopic 810-10 previously applied to decrease-in-ownership provisions when an entity either deconsolidates or realizes a decrease in ownership in which the entity retains control. When an entity deconsolidates a subsidiary, it is required to record any remaining interest at fair value and recognize a gain or loss. Update 2010-02 amends Subtopic 810-10 “Consolidation – Overall” and provides clarification on the entities and activities required to follow more specific guidance already included in the ASC. Update 2010-02 includes in the scope of decrease-in-ownership provisions of ASC 810-10 a subsidiary or groups of assets that is a business or nonprofit activity, a subsidiary or group of assets transferred to an equity method investee or joint venture, or an exchange of a group of assets that constitutes a business or nonprofit activity for a non-controlling interest in an entity. Excluded from the scope of Subtopic 810-10 are sales of in-substance real estate and conveyances of oil and gas mineral rights. The requirements of Update 2010-02 are effective at the start of a reporting entity’s first fiscal year beginning after December 15, 2009 (January 1, 2010 for the Company). The Company applied the requirements of Update 2010-02 upon its adoption on January 1, 2010, and it did not have a material impact on its financial position, results of operations or related disclosures.

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In October 2009, the FASB issued Accounting Standards Update 2009-15, “Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing” (“Update 2009-15”). Update 2009-15 includes amendments to Topic 470, “Debt”, and Topic 260, “Earnings per Share”, to provide guidance on share-lending arrangements entered into on an entity’s own shares in contemplation of a convertible debt offering or other financing. These requirements are effective for existing arrangements for fiscal years beginning on or after December 15, 2009 (January 1, 2010 for the Company), and interim periods within those fiscal years for arrangements outstanding as of the beginning of those years, with retrospective application required for such arrangements that meet the criteria. These requirements are also effective for arrangements entered into on (not outstanding) or after the beginning of the first reporting period that begins on or after June 15, 2009. The Company adopted the requirements of Update 2009-15 on January 1, 2010, and it did not have a material impact on its financial position, results of operations or related disclosures.

In June 2009, the FASB issued ASC 810-10-25-20 through 25-59, “Consolidation of Variable Interest Entities” (“ASC 810-10-25-20”), which changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. ASC 820-10-25-20 requires a reporting entity to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. A reporting entity will be required to disclose how its involvement with a variable interest entity affects the reporting entity’s financial statements. The requirements of ASC 820-10-25-20 are effective at the start of a reporting entity’s first fiscal year beginning after November 15, 2009 (January 1, 2010 for the Company). The Company adopted the requirements of ASC 810-10-25-20 on January 1, 2010, and it did not have a material impact on its financial position, results of operations or related disclosures.

NOTE 3 – COMMON STOCK

Merger with Atlas Energy Resources, LLC

On September 29, 2009, the Company completed its Merger, with ATN surviving as the Company’s wholly-owned subsidiary. In the Merger, the 33.4 million Class B common units of ATN not previously held by the Company were exchanged for 38.8 million shares of the Company’s common stock (a ratio of 1.16 shares of the Company’s common stock for each Class B common unit of ATN). The Company also changed its name from Atlas America, Inc. to Atlas Energy, Inc. Concurrent with the Merger, the Compensation Committee of the Board of Directors approved the Atlas Energy, Inc. 2009 Stock Incentive Plan, which created a new stock incentive plan for the combined entity. The Company also has assumed the legacy Atlas America stock incentive plan and the legacy ATN Long-Term Incentive Plan (see Note 17). Due to the Merger, the Company recognized a reduction of $556.4 million in non-controlling interests, a decrease of $197.4 million in deferred tax liabilities, and a $741.8 million increase to additional paid-in-capital on the Company’s consolidated balance sheet. The Company accounted for the Merger transaction in accordance with prevailing accounting literature related to entities under common control and recognized the cost of the interests exchanged in the Merger, excluding transaction costs incurred, of $741.8 million as a non-cash item in its consolidated statement of cash flows during the year ended December 31, 2009.

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The following data presents pro forma revenue, net income, net income per share and basic and diluted weighted average shares outstanding for the Company for the three months ended March 31, 2009 as if the Merger discussed above had occurred on January 1, 2009. The Company has prepared these unaudited pro forma financial results for comparative purposes only. The pro forma adjustments reflect an adjustment to income previously allocated to non-controlling interests offset by the related tax impact. These pro forma financial results may not be indicative of the results that would have occurred if the Merger had been completed at the beginning of the period shown below or the results that will be attained in the future (in thousands, except per share data; unaudited):

	Three Months Ended March 31, 2009
Revenue	$	362,121
Income attributable to common shareholders:
Income from continuing operations	$	9,713
Income from discontinued operations		623
Net income attributable to common shareholders	$	10,336
Net income attributable to common shareholders per share – basic:
Income from continuing operations attributable to common shareholders	$	0.12
Income from discontinued operations attributable to common shareholders		0.01
Net income attributable to common shareholders	$	0.13
Net income attributable to common shareholders per share – diluted:
Income from continuing operations attributable to common shareholders	$	0.12
Income from discontinued operations attributable to common shareholders		0.01
Net income attributable to common shareholders	$	0.13
Weighted average common shares outstanding:
Basic		78,057
Diluted		78,527

NOTE 4 – APL INVESTMENT IN JOINT VENTURE

On May 31, 2009, APL and a subsidiary of The Williams Companies, Inc. (NYSE: WMB) (“Williams”) completed the formation of Laurel Mountain Midstream, LLC (“Laurel Mountain”), a joint venture which owns and operates APL’s Appalachia Basin natural gas gathering system, excluding APL’s Northern Tennessee operations. Williams contributed cash of $100.0 million to the joint venture (of which APL received approximately $87.8 million, net of working capital adjustments) and a note receivable of $25.5 million. APL contributed its Appalachia Basin natural gas gathering system and retained a 49% ownership interest. APL is also entitled to preferred distribution rights relating to all payments on the note receivable. Williams retained the remaining 51% ownership interest in Laurel Mountain. Upon completion of the transaction, APL recognized its 49% ownership interest in Laurel Mountain as an investment in joint venture on the Company’s consolidated balance sheet at fair value and recognized a gain on sale of $108.9 million, including $54.2 million associated with the re-measurement of APL’s investment in Laurel Mountain to fair value as determined by the purchase price of the assets. APL used the net proceeds from the transaction to reduce borrowings under its senior secured credit facility (see Note 9). In addition, the Company sold two natural gas processing plants and associated pipelines located in Southwestern Pennsylvania to Laurel Mountain for $10.0 million, resulting in a $6.5 million loss which is included in gain on asset sale on the Company’s consolidated statement of operations for the year ended December 31, 2009.

During the three months ended March 31, 2010, APL utilized $6.8 million of the note receivable from Laurel Mountain to fund a portion of its capitalized expenditures, which is recorded as a non-cash investing activity in the Company’s consolidated statement of cash flows. As of March 31, 2010, 8.5 million of the 25.5 million note receivable has been utilized by APL.

Upon the completion of the contribution of APL’s Appalachia gathering systems to Laurel Mountain, Laurel Mountain entered into new gas gathering agreements with the Company which superseded the existing natural gas gathering agreements and omnibus agreement between APL and the Company. Pursuant to these gas gathering agreements with Laurel Mountain, the Company generally pays a gathering fee equal to 16% of the realized natural gas sales price (adjusted for the settlement of natural gas derivative instruments). However, in most of the Company’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, the Company’s Appalachian gathering expenses within its partnership management segment will generally exceed the revenues collected from the investment partnerships by approximately 3%. APL has accounted for its ownership interest in Laurel Mountain under the equity method of accounting, with recognition of its ownership interest in the income of Laurel Mountain within other income (loss) on the Company’s consolidated statements of operations.

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The following table provides summarized statement of operations on a 100% basis for Laurel Mountain for the three months ended March 31, 2010 and 2009 and balance sheet data as of March 31, 2010 and December 31, 2009 (in thousands):

	Three Months Ended March 31,
	2010		2009
Statement of Operations data:
Total revenue	$	11,084	$	—
Net income		2,646		—
	March 31, 2010		December 31, 2009
Balance Sheet data:
Current assets	$	14,009	$	12,193
Long-term assets		256,198		248,730
Current liabilities		13,551		19,724
Long-term liabilities		9,437		9,555
Net equity		247,219		231,644

NOTE 5 – DISCONTINUED OPERATIONS

On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system to Spectra Energy Partners OLP, LP (NYSE:SEP) (“Spectra”) for net proceeds of $292.0 million in cash, net of working capital adjustments. APL received an additional $2.5 million in cash in July 2009 upon the delivery of audited financial statements for the NOARK system assets to Spectra. APL used the net proceeds from the transaction to reduce borrowings under its senior secured term loan and revolving credit facility (see Note 9). The Company accounted for the sale of the NOARK system assets as discontinued operations within its consolidated financial statements and recorded a gain of $48.9 million (net of income taxes of $2.2 million) on the sale of APL’s NOARK assets within income from discontinued operations on its consolidated statement of operations for the year ended December 31, 2009. The following table summarizes the components included within income from discontinued operations on the Company’s consolidated statements of operations (amounts in thousands):

	Three Months Ended March 31,
	2010		2009
Total revenues	$	—	$	16,005
Total costs and expenses		—		(7,129	)
Income before income tax expense		—		8,876
Income tax expense		—		(399	)
Income from discontinued operations	$	—	$	8,477

NOTE 6 – PROPERTY, PLANT AND EQUIPMENT

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

							Estimated
	March 31,			December 31,			Useful Lives
	2010			2009			in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,265,556		$	1,243,932
Pre-development costs		6,797			6,270
Wells and related equipment		1,050,699			1,017,370
Total proved properties		2,323,052			2,267,572
Unproved properties		43,956			41,816
Support equipment		9,887			8,930
Total natural gas and oil properties		2,376,895			2,318,318
Pipelines, processing and compression facilities		1,699,275			1,685,200		2 – 40
Rights of way		167,685			167,105		20 – 40
Land, buildings and improvements		26,757			26,697		3 – 40
Other		23,103			21,931		3 – 10
		4,293,715			4,219,251
Less – accumulated depreciation, depletion and amortization		(706,980	)		(663,449	)
	$	3,586,735		$	3,555,802

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NOTE 7 – OTHER ASSETS

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

	March 31,		December 31,
	2010		2009
Deferred finance and organization costs, net of accumulated amortization of $38,222 and $35,470 at March 31, 2010 and December 31, 2009, respectively	$	44,341	$	47,147
Investment in Lightfoot		17,786		11,528
Other investments		6,794		6,340
Long-term pipeline lease prepayment		3,731		3,168
Security deposits		3,424		3,809
Long-term derivative receivable from Partnerships		6,608		2,841
	$	82,684	$	74,833

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 9).

Investments at March 31, 2010 included a $17.8 million net investment balance in Lightfoot. The Company owns, directly and indirectly, approximately 13% of Lightfoot LP. In addition, the Company owns, directly and indirectly, approximately 18% of Lightfoot GP, the general partner of Lightfoot LP, an entity of which Jonathan Cohen, Vice Chairman of the Company’s Board of Directors, is the Chairman of the Board. The Company committed to invest a total of $19.7 million in Lightfoot. The Company has certain co-investment rights until such point as Lightfoot LP raises additional capital through a private offering to institutional investors or a public offering. Lightfoot LP has initial equity funding commitments of approximately $160.0 million and focuses its investments primarily on incubating new master limited partnerships and providing capital to existing MLPs in need of additional equity or structured debt. Lightfoot LP concentrates on assets that are MLP-qualified such as infrastructure, coal and other asset categories. The Company accounts for its investment in Lightfoot under the equity method of accounting. For the three months ended March 31, 2010 and 2009, the Company recorded losses of $0.1 million for each period. During the three months ended March 31, 2010, the Company contributed capital of $6.3 million to its interest in Lightfoot, in order to maintain its aggregate ownership interest. As of March 31, 2010, the Company has fulfilled its commitment to invest the total of $19.7 million in Lightfoot LP.

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

NOTE 8 – ASSET RETIREMENT OBLIGATIONS

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

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

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

	Three Months Ended March 31,
	2010			2009
Asset retirement obligations, beginning of period	$	51,813		$	48,136
Liabilities incurred		43			430
Liabilities settled		(7	)		(62	)
Accretion expense		759			758
Asset retirement obligations, end of period	$	52,608		$	49,262

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

NOTE 9 – DEBT

At March 31, 2010, the Company’s debt consists entirely of instruments entered into by ATN, AHD and APL. The Company has not guaranteed any of its subsidiaries’ debt obligations, with the exception of the AHD credit facility. Total debt consists of the following at the dates indicated (in thousands):

	March 31,			December 31,
	2010			2009
ATN revolving credit facility	$	265,000		$	184,000
ATN 10.75 % senior notes – due 2018		405,739			405,922
ATN 12.125 % senior notes – due 2017		196,585			196,468
AHD credit facility		4,000			8,000
APL revolving credit facility		280,000			326,000
APL term loan		425,845			433,505
APL 8.125 % senior notes – due 2015		271,763			271,627
APL 8.75 % senior notes – due 2018		223,050			223,050
APL capital leases		2,741			—
Total debt		2,074,723			2,048,572
Less current maturities		(4,590	)		(8,000	)
Total long-term debt	$	2,070,133		$	2,040,572

ATN Revolving Credit Facility

At March 31, 2010, ATN had a credit facility with a syndicate of banks with a borrowing base of $575.0 million that matures in June 2012. The borrowing base is redetermined semiannually on April 1 and October 1 subject to changes in oil and gas reserves and is automatically reduced by 25% of the stated principal of any senior unsecured notes issued by ATN. In April 2010, in conjunction with a regularly scheduled borrowing base redetermination, the borrowing base under ATN’s revolving credit facility of $550.0 million was approved (see Note 19). Up to $50.0 million of the credit facility may be in the form of standby letters of credit, of which $1.6 million was outstanding at March 31, 2010, which was not reflected as borrowings on the Company’s consolidated balance sheets. The facility is secured by substantially all of ATN’s assets and is guaranteed by each of its subsidiaries. At March 31, 2010 and December 31, 2009, the weighted average interest rate on outstanding borrowings was 3.4% and 2.9%, respectively. The base rate for any day equals the higher of the federal funds rate plus 0.50%, the J.P. Morgan prime rate or the adjusted LIBOR for a month interest period plus 1.0%. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for Eurocurrency liabilities. The facility also allows ATN to distribute to the Company (a) amounts equal to the Company’s income tax liability attributable to ATN’s net income at the highest marginal rate and (b) up to $40.0 million per year and, to the extent that it distributes less than that amount in any year, it may carry over up to $20.0 million for use in the next year.

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The events which constitute an event of default for ATN’s credit facility are customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against ATN in excess of a specified amount and a change of control. In addition, the agreement limits sales, leases or transfers of assets and the incurrence of additional indebtedness. ATN was in compliance with these covenants as of March 31, 2010. The credit facility also requires ATN to maintain a ratio of current assets (as defined in the credit facility) to current liabilities (as defined in the credit facility) of not less than 1.0 to 1.0, and a ratio of total debt (as defined in the credit facility) to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”, as defined in the credit facility) of less than or equal to 3.5 to 1.0 effective January 1, 2010. Based on the definitions contained in ATN’s credit facility, its ratio of current assets to current liabilities was 1.8 to 1.0 and its ratio of total debt to EBITDA was 3.0 to 1.0 at March 31, 2010.

ATN Senior Notes

At March 31, 2010, ATN had $400.0 million principal amount outstanding of 10.75% senior unsecured notes (“ATN 10.75% Senior Notes”) due on February 1, 2018 and $200.0 million principal amount outstanding of 12.125% senior unsecured notes due August 1, 2017 (“ATN 12.125% Senior Notes”; collectively, the “ATN Senior Notes”). Interest on the ATN Senior Notes in the aggregate is payable semi-annually in arrears on February 1 and August 1 of each year. The ATN 10.75% Senior Notes, which are shown inclusive of unamortized premium of $5.7 million, are redeemable at any time on or after February 1, 2013, and the ATN 12.125% Senior Notes, which are shown net of unamortized discount of $3.4 million, are redeemable at any time on or after August 1, 2013, at specified redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, before February 1, 2011 for the ATN 10.75% Notes and before August 1, 2012 for the ATN 12.125% Senior Notes, ATN may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of equity offerings at a stated redemption price. The ATN Senior Notes are also subject to repurchase by ATN at a price equal to 101% of the principal amount of the ATN 10.75% Senior Notes and ATN 12.125% Senior Notes, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if ATN does not reinvest the net proceeds within 360 days. The ATN Senior Notes are junior in right of payment to ATN’s secured debt, including its obligations under its credit facility. The indentures governing the ATN Senior Notes contain covenants, including limitations of ATN’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. ATN was in compliance with these covenants as of March 31, 2010.

AHD Credit Facility

At March 31, 2010, AHD had $4.0 million outstanding under a credit facility with a syndicate of banks. In June 2009, AHD entered into an amendment to its credit facility agreement which, among other changes, required AHD to immediately repay $30.0 million of a then-outstanding $46.0 million in borrowings under the credit facility and to repay the remaining $16.0 million in $4.0 million installments on each of July 13, 2009, October 13, 2009 and January 13, 2010, with the balance of the indebtedness being due on the original maturity date of the credit facility of April 13, 2010. On April 13, 2010, the remaining balance outstanding under the credit facility was repaid, and the credit facility was terminated.

