ARKHAN 10Q 2009 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2009

¨	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 AMERICA, INC.

(Exact name of registrant as specified in its charter)


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

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

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

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

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

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


Large accelerated filer x	Accelerated filer ¨	Non-accelerated filer ¨	Smaller reporting company ¨
		(Do not check if 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 July 30, 2009 was 39,418,922 shares.

ATLAS AMERICA, INC. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM 10-Q


		PAGE
PART I. FINANCIAL INFORMATION		3

Item 1.	Financial Statements	3

	Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008 (Unaudited)	3

	Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2009 and 2008 (Unaudited)	4

	Consolidated Statement of Stockholders’ Equity for the Six Months Ended June 30, 2009 (Unaudited)	7

	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2009 and 2008 (Unaudited)	8

	Notes to Consolidated Financial Statements (Unaudited)	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	62

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	90

Item 4.	Controls and Procedures	100

PART II. OTHER INFORMATION		100

Item 1.	Legal Proceedings	100

Item 1A.	Risk Factors	101

Item 6.	Exhibits	103

SIGNATURES		106

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)

(Unaudited)


	June 30, 2009			December 31, 2008
ASSETS
Current assets:
Cash and cash equivalents	$	81,331		$	104,496
Accounts receivable		147,447			169,405
Current portion of derivative receivable from Partnerships		105			3,022
Current portion of derivative asset		118,792			152,727
Prepaid expenses and other		26,282			25,463
Prepaid and deferred income taxes		15,280			32,215
Current assets related to discontinued operations		—			13,441

Total current assets		389,237			500,769
Property, plant and equipment, net		3,714,402			3,744,815
Intangible assets, net		184,113			197,485
Goodwill, net		35,166			35,166
Long-term derivative receivable from Partnerships		5,028			2,719
Long term derivative asset		56,071			69,451
Investment in joint venture		133,803			—
Other assets, net		63,546			53,311
Long-term assets related to discontinued operations		—			242,165

	$	4,581,366		$	4,845,881

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	16,000		$	—
Accounts payable		98,291			140,725
Liabilities associated with drilling contracts		88,909			96,883
Accrued producer liabilities		47,067			66,846
Current portion of derivative liability to Partnerships		32,839			34,933
Current portion of derivative liability		62,189			73,776
Accrued liabilities		106,119			103,383
Advances from affiliate		202			108
Current liabilities related to discontinued operations		—			10,572

Total current liabilities		451,616			527,226
Long-term debt, less current portion		2,138,589			2,413,082
Deferred tax liability		237,003			242,058
Long-term derivative liability to Partnerships		19,965			22,581
Long-term derivative liability		43,081			59,103
Other long-term liabilities		54,093			52,263
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $0.01 par value: 1,000,000 authorized shares		—			—
Common stock, $0.01 par value: 49,000,000 authorized shares		426			426
Additional paid-in capital		412,370			412,869
Treasury stock, at cost		(144,110	)		(147,621	)
Accumulated other comprehensive income		29,487			21,143
Retained earnings		136,741			124,698

		434,914			411,515
Non-controlling interests		1,202,105			1,118,053

Total stockholders’ equity		1,637,019			1,529,568

	$	4,581,366		$	4,845,881

See accompanying notes to consolidated financial statements

ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Revenue:
Well construction and completion	$	63,367		$	122,341		$	175,735		$	226,479
Gas and oil production		69,979			78,956			141,922			155,182
Transmission, gathering and processing		186,070			438,461			349,737			807,417
Administration and oversight		2,642			5,137			6,495			10,154
Well services		4,839			5,266			9,932			10,064
Gain on asset sales		105,691			—			105,691			—
Equity income in joint venture		710			—			710			—
Loss on mark-to-market derivatives		(18,593	)		(316,068	)		(18,277	)		(404,849	)

Total revenue		414,705			334,093			771,945			804,447

Costs and expenses:
Well construction and completion		53,701			106,384			149,098			196,939
Gas and oil production		9,803			12,379			21,089			23,047
Transmission, gathering and processing		150,363			367,320			302,890			658,516
Well services		2,120			2,650			4,544			5,062
General and administrative		21,577			24,884			48,991			45,511
Net expense reimbursement – affiliate		80			184			562			434
Depreciation, depletion and amortization		50,272			43,359			100,967			85,214

Total costs and expenses		287,916			557,160			628,141			1,014,723

Operating income (loss)		126,789			(223,067	)		143,804			(210,276	)
Other income (expense):
Interest expense		(41,948	)		(34,739	)		(76,568	)		(69,207	)
Other, net		1,254			5,995			6,135			8,024

Total other income (expense)		(40,694	)		(28,744	)		(70,433	)		(61,183	)

Income (loss) from continuing operations before income taxes (benefit)		86,095			(251,811	)		73,371			(271,459	)
Provision (benefit) for income taxes		3,630			(5,030	)		6,263			(1,431	)

Net income (loss) from continuing operations		82,465			(246,781	)		67,108			(270,028	)
Discontinued operations:
Gain on sale of discontinued operations (net of income taxes of $2,234 and $2,234 for the three and six months ended June 30, 2009, respectively)		48,844			—			48,844			—
Income from discontinued operations (net of income taxes of $140 and $401 for the three months ended June 30, 2009 and 2008, respectively, and $499 and $643 for the six months ended June 30, 2009 and 2008, respectively)		2,401			7,844			10,917			13,848

Net income (loss)		133,710			(238,937	)		126,869			(256,180	)
(Income) loss attributable to non-controlling interests		(124,342	)		231,166			(112,858	)		254,831

Net income (loss) attributable to common shareholders	$	9,368		$	(7,771	)	$	14,011		$	(1,349	)

Net income (loss) attributable to common shareholders per share – basic:
Income (loss) from continuing operations attributable to common shareholders	$	0.15		$	(0.21	)	$	0.25		$	(0.06	)
Discontinued operations attributable to common shareholders		0.09			0.02			0.11			0.03

Net income (loss) attributable to common shareholders	$	0.24		$	(0.19	)	$	0.36		$	(0.03	)

Net income (loss) attributable to common shareholders per share – diluted:
Income (loss) from continuing operations attributable to common shareholders	$	0.15		$	(0.21	)	$	0.24		$	(0.06	)
Discontinued operations attributable to common shareholders		0.09			0.02			0.11			0.03

Net income (loss) attributable to common shareholders	$	0.24		$	(0.19	)	$	0.35		$	(0.03	)

Weighted average common shares outstanding:
Basic		39,432			40,335			39,297			40,330

Diluted		39,803			40,335			39,717			40,330

Income (loss) attributable to common shareholders:
Income (loss) from continuing operations (net of income taxes (benefit) of $3,630 and ($5,030) for the three months ended June 30, 2009 and 2008, respectively, and $6,263 and ($1,431) for the six months ended June 30, 2009 and 2008, respectively)	$	5,664		$	(8,397	)	$	9,746		$	(2,353	)
Discontinued operations (net of income taxes of $2,374 and $401 for the three months ended June 30, 2009 and 2008, respectively, and $2,734 and $643 for the six months ended June 30, 2009 and 2008, respectively)		3,704			626			4,265			1,004

Net income (loss) attributable to common shareholders	$	9,368		$	(7,771	)	$	14,011		$	(1,349	)

See accompanying notes to consolidated financial statements

ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

FOR THE SIX MONTHS ENDED JUNE 30, 2009

(in thousands, except share data)

(Unaudited)


	Common Stock			Additional Paid-In			Treasury Stock					Accumulated Other Comprehensive		Retained			Non- controlling			Total Stockholders’
	Shares	Amount		Capital			Shares		Amount			Income		Earnings			Interests			Equity
Balance at January 1, 2009	42,503,119	$	426	$	412,869		(3,252,861	)	$	(147,621	)	$	21,143	$	124,698		$	1,118,053		$	1,529,568
Common stock issuance	16,588		—		(2,444	)	71,579			3,511			—		—			—			1,067
Other comprehensive income	—		—		—		—			—			8,344		—			35,422			43,766
Stock option compensation expense	—		—		1,945		—			—			—		—			—			1,945
Dividends paid	—		—		—		—			—			—		(1,968	)		—			(1,968	)
Distributions to non-controlling interests	—		—		—		—			—			—		—			(42,505	)		(42,505	)
Non-controlling interests’ capital contributions	—		—		—		—			—			—		—			(21,723	)		(21,723	)
Net income	—		—		—		—			—			—		14,011			112,858			126,869

Balance at June 30, 2009	42,519,707	$	426	$	412,370		(3,181,282	)	$	(144,110	)	$	29,487	$	136,741		$	1,202,105		$	1,637,019

See accompanying notes to consolidated financial statements

ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)


	Six Months Ended June 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	126,869		$	(256,180	)
Income from discontinued operations		59,761			13,848

Income (loss) from continuing operations		67,108			(270,028	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		100,967			85,214
Amortization of deferred finance costs		6,382			4,181
Non-cash loss on derivative value, net		64,634			209,795
Non-cash compensation expense		1,775			5,171
Gain on asset sales and dispositions		(104,780	)		(12	)
Distributions paid to non-controlling interests		(42,505	)		(111,490	)
Equity income in joint venture		(710	)		—
Distributions received from joint venture		164			—
Deferred income taxes		5,927			(304	)
Changes in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable and prepaid expenses and other		25,115			(49,703	)
Accounts payable and accrued liabilities		(21,291	)		120,732
Accounts payable and accounts receivable - affiliate		94			65
Other operating assets/liabilities		2,574			624

Net cash provided by (used in) continuing operations operating activities		105,454			(5,755	)
Net cash provided by discontinued operations operating activities		14,201			21,208

Net cash provided by operating activities		119,655			15,453

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(226,907	)		(277,724	)
Acquisition purchase price adjustment		—			31,429
Investment in Lightfoot Capital Partners, L.P.		(2	)		(440	)
Proceeds from asset sales		97,953			34
Other		(7,838	)		290

Net cash used in continuing operations investing activities		(136,794	)		(246,411	)
Net cash provided by (used in) discontinued operations investing activities		290,594			(15,143	)

Net cash provided by (used in) investing activities		153,800			(261,554	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under Atlas Energy Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P. credit facilities		495,000			309,000
Repayments under Atlas Energy Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P. credit facilities		(763,295	)		(768,000	)
Issuance of Atlas Energy Resources, LLC long-term debt		—			407,021
Issuance of Atlas Pipeline Partners, L.P. long-term debt		—			244,854
Repayments on Atlas Pipeline Partners, L.P. long-term debt		—			(122,837	)
Net proceeds from Atlas Energy Resources, LLC equity offering		—			82,533
Net proceeds from Atlas Pipeline Partners, L.P. equity offering		—			207,106
Dividends paid		(1,968	)		(2,682	)
APL Class A preferred unit redemption		(15,000	)		—
Deferred financing costs and other		(11,357	)		(15,315	)

Net cash provided by (used in) financing activities		(296,620	)		341,680

Net change in cash and cash equivalents		(23,165	)		95,579
Cash and cash equivalents, beginning of period		104,496			145,896

Cash and cash equivalents, end of period	$	81,331		$	241,475

See accompanying notes to consolidated financial statements

ATLAS AMERICA, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

NOTE 1 – BASIS OF PRESENTATION

Atlas America, Inc. (the “Company”) is a publicly traded (NASDAQ:ATLS) Delaware corporation whose assets consist primarily of cash and its ownership interests in the following entities as of June 30, 2009:

•

Atlas Energy Resources, LLC (“Atlas Energy” or “ATN”), a publicly traded Delaware limited liability company (NYSE: ATN) which focuses on natural gas development and production in northern Michigan’s Antrim Shale, Indiana’s New Albany Shale and the Appalachian Basin, which the Company manages through its subsidiary, Atlas Energy Management, Inc., under the supervision of ATN’s board of directors. At June 30, 2009, the Company had a 48.3% ownership interest and owned all of the management incentive interests of ATN;

•

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 (NYSE:APL). At June 30, 2009, the Company had a 2.3% direct ownership interest in APL;

•

Atlas Pipeline Holdings, L.P. (“Atlas Pipeline Holdings” or “AHD”), a publicly traded Delaware limited partnership (NYSE: AHD) and owner of the general partner of APL. Through the Company’s ownership of AHD’s general partner, it manages AHD. AHD’s cash generating assets currently consist solely of its interests in APL. At June 30, 2009, the Company owned approximately 64.4% of the outstanding common units of AHD. AHD owned a 2% general partner interest, all of the incentive distribution rights, an approximate 12.0% common limited partner interest, and 15,000 $1,000 par value 12.0% Class B cumulative preferred limited partner units in APL; and

•

Lightfoot Capital Partners, LP (“Lightfoot LP”) and Lightfoot Capital Partners GP LLC, (“Lightfoot GP”), the general partner of Lightfoot (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. The Company has an approximate direct and indirect 18% ownership interest in Lightfoot GP and a commitment to invest a total of $20.0 million in Lightfoot LP. The Company also has direct and indirect ownership interest in Lightfoot LP. As of June 30, 2009, the Company has invested $10.7 million in Lightfoot LP.

On April 27, 2009, the Company and ATN executed a definitive merger agreement, pursuant to which the Company’s newly formed subsidiary will merge with and into ATN, with ATN surviving as the Company’s wholly-owned subsidiary. In the merger, each Class B common unit of ATN not currently held by the Company will be converted into 1.16 shares of the Company’s common stock, and the Company will be renamed “Atlas Energy, Inc.” The Company’s board of directors has approved the merger agreement and has resolved to recommend that the Company’s shareholders vote in favor of the transactions contemplated by the merger agreement. ATN’s board of directors and a special committee of its directors comprised entirely of independent directors have also approved the merger agreement and have resolved to recommend that ATN’s unitholders vote in favor of the merger. Pending consummation of the merger, ATN has suspended distributions to its Class A and Class B members’ interests. The transaction will be subject to approval by holders of a majority of the Company’s outstanding common stock and a majority of ATN’s outstanding Class B units and other customary closing conditions.

The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2008 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. Management has evaluated subsequent events through August 10, 2009, the date the financial statements were issued. 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, 2008. Certain amounts in the prior year’s consolidated financial statements have been reclassified to conform to the current year presentation, including $18.8 million of pre-development costs shown as component of “Property, plant, and equipment, net” which was previously combined with “Liabilities associated with drilling contracts” on the Company’s consolidated balance sheets at December 31, 2008. On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system (see Note 4). As such, the Company has adjusted its prior period consolidated financial statements and related footnote disclosures presented within this Form 10-Q to reflect the amounts related to the operations of the NOARK gas gathering and interstate pipeline system as discontinued operations. The results of operations for the three and six month periods ended June 30, 2009 may not necessarily be indicative of the results of operations for the full year ending December 31, 2009.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

In addition to matters discussed further within this note, a more thorough discussion of the Company’s significant accounting policies is included in its audited consolidated financial statements and notes thereto in its annual report on Form 10-K for the year ended December 31, 2008.

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 except for ATN and AHD, which are 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. The non-controlling ownership interests in the net income (loss) of ATN, AHD and APL are reflected within non-controlling interests on the Company’s consolidated statements of operations, and the non-controlling interests in the assets and liabilities of ATN, AHD and APL are reflected as a component of stockholders’ 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 ATN 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 “Oil and Gas Properties” below.

The Company’s consolidated financial statements also include APL’s 95% ownership interest in joint ventures which individually own a 100% ownership interest in the Chaney Dell natural gas gathering system and processing plants and a 72.8% undivided interest in the Midkiff/Benedum natural gas gathering system and processing plants. APL consolidates 100% of these joint ventures. The Company reflects the non-controlling 5% ownership interest in the joint ventures as non-controlling interests on its statements of operations. The Company also reflects the 5% ownership interest in the net assets of the joint ventures as non-controlling interests as a component of stockholders’ equity on its consolidated balance sheets. The joint ventures have a $1.9 billion note receivable from the holder of the 5% ownership interest in the joint ventures, which is reflected within non-controlling interests on the Company’s consolidated balance sheets.

