ATLAS ENERGY, INC. - FORM 10-Q

ATLAS ENERGY, INC. - FORM 10-Q - August 5, 2010

Attached files

Attached files

ATLAS ENERGY, INC. Reports

file	filename
EX-31.1 - RULE 13A-14(A)/15(D)-14(A) CERTIFICATION - ATLAS ENERGY, INC.	dex311.htm
EX-32.2 - SECTION 1350 CERTIFICATION - ATLAS ENERGY, INC.	dex322.htm
EX-31.2 - RULE 13A-14(A)/15(D)-14(A) CERTIFICATION - ATLAS ENERGY, INC.	dex312.htm
EX-32.1 - SECTION 1350 CERTIFICATION - ATLAS ENERGY, INC.	dex321.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2010

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

For the transition period from to

Commission file number: 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 officer)		(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 (Check one):


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

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

The number of outstanding shares of the registrant’s common stock on August 4, 2010 was 78,403,313 shares.

ATLAS ENERGY, INC. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM 10-Q


		PAGE
PART I.	FINANCIAL INFORMATION	3

Item 1.	Financial Statements (Unaudited)	3

	Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009	3

	Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2010 and 2009	4

	Consolidated Statement of Shareholders’ Equity for the Six Months Ended June 30, 2010	5

	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009	6

	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	50

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	67

Item 4.	Controls and Procedures	71

PART II.	OTHER INFORMATION	71

Item 1.	Legal Proceedings	71

Item 1A.	Risk Factors	72

Item 6.	Exhibits	72

SIGNATURES		75

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)


	June 30, 2010			December 31, 2009
ASSETS
Current assets:
Cash and cash equivalents	$	91,904		$	20,627
Accounts receivable		160,437			172,848
Current portion of derivative asset		94,626			74,064
Subscriptions receivable from Partnerships		—			47,275
Prepaid expenses and other		31,590			31,010
Prepaid and deferred taxes		—			1,559

Total current assets		378,557			347,383

Property, plant and equipment, net		3,650,801			3,555,802
Intangible assets, net		157,831			170,964
Goodwill, net		35,166			35,166
Long-term derivative asset		111,441			59,291
Investment in Laurel Mountain joint venture		134,504			132,990
Other assets, net		84,958			74,833
Long-term portion of deferred tax asset		—			29,734

	$	4,553,258		$	4,406,163


LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:
Current portion of long-term debt	$	600		$	8,000
Accounts payable		114,492			99,748
Liabilities associated with drilling contracts		36,012			122,532
Accrued producer liabilities		60,201			66,211
Current portion of derivative payable to Partnerships		28,610			22,382
Current portion of derivative liability		5,125			38,485
Accrued interest		30,616			38,898
Accrued well drilling and completion costs		81,539			89,261
Current portion of deferred tax liability		23,554			26,415
Leasehold acquisition liability		41,949			—
Accrued liabilities		38,965			45,969
Advances from affiliate		63			173

Total current liabilities		461,726			558,074

Long-term debt, less current portion		1,898,019			2,040,572
Long-term derivative payable to Partnerships		40,362			22,380
Long-term derivative liability		44,546			25,441
Long-term portion of deferred tax liability		99,261			—
Other long-term liabilities		60,009			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		816			814
Additional paid-in capital		1,164,076			1,156,580
Treasury stock, at cost		(141,599	)		(142,848	)
Accumulated other comprehensive income		85,929			58,022
Retained earnings		224,495			50,744

		1,333,717			1,123,312
Non-controlling interests		615,618			580,204

Total shareholders’ equity		1,949,335			1,703,516

	$	4,553,258		$	4,406,163

See accompanying notes to consolidated financial statements

ATLAS ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Revenues:
Gas and oil production	$	69,188		$	69,979		$	133,097		$	141,922
Well construction and completion		43,295			63,367			115,937			175,735
Transmission, gathering and processing		251,417			186,103			531,083			349,770
Administration and oversight		1,865			2,642			3,912			6,495
Well services		5,743			4,806			11,055			9,899
Gain (loss) on mark-to-market derivatives		8,072			(18,593	)		12,205			(18,277	)
Other, net		3,860			1,964			8,117			6,845

Total revenues		383,440			310,268			815,406			672,389


Costs and expenses:
Gas and oil production		13,096			9,803			25,380			21,089
Well construction and completion		36,682			53,701			98,243			149,098
Transmission, gathering and processing		209,927			150,363			439,984			302,890
Well services		2,697			2,120			5,275			4,544
General and administrative		25,336			21,657			56,147			49,553
Depreciation, depletion and amortization		53,366			50,272			102,620			100,967

Total costs and expenses		341,104			287,916			727,649			628,141


Operating income		42,336			22,352			87,757			44,248

Gain on asset sales		288,643			105,691			285,634			105,691
Interest expense		(41,596	)		(41,948	)		(86,195	)		(76,568	)


Income from continuing operations before income tax provision		289,383			86,095			287,196			73,371
Income tax provision		113,229			3,677			111,821			6,271

Net income from continuing operations		176,154			82,418			175,375			67,100

Discontinued operations:
Gain on sale of discontinued operations (net of income tax provision of $2,228 for the three and six months ended June 30, 2009)		—			48,851			—			48,851
Income from discontinued operations (net of income tax provision of $99 and $498 for the three and six months ended June 30, 2009, respectively)		—			2,441			—			10,918


Net income		176,154			133,710			175,375			126,869
Income attributable to non-controlling interests		(302	)		(124,342	)		(1,624	)		(112,858	)

Net income attributable to common shareholders	$	175,852		$	9,368		$	173,751		$	14,011


Net income attributable to common shareholders per share – basic:
Income from continuing operations attributable to common shareholders	$	2.24		$	0.15		$	2.22		$	0.25
Income from discontinued operations attributable to common shareholders		—			0.09			—			0.11

Net income attributable to common shareholders	$	2.24		$	0.24		$	2.22		$	0.36


Net income attributable to common shareholders per share – diluted:
Income from continuing operations attributable to common shareholders	$	2.16		$	0.15		$	2.14		$	0.24
Income from discontinued operations attributable to common shareholders		—			0.09			—			0.11

Net income attributable to common shareholders	$	2.16		$	0.24		$	2.14		$	0.35


Weighted average common shares outstanding:
Basic		78,350			39,432			78,275			39,297

Diluted		81,373			39,803			81,217			39,717


Income attributable to common shareholders:
Income from continuing operations (net of income tax provision of $113,229 and $3,677for the three months ended June 30, 2010 and 2009, respectively, and $111,821 and $6,271 for the six months ended June 30, 2009, respectively)	$	175,852		$	5,738		$	173,751		$	9,758
Income from discontinued operations (net of income tax provision of $2,327 and $2,726 for the three and six months ended June 30, 2009, respectively)		—			3,630			—			4,253

Net income attributable to common shareholders	$	175,852		$	9,368		$	173,751		$	14,011

See accompanying notes to consolidated financial statements

ATLAS ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

FOR THE SIX MONTHS ENDED JUNE 30, 2010

(in thousands, except share data)

(Unaudited)


				Additional							Accumulated 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	212,680		2		643	29,642			1,249			—		—		—			1,894
Other comprehensive income	—		—		—	—			—			27,907		—		19,050			46,957
Stock compensation expense	—		—		6,853	—			—			—		—		—			6,853
Distributions to non-controlling interests	—		—		—	—			—			—		—		(3,266	)		(3,266	)
Non-controlling interests’ capital contributions	—		—		—	—			—			—		—		18,006			18,006
Net income	—		—		—	—			—			—		173,751		1,624			175,375

Balance, June 30, 2010	81,503,172	$	816	$	1,164,076	(3,115,039	)	$	(141,599	)	$	85,929	$	224,495	$	615,618		$	1,949,335

See accompanying notes to consolidated financial statements

ATLAS ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)


	Six Months Ended June 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	175,375		$	126,869
Income from discontinued operations		—			59,769

Income from continuing operations		175,375			67,100
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		102,620			100,967
Amortization of deferred finance costs		5,678			6,382
Non-cash (gain) loss on derivative value, net		(5,450	)		64,634
Non-cash compensation expense		10,976			1,775
Gain on asset sales and dispositions		(285,634	)		(105,691	)
Distributions paid to non-controlling interests		(3,266	)		(42,505	)
Equity (income) loss in unconsolidated companies		(3,016	)		2,024
Distributions received from unconsolidated companies		6,450			164
Deferred income taxes		110,703			5,927
Changes in operating assets and liabilities:
Accounts receivable and prepaid expenses and other		73,857			25,960
Accounts payable and accrued liabilities		(102,982	)		(21,291	)

Net cash provided by continuing operations operating activities		85,311			105,446
Net cash provided by discontinued operations operating activities		—			14,209

Net cash provided by operating activities		85,311			119,655


CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(186,961	)		(226,907	)
Investments in unconsolidated companies		(11,937	)		(2	)
Proceeds from asset sales		317,418			97,953
Other		870			(7,838	)

Net cash provided by (used in) continuing operations investing activities		119,390			(136,794	)
Net cash provided by discontinued operations investing activities		—			290,594

Net cash provided by investing activities		119,390			153,800


CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under subsidiary credit facilities		409,000			495,000
Repayments under subsidiary credit facilities		(561,660	)		(763,295	)
Net proceeds from subsidiary equity offerings		15,319			—
Dividends paid		—			(1,968	)
APL Class A preferred unit redemption		—			(15,000	)
Deferred financing costs and other		3,917			(11,357	)

Net cash used in financing activities		(133,424	)		(296,620	)


Net change in cash and cash equivalents		71,277			(23,165	)
Cash and cash equivalents, beginning of period		20,627			104,496

Cash and cash equivalents, end of period	$	91,904		$	81,331

See accompanying notes to consolidated financial statements

ATLAS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 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 June 30, 2010, the Company had a 2.1% direct ownership interest in APL. In June 2010, the Company purchased 8,000 $1,000 par value APL 12.0% Cumulative Class C Preferred Units (see Note 16);

•

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 June 30, 2010, the Company owned approximately 64.3% of the outstanding common units of AHD. At June 30, 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. At June 30, 2010, the Company had an approximate direct and indirect 18% ownership interest in Lightfoot GP. 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 6). The results of operations for the three and six month periods ended June 30, 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 June 30, 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.

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.

In April 2010, the Company entered into an undivided joint venture with Reliance Industries Limited (“Reliance”), whereby the Company sold a 40% undivided joint venture interest in approximately 300,000 net acres (approximately 120,000 net acres to Reliance) of its core undeveloped Marcellus Shale leasehold acreage to Reliance (see Note 4). The joint venture also calls for Reliance to provide the Company with a $1,357.5 million drilling carry, whereby Reliance will fund 75% of the Company’s respective portion of the drilling and completion costs of the wells developed on the joint venture leasehold acreage. As a result of this provision, the Company will effectively fund 15% of the capital costs required to drill each well, while Reliance will fund 85% until the $1,357.5 million is fully utilized. As a result of this transaction, the Company proportionally consolidated its 60% ownership interest in the operating results of the joint venture in its consolidated statements of operations. The Company also proportionally consolidated its ownership interest in the joint venture’s assets, to the extent contributed, and liabilities in its consolidated balance sheets.

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 was 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 and six months ended June 30, 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 7). Depreciation and amortization expense was 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 to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil is converted to gas equivalent basis (“Mcfe”) at the rate of one barrel equals 6 Mcf.

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 proportionately consolidated investment partnerships, joint venture wells, 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 and six months ended June 30, 2010 and 2009.

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 and six months ended June 30, 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 10.2% and 6.6% for the three months ended June 30, 2010 and 2009, respectively, and 9.9% and 6.3% for the six months ended June 30, 2010 and 2009, respectively. The aggregate amount of interest capitalized by the Company was $4.1 million and $2.3 million for the three months ended June 30, 2010 and 2009, respectively, and $7.1 million and $5.7 million for the six months ended June 30, 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 June 30, 2010 and December 31, 2009 (in thousands):


	June 30, 2010			December 31, 2009			Estimated Useful Lives 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	$	(80,069	)	$	(67,291	)
Partnership management and operating contracts		(11,825	)		(11,470	)

	$	(91,894	)	$	(78,761	)

Net Carrying Amount:
Customer contracts and relationships	$	155,313		$	168,091
Partnership management and operating contracts		2,518			2,873

	$	157,831		$	170,964

Amortization expense on intangible assets was $6.6 million and $6.7 million for the three months ended June 30, 2010 and 2009, respectively, and $13.1 million and $13.4 million for the six months ended June 30, 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 June 30, 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 and six months ended June 30, 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 considers the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in the 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 and six months ended June 30, 2010 and 2009.

Net Income Per Share

Basic net income per share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted net income per share is calculated by dividing net income 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 18). The following table sets forth the reconciliation of the Company’s weighted average number of common shares used to compute basic net income per share with those used to compute diluted net income per share (in thousands):


	Three Months Ended June 30,		Six Months Ended June 30,
	2010	2009	2010	2009
Weighted average number of shares – basic	78,350	39,432	78,275	39,297
Add: effect of dilutive incentive awards	3,023	371	2,942	420

Weighted average number of shares – diluted	81,373	39,803	81,217	39,717

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.

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 June 30, 2010 and December 31, 2009 of $58.1 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 June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Net income	$	176,154		$	133,710		$	175,375		$	126,869
Income attributable to non-controlling interests		(302	)		(124,342	)		(1,624	)		(112,858	)

Net income attributable to common shareholders		175,852			9,368			173,751			14,011
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges, net of income tax provision (benefit) of $1,235 and $4,222 for the three months ended June 30, 2010 and 2009, respectively, and ($34,207) and ($13,003) for the six months ended June 30, 2010 and 2009, respectively		(1,931	)		(13,055	)		53,247			60,395
Less: reclassification adjustment for realized gains in net income, net of income tax provision of $7,623 and $5,448 for the three months ended June 30, 2010 and 2009, respectively, and $15,927 and $7,695 for the six months ended June 30, 2010 and 2009, respectively		(2,287	)		(17,318	)		(5,626	)		(16,672	)
Changes in non-controlling interest related to items in other comprehensive income (loss)		(9,632	)		15,248			(19,015	)		(35,422	)
Plus: amortization of additional post-retirement liability, net of income tax provision (benefit) of $25 and $13 for the three months ended June 30, 2010 and 2009, respectively, and ($367) and $26 for the six months ended June 30, 2010 and 2009, respectively		39			21			(699	)		43

Total other comprehensive income (loss)		(13,811	)		(15,104	)		27,907			8,344

Comprehensive income (loss) attributable to common shareholders	$	162,041		$	(5,736	)	$	201,658		$	22,355

Recently Adopted Accounting Standards

In April 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-14, “Accounting for Extractive Industries – Oil & Gas: Amendments to Paragraph 932-10-S99-1” (“Update 2010-14”). Update 2010-14 provides amendments to add the SEC’s Regulation S-X Rule 4-10, “Financial Accounting and Reporting for Oil and Gas Producing Activities Pursuant to the Federal Securities Laws and the Energy Policy and Conservation Act of 1975” (“S-X Rule 4-10”) to Accounting Standards Codification (“ASC”) Topic 932 “Extractive Activities – Oil and Gas”. S-X Rule 4-10 was included in the SEC’s Final Rule, “Modernization of Oil and Gas Reporting, which became effective January 1, 2010. As Update 2010-14 only served to align the FASB’s ASC Topic 932 with the SEC’s S-X Rule 4-10, the Company’s adoption did not have a material impact on its financial position, results of operations or related disclosures.