AHD’s $30.0 million repayment in June 2009 was funded from the proceeds of (i) a loan from the Company in the amount of $15.0 million (originated on June 1, 2009) and (ii) the purchase by APL of $15.0 million of preferred equity in a newly-formed subsidiary of AHD. Under the subordinate loan, interest accrues quarterly on the outstanding principal amount at the rate of 12% per annum, but before the maturity date, interest is payable entirely by increasing the principal amount of the note, and the maturity date is generally the day following the day that AHD pays all indebtedness under the credit facility (“Termination Date”). The material terms of the preferred units purchased by APL in a newly-formed subsidiary of AHD are as follows: distributions are payable quarterly at the rate of 12% per annum, but before the Termination Date, distributions will be paid by increasing APL’s investment in the preferred units; upon the Termination Date, all preferred distributions will be paid in cash to APL; and AHD has the option, after the Termination Date, of redeeming all of the preferred units APL owns for an amount equal to the preferred unit capital.

19

In June 2009, in connection with AHD’s amendment of the credit facility, the Company guaranteed the then remaining balance outstanding under the credit facility under a guarantee agreement with the administrative agent of the credit facility. In consideration for this guarantee, AHD issued to the Company a promissory note which requires it to pay interest to the Company in an amount based upon the principal amount outstanding under the credit facility. The maturity date of the promissory note is the day following the date that AHD repays all outstanding borrowings under its credit facility, after which it is payable on-demand. Interest on the promissory note, which is calculated on the outstanding balance under the credit facility plus a $1.0 million guaranty fee, accrues quarterly at the rate of 3.75% per annum. However, prior to the maturity date of the promissory note, interest under the promissory note will not be payable in cash, but instead the principal amount upon which interest is calculated will be increased by the interest amount payable. AHD funded all of the repayments of the outstanding balance under the credit facility through the Company’s guaranty of AHD’s obligations.

APL Term Loan and Credit Facility

At March 31, 2010, APL had a senior secured credit facility with a syndicate of banks which consisted of a term loan which matures in July 2014 and a $380.0 million revolving credit facility which matures in July 2013. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) adjusted LIBOR, subject to a floor of 2.0% per annum, plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on both the outstanding APL revolving credit facility and term loan borrowings at March 31, 2010 were both 6.8%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $9.8 million was outstanding at March 31, 2010. These outstanding letter of credit amounts were not reflected as borrowings on the Company’s consolidated balance sheet at March 31, 2010. At March 31, 2010, APL had $90.2 million of remaining committed capacity under its credit facility, subject to covenant limitations.

Borrowings under APL’s credit facility are secured by a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by Chaney Dell and Midkiff/Benedum joint ventures and the Laurel Mountain joint venture, and by the guaranty of each of APL’s consolidated subsidiaries other than the joint venture companies. The credit facility contains customary covenants, including restrictions on APL’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. In addition, the credit facility (a) allows APL to pay cash distributions commencing with the three months ended March 31, 2010 if its senior secured leverage ratio is less than 2.75x and it has minimum liquidity (as defined in the credit agreement) of at least $50.0 million, (b) limits APL’s annual capital expenditures to $70.0 million commencing January 1, 2010, (c) permits APL to retain up to $50.0 million of net cash proceeds from dispositions completed in any fiscal year subject to certain limitations (as defined within the credit agreement), and (d) has a mandatory repayment requirement of the outstanding senior secured term loan from excess cash flow (as defined in the credit agreement) based upon APL’s leverage ratio. APL is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement. APL is in compliance with these covenants as of March 31, 2010.

The events which constitute an event of default for the 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. The credit facility requires APL to maintain the following ratios:

		Maximum	Minimum
	Maximum	Senior Secured	Interest
	Leverage	Leverage	Coverage
Fiscal quarter ending:	Ratio	Ratio	Ratio
March 31, 2010	9.25x	5.75x	1.40x
June 30, 2010	8.00x	5.00x	1.65x
September 30, 2010	7.00x	4.25x	1.90x
December 31, 2010	6.00x	3.75x	2.20x
Thereafter	5.00x	3.00x	2.75x

20

At March 31, 2010, APL’s leverage ratio was 5.5 to 1.0, its senior secured leverage ratio was 3.3 to 1.0 and its interest coverage ratio was 2.2 to 1.0.

APL Senior Notes

At March 31, 2010, APL had $223.1 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“APL 8.75% Senior Notes”) and $275.5 million principal amount outstanding of 8.125% senior unsecured notes due on December 15, 2015 (“APL 8.125% Senior Notes”; collectively, the “APL Senior Notes”). The APL 8.125% Senior Notes are presented combined with a net $3.7 million of unamortized discount as of March 31, 2010. Interest on the APL Senior Notes in the aggregate is payable semi-annually in arrears on June 15 and December 15. The APL 8.75% Senior Notes are redeemable at any time after June 15, 2013, and the APL 8.125% Senior Notes are redeemable at any time after December 15, 2010 at certain redemption prices, together with accrued and unpaid interest to the date of redemption. Prior to June 15, 2011, APL may redeem up to 35% of the aggregate principal amount of the APL 8.75% Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The APL Senior Notes in the aggregate are also subject to repurchase by APL at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if APL does not reinvest the net proceeds within 360 days. The APL Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its credit facility.

Indentures governing the APL Senior Notes in the aggregate contain covenants, including limitations of APL’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. APL is in compliance with these covenants as of March 31, 2010.

Cash payments for interest related to debt made by the Company and its subsidiaries were $54.8 million and $37.1 million for the three months ended March 31, 2010 and 2009, respectively.

NOTE 10 – DERIVATIVE INSTRUMENTS

The Company and its subsidiaries use a number of different derivative instruments, principally swaps, collars and options, in connection with its commodity price and interest rate risk management activities. The Company and its subsidiaries enter into financial instruments to hedge its forecasted natural gas, NGL, crude oil and condensate sales against the variability in expected future cash flows attributable to changes in market prices. Its subsidiaries also enter into financial swap instruments to hedge certain portions of its floating interest rate debt against the variability in market interest rates. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs, crude oil and condensate is sold or interest payments on the underlying debt instrument are due. Under swap agreements, the Company and its subsidiaries receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas, NGLs, crude oil and condensate at a fixed price for the relevant contract period.

The Company and its subsidiaries formally document all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity and interest derivative contracts to the forecasted transactions. The Company and its subsidiaries 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, the Company and its subsidiaries will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by the Company and its subsidiaries through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s consolidated statements of operations. For derivatives qualifying as hedges, the Company and its subsidiaries recognize the effective portion of changes in fair value in shareholders’ equity as accumulated other comprehensive income and reclassify the portion relating to commodity derivatives to gas and oil production revenues for the Company’s derivatives and gathering, transmission and processing revenues for APL derivatives, and the portion relating to interest rate derivatives to interest expense within the Company’s consolidated statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Company and its subsidiaries recognize changes in fair value within gain (loss) on mark-to-market derivatives in its consolidated statements of operations as they occur.

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Derivatives are recorded on the Company’s consolidated balance sheet as assets or liabilities at fair value. The Company reflected net derivative assets on its consolidated balance sheets of $168.5 million and $69.4 million at March 31, 2010 and December 31, 2009, respectively. Of the $100.9 million of net gain in accumulated other comprehensive income within shareholders’ equity on the Company’s consolidated balance sheet related to commodity and interest rate derivatives at March 31, 2010, if the fair values of the instruments remain at current market values, the Company will reclassify $48.4 million of gains to the Company’s consolidated statements of operations over the next twelve month period as these contracts expire, consisting of $50.7 million of gains to gas and oil production revenues, $1.3 million of losses to transmission, gathering and processing revenues and $1.0 million of losses to interest expense. Aggregate gains of $52.5 million will be reclassified to the Company’s consolidated statements of operations in later periods as these remaining contracts expire, consisting of $54.7 million of gains to gas and oil production revenues, $1.1 million of losses to gathering, transmission and processing revenues and $1.1 million of losses to interest expense. Actual amounts that will be reclassified will vary as a result of future price changes.

The following table summarizes the fair value of the Company’s derivative instruments as of March 31, 2010 and December 31, 2009, as well as the gain or loss recognized in the consolidated statements of operations for effective derivative instruments for the three months ended March 31, 2010 and 2009:

Fair Value of Derivative Instruments:

	Asset Derivatives					Liability Derivatives
Derivatives in Cash Flow Hedging Relationships		Fair Value					Fair Value
	Balance Sheet Location	March 31, 2010		December 31, 2009		Balance Sheet Location	March 31, 2010			December 31, 2009
		(in thousands)					(in thousands)
Commodity contracts:	Current assets	$	117,798	$	73,066	Current liabilities	$	(956	)	$	(901	)
	Long-term assets		106,383		58,930	Long-term liabilities		(30,736	)		(14,091	)
			224,181		131,996			(31,692	)		(14,992	)
Interest rate contracts:	Current assets		—		—	Current liabilities		(3,350	)		(3,751	)
	Long-term assets		—		—	Long-term liabilities		—			(224	)
			—		—			(3,350	)		(3,975	)
Total derivatives		$	224,181	$	131,996		$	(35,042	)	$	(18,967	)

Effects of Derivative Instruments on Consolidated Statements of Operations:

Derivatives in Cash Flow Hedging Relationships	Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) for the Three Months Ended March 31,							Location of Gain/(Loss) Reclassified from Accumulated	Gain/(Loss) Reclassified from  OCI into Income (Effective Portion) for the Three Months Ended March 31,
	2010			2009				OCI into Income	2010			2009
								(Effective Portion)
	(in thousands)								(in thousands)
Commodity contracts	$	91,056			$	86,814		Gas and oil production	$	23,479			$	15,518
Interest rate contracts		(457	)			(873	)	Interest expense		(1,081	)			(1,002	)
	$	90,599			$	85,941			$	22,398			$	14,516

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

In January 2010, the Company received approximately $20.1 million in proceeds from the early settlement of natural gas and oil derivative positions for production periods from 2011 through 2013. In conjunction with the early termination of these derivatives, the Company 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 ATN’s revolving credit facility (see Note 9). In May 2009, the Company received approximately $28.5 million in proceeds from the early termination of natural gas and oil derivative positions for production periods from 2011 through 2013. In conjunction with the early termination of these derivatives, the Company 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 ATN’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 Company’s consolidated statements of operations in the same periods in which the hedged production revenues would have been recognized in earnings.

22

The Company recognized gains of $23.5 million and $15.5 million for three months ended March 31, 2010 and 2009, respectively, on settled contracts covering natural gas and oil production. These gains and losses are included within gas and oil production revenue in the Company’s consolidated statements of operations. As the underlying prices and terms in the Company’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three months ended March 31, 2010 and 2009 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

At March 31, 2010, ATN had $265.0 million of borrowings under its senior secured revolving credit facility (see Note 9). At March 31, 2010, the Company had interest rate derivative contracts having an aggregate notional principal amount of $150.0 million through January 2011, which were designated as cash flow hedges. These hedging arrangements reduce the impact of volatility of changes in the London interbank offered rate (“LIBOR”). Under the terms of the contract, the Company will pay a three-year fixed swap interest rate of 3.1%, plus the applicable margin as defined under the terms of its revolving credit facility, and will receive LIBOR, plus the applicable margin, on the notional principal amounts. This derivative effectively converts $150.0 million of ATN’s floating rate debt under the revolving credit facility to fixed-rate debt. The Company has accounted for the interest rate derivative contracts as effective hedge instruments under prevailing accounting standards.

At March 31, 2010, the Company had the following interest rate and commodity derivatives:

Interest Fixed Rate Swap

				Contract
	Notional			Period Ended	Fair Value
Term	Amount		Option Type	December 31,	Liability
					(in thousands)
January 2008 – January 2011	$	150,000,000	Pay 3.1% - Receive LIBOR	2010	$	(3,045	)
				2011		(305	)
					$	(3,350	)

Natural Gas Fixed Price Swaps

Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset
	(mmbtu)(1)	(per mmbtu) (1)		(in thousands) (2)
2010	30,750,003	$	7.354	$	95,033
2011	24,140,004	$	6.689		32,449
2012	19,652,260	$	6.850		20,280
2013	13,211,510	$	6.822		9,344
				$	157,106

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Natural Gas Costless Collars

Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset/(Liability)
		(mmbtu)(1)	(per mmbtu) (1)		(in thousands)(2)
2010	Puts purchased	2,520,000	$	7.839	$	9,039
2010	Calls sold	2,520,000	$	9.007		(22	)
2011	Puts purchased	12,840,000	$	6.197		19,167
2011	Calls sold	12,840,000	$	7.283		(4,929	)
2012	Puts purchased	9,780,000	$	6.220		16,311
2012	Calls sold	9,780,000	$	7.309		(9,240	)
2013	Puts purchased	11,820,000	$	6.228		21,487
2013	Calls sold	11,820,000	$	7.389		(15,904	)
					$	35,909

Crude Oil Fixed Price Swaps

Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset/(Liability)
	(Bbl) (1)	(per Bbl) (1)		(in thousands) (3)
2010	39,300	$	97.219	$	497
2011	42,600	$	77.460		(365	)
2012	33,500	$	76.855		(324	)
2013	10,000	$	77.360		(93	)
				$	(285	)

Crude Oil Costless Collars

Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset/ (Liability)
		(Bbl) (1)	(per Bbl) (1)		(in thousands) (3)
2010	Puts purchased	25,000	$	85.000	$	130
2010	Calls sold	25,000	$	112.546		(10	)
2011	Puts purchased	27,000	$	67.223		100
2011	Calls sold	27,000	$	89.436		(276	)
2012	Puts purchased	21,500	$	65.506		99
2012	Calls sold	21,500	$	91.448		(247	)
2013	Puts purchased	6,000	$	65.358		32
2013	Calls sold	6,000	$	93.442		(69	)
					$	(241	)
Total Company net asset					$	189,139

⁽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.

The Company’s commodity price risk management includes estimated future natural gas and crude oil production of the Partnerships. Therefore, a portion of any unrealized derivative gain or loss is allocable to the limited partners of the Partnerships based on their share of estimated gas and oil production related to the derivatives not yet settled. At March 31, 2010 and December 31, 2009, net unrealized derivative assets of $70.0 million and $41.7 million, respectively, are payable to the limited partners in the Partnerships and are included in the consolidated balance sheets as follows (in thousands).

	March 31,			December 31,
	2010			2009
Prepaid expenses and other	$	181		$	270
Other assets, net		6,608			2,841
Accrued liabilities		(37,605	)		(22,382	)
Long-term derivative liability		(39,187	)		(22,380	)
	$	(70,003	)	$	(41,651	)

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Atlas Pipeline Holdings and Atlas Pipeline Partners

In July 2008, APL discontinued hedge accounting for its existing commodity derivatives which were qualified as hedges under prevailing accounting literature. As such, subsequent changes in fair value of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s consolidated statements of operations. The fair value of these commodity derivative instruments at June 30, 2008, which was recognized in accumulated other comprehensive loss within shareholders’ equity on the Company’s consolidated balance sheet, will be reclassified to the Company’s consolidated statements of operations in the future at the time the originally hedged physical transactions affect earnings.

At March 31, 2010, AHD had an interest rate derivative contract having an aggregate notional principal amount of $25.0 million. Under the terms of agreement, AHD will pay an interest rate of 3.0%, plus the applicable margin as defined under the terms of its credit facility (see Note 9), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. The interest rate swap agreement was effective at March 31, 2010 and expires on May 28, 2010. In June 2009, AHD repaid a portion of its borrowings under its credit facility with additional payments made in July and October 2009 and January 2010 with a resulting balance of $4.0 million outstanding under its credit facility at March 31, 2010. In addition, in accordance with the June 2009 amendment to its credit facility, AHD is prohibited from borrowing additional amounts under its credit facility once the amounts have been repaid. In accordance with prevailing accounting literature, the portion of any gain or loss in other comprehensive income (loss) related to forecasted hedge transactions that are no longer expected to occur are to be removed from other comprehensive income (loss) and recognized within the statements of operations.

At March 31, 2010, APL had interest rate derivative contracts having aggregate notional principal amounts of $250.0 million. Under the terms of these agreements, APL will pay weighted average interest rates of 3.1%, plus the applicable margin as defined under the terms of its revolving credit facility (see Note 9), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. The APL interest rate swap agreements were effective as of March 31, 2010 and expire on April 30, 2010.

Beginning May 29, 2009, AHD and APL discontinued hedge accounting for their interest rate derivatives which were qualified as hedges under prevailing accounting literature. As such, subsequent changes in the fair value of these derivatives will be recognized immediately within loss on mark-to-market derivatives in the Company’s consolidated statements of operations. The fair value of these derivative instruments at May 29, 2009, which was recognized in accumulated other comprehensive loss within shareholders’ equity’ on the Company’s consolidated balance sheet, will be reclassified to the Company’s consolidated statements of operations in the future at the time the originally hedged physical transactions affect earnings.

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

	Asset Derivatives					Liability Derivatives
	Balance Sheet Location	March 31, 2010		December 31, 2009		Balance Sheet Location	March 31, 2010			December 31, 2009
Interest rate contracts	N/A	$	—	$	—	Current portion of derivative liability	$	(600	)	$	(2,533	)
Interest rate contracts	N/A		—		—	Current portion of derivative asset		(118	)		(593	)
Commodity contracts	Current portion of derivative asset		753		1,591	N/A		—			—
Commodity contracts	Long-term derivative asset		—		361	N/A		—			—
Commodity contracts	Current portion of derivative liability		3,718		6,562	Current portion of derivative liability		(16,544	)		(37,862	)
Commodity contracts	Long-term derivative liability		2,385		3,435	Long-term derivative liability		(10,278	)		(14,561	)
		$	6,856	$	11,949		$	(27,540	)	$	(55,549	)

25

As of March 31, 2010, AHD had the following interest rate derivatives, which do not qualify for hedge accounting:

Interest Fixed-Rate Swaps

Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Liability(1) (in thousands)
May 2008-May 2010	$	25,000,000	Pay 3.0% —Receive LIBOR	2010	$	(115	)
				Total AHD liability	$	(115	)

⁽¹⁾ Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace.