The Midkiff/Benedum joint venture has a 72.8% undivided joint venture interest in the Midkiff/Benedum system, of which the remaining 27.2% interest is owned by Pioneer Natural Resources Company (NYSE: PXD) (“Pioneer”). Due to the Midkiff/Benedum system’s status as an undivided joint venture, the Midkiff/Benedum joint venture proportionally consolidates its 72.8% ownership interest in the assets and liabilities and operating results of the Midkiff/Benedum system. APL has an agreement with Pioneer whereby Pioneer has an option to buy up to an additional 22.0% interest in the Midkiff/Benedum system which began on June 15, 2009 and ends on November 1, 2009. If the option is fully exercised, Pioneer would increase its interest in the system to approximately 49.2%. Pioneer would pay approximately $230.0 million, subject to certain adjustments, for the additional 22.0% interest if fully exercised. APL will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercises the purchase option.

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, 2009 represent actual results in all material respects (see “– Revenue Recognition” accounting policy for further description).

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 ATN’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 ATN’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. ATN 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, ATN’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 ATN’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.

ATN’s lower operating and administrative costs result from the limited partners paying to ATN their proportionate share of these expenses plus a profit margin. These assumptions could result in ATN’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. ATN cannot predict what reserve revisions may be required in future periods.

ATN’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 ATN sponsors and owns an interest in but does not control. ATN’s reserve quantities include reserves in excess of its proportionate share of reserves in a partnership which ATN may be unable to recover due to the partnership legal structure. ATN 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 ATN is governed under the Partnership agreement and must be at fair market value supported by an appraisal of an independent expert selected by ATN.

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 ATN 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 oil and gas properties or unproved properties recorded by the Company for the three and six months ended June 30, 2009 and 2008.

Capitalized Interest

ATN and APL capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds by ATN and APL in the aggregate was 6.6% and 5.5% for the three months ended June 30, 2009 and 2008, respectively, and 6.3% and 5.9% for the six months ended June 30, 2009 and 2008, respectively. The aggregate amount of interest capitalized by ATN and APL was $2.3 million and $2.4 million for the three months ended June 30, 2009 and 2008, respectively, and $5.6 million and $4.7 million for the six months ended June 30, 2009 and 2008, respectively.

Intangible Assets

Customer contracts and relationships.APL has recorded intangible assets with finite lives in connection with natural gas gathering contracts and customer relationships assumed in certain consummated acquisitions. SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”) requires that intangible assets with finite useful lives be amortized 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 and residual values 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, operating contracts and non-compete agreement.ATN has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through consummated acquisitions. In addition, ATN entered into a two-year non-compete agreement in connection with the acquisition of Atlas Gas and Oil Company. ATN 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, 2009 and December 31, 2008 (in thousands):


	June 30, 2009			December 31, 2008			Estimated Useful Lives In Years
Gross Carrying Amount:
Customer contracts and relationships	$	235,382		$	235,382		7 – 20
Partnership management and operating contracts		14,343			14,343		2 – 13
Non-compete agreement		890			890		2

	$	250,615		$	250,615

Accumulated Amortization:
Customer contracts and relationships	$	(54,514	)	$	(41,735	)
Partnership management and operating contracts		(11,098	)		(10,728	)
Non-compete agreement		(890	)		(667	)

	$	(66,502	)	$	(53,130	)

Net Carrying Amount:
Customer contracts and relationships	$	180,868		$	193,647
Partnership management and operating contracts		3,245			3,615
Non-compete agreement		—			223

	$	184,113		$	197,485

Amortization expense on intangible assets was $6.7 million for both of the three months ended June 30, 2009 and 2008 and $13.4 million for both of the six months ended June 30, 2009 and 2008. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2009-$26.3 million; 2010-$26.3 million; 2011-$26.2 million; 2012-$25.7 million; and 2013-$24.6 million.

Goodwill

At June 30, 2009 and December 31, 2008, the Company had $35.2 million of goodwill recorded in connection with ATN consummated acquisitions. The changes in the carrying amount of goodwill for the six months ended June 30, 2009 and 2008 were as follows (in thousands):


	Six Months Ended June 30,
	2009		2008
Balance, beginning of period	$	35,166	$	744,449
APL post-closing purchase price adjustment with seller and purchase price allocation adjustment – Chaney Dell and Midkiff/Benedum systems acquisition		—		(2,217	)
APL recovery of state sales tax initially paid on transaction – Chaney Dell and Midkiff/Benedum systems acquisition		—		(30,206	)

Balance, end of period	$	35,166	$	712,026

As a result of its impairment evaluation at December 31, 2008, the Company recognized a $676.9 million non-cash impairment charge within its consolidated statements of operations for the year ended December 31, 2008. The goodwill impairment resulted from the reduction in APL’s estimated fair value of its reporting units in comparison to their carrying amounts at December 31, 2008. APL’s estimated fair value of its reporting units was impacted by many factors, including the significant deterioration of commodity prices and global economic conditions during the fourth quarter of 2008. These estimates were subjective and based upon numerous assumptions about future operations and market conditions, which are subject to change. There were no goodwill impairments recognized by the Company related to ATN during the year ended December 31, 2008.

ATN tests its goodwill for impairment at each year end under the principles of SFAS No. 142 by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for its reporting units are not available, ATN’s management must apply judgment in determining the estimated fair value of these reporting units. ATN’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to ATN’s market capitalization. The principles of SFAS No. 142 and its interpretations acknowledge that 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’s individual equity securities. In most industries, including ATN’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, ATN also considers a control premium to the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ATN’s industry. The resultant fair values calculated for the reporting units are then compared to observable metrics on large mergers and acquisitions in ATN’s industry to determine whether those valuations appear reasonable in management’s judgment. The Company will continue to evaluate goodwill at least annually or when impairment indicators arise. During the six months ended June 30, 2009, no impairment indicators arose.

In April 2008, APL received a $30.2 million cash reimbursement for sales tax initially paid on its transaction to acquire the Chaney Dell and Midkiff/Benedum systems in July 2007. The $30.2 million was initially capitalized as an acquisition cost and allocated to the assets acquired, including goodwill, based upon their estimated fair values at the date of acquisition. Based upon the reimbursement of the sales tax paid in April 2008, APL reduced goodwill recognized in connection with the acquisition at March 31, 2008.

Net Income (Loss) Per Share

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of common stock outstanding during the period. Diluted net income (loss) per share is calculated by dividing net income (loss) by the sum of the weighted average number of common stock outstanding and the

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


	Three Months Ended June 30,		Six Months Ended June 30,
	2009	2008⁽¹⁾	2009	2008⁽¹⁾
Weighted average number of shares – basic	39,432	40,335	39,297	40,330
Add: effect of dilutive incentive awards	371	—	420	—

Weighted average number of common shares – diluted	39,803	40,335	39,717	40,330

(1)	For both the three and six months ended June 30, 2008, approximately 1.9 million shares were excluded from the computation of diluted earnings attributable to common shareholders because the inclusion of such shares would have been anti-dilutive.

Revenue Recognition

Atlas Energy.Certain energy activities are conducted by ATN through, and a portion of its revenues are attributable to, sponsored investment Partnerships. ATN contracts with the Partnerships to drill partnership wells. The contracts require that the Partnerships must pay ATN 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, ATN 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. ATN recognizes well services revenues at the time the services are performed. ATN 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.

ATN 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 ATN has an interest with other producers are recognized on the basis of ATN’s percentage ownership of working interest and/or overriding royalty. Generally, ATN’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 ATN’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, 2009 and December 31, 2008 of $70.9 million and $87.4 million, respectively, which are included in accounts receivable within the Company’s consolidated balance sheets.

Comprehensive Income (Loss)

Comprehensive income (loss) 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 (loss)” 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,
	2009			2008			2009			2008
Net income (loss)	$	133,710		$	(238,937	)	$	126,869		$	(256,180	)
(Income) loss attributable to non-controlling interests		(124,342	)		231,166			(112,858	)		254,831

Net income (loss) attributable to common shareholders		9,368			(7,771	)		14,011			(1,349	)
Other comprehensive loss:
Changes in fair value of derivative instruments accounted for as cash flow hedges, net of tax of $4,222 and $45,502 for the three months ended June 30, 2009 and 2008, respectively, and ($13,003) and $63,316 for the six months ended June 30, 2009 and 2008, respectively		(13,055	)		(290,136	)		60,395			(354,042	)
Less: reclassification adjustment for realized losses (gains) in net income (loss), net of tax of $5,448 and ($1,742) for the three months ended June 30, 2009 and 2008, respectively, and $7,695 and ($1,177) for the six months ended June 30, 2009 and 2008, respectively		(17,318	)		21,215			(16,672	)		32,896
Changes in non-controlling interest related to items in other comprehensive income (loss)		15,248			202,861			(35,422	)		224,310
Plus: amortization of additional post-retirement liability recorded upon adoption of SFAS No. 158, net of tax of $13 and $51 for the three months ended June 30, 2009 and 2008, respectively, and $26 and $102 for the six months ended June 30, 2009 and 2008, respectively		21			88			43			209

Total other comprehensive (loss) gain		(15,104	)		(65,972	)		8,344			(96,627	)

Comprehensive income (loss) attributable to shareholders	$	(5,736	)	$	(73,743	)	$	22,355		$	(97,976	)

Recently Adopted Accounting Standards

In May 2009, the FASB issued Statement No. 165, “Subsequent Events” (“SFAS No. 165”). SFAS No. 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS No. 165 requires management of a reporting entity to evaluate events or transactions that may occur after the balance sheet date for potential recognition or disclosure in the financial statements and provides guidance for disclosures that an entity should make about those events. SFAS No. 165 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. The Company adopted the requirements of SFAS No. 165 on April 1, 2009 and its adoption did not have a material impact on the Company’s financial position or results of operations or related disclosures. The adoption of SFAS No. 165 does not change the Company’s current practices with respect to evaluating, recording and disclosing subsequent events.

In April 2009, the FASB issued Staff Position 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP FAS 157-4”). FSP FAS 157-4 applies to all fair value measurements and provides additional clarification on estimating fair value when the market activity for an asset has declined significantly. FSP FAS 157-4 also requires an entity to disclose a change in valuation technique and related inputs to the valuation calculation and to quantify its effects, if practicable. FSP FAS 157-4 is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted the requirements of FSP FAS 157-4 on April 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

In April 2009, the FASB issued Staff Position 115-2 and 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (“FSP FAS 115-2 and FAS 124-2”). FSP FAS 115-2 and FAS 124-2 change existing guidance for determining whether an impairment is other than temporary for debt securities. FSP FAS 115-2 and FAS 124-2 replaces the existing requirement that an entity’s management assess it has both the intent and ability to hold an impaired security until recovery with a requirement that management assess that it does not have the intent to sell the security and that it is more likely than not that it will not have to sell the security before recovery of its cost basis. FSP FAS 115-2 and FAS 124-2 also requires that an entity recognize noncredit losses on held-to-maturity debt securities in other comprehensive income and amortize that amount over the remaining life of the security and for the entity to present the total other-than-temporary impairment in the statement of operations with an offset for the amount recognized in other comprehensive income. FSP FAS 115-2 and FAS 124-2 are effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted the requirements of FSP FAS 115-2 and FAS 124-2 on April 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

In April 2009, the FASB issued Staff Position 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP FAS 107-1 and APB 28-1”). FSP FAS 107-1 APB 28-1 requires an entity to provide disclosures about fair value of financial instruments in interim financial information. In addition, an entity shall disclose in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position. FSP FAS 107-1 APB 28-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted the requirements of FSP FAS 107-1 APB 28-1 on April 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

In April 2009, the FASB issued Staff Position 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“FSP 141(R)-1”). FSP 141(R)-1 requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be recognized at fair value if fair value can be reasonably estimated. If fair value of such an asset or liability cannot be reasonably estimated, the asset or liability would generally be recognized in accordance with FASB Statement No. 5, “Accounting for Contingencies” and FASB Interpretation No. 14, “Reasonable Estimation of the Amount of a Loss”. FSP 141(R)-1 also eliminates the requirement to disclose an estimate of the range of outcomes of recognized contingencies at the acquisition date. FSP FAS 141(R)-1 is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for the Company). The Company adopted the requirements of FSP 141(R)-1 on January 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

In June 2008, the Financial Accounting Standards Board (“FASB”) issued Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-6-1 applies to the calculation of earnings per share (“EPS”) described in paragraphs 60 and 61 of FASB Statement No. 128, “Earnings per Share” for share-based payment awards with rights to dividends or dividend equivalents. It states that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption was prohibited. All prior-period EPS data presented was adjusted retrospectively to conform to the provisions of this FSP. The Company applied the requirements of FSP EITF 03-6-1 upon its adoption on January 1, 2009 and the adoption of FSP EITF 03-6-1 had no impact on its financial position and results of operations.

In April 2008, the FASB issued Staff Position No. 142-3, “Determination of Useful Life of Intangible Assets” (“FSP FAS 142-3”). FSP FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No 141(R), “Business Combinations” (“SFAS No. 141(R)”), and other U.S. Generally Accepted Accounting Principles. FSP FAS 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption was prohibited. The guidance for determining the useful life of a recognized intangible asset should be applied prospectively to intangible assets acquired after the effective date. The disclosure requirements should be applied prospectively to all intangible assets recognized as of, and subsequent to, the effective date. The Company applied the requirements of FSP FAS 142-3 upon its adoption on January 1, 2009 and the adoption of FSP FAS 142-3 had no impact on its financial position and results of operations.

In March 2008, the FASB ratified the EITF consensus on EITF Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF No. 07-4”), an update of EITF No. 03-6, “Participating Securities and the Two-Class Method Under FASB Statement No. 128” (“EITF No. 03-6”). EITF 07-4 considers whether the incentive distributions of a master limited partnership represent a participating security when considered in the calculation of earnings per unit under the two-class method. EITF 07-4 also considers whether the partnership agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. EITF No. 07-4 is effective for fiscal years beginning after December 15, 2008, including interim periods within those fiscal years, and required retrospective application of the guidance to all periods presented. Early adoption is prohibited. The Company adopted the requirements of EITF No. 07-4 on January 1, 2009 and it did not have a material impact on its calculation of net income per common shareholder.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 amends the requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, with early adoption encouraged. The Company adopted the requirements of SFAS No. 161 on January 1, 2009 and it resulted in additional disclosures related to its commodity and interest rate derivatives (see Note 8).

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements-an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 amends ARB No. 51 to establish accounting and reporting standards for the non-controlling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 also requires consolidated net income to be reported, and disclosed on the face of the consolidated statement of operations, at amounts that include the amounts attributable to both the parent and the non-controlling interest. Additionally, SFAS No. 160 establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 also requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated and adjust its remaining investment, if any, at fair value. The Company adopted the requirements of SFAS No. 160 on January 1, 2009 and adjusted the presentation of its financial position and results of operations. Prior period financial positions and results of operations have been adjusted retrospectively to conform to the provisions of SFAS No. 160.

requires costs incurred in connection with an acquisition be expensed as incurred. Restructuring costs, if any, are to be recognized separately from the acquisition. The acquirer in a business combination achieved in stages must also recognize the identifiable assets and liabilities, as well as the non-controlling interests in the acquiree, at the full amounts of their fair values. SFAS No. 141(R) is effective for business combinations occurring in fiscal years beginning on or after December 15, 2008. The Company adopted the requirements of SFAS No. 141(R) on January 1, 2009 and it did not have a material impact on its financial position and results of operations.