In April 2010, the FASB issued Accounting Standards Update 2010-12, “Income Taxes (Topic 740): Accounting for Certain Tax Effects of the 2010 Health Care Reform Acts” (“Update 2010-12”). Update 2010-12 updates the FASB ASC for the SEC Staff Announcement, “Accounting for the Health Care and Education Reconciliation Act of 2010 and the Patient Protection and Affordable Care Act”. The announcement provides guidance on the accounting effect, if any, that arises from the different signing dates between the Health Care and Education Reconciliation Act of 2010, which is a reconciliation bill that amends the Patient Protection and Affordable Care Act (collectively, the “Acts”). Update 2010-12 clarifies the effect, if any, that the different signing dates might have on the accounting for these Acts. As Update 2010-12 serves only to clarify an accounting ambiguity between the Acts, the FASB did not provide a required adoption date.

In February 2010, the FASB issued Accounting Standards Update 2010-09, “Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements” (“Update 2010-09”). Update 2010-09 removes the requirement for an SEC filer to disclose a date through which subsequent events have been evaluated in both issued and revised financial statements. Revised financial statements include financial statements revised as a result of either correction of an error or retrospective application of U.S. generally accepted accounting standards. The requirements of Update 2010-09 were effective upon its issuance, February 24, 2010. The Company applied the requirements of Update 2010-09 upon its adoption and it did not have an impact on its financial position, results of operations or related disclosures.

In January 2010, the FASB issued Accounting Standards Update 2010-06, “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.

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.

Recently Issued Accounting Standards

In July 2010, the FASB issued Accounting Standards Update 2010-20, “Receivables – Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses” (“Update 2010-20”). Update 2010-20 provides enhanced disclosure requirements for allowance for credit losses and the credit quality of financing receivables to assist financial statement users in assessing credit risk exposures and evaluating the adequacy of the allowance for credit losses. This amendment requires disclosures on a disaggregated basis that will further facilitate the evaluation of the nature of credit risk inherent in an entity’s financing receivables, how the risks are analyzed and assessed in arriving at the allowance for credit losses, and the changes and reasons for such changes in the allowance for credit losses. This amendment also requires disclosure of credit quality indicators, past due information, a roll-forward schedule of the allowance for credit losses, and any modifications to financing receivables. The requirements of Update 2010-20 are effective at the end of a reporting entity’s first annual or quarterly reporting period ending after December 15, 2010 (December 31, 2010 for the Company). The Company will apply the requirements of Update 2010-11 upon its adoption on December 31, 2010 and does not expect it to have a material impact on its financial position, results of operations or related disclosures.

In March 2010, the FASB issued Accounting Standards Update 2010-11, “Derivatives and Hedging (Topic 815): Scope Exception Related to Embedded Credit Derivatives” (“Update 2010-11”). Update 2010-11 provides clarification with regard to the type of embedded credit derivative that is exempt from embedded derivative bifurcation requirements. Specifically, only one form of embedded credit derivative qualifies for the exemption – one that is related only to the subordination of one financial instrument to another. As a result, entities that have contracts containing an embedded credit derivative feature in a form other than such subordination may need to separately account for the embedded credit derivative feature. The requirements of Update 2010-11 are effective at the start of a reporting entity’s first fiscal year beginning after June 15, 2010 (January 1, 2011 for the Company). The Company will apply the requirements of Update 2010-11 upon its adoption on January 1, 2011 and does not expect it to 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 18). 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.

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 and six months ended June 30, 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 June 30, 2009		Six Months Ended June 30, 2009
Revenue	$	310,268	$	672,389
Income attributable to common shareholders:
Income from continuing operations	$	9,591	$	19,310
Income from discontinued operations		3,630		4,253

Net income attributable to common shareholders	$	13,221	$	23,563

Net income attributable to common shareholders per share – basic:
Income from continuing operations attributable to common shareholders	$	0.12	$	0.25
Income from discontinued operations attributable to common shareholders		0.05		0.05

Net income attributable to common shareholders	$	0.17	$	0.30

Net income attributable to common shareholders per share – diluted:
Income from continuing operations attributable to common shareholders	$	0.12	$	0.25
Income from discontinued operations attributable to common shareholders		0.05		0.05

Net income attributable to common shareholders	$	0.17	$	0.30

Weighted average common shares outstanding:
Basic		78,208		78,073

Diluted		78,579		78,493

NOTE 4 – MARCELLUS SHALE JOINT VENTURE

On April 20, 2010, the Company consummated a joint venture transaction with Reliance Industries Limited, whereby Reliance paid approximately $340.0 million in cash for a 40% undivided interest in approximately 300,000 net acres (120,000 net to Reliance) of core undeveloped Marcellus Shale leasehold acreage. The Company recognized a gain of $288.6 million, net of related transaction costs, within its consolidated statements of operations for the three and six months ended June 30, 2010 for the sale of the 40% undivided ownership interest in the leasehold acreage. In addition to the cash paid at closing, the Company will receive an additional $1,357.5 million in the form of a drilling carry. During the carry period, Reliance will fund 75% of the Company’s respective portion of drilling and completion costs of the wells developed on the joint venture leasehold acreage. As a result of this provision, the Company will effectively fund 15% of the capital costs required to drill each well, while Reliance will fund 85%, until the $1,357.5 million is fully utilized. The Company has five and one-half years to utilize the drilling carry, with a two-year extension possible if certain conditions are met. The Company will serve as the development operator for the joint venture and will act as the sole leasing agent for the joint venture in the area of mutual interest (“AMI”). Reliance will have the option after one year to operate in certain project areas within the AMI, but outside of the Company’s core operating counties in southwestern Pennsylvania. The Company proportionally consolidated its 60% ownership interest in the operating results of the joint venture in its consolidated statements of operations. The Company also proportionally consolidated its ownership interest in the joint venture’s assets, to the extent contributed, and liabilities in its consolidated balance sheets.

Subsequent to the formation of the joint venture, the Company and Reliance agreed, through two separate transactions, to purchase an additional approximate 42,400 undeveloped core Marcellus Shale leasehold acres, which is contained within the joint venture’s AMI, for an average purchase price of $4,532 per acre. One of the transactions was for approximately 17,000 leasehold acres, for which the Company agreed to pay a total purchase price of $85.9 million, of which $43.9 million was paid at closing, with the remaining $41.9 million to be paid following the completion of verification of the seller’s legal title to the properties, but no later than October 21, 2010. Of the $43.9 million paid at closing of the transaction, the Company was reimbursed for $17.6 million by Reliance for its 40% ownership interest. In connection with this transaction, the Company recorded a $41.9 million liability for the second installment of the purchase price and a $16.8 million receivable from Reliance for its 40% portion of the amount on its consolidated balance sheet at June 30, 2010. The second transaction was for approximately 25,400 leasehold acres, for which the Company agreed to pay a total purchase price of $106.0 million at closing, which is expected to be on or prior to September 5, 2010. Pursuant to our joint venture agreement, Reliance is obligated for its 40% portion of the cost of these transactions.

NOTE 5 – 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 10). 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 was included in gain on asset sale on the Company’s consolidated statement of operations for the year ended December 31, 2009.

Through June 30, 2010, APL utilized $8.5 million of the note receivable from Laurel Mountain to fund a portion of its capitalized expenditures, which was recorded as a non-cash investing activity in the Company’s consolidated statement of cash flows. In addition to contributions from the note receivable, APL funded its $5.6 million share of capital expenditures for the three and six months ended June 30, 2010.

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, net on the Company’s consolidated statements of operations.

The following table provides summarized statement of operations data on a 100% basis for Laurel Mountain for the three and six months ended June 30, 2010 and 2009 and balance sheet data as of June 30, 2010 and December 31, 2009 (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009⁽¹⁾		2010		2009⁽¹⁾
Statement of Operations data:
Total revenue	$	10,428	$	3,068	$	21,512	$	3,068
Net income		1,446		1,278		4,093		1,278


	June 30, 2010		December 31, 2009
Balance Sheet data:
Current assets	$	13,871	$	12,193
Long-term assets		266,490		248,730
Current liabilities		15,496		19,724
Long-term liabilities		9,454		9,555
Net equity		255,411		231,644

(1)	Represents the period from May 31, 2009, the date of initial formation, through June 30, 2009

NOTE 6 – 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 10). 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 three and six months ended June 30, 2009. The following table summarizes the components included within income from discontinued operations on the Company’s consolidated statements of operations (in thousands):


	Three Months Ended June 30,					Six Months Ended June 30,
	2010		2009			2010		2009
Total revenues	$	—	$	5,269		$	—	$	21,274
Total costs and expenses		—		(2,729	)		—		(9,858	)

Income before income tax expense		—		2,540			—		11,416
Income tax expense		—		(99	)		—		(498	)

Income from discontinued operations	$	—	$	2,441		$	—	$	10,918

NOTE 7 – PROPERTY, PLANT AND EQUIPMENT

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


	June 30, 2010			December 31, 2009			Estimated Useful Lives in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,307,480		$	1,243,932
Pre-development costs		7,346			6,270
Wells and related equipment		1,080,959			1,017,370

Total proved properties		2,395,785			2,267,572
Unproved properties		60,864			41,816
Support equipment		10,770			8,930

Total natural gas and oil properties		2,467,419			2,318,318
Pipelines, processing and compression facilities		1,716,188			1,685,200		2 – 40
Rights of way		168,068			167,105		20 – 40
Land, buildings and improvements		26,836			26,697		3 – 40
Other		24,142			21,931		3 – 10

		4,402,653			4,219,251
Less – accumulated depreciation, depletion and amortization		(751,852	)		(663,449	)

	$	3,650,801		$	3,555,802

NOTE 8 – OTHER ASSETS

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


	June 30, 2010		December 31, 2009
Deferred finance and organization costs, net of accumulated amortization of $41,148 and $35,470 at June 30, 2010 and December 31, 2009, respectively	$	42,179	$	47,147
Investment in Lightfoot		17,414		11,528
Other investments		7,386		6,340
Long-term pipeline lease prepayment		3,293		3,168
Security deposits		3,413		3,809
Long-term derivative receivable from Partnerships		11,273		2,841

	$	84,958	$	74,833

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 10).

Investments at June 30, 2010 included a $17.4 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 for which Jonathan Cohen, Vice Chairman of the Company’s Board of Directors, is the Chairman of the Board. 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. The Company accounts for its investment in Lightfoot under the equity method of accounting. The Company recorded losses in other income, net of $0.2 million and $1.7 million for the three months ended June 30, 2010 and 2009, respectively, and $0.2 million and $1.8 million for the six months ended June 30, 2010 and 2009, respectively. During the six months ended June 30, 2010, the Company contributed capital of $6.3 million to its interest in Lightfoot, in order to maintain its aggregate ownership interest.

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 9 – 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.

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 June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Asset retirement obligations, beginning of period	$	52,608		$	49,262		$	51,813		$	48,136
Liabilities incurred		119			166			161			596
Liabilities settled		(85	)		(23	)		(91	)		(85	)
Accretion expense		813			737			1,572			1,495

Asset retirement obligations, end of period	$	53,455		$	50,142		$	53,455		$	50,142

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 10 – DEBT

At June 30, 2010, the Company’s debt consists entirely of instruments entered into by ATN and APL. The Company has not guaranteed any of its subsidiaries’ debt obligations, with the exception of the AHD credit facility, which terminated April 13, 2010. Total debt consists of the following at the dates indicated (in thousands):


	June 30, 2010			December 31, 2009
ATN revolving credit facility	$	88,000		$	184,000
ATN 10.75 % senior notes – due 2018		405,556			405,922
ATN 12.125 % senior notes – due 2017		196,703			196,468
AHD credit facility		—			8,000
APL revolving credit facility		285,000			326,000
APL term loan		425,845			433,505
APL 8.125 % senior notes – due 2015		271,900			271,627
APL 8.75 % senior notes – due 2018		223,050			223,050
APL capital leases		2,565			—

Total debt		1,898,619			2,048,572
Less current maturities		(600	)		(8,000	)

Total long-term debt	$	1,898,019		$	2,040,572

ATN Revolving Credit Facility

At June 30, 2010, ATN had a credit facility with a syndicate of banks with a borrowing base of $550.0 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. 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 June 30, 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 June 30, 2010 and December 31, 2009, the weighted average interest rate on outstanding borrowings was 3.2% 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 less 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.

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 June 30, 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. Based on the definitions contained in ATN’s credit facility, its ratio of current assets to current liabilities was 2.3 to 1.0 and its ratio of total debt to EBITDA was 2.7 to 1.0 at June 30, 2010.

ATN Senior Notes

At June 30, 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 $5.6 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 $3.3 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 June 30, 2010.

AHD Credit Facility

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 (the “Termination Date”). On April 13, 2010, AHD repaid the remaining $4.0 million outstanding under its credit facility, and the credit facility no longer exists at June 30, 2010.

AHD’s $30.0 million repayment in June 2009 was funded from the proceeds of (i) a subordinate 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 accrued quarterly on the outstanding principal amount at the rate of 12% per annum, but before the maturity date, interest was payable entirely by increasing the principal amount of the note. The maturity date was the day following the 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 were paid by increasing APL’s investment in the preferred units; effective 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.

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 required it to pay to the Company an amount equal to (i) 3.75% per annum multiplied by (ii) the principal amount outstanding under the credit facility plus a $1.0 million guarantee fee. The maturity date of the promissory note was the day following the Termination Date. Interest on the promissory note accrued quarterly at the rate of 3.75% per annum. However, prior to the maturity date, interest was payable entirely by increasing the principal amount of the note. The Company paid the remaining $16 million balance of AHD’s credit facility pursuant to its guarantee.

In July 2010, AHD entered into an amended and consolidated note with the Company, which consolidates in one instrument the debt owed by AHD to the Company under the subordinate note and the guarantee note and the Company’s advance of $16 million under its guarantee of AHD’s credit facility. The principal amount of the note is $33.4 million; the interest rate is 12% per annum which, prior to demand by the Company for cash payment, will be payable by accruing such interest and adding the amount to the principal amount of the note on a quarterly basis; and the note is payable on demand.

APL Term Loan and Credit Facility

At June 30, 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 June 30, 2010 were both 6.8%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $8.1 million was outstanding at June 30, 2010. These outstanding letter of credit amounts were not reflected as borrowings on the Company’s consolidated balance sheet at June 30, 2010. At June 30, 2010, APL had $86.9 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 guarantee 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 was in compliance with these covenants as of June 30, 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:


Fiscal quarter ending:	Maximum Leverage Ratio	Maximum Senior Secured Leverage Ratio	Minimum Interest Coverage Ratio

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

At June 30, 2010, APL’s leverage ratio was 7.26 to 1.0, its senior secured leverage ratio was 4.30 to 1.0, and its interest coverage ratio was 1.66 to 1.0.