As of March 31, 2010, APL had the following interest rate and commodity derivatives, which do not qualify for hedge accounting:

Interest Fixed-Rate Swaps

Term	Amount		Type	Fair  Value(1) Asset/(Liability) (in thousands)
April 2008-April 2010	$	250,000,000	Pay 3.1% —Receive LIBOR	$	(603	)

Fixed Price Swaps

Production Period	Purchased/ Sold	Commodity	Volumes(2)	Average Fixed Price		Fair  Value(1) Asset/(Liability) (in thousands)
Natural Gas
2010	Sold	Natural Gas Basis	3,390,000	(0.659	)	$	(1,775	)
2010	Purchased	Natural Gas Basis	5,580,000	(0.619	)		2,523
2011	Sold	Natural Gas Basis	1,920,000	(0.728	)		(988	)
2011	Purchased	Natural Gas Basis	1,920,000	(0.758	)		1,045
2012	Sold	Natural Gas Basis	720,000	(0.685	)		(321	)
2012	Purchased	Natural Gas Basis	720,000	(0.685	)		321
Natural Gas Liquids
2010	Sold	Propane	17,640,000	1.108			(423	)
Total Fixed Price Swaps						$	382

26

Options

Production Period	Purchased/ Sold	Type	Commodity	Volumes(2)	Average Strike Price		Fair  Value(1) Asset/(Liability) (in thousands)
Natural Gas
2010	Purchased	Call	Natural Gas	6,390,000	$	5.829	$	(672	)
Natural Gas Liquids
2010	Purchased	Put	Propane	23,688,000	$	1.073		84
2010	Purchased	Put	Normal Butane	2,772,000		1.440		(187	)
Crude Oil
2010	Purchased	Put	Crude Oil	627,000		74.31		1,045
2010	Sold	Call	Crude Oil	1,961,250		83.83		(12,184	)
2010	Purchased(3)	Call	Crude Oil	444,000		120.00		107
2011	Sold	Call	Crude Oil	678,000		94.68		(4,996	)
2011	Purchased(3)	Call	Crude Oil	252,000		120.00		548
2012	Sold	Call	Crude Oil	498,000		95.83		(4,871	)
2012	Purchased(3)	Call	Crude Oil	180,000		120.00		778
Total Options							$	(20,348	)
				Total APL liability			$	(20,569	)

⁽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 2010 through 2012 represent offsetting positions for calls sold. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise.

During the three months ended March 31, 2010 and 2009, APL made net payments of $13.4 million and $5.0 million, respectively, related to the early termination of derivative contracts. Terminated derivative contracts are due to expire through December 31, 2012. During the three months ended March 31, 2010 and 2009, the Company recognized the following derivative activity related to APL’s early termination of these derivative instruments within its consolidated statements of operations (in thousands):

Early termination of derivative contracts:	For the Three Months Ended March 31,
	2010			2009
Cash paid for early termination	$	(13,370	)	$	(5,000	)
Less: Deferred recognition of loss on early termination(1)		(5,615	)		—
		(18,985	)		(5,000	)
Net cash derivative expense included within transmission, gathering and processing revenue		5,197			—
Net cash derivative expense included within gain on mark-to-market derivatives		(24,182	)		(5,000	)
Recognition of deferred hedge loss from prior periods included within transmission, gathering and processing revenue		(15,532	)		(21,944	)
Recognition of deferred hedge gain from prior periods included within gain on mark-to-market derivative		22,084			12,103
Total recognized loss from early termination	$	(12,433	)	$	(14,841	)

⁽¹⁾ Deferred recognition based upon effective portion of hedges deferred to accumulated other comprehensive income, plus theoretical premium related to unwound options which had previously been purchased or sold as part of costless collars

In addition, APL will recognize $13.7 million in the period beginning April 1, 2010 and ending on December 31, 2010 and $2.3 million and $2.0 million of income in years 2011 and 2012, respectively, the remaining period for which the hedged physical transactions are scheduled to be settled, in the Company’s consolidated statements of operations. This $18.0 million includes $16.1 million of income related to the theoretical premiums for unwound options which had previously been purchased or sold as part of costless collars, plus $1.9 million which will be reclassified from accumulated other comprehensive loss within shareholder’s equity on the Company’s consolidated balance sheet.

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

	Gain (Loss) Recognized in Accumulated OCI					Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
	Three Months Ended March 31,						Three Months Ended March 31,
	2010		2009			Location	2010			2009
Interest rate contracts(1)	$	—	$	(1,377	)	Interest expense	$	(1,823	)	$	(3,054	)
Interest rate contracts(1)		—		—		Gain on mark-to market derivatives		(20	)		—
Commodity contracts(1)		—		—		Transmission, gathering and processing revenue		(8,933	)		(15,970	)
	$	—	$	(1,377	)		$	(10,776	)	$	(19,024	)

	Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
		Three Months Ended March 31,
	Location	2010			2009
Interest rate contracts(1)	Gain on mark-to market derivatives	$	(10	)	$	—
Commodity contracts(1)	Transmission, gathering and processing revenue		—			(4,203	)
Commodity contracts(2)	Gain on mark-to market derivatives		4,139			316
		$	4,129		$	(3,887	)

⁽¹⁾ Hedges previously designated as cash flow hedges

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

The fair value of the derivatives included in the Company’s consolidated balance sheets is as follows (in thousands):

	March 31,			December 31,
	2010			2009
Current portion of derivative asset	$	118,433		$	74,064
Long-term derivative asset		106,383			59,291
Current portion of derivative liability		(17,732	)		(38,485	)
Long-term derivative liability		(38,629	)		(25,441	)
Total Company net asset	$	168,455		$	69,429

NOTE 11 – FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company has established a hierarchy to measure its financial instruments at fair value which requires it 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 assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

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Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Company uses a fair value methodology to value the assets and liabilities for its, AHD’s and APL’s outstanding derivative contracts (see Note 10) and the Company’s Supplemental Employment Retirement Plans (“SERPs”—see Note 17). The Company’s and APL’s commodity derivative contracts, with the exception of APL’s NGL fixed price swaps and NGL options, are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. The Company’s, AHD’s and APL’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model and are therefore defined as Level 2 fair value measurements. The Company’s SERPs are calculated based on observable actuarial inputs developed by a third-party actuary and therefore is defined as a Level 2 fair value measurement, while the asset related to the funding of the SERPs are based on publicly traded equity and debt securities and is therefore defined as a Level 1 fair value measurement. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGL’s for similar locations, and therefore are defined as Level 3 fair value measurements. Valuations for APL’s NGL options are based on forward price curves developed by the related financial institution, and therefore are defined as Level 3 fair value measurements.

In June 2009, APL changed the basis for its valuation of crude oil options. Previously, APL utilized forward price curves developed by its derivative counterparties. Effective June 2009, APL utilized crude oil option prices quoted from a public commodity exchange. With this change in valuation basis, APL reclassified the inputs for the valuation of its crude oil options from a Level 3 input to a Level 2 input. The change in valuation basis did not materially impact the fair value of its derivative instruments on its consolidated statements of operations.

Assets and liabilities measured at fair value at March 31, 2010 and December 31, 2009 were as follows (in thousands):

	Level 1		Level 2			Level 3			Total
March 31, 2010
SERP liability	$	—	$	(6,025	)	$	—		$	(6,025	)
SERP asset funded in rabbi trust		3,940		—			—			3,940
Company commodity-based derivatives		—		192,489			—			192,489
APL commodity-based derivatives		—		(19,440	)		(526	)		(19,966	)
Interest rate derivatives		—		(4,068	)		—			(4,068	)
Total	$	3,940	$	162,956		$	(526	)	$	166,370
December 31, 2009
SERP liability	$	—	$	(3,968	)	$	—		$	(3,968	)
SERP asset funded in rabbi trust		3,778		—			—			3,778
Company commodity-based derivatives		—		117,003			—			117,003
APL commodity-based derivatives		—		(41,742	)		1,268			(40,474	)
Interest rate derivatives		—		(7,100	)		—			(7,100	)
Total	$	3,778	$	64,193		$	1,268		$	69,239

APL’s Level 3 fair value amount relates to its derivative contracts on NGL fixed price swaps and crude oil options. The following table provides a summary of changes in fair value of APL’s Level 3 derivative instruments as of March 31, 2010 (in thousands):

	NGL Fixed Price Swaps			NGL Put Options			Total
Balance – December 31, 2009	$	—		$	1,268		$	1,268
New contracts		—			—			—
Cash settlements from unrealized loss(1) (2)		—			3,951			3,951
Net change in unrealized loss(1)		(423	)		(1,371	)		(1,794	)
Deferred option premium recognition		—			(3,951	)		(3,951	)
Balance – March 31, 2010	$	(423	)	$	(103	)	$	(526	)

(1) Included within gain on mark-to-market derivatives on the Company’s consolidated statements of operations.

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

Other Financial Instruments

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

The Company’s other current assets and liabilities on its consolidated balance sheets are financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature. The estimated fair values of the Company’s debt at March 31, 2010 and December 31, 2009, which consists principally of APL’s term loan, ATN and APL’s Senior Notes and borrowings under the ATN’s, AHD’s and APL’s credit facilities, were $2,124.7 million and $1,911.4 million, respectively, compared with the carrying amounts of $2,074.7 million and $2,048.6 million, respectively. The Senior Notes were valued based upon recent trading activity. The carrying value of outstanding borrowings under the credit facilities, which bear interest at a variable interest rate, approximates their estimated fair value.

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

The Company estimates the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements; the credit-adjusted risk-free rate of the Company; and estimated inflation rates (see Note 8). Information for assets that are measured at fair value on a nonrecurring basis for the three months ended March 31, 2010 was as follows (in thousands):

	Three Months Ended
	March 31, 2010				March 31, 2009
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	43	$	43	$	430	$	430
Total	$	43	$	43	$	430	$	430

NOTE 12 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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

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

Relationship with Resource America, Inc.The Company has a transition services agreement with Resource America, Inc. (“RAI”), its former parent that is still in effect at March 31, 2010. The transition services agreement governs the provision of support services by the Company to RAI and by RAI to the Company, such general and administrative functions. The Company reimburses RAI for various costs and expenses it incurs for these services on behalf of the Company, primarily payroll and rent. For both the three months ended March 31, 2010 and 2009, the Company’s reimbursements to RAI totaled $0.3 million. At March 31, 2010 and December 31, 2009, reimbursements to RAI totaling $0.1 million and $0.2 million, respectively, which remain to be settled between the parties, were reflected in the Company’s consolidated balance sheets as advances to/from affiliate.

Relationship with Laurel Mountain. Upon completion of the transaction with Laurel Mountain, the Company entered into new gas gathering agreements with Laurel Mountain which superseded the existing master natural gas gathering agreement and omnibus agreement between the Company and APL. Under the new gas gathering agreements, the Company is obligated to pay Laurel Mountain all of the gathering fees it collects from the Partnerships, which generally ranges from $0.35 per Mcf to the amount of the competitive gathering fee (which is currently defined as 13% of the gross sales price received for the Partnerships gas) plus any excess amount of the gathering fees collected up to an amount equal to approximately 16% of the natural gas sales price. The new gathering agreements contain additional provisions which define certain obligations and options of each party to build and connect newly drilled wells to any Laurel Mountain gathering system.

Relationship with Crown Drilling of Pennsylvania, LLC.Since 2007, the Company has had an equity interest in Crown Drilling of Pennsylvania, LLC (“Crown”), a company that performs the drilling activities for certain of the Company’s investment partnerships. In addition to its equity ownership, the Company guarantees 50% of the outstanding balances of Crown’s credit agreement. As of March 31, 2010, the Company’s guarantee was limited to $10.7 million.

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NOTE 13 – COMMITMENTS AND CONTINGENCIES

General Commitments

The Company is the managing general partner of the Partnerships, and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Partnership assets. Subject to certain conditions, investor partners in certain Partnerships have the right to present their interests for purchase by the Company, as managing general partner. The Company is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on past experience, the management of the Company believes that any liability incurred would not be material. The Company may be required to subordinate a part of its net partnership revenues from the Partnerships to the benefit of the investor partners for an amount equal to at least 10% of their subscriptions, determined on a cumulative basis, in accordance with the terms of the partnership agreements. For the three months ended March 31, 2010, $3.3 million of the Company’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the investment partnerships. No subordination of the Company’s net revenues was required for the three months ended March 31, 2009.

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

As of March 31, 2010, the Company and its subsidiaries are committed to expend approximately $47.1 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

Legal Proceedings

Following announcement of the Merger on April 27, 2009, five purported class actions were filed in Delaware Chancery Court and were later consolidated into a single complaint, Inre Atlas Energy Resources, LLC Unitholder Litigation, C.A. No. 4589-VCN (the “Consolidated Action”) filed on July 1, 2009 (the “Consolidated Complaint”). The Consolidated Complaint named the Company and ATN’s various officers and directors as defendants (the “Defendants”), alleged violations of fiduciary duties in connection with the Merger, and requested injunctive relief and damages.

On August 7, 2009, plaintiffs advised the Delaware Chancery Court by letter that they would not pursue their motion for a preliminary injunction, which had been scheduled for a hearing on September 4, 2009, and requested that the September 4 hearing date be removed from the Court’s calendar. On October 16, 2009, the Company filed a motion to dismiss the Consolidated Complaint. On December 15, 2009, plaintiffs filed an Amended Complaint (the “Amended Complaint”). On January 6, 2010, the Delaware Chancery Court granted the parties’ Scheduling Stipulation and Order, providing that Defendants would have until February 18, 2010, to file a motion to dismiss the Amended Complaint; that plaintiffs’ answering brief in opposition would be due on or before May 3, 2010; and that Defendants’ reply papers would be due on or before June 4, 2010. Defendants filed their opening brief in support of their motion to dismiss on February 18, 2010 and plantiffs filed their brief in opposition on May 3, 2010.

The Amended Complaint alleges that Defendants breached their purported fiduciary duties to ATN’s public unitholders in connection with their negotiation of the Merger. In particular, plaintiffs allege that the Merger was not entirely fair to ATN’s public unitholders, and that Defendants conducted the Merger process in bad faith.

Predicting the outcome of this lawsuit is difficult. An adverse judgment for monetary damages could have a material adverse effect on the operations of the Company. Based on the facts known to date, Defendants believe that the claims asserted against them in this lawsuit are without merit, and will continue to defend themselves vigorously against the claims.

In June 2008, the Company’s wholly-owned subsidiary, Atlas America, LLC, was named as a co-defendant in the matter captionedCNX Gas Company, LLC (“CNX”) v. Miller Petroleum, Inc. (“Miller”), et al. (Chancery Court, Campbell County, Tennessee). In its complaint, CNX alleged that Miller breached a contract to assign to CNX certain leasehold rights (“Leases”) representing approximately 30,000 acres in Campbell County, Tennessee and that Atlas America, LLC and another defendant, Wind City Oil & Gas, LLC, interfered with the closing of this assignment on June 6, 2008. ATN purchased the Leases from Miller for approximately $19.1 million. On December 15, 2008, the Chancery Court dismissed the matter in its entirety, holding that there had been no breach of the contract by Miller and, therefore, that Atlas America, LLC could not have tortuously interfered with the contract. The Chancery Court dismissed all claims against Atlas America, LLC; however, CNX has appealed this decision.

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

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NOTE 14 – INCOME TAXES

The Company accounts for income taxes under the asset and liability method pursuant to prevailing accounting literature. Under such literature, deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value. As of March 31, 2010 and December 31, 2009, the Company determined that no valuation allowance was necessary.

The Company recognizes the financial statement benefit of a tax position after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting a more-likely-than-not threshold, the amount recognized in the consolidated financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. The Company had applied this methodology to all tax positions for which the statute of limitation remains open, and there were no additions, reductions or settlements in unrecognized tax benefits during the three months ended March 31, 2010 and 2009. The Company has no material uncertain tax positions at March 31, 2010. During the three months ended March 31, 2009, the Company made cash tax payments of $0.3 million.

The Company is subject to income taxes in the U.S. federal jurisdiction and various states. Tax regulations within each jurisdiction are subject to the interpretations of the related tax laws and regulations and require significant judgment to apply. With few exceptions, the Company is no longer subject to U.S. federal, state, and local, or non-U.S. income tax examinations by tax authorities for the years before 2006. The Company’s policy is to reflect interest and penalties related to uncertain tax positions as part of the income tax expense, when and if they become applicable.

NOTE 15 – ISSUANCES OF SUBSIDIARY UNITS

The Company recognizes gains on its subsidiaries’ equity transactions as a credit to equity rather than as income pursuant to prevailing accounting literature. These gains represent the Company’s portion of the excess net offering price per unit of each of its subsidiary’s units to the book carrying amount per unit.

In January 2010, APL executed amendments to warrants to purchase 2,689,765 of its common units. The warrants were originally issued along with its common units in connection with a private placement to institutional investors that closed on August 20, 2009. The amendments to the warrants provided that, for the period January 8 through January 12, 2010, the warrant exercise price was lowered to $6.00 from $6.35 per unit. In connection with the amendments, the holders of the warrants agreed to exercise all of the warrants for cash, which resulted in net cash proceeds of approximately $15.3 million. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan and credit facility (see Note 9), and to fund the early termination of certain derivative agreements.

In August 2009, APL sold 2,689,765 common units in a private placement at an offering price of $6.35 per unit, yielding net proceeds of approximately $16.1 million. APL also received a capital contribution from AHD of $0.4 million for AHD to maintain its-then 2.0% general partner interest in the APL. In addition, APL issued warrants granting investors in its private placement the right to purchase an additional 2,689,765 common units at a price of $6.35 per unit for a period of two years following the issuance of the original common units. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan (see Note 9).