Recently Issued Accounting Standards

In June 2009, the FASB issued Statement No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – A Replacement of FASB Statement No. 162” (“SFAS No. 168”). SFAS No. 168 establishes the FASB Accounting Standards Codification (“Codification”) as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The Codification supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following SFAS No. 168, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting Standards Updates, which will serve only to update the Codification. SFAS No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Company will apply the requirements of SFAS No. 168 to its financial statements for the interim period ending September 30, 2009 and does not expect it to have a material impact to its financial position or results of operations or related disclosures.

In June 2009, the FASB issued Statement No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS No. 167”). SFAS No. 167 is a revision to FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities” and 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. SFAS No. 167 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. SFAS No. 167 is 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 will apply the requirements of SFAS No. 167 upon its adoption on January 1, 2010 and does not expect it to have a material impact to its financial position or results of operations or related disclosures.

Modernization of Oil and Gas Reporting

In December 2008, the Securities and Exchange Commission (“SEC”) announced that it had approved revisions to its oil and gas reporting disclosures by adopting amendments to Rule 4-10 of Regulation S-X and Items 201, 801, and 802 of Regulation S-K. These new disclosure requirements are referred to as “Modernization of Oil and Gas Reporting” and include provisions that:

•

Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.

•

Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end pricing. This should maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.

•

Permit companies to disclose their probable and possible reserves on a voluntary basis. Current rules limit disclosure to only proved reserves.

•

Update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include “by geographic area” and “reasonable certainty”.

•

Permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

•

Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures are required related to internal controls over reserve estimation, as well as a report addressing the independence and qualifications of a company’s reserves preparer or auditor based on Society of Petroleum Engineers criteria.

The Company will begin complying with the disclosure requirements in its annual report on Form 10-K for the year ending December 31, 2009. The new rules may not be applied to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. The Company is currently in the process of evaluating the new requirements.

NOTE 3 – APL INVESTMENT IN JOINT VENTURE

On May 31, 2009, APL and subsidiaries of The Williams Companies, Inc. (NYSE: WMB) (“Williams”) completed the formation of Laurel Mountain Midstream, LLC (“Laurel Mountain”), a joint venture which will own and operate APL’s Appalachia Basin natural gas gathering system, excluding APL’s Northern Tennessee operations. To the joint venture, Williams contributed cash of $100.0 million, of which APL received approximately $87.8 million, net of working capital adjustments, and a note receivable of $25.5 million. In addition, ATN sold certain assets to the joint venture for $12.0 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 $105.7 million, including $79.7 million associated with the remeasurement of APL’s investment in Laurel Mountain to fair value. APL used the net proceeds from the transaction to reduce borrowings under its senior secured credit facility (see Note 8). In addition, ATN sold to Laurel Mountain two natural gas processing plants and associated pipelines located in Southwestern Pennsylvania for $10.0 million, resulting in a $4.2 million loss which is included in gain on asset sale on the Company’s consolidated statement of operations. Upon the completion of the contribution of APL’s Appalachia gathering systems to Laurel Mountain, Laurel Mountain entered into new gas gathering agreements with ATN which superseded the existing natural gas gathering agreements and omnibus agreement between APL and ATN. Under the new gas gathering agreement, ATN is obligated to pay the joint venture all of the gathering fees it collects from its investment drilling partnerships plus any excess amount over the amount of the competitive gathering fee (which is currently defined as 13% of the gross sales price received for the ATN’s gas). 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 as equity income on the Company’s consolidated statements of operations.

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


	Three Months Ended June 30, 2009⁽¹⁾		Six Months Ended June 30, 2009⁽¹⁾
Statement of Operations data:
Total revenue	$	3,068	$	3,068
Net income		1,278		1,278

	June 30, 2009
Balance Sheet data:
Current assets	$	7,565
Long-term assets		245,395
Current liabilities		11,104
Long-term liabilities		15,500
Net equity		226,356

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

NOTE 4 – DISCONTINUED OPERATIONS

On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system to Spectra Energy Partners OLP, LP (NYSE:SEP) (“Spectra”) for net proceeds of $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 8). The Company accounted for the sale of the NOARK system assets as discontinued operations within its consolidated financial statements and recorded a gain of $48.8 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 financial 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 (amounts in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Total revenue and other loss, net	$	5,269		$	15,988		$	21,274		$	32,359
Total costs and expenses		(2,728	)		(7,743	)		(9,858	)		(17,868	)

Income before income tax expense		2,541			8,245			11,416			14,491
Income tax expense		(140	)		(401	)		(499	)		(643	)

Income from discontinued operations	$	2,401		$	7,844		$	10,917		$	13,848

The following table summarizes the components included within total assets and liabilities of discontinued operations within the Company’s consolidated balance sheet for the period indicated (amounts in thousands):


	December 31, 2008
Cash and cash equivalents	$	75
Accounts receivable		12,365
Prepaid expenses and other		1,001

Total current assets of discontinued operations		13,441
Property, plant and equipment, net		241,926
Other assets, net		239

Total assets of discontinued operations	$	255,606

Accounts payable	$	4,120
Accrued liabilities		5,892
Accrued producer liabilities		560

Total current liabilities of discontinued operations	$	10,572

NOTE 5 – PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment are stated at cost. Depreciation, depletion and amortization are based on cost less estimated salvage value primarily using the unit-of-production or straight-line methods 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 following is a summary of property, plant and equipment (in thousands):


	June 30, 2009			December 31, 2008⁽¹⁾			Estimated Useful Lives in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,232,197		$	1,214,991
Pre-development costs		13,501			18,772
Wells and related equipment		936,377			872,128

Total proved properties		2,182,075			2,105,891
Unproved properties		43,996			43,749
Support equipment		9,081			9,527

Total natural gas and oil properties		2,235,152			2,159,167
Pipelines, processing and compression facilities		1,679,471			1,728,472		15 – 40
Rights of way		166,723			168,206		20 – 40
Land, buildings and improvements		24,501			24,385		10 – 40
Other		21,423			22,108		3 – 10

		4,127,270			4,102,338
Less – accumulated depreciation, depletion and amortization		(412,868	)		(357,523	)

	$	3,714,402		$	3,744,815

(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 4)

The Company follows the successful efforts method of accounting for oil and gas producing activities. Acquisition costs of leases and development activities are capitalized. 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 and delay rentals are expensed. Oil is converted to gas equivalent basis (“Mcfe”) at the rate one barrel equals 6 thousand cubic feet (“Mcf”). Depletion is provided on the units-of-production method.

Depletion, depreciation and amortization expense is determined on a field-by-field basis using the units-of-production method. Depletion, depreciation and amortization rates for leasehold acquisition costs based on estimated proved reserves and depletion, depreciation and amortization rates for well and related equipment costs 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 ATN’s costs of property interests in uncontrolled, but proportionately consolidated from investment partnerships, wells drilled solely by ATN for its interest, properties purchased and working interests with other outside operators.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to income. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion. Upon the 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 statements of income. 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.

NOTE 6 – OTHER ASSETS

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


	June 30, 2009		December 31, 2008⁽¹⁾
Deferred finance costs, net of accumulated amortization of $29,487 and $23,105 at June 30, 2009 and December 31, 2008, respectively	$	43,876	$	38,836
Investments		14,190		12,702
Long-term pipeline lease prepayment		2,043		—
Security deposits		1,975		1,617
Other		1,462		156

	$	63,546	$	53,311

(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 4)

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 8). During May 2009, APL recorded $2.3 million of accelerated amortization of deferred financing costs associated with the retirement of a portion of its term loan with the proceeds from the sale of its NOARK system (see Note 4). In June 2008, APL recorded $1.2 million for accelerated amortization of deferred financing costs associated with the retirement of a portion of its term loan with a portion of the net proceeds from its issuance of senior notes (see Note 8).

Investments at June 30, 2009 and December 31, 2008 included an aggregate $10.7 million invested in Lightfoot LP. The Company owns, directly and indirectly, approximately 13% of Lightfoot LP, an entity of which Jonathan Cohen, Vice Chairman of the Company’s Board of Directors, is the Chairman of the Board. In addition, the Company owns, directly and indirectly, approximately 18% of Lightfoot GP, the general partner of Lightfoot LP. The Company committed to invest a total of $20.0 million in Lightfoot LP. The Company has certain co-investment rights until such point as Lightfoot LP raises additional capital through a private offering to institutional investors or a public offering. Lightfoot LP has initial equity funding commitments of approximately $160.0 million and focuses its investments primarily on incubating new master limited partnerships and providing capital to existing MLPs in need of additional equity or structured debt. Lightfoot LP concentrates on assets that are MLP-qualified such as infrastructure, coal, and other asset categories. The Company accounts for its investment in Lightfoot under the equity method of accounting. For the three months ended June 30, 2009 and 2008, the Company recorded a loss of $1.7 million and $0.1 million, respectively. For the six months ended June 30, 2009 and 2008, the Company recorded a loss of $1.7 million and $0.7 million, respectively.

NOTE 7 – ASSET RETIREMENT OBLIGATIONS

The Company follows SFAS No 143, “Accounting for Retirement Asset Obligations” (“SFAS No. 143”) and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), which requires the Company to recognize an estimated liability for the plugging and abandonment of ATN’s oil and gas wells and related facilities. Under SFAS No. 143, the Company must currently recognize 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. SFAS No. 143 requires the Company to consider estimated salvage value in the calculation of depreciation, depletion and amortization. The Company’s asset retirement obligations consist principally of the plugging and abandonment of ATN’s oil and gas wells.

The estimated liability is based on ATN’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. ATN has no assets legally restricted for purposes of settling asset retirement obligations. Except for the item previously referenced, the Company has determined that there are no other material retirement obligations associated with tangible long-lived assets.

A reconciliation of ATN’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,
	2009			2008		2009			2008
Asset retirement obligations, beginning of period	$	49,262		$	43,801	$	48,136		$	42,358
Liabilities incurred		166			858		596			1,640
Liabilities settled		(23	)		—		(85	)		(2	)
Accretion expense		737			675		1,495			1,338

Asset retirement obligations, end of period	$	50,142		$	45,334	$	50,142		$	45,334

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

NOTE 8 – DEBT

Total debt consists of the following (in thousands):


	June 30, 2009			December 31, 2008
ATN revolving credit facility	$	456,000		$	467,000
ATN 10.75 % senior notes – due 2018		406,289			406,655
AHD credit facility		16,000			46,000
APL revolving credit facility		322,000			302,000
APL term loan		459,885			707,180
APL 8.125 % senior notes – due 2015		271,365			261,197
APL 8.75 % senior notes – due 2018		223,050			223,050

Total debt		2,154,589			2,413,082
Less current maturities		(16,000	)		—

Total long-term debt	$	2,138,589		$	2,413,082

ATN Revolving Credit Facility

At June 30, 2009, ATN had a credit facility with a syndicate of banks with a borrowing base of $650.0 million that matures in June 2012. The borrowing base is redetermined semiannually on April 1 and October 1 subject to changes in ATN’s oil and gas reserves or is automatically reduced by 25% of the stated principal of any senior unsecured notes issued by ATN. On July 16, 2009, ATN issued $200.0 million of senior unsecured notes, and the borrowing base was reduced by $50.0 million to $600.0 million (see Note 19). Up to $50.0 million of the credit facility may be in the form of standby letters of credit, of which $1.2 million was outstanding at June 30, 2009, which are 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 and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at ATN’s option. On April 9, 2009, the credit agreement was amended to, among other things, increase the applicable margin on Eurodollar Loans from a range of 100 to 175 basis points to a range of 200 to 300 basis points and the applicable margin for base rate loans from a range of 0 to 75 basis points to a range of 112.5 to 212.5 basis points. At June 30, 2009 and December 31, 2008, the weighted average interest rate on outstanding borrowings was 2.9% and 2.8%, respectively. The base rate for any day equals the higher of the federal funds rate plus 0.50% or the J.P. Morgan prime rate or the adjusted LIBOR for a month interest period plus 1.0%. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for Eurocurrency liabilities. The credit agreement was amended on July 10, 2009, in anticipation of the merger between ATN and the Company (see Note 19).

The events which constitute an event of default for ATN’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against 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. The agreement limits the distributions payable by ATN if an event of default has occurred and is continuing or would occur as a result of such distribution. ATN is in compliance with these covenants as of June 30, 2009. 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 3.75 to 1.0 commencing January 1, 2009, and decreasing to 3.5 to 1.0 commencing January 1, 2010 and thereafter. According to the definitions contained in ATN’s credit facility, ATN’s ratio of current assets to current liabilities was 1.3 to 1.0 and its ratio of total debt to EBITDA was 2.7 to 1.0 at June 30, 2009.

ATN Senior Notes

At June 30, 2009, ATN had $400.0 million principal amount outstanding of 10.75% senior unsecured notes (“ATN Senior Notes”) due on February 1, 2018. The ATN Senior Notes are presented combined with the $6.3 million unamortized premium received at June 30, 2009. Interest on the ATN Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year. The ATN Senior Notes are redeemable at any time at specified redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, before February 1, 2011, 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 their principal amount, 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 indenture governing the ATN Senior Notes contains 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 is in compliance with the covenants as of June 30, 2009.

AHD Credit Facility

At June 30, 2009, AHD had $16.0 million outstanding under a revolving credit facility with a syndicate of banks. On June 1, 2009, AHD entered into an amendment to its credit facility agreement which, among other changes:

•

required AHD to immediately repay $30.0 million of then-outstanding $46.0 million of borrowings under the credit facility, $16.0 million of which was borrowed from the Company through a subordinate loan;

•

required AHD to repay $4.0 million of the remaining $16.0 million outstanding under the credit facility 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. AHD repaid $4.0 million of its outstanding credit facility borrowings on July 13, 2009 in accordance with the amendment through a subordinate loan with the Company. AHD may not borrow additional amounts under the credit facility or issue letters of credit;

•

required AHD to use any of its “excess cash flow”, which the amendment generally defines as cash in excess of $1.5 million as of the last business day of each month, to repay outstanding borrowings under the credit facility. In addition, the amendment requires AHD to repay borrowings under the credit facility with the net proceeds of any sales of its common units in APL;

•

eliminated all financial covenants in the credit agreement, including the leverage ratio, the combined leverage ratio with APL, and the interest coverage ratio (all as defined within the credit facility agreement);

•

prohibits AHD from paying any cash distributions on or redeeming any of its equity while the credit facility is in effect and permits AHD to pay operating expenses only to the extent incurred or paid in the ordinary course of business; and

•

reduces the applicable margin above LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank, National Association prime rate to be 0.75% for LIBOR loans and 0.0% for federal funds rate or prime rate loans. The weighted average interest rate on the outstanding credit facility borrowings at June 30, 2009 was 1.1%.

Borrowings under AHD’s credit facility are secured by a first-priority lien on a security interest in all of AHD’s assets, including the pledge of Atlas Pipeline GP’s interests in APL, and are guaranteed by Atlas Pipeline GP and AHD’s other subsidiaries (excluding APL and its subsidiaries). AHD’s credit facility contains customary covenants, including restrictions on its ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to AHD’s unitholders if an event of default exists or would result from such distribution; or enter into a merger or sale of substantially all of AHD’s property or assets, including the sale or transfer of interest in its subsidiaries. AHD is in compliance with these covenants as of June 30, 2009. The events which constitute an event of default under AHD’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreements, adverse judgments against AHD in excess of a specified amount, a change of control of the Company, AHD’s general partner or any other obligor, and termination of a material agreement and occurrence of a material adverse effect.

On June 1, 2009, in connection with AHD’s amendment of the credit facility, the Company guaranteed the remaining balance outstanding under the credit facility under a guarantee agreement with the administrative agent of the credit facility. In consideration for this guarantee, AHD issued to the Company a promissory note which requires it to pay interest to the Company in an amount based upon the principal amount outstanding under the credit facility. The maturity date of the promissory note is the day following the date that AHD repays all outstanding borrowings under its credit facility. Interest on the promissory note, which is calculated on the outstanding balance under the credit facility, accrues quarterly at the rate of 3.75% per annum. However, prior to the maturity date of the promissory note, interest under the promissory note will not be payable in cash, but instead the principal amount upon which interest is calculated will be increased by the interest amount payable.