APL Senior Notes

At June 30, 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 $3.6 million of unamortized discount as of June 30, 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 was in compliance with these covenants as of June 30, 2010.

Cash payments for interest related to debt made by the Company and its subsidiaries were $94.5 million and $75.1 million for the six months ended June 30, 2010 and 2009, respectively.

NOTE 11 – 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 the 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 transmission, gathering 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.

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 $156.4 million and $69.4 million at June 30, 2010 and December 31, 2009, respectively. Of the $87.0 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 June 30, 2010, if the fair values of the instruments remain at current market values, the Company will reclassify $35.9 million of gains to the Company’s consolidated statements of operations over the next twelve month period as these contracts expire, consisting of $38.3 million of gains to gas and oil production revenues, $1.0 million of losses to transmission, gathering and processing revenues and $1.4 million of losses to interest expense. Aggregate gains of $51.1 million will be reclassified to the Company’s consolidated statements of operations in later periods as these remaining contracts expire, consisting of $51.9 million of gains to gas and oil production revenues and $0.8 million of losses to transmission, gathering and processing revenues. 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 June 30, 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 and six months ended June 30, 2010 and 2009:

Fair Value of Derivative Instruments:


	Asset Derivatives					Liability Derivatives
Derivatives in		Fair Value					Fair Value
Cash Flow Hedging Relationships	Balance Sheet Location	June 30, 2010		December 31, 2009		Balance Sheet Location	June 30, 2010			December 31, 2009
		(in thousands)					(in thousands)
Commodity contracts:	Current assets	$	85,754	$	73,066	Current liabilities	$	(1,832	)	$	(901	)
	Long-term assets		110,928		58,930	Long-term liabilities		(39,768	)		(14,091	)

			196,682		131,996			(41,600	)		(14,992	)
Interest rate contracts:	Current assets		—		—	Current liabilities		(2,274	)		(3,751	)
	Long-term assets		—		—	Long-term liabilities		—			(224	)

			—		—			(2,274	)		(3,975	)

Total derivatives		$	196,682	$	131,996		$	(43,874	)	$	(18,967	)

Effects of Derivative Instruments on Consolidated Statements of Operations:


Derivatives in Cash Flow	Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) for the Three Months Ended June 30,						Location of Gain/(Loss) Reclassified from Accumulated OCI into Income	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) for the Three Months Ended June 30,
Hedging Relationships	2010			2009			(Effective Portion)	2010			2009
	(in thousands)							(in thousands)
Commodity contracts	$	(3,085	)	$	(22,528	)	Gas and oil production	$	21,722		$	31,564
Interest rate contracts		(81	)		(132	)	Interest expense		(1,084	)		(1,030	)

	$	(3,166	)	$	(22,660	)		$	20,638		$	30,534

Derivatives in Cash Flow	Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) for the Six Months Ended June 30,						Location of Gain/(Loss) Reclassified from Accumulated OCI into Income	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) for the SixMonths Ended June 30,
Hedging Relationships	2010			2009			(Effective Portion)	2010			2009
	(in thousands)							(in thousands)
Commodity contracts	$	87,971		$	64,286		Gas and oil production	$	45,199		$	47,082
Interest rate contracts		(538	)		(1,005	)	Interest expense		(2,165	)		(2,032	)

	$	87,433		$	63,281			$	43,034		$	45,050

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 10). 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 10). 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.

The Company recognized gains of $21.7 million and $31.6 million for the three months ended June 30, 2010 and 2009, respectively, and $45.2 million and $47.1 million for the six months ended June 30, 2010 and 2009, respectively, on settled contracts covering natural gas and oil production. These gains 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 and six months ended June 30, 2010 and 2009 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

At June 30, 2010, ATN had interest rate derivative contracts with an aggregate notional principal amount of $150.0 million through January 2011. Under the terms of the contracts, ATN 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. During the three months ended June 30, 2010, ATN repaid a portion of its outstanding balance under the revolving credit facility, which had a balance of $88.0 million at June 30, 2010. Prior to the repayment of a portion of the outstanding balance under the revolving credit facility, the interest rate derivative contracts were designated as cash flow hedges. As a result of this reduction in the outstanding balance under the credit facility to an amount below the notional amount of the interest rate derivative contract and the uncertainty of whether the forecasted transaction will occur, ATN discontinued hedge accounting for these derivatives. In accordance with prevailing accounting literature, the portion of any gain or loss in other comprehensive income related to forecasted hedge transactions that are no longer expected to occur are to be removed from other comprehensive income and recognized within the Company’s statements of operations. As a result, the Company recognized a gain of $0.1 million within gain (loss) on mark-to-market derivatives on its consolidated statements of operations for the three and six months ended June 30, 2010 for the change in fair value following the discontinuation of hedge accounting.

At June 30, 2010, the Company had the following interest rate and commodity derivatives:

Interest Fixed Rate Swap


Term	Notional Amount		Option Type	Contract Period Ended December 31,	Fair Value Liability
					(in thousands)
January 2008 – January 2011	$	150,000,000	Pay 3.1% - Receive LIBOR	2010	$	(1,949	)
				2011		(325	)

					$	(2,274	)

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	20,140,000	$	7.387	$	51,562
2011	26,480,000	$	6.591		32,932
2012	20,852,300	$	6.797		22,821
2013	13,211,500	$	6.822		11,873

				$	119,188

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	2,400,000	$	6.721	$	5,177
2010	Calls sold	2,400,000	$	7.909		(203	)
2011	Puts purchased	13,380,000	$	6.147		18,461
2011	Calls sold	13,380,000	$	7.236		(4,391	)
2012	Puts purchased	12,240,000	$	6.052		18,333
2012	Calls sold	12,240,000	$	7.160		(10,132	)
2013	Puts purchased	14,880,000	$	6.094		25,542
2013	Calls sold	14,880,000	$	7.245		(17,689	)
2014	Puts purchased	5,040,000	$	5.850		8,427
2014	Calls sold	5,040,000	$	6.950		(7,953	)

					$	35,572

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	26,700	$	97.122	$	551
2011	42,600	$	77.460		(82	)
2012	33,500	$	76.855		(139	)
2013	10,000	$	77.360		(44	)

				$	286

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	17,000	$	85.000	$	169
2010	Calls sold	17,000	$	112.349		(1	)
2011	Puts purchased	27,000	$	67.223		152
2011	Calls sold	27,000	$	89.436		(201	)
2012	Puts purchased	21,500	$	65.506		156
2012	Calls sold	21,500	$	91.448		(220	)
2013	Puts purchased	6,000	$	65.358		51
2013	Calls sold	6,000	$	93.442		(70	)

					$	36

				Total Company net asset	$	152,808

⁽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 June 30, 2010 and December 31, 2009, net unrealized derivative assets of $57.2 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):


	June 30, 2010			December 31, 2009
Accounts receivable	$	450		$	270
Other assets, net		11,273			2,841
Current portion of derivative payable to Partnerships		(28,610	)		(22,382	)
Long-term portion of derivative payable to Partnerships		(40,362	)		(22,380	)

	$	(57,249	)	$	(41,651	)

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.

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


Contract Type	Balance Sheet Location	June 30, 2010			December 31, 2009

Asset Derivatives
Commodity contracts	Current portion of derivative asset	$	9,877		$	1,591
Commodity contracts	Long-term derivative asset		1,259			361
Commodity contracts	Current portion of derivative liability		1,197			6,562
Commodity contracts	Long-term derivative liability		1,710			3,435

			14,043			11,949

Liability Derivatives
Interest rate contracts	Current portion of derivative liability		—			(2,533	)
Interest rate contracts	Current portion of derivative asset		—			(593	)
Commodity contracts	Current portion of derivative asset		(1,005	)		—
Commodity contracts	Long-term derivative asset		(746	)		—
Commodity contracts	Current portion of derivative liability		(2,216	)		(37,862	)
Commodity contracts	Long-term derivative liability		(6,488	)		(14,561	)

			(10,455	)		(55,549	)

Total Derivatives		$	3,588		$	(43,600	)

As of June 30, 2010, APL had the following commodity derivatives, which do not qualify for hedge accounting:

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	2,280,000	(0.700	)	$	(699	)
2010	Purchased	Natural Gas Basis	2,280,000	(0.705	)		711
2011	Sold	Natural Gas Basis	1,920,000	(0.728	)		(764	)
2011	Purchased	Natural Gas Basis	1,920,000	(0.758	)		821
2012	Sold	Natural Gas Basis	720,000	(0.685	)		(270	)
2012	Purchased	Natural Gas Basis	720,000	(0.685	)		270

Natural Gas Liquids

2010	Sold	Propane	17,640,000	1.108			1,757
2010	Sold	Normal Butane	1,890,000	1.550			365
2010	Sold	Natural Gasoline	1,512,000	1.925			412

Crude Oil

2011	Sold	Crude Oil	78,000	92.870			1,089


Total Fixed Price Swaps						$	3,692

Options


Production Period	Purchased/ Sold	Type	Commodity	Volumes⁽²⁾	Average Strike Price		Fair Value⁽¹⁾ Asset/(Liability) (in thousands)

Natural Gas

2010	Purchased⁽³⁾	Call	Natural Gas	4,200,000	$	6.000	$	(735	)

Natural Gas Liquids

2010	Purchased⁽³⁾	Put	Propane	6,048,000	$	1.110		(52	)
2010	Purchased⁽³⁾	Put	Normal Butane	2,772,000		1.440		(75	)

Crude Oil

2010	Purchased	Put	Crude Oil	324,000		74.268		1,214
2010	Sold	Call	Crude Oil	546,000		100.051		(283	)
2010	Purchased⁽⁴⁾	Call	Crude Oil	174,000		120.000		18
2011	Purchased	Put	Crude Oil	420,000		89.000		6,299
2011	Sold	Call	Crude Oil	678,000		94.681		(3,405	)
2011	Purchased⁽⁴⁾	Call	Crude Oil	252,000		120.000		387
2012	Sold	Call	Crude Oil	498,000		95.835		(4,172	)
2012	Purchased⁽⁴⁾	Call	Crude Oil	180,000		120.00		700


Total Options							$	(104	)

						Total APL asset	$	3,588

⁽¹⁾	See Note 12 for discussion on fair value methodology.

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

⁽³⁾	Liabilities for purchased options are due to deferred premium payments, which will be paid at the time the options are settled.

⁽⁴⁾	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.

APL made net payments related to the early termination of derivative contracts of $20.3 million during the three months ended June 30, 2010 and $25.3 million and $5.0 million during the six months ended June 30, 2010 and 2009, respectively. There were no net payments made during the three months ended June 30, 2009. The terminated derivative contracts were due to expire during periods through December 31, 2012. During the three and six months ended June 30, 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):


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
Early termination of derivative contracts:		2010			2009			2010			2009
Cash paid for early termination	$	(11,945	)	$	—		$	(25,315	)	$	(5,000	)
Less: Deferred recognition of loss on early termination⁽¹⁾		—			—			(5,615	)		—
Plus: Equity applied to prior period early termination		(8,421	)		—			(8,421	)		—

		(20,366	)		—			(39,351	)		(5,000	)

Net cash derivative expense included within transmission, gathering and processing revenue		5,925			—			11,122			—
Net cash derivative expense included within gain (loss) on mark-to-market derivatives		(26,291	)		—			(50,473	)		(5,000	)
Recognition of deferred hedge loss from prior periods included within transmission, gathering and processing revenue⁽³⁾		(9,658	)		(12,123	)		(25,190	)		(34,067	)
Recognition of deferred hedge gain from prior periods included within gain (loss) on mark-to-market derivative⁽³⁾		22,726			7,117			44,810			19,220

Total realized loss at early termination⁽²⁾	$	(7,298	)	$	(5,006	)	$	(19,731	)	$	(19,847	)

⁽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.

⁽²⁾

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

⁽³⁾

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

In addition, APL will recognize a net gain of $4.9 million from terminated hedge contracts during the periods for which the hedged physical transactions were scheduled to be settled through December 31, 2012, with $0.6 million to be recognized during the second half of 2010 and $2.3 million and $2.0 million to be recognized during the years ending December 31, 2011 and 2012, respectively. The net gain of $4.9 million includes an $8.5 million gain related to the theoretical premiums for unwound options which had previously been purchased or sold as part of puts and calls, partially offset by $3.6 million of early termination activity previously recorded in other comprehensive income within stockholders’ equity on the Company’s consolidated balance sheets.

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 (in thousands):


	Gain (Loss) Recognized in Accumulated OCI					Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
	Three Months Ended June 30,						Three Months Ended June 30,
	2010		2009			Location	2010			2009
Interest rate contracts⁽¹⁾	$	—	$	(1,065	)	Interest expense	$	(470	)	$	(3,125	)
		—		—		Interest expense		—			(196	)
Commodity contracts⁽¹⁾		—		—		Transmission, gathering and processing revenue		(10,258	)		(10,894	)

	$	—	$	(1,065	)		$	(10,728	)	$	(14,215	)


	Gain (Loss) Recognized in Accumulated OCI					Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
	Six Months Ended June 30,						Six Months Ended June 30,
	2010		2009			Location	2010			2009
Interest rate contracts⁽¹⁾	$	—	$	(2,298	)	Interest expense	$	(2,293	)	$	(6,180	)
		—		—		Interest expense		(20	)		(196	)
Commodity contracts⁽¹⁾		—		—		Transmission, gathering and processing revenue		(19,191	)		(26,864	)

	$	—	$	(2,298	)		$	(21,504	)	$	(33,240	)


	Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
		Three Months Ended June 30,					Six Months Ended June 30,
	Location	2010		2009			2010			2009
Interest rate contracts⁽¹⁾	Gain on mark-to market derivatives	$	—	$	3,694		$	(10	)	$	—
Commodity contracts⁽¹⁾	Transmission, gathering and processing revenue		—		—			—			(509	)
Commodity contracts⁽²⁾	Gain on mark-to market derivatives		8,022		(18,593	)		12,161			(18,277	)

		$	8,022	$	(14,899	)	$	12,151		$	(18,786	)

⁽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):


	June 30, 2010			December 31, 2009
Current portion of derivative asset	$	94,626		$	74,064
Long-term derivative asset		111,441			59,291
Current portion of derivative liability		(5,125	)		(38,485	)
Long-term derivative liability		(44,546	)		(25,441	)

Total Company net asset	$	156,396		$	69,429

NOTE 12 — 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.

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 and APL’s outstanding derivative contracts (see Note 11) and the Company’s Supplemental Employment Retirement Plans (“SERPs” - see Note 18). 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 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 was 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.