NOTE 16 – SUBSIDIARY CASH DISTRIBUTIONS

Atlas Pipeline Partners Cash Distributions. APL is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders and AHD, as general partner. If APL’s common unit distributions in any quarter exceed specified target levels, AHD will receive between 15% and 50% of such distributions in excess of the specified target levels. Common unit and general partner distributions declared by APL for the period from January 1, 2009 through March 31, 2010 were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid	For Quarter Ended	APL Cash Distribution per Common Limited Partner Unit		Total APL  Cash Distribution to Common Limited Partners		Total APL  Cash Distribution to the General Partner
February 13, 2009	December 31, 2008	$	0.38	$	17,463	$	2,545
May 13, 2009	March 31, 2009	$	0.15	$	7,147	$	1,010

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On May 29, 2009, APL entered into an amendment to its senior secured credit facility (see Note 9), which, among other things, required that it pay no cash distributions during the remainder of the year ended December 31, 2009 and allows it to pay cash distributions commencing with the quarter ended March 31, 2010 if its senior secured leverage ratio is below certain thresholds and it has minimum liquidity (both as defined in the credit agreement) of at least $50.0 million.

Atlas Pipeline Holdings Cash Distributions.AHD 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 its partnership agreement) for that quarter to its common unitholders. Distributions declared by AHD for the period from January 1, 2009 through March 31, 2010 were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid or Payable	For Quarter Ended	Cash Distribution per Common Limited Partner Unit		Total Cash Distribution to the Company (in thousands)
February 19, 2009	December 31, 2008	$	0.06	$	1,068

On June 1, 2009, AHD entered into an amendment to its credit facility agreement, which, among other changes, prohibited it from paying any cash distributions on its equity while the credit facility was in effect (see Note 9).

NOTE 17 – BENEFIT PLANS

Stock Incentive Plan

The Company has a Stock Incentive Plan (the “2004 Plan”) which authorizes the granting of up to 4,499,999 shares of the Company’s common stock to employees, affiliates, consultants and directors of the Company in the form of incentive stock options (“ISOs”), non-qualified stock options, stock appreciation rights (“SARs”), restricted stock and deferred units. The Company also has a 2009 Stock Incentive Plan (the “2009 Plan” and together with the 2004 Plan, the “Plans”) which authorizes the granting of up to 4,800,000 shares of the Company’s common stock to employees, affiliates, consultants and directors of the Company in the form of ISOs, non-qualified stock options, SARs, restricted stock, restricted stock units and deferred units. Generally, all share-based payments to employees, including grants of employee stock options, are required to be recognized in the financial statements based on their fair values.

2009 Plan Stock Options. Generally, options granted under the 2009 Plan as of March 31, 2009 vest 25% per year upon the anniversary of the grant and expire not later than ten years after the date of grant. Compensation cost is recorded on a straight-line basis. The Company issues shares when stock options are exercised or units are converted to shares. The following tables set forth the 2009 Plan activity for the three months ended March 31, 2010 (there was no plan activity for the three months ended March 31, 2009):

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in  thousands)
Outstanding at January 1, 2010		2,500	$	29.10
Granted		1,185,500		29.09
Exercised		—		—
Cancelled		—		—
Forfeited or expired		—		—
Outstanding at March 31, 2010		1,188,000	$	29.09	9.9	$	2,434
Options exercisable at March 31, 2010		—		—
Non-cash compensation expenserecognized (in thousands)	$	709
Available for grant at March 31, 2010		3,353,459

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The Company used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the period indicated:

	Three Months Ended March 31, 2010
Expected dividend yield		—
Expected stock price volatility		48	%
Risk-free interest rate		2.6	%
Expected term (in years)		6.25
Fair value of stock options granted	$	14.43

2009 Plan Restricted Share Units and Restricted Shares.Under the 2009 Plan, restricted share units are granted from time to time to employees of the Company. Each unit represents the right to receive one share of the Company’s common stock upon vesting. The vesting schedule is determined by the Compensation Committee of the Company’s Board of Directors. Units will vest sooner upon a change in control of the Company or death or disability of a grantee, provided that a grantee has completed at least six months’ service. The fair value of the grants is based on the closing share price on the grant date, and is being charged to operations over the requisite service periods using a straight-line attribution method. Upon termination of service by a grantee, all unvested units are forfeited.

Restricted shares are granted from time to time to employees of the Company. The shares are issued to the participant, held in escrow, and distributed to the participant upon vesting. The vesting schedule is determined by the Compensation Committee of the Company’s Board of Directors. The fair value of the grant is based on the closing price on the grant date, and is expensed over the requisite service period using a straight-line attribution method.

The following table summarizes the activity of deferred and restricted units for the three months ended March 31, 2010 (there was no activity for deferred and restricted units for the three months ended March 31, 2009):

	Units		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at January 1, 2010		12,633	$	29.50
Granted		245,908		29.07
Vested		—		—
Forfeited		—		—
Non-vested shares outstanding at March 31, 2010(1)		258,541	$	29.09
Non-cash compensation expense recognized (in thousands)	$	305

⁽¹⁾ The aggregate intrinsic value for restricted stock unit awards outstanding at March 31, 2010 was $8.0 million.

For the three months ended March 31, 2010, the Company recorded non-cash compensation of $1.0 million for the Company’s options and units under the 2009 Plan. At March 31, 2010, the Company had unamortized compensation expense related to its unvested portion of the 2009 Plan options and units of $23.6 million that the Company expects to recognize over the next four years.

34

2004 Plan Stock Options. For options granted under the 2004 Plan, 25% of the granted amount becomes exercisable each year upon the grant date anniversary, except options totaling 1,687,500 shares awarded in fiscal 2005 to Messrs. Edward Cohen and Jonathan Cohen, which are immediately exercisable, and expire not later than ten years after the date of grant. Compensation cost is recorded on a straight-line basis. The Company received $2,000 during the three months ended March 31, 2010 from the exercise of options. The Company issues new shares when stock options are exercised or units are converted to shares. The following tables set forth the Plan activity for the three months ended March 31, 2010 and 2009:

	Three Months Ended March 31,
	2010					2009
				Weighted					Weighted
	Number			Average		Number			Average
	of Unit			Exercise		of Unit			Exercise
	Options			Price		Options			Price
Outstanding, beginning of period		3,507,054		$	16.81		3,495,351		$	16.96
Granted		—			—		100,000		$	13.35
Exercised(1)		(183	)	$	11.32		—			—
Cancelled		—			—		(15,187	)	$	11.32
Forfeited		—			—		(21,938	)	$	11.32
Outstanding, end of period(2)(3)		3,506,871		$	16.81		3,558,226		$	16.92
Options exercisable, end of period(4)		2,983,746		$	14.66
Non-cash compensation expense recognized (in thousands)	$	703				$	920
Available for grant at March 31, 2010		759,270

⁽¹⁾ The aggregate intrinsic value for the options that were exercised during the three months ended March 31, 2010 was $4,000.

⁽²⁾ The weighted average remaining contractual life for outstanding options at March 31, 2010 was 6.2 years.

⁽³⁾ The aggregate intrinsic value of options outstanding at March 31, 2010 was approximately $51.5 million.

⁽⁴⁾ The weighted average outstanding contractual life of exercisable options at March 31, 2010 is 5.7 years.

The Company used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the periods indicated:

	Three Months Ended March 31,
	2010		2009
Expected dividend yield		—		0.6	%
Expected stock price volatility		—		36	%
Risk-free interest rate		—		2.2	%
Expected term (in years)		—		6.25
Fair value of stock options granted	$	—	$	4.89

2004 Plan Deferred Units and Restricted Shares. Under the 2004 Plan, on an annual basis, non-employee directors of the Company are awarded deferred units that vest over a four-year period. Each unit represents the right to receive one share of the Company’s common stock upon vesting. Units will vest sooner upon a change in control of the Company or death or disability of a grantee, provided that a grantee has completed at least six months’ service. The fair value of the grants is based on the closing stock price on the grant date, and is being charged to operations over the requisite service periods using a straight-line attribution method. Upon termination of service by a grantee, all unvested units are forfeited.

Restricted shares are granted from time to time to employees of the Company. The shares are issued to the participant, held in escrow, and distributed to the participant upon vesting. The units vest one-fourth at each anniversary date over a four-year service period. The fair value of the grant is based on the closing price on the grant date, and is being expensed over the requisite service period using a straight-line attribution method.

35

The following table summarizes the activity of deferred and restricted units for the three months ended March 31, 2010 and 2009:

	Three Months Ended March 31,
	2010					2009
	Number of Units			Weighted Average Grant  Date Fair Value		Number of Units			Weighted Average Grant  Date Fair Value
Non-vested shares outstanding, beginning of period		34,366		$	22.94		12,512		$	24.05
Granted		—			—		—			—
Matured(1)		(1,425	)	$	22.93		(842	)	$	20.76
Forfeited		—			—		—			—
Non-vested shares outstanding, end of period(2)		32,941		$	22.94		11,670		$	24.29
Non-cash compensation expense recognized (in thousands)	$	54				$	26
(1)       The aggregate intrinsic values for phantom unit awards that matured during the three months ended March 31, 2010 and 2009 were $45,000 and $10,000, respectively. (2)       The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2010 was $1.0 million.

For the three months ended March 31, 2010 and 2009, the Company recorded non cash compensation expense of $0.8 million and $0.9 million, respectively, for the Company’s options and units under the 2004 Plan. At March 31, 2010, the Company had unamortized compensation expense related to its unvested portion of the options and units of $5.3 million that the Company expects to recognize over the next four years.

Amended and Restated Atlas Energy, Inc. Assumed Long-Term Incentive Plan

Prior to the Merger on September 29, 2009, ATN had a Long-Term Incentive Plan (“LTIP”), which provided equity incentive awards to officers, employees and directors and employees of its affiliates, consultants and joint-venture partners. Subsequent to the Merger, the Company assumed ATN’s LTIP and renamed the LTIP as the “Atlas Energy, Inc. Assumed Long-Term Incentive Plan” (“Assumed LTIP”) and each outstanding unit option, phantom unit and restricted unit granted under the LTIP was converted to an equivalent stock option, phantom share or restricted share of the Company’s at a ratio of 1.0 ATN unit to 1.16 Company common shares. No new grant awards will be issued under the Assumed LTIP.

Other than the conversion of the LTIP awards to the Company’s options, restricted shares or phantom shares, the terms of the grants that had been awarded under the LTIP remain unchanged under the Assumed LTIP. Awards granted to all participants other than non-employee directors vest 25% upon the third anniversary of the grant date and 75% upon the fourth anniversary of the grant date. Awards to non-employee directors vest 25% per year over four years. Generally, upon termination of service by a grantee, all unvested awards will be forfeited. Upon vesting of a phantom stock award, a grantee is entitled to receive an equivalent number of common shares of the Company. Non-employee directors have the right, upon the vesting of their phantom stock awards to receive an equivalent number of common shares or, the cash equivalent to the then fair market value of the Company’s common shares.

Assumed Plan Restricted and Phantom Units. The fair value of the grants under the Assumed LTIP was based on the closing stock price on the grant date, and was charged to operations over the requisite service periods using the straight-line method. The following table summarizes the pre-Merger unconverted restricted unit and phantom unit activity for the period from January 1, 2009 to March 31, 2009 and the post-Merger converted restricted stock and phantom unit activity from January 1, 2010 through March 31, 2010:

	Three Months Ended March 31,
	2010					2009
	Number of Units(1)			Weighted Average Grant  Date Fair Value(1)		Number of  Units(2)			Weighted Average Grant  Date Fair  Value(2)
Non-vested shares outstanding, beginning of period		856,172		$	19.97		768,829		$	23.86
Granted		—			—		17,000		$	14.18
Matured(3)		(147,393	)	$	19.83		(1,168	)	$	28.82
Forfeited		(580	)	$	22.45		—			—
Non-vested shares outstanding, end of period(4)		708,199		$	20.00		784,661		$	23.65
Non-cash compensation expense recognized (in thousands)	$	1,110				$	1,183

36

⁽¹⁾       The shares and fair values for the three months ended March 31, 2010 (post-Merger shares) have been adjusted to reflect the post-Merger conversion ratio of 1.0 ATN common unit to 1.16 common shares of the Company.

⁽²⁾       The shares and fair values for the three months ended March 31, 2009 (pre-Merger shares) have not been adjusted to reflect the post-Merger conversion of 1.0 ATN common unit to 1.16 common shares of the Company.

⁽³⁾       The intrinsic values for phantom unit awards vested during the three months ended at March 31, 2010 and 2009 were $4.4 million and $14,000, respectively.

⁽⁴⁾       The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2010 was $22.0 million.

Assumed Plan Stock Options. Option awards under the Assumed LTIP expire 10 years from the date of grant and were generally granted with an exercise price equal to the market price of ATN’s stock at the date of grant. For the period from January 1, 2009 to March 31, 2009, the following table summarizes the unconverted number of the ATN Class B units prior to the Merger on September 29, 2009. The converted number of the Company’s common shares subsequent to the Merger and the weighted average exercise price underlying the converted stock options are listed from January 1, 2010 through March 31, 2010. For the three months ended March 31, 2010, the Company received $0.1 million from the exercise of options. The following table sets forth the Assumed Plan option activity for the periods indicated:

	Three Months Ended March 31,
	2010					2009
	Number of Unit Options(1)			Weighted Average Exercise Price(1)		Number of Unit Options(2)			Weighted Average Exercise Price(2)
Outstanding, beginning of period		2,068,514		$	20.38		1,902,902		$	24.17
Granted		—			—		—			—
Exercised(3)		(7,279	)	$	19.88		—			—
Cancelled		(174	)	$	19.88		—			—
Forfeited		(2,784	)	$	19.88		(900	)	$	23.06
Outstanding, end of period(4)(5)		2,058,277		$	20.38		1,902,002		$	24.17
Options exercisable, end of period(6)		681,647		$	19.03
Non-cash compensation expense recognized (in thousands)	$	296				$	334
Available for grant at March 31, 2010		—
(1)         The shares and exercise prices for the three months ended March 31, 2010 (post-Merger shares) have been adjusted to reflect the post-Merger conversion ratio of 1.0 ATN common unit to 1.16 common shares of the Company. (2)         The shares and exercise prices for the three months ended March 31, 2009 (pre-Merger shares) have not been adjusted to reflect the post-Merger conversion ratio of 1.0 ATN common unit to 1.16 common shares of the Company. (3)         The aggregate intrinsic value of options exercised was approximately $0.1 million for the three months ended March 31, 2010. (4)         The weighted average remaining contractual life for outstanding options at March 31, 2010 was 6.8 years. (5)         The aggregate intrinsic value of options outstanding at March 31, 2010 was approximately $22.1 million. (6)         The weighted average outstanding contractual life of exercisable options at March 31, 2010 is 6.8 years.

37

The following tables summarize information about stock options outstanding and exercisable under the Assumed LTIP at March 31, 2010 subsequent to the Merger and the weighted average exercise price underlying the converted stock options:

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number of Shares Outstanding	Weighted Average Remaining Contractual Life in Years	Weighted Average Exercise Price		Number of Shares Exercisable	Weighted Average Exercise Price
$18.10 – 22.22	1,885,669	6.8	$	19.48	681,647	$	19.03
$26.07 – 30.17	163,908	7.3	$	29.98	—		—
$34.30 and above	8,700	8.2	$	34.30	—		—
	2,058,277	6.8	$	20.38	681,647	$	19.03

The Company recognized $1.4 million and $1.5 million in compensation expense related to the Assumed LTIP restricted stock units, phantom units and unit options for the three months ended March 31, 2010 and 2009, respectively. ATN paid $0.4 million with respect to distribution equivalent rights (“DER”) for three months ended March 31, 2009. These amounts were recorded as a reduction of non-controlling interests on the Company’s consolidated balance sheet during the respective period. ATN made no payments related to DERs during the three months ended March 31, 2010. At March 31, 2010, the Company had approximately $5.9 million of unrecognized compensation expense related to the unvested portion of the restricted shares, phantom shares and stock options.

Employee Stock Ownership Plan

The Company has an Employee Stock Ownership Plan (“ESOP”), which is a qualified non-contributory retirement plan, that was established to acquire shares of the Company’s common stock for the benefit of all employees who are 21 years of age or older and have completed 1,000 hours of service. Contributions to the ESOP were made at the discretion of the Company’s Board of Directors. Any dividends which may be paid on allocated shares will reduce retained earnings.

The common stock purchased by the ESOP is held by the ESOP trustee in a suspense account. On an annual basis, a portion of the common stock will be released from the suspense account and allocated to participating employees. As of December 31, 2009, all shares were allocated to participants. Participants will receive shares upon vesting, which occurs over a five year period, beginning after the participant’s second year of service.

Supplemental Employment Retirement Plans (“SERPs”)

The Company has employment agreements with certain executive officers, pursuant to which the Company has agreed to provide them with SERPs and with certain financial benefits upon termination of their employment. Under the SERPs, the executive officers entitled to SERP benefits will be paid an annual benefit upon retirement, death or other termination of employment based upon their salary at the time of the termination of their employment, number of years of service to the Company and other factors. During the three months ended March 31, 2010 and 2009, expense recognized with respect to these commitments was $0.7 million and $0.2 million, respectively.

During the year ended December 31, 2009, the Company funded $3.2 million of the outstanding liability with a financial institution in a rabbi trust for the SERP Plans, which is included in other assets on the Company’s consolidated balance sheet. As of March 31, 2010 and December 31, 2009, the actuarial present value of the expected postretirement obligation due under its SERPs were $6.0 million and $4.0 million, respectively, which were included in other long-term liabilities on the Company’s consolidated balance sheets. The following table provides information about amounts recognized in the Company’s consolidated balance sheets at the dates indicated (in thousands):

	March 31, 2010			December 31, 2009
Other liabilities	$	(6,025	)	$	(3,968	)
Accumulated other comprehensive income		1,172			340
Deferred income tax asset		749			218
Net amount recognized	$	(4,104	)	$	(3,410	)

The estimated amount that will be amortized from accumulated other comprehensive income into expense for the year ended December 31, 2010 is $0.2 million.