APL Term Loan and Revolving Credit Facility

At June 30, 2009, 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 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 the outstanding APL revolving credit facility borrowings at June 30, 2009 was 6.8%, and the weighted average interest rate on the outstanding APL term loan borrowings at June 30, 2009 was 6.8%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $3.5 million was outstanding at June 30, 2009. These outstanding letter of credit amounts were not reflected as borrowings on the Company’s consolidated balance sheet.

On May 29, 2009, APL entered into an amendment to its credit facility agreement which, among other changes:

•

increased the applicable margin above adjusted LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank prime rate upon which borrowings under the credit facility bear interest;

•

for borrowings under the credit facility that bear interest at LIBOR plus the applicable margin, set a floor for the adjusted LIBOR interest rate of 2.0% per annum;

•

increased the maximum ratios of funded debt (as defined in the credit agreement) to consolidated EBITDA (as defined in the credit agreement; the “leverage ratio”) and interest coverage (as defined in the credit agreement) that the credit facility requires APL to maintain;

•

instituted a maximum ratio of senior secured debt (as defined in the credit agreement) to consolidated EBITDA (the “senior secured leverage ratio”) that the credit facility requires APL to maintain;

•

requires that APL pay no cash distributions during the remainder of the year ended December 31, 2009 and allows it to pay cash distributions beginning January 1, 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;

•

generally limits APL’s annual capital expenditures to $95.0 million for the remainder of fiscal 2009 and $70.0 million each year thereafter;

•

permitted APL to retain (i) up to $135.0 million of net cash proceeds from dispositions completed in fiscal 2009 for reinvestment in similar replacement assets within 360 days, and (ii) up to $50.0 million of net cash proceeds from dispositions completed in any subsequent fiscal year subject to certain limitations as defined within the credit agreement; and

•

instituted 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.

In June 2008, APL entered into an amendment to the credit facility agreement to revise the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to its early termination of certain derivative contracts (see Note 9) in calculating Consolidated EBITDA. Pursuant to this amendment, in June 2008, APL repaid $122.8 million of its outstanding term loan and repaid $120.0 million of outstanding borrowings under the revolving credit facility with proceeds from its issuance of $250.0 million of 10-year 8.75% senior unsecured notes. Additionally, pursuant to this amendment, in June 2008 APL’s lenders increased their commitments for the revolving credit facility by $80.0 million to $380.0 million.

Borrowings under the 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 APL’s investment in the Laurel Mountain joint venture, and by the guaranty of each of APL’s consolidated subsidiaries other than the joint venture companies. The credit facility contains customary covenants, including restrictions on APL’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement. APL is in compliance with these covenants as of June 30, 2009.

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, 2009	5.50	x	3.00	x	2.50	x
September 30, 2009	6.50	x	3.75	x	2.50	x
December 31, 2009	8.50	x	5.25	x	1.70	x
March 31, 2010	9.25	x	5.75	x	1.40	x
June 30, 2010	8.00	x	5.00	x	1.65	x
September 30, 2010	7.00	x	4.25	x	1.90	x
December 31, 2010	6.00	x	3.75	x	2.20	x
Thereafter	5.00	x	3.00	x	2.75	x

As of June 30, 2009, APL’s leverage ratio was 3.6 to 1.0, its senior secured leverage ratio was 2.2 to 1.0, and its interest coverage ratio was 4.2 to 1.0.

APL Senior Notes

At June 30, 2009, 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 $4.1 million of unamortized discount as of June 30, 2009. Interest on the APL Senior Notes in the aggregate is payable semi-annually in arrears on June 15 and December 15. The APL Senior Notes are redeemable at any time 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 8.75% 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 8.75% Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its credit facility.

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

Indentures governing the APL Senior Notes in the aggregate contain covenants, including limitations of APL’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. APL is in compliance with these covenants as of June 30, 2009.

In connection with the issuance of the APL 8.75% Senior Notes, APL entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission for the APL 8.75% Senior Notes, (b) cause the exchange offer registration statement to be declared effective by the Securities and Exchange Commission, and (c) cause the exchange offer to be consummated by February 23, 2009. If APL did not meet the aforementioned deadline, the APL 8.75% Senior Notes would have been subject to additional interest, up to 1% per annum, until such time that APL had caused the exchange offer to be consummated. On November 21, 2008, APL filed an exchange offer registration statement for the APL 8.75% Senior Notes with the Securities and Exchange Commission, which was declared effective on December 16, 2008. The exchange offer was consummated on January 21, 2009, thereby fulfilling all of the requirements of the APL 8.75% Senior Notes registration rights agreement by the specified dates.

NOTE 9 – DERIVATIVE INSTRUMENTS

APL, ATN and AHD 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, NGLs, 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 is due. Under swap agreements, the Company and its subsidiaries receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not 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 stockholders’ equity as accumulated other comprehensive income and reclassifies the portion relating to commodity derivatives to gas and oil production revenues for ATN derivatives, gathering, transmission and processing revenues for APL derivatives, and the portion relating to interest rate derivatives to interest expense within the Company’s consolidated statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Company and its subsidiaries recognize changes in fair value within gain (loss) on mark-to-market derivatives in its consolidated statements of operations as they occur.

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 $69.6 million and $89.3 million at June 30, 2009 and December 31, 2008, respectively. Of the $29.5 million of net gain in accumulated other comprehensive income within stockholders’ equity on the Company’s consolidated balance sheet at June 30, 2009, if the fair values of the instruments remain at current market values, the Company will reclassify $20.6 million of gains to the Company’s consolidated statements of operations over the next twelve month period as these contracts expire, consisting of $24.6 million of gains to gas and oil production revenues, $2.6 million of losses to gathering, transmission and processing revenues and $1.4 million of losses to interest expense. Aggregate gains of $9.1 million will be reclassified to the Company’s consolidated statements of operations in later periods as these remaining contracts expire, consisting of $11.8 million of gains to gas and oil production revenues, $2.0 million of losses to gathering, transmission and processing revenues and $0.7 million of losses to interest expense. Actual amounts that will be reclassified will vary as a result of future price changes.

Atlas Energy

The following table summarizes the fair value of ATN’s derivative instruments as of June 30, 2009 and December 31, 2008, as well as the gain or loss recognized for the six months ended June 30, 2009 and 2008. There were no gains or losses recognized in income for ineffective derivative instruments for the six months ended June 30, 2009 and 2008.

Fair Value of ATN Derivative Instruments:


	Asset Derivatives					Liability Derivatives
Derivatives in SFAS 133 Cash Flow Hedging Relationships	Balance Sheet Location	Fair Value				Balance Sheet Location	Fair Value
		June 30, 2009		December 31, 2008			June 30, 2009			December 31, 2008
		June 30, 2009		December 31, 2008			June 30, 2009			December 31, 2008
		(in thousands)					(in thousands)
Commodity contracts:	Current assets	$	116,977	$	107,766	Current liabilities	$	(383	)	$	(9,348	)
	Long-term assets		54,465		69,451	Long-term liabilities		(29,120	)		(8,410	)

			171,442		177,217			(29,503	)		(17,758	)
Interest rate contracts:	Current assets		—		—	Current liabilities		(3,602	)		(3,481	)
	Long-term assets		—		—	Long-term liabilities		(1,213	)		(2,361	)

			—		—			(4,815	)		(5,842	)

Total derivatives under SFAS No. 133		$	171,442	$	177,217		$	(34,318	)	$	(23,600	)

Effects of ATN Derivative Instruments on Consolidated Statements of Operations:


Derivatives in SFAS 133 Cash Flow Hedging Relationships	Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) For the Three Months Ended						Location of Gain/(Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) For the Three Months Ended
	June 30, 2009			June 30, 2008				June 30, 2009			June 30, 2008
	(in thousands)							(in thousands)
Commodity contracts	$	(22,528	)	$	(212,364	)	Gas and oil production	$	31,564		$	(4,896	)
Interest rate contracts		(132	)		3,831		Interest expense		(1,030	)		(114	)

	$	(22,660	)	$	(208,533	)		$	30,534		$	(5,010	)


Derivatives in SFAS 133 Cash Flow Hedging Relationships	Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) For the Six Months Ended						Location of Gain/(Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) For the Six Months Ended
	June 30, 2009			June 30, 2008				June 30, 2009			June 30, 2008
	(in thousands)							(in thousands)
Commodity contracts	$	64,286		$	(310,522	)	Gas and oil production	$	47,082		$	1,645
Interest rate contracts		(1,005	)		1,795		Interest expense		(2,032	)		(23	)

	$	63,281		$	(308,727	)		$	45,050		$	1,622

ATN’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 future gas and oil production related to the hedges not yet settled. At June 30, 2009 and December 31, 2008, unrealized derivative liabilities of $47.7 million and $51.8 million are payable to the limited partners in the Partnerships and are included in the Company’s consolidated balance sheets.

In May 2009, ATN 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, ATN 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 8). The gain recognized upon the early termination of these derivative positions will continue to be reported in accumulated other comprehensive income on the Company’s consolidated balance sheets, 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.

At June 30, 2009, ATN had debt outstanding of $456.0 million under its revolving credit facility. In January 2008, ATN entered into derivative contracts in the form of interest rate swaps to reduce the impact of volatility of changes in the London interbank offered rate (“LIBOR”). ATN has LIBOR interest rate swaps at a three-year fixed swap rate of 3.11% on $150.0 million of outstanding debt through January 2011. The swaps have been designated as cash flow hedges to minimize the risk associated with changes in the designated benchmark interest rate (in this case, LIBOR) related to forecasted payments associated with interest on the credit facility. ATN has accounted for the interest rate swaps under the “long-haul” method to measure ineffectiveness under SFAS No. 133. Using the change in variable cash flow method, no hedge ineffectiveness was identified. The values of ATN’s cash flow hedges included in accumulated other comprehensive income were net unrecognized losses of approximately $4.8 million and $5.8 million at June

30, 2009 and December 31, 2008, respectively. ATN recognized gains on settled swaps of $1.0 million and $0.1 million for the three months ended June 30, 2009 and 2008, respectively, and gains of $2.0 million and $23,000 for the six months ended June 30, 2009 and 2008, respectively.

As of June 30, 2009, ATN 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 3.11% - Receive LIBOR	2009	$	(1,932	)
				2010		(2,757	)
				2011		(126	)

					$	(4,815	)

Natural Gas Fixed Price Swaps


Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset/(Liability)⁽¹⁾
	(MMBtu)	(per MMBtu)		(in thousands)
2009	21,790,000	$	8.044	$	79,987
2010	31,880,000	$	7.708		52,270
2011	20,720,000	$	7.040		2,973
2012	19,680,000	$	7.223		1,131
2013	10,620,000	$	7.126		(1,631	)

				$	134,730

Natural Gas Costless Collars


Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset/(Liability)⁽¹⁾
		(MMBtu)	(per MMBtu)		(in thousands)
2009	Puts purchased	120,000	$	11.000	$	795
2009	Calls sold	120,000	$	15.350		—
2010	Puts purchased	3,360,000	$	7.839		6,584
2010	Calls sold	3,360,000	$	9.007		—
2011	Puts purchased	9,540,000	$	6.523		145
2011	Calls sold	9,540,000	$	7.666		—
2012	Puts purchased	4,020,000	$	6.514		—
2012	Calls sold	4,020,000	$	7.718		(978	)
2013	Puts purchased	5,340,000	$	6.516		—
2013	Calls sold	5,340,000	$	7.811		(1,737	)

					$	4,809

Crude Oil Fixed Price Swaps


Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset/(Liability)⁽²⁾
	(Bbl)	(per Bbl)		(in thousands)
2009	31,700	$	99.497	$	896
2010	48,900	$	97.400		1,079
2011	42,600	$	77.460		(30	)
2012	33,500	$	76.855		(105	)
2013	10,000	$	77.360		(35	)

				$	1,805

Crude Oil Costless Collars


Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset/(Liability)⁽²⁾
		(Bbl)	(per Bbl)		(in thousands)
2009	Puts purchased	19,500	$	85.000	$	289
2009	Calls sold	19,500	$	116.884		—
2010	Puts purchased	31,000	$	85.000		448
2010	Calls sold	31,000	$	112.918		—
2011	Puts purchased	27,000	$	67.223		—
2011	Calls sold	27,000	$	89.436		(45	)
2012	Puts purchased	21,500	$	65.506		—
2012	Calls sold	21,500	$	91.448		(73	)
2013	Puts purchased	6,000	$	65.358		—
2013	Calls sold	6,000	$	93.442		(24	)

					$	595

		Total ATN net asset			$	137,124

⁽¹⁾	Fair value based on forward NYMEX natural gas prices, as applicable.

⁽²⁾	Fair value based on forward WTI crude oil prices, as applicable.

Atlas Pipeline Holdings and Atlas Pipeline Partners

Beginning July 1, 2008, APL discontinued hedge accounting for its existing commodity derivatives which were qualified as hedges under SFAS No. 133. 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 income within stockholders’ 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.

During the six months ended June 30, 2009 and year ended December 31, 2008, APL made net payments of $5.0 million and $274.0 million, respectively, related to the early termination of derivative contracts. Substantially all of these derivative contracts were put into place simultaneously with the APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 and related to production periods ranging from the end of the second quarter of 2008 through the fourth quarter of 2009. During the three and six months ended June 30, 2009 and 2008, the Company recognized the following derivative activity related to the termination of these derivative instruments within its consolidated statements of operations (amounts in thousands):


	Early Termination of Derivative Contracts
	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Net cash derivative expense included within loss on mark-to-market derivatives	$	—		$	(115,810	)	$	(5,000	)	$	(115,810	)
Net non-cash derivative income included within loss on mark-to-market derivatives		—			(315	)		—			(315	)
Net non-cash derivative expense included within gathering, transmission and processing revenue		7,117			(46,345	)		19,220			(46,345	)
Net cash derivative expense included within loss on mark-to-market derivatives		(12,123	)		—			(34,067	)		—

At June 30, 2009, AHD had an interest rate derivative contract having an aggregate notional principal amount of $25.0 million, which was designated as a cash flow hedge. Under the terms of the agreement, AHD will pay an interest rate of 3.01%, plus the applicable margin as defined under the terms of its revolving credit facility (see Note 8), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. The interest rate swap agreement is effective at June 30, 2009 and expires on May 28, 2010. In June 2009, AHD repaid a portion of its borrowings under the credit facility, with a resulting balance of $16.0 million outstanding under the credit facility at June 30, 2009. In addition, in accordance with the June 2009 amendment to its credit facility (see Note 8), AHD is prohibited from borrowing additional amounts under its credit facility once the amounts have been repaid. In accordance with SFAS No. 133, 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 of this reduction in borrowings under the credit facility below the notional amount of the interest rate derivative contract, the Company recognized an expense of $0.2 million within other loss, net in its consolidated statement of operations for the three and six months ended June 30, 2009.

At June 30, 2009, APL had interest rate derivative contracts having aggregate notional principal amounts of $450.0 million. Under the terms of these agreements, APL will pay weighted average interest rates of 3.02%, plus the applicable margin as defined under the terms of its credit facility (see Note 8), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. The APL interest rate swap agreements were in effect as of June 30, 2009 and expire during periods ranging from January 30, 2010 through April 30, 2010. Beginning May 29, 2009, APL discontinued hedge accounting for its interest rate derivatives which were qualified as hedges under SFAS No. 133. As such, subsequent changes in fair value of these derivatives will be recognized immediately within other loss, net in the Company’s consolidated statements of operations. The fair value of these derivative instruments at May 29, 2009, which was recognized within accumulated other comprehensive income within stockholders’ equity on the Company’s consolidated balance sheet, will be reclassified to the Company’s consolidated statements of operations in the future at the time the originally hedged physical transactions affect earnings.