Information for assets and liabilities measured at fair value at June 30, 2010 and December 31, 2009 was as follows (in thousands):


	Level 1		Level 2			Level 3		Total
June 30, 2010
SERP liability	$	—	$	(6,238	)	$	—	$	(6,238	)
SERP asset funded in rabbi trust		3,740		—			—		3,740
Company commodity-based derivatives		—		155,082			—		155,082
APL commodity-based derivatives		—		1,180			2,408		3,588
Interest rate derivatives		—		(2,274	)		—		(2,274	)

Total	$	3,740	$	147,750		$	2,408	$	153,898


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 June 30, 2010 (in thousands):


	NGL Fixed Price Swaps			NGL Put Options					Total
	Volume⁽¹⁾	Amount		Volume⁽¹⁾		Amount			Amount
Balance – December 31, 2009	—	$	—	43,470		$	1,268		$	1,268
New contracts	21,042		—	8,820			—			—
Cash settlements from unrealized loss⁽²⁾⁽³⁾	—		—	(43,470	)		6,381			6,381
Net change in unrealized loss⁽²⁾	—		2,535	—			(1,268	)		1,267
Deferred option premium recognition⁽³⁾	—		—	—			(6,508	)		(6,508	)

Balance – June 30, 2010	21,042	$	2,535	8,820		$	(127	)	$	2,408

(1)	Volumes are stated in gallons.

(2)	Included within other income, net on the Company’s consolidated statements of operations.

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

Other Financial Instruments

The estimated fair value of the 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 June 30, 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 (AHD’s credit facility expired in April 2010), were $1,908.2 million and $2,055.2 million, respectively, compared with the carrying amounts of $1,898.6 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.

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 9). Information for assets that are measured at fair value on a nonrecurring basis for the three and six months ended June 30, 2010 and 2009 was as follows (in thousands):


	Three Months Ended June 30,
	2010				2009
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	119	$	119	$	166	$	166

Total	$	119	$	119	$	166	$	166


	Six Months Ended June 30,
	2010				2009
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	161	$	161	$	596	$	596

Total	$	161	$	161	$	596	$	596

NOTE 13 – 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 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 June 30, 2010. The transition services agreement governs the provision of support services by the Company to RAI and by RAI to the Company, such as 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 the three months ended June 30, 2010 and 2009, the Company’s reimbursements to RAI totaled $0.2 million and $0.3 million, respectively, and $0.4 million and $0.6 million for the six months ended June 30, 2010 and 2009, respectively. At June 30, 2010 and December 31, 2009, reimbursements to RAI totaling $0.2 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 June 30, 2010, the Company’s guarantee was limited to $10.1 million.

NOTE 14 – 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 June 30, 2010 and 2009, $1.9 million and $0.9 million, respectively, of the Company’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the investment partnerships. For the six months ended June 30, 2010 and 2009, $5.2 million and $0.9 million, respectively, of net revenues were subordinated.

On February 26, 2010, APL received notice from Williams, its partner in Laurel Mountain, alleging that certain title defects exist with respect to the real property contributed by APL to Laurel Mountain. Under the Formation and Exchange Agreement with Williams: (i) Williams had nine months after closing (the “Claim Date”) to assert any alleged title defects, and (ii) APL has 30 days following the Claim Date to contest the title defects asserted by Williams and 180 days following the Claim Date to cure those title defects. On March 26, 2010, APL delivered notice, disputing Williams alleged title defects as well as the amounts claimed. APL is currently conducting a review with respect to the title defects that have been alleged. At the end of the cure period with respect to any remaining title defects, APL may elect, at its option, to pay Williams for the cost of such defects, up to a total of $3.5 million, or indemnify Williams with respect to such title defects. Although an adverse outcome is reasonably possible, it is not currently possible to evaluate the amount that APL may be required to pay with respect to such alleged title defects.

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 June 30, 2010, the Company and its subsidiaries are committed to expend approximately $85.5 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

Legal Proceedings

Following the 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, In re 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.

In October 2009, the Company filed a motion to dismiss the Consolidated Complaint. Subsequently, in December 2009, plaintiffs filed an Amended Complaint (the “Amended Complaint”). Pursuant to the Delaware Chancery Court’s January 2010 Scheduling Stipulation and Order, 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. Defendants filed a reply brief on June 11, 2010 and oral argument was held on the motion on July 20, 2010. The Court has not yet ruled on the motion.

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 captioned CNX 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 the decision. On May 18, 2010, the appeal was argued before the Tennessee Court of Appeals. The parties are awaiting the court’s 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.

NOTE 15 – 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 June 30, 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 six months ended June 30, 2010 and 2009. The Company has no material uncertain tax positions at June 30, 2010. During the six months ended June 30, 2010 and 2009, the Company made no cash tax payments.

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 16 – 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 over the book carrying amount per unit.

In June 2010, APL sold 8,000 newly-created 12% Cumulative Class C Limited Partner Preferred Units (the “APL Class C Preferred Units”) to the Company for cash consideration of $1,000 per APL Class C Preferred Unit (the “Face Value”). The APL Class C Preferred Units are redeemable by APL for an amount equal to the Face Value of the units being redeemed plus all accrued but unpaid dividends. The Company is entitled to distributions of 12% per annum, paid quarterly on the same date as the distribution payment date for APL’s common units. The sale of the APL Class C Preferred Units to the Company was exempt from the registration requirements of the Securities Act of 1933. The Company is entitled to receive the distributions on the APL Class C Preferred units pro rata from the July 1, 2010 commencement date.

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 10), 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 10).

NOTE 17 – 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 June 30, 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

On May 29, 2009, APL entered into an amendment to its senior secured credit facility (see Note 10), 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 June 30, 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 10). AHD’s credit facility agreement expired in April 2010.

NOTE 18 – 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 June 30, 2010 expire not later than ten years after the date of grant and vest according to a schedule determined by the Compensation Committee of the Company’s Board of Directors. 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 and six months ended June 30, 2010. (There was no plan activity for the three and six months ended June 30, 2009):


	Three Months Ended June 30, 2010					Six Months Ended June 30, 2010
	Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price
Outstanding at beginning of period		1,188,000		$	29.09		2,500		$	29.10
Granted		145,000		$	33.70		1,333,500		$	29.59
Exercised		—			—		—			—
Cancelled		—			—		—			—
Forfeited or expired		(2,500	)	$	29.10		(2,500	)	$	29.10

Outstanding at end of period⁽¹⁾⁽²⁾		1,333,500		$	29.59		1,333,500		$	29.59

Options exercisable at June 30, 2010		—			—
Non-cash compensation expense recognized (in thousands)	$	1,182				$	1,891

Available for grant at June 30, 2010		2,975,903

(1)	There was no aggregate intrinsic value for options outstanding at June 30, 2010.

(2)	The weighted average remaining contractual term of options outstanding at June 30, 2010 was 9.6 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 period indicated:


	Three Months Ended June 30, 2010			Six Months Ended June 30, 2010
Expected dividend yield		—			—
Expected stock price volatility		48	%		48	%
Risk-free interest rate		2.5	%		2.6	%
Expected term (in years)		6.55			6.28
Fair value of stock options granted	$	17.02		$	14.71

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 and six months ended June 30, 2010 (there was no activity for deferred and restricted units for the three and six months ended June 30, 2009):


	Three Months Ended June 30, 2010					Six Months Ended June 30, 2010
	Units			Weighted Average Grant Date Fair Value		Units			Weighted Average Grant Date Fair Value
Non-vested shares outstanding at beginning of period		258,541		$	29.09		12,633		$	29.50
Granted		235,056		$	33.82		483,464		$	31.40
Vested		—		$	—		—		$	—
Forfeited		(2,500	)	$	29.10		(2,500	)	$	29.10

Non-vested shares outstanding at end of period⁽¹⁾		491,097		$	31.36		493,597		$	31.36

Non-cash compensation expense recognized (in thousands)	$	565				$	869

⁽¹⁾	The aggregate intrinsic value for restricted stock unit awards outstanding at June 30, 2010 was $13.4 million.

For the three and six months ended June 30, 2010, the Company recorded non-cash compensation of $1.7 million and $2.8 million, respectively, for the Company’s options and units under the 2009 Plan. At June 30, 2010, the Company had unamortized compensation expense related to its unvested portion of the 2009 Plan options and units of $32.3 million that the Company expects to recognize over the next four years.

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 $0.6 million during the three and six months ended June 30, 2010 from the exercise of options. The Company also received $0.1 million during the three and six months ended June 30, 2009 from the exercise of stock options. The Company issues new shares when stock options are exercised or units are converted to shares. The following tables set forth the 2004 Plan activity for the three and six months ended June 30, 2010 and 2009:


	Three Months Ended June 30,
	2010					2009
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price

Outstanding, beginning of period		3,506,871		$	16.81		3,558,226		$	16.92
Granted		—		$	—		—		$	—
Exercised⁽¹⁾		(46,938	)	$	12.40		(12,656	)	$	11.32
Cancelled		—		$	—		—		$	—
Forfeited		—		$	—		(8,438	)	$	11.32

Outstanding, end of period⁽²⁾⁽³⁾		3,459,933		$	16.87		3,537,132		$	16.96


Non-cash compensation expense recognized (in thousands)	$	638				$	974


	Six Months Ended June 30,
	2010					2009
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of period		3,507,054		$	16.81		3,495,351		$	16.96
Granted		—		$	—		100,000		$	13.35
Exercised⁽¹⁾		(47,121	)	$	12.40		(12,656	)	$	11.32
Cancelled		—		$	—		(15,187	)	$	11.32
Forfeited		—		$	—		(30,376	)	$	11.32

Outstanding, end of period⁽²⁾⁽³⁾		3,459,933		$	16.87		3,537,132		$	16.96


Options exercisable, end of period⁽⁴⁾		2,964,933		$	14.76


Non-cash compensation expense recognized (in thousands)	$	1,341				$	1,894


Available for grant at June 30, 2010		757,905

⁽¹⁾	The aggregate intrinsic values for the options that were exercised were $0.9 million and $0.1 million during the three months ended June 30, 2010 and 2009, respectively, and $0.9 million and $0.1 million during the six months ended June 30, 2010 and 2009, respectively.

⁽²⁾	The weighted average remaining contractual life for outstanding options at June 30, 2010 was 6.0 years.

⁽³⁾	The aggregate intrinsic value of options outstanding at June 30, 2010 was approximately $40.6 million.

⁽⁴⁾	The weighted average outstanding contractual life of exercisable options at June 30, 2010 was 5.4 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 June 30,				Six Months Ended June 30,
	2010		2009		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. 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.

The following table summarizes the activity of deferred and restricted units for the three and six months ended June 30, 2010 and 2009:


	Three Months Ended June 30,
	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		32,941		$	22.94		11,670		$	24.29
Granted		1,365		$	32.95		4,805		$	15.60
Vested⁽¹⁾		(1,575	)	$	28.56		(3,941	)	$	15.26
Forfeited		—		$	—		—		$	—

Non-vested shares outstanding, end of period⁽²⁾		32,731		$	23.09		12,534		$	23.80

Non-cash compensation expense recognized (in thousands)	$	52				$	26


	Six Months Ended June 30,
	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		1,365		$	32.95		4,805		$	15.60
Vested ⁽¹⁾		(3,000	)	$	25.89		(4,783	)	$	16.22
Forfeited		—		$	—		—		$	—

Non-vested shares outstanding, end of period⁽²⁾		32,731		$	23.09		12,534		$	23.80

Non-cash compensation expense recognized (in thousands)	$	106				$	51

⁽¹⁾	The aggregate intrinsic values for phantom unit awards that matured were $0.1 million for both the three months ended June 30, 2010 and 2009 and $0.1 million during both the six months ended June 30, 2010 and 2009.

⁽²⁾	The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2010 was $0.9 million.

The Company recorded non cash compensation expense for the Company’s options and units under the 2004 Plan of $0.7 million and $1.0 million for the three months ended June 30, 2010 and 2009, respectively, and $1.4 million and $1.9 million for the six months ended June 30, 2010 and 2009, respectively. At June 30, 2010, the Company had unearned compensation expense related to its unvested portion of the options and units of $4.7 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 three and six months ended June 30, 2009 and the post-Merger converted restricted stock and phantom unit activity for the three and six months ended June 30, 2010:


	Three Months Ended June 30,
	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		708,199		$	20.00		784,661		$	23.65
Granted		—		$	—		6,523		$	15.13
Vested ⁽³⁾		(13,808	)	$	18.10		(11,905	)	$	21.00
Forfeited		(6,670	)	$	21.91		(8,000	)	$	20.78

Non-vested shares outstanding, end of period		687,721		$	20.02		771,279		$	23.65

Non-cash compensation expense recognized (in thousands)	$	1,021				$	1,140


	Six Months Ended June 30,
	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		—		$	—		23,523		$	14.50
Vested ⁽³⁾		(161,201	)	$	19.69		(13,073	)	$	21.70
Forfeited		(7,250	)	$	21.96		(8,000	)	$	20.78


Non-vested shares outstanding, end of period⁽⁴⁾		687,721		$	20.02		771,279		$	23.65

Non-cash compensation expense recognized (in thousands)	$	2,122				$	2,323

⁽¹⁾	The shares and fair values for the six months ended June 30, 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 six months ended June 30, 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 were $0.5 million and $0.2 million during the three months ended June 30, 2010 and 2009, respectively, and $4.9 million and $0.2 million during the six months ended at June 30, 2010 and 2009, respectively.

⁽⁴⁾	The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2010 was $18.6 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 three and six months ended June 30, 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 for the three and six months ended June 30, 2010. For the three and six months ended June 30, 2010, the Company received $0.2 million and $0.3 million from the exercise of options. There were no proceeds from the exercise of options during the three and six months ended June 30, 2009. The following table sets forth the Assumed Plan option activity for the periods indicated:


	Three Months Ended June 30,
	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		2,058,277		$	20.38		1,902,002		$	24.17
Granted		—		$	—		—		$	—
Exercised⁽³⁾		(9,993	)	$	19.88		—		$	—
Cancelled		—		$	—		—		$	—
Forfeited		(8,758	)	$	21.43		(6,600	)	$	23.06

Outstanding, end of period		2,039,526		$	20.38		1,895,402		$	24.18

Non-cash compensation expense recognized (in thousands)	$	228				$	326


	Six Months Ended June 30,
	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⁾		(17,272	)	$	19.88		—		$	—
Cancelled		(174	)	$	19.88		—		$	—
Forfeited		(11,542	)	$	21.96		(7,500	)	$	23.06

Outstanding, end of period⁽⁴⁾⁽⁵⁾		2,039,526		$	20.38		1,895,402		$	24.18

Options exercisable, end of period⁽⁶⁾		780,042		$	18.89

Non-cash compensation expense recognized (in thousands)	$	524				$	660

Available for grant at June 30, 2010		—

⁽¹⁾	The shares and exercise prices for the three and six months ended June 30, 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 and six months ended June 30, 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 and $0.2 million for the three and six months ended June 30, 2010, respectively.

⁽⁴⁾	The weighted average remaining contractual life for outstanding options at June 30, 2010 was 6.5 years.