38

AHD Long-Term Incentive Plan

The Board of Directors of AHD approved and adopted AHD’s Long-Term Incentive Plan (“AHD LTIP”), which 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 AHD. The AHD LTIP is administered by a committee (the “AHD LTIP Committee”), appointed by AHD’s board, which is the Compensation Committee of the Company’s Board of Directors. Under the AHD LTIP, phantom units and/or unit options may be granted, at the discretion of the AHD LTIP Committee, to all or designated Participants, at the discretion of the AHD LTIP Committee. The AHD LTIP Committee may grant such awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units. At March 31, 2010, AHD had 1,093,375 phantom units and unit options outstanding under the AHD LTIP, with 961,150 phantom units and unit options available for grant.

AHD Phantom Units.A phantom unit entitles a Participant to receive a common unit of AHD upon vesting of the phantom unit. Non-employee directors receive an annual grant of a maximum of 500 phantom units which, upon vesting, entitles the grantee to receive the equivalent number of common units of AHD or the cash equivalent to the then fair market value of the common limited partner units of AHD. In tandem with phantom unit grants, the AHD LTIP Committee may grant a Participant a distribution equivalent right (“DER”), which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions AHD makes on a common unit during the period such phantom unit is outstanding. The AHD LTIP Committee determines the vesting period for phantom units. Through March 31, 2010, phantom units granted under the AHD 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 AHD, as defined in the AHD LTIP. Of the phantom units outstanding under the AHD LTIP at March 31, 2010, 132,713 units will vest within the following twelve months. All phantom units outstanding under the AHD LTIP at March 31, 2010 include DERs granted to the Participants by the AHD LTIP Committee. There were no amounts paid with respect to AHD’s LTIP DERs for the three months ended March 31, 2010 and 2009. These amounts were recorded as an adjustment of non-controlling interests on the Company’s consolidated balance sheet. The following table sets forth the AHD LTIP phantom unit activity for the periods indicated:

	Three Months Ended March 31,
	2010			2009
Outstanding, beginning of period		138,875			226,300
Granted		—			—
Matured		—			—
Forfeited		(500	)		(45,000	)
Outstanding, end of period(1)		138,375			181,300
Non-cash compensation expense recognized (in thousands)	$	196		$	(308	)
(1)       The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2010 is $0.9 million.

At March 31, 2010, AHD had approximately $0.5 million of unrecognized compensation expense related to unvested phantom units outstanding under AHD’s LTIP based upon the fair value of the awards.

AHD Unit Options.A unit option entitles a Participant to receive a common unit of AHD 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 AHD’s common unit on the date of grant of the option. The AHD LTIP Committee also shall determine how the exercise price may be paid by the Participant. The AHD LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through March 31, 2010, unit options granted under the AHD 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 AHD, as defined in the AHD LTIP. There are 641,250 unit options outstanding under the AHD LTIP at March 31, 2010 that will vest within the following twelve months. The following table sets forth the AHD LTIP unit option activity for the periods indicated:

	Three Months Ended March 31,
	2010				2009
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of period		955,000	$	20.54		1,215,000		$	22.56
Granted		—		—		100,000		$	3.24
Forfeited		—		—		(360,000	)	$	22.56
Outstanding, end of period(1)(2)		955,000	$	20.54		955,000		$	20.54
Options exercisable, end of period(3)		213,750	$	22.56		—			—
Weighted average fair value of unit options per unit granted during the period								$	0.61
Non-cash compensation expense recognized (in thousands)	$	155			$	(573	)

39

⁽¹⁾       The weighted average remaining contractual life for outstanding options at March 31, 2010 was 6.8 years.

⁽²⁾        The aggregate intrinsic value of options outstanding at March 31, 2010 was approximately $0.3 million.

⁽³⁾        The weighted average remaining contractual life for options exercisable at March 31, 2010 was 6.6 years.

AHD used the Black-Scholes option pricing model to estimate the weighted average fair value of each unit option granted. The following weighted average assumptions were used for the period indicated:

	Three Months Ended March 31, 2009
Expected dividend yield	7.0	%
Expected stock price volatility	40	%
Risk-free interest rate	2.3	%
Expected term (in years)	6.9

At March 31, 2010, AHD had approximately $0.4 million of unrecognized compensation expense related to unvested unit options outstanding under AHD’s LTIP based upon the fair value of the awards.

APL Long-Term Incentive Plan

APL has a Long-Term Incentive Plan (“APL LTIP”), in which officers, employees and non-employee managing board members of the General Partner and employees of the General Partner’s affiliates and consultants are eligible to participate. The APL LTIP is administered by a committee (the “APL LTIP Committee”) appointed by AHD’s managing board. The APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 435,000 common units.

APL Phantom Units.A phantom unit entitles a grantee to receive a common unit, without payment of an exercise price, upon vesting of the phantom unit. Non-employee directors receive an annual grant of a maximum of 500 phantom units which, upon vesting, entitles the grantee to receive the equivalent number of common units or the cash equivalent to the then fair market value of the common limited partner units of APL. In addition, the APL LTIP Committee may grant a participant a DER, which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions APL makes on a common unit during the period the phantom unit is outstanding. Except for phantom units awarded to non-employee managing board members of AHD, the APL LTIP Committee will determine the vesting period for phantom units and the exercise period for options. Through March 31, 2010, phantom units granted under the APL LTIP generally had vesting periods of four years. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards will automatically vest upon a change of control, as defined in the APL LTIP. Of the units outstanding under the APL LTIP at March 31, 2010, 28,153 units will vest within the following twelve months. All phantom units outstanding under the APL LTIP at March 31, 2010 include DERs granted to the participants by the APL LTIP Committee. The amount paid with respect to APL LTIP DERs was $0.1 million for the three months ended March 31, 2009. This amount was recorded as reductions of non-controlling interest on the Company’s consolidated balance sheet. No APL LTIP DERs were paid for the three months ended March 31, 2010. The following table sets forth the APL LTIP phantom unit activity for the periods indicated:

	Three Months Ended March 31,
	2010			2009
Outstanding, beginning of period		52,233			126,565
Granted(1)		1,000			1,500
Matured(2)		(2,695	)		(9,886	)
Forfeited		(1,375	)		(16,250	)
Outstanding, end of period(3)		49,163			101,929
Non-cash compensation expense recognized (in thousands)	$	122		$	(95	)

40

⁽¹⁾       The weighted average prices for phantom unit awards on the date of grant, which are utilized in the calculation of compensation expense and do not represent exercise prices to be paid by the recipients, were $5.58 and $4.60 for awards granted for the three months ended March 31, 2010 and 2009, respectively.

⁽²⁾       The intrinsic values for phantom unit awards exercised during the three months ended at March 31, 2010 and 2009 were $0.4 million and $0.1 million, respectively.

⁽³⁾       The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2010 is $0.7 million.

At March 31, 2010, APL had approximately $0.5 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIP based upon the fair value of the awards.

APL Unit Options.A unit option entitles a Participant to receive a common unit of APL 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 APL’s common unit on the date of grant of the option. The APL LTIP Committee also shall determine how the exercise price may be paid by the Participant. The APL LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through March 31, 2010, unit options granted under APL’s LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. Awards will automatically vest upon a change of control of APL, as defined in the APL’s LTIP. There were 25,000 unit options outstanding under APL’s LTIP at March 31, 2010 that will vest within the following twelve months.

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

	Three Months Ended March 31,
	2010				2009
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of period		100,000	$	6.24		—	$	—
Granted		—		—		100,000		6.24
Matured		—		—		—		—
Forfeited		—		—		—		—
Outstanding, end of period(1)(2)		100,000	$	6.24		100,000	$	6.24
Options exercisable, end of period(3)		25,000	$	6.24		—		—
Weighted average fair value of unit options per unit granted during the period Weighted average fair value of unit							$	0.14
Non-cash compensation expense recognized (in thousands)	$	1			$	2
(1)       The weighted average remaining contractual life for outstanding options at March 31, 2010 was 8.8 years.
(2)       The aggregate intrinsic value of options outstanding at March 31, 2010 was $0.8 million.
(3)       The weighted average remaining contractual life for exercisable options at March 31, 2010 was 8.8 years.

41

APL used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the period indicated:

	Three Months Ended March 31, 2009
Expected dividend yield	11.0	%
Expected stock price volatility	20	%
Risk-free interest rate	2.2	%
Expected term (in years)	6.3

APL Employee Incentive Compensation Plan and Agreement

In June 2009, a wholly-owned subsidiary of APL adopted an incentive plan (the “APL Plan”) which allows for equity-indexed cash incentive awards to employees of APL (the “Participants”), but expressly excludes as an eligible Participant any person that, at the time of the grant, is a “Named Executive Officer” of APL (as such term is defined under the rules of the Securities and Exchange Commission). The APL Plan is administered by a committee appointed by the chief executive officer of APL. Under the APL Plan, cash bonus units may be awarded to Participants at the discretion of the committee and bonus units totaling 325,000 were awarded under the APL Plan in June 2009. In September 2009, the APL subsidiary entered into an agreement with an APL executive officer that granted an award of 50,000 bonus units on substantially the same terms as the bonus units available under the APL Plan (the bonus units issued under the APL Plan and under the separate agreement are, for purposes hereof, referred to as “APL Bonus Units”). An APL Bonus Unit entitles the employee to receive the cash equivalent of the then-fair market value of an APL common limited partner unit, without payment of an exercise price, upon vesting of the APL Bonus Unit. APL Bonus Units vest ratably over a three year period from the date of grant and will automatically vest upon a change of control, death, or termination without cause, each as defined in the governing document. Vesting will terminate upon termination of employment with cause. Of the 375,000 APL Bonus Units outstanding at March 31, 2010, 123,750 APL Bonus Units will vest within the following twelve months. APL recognized $1.3 million of compensation expense related to these awards based upon the fair value of the awards within general and administrative expense on the Company’s consolidated statements of operations with respect to the vesting of these awards for the three months ended March 31, 2010. At March 31, 2010 and December 31, 2009, the Company has recognized $2.5 million and $1.2 million, respectively, within accrued liabilities on its consolidated balance sheets with regard to the awards, which represents their fair value at the respective dates.

NOTE 18 – OPERATING SEGMENT INFORMATION

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

	Three Months Ended March 31,
	2010			2009(1)
Gas and oil production
Revenues	$	63,909		$	71,943
Costs and expenses		(12,284	)		(11,286	)
Depreciation, depletion and amortization expense		(25,257	)		(27,010	)
Segment income	$	26,368		$	33,647
Well construction and completion
Revenues	$	72,642		$	112,368
Costs and expenses		(61,561	)		(95,397	)
Segment income	$	11,081		$	16,971
Other partnership management(2)
Revenues	$	12,137		$	3,567
Loss on asset sales		(2,942	)		—
Costs and expenses		(10,249	)		(3,051	)
Depreciation, depletion and amortization expense		(1,251	)		(1,017	)
Segment loss	$	(2,305	)	$	(501	)
Atlas Pipeline(1)
Revenues(3)	$	283,211		$	164,094
Revenues – affiliates		—			10,149
Costs and expenses		(222,386	)		(151,900	)
Depreciation and amortization expense		(22,746	)		(22,668	)
Segment income (loss)	$	38,079		$	(325	)

42

Reconciliation of segment income (loss) to net loss before income tax provision (benefit)
Segment income (loss)
Gas and oil production	$	26,368		$	33,647
Well construction and completion		11,081			16,971
Other partnership management		(2,305	)		(501	)
Atlas Pipeline		38,079			(325	)
Total segment income		73,223			49,792
General and administrative expenses(4)		(30,811	)		(27,896	)
Interest expense(4)		(44,599	)		(34,620	)
Net loss from continuing operations before income tax provision (benefit)	$	(2,187	)	$	(12,724	)
Capital expenditures
Gas and oil production	$	65,212		$	49,618
Well construction and completion		—			—
Other partnership management		4,632			7,427
Atlas Pipeline		10,914			72,196
Corporate and other		155			162
Total capital expenditures	$	80,913		$	129,403

	March 31, 2010		December 31, 2009
Balance sheet
Goodwill:
Gas and oil production	$	21,527	$	21,527
Well construction and completion		6,389		6,389
Other partnership management		7,250		7,250
Atlas Pipeline		—		—
	$	35,166	$	35,166
Total assets:
Gas and oil production	$	2,190,947	$	2,115,867
Well construction and completion		12,118		12,054
Other partnership management		48,035		44,311
Atlas Pipeline		2,085,093		2,135,860
Corporate and other		82,569		98,071
	$	4,418,762	$	4,406,163
(1)     Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 5). (2)     Includes revenues and expenses from well services, transportation and administration and oversight that do not meet the quantitative threshold for reporting segment information. (3)     Includes gains on mark-to-market derivatives of $4.1 million and $0.3 million for the three months ended March 31, 2010 and 2009, respectively. (4)     The Company notes that income taxes, interest expense and general and administrative expenses have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.

NOTE 19 – SUBSEQUENT EVENTS

Marcellus Shale Joint Venture. Effective April 20, 2010, the Company consummated a transaction whereby it entered into an undivided joint venture with Reliance Industries Limited (“Reliance”). Pursuant to the agreement, the Company sold Reliance a 40% undivided joint venture interest in approximately 300,000 net acres (approximately 120,000 to Reliance) of undeveloped core Marcellus Shale acreage held by the Company in exchange for $340.0 million of cash and $1,360.0 million in the form of a drilling carry. In addition to funding its own 40% interest of the drilling and completion costs, Reliance is required to fund 75% of the Company’s respective portion of drilling and completion costs until the $1,360.0 million drilling carry is fully utilized. The Company has five and a half years to utilize the drilling carry, subject to a two-year extension under certain conditions.

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Acquisition of additional Marcellus Shale Acreage. In April 2010, the Company and Reliance agreed, through a series of transactions subsequent to the completion of the undivided joint venture agreement, to purchase an additional 42,344 undeveloped core Marcellus Shale acreage for an average purchase price of $4,532 per acre. The acreage is contained within the joint venture’s area of mutual interest. Pursuant to the joint venture agreement with Reliance, the Company will contribute 60% of the cost associated with this acreage, while Reliance will contribute the remaining 40%. As a result of the transactions, the joint venture between the Company and Reliance will control approximately 343,000 Marcellus Shale acres.

Borrowing Base Redetermination. In April 2010, in conjunction with a regularly scheduled borrowing base redetermination, the borrowing base under ATN’s revolving credit facility of $550.0 million was approved.

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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, 2009. 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 corporation whose common units are listed on the NASDAQ Stock Market under the symbol “ATLS”. On September 29, 2009, we completed our merger with Atlas Energy Resources, LLC (“ATN”), our formerly publicly traded subsidiary and a Delaware limited liability company, pursuant to the definitive merger agreement previously executed between us and ATN, with ATN surviving as our wholly-owned subsidiary (the “Merger”).

We are an independent developer and producer of natural gas and oil, with operations in the Appalachian Basin, the Michigan Basin, and the Illinois Basin. Within these Basins, we believe we are one of the leading natural gas producers in four established shale plays: the Marcellus Shale of western Pennsylvania, the Antrim Shale of northern Michigan, the Chattanooga Shale of northeastern Tennessee and the New Albany Shale of west central Indiana. We specialize in development of these natural gas basins, because they provide repeatable, low-risk drilling opportunities. We are also a leading sponsor and manager of tax-advantaged direct investment natural gas and oil partnerships in the United States. Through March 31, 2010, we have funded the majority of our drilling of natural gas and oil wells on our acreage by sponsoring and managing tax advantaged investment partnerships (see “Subsequent Events”). We generally structure our investment partnerships so that, upon formation of a partnership, we co-invest in and contribute leasehold acreage to it, enter into drilling and well operating agreements with it and become its managing general partner.

The following is a summary of our key operating measures as of and for the three months ended March 31, 2010:

	Appalachia	Michigan/ Indiana	Total
Acreage:
Gross developed acreage – Marcellus Shale	146,333	—	146,333
Gross developed acreage – Other	154,359	331,671	486,030
Gross undeveloped acreage – Marcellus Shale	446,856	—	446,856
Gross undeveloped acreage – Other	166,230	259,788	426,018
Total gross acreage	913,778	591,459	1,505,237
Net developed acreage – Marcellus Shale	137,275	—	137,275
Net developed acreage – Other	128,653	259,088	387,741
Net undeveloped acreage – Marcellus Shale	436,953	—	436,953
Net undeveloped acreage – Other	173,765	145,276	319,041
Total net acreage	876,646	404,364	1,281,010
Net core Marcellus Shale acreage (included above)			269,479
Production per day (Mcfed)	45,239	54,719	99,958
Direct and indirect gross well working interests	9,329	2,561	11,890

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OTHER OWNERSHIP INTERESTS

In addition to our production operations, we also maintain ownership interests in the following entities at March 31, 2010:

• Atlas Pipeline Holdings, L.P. (“Atlas Pipeline Holdings” or “AHD”), our publicly-traded subsidiary (NYSE: AHD). At March 31, 2010, we had a 64.3% ownership interest in AHD and a 100% ownership interest in its general partner, through which we control AHD;

• Atlas Pipeline Partners, L.P. (“Atlas Pipeline Partners” or “APL”), our publicly-traded subsidiary which AHD controls through its 100% ownership of APL’s general partner. At March 31, 2010, we had a 2.1% direct ownership interest in APL and AHD had a 12.5% ownership interest in APL; and

• Lightfoot Capital Partners LP (“Lightfoot LP”) and Lightfoot Capital Partners GP LLC (“Lightfoot GP”), the general partner of Lightfoot (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. We have an approximate direct and indirect 18% ownership interest in Lightfoot GP. At March 31, 2010, we have satisfied our commitment to invest a total of $19.7 million in Lightfoot. We also have direct and indirect ownership interests in Lightfoot LP.