The following table summarizes AHD and APL’s derivative activity for the periods indicated (amounts in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Loss from cash and non-cash settlement of qualifying hedge instruments⁽¹⁾	$	(7,327	)	$	(33,152	)	$	(27,502	)	$	(50,795	)
Gain/(loss) from change in market value of non-qualifying derivatives⁽²⁾		2,509			(136,736	)		(42,481	)		(207,932	)
Gain/(loss) from change in market value of ineffective portion of qualifying derivatives⁽²⁾		—			1,934			10,813			(3,726	)
Loss from cash and non-cash settlement of non-qualifying derivatives⁽²⁾		(21,105	)		(184,564	)		13,390			(196,489	)
Loss from cash settlement of interest rate derivatives⁽³⁾		(3,125	)		(207	)		(6,179	)		(207	)

(1)	Included within transmission, gathering and processing revenue on the Company’s consolidated statements of operations.

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

(3)	Included within interest expense on the Company’s consolidated statements of operations.

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


	June 30, 2009
	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments under SFAS No. 133:
N/A		$	—		$	—
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts		$	—	Current portion of derivative liability	$	(8,715	)
Commodity contracts	Current portion of derivative asset		1,815			—
Commodity contracts	Long-term derivative asset		1,606			—
Commodity contracts	Current portion of derivative liability		6,848	Current portion of derivative liability		(56,337	)
Commodity contracts	Long-term derivative liability		3,151	Long-term derivative liability		(15,899	)

		$	13,420		$	(80,951	)

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


	Three months ended June 30, 2009
	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			Location of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)			Location of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
Derivatives in SFAS No. 133 cash flow hedging relationships:
N/A
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts	$	(3,125	)	Interest expense	$	—		N/A
Commodity contracts⁽¹⁾		(10,894	)	Natural gas and liquids revenue		(13,381	)	Other loss, net
Commodity contracts⁽²⁾		—		N/A		(4,155	)	Other loss, net

	$	(14,019	)		$	(17,536	)

(1)	Hedges previously designated as cash flow hedges

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


	Six months ended June 30, 2009
	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			Location of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)			Location of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
Derivatives in SFAS No. 133 cash flow hedging relationships:
N/A
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts	$	(6,179	)	Interest expense	$	—		N/A
Commodity contracts⁽¹⁾		(26,864	)	Natural gas and liquids revenue		(22,908	)	Other loss, net
Commodity contracts⁽²⁾		—		N/A		35,665		Other loss, net

	$	(33,043	)		$	12,757

(1)	Hedges previously designated as cash flow hedges

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

As of June 30, 2009, the AHD had the following interest rate derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swap


Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Liability⁽¹⁾
					(in thousands)
May 2008-May 2010	$	25,000,000	Pay 3.01% —Receive LIBOR	2009	$	(323	)
				2010		(221	)

				Total AHD net liability	$	(544	)

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

As of June 30, 2009, APL had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swap


Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Liability⁽¹⁾
					(in thousands)
January 2008-anuary 2010	$	200,000,000	Pay 2.88% —Receive LIBOR	2009	$	(2,480	)
				2010		(351	)

					$	(2,831	)

April 2008-April 2010	$	250,000,000	Pay 3.14% —Receive LIBOR	2009	$	(3,430	)
				2010		(1,910	)

					$	(5,340	)

Natural Gas Liquids Sales – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability⁽²⁾
	(gallons)	(per gallon)		(in thousands)
2009	11,088,000	$	0.745	$	(573	)

Crude Oil Sales Options (associated with NGL volume)


Production Period Ended December 31,	Crude Volume	Associated NGL Volume	Average Crude Price⁽⁴⁾		Fair Value Asset/(Liability)⁽³⁾			Option Type
	(barrels)	(gallons)	(per barrel)		(in thousands)
2009	234,000	13,185,000	$	60.97	$	1,234		Puts purchased
2009	1,055,400	59,081,820	$	84.75		(2,622	)	Calls sold
2010	486,000	27,356,700	$	61.24		3,838		Puts purchased
2010	3,127,500	213,088,050	$	86.20		(22,103	)	Calls sold
2010	714,000	45,415,440	$	132.17		708		Calls purchased⁽⁵⁾
2011	606,000	33,145,560	$	100.70		(4,065	)	Calls sold
2011	252,000	13,547,520	$	133.16		764		Calls purchased⁽⁵⁾
2012	450,000	25,893,000	$	102.71		(3,746	)	Calls sold
2012	180,000	9,676,800	$	134.27		801		Calls purchased⁽⁵⁾

					$	(25,191	)

Natural Gas Sales – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Asset⁽³⁾
	(mmbtu)⁽⁶⁾	(per mmbtu)⁽⁶⁾		(in thousands)
2009	240,000	$	8.000	$	866

Natural Gas Basis Sales


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset⁽³⁾
	(mmbtu)⁽⁶⁾	(per mmbtu)⁽⁶⁾			(in thousands)
2009	2,460,000	$	(0.558	)	$	27
2010	2,220,000	$	(0.607	)		124

					$	151

Natural Gas Purchases – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability⁽³⁾
	(mmbtu)⁽⁶⁾	(per mmbtu)⁽⁶⁾		(in thousands)
2009	5,160,000	$	8.687	$	(22,156	)
2010	4,380,000	$	8.635		(12,414	)

				$	(34,570	)

Natural Gas Basis Purchases


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Liability⁽³⁾
	(mmbtu)⁽⁶⁾	(per mmbtu)⁽⁶⁾			(in thousands)
2009	7,380,000	$	(0.659	)	$	(83	)
2010	6,600,000	$	(0.590	)		(111	)

					$	(194	)

Ethane Put Options


Production Period Ended December 31,	Associated NGL Volume	Average Price⁽⁴⁾		Fair Value Liability⁽¹⁾			Option Type
	(gallons)	(per gallon)		(in thousands)
2009	630,000	$	0.340	$	(40	)	Puts purchased

Propane Put Options


Production Period Ended December 31,	Associated NGL Volume	Average Price⁽⁴⁾		Fair Value Asset⁽¹⁾		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	15,498,000	$	0.767	$	752	Puts purchased

Isobutane Put Options


Production Period Ended December 31,	Associated NGL Volume	Average Price⁽⁴⁾		Fair Value Asset⁽¹⁾		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	1,134,000	$	0.969	$	20	Puts purchased

Normal Butane Put Options


Production Period Ended December 31,	Associated NGL Volume	Average Price⁽⁴⁾		Fair Value Asset⁽¹⁾		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	9,324,000	$	0.964	$	585	Puts purchased


Natural Gasoline Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Price⁽⁴⁾		Fair Value Asset⁽¹⁾		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	5,796,000	$	1.267	$	358	Puts purchased

Crude Oil Sales


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability⁽³⁾
	(barrels)	(per barrel)		(in thousands)
2009	15,000	$	62.700	$	(131	)

Crude Oil Sales Options


Production Period Ended December 31,	Volumes	*Average Crude Price⁽⁴⁾***		Fair Value Asset(Liability)⁽³⁾			Option Type
	(barrels)	(per barrel)		(in thousands)
2009	231,000	$	63.017	$	1,100		Puts purchased
2009	153,000	$	84.881		(434	)	Calls sold
2010	174,000	$	61.111		1,361		Puts purchased
2010	234,000	$	88.088		(1,557	)	Calls sold
2011	72,000	$	93.109		(699	)	Calls sold
2012	48,000	$	90.314		(620	)	Calls sold

				$	(849	)

			Total APL net liability	$	(66,987	)

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

⁽²⁾	Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas, light crude and propane prices.

⁽³⁾	Fair value based on forward NYMEX natural gas and light crude prices, as applicable.

⁽⁴⁾	Average price of options based upon average strike price adjusted by average premium paid or received.

⁽⁵⁾	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.

⁽⁶⁾	Mmbtu represents million British Thermal Units

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


	June 30, 2009			December 31, 2008
Current portion of derivative asset	$	118,792		$	152,727
Long-term derivative asset		56,071			69,451
Current portion of derivative liability		(62,189	)		(73,776	)
Long-term derivative liability		(43,081	)		(59,103	)

Total Company net asset	$	69,593		$	89,299

NOTE 10 — FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company applies the provisions of SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”) to its financial instruments. SFAS No. 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS No. 157’s 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 the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities for ATN’s, APL’s and AHD’s outstanding commodity derivative contracts (see Note 9) and the Company’s Supplemental Employment Retirement Plan (“SERP” - see Note 17). ATN’s and APL’s commodity hedges, with the exception of APL’s NGL fixed price swaps and NGL options, are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. ATN’s, AHD’s and APL’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model and are therefore defined as Level 2 fair value measurements. The Company’s SERP is calculated based on observable actuarial inputs developed by a third-party actuary and therefore is defined as a Level 2 fair value measurement, while the asset related to the funding of the SERP in a rabbi trust is based on third-party financial statements and is therefore also defined as a Level 2 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. In accordance with SFAS No. 157, the following table represents the Company’s assets and liabilities recorded at fair value as of June 30, 2009 (in thousands):


	Level 1		Level 2			Level 3		Total
SERP liability	$	—	$	(3,461	)	$	—	$	(3,461	)
SERP asset funded in rabbi trust		—		3,382			—		3,382
Interest rate derivatives		—		(13,530	)		—		(13,530	)
APL commodity-based derivatives		—		(59,919	)		1,103		(58,816	)
ATN commodity-based derivatives		—		141,939			—		141,939

Total	$	—	$	68,411		$	1,103	$	69,514

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, 2009 (in thousands):


	NGL Fixed Price Swaps			NGL Sales Options			Total
Balance – December 31, 2008	$	1,509		$	12,316		$	13,825
New options contracts		—			(1,024	)		(1,024	)
Cash settlements from unrealized gain (loss)⁽¹⁾		(4,215	)		(11,410	)		(15,625	)
Cash settlements from other comprehensive income⁽¹⁾		3,700			—			3,700
Net change in unrealized gain (loss)⁽²⁾		(1,567	)		(1,061	)		(2,628	)
Deferred option premium recognition		—			2,855			2,855
Net change in other comprehensive loss		—			—			—

Balance – June 30, 2009	$	(573	)	$	1,676		$	1,103

(1)	Included within transmission, gathering and processing revenue on the Company’s consolidated statements of operations.

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

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, 2009 and December 31, 2008, which consists principally of APL’s term loan, ATN and APL’s Senior Notes and borrowings under the ATN, AHD and APL’s credit facilities, were $1,971.5 million and $1,911.4 million, respectively, compared with the carrying amounts of $2,154.6 million and $2,413.1 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 7).

Information for assets that are measured at fair value on a nonrecurring basis for the three and six months ended June 30, 2009 and 2008 is as follows (in thousands):


	Three Months Ended June 30, 2009				Six Months Ended June 30, 2009
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	166	$	166	$	596	$	596

Total	$	166	$	166	$	596	$	596

NOTE 11 — 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 ATN Sponsored Investment Partnerships.ATN conducts certain activities through, and a substantial portion of its revenues are attributable to, the Partnerships. ATN serves as general partner of the Partnerships and assumes customary rights and obligations for the Partnerships. As the general partner, ATN 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. ATN 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 two agreements that govern its ongoing relationship with Resource America, Inc. (“RAI”), its former parent, that are still in effect at June 30, 2009. These agreements are the tax matters agreement and the transition services agreement. The tax matters agreement governs the respective rights, responsibilities and obligations of the Company and RAI with respect to tax liabilities and benefits, tax attributes, tax contests and other matters regarding income taxes, non-income taxes and related tax matters. The transition services agreement governs the provision of support services by the Company to RAI and by RAI to the Company, such general and administrative functions. The Company reimburses RAI for various costs and expenses it incurs for these services on behalf of the Company, primarily payroll and rent. For the three months ended June 30, 2009 and 2008, the Company’s reimbursements to RAI totaled $0.3 million and $0.2 million, respectively, and $0.6 million and $0.4 million for the six months ended June 30, 2009 and 2008, respectively. At June 30, 2009 and December 31, 2008, reimbursements to RAI totaling $0.2 million and $0.1 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, ATN entered into new gas gathering agreements with Laurel Mountain which superseded the existing master natural gas gathering agreement and omnibus agreement between ATN and APL. Under the new gas gathering agreement, ATN 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 agreement contains additional provisions which define certain obligations and options of each party to build and connect newly drilled wells to any Laurel Mountain gathering system.

NOTE 12 — COMMITMENTS AND CONTINGENCIES

General Commitments

The Company, through ATN, is the managing general partner of various energy 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 energy partnerships have the right to present their interests for purchase by the Company, as managing general partner. ATN is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on past experience, the management of ATN believes that any liability incurred would not be material. ATN may be required to subordinate a part of its net partnership revenues from its energy partnerships to the receipt by investor partners of cash distributions

from the energy partnerships 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 and six months ended June 30, 2009, $0.7 million and $0.9 million, respectively, of the Company’s net revenues were subordinated, which reduced its cash distribution received from the investment partnerships for the respective periods. No subordination was required for the three and six months ended June 30, 2008.

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, 2009, the Company and its subsidiaries are committed to expend approximately $19.2 million on pipeline extensions, compressor station upgrades, and processing facility upgrades.

Legal Proceedings

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.

Following the announcement of the merger agreement on April 27, 2009 between the Company and ATN, the following actions were filed in Delaware Chancery Court purporting to challenge the merger:

•

Alonzo v. Atlas Energy Resources, LLC, et al., C.A. No. 4553-VCN (Del. Ch. filed 4/30/09);

•

Operating Engineers Constructions Industry and Miscellaneous Pension Fund v. Atlas America, Inc., et al., C.A. No. 4589-VCN (Del. Ch. filed 5/13/09);

•

Vanderpool v. Atlas Energy Resources, LLC, et al., C.A. No. 4604-VCN (Del. Ch. filed 5/15/09);

•

Farrell v. Cohen, et al., C.A. No. 4607-VCN (Del. Ch. filed 5/19/09); and

•

Montgomery County Employees’ Retirement Fund v. Atlas Energy Resources, L.L.C., et al., C.A. No. 4613-VCN (Del. Ch. filed 5/21/09).

On June 15, 2009, Vice Chancellor Noble issued an order consolidating all five lawsuits, renaming the actionIn re Atlas Energy Resources, LLC Unitholder Litigation, C.A. No. 4589-VCN, and appointing as co-lead plaintiffs Operating Engineers Construction Industry and Miscellaneous Pension Fund and Montgomery County Employees Retirement Fund. Plaintiffs filed a Verified Consolidated Class Action Complaint on July 1, 2009, which has superseded all prior complaints. On July 27, 2009, the Chancery Court granted the parties’ scheduling stipulation, setting a preliminary injunction hearing for September 4, 2009. The complaint advances claims of breach of fiduciary duty in connection with the merger agreement, including allegations of inadequate disclosures in connection with the unitholder vote on the merger, and seeks monetary damages or injunctive relief, or both. On August 7, 2009, Plaintiffs advised the Court by letter that they are not pursuing their motion for preliminary injunction and requested that the hearing date be removed from the Court’s calendar. Plaintiffs have advised counsel for the defendants that they intend to continue to pursue the case after the merger as a claim for money damages. 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 combined company after the merger. A preliminary injunction , had plaintiffs successfully pursued it, could have delayed or jeopardized the completion of the merger, and an adverse judgment granting permanent injunctive relief could have indefinitely enjoined completion of the merger. Based on the facts known to date, the defendants believe that the claims asserted against them in this lawsuit are without merit, and intend to defend themselves vigorously against the claims.