⁽⁵⁾	The aggregate intrinsic value of options outstanding at June 30, 2010 was approximately $14.2 million.

⁽⁶⁾	The weighted average outstanding contractual life of exercisable options at June 30, 2010 was 6.4 years.

The following tables summarize information about stock options outstanding and exercisable under the Assumed LTIP at June 30, 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 – 19.88	1,866,918	6.5	$	19.47	780,042	$	18.89
$26.07 – 30.17	163,908	7.0	$	29.98	—	$	—
$34.30 and above	8,700	8.0	$	34.30	—	$	—

	2,039,526	6.5	$	20.38	780,042	$	18.89

The Company recognized $1.3 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 June 30, 2010 and 2009, respectively, and $2.6 million and $3.0 million during the six months ended June 30, 2010 and 2009, respectively. ATN paid $0.4 million with respect to distribution equivalent rights (“DER”) for six months ended June 30, 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 June 30, 2010 and 2009, and during the six months ended June 30, 2010. At June 30, 2010, the Company had approximately $4.4 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. Expense recognized with respect to these commitments within general and administrative expense in the Company’s consolidated statements of operations was $0.3 million and $0.2 million, respectively during the three months ended June 30, 2010 and 2009, respectively, and $1.0 million and $0.3 million during the six months ended June 30, 2010 and 2009, 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 was included in other assets on the Company’s consolidated balance sheet. As of June 30, 2010 and December 31, 2009, the actuarial present value of the expected postretirement obligation due under its SERPs were $6.2 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):


	June 30, 2010			December 31, 2009
Other liabilities	$	(6,238	)	$	(3,968	)
Accumulated other comprehensive income		1,132			340
Deferred income tax asset		724			218

Net amount recognized	$	(4,382	)	$	(3,410	)

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

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 June 30, 2010, AHD had 1,099,375 phantom units and unit options outstanding under the AHD LTIP, with 955,150 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 DERs, which are the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions 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 June 30, 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 June 30, 2010, 132,713 units will vest within the following twelve months. All phantom units outstanding under the AHD LTIP at June 30, 2010 include DERs granted to the Participants by the AHD LTIP Committee. The amount paid with respect to AHD’s LTIP DERs was $14,000 for the six months ended June 30, 2009. This amount was recorded as an adjustment of non-controlling interests on the Company’s consolidated balance sheet. There were no amounts paid with respect to AHD’s LTIP DERs for the three months ended June 30, 2010 and 2009, and no DERs were paid during the six months ended June 30, 2010. The following table sets forth the AHD LTIP phantom unit activity for the periods indicated:


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010				2009
	Number of Units	Weighted Average Grant Date Fair Value		Number of Units	Weighted Average Grant Date Fair Value		Number of Units		Weighted Average Grant Date Fair Value		Number of Units		Weighted Average Grant Date Fair Value
Outstanding, beginning of period	138,375	$	22.14	181,300	$	22.77	138,875		$	22.18	226,300		$	22.73
Granted	6,000		6.22	—		—	6,000			6.22	—			—
Vested ⁽¹⁾	—		—	—		—	—			—	—			—
Forfeited	—		—	—		—	(500	)		32.28	(45,000	)		22.56

Outstanding, end of period⁽²⁾	144,375	$	21.48	181,300	$	22.77	144,375		$	21.48	181,300		$	22.77

Non-cash compensation expense (income) recognized (in thousands)		$	203		$	291			$	399			$	(17	)

(1)	There were no phantom units exercised for the six months ended June 30, 2010 and 2009.

(2)	The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2010 was $0.6 million.

At June 30, 2010, AHD had approximately $0.4 million of unrecognized compensation expense related to unvested phantom units outstanding under the AHD 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 June 30, 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 June 30, 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 June 30,
	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		955,000		$	20.54
Granted		—		—		—			—
Forfeited		—		—		—			—
Outstanding, end of period⁽¹⁾⁽²⁾		955,000	$	20.54		955,000		$	20.54
Weighted average fair value of unit options per unit granted during the period		—		—		—			—

Non-cash compensation expense recognized (in thousands)	$	155			$	222


	Six Months Ended June 30,
	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		—		—		100,000		$	0.61

Non-cash compensation expense (income) recognized (in thousands)	$	310			$	(351	)

⁽¹⁾	The weighted average remaining contractual life for outstanding options at June 30, 2010 was 6.6 years.

⁽²⁾	The aggregate intrinsic value of options outstanding at June 30, 2010 was approximately $0.1 million.

⁽³⁾	The weighted average remaining contractual life for options exercisable at June 30, 2010 was 6.6 years. There were no options exercised during the six months ended June 30, 2010 and 2009.

AHD 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:


	Six Months Ended June 30 , 2009
Expected dividend yield	7.0	%
Expected stock price volatility	40	%
Risk-free interest rate	2.3	%
Expected term (in years)	6.9

At June 30, 2010, AHD had approximately $0.2 million of unrecognized compensation expense related to unvested unit options outstanding under the AHD LTIP based upon the fair value of the awards.

APL Long-Term Incentive Plan

APL has a 2004 Long-Term Incentive Plan (“APL 2004 LTIP”), and a 2010 Long-Term Incentive Plan (“APL 2010 LTIP”), (collectively the “APL LTIPs”), in which officers, employees and non-employee managing board members of the General Partner and employees of the General Partner’s affiliates and consultants are eligible to participate. On June 15, 2010, APL’s unitholders approved the terms of the APL 2010 LTIP, which provides for the grant of options, phantom units, unit awards, unit appreciation rights and DERs. The APL LTIPs are administered by a committee (the “APL LTIP Committee”) appointed by the General Partner. Under the 2010 APL LTIP, the APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 3,000,000 common units, in addition to the 435,000 common units authorized in previous plans. At June 30, 2010, APL had 470,774 phantom units and unit options outstanding under the APL LTIPs, with 2,637,459 phantom units and unit options available for grant.

APL Phantom Units. A phantom unit entitles a grantee to receive a common unit upon vesting of the phantom unit. The APL LTIP Committee may grant a participant DERs, 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 determines the vesting period for phantom units. Through June 30, 2010, phantom units granted under the APL LTIPs generally had vesting periods of four years. In conjunction with the approval of the 2010 LTIP, the holders of 300,000 of the 375,000 equity indexed bonus units (“APL Bonus Units”) under APL’s subsidiary’s plan agreed to exchange their APL Bonus Units for an equivalent number of phantom units, effective as of June 1, 2010. These phantom units will vest over a two year period. The first tranche vested on June 1, 2010. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards will automatically vest upon a change of control, as defined in the APL LTIPs. Of the units outstanding under the APL LTIPs at June 30, 2010, 159,685 units will vest within the following twelve months. All phantom units outstanding under the APL LTIPs at June 30, 2010 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL LTIP DERs were $11,000 and $0.1 million for the three months and six months ended June 30, 2009, respectively. These amounts were recorded as a reduction of non-controlling interest on the Company’s consolidated balance sheet. No APL LTIP DERs were paid for the six months ended June 30, 2010.

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


	Three Months Ended June 30,								Six Months Ended June 30,
	2010				2009				2010				2009
	Number of Units		Weighted Average Grant Date Fair Value		Number of Units		Weighted Average Grant Date Fair Value		Number of Units		Weighted Average Grant Date Fair Value		Number of Units		Weighted Average Grant Date Fair Value
Outstanding, beginning of period	49,163		$	38.85	101,929		$	42.58	52,233		$	39.72	126,565		$	44.22
Granted	565,500			10.35	500			5.20	566,500			10.35	2,000			4.75
Vested ⁽¹⁾	(7,889	)		43.15	(25,208	)		47.02	(10,584	)		43.05	(35,094	)		47.22
Forfeited	—			—	(500	)		43.05	(1,375	)		43.99	(16,750	)		48.50

Outstanding, end of period⁽²⁾	606,774		$	12.23	76,721		$	40.88	606,774		$	12.23	76,721		$	40.88

Non-cash compensation expense recognized (in thousands)⁽³⁾			$	1,903			$	351			$	2,025			$	256

(1)	The intrinsic values for phantom unit awards exercised during the three months ended June 30, 2010 and 2009 were $0.1 million and $0.1 million, respectively, and $0.1 million and $0.2 million during the six months ended June 30, 2010 and 2009, respectively.

(2)	The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2010 was $5.9 million.

(3)	Non-cash compensation expense includes $1.8 million related to APL Bonus Units converted to phantom units during the three and six months ended June 30, 2010.

At June 30, 2010, APL had approximately $3.6 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIPs based upon the fair value of the awards.

APL Unit Options. A unit option entitles a grantee to purchase a common limited partner 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 June 30, 2010, unit options granted under the APL LTIPs generally will vest 25% on each of the next four anniversaries of the date of grant. Awards will automatically vest upon a change of control of APL, as defined in the APL LTIPs. There are 25,000 unit options outstanding under APL LTIPs at June 30, 2010 that will vest within the following twelve months.

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


	Three Months Ended June 30,
	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		100,000	$	6.24
Granted				—		—		—
Vested		—		—		—		—
Forfeited		—		—		—		—

Outstanding, end of period⁽¹⁾⁽²⁾		100,000	$	6.24		100,000	$	6.24

Options exercisable, end of period⁽¹⁾⁽³⁾		25,000	$	6.24		—		—

Weighted average fair value of unit options per unit granted during the period Weighted average fair value of unit		—	$	—		100,000	$	0.14

Non-cash compensation expense recognized (in thousands)	$	1			$	2


	Six Months Ended June 30,
	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
Vested		—		—		—		—
Forfeited		—		—		—		—

Outstanding, end of period⁽¹⁾⁽²⁾		100,000	$	6.24		100,000	$	6.24

Options exercisable, end of period⁽¹⁾⁽³⁾		25,000	$	6.24		—		—

Weighted average fair value of unit options per unit granted during the period Weighted average fair value of unit		—	$	—		100,000	$	0.14

Non-cash compensation expense recognized (in thousands)	$	2			$	4

(1)	The weighted average remaining contractual life for outstanding and exercisable options at June 30, 2010 was 8.5 years.

(2)	The aggregate intrinsic value of options outstanding at June 30, 2010 was $0.3 million.

(3)	There were no options exercised during the six months ended June 30, 2010 and 2009.

At June 30, 2010, APL had approximately $5,000 of unrecognized compensation expense related to unvested unit options outstanding under the APL LTIPs based upon the fair value of the awards.

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:


	Six Months Ended June 30, 2009
Expected dividend yield	11.0	%
Expected stock price volatility	20.0	%
Risk-free interest rate	2.2	%
Expected term (in years)	6.3

APL Employee Incentive Compensation Plan and Agreement

A wholly-owned subsidiary of APL has an incentive plan (the “APL Cash Plan”) which allows for equity-indexed cash incentive awards to employees of APL (the “Participants”), but expressly excludes as an eligible Participant any person that, at the time of the grant, is a “Named Executive Officer” of APL (as such term is defined under the rules of the Securities and Exchange Commission). The APL Cash Plan is administered by a committee appointed by the chief executive officer of APL. Under the APL Cash Plan, APL Bonus Units may be awarded to Participants at the discretion of the committee, which granted 325,000 APL Bonus Units during 2009. In addition, the subsidiary granted an award of 50,000 bonus units to an executive officer on substantially the same terms as the bonus units available under the APL Cash Plan (the bonus units issued under the APL Cash Plan and under the separate agreement are, for purposes hereof, referred to as “APL Bonus Units”). An APL Bonus Unit entitles the employee to receive the cash equivalent of the then-fair market value of an APL common limited partner unit, without payment of an exercise price, upon vesting of the APL Bonus Unit. APL Bonus Units vest ratably over a three year period from the date of grant and will automatically vest upon a change of control, death, or termination without cause, each as defined in the governing document. Vesting will terminate upon termination of employment with cause.

In conjunction with the approval of the APL 2010 LTIP, the holders of 300,000 of the 375,000 APL Bonus Units outstanding at June 16, 2010 agreed to exchange their APL Bonus Units for APL phantom units, retroactive to June 1, 2010. Of the 75,000 remaining APL Bonus Units, 25,000 APL Bonus Units vested on June 1, 2010. Of the remaining 50,000 outstanding APL Bonus Units at June 30, 2010, 25,000 APL Bonus Units will vest within the following twelve months. APL recognized compensation expense related to these awards based upon the fair value, which is re-measured each reporting period based upon the current fair value of the underlying APL common units. APL recognized a reduction of $2.1 million and a reduction of $0.8 million of compensation expense within general and administrative expense on the Company’s consolidated statements of operations in the three and six months ended June 30, 2010, respectively, with respect to the transfer of the APL Bonus Units to the APL 2010 LTIP and the vesting of the remaining awards. At June 30, 2010 and December 31, 2009, APL recognized $0.5 million and $1.2 million, respectively, within accrued liabilities on the Company’s consolidated balance sheets with regard to the awards, which represents their fair value at the respective dates.

NOTE 19 — 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 June 30,						Six Months Ended June 30,
	2010			2009⁽¹⁾			2010			2009⁽¹⁾
Gas and oil production
Revenues	$	69,188		$	69,979		$	133,097		$	141,922
Costs and expenses		(13,096	)		(9,803	)		(25,380	)		(21,089	)
Depreciation, depletion and amortization expense		(29,170	)		(26,115	)		(54,427	)		(53,125	)
Segment income	$	26,922		$	34,061		$	53,290		$	67,708

Well construction and completion
Revenues	$	43,295		$	63,367		$	115,937		$	175,735
Costs and expenses		(36,682	)		(53,701	)		(98,243	)		(149,098	)

Segment income	$	6,613		$	9,666		$	17,694		$	26,637

Other partnership management⁽²⁾
Revenues	$	13,865		$	4,754		$	26,002		$	8,321
Costs and expenses		(9,902	)		(5,889	)		(20,151	)		(8,940	)
Depreciation, depletion and amortization expense		(1,297	)		(1,158	)		(2,548	)		(2,175	)

Segment income (loss)	$	2,666		$	(2,293	)	$	3,303		$	(2,794	)

Atlas Pipeline⁽¹⁾
Revenues ⁽³⁾	$	257,092		$	165,551		$	540,370		$	329,645
Revenues – affiliates		—			6,617			—			16,766
Costs and expenses		(202,722	)		(146,594	)		(425,108	)		(298,494	)
Depreciation and amortization expense		(22,899	)		(22,999	)		(45,645	)		(45,667	)

Segment income	$	31,471		$	2,575		$	69,617		$	2,250

Reconciliation of segment income to net income before income tax provision
Segment income:
Gas and oil production	$	26,922		$	34,061		$	53,290		$	67,708
Well construction and completion		6,613			9,666			17,694			26,637
Other partnership management		2,666			(2,293	)		3,303			(2,794	)
Atlas Pipeline		31,471			2,575			69,617			2,250

Total segment income		67,672			44,009			143,904			93,801
General and administrative expenses⁽⁴⁾		(25,336	)		(21,657	)		(56,147	)		(49,553	)
Gain on asset sales		288,643			105,691			285,634			105,691
Interest expense⁽⁴⁾		(41,596	)		(41,948	)		(86,195	)		(76,568	)

Net income from continuing operations before income tax provision	$	289,383		$	86,095		$	287,196		$	73,371

Capital expenditures
Gas and oil production	$	87,715		$	30,768		$	152,927		$	80,386
Well construction and completion		—			—			—			—
Other partnership management		2,104			8,180			6,736			15,607
Atlas Pipeline		15,786			58,298			26,700			130,494
Corporate and other		443			258			598			420

Total capital expenditures	$	106,048		$	97,504		$	186,961		$	226,907


	June 30, 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	$	2,262,581	$	2,115,867
Well construction and completion		12,251		12,054
Other partnership management		48,913		44,311
Atlas Pipeline		2,079,299		2,135,860
Corporate and other		150,214		98,071

	$	4,553,258	$	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 6).