FINANCIAL PRESENTATION

Our consolidated financial statements contain our accounts and those of our subsidiaries, including ATN, AHD and APL. Due to the structure of our ownership interests in ATN, AHD and APL, in accordance with generally accepted accounting principles, we consolidate the financial statements of these subsidiaries into our financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in ATN prior to the Merger, AHD and APL are reflected as income (loss) attributable to non-controlling interests in our consolidated statements of operations and as a component of shareholders’ equity on our consolidated balance sheets. Throughout this section, when we refer to “our” consolidated financial statements, we are referring to the consolidated results for us and our wholly-owned subsidiaries and the consolidated results of AHD, including APL’s financial results, adjusted for non-controlling interests in ATN’s net income (loss) prior to the Merger on September 29, 2009 and AHD’s and APL’s net income (loss).

On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system (“NOARK”). As such, we have adjusted the prior year consolidated financial information presented to reflect the amounts related to the operations of the NOARK as discontinued operations.

SUBSEQUENT EVENTS

Marcellus Shale Joint Venture. Effective April 20, 2010, we consummated a transaction whereby we entered into an undivided joint venture with Reliance Industries Limited (“Reliance”). Pursuant to the agreement, we sold Reliance a 40% undivided joint venture interest in approximately 300,000 net acres (approximately 120,000 to Reliance) of undeveloped core Marcellus Shale acreage held by us in exchange for $340.0 million of cash and $1,360.0 million in the form of a drilling carry. In addition to funding its own 40% interest of the drilling and completion costs, Reliance is required to fund 75% of our respective portion of drilling and completion costs until the $1,360.0 million drilling carry is fully utilized. We have five and a half years to utilize the drilling carry, subject to a two-year extension under certain conditions.

Acquisition of additional Marcellus Shale Acreage. In April 2010, we and Reliance agreed, through a series of transactions subsequent to the completion of the undivided joint venture agreement, to purchase an additional 42,344 undeveloped core Marcellus Shale acreage for an average purchase price of $4,532 per acre. The acreage is contained within the joint venture’s area of mutual interest. Pursuant to the joint venture agreement with Reliance, we will contribute 60% of the cost associated with this acreage, while Reliance will contribute the remaining 40%. As a result of the transactions, the joint venture between us and Reliance will control approximately 343,000 core Marcellus Shale acres.

Borrowing Base Redetermination. In April 2010, in conjunction with a regularly scheduled borrowing base redetermination, the borrowing base under ATN’s revolving credit facility of $550.0 million was approved.

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RECENT DEVELOPMENTS

Monetization of Certain Derivative Positions. In January 2010, we received approximately $20.1 million in proceeds from the early settlement of natural gas and oil derivative positions for production periods from 2011 through 2013. In conjunction with the early termination of these derivatives, we 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 ATN’s revolving credit facility.

CONTRACTUAL REVENUE ARRANGEMENTS

Appalachia Natural Gas. We market the majority of our natural gas production in the Appalachian Basin to Hess Corporation, Colonial Energy, Inc., Atmos Energy, UGI Energy Services, Equitable Gas Co., EQT Energy, Sequent Energy and South Jersey Resources Group. The remainder of our natural gas production in the Appalachian Basin has been primarily supplied to gas marketers, local distribution companies, industrial or other end-users, and companies generating electricity. The sales price of natural gas produced in the Appalachian Basin has been primarily based upon the NYMEX spot market price.

Michigan/Indiana Natural Gas. In Michigan, we have natural gas sales agreements with DTE Energy Company (“DTE”) through December 31, 2012. DTE has the obligation to purchase all of the natural gas produced and delivered by us and our affiliates from specific projects at certain delivery points. The remainder of our natural gas production in Michigan and Indiana has been primarily supplied to gas marketers, local distribution companies, industrial or other end-users, and companies generating electricity. The sales price of natural gas produced in Michigan has been primarily based upon the NYMEX spot market price and Indiana has been primarily based upon the Texas Gas Zone SL and Chicago spot market prices.

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

Investment Partnerships. Through March 31, 2010, we generally have funded the majority of our drilling activities through sponsorship of tax-advantaged investment partnerships (see “Subsequent Events”). In addition to providing capital for our drilling activities, our investment partnerships are a source of fee-based revenues, which are not directly dependent on natural gas and oil prices. As managing general partner of the investment partnerships, we receive the following fees:

• Well construction and completion.For each well that is drilled by an investment partnership, we receive an 18% mark-up on those costs incurred to drill and complete the well. For our investment partnerships that were formed prior to November 2008, the mark-up was 15%;

• Administration and oversight.For each well drilled by an investment partnership, we receive a fixed fee of approximately $249,000 for horizontal Marcellus Shale wells and a range of $15,700 to $62,200 for all other well types. For our investment partnerships that were formed prior to April 2009, the fixed fee for wells ranged from $15,700 to $62,000, including horizontal Marcellus Shale wells. Additionally, the partnership pays us a monthly per well administrative fee of $75 for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well; and

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

GENERAL TRENDS AND OUTLOOK

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

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Natural Gas Supply and Outlook.While commodity prices for natural gas were at lower levels during the three months ended March 31, 2010 when compared with the prior year, we believe that the current development of the Marcellus Shale and new horizontal drilling techniques will likely cause relatively high levels of natural gas-related drilling in these geological areas as producers seek to increase their level of natural gas production. The areas in which we operate are experiencing a decline in the development of shallow wells, but a significant increase in drilling activity 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. While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas reserves.

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

RESULTS OF OPERATIONS

GAS AND OIL PRODUCTION

Production Profile. Currently, we have focused our natural gas production operations in various shale plays in the northeastern and Midwestern United States. Notably, we are one of the leading producers in the Marcellus Shale, a rich, organic shale located in the Appalachia basin. The portion of the Marcellus Shale in southwestern Pennsylvania in which we focus our drilling is high-pressured and generally contains dry, pipeline-quality natural gas. In addition, we also are a leading natural gas producer in Michigan through our activity in the Antrim Shale, a biogenic shale play with a long-lived and shallow decline profile. We have also established a position in the New Albany Shale in southwestern Indiana, where we produce out of the biogenic region of the shale similar to the Antrim Shale. We also produce from the Chattanooga Shale in northeastern Tennessee, which enables us to access other formations in that region such as the Monteagle and Ft. Payne Limestone.

Production Volumes. The following table presents our total net gas and oil production volumes and production per day during the three months ended March 31, 2010 and 2009:

	Three Months Ended March 31,
	2010		2009
Production:(1)(2)
Appalachia:(3)
Natural gas (MMcf)	3,603		3,592
Oil (000’s Bbls)	78	(4)	35
Total (MMcfe)	4,072		3,804
Michigan/Indiana:
Natural gas (MMcf)	4,906		5,242
Oil (000’s Bbls)	3	(4)	1
Total (MMcfe)	4,925		5,246
Total:
Natural gas (MMcf)	8,509		8,834
Oil (000’s Bbls)	81	(4)	36
Total (MMcfe)	8,996		9,050
Production per day: (1)(2)
Appalachia:(3)
Natural gas (Mcfd)	40,029		39,908
Oil (Bpd)	868	(4)	393
Total (Mcfed)	45,239		42,267
Michigan/Indiana:
Natural gas (Mcfd)	54,516		58,250
Oil (Bpd)	34	(4)	6
Total (Mcfed)	54,719		58,289
Total:
Natural gas (Mcfd)	94,545		98,158
Oil (bpd)	902	(4)	400
Total (Mcfed)	99,958		100,556

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

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

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

⁽⁴⁾       Includes NGL production volume for the three months ended March 31, 2010.

Production Revenues, Prices and Costs. Our production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised 99% of our proved reserves on an energy equivalent basis at December 31, 2009. The following table presents our production revenues and average sales prices for our natural gas and oil production for the three months ended March 31, 2010 and 2009, along with our average production costs, taxes, and transmission and compression costs in each of the reported periods:

	Three Months Ended March 31,
	2010			2009
Production revenues (in thousands):
Appalachia:(1)
Natural gas revenue	$	22,423		$	27,544
Oil revenue		4,270	(6)		2,050
Total revenues	$	26,693		$	29,594
Michigan/Indiana:
Natural gas revenue	$	37,119		$	42,330
Oil revenue		97	(6)		19
Total revenues	$	37,216		$	42,349
Total:
Natural gas revenue	$	59,542		$	69,874
Oil revenue		4,367	(6)		2,069
Total revenues	$	63,909		$	71,943
Average sales price:(2)
Natural gas (per Mcf):
Total realized price, after hedge(3) (4)	$	7.61		$	8.09
Total realized price, before hedge(3) (4)	$	5.68		$	5.21
Oil (per Bbl):
Total realized price, after hedge	$	71.99		$	57.56
Total realized price, before hedge	$	67.58		$	30.01
Production costs (per Mcfe):(2)
Appalachia:(1)
Lease operating expenses(5)	$	0.99		$	1.04
Production taxes		0.04			0.04
Transportation and compression		0.76			0.87
	$	1.80		$	1.95
Michigan/Indiana:
Lease operating expenses	$	0.77		$	0.81
Production taxes		0.33			0.30
Transportation and compression		0.24			0.26
	$	1.34		$	1.37
Total:
Lease operating expenses(5)	$	0.87		$	0.91
Production taxes		0.20			0.19
Transportation and compression		0.48			0.51
	$	1.55		$	1.61

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

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

⁽³⁾       Excludes the impact of certain allocations of production revenue to investor partners within our investment partnerships for the three months ended March 31, 2010. Including the effect of these allocations, the average realized gas sales price for the three months ended March 31, 2010 was $7.03 per Mcf ($5.10 per Mcf before the effects of financial hedging). There were no such allocations of production revenue for the three months ended March 31, 2009.

⁽⁴⁾       Includes cash proceeds of $0.3 million and $1.6 million for the three months ended March 31, 2010 and 2009, respectively, received from the settlement of ineffective derivative gains but were not reflected in the consolidated statement of operations for the respective periods.

⁽⁵⁾       Excludes the effects of our proportionate share of lease operating expenses associated with certain allocations of production revenue to investor partners within our investment partnerships for the three months ended March 31, 2010. Including the effects of these costs, lease operating expenses per Mcfe for the three months ended March 31, 2010 for Appalachia were $0.59 per Mcfe (total production costs per Mcfe were $1.40) and in total they were $0.69 per Mcfe (total production costs per Mcfe were $1.37). There were no such allocations of production revenue and therefore no affect on lease operating expenses for the three months ended March 31, 2009.

⁽⁶⁾       Includes NGL production revenue for the three months ended March 31, 2010.

Total natural gas revenues were $59.5 million for the three months ended March 31, 2010, a decrease of $10.4 million from $69.9 million for the three months ended March 31, 2009. This decrease consisted of a $2.5 million decrease attributable to lower natural gas production volumes, a $3.0 million decrease attributable to lower realized natural gas prices and $4.9 million of gas revenues subordinated to the investor partners within our investment partnerships during the three months ended March 31, 2010. Total oil revenues were $4.4 million for the three months ended March 31, 2010, an increase of $2.3 million from $2.1 million for the comparable prior year period. This increase resulted primarily from a $1.6 million increase in revenue from the sale of natural gas liquids, a $0.2 million increase associated with higher average realized oil prices and a $0.5 million increase associated with higher production volumes.

Appalachia production costs were $5.7 million for the three months ended March 31, 2010, an increase of $1.6 million from $4.1 million for the three months ended March 31, 2009. This increase was principally due to a $3.3 million decrease in the elimination of intercompany transportation costs subsequent to the formation of the Laurel Mountain joint venture. Prior to the formation of Laurel Mountain, the transportation costs included within Appalachia production costs were eliminated within our consolidated financial statements against APL’s corresponding transportation revenue for performing such transportation services. Subsequent to the formation of Laurel Mountain, APL no longer recognizes transportation revenue for these transportation services, but rather recognizes its equity in the net income of Laurel Mountain. This amount was partially offset by a $1.6 million decrease associated with our proportionate share of lease operating expenses associated with our revenue that was subordinated to the investor partners within our investment partnerships. Michigan/Indiana production costs were $6.6 million for the three months ended March 31, 2010, a decrease of $0.6 million from $7.2 million for the comparable prior year period. This decrease was primarily attributable to a $0.3 million decrease in compression station expenses and a $0.2 million decrease in transportation costs attributable to production.

PARTNERSHIP MANAGEMENT

Well Construction and Completion

Drilling Program Results. The number of wells we drill will vary depending on the amount of money we raise through our investment partnerships, the cost of each well, the depth or type of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. The following table presents the number of gross and net development wells we drilled for us and our investment partnerships during the three months ended March 31, 2010 and 2009. We did not drill any exploratory wells during the three months ended March 31, 2010 and 2009:

	Three Months Ended March 31,
	2010	2009
Gross wells drilled:
Appalachia	15	79
Michigan/Indiana	—	26
Total	15	105
Net wells drilled:
Appalachia	12	67
Michigan/Indiana	—	23
Total	12	90
Our share of net wells drilled(1):
Appalachia	5	24
Michigan/Indiana	—	6
Total	5	30
(1)       Includes (i) our percentage interest in wells in which we have a direct ownership interest and (ii) our percentage interest in the wells based on our percentage interest in our investment partnerships.

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

	Three Months Ended March 31,
	2010			2009
Average construction and completion per well:
Revenue	$	2,137		$	1,050
Costs		(1,811	)		(892	)
Gross profit	$	326		$	158
Gross profit margin	$	11,081		$	16,971
Net wells drilled within investment partnerships:(1)
Marcellus Shale		20			24
Chattanooga Shale		6			5
Michigan/Indiana		8			24
Other - shallow		—			54
		34			107
(1)       Includes wells drilled for which revenue is recognized on a percentage of completion basis.

Well construction and completion segment margin was $11.1 million for the three months ended March 31, 2010, a decrease of $5.9 million from $17.0 million for the three months ended March 31, 2009. This decrease was due primarily to a $23.8 million decrease associated with a decline in the number of wells drilled within the investment partnerships, partially offset by an $17.9 million increase due to increased gross profit per well. Since our drilling contracts with the investment partnerships are on a “cost-plus” basis (typically cost-plus 18%), an increase in our average cost per well also results in a proportionate increase in our average revenue per well, which directly affects the number of wells we drill. Average cost and revenue per well have increased due to a shift from drilling less expensive shallow wells to more expensive deep or horizontal shale wells in both Appalachia and Michigan/Indiana during the three months ended March 31, 2010 in comparison to the comparable prior year period.

Our consolidated balance sheet at March 31, 2010 includes $49.5 million of “liabilities associated with drilling contracts” for funds raised by our investment partnerships that have not been applied to the completion of wells due to the timing of drilling operations, and thus had not been recognized as well construction and completion revenue on our consolidated statements of operations. We expect to recognize this amount as revenue during the second quarter of 2010.

Administration and Oversight

Administration and oversight fee revenues represents supervision and administrative fees earned for the drilling and subsequent ongoing management of wells for our investment partnerships. Administration and oversight fee revenues were $2.0 million for the three months ended March 31, 2010, a decrease of $1.9 million from $3.9 million for the three months ended March 31, 2009. This decrease was primarily due to fewer wells drilled during the current year period in comparison to the prior year comparable period, partially offset by an increase in the number of Marcellus Shale horizontal wells drilled, for which we earn higher fees for our partnership management activities in comparison to conventional wells.

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Well Services

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

Well services revenues were $5.3 million for the three months ended March 31, 2010, an increase of $0.2 million from $5.1 million for the three months ended March 31, 2009. Well services expenses were $2.6 million for three months ended March 31, 2010, an increase of $0.2 million from $2.4 million for the three months ended March 31, 2009. These increases were primarily attributable to an increase in the number of producing wells.

Transmission, Gathering and Processing

Transmission, gathering and processing revenue includes gathering fees we charge to our investment partnership wells that are connected to Laurel Mountain’s Appalachian gathering systems and the operating revenues and expenses of APL. On May 31, 2009, APL contributed its Appalachian gathering systems to Laurel Mountain, a joint venture in which APL retained a 49% ownership interest. Under new gas gathering agreements with Laurel Mountain entered into upon formation of the joint venture, we are obligated to pay to Laurel Mountain all of the gathering fees we collect from the investment partnerships. During the period from January 1, 2009 to June 1, 2009, we were required to remit these gathering fees to APL, which were eliminated when we consolidated APL’s financial statements.

The gathering fees charged to our investment partnership wells generally range from $0.35 per Mcf to the amount of the competitive gathering fee, currently defined as 13% of the gross sales price of the natural gas. Pursuant to our new agreements with Laurel Mountain, we must also pay an additional amount equal to the excess of the gathering fees collected from the investment partnerships up to an amount equal to approximately 16% of the natural gas sales price. As a result of our agreements with Laurel Mountain, our Appalachian gathering expenses within our partnership management segment will generally exceed the revenues collected from the investment partnerships by approximately 3%. We recognize a proportionate share of gathering fees paid to Laurel Mountain based on our percentage interest in the investment partnership wells, which is included in gas and oil production expense. The net effect of the elimination amounts is eliminated against our pro-rata portion of production costs from our investment partnerships in our consolidated statements of operations.

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

	Three Months Ended March 31,
Transmission, Gathering and Processing:	2010			2009(1)
Atlas Energy:
Revenue	$	4,461		$	4,723
Expense		(7,671	)		(7,480	)
Gross Margin	$	(3,210	)	$	(2,757	)
Atlas Pipeline:
Revenue	$	275,205		$	169,093
Expense		(222,386	)		(151,900	)
Gross Margin	$	52,819		$	17,193
Eliminations:
Revenue	$	—		$	(10,149	)
Expense		—			6,853
Gross Margin	$	—		$	(3,296	)
Total:
Revenue	$	279,666		$	163,667
Expense		(230,057	)		(152,527	)
Gross Margin	$	49,609		$	11,140
(1)     Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system.