In January 2009, in the matter captioned “Elk City Oklahoma Pipeline, L.P. v. Northern Natural Gas Company”, (District Court of Tulsa County, Oklahoma), Elk City Oklahoma Pipeline, L.P. (“Elk City”), a subsidiary of APL’s, filed a petition against Northern Natural Gas Company (“NNG”), seeking a declaratory judgment related to the interpretation of a Purchase and Sale Agreement for certain pipeline and assets in Western Oklahoma which was entered into between the two parties on June 12, 2008 (the “PSA”). In March 2009, NNG filed a petition together with a motion for summary judgment alleging breach of the PSA for Elk City’s failure to complete the purchase and seeking specific performance or, alternatively, damages, in the matter captioned “Northern Natural Gas Company vs. Elk City Oklahoma Pipeline, L.P.”, (District Court of Tulsa County, Oklahoma). These matters were previously described in the Company’s quarterly report on Form 10-Q for the quarter ended March 31, 2009. Both matters were settled by agreement dated May 19, 2009. The settlement involved a monetary payment by Elk City, but does not require Elk City to purchase the pipeline assets. The amounts Elk City agreed to pay in connection with the settlement do not have a material impact on the Company’s financial condition or results of operations.

In June 2008, ATN’s wholly-owned subsidiary, Atlas America, LLC, was named as a co-defendant in the matter captionedCNX Gas Company, LLC (“CNX”) v. Miller Petroleum, Inc. (“Miller”), et al. (Chancery Court, Campbell County, Tennessee). In its complaint, CNX 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 ATN 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 ATN; however, CNX has appealed this decision.

NOTE 13 — INCOME TAXES

The Company accounts for income taxes under the asset and liability method pursuant to SFAS No. 109, “Accounting for Income Taxes” (“SFAS No. 109”). Under SFAS 109, 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, 2009 and December 31, 2008, the Company determined that no material valuation allowance was necessary.

The Company applies the provisions of FASB Interpretation 48, Accounting for Uncertainty in Income Taxes (“FIN 48”)to its income tax positions. As required by FIN 48, which clarifies Statement 109,Accounting for Income Taxes, 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 the more-likely-than-not threshold, the amount recognized in the 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 FIN 48 to all tax positions for which the statute of limitation remains open, and there were no additions, reductions or settlements in unrecognized tax benefits during the three and six months ended June 30, 2009 and 2008. The Company has no material uncertain tax positions at June 30, 2009.

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 2005. 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 14 — COMMON STOCK

Stock Repurchase Plan

In September 2008, the Company’s Board of Directors approved a stock repurchase program of up to $50.0 million at a price not to exceed $36.00 per share. The daily repurchase amount was limited to 50,000 shares. The Company purchased 595,292 of its shares during September and October 2008 for a total price of $20.0 million under this program. In addition, the Company utilized the remaining $20.0 million of availability under a stock repurchase program approved in September 2005 to purchase 560,291 shares in August and September 2008. The average price for the shares purchased during 2008 was $34.76 per share.

Stock Splits

On April 22, 2008, the Company’s Board of Directors approved a three-for-two stock split of the Company’s common stock effected in the form of a 50% stock dividend. All shareholders of record as of May 21, 2008 received one additional share of common stock for every two shares of common stock held on that date. The additional shares of common stock were distributed on May 30, 2008. Information pertaining to shares and earnings per share has been restated for the three and six months ended June 30, 2008 in the accompanying consolidated financial statements and notes to the consolidated financial statements to reflect this split.

NOTE 15 — ISSUANCE OF SUBSIDIARY UNITS

The Company accounts for offerings by its subsidiaries in accordance with Staff Accounting Bulletin No. 51, “Accounting by the Parent in Consolidation for Sales of Stock by a Subsidiary” (“SAB 51”) and SFAS No. 160. The Company has adopted a policy to recognize gains on such transactions as a credit to equity rather than as income. These gains represent the Company’s portion of the excess net offering price per unit of each of its subsidiary’s units to the book carrying amount per unit.

In June 2008, APL sold 5,750,000 common limited partner units in a public offering at a price of $37.52 per unit, yielding net proceeds of approximately $206.6 million. Also in June 2008, the Company purchased 308,109 AHD common units and 1,112,000 APL common limited partner units through a private placement transaction at a price of $32.50 and $36.02 per unit, respectively, for net proceeds of approximately $10.0 million and $40.1 million, respectively. AHD utilized the net proceeds from the sale to purchase 278,000 common units of APL, which in turn utilized the proceeds to partially fund the early termination of certain derivative agreements (see Note 9).

In May 2008, ATN sold 2,070,000 of its Class B common units in a public offering yielding net proceeds of approximately $82.5 million. The net proceeds were used to repay a portion of ATN’s outstanding balance under its revolving credit facility. A gain of $17.7 million, net of an income tax provision of $8.7 million, in accordance with SAB 51 and SFAS No. 160 was recorded in consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $26.4 million to non-controlling interest, during the year ended December 31, 2008.

In May 2008, the Company purchased 600,000 of ATN’s Class B common units in a private placement at $42.00 per common unit, increasing the Company’s ownership of ATN’s common units to 29,952,996 common units. ATN’s net proceeds of $25.2 million were used to repay a portion of its outstanding balance under its revolving credit facility.

NOTE 16 – CASH DISTRIBUTIONS

Atlas Energy Resources Cash Distributions. ATN is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its limited liability company agreement) for that quarter to its Class A and Class B common unitholders in accordance with their respective percentage interests. If Class A and Class B common unit distributions exceed specified target levels in any quarter during or subsequent to the completion of certain tests set forth in ATN’s limited liability company agreement, the Company will receive management incentive distributions of between 15% and 50% of such distributions in excess of the specified target levels as defined in the Company’s limited liability company agreement. The tests within the Company’s limited liability company agreement include a 12-quarter test which requires, among other things, that ATN pay a quarterly cash distribution per unit that on average exceeds $0.42 per unit for 12 full, consecutive, non-overlapping calendar quarters and does not have a calendar quarter during which the distribution per unit was reduced. Effective April 27, 2009, ATN has suspended further distributions pursuant to its merger agreement with the Company (see Note 1). ATN’s suspension of the quarterly distribution during the three months and six months ended June 30, 2009 means that it has not met the tests within the limited liability company agreement and, as such, the Company will not receive the MIIs that were previously reserved for during previous periods. Distributions declared by ATN from January 1, 2008 through June 30, 2009 were as follows:


Date Cash Distribution Paid or Payable	For Quarter Ended	Cash Distribution Per Common Unit		Total Cash Distribution to the Company
				(in thousands)
February 14, 2008	December 31, 2007	$	0.57	$	17,437
May 15, 2008	March 31, 2008	$	0.59	$	18,410
August 14, 2008	June 30, 2008	$	0.61	$	19,060
November 14, 2008	September 30, 2008	$	0.61	$	19,060
February 13, 2009	December 31, 2008	$	0.61	$	19,060

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, 2008 through June 30, 2009 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 14, 2008	December 31, 2007	$	0.93	$	36,051	$	5,092
May 15, 2008	March 31, 2008	$	0.94	$	36,450	$	7,891
August 14, 2008	June 30, 2008	$	0.96	$	44,096	$	9,308
November 14, 2008	September 30, 2008	$	0.96	$	44,105	$	9,312
February 13, 2009	December 31, 2008	$	0.38	$	17,463	$	2,545
May 13, 2009	March 31, 2009	$	0.15	$	7,147	$	1,010

In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems, AHD, which holds all of the incentive distribution rights in APL, agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. AHD also agreed that the resulting allocation of incentive distribution rights back to APL would be after AHD receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter.

APL did not declare a cash distribution for the quarter ended June 30, 2009. On May 29, 2009, APL entered into an amendment to its senior secured credit facility (see Note 8), which, among other things, requires that it pay no cash distributions during the remainder of the year ended December 31, 2009 and allows it to pay cash distributions beginning January 1, 2010 if its senior secured leverage ratio is above 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, 2008 through June 30, 2009 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, 2008	December 31, 2007	$	0.34	$	5,950
May 20, 2008	March 31, 2008	$	0.43	$	7,525
August 19, 2008	June 30, 2008	$	0.51	$	9,082
November 19, 2008	September 30, 2008	$	0.51	$	9,082
February 19, 2009	December 31, 2008	$	0.06	$	1,068

There was no distribution declared by AHD for the quarter ended March 31, 2009 or June 30, 2009. 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 is in effect (see Note 8).

NOTE 17 – BENEFIT PLANS

Incentive Bonus Plan

The Company’s shareholders approved an Incentive Bonus Plan (“Bonus Plan”) for the benefit of its senior executive officers. The total amount of cash bonus awards to be made under the Bonus Plan for any plan year will be based on performance goals related to objective business criteria for such year. For any plan year, the Company’s performance must achieve levels targeted by the Company’s compensation committee, as established at the beginning of each year, for any bonus awards to be made. Aggregate bonus awards to all participants under the Bonus Plan may not exceed a limit as set by the compensation committee. The compensation committee has the authority to reduce the total amount of bonus awards, if any, to be made to the eligible employees for any plan year based on its assessment of personal performance or other factors as the Board may determine to be relevant or appropriate. The compensation committee may permit participants to elect to defer awards. For the three month periods ended June 30, 2009 and 2008, the Company recognized $1.7 million and $1.3 million, respectively, of estimated expenses under the plan and $3.5 million and $2.8 million for the six month periods ended June 30, 2009 and 2008, respectively.

Stock Incentive Plan

The Company has a Stock Incentive Plan (the “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 and its subsidiaries follow the provisions of SFAS No. 123(R), “Share-Based Payment”, as revised (“SFAS No. 123(R)”), for their stock compensation. Generally, the approach to accounting in SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.

Stock Options. Options under the Plan become exercisable as to 25% of the optioned shares each year after the date of grant, 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 issues new shares when stock options are exercised or units are converted to shares. There were 12,656 options exercised during the three and six months ended June 30, 2009. No options were exercised during the three and six months ended June 30, 2008, respectively.

The following tables set forth the Plan activity for the three and six months ended June 30, 2009 and 2008:


	Three Months Ended June 30,
	2009					2008
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of period		3,558,226		$	16.89		3,540,380	$	16.89
Granted		—			—		—		—
Exercised		(12,656	)	$	11.32		—		—
Cancelled		—			—		—		—
Forfeited		(8,438	)	$	11.32		—		—

Outstanding, end of period⁽¹⁾⁽²⁾		3,537,132		$	16.96		3,540,380	$	16.89

Options exercisable, end of period⁽³⁾		2,539,674		$	13.35		2,144,650	$	11.64

Non-cash compensation expense recognized (in thousands)	$	974				$	983


	Six Months Ended June 30,
	2009					2008
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of period		3,495,351		$	16.97		2,715,380	$	12.10
Granted		100,000		$	13.35		825,000	$	32.68
Exercised		(12,656	)	$	11.32		—		—
Cancelled		(15,187	)	$	11.32		—		—
Forfeited		(30,376	)	$	11.32		—		—

Outstanding, end of period⁽¹⁾⁽²⁾		3,537,132		$	16.96		3,540,380	$	16.89

Options exercisable, end of period⁽³⁾		2,539,674		$	13.35		2,144,650	$	11.64

Non-cash compensation expense recognized (in thousands)	$	1,894				$	1,945

Available for grant at June 30, 2009		763,725

(1)	The weighted average remaining contractual life for outstanding options at June 30, 2009 was 7.0 years.

(2)	The aggregate intrinsic value of options outstanding at June 30, 2009 was approximately $3.2 million.

(3)	The weighted average outstanding contractual life of exercisable options at June 30, 2009 is 6.2 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,
	2009	2008	2009			2008
Expected dividend yield	—	—		0.6	%		0.4	%
Expected stock price volatility	—	—		36	%		33	%
Risk-free interest rate	—	—		2.2	%		2.6	%
Expected term (in years)	—	—		6.25			6.25
Fair value of stock options granted	—	—	$	4.89		$	11.75

Deferred Units and Restricted Shares

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

Restricted shares are granted from time to time to employees of the Company. Each unit represents the right to receive one share of the Company’s common stock upon vesting. The shares are issued to the participant, held in escrow, and paid 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, 2009 and 2008:


	Three Months Ended June 30,
	2009					2008
	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		11,670		$	24.29		20,270		$	14.31
Granted		4,805		$	15.60		1,523		$	49.26
Matured⁽¹⁾		(3,941	)	$	15.26		(9,429	)	$	7.96
Forfeited		—			—		—			—

Non-vested shares outstanding, end of period⁽²⁾		12,534		$	23.80		12,364		$	23.46

Non-cash compensation expense recognized (in thousands)	$	26				$	24


	Six Months Ended June 30,
	2009					2008
	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		12,512		$	24.05		21,395		$	14.65
Granted		4,805		$	15.60		1,523		$	49.26
Matured⁽¹⁾		(4,783	)	$	16.22		(10,554	)	$	9.33
Forfeited		—			—		—			—

Non-vested shares outstanding, end of period⁽²⁾		12,534		$	23.80		12,364		$	23.46

Non-cash compensation expense recognized (in thousands)	$	51				$	49

(1)	The intrinsic values for phantom unit awards vested during the three months ended at June 30, 2009 and 2008 were $0.1 million and $0.5 million, respectively, and $0.1 million and $28,000 during the six months ended June 30, 2009 and 2008, respectively.

(2)	The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2009 was $0.2 million.

At June 30, 2009, the Company had unamortized compensation expense related to its unvested portion of the options and units of $7.2 million that the Company expects to recognize over the next four years.

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 are made at the discretion of the Company’s Board of Directors. Any dividends which may be paid on allocated shares will reduce retained earnings; dividends on unearned ESOP shares will be used to service the related debt.

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 June 30, 2009, there were 767,378 shares allocated to participants and 49,861 shares which are unallocated. All unallocated shares will be allocated to participating employees at the end of the ESOP’s fiscal year on September 30, 2009. Participants will receive shares upon vesting, which occurs over a five year period, beginning after the participant’s second year of service. The fair value of unearned ESOP shares was $0.9 million at June 30, 2009.

Supplemental Employment Retirement Plan (“SERP”)

The Company entered into an employment agreement with its Chairman of the Board, Chief Executive Officer and President, Edward E. Cohen, pursuant to which the Company has agreed to provide him with a SERP and with certain financial benefits upon termination of his employment. Under the SERP, Mr. Cohen will be paid an annual benefit equal to the product of (a) 6.5% multiplied by, (b) his base salary at the time of

his retirement, death or other termination of employment with the Company, multiplied by, (c) the amount of years he shall be employed by the Company commencing upon the effective date of the SERP agreement, limited to an annual maximum benefit of 65% of his final base salary and a minimum of 26% of his final base salary. During the three months ended June 30, 2009 and 2008, expense recognized with respect to this commitment was $0.2 million and $0.4 million, respectively, and $0.3 million and $0.7 million during the six months ended June 30, 2009 and 2008, respectively.

During the six months ended June 30, 2009, the Company funded $3.2 million of the outstanding liability with a financial institution in a rabbi trust, which is included in other assets on the Company’s consolidated balance sheet. As of June 30, 2009, the actuarial present value of the expected postretirement obligation due under this the SERP was $3.5 million, which is 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, 2009			December 31, 2008
Other liabilities	$	(3,461	)	$	(3,209	)
Accumulated other comprehensive income		210			255
Deferred income tax asset		123			150

Net amount recognized	$	(3,128	)	$	(2,804	)

The estimated amount that will be amortized from accumulated other comprehensive income into expense for the year ended December 31, 2009 is $0.1 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 performance 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. 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, 2009, AHD had 1,136,300 phantom units and unit options outstanding under the AHD LTIP, with 962,650 phantom units and unit options available for grant.