(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 $8.0 million and $12.1 million for the three and six months ended June 30, 2010, respectively, and losses of $18.6 million and $18.3 million during the three and six months ended June 30, 2009.

(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 20 — SUBSEQUENT EVENTS

On July 27, 2010, APL entered into an agreement with a subsidiary of Enbridge Energy Partners, L.P. (NYSE: EEP) to sell its Elk City and Sweetwater, Oklahoma natural gas gathering systems, the related processing and treating facilities (including the Prentiss treating facility) and the Nine Mile processing plant for $682.0 million in cash, subject to working capital adjustments. The transaction is expected to close prior to December 31, 2010, pending the satisfaction of customary closing conditions. APL intends to utilize the proceeds from the sale to repay a portion of its indebtedness under its senior secured term loan and revolving credit facility (see Note 10).

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. In addition to internally generated cash and borrowings under ATN’s credit facility, we have funded our drilling activities in the following manner:

•

In April 2010, we consummated an undivided joint venture with Reliance Industries Limited (“Reliance”), whereby we sold a 40% undivided joint venture interest in approximately 300,000 net acres (approximately 120,000 net acres to Reliance) of our core undeveloped Marcellus Shale leasehold acreage for $340.0 million of cash and $1,357.5 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 the remaining 75% of our respective portion of drilling and completion costs until the $1,357.5 million drilling carry is fully utilized. Therefore, we are responsible for only a net 15% of the capital costs required to drill and complete each well included in the area of mutual interest (“AMI”), which is calculated as 25% of our 60% interest in each well. We have five and a half years to utilize the drilling carry, subject to a two-year extension under certain conditions.

•

We are also a leading sponsor and manager of tax-advantaged direct investment natural gas and oil partnerships in the United States. Through June 30, 2010, we have funded a portion of our natural gas and oil well drilling by sponsoring and managing tax-advantaged investment partnerships. We generally structure our investment partnerships so that, upon formation, 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 June 30, 2010:


	Appalachia	Michigan/ Indiana	Total
Gross wells drilled:
Partnerships	—	27	27
Marcellus Shale joint venture	11	—	11
Production per day (Mcfed)	54,876	54,982	109,858
Direct and indirect gross well working interests	9,316	2,543	11,859

OTHER OWNERSHIP INTERESTS

In addition to our production operations, we also maintain ownership interests in the following entities at June 30, 2010:

•

Atlas Pipeline Holdings, L.P. (“Atlas Pipeline Holdings” or “AHD”), our publicly-traded subsidiary (NYSE: AHD). At June 30, 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 June 30, 2010, we had a 2.1% direct ownership interest in APL and AHD had a 12.5% ownership interest in APL. In June 2010, we purchased 8,000 $1,000 par value APL 12.0% Cumulative Class C Preferred Units; 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. 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 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 prior to the Merger on September 29, 2009 and AHD’s and APL’s net income.

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 NOARK as discontinued operations.

SUBSEQUENT EVENTS

RECENT DEVELOPMENTS

Marcellus Shale Joint Venture. Effective April 20, 2010, we consummated an undivided joint venture with Reliance, whereby we sold a 40% undivided joint venture interest in approximately 300,000 net acres (approximately 120,000 net acres to Reliance) of undeveloped core Marcellus Shale leasehold acreage in exchange for $340.0 million of cash and $1,357.5 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 the remaining 75% of our respective portion of drilling and completion costs until the $1,357.5 million drilling carry is fully utilized. Therefore, we are responsible for only a net 15% of the capital costs required to drill and complete each well included in the AMI for the duration of the drilling carry, which is calculated as 25% of our 60% interest in each well. 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 two separate transactions, to purchase an additional approximate 42,400 undeveloped core Marcellus Shale leasehold acres, which is contained within the joint venture’s AMI, for an average purchase price of $4,532 per acre. One of the transactions was for approximately 17,000 leasehold acres, for which we agreed to pay a total purchase price of $85.9 million, of which $43.9 million was paid at closing, with the remaining $41.9 million to be paid following the completion of verification of the seller’s legal title to the properties, but no later than October 21, 2010. Of the $43.9 million paid at closing of the transaction, we were reimbursed for $17.6 million by Reliance for its 40% ownership interest. In connection with this transaction, we recorded a $41.9 million liability for the second installment of the purchase price and a $16.8 million receivable from Reliance for its 40% portion of the amount on our consolidated balance sheet at June 30, 2010. The second transaction was for approximately 25,400 leasehold acres, for which we agreed to pay a total purchase price of $106.0 million at closing, which is expected to be on or prior to September 5, 2010. Pursuant to our joint venture agreement, Reliance is obligated for its 40% portion of the cost of these transactions.

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.

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, National Fuel Resources, Energy Mark LLC, Interstate Gas Supply, 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. We generally have funded a portion of our drilling activities through sponsorship of tax-advantaged investment partnerships. In addition to providing capital for our drilling activities, our investment partnerships are a source of fee-based revenues, which are not directly dependent on natural gas and oil prices. 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;

•

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. 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.

Natural Gas Supply and Outlook. While commodity prices for natural gas were at lower levels during the three months ended June 30, 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 decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce.

RESULTS OF OPERATIONS

GAS AND OIL PRODUCTION

Production Profile. Currently, we have focused our natural gas 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.

The following table presents the number of wells we drilled, both gross and for our interest, and the number of gross wells we turned in line during the three and six months ended June 30, 2010 and 2009:


	Three Months Ended June 30		Six Months Ended June 30
	2010	2009	2010	2009
Gross wells drilled:
Appalachia:
Partnerships	—	21	10	98
Marcellus Shale joint venture	11	—	11	—
Our direct interest	—	—	—	2

	11	21	21	100


Michigan/Indiana:
Partnerships	27	10	27	36
Our direct interest	—	3	—	3

	27	13	27	39


Gross wells drilled	38	34	48	139


Our share of gross wells drilled⁽¹⁾:
Appalachia:
Partnerships	—	5	2	22
Marcellus Shale joint venture	6	—	6	—
Our direct interest	—	—	—	1

	6	5	8	23


Michigan/Indiana:
Partnerships	7	3	7	8
Our direct interest	—	1	—	1

	7	4	7	9


Our share of gross wells drilled	13	9	15	32


Gross wells turned in line:
Appalachia:
Partnerships	32	82	67	214
Marcellus Shale joint venture	—	—	—	—
Our direct interest	6	1	10	2

	38	83	77	216


Michigan/Indiana:
Partnerships	13	14	31	29
Our direct interest	3	5	3	12

	16	19	34	41


Gross wells turned in line	54	102	111	257

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

Production Volumes. The following table presents our total net gas and oil production volumes and production per day during the three and six months ended June 30, 2010 and 2009:


	Three Months Ended June 30,			Six Months Ended June 30,
	2010		2009	2010		2009
Production:⁽¹⁾⁽²⁾
Appalachia:⁽³⁾
Natural gas (MMcf)	4,522		3,710	8,124		7,302
Oil (000’s Bbls)	79	⁽⁴⁾	43	157	⁽⁴⁾	78

Total (MMcfe)	4,994		3,968	9,065		7,772

Michigan/Indiana:
Natural gas (MMcf)	4,987		5,283	9,894		10,526
Oil (000’s Bbls)	3	⁽⁴⁾	1	6	⁽⁴⁾	2

Total (MMcfe)	5,003		5,290	9,928		10,536

Total:
Natural gas (MMcf)	9,509		8,993	18,018		17,828
Oil (000’s Bbls)	82	⁽⁴⁾	44	163	⁽⁴⁾	80

Total (MMcfe)	9,997		9,257	18,993		18,307


Production per day: ⁽¹⁾⁽²⁾
Appalachia:⁽³⁾
Natural gas (Mcfd)	49,689		40,770	44,886		40,341
Oil (Bpd)	864	⁽⁴⁾	472	866	⁽⁴⁾	433

Total (Mcfed)	54,876		43,603	50,084		42,939

Michigan/Indiana:
Natural gas (Mcfd)	54,806		58,058	54,662		58,154
Oil (Bpd)	29	⁽⁴⁾	11	32	⁽⁴⁾	9

Total (Mcfed)	54,982		58,127	54,851		58,207

Total:
Natural gas (Mcfd)	104,495		98,828	99,547		98,495
Oil (bpd)	894	⁽⁴⁾	484	898	⁽⁴⁾	442

Total (Mcfed)	109,858		101,730	104,935		101,146

⁽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 and six months ended June 30, 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 and six months ended June 30, 2010 and 2009, along with our average production costs, taxes, and transmission and compression costs in each of the reported periods:


	Three Months Ended June 30,					Six Months Ended June 30,
	2010			2009		2010			2009
Production revenues (in thousands):
Appalachia:⁽¹⁾
Natural gas revenue	$	26,178		$	29,527	$	48,601		$	57,071
Oil revenue		4,640	⁽⁶⁾		3,029		8,910	⁽⁶⁾		5,079

Total revenues	$	30,818		$	32,556	$	57,511		$	62,150

Michigan/Indiana:
Natural gas revenue	$	38,284		$	37,370	$	75,403		$	79,700
Oil revenue		86	⁽⁶⁾		53		183	⁽⁶⁾		72

Total revenues	$	38,370		$	37,423	$	75,586		$	79,772

Total:
Natural gas revenue	$	64,462		$	66,897	$	124,004		$	136,771
Oil revenue		4,726	⁽⁶⁾		3,082		9,093	⁽⁶⁾		5,151

Total revenues	$	69,188		$	69,979	$	133,097		$	141,922


Average sales price:⁽²⁾
Natural gas (per Mcf):
Total realized price, after hedge^{(3) (4)}	$	7.09		$	7.64	$	7.34		$	7.86
Total realized price, before hedge^{(3) (4)}	$	4.32		$	3.65	$	4.96		$	4.42
Oil (per Bbl):
Total realized price, after hedge	$	78.20		$	70.01	$	75.12		$	64.41
Total realized price, before hedge	$	71.72		$	54.06	$	69.67		$	46.63

Production costs (per Mcfe):⁽²⁾
Appalachia:⁽¹⁾
Lease operating expenses⁽⁵⁾	$	0.93		$	1.08	$	0.96		$	1.06
Production taxes		0.02			0.02		0.03			0.03
Transportation and compression		0.61			0.73		0.68			0.80

	$	1.55		$	1.84	$	1.66		$	1.89

Michigan/Indiana:
Lease operating expenses	$	0.82		$	0.62	$	0.79		$	0.71
Production taxes		0.26			0.23		0.30			0.27
Transportation and compression		0.23			0.25		0.23			0.25

	$	1.31		$	1.10	$	1.32		$	1.23

Total:
Lease operating expenses⁽⁵⁾	$	0.87		$	0.82	$	0.87		$	0.86
Production taxes		0.14			0.14		0.17			0.17
Transportation and compression		0.42			0.45		0.45			0.48

	$	1.43		$	1.42	$	1.49		$	1.51

⁽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 and six months ended June 30, 2010 and 2009. Including the effect of these allocations, the average realized gas sales price were $6.76 per Mcf ($3.99 per Mcf before the effects of financial hedging) and $7.49 per Mcf ($3.50 per Mcf before the effects of financial hedging) for the three months ended June 30, 2010 and 2009, respectively, and $6.89 per Mcf ($4.51 per Mcf before the effects of financial hedging) and $7.79 per Mcf ($4.35 per mcf before the effects of financial hedging) for the six months ended June 30, 2010 and 2009, respectively.

⁽⁴⁾

Includes adjustments of $(0.1) million and $0.5 million for the three months ended June 30, 2010 and 2009, respectively, and $0.2 million and $2.1 million for the six months ended June 30, 2010 and 2009, respectively, related to cash proceeds received and payments made in June 2007 from the settlement of ineffective derivatives associated with the acquisition of the Company’s Michigan operations.

⁽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. Including the effects of these costs, Appalachia lease operating expenses per Mcfe were $0.68 per Mcfe ($1.31 per Mcfe for total production costs) and $0.98 per Mcfe ($1.74 per Mcfe for total production costs) for the three months ended June 30, 2010 and 2009, respectively, and $0.64 per Mcfe ($1.35 per Mcfe for total production costs) and $1.01 per Mcfe ($1.84 per Mcfe for total production costs) for the six months ended June 30, 2010 and 2009, respectively. Including the effects of these costs, total lease operating expenses per Mcfe were $0.75 per Mcfe ($1.31 per Mcfe for total production costs) and $0.78 per Mcfe ($1.37 per Mcfe for total production costs) for the three months ended June 30, 2010 and 2009, respectively, and $0.72 per Mcfe ($1.34 per Mcfe for total production costs) and $0.84 per Mcfe ($1.49 per Mcfe for total production costs) for the six months ended June 30, 2010 and 2009, respectively.

⁽⁶⁾	Includes NGL production revenue for the three and six months ended June 30, 2010.

Three Months Ended June 30, 2010 Compared with the Three Months Ended June 30, 2009. Total natural gas revenues were $64.5 million for the three months ended June 30, 2010, a decrease of $2.4 million from $66.9 million for the three months ended June 30, 2009. This decrease consisted of a $4.2 million decrease attributable to lower realized natural gas prices and a $1.8 million increase in gas revenues allocated to the investor partners within our investment partnerships for the three months ended June 30, 2010 compared with the prior year period, partially offset by a $3.7 million increase attributable to higher natural gas production volumes. Total oil revenues were $4.7 million for the three months ended June 30, 2010, an increase of $1.6 million from $3.1 million for the comparable prior year period. This increase resulted primarily from a $1.7 million increase from the sale of natural gas liquids and a $0.3 million increase associated with higher average realized oil prices, partially offset by a $0.4 million decrease associated with lower oil production volumes.

Appalachia production costs were $6.6 million for the three months ended June 30, 2010, an increase of $2.6 million from $4.0 million for the three months ended June 30, 2009. This increase was principally due to a $2.9 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 $0.8 million increase associated with our proportionate share of lease operating expenses associated with our revenue that was allocated to the investor partners within our investment partnerships. Michigan/Indiana production costs were $6.5 million for the three months ended June 30, 2010, an increase of $0.7 million from $5.8 million for the comparable prior year period. This increase was primarily attributable to a $0.2 million increase in compression station expenses, a $0.2 million increase in gas treating expenses and a $0.1 million increase for production-related taxes.