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Our net gathering fee expense for the three months ended March 31, 2010 was $3.2 million compared with $2.8 million for the three months ended March 31, 2009. This increase was principally due a decrease in fees received from the investment partnership due to lower investment partnership volumes, a decrease in natural gas prices and an increase in our equity natural gas volumes due to an increase in the number of wells drilled for our own account.

Transmission, gathering and processing margin for APL was $52.8 million for the three months ended March 31, 2010 compared with $17.2 million for the three months ended March 31, 2009. This increase was due principally to higher average natural gas liquids and crude oil commodity prices between periods.

Loss on Asset Sales

Loss on asset sales of $3.0 million for the three months ended March 31, 2010 principally represents the loss recognized on our sale of a processing plant outside of our core operating area.

Gain on Mark-to-Market Derivatives

Gain on mark-to-market derivatives was $4.1 million for the three months ended March 31, 2010 compared with $0.3 million for the three months ended March 31, 2009. This favorable movement was due primarily to a $53.4 million favorable movement in APL’s non-cash mark-to market adjustments on derivatives and a $10.0 million favorable movement in non-cash derivative gains related to the early termination of a portion of its derivative contracts, partially offset by an unfavorable movement of $40.3 million related to cash settlements on APL’s non-qualified derivatives and a $19.2 million unfavorable variance due to early cash settlements.

OTHER COSTS AND EXPENSES

General and Administrative

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

	Three Months Ended March 31,
	2010		2009(1)
General and Administrative expenses:
Atlas Energy	$	20,227	$	17,754
Atlas Pipeline and Atlas Pipeline Holdings		10,584		10,142
Total	$	30,811	$	27,896
(1)     Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system.

Total general and administrative expenses, including amounts reimbursed to affiliates, increased to $30.8 million for the three months ended March 31, 2010 compared with $27.9 million for the three months ended March 31, 2009. This $2.9 million increase was due to our $2.5 million increase and a $0.4 million increase related to APL and AHD. The $2.5 million increase was principally attributable to a $1.9 million increase in expenses related to wages and other corporate activities due to the growth of our business and a $0.6 million increase in non-cash stock compensation expense. The $0.4 million increase for APL and AHD was due principally to a $1.1 million increase in expenses related to its respective long-term incentive plans, partially offset by a $0.7 million decrease in other expenses, principally professional fees and other outside services.

Depreciation, Depletion and Amortization

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

	Three Months Ended March 31,
	2010		2009(1)
Depreciation, depletion and amortization:
Atlas Energy	$	26,508	$	28,027
Atlas Pipeline and Atlas Pipeline Holdings		22,746		22,668
Total	$	49,254	$	50,695
(1)     Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system.

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Total depreciation, depletion and amortization decreased to $49.3 million for the three months ended March 31, 2010 compared with $50.7 million for the comparable prior year period, due primarily to a $1.8 million decrease in our depletion expense, partially offset by additional depreciation recorded as a result of APL’s expansion capital expenditures incurred subsequent to March 31, 2009.

The following table presents our depletion expense, excluding amounts attributable to APL and AHD, per Mcfe for our Appalachia and Michigan/Indiana regions for of the respective periods:

	Three Months Ended March 31,
	2010			2009
Depletion expense (in thousands):
Appalachia	$	10,509		$	13,102
Michigan/Indiana		14,748			13,908
Total	$	25,257		$	27,010
Depletion expense as a percentage of gas and oil production revenue		40	%		38	%
Depletion per Mcfe:
Appalachia	$	2.58		$	3.44
Michigan/Indiana	$	2.99		$	2.65
Total	$	2.81		$	2.98

Depletion expense varies from period to period and is directly affected by changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties. Decreases in our depletable basis, primarily due to the $156.4 million write-down of our Upper Devonian field during the three months ended December 31, 2009, and fluctuations in our production volumes by region caused depletion expense to decrease $1.7 million to $25.3 million for the three months ended March 31, 2010 compared with $27.0 million for the three months ended March 31, 2009. Our depletion expense of oil and gas properties as a percentage of oil and gas revenues was 40% for the three months ended March 31, 2010, compared with 38% for the three months ended March 31, 2009. Depletion expense per Mcfe was $2.81 for the three months ended March 31, 2010, a decrease of $0.17 per Mcfe from $2.98 for the three months ended March 31, 2009.

Interest Expense

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

	Three Months Ended March 31,
	2010			2009(1)
Interest Expense:
Atlas Energy	$	18,032		$	12,984
Atlas Pipeline and Atlas Pipeline Holdings		27,049			21,665
Eliminations		(482	)		(29	)
Total	$	44,599		$	34,620
(1)     Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system.

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Total interest expense increased to $44.6 million for the three months ended March 31, 2010 as compared with $34.6 million for the three months ended March 31, 2009. This $10.0 million increase was primarily due to our $5.1 million increase and a $5.4 million increase related to APL and AHD, partially offset by a $0.5 million elimination of intercompany interest related to AHD’s promissory note. Our $5.1 million increase was principally attributable to a $6.2 million increase associated with ATN’s issuance of $200.0 million of 12.125% senior unsecured notes in July 2009, partially offset by a $1.0 million decrease associated with borrowings under ATN’s credit facility. The $1.0 million decrease associated with ATN’s credit facility was primarily due to the repayment of amounts the net proceeds from the issuance of the senior notes and lower average interest rates. The $5.4 million increase in interest expense for APL and AHD was due principally to a $2.9 million increase associated with higher borrowings under APL’s credit facility, an $1.5 million increase associated with APL’s term loan, and a $1.2 million decrease in capitalized interest associated with a reduction in APL’s capital expenditures.

Income Taxes

Income tax benefit related to net income (loss) from continuing operations attributable to common shareholders for the three months ended March 31, 2010 was $1.4 million as compared with income tax expense of $2.6 million for the three months ended March 31, 2009. Our effective income tax rate related to net income (loss) from continuing operations attributable to common shareholders was 40% and 39% for the three months ended March 31, 2010 and 2009, respectively. Our effective tax rate fluctuates as a result of the impact of state income taxes and permanent differences between our accounting for certain revenue or expense items and their corresponding treatment for income tax purposes. We expect our effective income tax rate to be 40% for the year ended December 31, 2010.

Income from Discontinued Operations

Income from discontinued operations, net of income taxes, which consists of amounts associated with APL’s NOARK gas gathering and interstate pipeline system that was sold in May 2009, was $8.5 million for the three months ended March 31, 2009, net of related taxes of $0.4 million.

Income (Loss) Attributable to Non-Controlling Interests

Income (loss) attributable to non-controlling interests was a loss of $1.3 million for the three months ended March 31, 2010 compared with a benefit of $11.5 million for the comparable prior year period. Income (loss) attributable to non-controlling interests includes an allocation of APL’s and AHD’s net income (loss) to non-controlling interest holders, as well as an allocation of ATN’s net income prior to the Merger on September 29, 2009 to its non-controlling interest holders. This change was primarily due to an increase in ATN’s and APL’s net earnings between periods.

LIQUIDITY AND CAPITAL RESOURCES

General

Our primary sources of liquidity are cash generated from operations, capital raised through investment partnerships and borrowings under ATN’s credit facility. Our primary cash requirements, in addition to normal operating expenses, are for debt service and capital expenditures. In general, we expect to fund:

• capital expenditures and working capital deficits through the retention of cash, 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 shares.

Recent instability in the financial markets, as a result of recession or otherwise, has increased the cost of capital while the availability of funds has diminished significantly. This may affect our ability to raise capital and reduce the amount of cash available to fund our operations. We rely on cash flow from operations and ATN’s credit facility to execute our growth strategy and to meet our financial commitments and other short-term liquidity needs. We cannot be certain that additional capital will be available to us to the extent required and on acceptable terms. We believe that we will have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve month period. However, we are subject to business, operational and other risks that could adversely affect our cash flow. We may supplement our cash generation with proceeds from financing activities, including borrowings under ATN’s credit facility and other borrowings, the issuance of additional common shares, the sale of assets and other transactions.

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ATN Revolving Credit Facility

At March 31, 2010, ATN had a credit facility with a syndicate of banks that matures in June 2012. The borrowing base is redetermined semiannually on April 1 and October 1 subject to changes in oil and gas reserves and is automatically reduced by 25% of the stated principal of any senior unsecured notes issued by ATN. In April 2010, in conjunction with a regularly scheduled borrowing base redetermination, the borrowing base under ATN’s revolving credit facility of $550.0 million was approved. Up to $50.0 million of the credit facility may be in the form of standby letters of credit, of which $1.6 million was outstanding at March 31, 2010. The facility is secured by substantially all of ATN’s assets and is guaranteed by each of its subsidiaries. The facility allows ATN to distribute to us (a) amounts equal to our income tax liability attributable to ATN’s net income at the highest marginal rate and (b) up to $40.0 million per year and, to the extent that it distributes less than that amount in any year, it may carry over up to $20.0 million for use in the next year.

The events which constitute an event of default for ATN’s credit facility are customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against ATN in excess of a specified amount and a change of control. In addition, the agreement limits sales, leases or transfers of assets and the incurrence of additional indebtedness. ATN is in compliance with these covenants as of March 31, 2010. The credit facility also requires ATN to maintain a ratio of current assets (as defined in the credit facility) to current liabilities (as defined in the credit facility) of not less than 1.0 to 1.0, and a ratio of total debt (as defined in the credit facility) to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”, as defined in the credit facility) of less than or equal to 3.5 to 1.0 effective January 1, 2010. Based on the definitions contained in ATN’s credit facility, its ratio of current assets to current liabilities was 1.8 to 1.0 and its ratio of total debt to EBITDA was 3.0 to 1.0 at March 31, 2010.

Cash Flows – Three Months Ended March 31, 2010 Compared to the Three Months Ended March 31, 2009

Net cash provided by operating activities of $38.2 million for the three months ended March 31, 2010 represented a favorable movement of $12.5 million from net cash provided by operating activities of $25.7 million for the comparable prior year period. The increase was derived principally from a $34.6 million favorable movement in distributions paid to non-controlling interest holders and a $16.7 million favorable movement in working capital changes, partially offset by a $15.2 million decrease in net income excluding non-cash items, an $11.6 million unfavorable movement in deferred taxes and a $12.0 million unfavorable movement in cash provided by discontinued operations. The non-cash charges which impacted net income include an unfavorable movement in non-cash loss on derivatives of $37.2 million, partially offset by a $3.0 million loss an asset sales and a $2.7 million increase in non-cash compensation expense. The movement in non-cash derivative losses resulted from decreases in commodity prices during the three months ended March 31, 2010 and their favorable impact on the fair value of derivative contracts we and APL have for future periods. The movement in cash distributions to non-controlling interest holders is due mainly to decreases in the cash distributions of our consolidated subsidiaries, including ATN prior to the Merger. The movement in working capital was principally due to a $46.5 million favorable movement in accounts receivable and other current assets, partially offset by a $31.3 million unfavorable movement in accounts payable.

Net cash used in investing activities of $87.3 million for the three months ended March 31, 2010 represented a favorable movement of $42.7 million from $130.0 million of net cash used in investing activities for the comparable prior year period. This favorable movement was principally due to a $48.5 million decrease in our and APL’s capital expenditures, partially offset by a $6.3 million unfavorable movement in investments in unconsolidated subsidiaries, including our investment in Lightfoot.

Net cash provided by financing activities of $42.1 million for the three months ended March 31, 2010 represented an unfavorable movement of $45.1 million from $87.2 million for the comparable prior year period. This unfavorable movement was principally due to a $58.0 million reduction in subsidiary borrowings under their respective credit facilities, partially offset by a $15.3 million favorable movement resulting from the issuance of additional common units by APL.

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Capital Requirements

Our capital requirements consist primarily of capital expenditures we make to expand our capital asset base for longer than the short-term, which includes new leasehold interests and the development and exploitation of existing leasehold interests through acquisitions and investments in our drilling partnerships. The following table presents our capital expenditures and those attributable to APL for the periods presented (in thousands):

	Three Months Ended March 31,
	2010		2009(1)
Atlas Energy	$	69,999	$	57,207
Atlas Pipeline		10,914		72,196
Total	$	80,913	$	129,403
(1)       Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system.

During the three months ended March 31, 2010, our capital expenditures related primarily to $20.3 million for wells drilled exclusively for our own account, an increase of $8.6 million when compared with the comparable prior year period, $22.6 million incurred for leasehold acquisition costs, an increase of $12.5 million when compared with the comparable prior year period, and $17.7 million of investments in our investment partnerships, a decrease of $10.1 million when compared with the comparable prior year period.

Through March 31, 2010, the level of capital expenditures we have devoted to our exploration and production operations depended upon any acquisitions made and the level of funds raised through our investment partnerships (see “Subsequent Events”). We believe cash flows from operations and amounts available under ATN’s credit facility will be adequate to fund our capital expenditures. However, the amount of funds we raise and the level of our capital expenditures will vary in the future depending on market conditions for natural gas and other factors. We expect to fund our capital expenditures with cash flow from our operations, borrowings under ATN’s credit facility, and with the temporary use of funds raised in our investment partnerships in the period before we invest the funds. We may also consider other transactions, which may supplement our cash generation activities and provide liquidity to fund capital expenditures.

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

Atlas Pipeline Partners. APL’s capital expenditures decreased to $10.9 million for the three months ended March 31, 2010, compared with $72.2 million for the comparable prior year period. The decrease was due principally to costs incurred in the prior year related to APL’s construction of the Madill to Velma pipeline and its Nine Mile gas plant and compressor upgrades.

As of March 31, 2010, APL is committed to expend approximately $47.1 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

OFF BALANCE SHEET ARRANGEMENTS

As of March 31, 2010, our off balance sheet arrangements are limited to our guarantee of Crown Drilling of Pennsylvania, LLC’s $10.7 million credit agreement, ATN’s and APL’s letters of credit outstanding of $1.6 million and $9.8 million, respectively, our estimated capital contribution for drilling and completion expenditures related to Atlas Resources Public #18-2008 Program of approximately $10.8 million, and APL’s commitments to expend approximately $47.1 million on capital projects.

DIVIDENDS

We paid cash dividends of $2.0 million for the three months ended March 31, 2009. No dividends were paid for the three months ended March 31, 2010. The determination of the amount of future cash dividends, if any, is at the sole discretion of our board of directors and will depend on the various factors affecting our financial condition and other matters the board of directors deems relevant.

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ISSUANCE OF SUBSIDIARY COMMON UNITS

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

Atlas Pipeline Partners and Atlas Pipeline Holdings

On January 7, 2010, APL executed amendments to warrants to purchase 2,689,765 of its common units. The warrants were originally issued along with its common units in connection with a private placement to institutional investors that closed on August 20, 2009. The amendments to the warrants provided that, for the period January 8 through January 12, 2010, the warrant exercise price was lowered to $6.00 from $6.35 per unit. In connection with the amendments, the holders of the warrants agreed to exercise all of the warrants for cash, which resulted in net cash proceeds of approximately $15.3 million. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan and credit facility.

In August 2009, APL sold 2,689,765 common units in a private placement at an offering price of $6.35 per unit, yielding net proceeds of approximately $16.1 million. APL also received a capital contribution from AHD of $0.4 million for AHD to maintain its-then 2.0% general partner interest in APL. In addition, APL issued warrants granting investors in our private placement the right to purchase an additional 2,689,765 common units at a price of $6.35 per unit for a period of two years following the issuance of the original common units. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan. The common units and warrants sold by APL were registered with the Securities and Exchange Commission and the registration statement was declared effective on October 14, 2009.

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, deferred tax assets and liabilities, 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 financial statements is included within our Audit Report on Form 10-K for the year ended December 31, 2009 and in Note 2 under Item 1, “Financial Statements” included in this report, and there have been no material changes to these policies through March 31, 2010.

Fair Value of Financial Instruments

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

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

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

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

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We use a fair value methodology to value the assets and liabilities for our, AHD’s and APL’s outstanding derivative contracts and our Supplemental Employment Retirement Plan (“SERP”). Our and APL’s commodity hedges, with the exception of APL’s NGL fixed price swaps and NGL options, are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. Our, AHD’s and APL’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model and are therefore defined as Level 2 fair value measurements. Our SERP is calculated based on observable actuarial inputs developed by a third-party actuary and therefore is defined as a Level 2 fair value measurement, while the asset related to the funding of the SERP in a rabbi trust is based on publicly traded equity and debt securities and is therefore defined as a Level 1 fair value measurement. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of natural gas, crude oil and propane prices and therefore are defined as Level 3 fair value measurements. Valuations for APL’s NGL options are based on forward price curves developed by the related financial institution and therefore are defined as Level 3 fair value measurements.

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

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 potential exposure to market risks. As our assets currently consist principally of our ownership interests in our subsidiaries, the following information principally encompasses their exposure to market risks unless otherwise noted. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and oil and natural gas prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of the market risk sensitive instruments were entered into for purposes other than trading.

General

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

We and our subsidiaries are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We and our subsidiaries manage these risks through regular operating and financing activities and periodical use of derivative financial instruments such as forward contracts and interest rate cap and swap agreements. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on March 31, 2010. 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 commodity and interest-rate derivative contracts are banking institutions, who also participate in their revolving credit facilities. The creditworthiness of our counterparties is constantly monitored, and we currently believe them to be financially viable. We are not aware of any inability on the part of our counterparties to perform under their contracts and believe our exposure to non-performance is remote.

Interest Rate Risk.At March 31, 2010, ATN had an outstanding balance of $265.0 million on its senior secured revolving credit facility with a borrowing base of $575.0 million. At March 31, 2010, we had interest rate derivative contracts having aggregate notional principal amounts of $150.0 million. Under the terms of this agreement, we will pay weighted average interest rates of 3.1% plus the applicable margin as defined under the terms of ATN’s revolving credit facility, and will receive LIBOR plus the applicable margin on the notional principal amounts. These derivatives effectively convert $150.0 million of ATN’s floating rate debt under its revolving credit facility to fixed rate debt. The interest rate swap agreement is effective as of March 31, 2010 and expires on January 31, 2011.