AHD Phantom Units.A phantom unit entitles a Participant to receive a common unit of AHD, without payment of an exercise price, upon vesting of the phantom unit or, at the discretion of the AHD LTIP Committee, cash equivalent to the then fair market value of a common limited partner unit of AHD. In tandem with phantom unit grants, the AHD LTIP Committee may grant a Participant a distribution equivalent right (“DER”), which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions AHD makes on a common unit during the period such phantom unit is outstanding. The AHD LTIP Committee will determine the vesting period for phantom units. Through June 30, 2009, phantom units granted under the AHD LTIP generally will vest 25% three years from the date of grant and 100% four years from the date of grant. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the AHD LTIP Committee, although no awards currently outstanding contain any such provision. 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, 2009, 44,425 units will vest within the following twelve months. All phantom units outstanding under the AHD LTIP at June 30, 2009 include

DERs granted to the Participants by the AHD LTIP Committee. The amount paid with respect to AHD’s LTIP DERs was $0.1 million for the three months ended June 30, 2008, and $14,000 and $0.2 million for the six months ended June 30, 2009 and 2008, respectively. No DER payments were made during the three months ended June 30, 2009. These amounts were recorded as an adjustment of non-controlling interests on the Company’s consolidated balance sheet.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009			2008
Outstanding, beginning of period		181,300		225,475		226,300			220,825
Granted⁽¹⁾		—		—		—			4,650
Matured		—		—		—			—
Forfeited		—		—		(45,000	)		—

Outstanding, end of period⁽²⁾		181,300		225,475		181,300			225,475

Non-cash compensation expense recognized (in thousands)	$	291	$	372	$	(17	)	$	738

⁽¹⁾

The weighted average price for phantom unit awards on the date of grant, which is utilized in the calculation of compensation expense and does not represent an exercise price to be paid by the recipient, was $32.28 for the six months ended June 30, 2008. There were no grants awarded for the three months ended June 30, 2009 and 2008 and the six months ended June 30, 2009.

⁽²⁾	The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2009 is $0.3 million.

At June 30, 2009, AHD had approximately $1.2 million of unrecognized compensation expense related to unvested phantom units outstanding under AHD’s LTIP based upon the fair value of the awards.

AHD Unit Options.A unit option entitles a Participant to receive a common unit of AHD upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of AHD’s common unit as determined by the AHD LTIP Committee 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, 2009, unit options granted under the AHD LTIP generally will vest 25% three years from the date of grant and 100% four years from the date of grant. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by AHD’s LTIP Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control of AHD, as defined in the AHD LTIP. There are 213,750 unit options outstanding under the AHD LTIP at June 30, 2009 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,
	2009				2008
	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		—		—		—		—
Matured		—		—		—		—
Forfeited		—		—		—		—

Outstanding, end of period⁽¹⁾⁽²⁾		955,000	$	20.54		1,215,000	$	22.56

Options exercisable, end of period		—		—		—		—

Non-cash compensation expense recognized (in thousands)	$	222			$	309


	Six Months Ended June 30,
	2009					2008
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of period		1,215,000		$	22.56		1,215,000	$	22.56
Granted		100,000		$	3.24		—		—
Matured		—			—		—		—
Forfeited		(360,000	)	$	22.56		—		—

Outstanding, end of period⁽¹⁾⁽²⁾		955,000		$	20.54		1,215,000	$	22.56

Options exercisable, end of period		—			—		—		—

Non-cash compensation expense recognized (in thousands)	$	(351	)			$	619

(1)	The weighted average remaining contractual lives for outstanding options at June 30, 2009 were 7.6 years.

(2)	There was no intrinsic value of options outstanding at June 30, 2009.

At June 30, 2009, AHD had approximately $0.9 million of unrecognized compensation expense related to unvested unit options outstanding under AHD’s LTIP based upon the fair value of the awards.

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:


	Three and 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

APL Long-Term Incentive Plan

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

APL Phantom Units. A phantom unit entitles a grantee to receive a common unit, without payment of an exercise price, upon vesting of the phantom unit or, at the discretion of the APL LTIP Committee, cash equivalent to the fair market value of an APL common unit. In addition, the APL LTIP Committee may grant

a participant a DER, which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions APL makes on a common unit during the period the phantom unit is outstanding. A unit option entitles the grantee to purchase APL’s common limited partner units at an exercise price determined by the APL LTIP Committee at its discretion. The APL LTIP Committee also has discretion to determine how the exercise price may be paid by the participant. Except for phantom units awarded to non-employee managing board members of AHD, the APL LTIP Committee will determine the vesting period for phantom units and the exercise period for options. Through June 30, 2009, phantom units granted under the APL LTIP generally had vesting periods of four years. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the APL LTIP Committee, although no awards currently outstanding contain any such provision. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards will automatically vest upon a change of control, as defined in the APL LTIP. Of the units outstanding under the APL LTIP at June 30, 2009, 29,376 units will vest within the following twelve months. All phantom units outstanding under the APL LTIP at June 30, 2009 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL LTIP DERs were $11,000 and $0.2 million for the three months ended June 30, 2009 and 2008, respectively, and $0.1 million and $0.3 million for the six months ended June 30, 2009 and 2008, respectively. These amounts were recorded as reductions of non-controlling interest on the Company’s consolidated balance sheet.

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,
	2009			2008			2009			2008
Outstanding, beginning of period		101,929			171,087			126,565			129,746
Granted⁽¹⁾		500			345			2,000			54,296
Matured⁽²⁾		(25,208	)		(21,509	)		(35,094	)		(33,369	)
Forfeited		(500	)		—			(16,750	)		(750	)

Outstanding, end of period⁽³⁾		76,721			149,923			76,721			149,923

Non-cash compensation expense recognized (in thousands)	$	351		$	697		$	256		$	1,183

⁽¹⁾

The weighted average prices for phantom unit awards on the date of grant, which is utilized in the calculation of compensation expense and does not represent an exercise price to be paid by the recipient, were $5.20 and $43.42 for awards granted for the three months ended June 30, 2009 and 2008, respectively, and $4.75 and $44.43 for awards granted for the six months ended June 30, 2009 and 2008, respectively.

⁽²⁾	The intrinsic values for phantom unit awards exercised during the three months ended June 30, 2009 and 2008 were $0.1 million and $0.9 million, respectively, and $0.2 million and $1.4 million during the six months ended June 30, 2009 and 2008, respectively.

⁽³⁾	The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2009 was $0.6 million.

At June 30, 2009, APL had approximately $1.1 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIP based upon the fair value of the awards.

APL Unit Options.A unit option entitles a participant to receive a common unit of APL upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of APL’s common unit as determined by the APL LTIP Committee 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, 2009, unit options granted under APL’s LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the APL

LTIP Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control of APL, as defined in the APL’s LTIP. There were 25,000 unit options outstanding under APL’s LTIP at June 30, 2009 that will vest within the following twelve months. The following table sets forth the APL LTIP unit option activity for the periods indicated:


	Three Months Ended June 30,
	2009				2008
	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		—		—	—	—
Matured		—		—	—	—
Forfeited		—		—	—	—

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

Options exercisable, end of period		—		—	—	—

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

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


	Six Months Ended June 30,
	2009				2008
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options	Weighted Average Exercise Price
Outstanding, beginning of period		—		—	—	—
Granted		100,000	$	6.24	—	—
Matured		—		—	—	—
Forfeited		—		—	—	—

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

Options exercisable, end of period		—		—	—	—

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

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

(1)	The weighted average remaining contractual life for outstanding options at June 30, 2009 was 9.5 years.

(2)	There was $0.2 million aggregate intrinsic value of options outstanding at June 30, 2009.

At June 30, 2009, APL had approximately $10,000 of unrecognized compensation expense related to unvested unit options outstanding under the APL’s LTIP 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:


	Three & Six Months Ended June 30, 2009
Expected dividend yield	11.0	%
Expected stock price volatility	20	%
Risk-free interest rate	2.2	%
Expected term (in years)	6.3

APL Incentive Compensation Agreements

APL has incentive compensation agreements which have granted awards to certain key employees retained from previously consummated acquisitions. These individuals were entitled to receive common units of APL upon the vesting of the awards, which was dependent upon the achievement of certain predetermined performance targets through September 30, 2007. At September 30, 2007, the predetermined performance targets were achieved and all of the awards under the incentive compensation agreements vested. Of the total common units to be issued under the incentive compensation agreements, 58,822 common units were issued during the year ended December 31, 2007. The ultimate number of common units to be issued under the incentive compensation agreements was determined principally by the financial performance of certain APL assets during the year ended December 31, 2008 and the market value of APL’s common units at December 31, 2008. APL’s incentive compensation agreements also dictate that no individual covered under the agreements shall receive an amount of common units in excess of one percent of the outstanding common units of APL at the date of issuance. Common unit amounts due to any individual covered under the agreements in excess of one percent of the outstanding common units of APL shall be paid in cash.

As of December 31, 2008, APL recognized in full within its consolidated statements of operations the compensation expense associated with the vesting of awards issued under its incentive compensation agreements, therefore no compensation expense was recognized during the three and six months ended June 30, 2009. APL recognized compensation expense of $0.5 million and a reduction of compensation expense of $2.8 million for the three and six months ended June 30, 2008 related to the vesting of awards under its incentive compensation agreements. The non-cash compensation expense adjustments for the three and six months ended June 30, 2008 were principally attributable to changes in APL’s common unit market price, which was utilized in the calculation of the non-cash compensation expense for these awards, at June 30, 2008 when compared with the common unit market price at earlier periods and adjustments based upon the achievement of actual financial performance targets through June 30, 2008. APL follows SFAS No. 123(R) and recognized compensation expense related to these awards based upon the fair value method. During the six months ended June 30, 2009, APL issued 348,620 common units to the certain key employees covered under APL’s incentive compensation agreements. No additional common units will be issued with regard to these agreements.

APL Executive Incentive Plan

In June 2009, APL adopted an executive incentive plan (the “APL Plan”), which provides cash incentive awards to certain employees of APL, but not “Named Executive Officers” of APL, as defined under Securities and Exchange Commission regulations (the “APL Plan Participants”). The APL Plan is administered by a committee (the “APL Plan Committee”) appointed by APL’s chief executive officer. Under the APL Plan, cash bonus units (“Bonus Unit”) may be awarded to the APL Plan Participants at the discretion of the APL Plan Committee. A Bonus Unit entitles an APL Plan Participant 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 Bonus Unit. The APL Plan Committee will determine the vesting period for Bonus Units. Through June 30, 2009, Bonus Units granted under the APL Plan vest ratably over a three year period from the date of grant. Awards under the APL Plan will automatically vest upon a change of control of APL, as defined in the APL Plan, and vesting will terminate upon termination of employment. During the three and six months ended June 30, 2009, the APL Plan Committee granted 325,000 Bonus Units to APL Plan Participants under the APL Plan. Of the Bonus Units outstanding under the APL Plan at June 30, 2009, 107,250 Bonus Units will vest within the following twelve months. APL follows SFAS No. 123(R) and recognized compensation expense related to these awards based upon the fair value. During the three and six months ended June 30, 2009, the Company recognized $0.1 million of compensation expense within general and administrative expense on the Company’s consolidated statements of operations with respect to the vesting of these awards. At June 30, 2009, the Company has recognized $0.1 million within accrued liabilities on its consolidated balance sheet with regard to the awards, which represents their fair value at June 30, 2009.

Atlas Energy Resources, LLC Long-Term Incentive Plan

ATN has a Long-Term Incentive Plan (“ATN LTIP”), which provides performance incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners. The LTIP is administered by ATN’s compensation committee, which may grant awards of restricted stock units, phantom units or unit options. Awards for a total of 3,742,000 common units may be granted under the LTIP. Awards granted after 2006 vest 25% after three years and 100% upon the four-year anniversary of grant, except for awards of 1,500 units to board members which vest 25% per year over four years. Awards granted in 2006 vest 25% per year over four years. Upon termination of service by a grantee, all unvested awards are forfeited. A restricted stock or phantom unit entitles a grantee to receive a common unit of ATN upon vesting of the unit or, at the discretion of ATN’s compensation committee, cash equivalent to the then fair market value of a common unit of ATN. In tandem with phantom unit grants, ATN’s compensation committee may grant a distribution equivalent right (“DER”), which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions ATN makes on a common unit during the period such phantom unit is outstanding.

Restricted Stock and Phantom Units. Under the ATN LTIP, 23,523 and 26,375 units of restricted stock and phantom units were awarded during the six months ended June 30, 2009 and 2008, respectively. 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.

The following table summarizes the activity of restricted stock and phantom units for the six months ended June 30, 2009:


	Units		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2008	768,829		$	23.86
Granted	23,523			14.50
Vested	(13,073	)		21.70
Forfeited	(8,000	)		20.78

Non-vested shares outstanding at June 30, 2009	771,279		$	23.65

Unit Options. There were no unit options granted during the six months ended June 30, 2009. During the six months ended June 30, 2008, 14,000 unit options were awarded under the ATN LTIP. Option awards expire 10 years from the date of grant and are generally granted with an exercise price equal to the market

price of ATN’s stock at the date of grant. ATN uses the Black-Scholes option pricing model to estimate the weighted average fair value per option granted. The following table sets forth option activity for the six months ended June 30, 2009:


	Units		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding at December 31, 2008	1,902,902		$	24.17
Granted	—			—
Exercised	—			—
Forfeited or expired	(7,500	)		23.06

Outstanding at June 30, 2009	1,895,402		$	24.18	7.4	$	0

Options exercisable at June 30, 2009	280,314		$	21.00	6.8

Available for grant at June 30, 2009	1,038,063

The following tables summarize information about unit options outstanding and exercisable at June 30, 2009:


	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
$21.00 – 23.06	1,647,302	7.4	$	22.59	280,314	$	21.00
$30.24 – 35.00	240,600	8.0	$	34.53	—		—
$37.79 and above	7,500	8.5	$	39.79	—		—

	1,895,402	7.4	$	24.18	280,314	$	21.00

ATN recognized $1.5 million and $1.3 million in compensation expense related to restricted stock units, phantom units and unit options for the three months ended June 30, 2009 and 2008, respectively. ATN recognized $3.0 million and $2.7 million in related compensation expense for the six months ended June 30, 2009 and 2008, respectively. ATN paid $0.3 million with respect to its ATN LTIP DERs for the three months ended June 30, 2008, and $0.4 million and $0.7 million for the six months ended June 30, 2009 and 2008, respectively. No payment was made with respect to ATN’s LTIP DERs for the three months ending June 30, 2009. These amounts were recorded as a reduction of non-controlling interests’ equity on the Company’s consolidated balance sheet. At June 30, 2009, ATN had approximately $10.9 million of unrecognized compensation expense related to the unvested portion of the restricted stock units, phantom units and options.