Six Months Ended June 30, 2010 Compared with the Six Months Ended June 30, 2009. Total natural gas revenues were $124.0 million for the six months ended June 30, 2010, a decrease of $12.8 million from $136.8 million for the six months ended June 30, 2009. This decrease consisted of a $7.4 million decrease attributable to lower realized natural gas prices and a $6.8 million increase in gas revenues allocated to the investor partners within our investment partnerships for the six months ended June 30, 2010 compared with the prior year period, partially offset by a $1.4 million increase attributable to higher natural gas production volumes. Total oil revenues were $9.1 million for the six months ended June 30, 2010, an increase of $3.9 million from $5.2 million for the comparable prior year period. This increase resulted primarily from a $3.3 million increase from the sale of natural gas liquids and a $0.9 million increase associated with higher average realized oil prices, partially offset by a $0.2 million decrease associated with lower oil production volumes.

Appalachia production costs were $12.3 million for the six months ended June 30, 2010, an increase of $4.2 million from $8.1 million for the six months ended June 30, 2009. This increase was principally due to a $6.2 million decrease in the elimination of intercompany transportation costs subsequent to the formation of the Laurel Mountain joint venture mentioned previously. This amount was partially offset by a $2.4 million increase associated with our proportionate share of lease operating expenses associated with our revenue that was allocated to the investor partners within our investment partnerships. Michigan/Indiana production costs were $13.1 million for the six months ended June 30, 2010, an increase of $0.1 million from $13.0 million for the comparable prior year period.

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 amounts of drilling partnership investor capital raised and deployed (in thousands), as well as the number of gross and net development wells we drilled for our investment partnerships during the three and six months ended June 30, 2010 and 2009. We drilled one exploratory well during the three and six months ended June 30, 2010. There were no exploratory wells drilled during the three and six months ended June 30, 2009:


	Three Months Ended June 30				Six Months Ended June 30
	2010		2009		2010		2009
Drilling partnership investor capital:
Raised	$	29,417	$	122,000	$	29,417	$	122,000
Deployed	$	43,295	$	63,367	$	115,937	$	175,735

Gross partnership wells drilled:
Appalachia		—		21		10		98
Michigan/Indiana		27		10		27		36

Total		27		31		37		134


Net partnership wells drilled:
Appalachia		—		20		10		85
Michigan/Indiana		23		9		23		32

Total		23		29		33		117

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 June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
Average construction and completion:
Revenue per well	$	2,062	$	2,263	$	2,108	$	1,302
Cost per well		1,747		1,918		1,786		1,105

Gross profit per well	$	315	$	345	$	322	$	197


Gross profit margin	$	6,613	$	9,666	$	17,694	$	26,637


Partnership net wells associated with revenue recognized⁽¹⁾:
Marcellus Shale		7		18		27		42
Chattanooga Shale		2		1		8		6
Michigan/Indiana		12		5		20		29
Other – shallow		—		4		—		58

		21		28		55		135

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

Three Months Ended June 30, 2010 Compared with the Three Months Ended June 30, 2009. Well construction and completion segment margin was $6.6 million for the three months ended June 30, 2010, a decrease of $3.1 million from $9.7 million for the three months ended June 30, 2009. This decrease was due to a $2.2 million decrease associated with a decline in the number of wells recognized for revenue within the investment partnerships and a $0.9 million decrease associated with lower 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 decreased due to a shift to drilling Marcellus wells for the Company’s own account or within its joint venture during the second quarter 2010 compared with drilling such wells within the investor partnerships during the second quarter 2009.

Our consolidated balance sheet at June 30, 2010 includes $36.0 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 third quarter of 2010.

Six Months Ended June 30, 2010 Compared with the Six Months Ended June 30, 2009. Well construction and completion segment margin was $17.7 million for the six months ended June 30, 2010, a decrease of $8.9 million from $26.6 million for the six months ended June 30, 2009. This decrease was due primarily to a $25.7 million decrease associated with a decline in the number of wells recognized for revenue within the investment partnerships, partially offset by a $16.8 million increase due to increased gross profit per well. Average cost and revenue per well have increased due to a shift, principally during the first quarter 2010, from drilling less expensive shallow wells to more expensive deep or horizontal shale wells in both Appalachia and Michigan/Indiana during the six months ended June 30, 2010 in comparison to the comparable prior year period.

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.

Three Months Ended June 30, 2010 Compared with the Three Months Ended June 30, 2009. Administration and oversight fee revenues were $1.9 million for the three months ended June 30, 2010, a decrease of $0.7 million from $2.6 million for the three months ended June 30, 2009. This decrease was primarily due to fewer wells drilled during the current year period in comparison to the prior year period.

Six Months Ended June 30, 2010 Compared with the Six Months Ended June 30, 2009. Administration and oversight fee revenues were $3.9 million for the six months ended June 30, 2010, a decrease of $2.6 million from $6.5 million for the six months ended June 30, 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.

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.

Three Months Ended June 30, 2010 Compared with the Three Months Ended June 30, 2009. Well services revenues were $5.7 million for the three months ended June 30, 2010, an increase of $0.9 million from $4.8 million for the three months ended June 30, 2009. Well services expenses were $2.7 million for three months ended June 30, 2010, an increase of $0.6 million from $2.1 million for the three months ended June 30, 2009. These increases were primarily attributable to an increase in the number of producing wells.

Six Months Ended June 30, 2010 Compared with the Six Months Ended June 30, 2009. Well services revenues were $11.1 million for the six months ended June 30, 2010, an increase of $1.2 million from $9.9 million for the six months ended June 30, 2009. Well services expenses were $5.3 million for six months ended June 30, 2010, an increase of $0.8 million from $4.5 million for the six months ended June 30, 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 realized natural gas sales price (adjusted for the settlement of natural gas derivative instruments). However, in most of our direct investment partnerships, we collect a gathering fee of 13% of the realized natural gas sales price per the respective partnership agreement. As a result 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 was included in gas and oil production expense. The net effect of the elimination amounts was 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 June 30,						Six Months Ended June 30,
	Three Months Ended June 30,						Six Months Ended June 30,
Transmission, Gathering and Processing:	2010			2009⁽¹⁾			2010			2009⁽¹⁾
Atlas Energy:
Revenue	$	5,778		$	5,389		$	10,239		$	10,112
Expense		(7,205	)		(8,752	)		(14,876	)		(16,232	)

Gross Margin	$	(1,427	)	$	(3,363	)	$	(4,637	)	$	(6,120	)

Atlas Pipeline:
Revenue	$	245,639		$	187,331		$	520,844		$	356,424
Expense		(202,722	)		(146,594	)		(425,108	)		(298,494	)

Gross Margin	$	42,917		$	40,737		$	95,736		$	57,930

Eliminations:
Revenue	$	—		$	(6,617	)	$	—		$	(16,766	)
Expense		—			4,983			—			11,836

Gross Margin	$	—		$	(1,634	)	$	—		$	(4,930	)

Total:
Revenue	$	251,417		$	186,103		$	531,083		$	349,770
Expense		(209,927	)		(150,363	)		(439,984	)		(302,890	)

Gross Margin	$	41,490		$	35,740		$	91,099		$	46,880

⁽¹⁾	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system.

Three Months Ended June 30, 2010 Compared with the Three Months Ended June 30, 2009. Our net gathering fee expense for the three months ended June 30, 2010 was $1.4 million compared with $3.4 million for the three months ended June 30, 2009. This favorable decrease was principally due to lower average gas sales prices between periods, partially offset by higher Appalachia production volumes.

Transmission, gathering and processing margin for APL was $42.9 million for the three months ended June 30, 2010 compared with $40.7 million for the three months ended June 30, 2009. This increase was due principally to higher average natural gas liquids and crude oil commodity prices between periods.

Six Months Ended June 30, 2010 Compared with the Six Months Ended June 30, 2009. Our net gathering fee expense for the six months ended June 30, 2010 was $4.6 million compared with $6.1 million for the six months ended June 30, 2009. This favorable decrease was principally due to lower average gas sales prices between periods, partially offset by higher Appalachia production volumes.

Transmission, gathering and processing margin for APL was $95.7 million for the six months ended June 30, 2010 compared with $57.9 million for the six months ended June 30, 2009. This increase was due principally to higher average natural gas liquids and crude oil commodity prices between periods.

Gain (loss) on Mark-to-Market Derivatives

Three Months Ended June 30, 2010 Compared with the Three Months Ended June 30, 2009. Gain on mark-to-market derivatives was $8.1 million for the three months ended June 30, 2010 compared with a loss of $18.6 million for the three months ended June 30, 2009. This favorable movement was due primarily to a $33.9 million favorable variance related to APL’s cash settlements on derivatives that were not designated as hedges, a $15.6 million favorable movement in non-cash derivative gains related to early terminations of a portion of its derivative contracts and a $3.5 million favorable movement in APL’s non-cash mark-to-market adjustments on outstanding derivative contracts, partially offset by an unfavorable movement of $26.3 million related to cash settlements on net cash derivative expense related to the early termination of a portion of its derivative contracts.

Six Months Ended June 30, 2010 Compared with the Six Months Ended June 30, 2009. Gain on mark-to-market derivatives was $12.2 million for the six months ended June 30, 2010 compared with a loss of $18.3 million for the six months ended June 30, 2009. This favorable movement was due primarily to a $57.4 million favorable movement in APL’s non-cash mark-to-market adjustments on outstanding derivative contracts and a $25.6 million favorable movement in non-cash derivative gains related to early terminations of a portion of its derivative contracts, partially offset by an unfavorable movement of $45.5 million related to cash settlements on net cash derivative expense related to the early termination of a portion of its derivative contracts and a $6.4 million unfavorable variance due to APL’s cash settlements on derivatives that were not designated as hedges.

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 June 30,				Six Months Ended June 30,
	2010		2009⁽¹⁾		2010		2009⁽¹⁾
General and Administrative expenses:
Atlas Energy	$	18,515	$	14,345	$	38,742	$	32,099
Atlas Pipeline and Atlas Pipeline Holdings		6,821		7,312		17,405		17,454

Total	$	25,336	$	21,657	$	56,147	$	49,553

⁽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 $25.3 million for the three months ended June 30, 2010 compared with $21.7 million for the three months ended June 30, 2009. This increase was due to our $4.2 million increase, partially offset by a $0.6 million decrease related to APL and AHD. Our $4.2 million increase was primarily related to a $2.0 million increase in expenses related to wages and other corporate activities due to the growth of our business and a $2.2 million increase in non-cash stock compensation expense. APL and AHD’s $0.6 million decrease was principally due to a $1.8 million decrease in expenses related to wages, partially offset by a $1.2 million increase in non-cash stock compensation expense.

Total general and administrative expenses, including amounts reimbursed to affiliates, increased to $56.1 million for the six months ended June 30, 2010 compared with $49.6 million for the six months ended June 30, 2009. This $6.5 million increase was due to our $6.6 million increase, partially offset by a $0.1 million decrease related to APL and AHD. Our $6.6 million increase was primarily related to a $5.7 million increase in expenses related to wages and other corporate activities due to the growth of our business and a $0.8 million increase in non-cash stock compensation expense. APL and AHD’s $0.1 million decrease was principally due to a $2.7 million decrease in expenses related to wages, partially offset by a $2.6 million increase in non-cash stock compensation expense.

Depreciation, Depletion and Amortization

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009⁽¹⁾		2010		2009⁽¹⁾
Depreciation, depletion and amortization:
Atlas Energy	$	30,467	$	27,273	$	56,975	$	55,300
Atlas Pipeline and Atlas Pipeline Holdings		22,899		22,999		45,645		45,667

Total	$	53,366	$	50,272	$	102,620	$	100,967

(1)	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system.

Total depreciation, depletion and amortization increased to $53.4 million for the three months ended June 30, 2010 compared with $50.3 million for the comparable prior year period, due primarily to a $3.1 million increase in our depletion expense. Total depreciation, depletion and amortization increased to $102.6 million for the six months ended June 30, 2010 compared with $101.0 million for the comparable prior year period, due primarily to a $1.3 million increase in our depletion expense.

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Depletion expense (in thousands):
Appalachia	$	14,319		$	12,159		$	24,829		$	25,261
Michigan/Indiana		14,851			13,956			29,598			27,864

Total	$	29,170		$	26,115		$	54,427		$	53,125

Depletion expense as a percentage of gas and oil production revenue		42	%		37	%		41	%		37	%

Depletion per Mcfe:
Appalachia	$	2.87		$	3.06		$	2.74		$	3.25
Michigan/Indiana	$	2.97		$	2.64		$	2.98		$	2.64
Total	$	2.92		$	2.82		$	2.87		$	2.90

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. For the three months ended June 30, 2010, depletion expense increased $3.1 million to $29.2 million for the compared with $26.1 million for the three months ended June 30, 2009. Our depletion expense of oil and gas properties as a percentage of oil and gas revenues was 42% for the three months ended June 30, 2010, compared with 37% for the three months ended June 30, 2009. Depletion expense per Mcfe was $2.92 for the three months ended June 30, 2010, an increase of $0.10 per Mcfe from $2.82 for the three months ended June 30, 2009. Depletion expense increased between periods principally due an overall increase in production volumes, partially offset by a $156.4 million write-down of our Upper Devonian field during the three months ended December 31, 2009.

For the six months ended June 30, 2010, depletion expense increased $1.3 million to $54.4 million for the three months ended June 30, 2010 compared with $53.1 million for the six months ended June 30, 2009. Our depletion expense of oil and gas properties as a percentage of oil and gas revenues was 41% for the six months ended June 30, 2010, compared with 37% for the six months ended June 30, 2009. Depletion expense per Mcfe was $2.87 for the six months ended June 30, 2010, a decrease of $0.03 per Mcfe from $2.90 for the six months ended June 30, 2009. Depletion expense increased between periods principally due an overall increase in production volumes, partially offset by a $156.4 million write-down of our Upper Devonian field during the three months ended December 31, 2009.

Gain on Asset Sales

Gain on asset sales, net of related transaction costs, of $288.6 million and $285.6 million for the three and six months ended June 30, 2010, respectively, principally represents the gain recognized on the sale of acreage to Reliance in connection with the formation of our Marcellus Shale joint venture, partially offset by the loss recognized on our sale of a processing plant outside of our core operating area during the first quarter 2010. Gain on asset sales of $105.7 million for both the three and six months ended June 30, 2009 principally represents the gain recognized on APL’s sale of a 51% ownership interest in its Appalachia natural gas gathering system to the Laurel Mountain joint venture.

Interest Expense

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009⁽¹⁾			2010			2009⁽¹⁾
Interest Expense:
Atlas Energy	$	16,987		$	15,124		$	35,019		$	28,108
Atlas Pipeline and Atlas Pipeline Holdings		25,106			26,852			52,155			48,517
Eliminations		(497	)		(28	)		(979	)		(57	)

Total	$	41,596		$	41,948		$	86,195		$	76,568

(1)	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system.