At March 31, 2010, AHD had a credit facility with $4.0 million outstanding. AHD also had an interest rate derivative contract having an aggregate notional principal amount of $25.0 million, which expires on May 28, 2010. Under the terms of agreement, AHD pays an interest rate of 3.0%, plus the applicable margin as defined under the terms of its credit facility, and receives LIBOR, plus the applicable margin, on the notional principal amounts.

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At March 31, 2010, APL had $280.0 million of outstanding borrowings under its $380.0 million senior secured revolving credit facility and $425.8 million outstanding under its senior secured term loan. Borrowings under APL’s credit facility bear interest, at its option, at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). On May 29, 2009, APL entered into an amendment to its senior secured credit facility agreement, which, among other changes, set a floor for the LIBOR interest rate of 2.0% per annum. At March 31, 2010, APL had contracts having an aggregate notional principal amount of $250.0 million. Under the terms of these agreements, APL pays weighted average interest rates of 3.1%, plus the applicable margin as defined under the terms of its revolving credit facility, and receives LIBOR, plus the applicable margin, on the notional principal amount. These derivatives effectively convert $250.0 million of APL’s floating rate debt under its term loan and revolving credit facility to fixed-rate debt. These derivatives are in effect as of March 31, 2010 and expired on April 30, 2010.

Holding all other variables constant, including the effect of interest rate derivatives, a hypothetical 100 basis-point or 1% change in variable interest rates would change our consolidated interest expense by $0.9 million.

Commodity Price Risk. Our market risk exposure to commodities is due to the fluctuations in the price of natural gas, NGLs, condensate and oil and the impact those price movements have on the financial results of our subsidiaries. To limit our exposure to changing natural gas and oil prices, we use financial derivative instruments for a portion of our future natural gas and oil production. APL is exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. APL enters into financial swap and option instruments to hedge forecasted sales against the variability in expected future cash flows attributable to changes in market prices. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate are sold. Under these swap agreements, APL receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas, NGLs and condensate at a fixed price for the relevant period.

Holding all other variables constant, including the effect of commodity derivatives, a 10% change in the average price of natural gas, NGLs, condensate and oil would result in a change to our consolidated operating income from continuing operations, excluding income tax effects, for the twelve-month period ending March 31, 2011 of approximately $30.0 million.

Realized pricing of our oil and natural gas production is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for many years. To limit our exposure to changing natural gas prices, we enter into natural gas and oil swap and costless collar option contracts. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts have qualified and been designated as cash flow hedges and been recorded at their fair values.

At March 31, 2010, we had the following interest rate and commodity derivatives:

Interest Fixed Rate Swap

Term	Notional Amount		Option Type	Contract Period Ended December 31,
January 2008 – January 2011	$	150,000,000	Pay 3.1% — Receive LIBOR	2010
				2011

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Natural Gas Fixed Price Swaps

Production Period Ending December 31,	Volumes	Average Fixed Price
	(mmbtu)(1)	(per mmbtu) (1)
2010	30,750,003	$	7.354
2011	24,140,004	$	6.689
2012	19,652,260	$	6.850
2013	13,211,510	$	6.822

Natural Gas Costless Collars

Production Period Ending December 31,	Option Type	Volumes	Average Floor and  Cap
		(mmbtu)(1)	(per mmbtu) (1)
2010	Puts purchased	2,520,000	$	7.839
2010	Calls sold	2,520,000	$	9.007
2011	Puts purchased	12,840,000	$	6.197
2011	Calls sold	12,840,000	$	7.283
2012	Puts purchased	9,780,000	$	6.220
2012	Calls sold	9,780,000	$	7.309
2013	Puts purchased	11,820,000	$	6.228
2013	Calls sold	11,820,000	$	7.389

Crude Oil Fixed Price Swaps

Production Period Ending December 31,	Volumes	Average Fixed Price
	(Bbl) (1)	(per Bbl) (1)
2010	39,300	$	97.219
2011	42,600	$	77.460
2012	33,500	$	76.855
2013	10,000	$	77.360

Crude Oil Costless Collars

Production Period Ending December 31,	Option Type	Volumes	Average Floor and  Cap
		(Bbl) (1)	(per Bbl) (1)
2010	Puts purchased	25,000	$	85.000
2010	Calls sold	25,000	$	112.546
2011	Puts purchased	27,000	$	67.223
2011	Calls sold	27,000	$	89.436
2012	Puts purchased	21,500	$	65.506
2012	Calls sold	21,500	$	91.448
2013	Puts purchased	6,000	$	65.358
2013	Calls sold	6,000	$	93.442
(1)       “Mmbtu” represents million British Thermal Units; “Bbl” represents barrels.

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As of March 31, 2010, AHD had the following interest rate derivatives:

Interest Fixed-Rate Swap

Term	Notional Amount		Type	Contract Period Ended December 31,
May 2008 - May 2010	$	25,000,000	Pay 3.0% — Receive LIBOR	2010

As of March 31, 2010, APL had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swap

Term	Amount		Type
April 2008-April 2010	$	250,000,000	Pay 3.1% — Receive LIBOR

Fixed Price Swaps

Production Period	Purchased/ Sold	Commodity	Volumes(1)	Average Fixed Price
2010	Sold	Propane	17,640,000	$	1.108
2010	Sold	Natural Gas Basis	3,390,000		(0.659	)
2010	Purchased	Natural Gas Basis	5,580,000		(0.619	)
2011	Sold	Natural Gas Basis	1,920,000		(0.728	)
2011	Purchased	Natural Gas Basis	1,920,000		(0.758	)
2012	Sold	Natural Gas Basis	720,000		(0.685	)
2012	Purchased	Natural Gas Basis	720,000		(0.685	)

NGL Options

Production Period	Purchased/ Sold	Type	Commodity	Volumes(1)	Average Strike Price
2010	Purchased	Put	Propane	23,688,000	$	1.073
2010	Purchased	Put	Normal Butane	2,772,000		1.440
2010	Purchased	Call	Natural Gas	6,390,000		5.829

Crude Oil Options

Production Period	Purchased/ Sold	Type	Commodity	Volumes(1)	Average Strike Price
2010	Purchased	Put	Crude Oil	627,000	74.31
2010	Sold	Call	Crude Oil	1,961,250	83.83
2010	Purchased(2)	Call	Crude Oil	444,000	120.00
2011	Sold	Call	Crude Oil	678,000	94.68
2011	Purchased(2)	Call	Crude Oil	252,000	120.00
2012	Sold	Call	Crude Oil	498,000	95.83
2012	Purchased(2)	Call	Crude Oil	180,000	120.00

⁽¹⁾ Volumes for Natural Gas are stated in MMBTU’s. Volumes for NGLs are stated in gallons. Volumes for crude are stated in barrels.

⁽²⁾ Calls purchased for 2010 through 2012 represent offsetting positions for calls sold. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise.

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 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.

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Under the supervision of our Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2010, 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.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Following announcement of the Merger on April 27, 2009, five purported class actions were filed in Delaware Chancery Court and were later consolidated into a single complaint, Inre Atlas Energy Resources, LLC Unitholder Litigation, C.A. No. 4589-VCN (the “Consolidated Action”) filed on July 1, 2009 (the “Consolidated Complaint”). The Consolidated Complaint named us and ATN’s various officers and directors as defendants (the “Defendants”), alleged violations of fiduciary duties in connection with the Merger, and requested injunctive relief and damages.

On August 7, 2009, plaintiffs advised the Delaware Chancery Court by letter that they would not pursue their motion for a preliminary injunction, which had been scheduled for a hearing on September 4, 2009, and requested that the September 4 hearing date be removed from the Court’s calendar. On October 16, 2009, Defendants filed a motion to dismiss the Consolidated Complaint. On December 15, 2009, plaintiffs filed an Amended Complaint (the “Amended Complaint”). On January 6, 2010, the Delaware Chancery Court granted the parties’ Scheduling Stipulation and Order, providing that Defendants would have until February 18, 2010, to file a motion to dismiss the Amended Complaint; that plaintiffs’ answering brief in opposition would be due on or before May 3, 2010; and that Defendants’ reply papers would be due on or before June 4, 2010. Defendants filed their opening brief in support of their motion to dismiss on February 18, 2010 and plaintiffs filed their brief in opposition on May 3, 2010.

The Amended Complaint alleges that Defendants breached their purported fiduciary duties to ATN’s public unitholders in connection with the negotiation of the Merger. In particular, plaintiffs allege that the Merger was not entirely fair to ATN’s public unitholders, and that Defendants conducted the Merger process in bad faith.

Predicting the outcome of this lawsuit is difficult. An adverse judgment for monetary damages could have a material adverse effect on our operations. Based on the facts known to date, Defendants believe that the claims asserted against them in this lawsuit are without merit, and will continue to defend themselves vigorously against the claims.

In June 2008, our wholly-owned subsidiary, Atlas America, LLC, was named as a co-defendant in the matter captionedCNX Gas Company, LLC (“CNX”) v. Miller Petroleum, Inc. (“Miller”), et al. (Chancery Court, Campbell County, Tennessee). In its complaint, CNX alleges that Miller breached a contract to assign to CNX certain leasehold rights (“Leases”) representing approximately 30,000 acres in Campbell County, Tennessee and that Atlas America, LLC and another defendant, Wind City Oil & Gas, LLC, interfered with the closing of this assignment on June 6, 2008. ATN purchased the Leases from Miller for approximately $19.1 million. On December 15, 2008, the Chancery Court dismissed the matter in its entirety, holding that there had been no breach of the contract by Miller and, therefore, that Atlas America, LLC could not have tortuously interfered with the contract. The Chancery Court dismissed all claims against Atlas America, LLC; however, CNX has appealed this decision.

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

ITEM 1A. RISK FACTORS

Our business operations and financial position are subject to various risks. These are described elsewhere in this report and in our most recent Form 10-K for the year ended December 31, 2009. The risk factors identified therein have not changed in any material respect.

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ITEM 6. EXHIBITS

Exhibit No.	Description
2.1	Purchase and Sale Agreement, dated April 9, 2010, by and between Atlas Energy Resources, LLC and Reliance Marcellus, LLC. (26) Schedules and exhibits to the Agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company agrees to furnish a copy of any omitted schedule or similar attachment to the SEC upon request
2.2	Participation and Development Agreement, dated April 20, 2010, by and between Atlas Energy Resources, LLC, Atlas America, LLC, Viking Resources, LLC, Atlas Resources, LLC and Reliance Marcellus, LLC. (27) Schedules and exhibits to the Agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company agrees to furnish a copy of any omitted schedule or similar attachment to the SEC upon request
2.3	Standstill, AMI and Transfer Restriction Agreement, dated April 20, 2010, by and among Atlas Energy, Inc., Atlas Energy Resources, LLC, Reliance Industries Limited and Reliance Marcellus, LLC(27)
2.4	Agreement and Plan of Merger, dated as of April 27, 2009, by and among Atlas Energy Resources, LLC, Atlas America, Inc., Atlas Energy Management, Inc. and Merger Sub, as defined therein. (13) Schedules and exhibits to the Agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company agrees to furnish a copy of any omitted schedule or similar attachment to the SEC upon request
3.1	Amended and Restated Certificate of Incorporation(1)
3.2	Amended and Restated Bylaws(1)
4.1	Form of stock certificate(2)
10.1	Indenture dated as of January 23, 2008 among Atlas Energy Operating Company, LLC, Atlas Energy Finance Corp., as Issuers, the subsidiaries named therein, as Guarantors, and U.S. Bank National Association, as Trustee(14)
10.2	Form of 10.75% Senior Note due 2018 (included as an exhibit to the Indenture filed as Exhibit 10.1 hereto)
10.3	Senior Indenture dated July 16, 2009 among Atlas Energy Operating Company, LLC, Atlas Energy Finance Corp., as Issuers, the subsidiaries named therein, as Guarantors, and U.S. Bank National Association, as Trustee(15)
10.4	First Supplemental Indenture date July 16, 2009(15)
10.5	Form of Note 12.125% Senior Notes due 2017 (contained in Annex A to the First Supplemental Indenture filed as Exhibit 10.4 hereto)
10.6	Tax Matters Agreement between Atlas America, Inc. and Resource America, Inc. dated May 14, 2004(5)
10.7	Transition Services Agreement between Atlas America, Inc. and Resource America, Inc. dated May 14, 2004(5)
10.8(a)	Employment Agreement for Edward E. Cohen dated May 14, 2004(5)
10.8(b)	Amendment to Employment Agreement dated as of December 31, 2008(12)
10.9(a)	Agreement for Services among Atlas America, Inc. and Richard Weber, dated April 5, 2006(6)
10.9(b)	Amendment No. 1 to Agreement for Services dated as of April 26, 2007(7)
10.9(c)	Amendment No. 2 to Agreement for Services dated as of December 18, 2008(12)
10.10	Management Agreement, dated as of December 18, 2006, among Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC and Atlas Energy Management, Inc.  (4)

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Exhibit No.	Description
10.11	Stock Incentive Plan(12)
10.12	2009 Stock Incentive Plan(1)
10.13	Assumed Long-Term Incentive Plan(16)
10.14	Atlas America Employee Stock Ownership Plan(8)
10.15	Atlas America, Inc. Investment Savings Plan(8)
10.16	Form of Stock Award Agreement(9)
10.17	Amended and Restated Annual Incentive Plan for Senior Executives(10)
10.18	Employment Agreement between Atlas America, Inc. and Jonathan Z. Cohen dated as of January 30, 2009(12)
10.19(a)	Revolving Credit Agreement, dated as of June 29, 2007, among Atlas Energy Operating Company, LLC its subsidiaries, J.P. Morgan Chase Bank, N.A., as Administrative Agent and the other lenders signatory thereto(19)
10.19(b)	First Amendment to Credit Agreement, dated as of October 25, 2007(20)
10.19(c)	Second Amendment to Credit Agreement, dated as of April 9, 2009(21)
10.19(d)	Third Amendment to Credit Agreement, dated as of July 10, 2009(22)
10.20	ATN Option Agreement dated as of June 1, 2009, by and among APL Laurel Mountain, LLC, Atlas Pipeline Operating Partnership, L.P. and Atlas Energy Resources, LLC(23)
10.21	Amended and Restated Limited Liability Company Agreement of Laurel Mountain Midstream, LLC dated as of June 1, 2009(23)
10.22	Employment Agreement for Matthew A. Jones dated July 1, 2009(17)
10.23	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.(24) Specific terms in this exhibit have been redacted, as marked three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
10.24	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.(24) Specific terms in this exhibit have been redacted, as marked three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
10.25	From of Non-Qualified Stock Option Grant Agreement(25)
10.26	From of Incentive Stock Option Grant Agreement(25)
10.27	From of Restricted Stock Unit Agreement(25)
10.28	Securities Purchase Agreement dated April 7, 2009 by and between Atlas Pipeline Mid-Continent, LLC and Spectra Energy Partners OLP, LP(17)
31.1	Rule 13a-14(a)/15d-14(a) Certification.
31.2	Rule 13a-14(a)/15d-14(a) Certification.
32.1	Section 1350 Certification.
32.2	Section 1350 Certification.

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(1) Previously filed as an exhibit to our Form 8-K filed September 30, 2009

(2) Previously filed as an exhibit to our registration statement on Form S-1 (registration no. 333-112653)

(3) [Intentionally omitted]

(4) [Intentionally omitted]

(5) Previously filed as an exhibit to our Form 10-Q for the quarter ended June 30, 2004

(6) Previously filed as an exhibit to our Form 10-Q for the quarter ended June 30, 2006

(7) Previously filed as an exhibit to our Form 8-K filed May 1, 2007

(8) Previously filed as an exhibit to our Form 10-K for the year ended September 30, 2005

(9) Previously filed as an exhibit to our Form 10-Q for the quarter ended December 31, 2005

(10) Previously filed as an exhibit to our definitive proxy statement filed May 8, 2008

(11) [Intentionally omitted]

(12) Previously filed as an exhibit to our Form 10-K for the year ended December 31, 2008

(13) Previously filed as an exhibit to our Form 8-K filed April 27, 2009.

(14) Previously filed as an exhibit to Atlas Energy Resources, LLC’s Form 8-K filed January 24, 2008

(15) Previously filed as an exhibit to Atlas Energy Resources, LLC’s Form 8-K filed July 17, 2009

(16) Previously filed as an exhibit to our Form S-8 filed September 30, 2009

(17) Previously filed as an exhibit to our Form 10-Q for the quarter ended June 30, 2009

(18) [Intentionally omitted]

(19) Previously filed as an exhibit to Atlas Energy Resources, LLC’s Form 8-K filed June 29, 2007

(20) Previously filed as an exhibit to Atlas Energy Resources, LLC’s Form 8-K filed October 26, 2007

(21) Previously filed as an exhibit to Atlas Energy Resources, LLC’s Form 8-K filed April 17, 2009

(22) Previously filed as an exhibit to Atlas Energy Resources, LLC’s Form 8-K filed July 24, 2009

(23) Previously filed as an exhibit to our Form 8-K filed June 5, 2009

(24) Previously filed as an exhibit to Atlas Energy Resources, LLC’s Form 10-Q for the quarter ended June 30, 2009

(25) Previously filed as an exhibit to our Form 10-K for the year ended December 31, 2009

(26) Previously filed as an exhibit to our Form 8-K filed April 13, 2010

(27) Previously filed as an exhibit to our Form 8-K filed April 21, 2010

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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, INC.
Date:  May 7, 2010	By:	/s/ EDWARD E. COHEN
		Edward E. Cohen
		Chairman and Chief Executive Officer
Date:  May 7, 2010	By:	/s/ MATTHEW A. JONES
		Matthew A. Jones
		Chief Financial Officer
Date:  May 7, 2010	By:	/s/ SEAN P. MCGRATH
		Sean P. McGrath
		Chief Accounting Officer

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