Total interest expense decreased to $41.6 million for the three months ended June 30, 2010 as compared with $41.9 million for the three months ended June 30, 2009. This $0.3 million decrease was primarily due to a $1.7 million decrease related to APL and AHD and a $0.5 million favorable increase in intercompany eliminations related to AHD’s promissory note, partially offset by our $1.9 million increase. Our $1.9 million increase was principally attributable to a $6.1 million increase associated with ATN’s issuance of $200.0 million of 12.125% senior unsecured notes in July 2009, partially offset by a $2.9 million decrease associated with lower average borrowings under ATN’s credit facility and a $2.1 million favorable movement in capitalized interest. The $2.9 million decrease associated with ATN’s credit facility was primarily due to the repayment of amounts outstanding subsequent to the formation of our Marcellus Shale joint venture. The $1.7 million decrease in interest expense for APL and AHD was due principally to a $2.1 million decrease in the amortization of deferred financing costs, which was accelerated during the three months ended June 30, 2009 following the retirement of a portion of APL’s term loan.

Total interest expense increased to $86.2 million for the six months ended June 30, 2010 as compared with $76.6 million for the six months ended June 30, 2009. This $9.6 million increase was primarily due to our $7.0 million increase and a $3.6 million increase related to APL and AHD, partially offset by a $0.9 million decrease from eliminations of intercompany interest related to AHD’s promissory note. Our $7.0 million increase was principally attributable to a $12.4 million increase associated with ATN’s issuance of $200.0 million of 12.125% senior unsecured notes in July 2009, partially offset by a $3.9 million decrease associated with lower average borrowings under ATN’s credit facility and a $3.0 million favorable increase in capitalized interest. The $3.9 million decrease associated with ATN’s credit facility was primarily due to the repayment of amounts outstanding subsequent to the formation of our Marcellus Shale joint venture. The $3.6 million increase in interest expense for APL and AHD was due principally a $2.7 million increase in interest expense associated with APL’s term loan, a $1.5 million reduction in capitalized interest and a $1.4 million decrease in amortization of deferred finance costs, partially offset by a $0.8 million increase in interest expense associated with outstanding borrowings on APL’s revolving credit facility.

Income Taxes

Income tax expense related to net income from continuing operations attributable to common shareholders for the three months ended June 30, 2010 was $113.2 million as compared with $3.7 million for the three months ended June 30, 2009. Our effective income tax rate related to net income from continuing operations attributable to common shareholders was 39% for both the three months ended June 30, 2010 and 2009. 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.

Income tax expense related to net income from continuing operations attributable to common shareholders for the six months ended June 30, 2010 was $111.8 million as compared with $6.3 million for the six months ended June 30, 2009. Our effective income tax rate related to net income from continuing operations attributable to common shareholders was 39% for both the six months ended June 30, 2010 and 2009. 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 39% for the year ending 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 $51.3 million and $59.8 million for the three and six months ended June 30, 2009, respectively, net of related taxes of $2.3 million and $2.7 million, respectively.

Income Attributable to Non-Controlling Interests

Income attributable to non-controlling interests was $0.3 million for the three months ended June 30, 2010 compared with $124.3 million for the comparable prior year period. Income attributable to non-controlling interests was $1.6 million for the six months ended June 30, 2010 compared with $112.9 million for the comparable prior year period. Income 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 APL’s net earnings between periods.

LIQUIDITY AND CAPITAL RESOURCES

General

Our primary sources of liquidity are cash generated from operations, funding provided by the drilling carry associated with our Marcellus joint venture for a portion of our capital expenditures (see “Recent Developments”), 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 cash generated from operations, cash provided by our joint venture drilling carry, 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, our joint venture drilling carry 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, our joint venture drilling carry 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.

ATN Revolving Credit Facility

At June 30, 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 June 30, 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 June 30, 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. Based on the definitions contained in ATN’s credit facility, its ratio of current assets to current liabilities was 2.3 to 1.0 and its ratio of total debt to EBITDA was 2.7 to 1.0 at June 30, 2010.

Cash Flows – Six Months Ended June 30, 2010 Compared with the Six Months Ended June 30, 2009

Net cash provided by operating activities of $85.3 million for the six months ended June 30, 2010 represented an unfavorable movement of $34.4 million from net cash provided by operating activities of $119.7 million for the comparable prior year period. The decrease was derived principally from a $196.4 million decrease in net income excluding non-cash items, a $33.8 million unfavorable movement in working capital changes, and a $14.2 million unfavorable movement in cash provided by discontinued operations, partially offset by a $104.8 million favorable movement in deferred taxes and a $45.5 million favorable movement in distributions paid to non-controlling interest holders. The non-cash charges which impacted net income include a $180.0 million unfavorable movement in gains on asset sales and an unfavorable movement in non-cash gain on derivatives of $70.1 million, partially offset by a $48.5 million increase in net income and a $9.2 million favorable movement in non-cash compensation expense. The movement in non-cash derivative losses resulted from significant increase in commodity prices from January 1, 2009 through June 30, 2009 and their $64.6 million unfavorable impact on the fair value of derivative contracts we and APL had for future periods. The movement in cash distributions to non-controlling interest holders was 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 an $81.7 million unfavorable movement in accounts payable and other current liabilities, partially offset by a $47.9 million favorable movement in accounts receivable and other current assets.

Net cash provided by investing activities of $119.4 million for the six months ended June 30, 2010 represented an unfavorable movement of $34.4 million from $153.8 million for the comparable prior year period. This unfavorable movement was principally due to a $290.6 million decrease in net cash provided by investing activities related to discontinued operations and a $6.3 million unfavorable movement in investments in unconsolidated subsidiaries, including our investment in Lightfoot, partially offset by a $219.5 million increase in proceeds from assets sales and a $39.9 million favorable movement in capitalized expenditures. See further discussion of capital expenditures under “- Capital Requirements”.

Net cash used in financing activities of $133.4 million for the six months ended June 30, 2010 represented a favorable movement of $163.2 million from $296.6 million for the comparable prior year period. This favorable movement was principally due to a $201.6 million decrease in repayments of amounts outstanding under ATN’s, AHD’s and APL’s respective credit facilities and a $30.3 million favorable movement related to APL’s issuances of units, partially offset by a $86.0 million reduction in subsidiary borrowings under their respective credit facilities.

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 June 30,				Six Months Ended June 30,
	2010		2009⁽¹⁾		2010		2009⁽¹⁾
Atlas Energy	$	90,262	$	39,206	$	160,261	$	96,413
Atlas Pipeline		15,786		58,298		26,700		130,494

Total	$	106,048	$	97,504	$	186,961	$	226,907

⁽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 June 30, 2010, our capital expenditures related primarily to $53.6 million incurred for leasehold acquisition costs, an increase of $47.1 million when compared with the prior year period, $22.7 million for wells drilled exclusively for our own account and that of our Marcellus joint venture, an increase of $24.5 million when compared with the prior year period, and $10.1 million of investments in our investment partnerships, a decrease of $12.1 million when compared with the prior year period. Capital expenditures for wells drilled exclusively for our own account and that of our Marcellus joint venture includes $1.1 million of expenditures which represents our 15% contribution for joint venture capital expenditures under the joint venture agreement for the three months ended June 30, 2010. At June 30, 2010, the remaining balance of our drilling carry from Reliance was $1,355.3 million.

During the six months ended June 30, 2010, our capital expenditures related primarily to $76.1 million incurred for leasehold acquisition costs, an increase of $59.5 million when compared with the prior year period, $44.3 million for wells drilled exclusively for our own account and that of our Marcellus joint venture, an increase of $34.8 million when compared with the prior year period, and $25.1 million of investments in our investment partnerships, a decrease of $23.3 million when compared with the prior year period. Capital expenditures for wells drilled exclusively for our own account and that of our Marcellus joint venture includes $1.1 million of expenditures which represents our 15% contribution for joint venture capital expenditures under the joint venture agreement for the six months ended June 30, 2010.

We believe cash flows from operations, our joint venture drilling carry, amounts available under ATN’s credit facility and temporary use of funds raised through investment partnerships 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, funds provided by our joint venture drilling carry, borrowings under ATN’s credit facility, and 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 $15.8 million for the three months ended June 30, 2010, compared with $58.3 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. APL’s capital expenditures decreased to $26.7 million for the six months ended June 30, 2010, compared with $130.5 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 June 30, 2010, we and APL are committed to expend approximately $85.5 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

OFF BALANCE SHEET ARRANGEMENTS

As of June 30, 2010, our off-balance sheet arrangements are limited to our guarantee of Crown Drilling of Pennsylvania, LLC’s $10.1 million credit agreement, ATN’s and APL’s letters of credit outstanding of $1.6 million and $8.1 million, respectively, and commitments to spend $85.5 million related to our drilling and completion expenditures and APL’s capital expenditures.

DIVIDENDS

We paid cash dividends of $2.0 million for the six months ended June 30, 2009. No dividends were paid for the three and six months ended June 30, 2010 or for the three months ended June 30, 2009. 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.

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 over the book carrying amount per unit.

Atlas Pipeline Partners and Atlas Pipeline Holdings

In June 2010, APL sold 8,000 newly-created 12% Cumulative Class C Limited Partner Preferred Units (the “APL Class C Preferred Units”) to us for cash consideration of $1,000 per APL Class C Preferred Unit (the “Face Value”). The APL Class C Preferred Units are redeemable by APL for an amount equal to the Face Value of the units being redeemed plus all accrued but unpaid dividends. We are entitled to distributions of 12% per annum, paid quarterly on the same date as the distribution payment date for APL’s common units. The sale of the APL Class C Preferred Units to us was exempt from the registration requirements of the Securities Act of 1933. We are entitled to receive the distributions on the APL Class C Preferred units pro rata from the July 1, 2010 commencement date.

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

In August 2009, APL sold 2,689,765 common units in a private placement at an offering price of $6.35 per unit, yielding net proceeds of approximately $16.1 million. APL also received a capital contribution from 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 a 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 was 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 June 30, 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.

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 Plans (“SERPs”). 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 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 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 SERP in a rabbi trust was 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 June 30, 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 June 30, 2010, ATN had an outstanding balance of $88.0 million on its senior secured revolving credit facility with a borrowing base of $550.0 million. At June 30, 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. The interest rate swap agreement was effective as of June 30, 2010 and expires on January 31, 2011. Beginning May 1, 2010, ATN discontinued hedge accounting for its 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 within other income, net in our consolidated statement of operations.

At June 30, 2010, APL had $285.0 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.

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 $0.2 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 the 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 June 30, 2011 of approximately $27.8 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 June 30, 2010, we had the following interest rate and commodity derivatives:

Interest Fixed Rate Swap

Natural Gas Fixed Price Swaps


Production Period Ending December 31,	Volumes	Average Fixed Price
	(mmbtu)⁽¹⁾	(per mmbtu) ⁽¹⁾
2010	20,140,000	$	7.387
2011	26,480,000	$	6.591
2012	20,852,300	$	6.797
2013	13,211,500	$	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	2,400,000	$	6.721
2010	Calls sold	2,400,000	$	7.909
2011	Puts purchased	13,380,000	$	6.147
2011	Calls sold	13,380,000	$	7.236
2012	Puts purchased	12,240,000	$	6.052
2012	Calls sold	12,240,000	$	7.160
2013	Puts purchased	14,880,000	$	6.094
2013	Calls sold	14,880,000	$	7.245
2014	Puts purchased	5,040,000	$	5.850
2014	Calls sold	5,040,000	$	6.950

Crude Oil Fixed Price Swaps


Production Period Ending December 31,	Volumes	Average Fixed Price
	(Bbl) ⁽¹⁾	(per Bbl) ⁽¹⁾
2010	26,700	$	97.122
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	17,000	$	85.000
2010	Calls sold	17,000	$	112.349
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.

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

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

As of June 30, 2010, APL had the following commodity derivatives, which do not qualify for hedge accounting:

Fixed Price Swaps


Production Period	Purchased Sold	Commodity	Volumes⁽¹⁾	Average Fixed Price
Natural Gas
2010	Sold	Natural Gas Basis	2,280,000	(0.700	)
2010	Purchased	Natural Gas Basis	2,280,000	(0.705	)
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	)

Natural Gas Liquids
2010	Sold	Propane	17,640,000	1.108
2010	Sold	Normal Butane	1,890,000	1.550
2010	Sold	Natural Gasoline	1,512,000	1.925

Crude Oil
2011	Sold	Crude Oil	78,000	92.870

Options


Production Period	Purchased/ Sold	Type	Commodity	Volumes⁽²⁾	Average Strike Price
Natural Gas
2010	Purchased⁽²⁾	Call	Natural Gas	4,200,000	$6.000

Natural Gas Liquids
2010	Purchased⁽²⁾	Put	Propane	6,048,000	$1.110
2010	Purchased⁽²⁾	Put	Normal Butane	2,772,000	1.440

Crude Oil
2010	Purchased	Put	Crude Oil	324,000	74.268
2010	Sold	Call	Crude Oil	546,000	100.051
2010	Purchased⁽³⁾	Call	Crude Oil	174,000	120.000
2011	Purchased	Put	Crude Oil	420,000	89.000
2011	Sold	Call	Crude Oil	678,000	94.681
2011	Purchased⁽³⁾	Call	Crude Oil	252,000	120.000
2012	Sold	Call	Crude Oil	498,000	95.835
2012	Purchased⁽³⁾	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 Oil are stated in barrels.

⁽²⁾	Liabilities for purchased options are due to deferred premium payments, which will be paid at the time the options are settled.

⁽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.

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.

Under the supervision and with the participation of our management, including of our Chief Executive Officer and Chief Financial Officer, 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 June 30, 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 the 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, In re 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.

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 captioned CNX 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 the decision. On May 18, 2010, the appeal was argued before the Tennessee Court of Appeals. The parties are awaiting the court’s 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.

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)


Exhibit No.		Description

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⁾

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


Exhibit No.		Description

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		Form of Non-Qualified Stock Option Grant Agreement⁽²⁵⁾

10.26		Form of Incentive Stock Option Grant Agreement⁽²⁵⁾

10.27		Form 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⁾

10.29		Securities Purchase Agreement dated July 27, 2010 by and among Atlas Pipeline Mid-Continent, LLC, Atlas Pipeline Partners, L.P., Enbridge Pipelines (Taxes Gathering) L.P. and Enbridge Energy Partners, L.P.⁽²⁸⁾

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

(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

(28)	Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s Form 8-K filed April 29, 2010

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: August 5, 2010	By:	/s/ EDWARD E. COHEN
		Edward E. Cohen
		Chairman and Chief Executive Officer

Date: August 5, 2010	By:	/s/ MATTHEW A. JONES
		Matthew A. Jones
		Chief Financial Officer

Date: August 5, 2010	By:	/s/ SEAN P. MCGRATH
		Sean P. McGrath
		Chief Accounting Officer

Notional
Amount

Option Type

Contract
Period Ended
December 31,

January 2008 – January 2011

$150,000,000

Pay 3.1% -Receive