NOTE 18 — OPERATING SEGMENT INFORMATION

The Company’s operations include three reportable operating segments. These operating segments reflect the way the Company manages its operations and makes business decisions. The Company does not allocate income taxes to its operating segments. Operating segment data for the periods indicated are as follows (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008 (c)			2009 (c)			2008 (c)
Gas and oil production
Revenues (a)	$	69,979		$	78,956		$	141,922		$	155,182
Costs and expenses		(9,803	)		(12,379	)		(21,089	)		(23,047	)

Segment profit	$	60,176		$	66,577		$	120,833		$	132,135

Well construction and completion
Revenues	$	63,367		$	122,341		$	175,735		$	226,479
Costs and expenses		(53,701	)		(106,384	)		(149,098	)		(196,939	)

Segment profit	$	9,666		$	15,957		$	26,637		$	29,540

Atlas Pipeline (c)
Revenues (b)	$	162,088		$	116,538		$	321,348		$	392,303
Revenues – affiliates		6,617			11,523			16,766			20,747
Equity income in joint venture		710			—			710			—
Costs and expenses		(146,594	)		(367,187	)		(298,494	)		(658,262	)

Segment profit (loss)	$	22,821		$	(239,126	)	$	40,330		$	(245,212	)

Other (d)
Revenues	$	6,253		$	4,735		$	9,773		$	9,736
Costs and expenses		(5,889	)		(2,783	)		(8,940	)		(5,316	)

Segment profit	$	364		$	1,952		$	833		$	4,420

Reconciliation of segment profit (loss) to net income (loss) before income tax provision (benefit)
Segment profit (loss)
Gas and oil production	$	60,176		$	66,577		$	120,833		$	132,135
Well construction and completion		9,666			15,957			26,637			29,540
Atlas Pipeline		22,821			(239,126	)		40,330			(245,212	)
Other (d)		364			1,952			833			4,420

Total segment profit (loss)		93,027			(154,640	)		188,633			(79,117	)
Gain on sale of APL’s Appalachia system assets		105,691			—			105,691			—
General and administrative expenses		(21,577	)		(24,884	)		(48,991	)		(45,511	)
Net expense reimbursement - affiliate		(80	)		(184	)		(562	)		(434	)
Depreciation, depletion and amortization		(50,272	)		(43,359	)		(100,967	)		(85,214	)
Interest expense (e)		(41,948	)		(34,739	)		(76,568	)		(69,207	)
Other income (loss) – net		1,254			5,995			6,135			8,024

Income (loss) from continuing operations before income tax provision (benefit)		86,095			(251,811	)		73,371			(271,459	)

Capital expenditures
Gas and oil production	$	30,769		$	79,340		$	80,386		$	133,814
Well construction and completion		—			—			—			—
Atlas Pipeline		58,299			66,181			130,494			142,054
Corporate and other		8,437			713			16,027			1,856

Total capital expenditures	$	97,505		$	146,234		$	226,907		$	277,724


	June 30, 2009			December 31, 2008 (c)
Balance sheet
Goodwill
Gas and oil production	$	21,527		$	21,527
Well construction and completion		13,639			13,639
Atlas Pipeline		—			—

	$	35,166		$	35,166

Total assets
Gas and oil production	$	2,229,804		$	2,189,931
Well construction and completion		13,580			16,399
Atlas Pipeline (c)		2,169,644			2,157,590
Discontinued operations		—			255,606
Corporate and other		168,338			226,355

	$	4,581,366		$	4,845,881

(a)	Includes losses of $0.5 million and $5.0 million on mark-to-market derivatives for three months ended June 30, 2009 and 2008, respectively, and losses of $2.1 million and $7.9 million on mark-to-market derivatives for six months ended June 30, 2009 and 2008, respectively.

(b)	Includes losses of $18.6 million and $316.1 million on mark-to-market derivatives for three months ended June 30, 2009 and 2008, respectively, and losses of $18.3 million and $404.8 million on mark-to-market derivatives for six months ended June 30, 2009 and 2008, respectively.

(c)	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4).

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

(e)	The Company notes that interest expense has not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.

Operating profit (loss) represents total revenues less costs and expenses attributable thereto. Amounts for interest, provision for possible losses and depreciation, depletion and amortization and general corporate expenses are shown in the aggregate because these measures are not significant drivers in deciding how to allocate resources and assessing performance of each defined segment.

NOTE 19 – SUBSEQUENT EVENTS

On July 20, 2009, ATN entered into certain natural gas derivative contracts for calendar 2013 production volume of 220,000 MMbtu per month with an average fixed price of $6.90 per MMbtu.

On July 16, 2009, ATN issued $200.0 million of 12.125% senior unsecured notes (“12.125% Senior Notes”) due 2017 at 98.116% of par value to yield 12.5% at maturity. ATN used the net proceeds from the issuance of approximately $191.7 million, net of underwriting fees of $4.5 million, to repay outstanding borrowings under its revolving credit facility. Under the terms of ATN’s credit facility (see Note 8), the credit facility borrowing base is automatically reduced by 25% of the stated principal amount of any senior unsecured notes offering. As such, the borrowing base of ATN’s credit facility was reduced by $50.0 million to $600.0 million upon the issuance of the 12.125% Senior Notes. Interest on the 12.125% Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year. The 12.125% Senior Notes are redeemable at any time at certain redemption prices, together with accrued interest at the date of redemption. In addition, before August 1, 2012, ATN may redeem up to 35% of the aggregate principal amount of the 12.125% Senior Notes with the proceeds of certain equity offerings at a stated redemption price of 112.125% of the principal, plus accrued interest. The 12.125% Senior Notes are junior in right of payment to ATN’s secured debt, including its obligations under its revolving credit facility. The indenture governing the 12.125% Senior Notes contains 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.

On July 13, 2009, APL sold a natural gas processing facility and a one-third undivided interest in other associated assets located in its Mid-Continent operating segment for approximately $22.6 million in cash. The facility was sold to Penn Virginia Resource Partners, L.P. (NYSE: PVR), who will provide natural gas volumes to the facility and reimburse APL for its proportionate share of the operating expenses. APL will continue to operate the facility. APL used the proceeds from this transaction to reduce outstanding borrowings under its senior secured credit facility.

On July 10, 2009, ATN received the requisite consent from its lenders to amend its revolving credit facility to permit the merger with the Company. The material terms of the amendment are:

•

The merger with the Company will be permitted;

•

Restrictions on ATN’s ability to make payments with respect to its equity interest will be revised to permit it to make distributions to the Company in an amount equal to the income tax liability at the highest marginal rate attributable to ATN’s net income. In addition, ATN will be permitted to make distributions to the Company of up to $40.0 million per year and, to the extent that it distributes less than that amount in any year, may carry over up to $20.0 million for use in the next year; and

•

The definition of change of control will be revised to include a change of control of the Company.

The amendment will become effective upon consummation of the merger.

On July 7, 2009, APL received an additional $2.5 million in cash upon the delivery of audited financial statements for the NOARK system assets to Spectra in connection with the completion of APL’s sale of its NOARK gas gathering and interstate pipeline system to Spectra for net proceeds of $292.0 million in cash, net of working capital adjustments (see Note 4).

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, 2008. 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.

General

The following discussion provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this report.

We are a publicly traded Delaware corporation whose common units are listed on the NASDAQ Stock Market under the symbol “ATLS”. Our assets currently consist principally of cash on hand and our ownership interests in the following entities:

•

Atlas Energy Resources, LLC (“Atlas Energy” or “ATN”), a publicly traded Delaware limited liability company (NYSE: ATN) focused on natural gas development and production in northern Michigan’s Antrim Shale, the Appalachian Basin and Indiana’s New Albany Shale, which we manage through our subsidiary, Atlas Energy Management, Inc., under the supervision of ATN’s board of directors;

•

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 and a commitment to invest a total of $20.0 million in Lightfoot LP. We also have a direct and indirect ownership interests in Lightfoot LP.

Our ownership interest in ATN consists of the following:

•

all of the outstanding Class A units, representing 1,293,496 units at June 30, 2009, which entitles us to receive 2% of the cash distributed by ATN without any obligation to make future capital contributions to ATN;

•

all of the management incentive interests in ATN, which entitle us to receive increasing percentages, up to a maximum of 25.0%, of any cash distributed by ATN as it reaches certain target distribution levels in excess of $0.48 per ATN common unit in any quarter after ATN has met the tests set forth within its limited liability company agreement; and

•

29,952,996 common units, representing approximately 47.3% of the outstanding common units at June 30, 2009, or a 46.3% ownership interest in ATN.

Our ownership of ATN’s management incentive interests entitles us to receive an increasing percentage of cash distributed by ATN as it reaches certain target distribution levels after ATN has met the tests set forth within its limited liability company agreement. The rights entitle us to receive 15.0% of all cash distributed in a quarter after each ATN common unit has received $0.48 for that quarter and 25.0% of all cash distributed after each ATN common unit has received $0.59 for that quarter. As set forth in ATN’s limited liability company agreement, for us to receive distributions from ATN under the management incentive interests, ATN has to:

•

for 12 full, consecutive, non-overlapping calendar quarters, (a) pay a quarterly cash distribution to the outstanding Class A and common units in an amount that, on average exceeds $0.48 per unit, (b) generate adjusted operating surplus, as defined, that on average is equal to the amount of all cash distributions paid to the Class A and common units plus the amount of management incentive distributions earned and (c) not reduce the quarterly cash distribution per unit for any of such 12 quarters; and

•

for the last four full, consecutive, non-overlapping quarters during the 12 quarter period described previously (or any four full, consecutive and non-overlapping quarters after the completion of the 12 quarter test is complete), (a) pay a quarterly cash distribution to the outstanding Class A and common units in an amount that exceeds $0.48 per unit, (b) generate adjusted operating surplus, as defined, that on average is equal to the amount of all cash distributions paid to the Class A and common units plus the amount of management incentive distributions earned and (c) not reduce the quarterly cash distribution per unit for any of such four quarters.

Effective April 27, 2009, ATN has suspended further distributions pursuant to its merger agreement with the Company (see “Recent Developments”). ATN’s suspension of the quarterly distribution during the six months ended June 30, 2009 means that it did not comply with the terms of the 12-quarter test and, as such, we will not receive the management incentive distributions that were reserved for during previous periods.

Our ownership interest in APL consists of 1,112,000 common units, representing approximately 2.3% of the outstanding common units of APL at June 30, 2009, or a 2.3% ownership interest.

Our ownership interest in AHD consists of 17,808,109 common units, representing approximately 64.4% of the outstanding common units of AHD at June 30, 2009. AHD’s general partner, which is a wholly-owned subsidiary of ours, does not have an economic interest in AHD, and AHD’s capital structure does not include incentive distribution rights. AHD’s ownership interest in APL consists of the following:

•

a 2.0% general partner interest, which entitles it to receive 2% of the cash distributed by APL;

•

all of the incentive distribution rights, which entitle it to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per APL common unit in any quarter. AHD, the holder of all of the incentive distribution rights in APL, had agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter (“the IDR Adjustment Agreement”). AHD also agreed that the resulting allocation of incentive distribution rights back to APL would be after AHD receives the initial $7.0 million per quarter of incentive distribution rights;

•

5,754,253 common units, representing approximately 12.0% of the outstanding common units at June 30, 2009, or a 11.8% ownership interest in APL; and

•

15,000 $1,000 par value 12.0% cumulative preferred limited partner units at June 30, 2009.

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

•

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

•

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

•

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

Financial Presentation

Our principal operating activities are conducted primarily through ATN, AHD, and APL, and our cash flows consist primarily of distributions received from ATN, APL and AHD on our ownership interests. Our consolidated financial statements contain the consolidated financial statements of ATN and AHD, and AHD’s consolidated financial statements include the consolidated financial statements of APL. The non-controlling interests in ATN, AHD and APL are reflected as loss attributable to non-controlling interests in our consolidated statements of operations and as a component of stockholders’ 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 ATN and AHD, including APL’s financial results, adjusted for non-controlling interests in ATN’s, AHD’s and APL’s net income (loss).

Atlas Energy

ATN is 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, ATN focuses its drilling and production in four established shale plays; namely, 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. ATN’s Appalachian Basin major operations are located in eastern Ohio, western Pennsylvania, and north central Tennessee. ATN has additional operations in New York, West

Virginia and Kentucky. ATN specializes in development of these natural gas basins because they provide it with repeatable, low-risk drilling opportunities. ATN is also a leading sponsor and manager of tax-advantaged direct investment natural gas and oil partnerships in the United States. ATN funds the drilling of natural gas and oil wells on its acreage by sponsoring and managing tax advantaged investment partnerships. It generally structures its investment partnerships so that, upon formation of a partnership, ATN co-invests in and contributes leasehold acreage to it, enters into drilling and well operating agreements with it and becomes its managing general partner. ATN is managed by Atlas Energy Management, Inc., our wholly-owned subsidiary, through which we provide ATN with the personnel necessary to manage its assets and raise capital.

As of and for the six months ended June 30, 2009, ATN had the following key assets:

Appalachia gas and oil operations

•

direct and indirect working interests in approximately 8,631 gross producing gas and oil wells;

•

overriding royalty interests in approximately 629 gross producing gas and oil wells;

•

net daily production of 43.6 million cubic feet equivalents per day (“MMcfed”) and 42.9 Mmcfed for the three and six months ended June 30, 2009; and

•

approximately 935,300 gross (889,700 net) acres, of which approximately 623,300 gross (616,400 net) acres, are undeveloped. Included in the undeveloped acreage is 531,950 Marcellus Shale acres in Pennsylvania, New York and West Virginia, of which approximately 266,100 acres are located in ATN’s core Marcellus Shale position in southwestern Pennsylvania.

Michigan gas and oil operations

•

direct and indirect working interests in approximately 2,488 gross producing gas and oil wells;

•

overriding royalty interest in approximately 93 gross producing natural gas and oil wells;

•

net daily production of 57.9 Mmcfed and 58.0 MMcfed for the three and six months ended June 30, 2009; and

•

approximately 344,400 gross (272,200 net) acres, of which approximately 35,800 gross (28,100 net) acres, are undeveloped.

Indiana gas and oil operations

•

direct and indirect working interests in approximately 16 gross producing gas and oil wells;

•

net daily production of 0.2 Mmcfed for both the three months and six months ended June 30, 2009; and

•

approximately 244,100 gross (118,200 net) acres, of which approximately 239,100 gross (114,400 net) acres, are undeveloped.

Partnership management business

•

ATN investment partnership business, which includes equity interests in 95 investment partnerships and a registered broker-dealer which acts as the dealer-manager of ATN’s investment partnership offerings.

•

since July 2008, ATN has raised $560.0 million in investor funds, including $122.8 million raised in the three months ended June 30, 2009 for its most recent investment partnership, Atlas Resources Public #18-2009(B) L.P.

Atlas Pipeline Holdings and Atlas Pipeline Partners

AHD is the general partner of APL and its cash generating assets currently consist solely of its interests in APL.

APL is a leading provider of natural gas gathering services in the Anadarko and Permian Basins and the Golden Trend in the southwestern and mid-continent United States and the Appalachian Basin in the eastern United States. In addition, APL is a leading provider of natural gas processing and treatment services in Oklahoma and Texas. APL’s business is conducted in the midstream segment of the natural gas industry through two reportable segments: its Mid-Continent operations and its Appalachian operations.

As of June 30, 2009, through its Mid-Continent operations, APL owns and operates:

•

eight active natural gas processing plants with aggregate capacity of approximately 810 MMcfd and one treating facility with a capacity of approximately 200 MMcfd, located in Oklahoma and Texas; and

•

8,750 miles of active natural gas gathering systems located in Oklahoma, Kansas and Texas, which transport gas from wells and central delivery points in the Mid-Continent region to APL’s natural gas processing and treating plants or third party pipelines.

As of June 30, 2009, APL’s Appalachia operations are conducted principally through its 49% ownership interest in Laurel Mountain Midstream, LLC (“Laurel Mountain” – see “Recent Events”), a joint venture which owns and operates a 1,700 mile natural gas gathering system in the Appalachia Basin located in eastern Ohio, western New York, and western Pennsylvania. APL also owns a 65-mile natural gas gathering system in northeastern Tennessee. Laurel Mountain gathers the majority all of the natural gas from wells operated by ATN.

Recent Developments

On June 29, 2009, ATN completed fundraising for Atlas Resources Public #18-2008 Drilling Program, raising $122.8 million, representing the second partnership (Atlas Resources Public #18-2009(B) L.P.) in the program. Atlas Resources, LLC, ATN’s wholly-owned subsidiary, serves as the managing general partner.

On June 1, 2009, AHD entered into an amendment to its credit facility agreement which, among other changes:

•

required AHD to immediately repay $30.0 million of then-outstanding $46.0 million of borrowings under the credit facility, $16.0 million of which was borrowed from us through a subordinate loan;

•

repaid $4.0 million of its outstanding credit facility borrowings on July 13, 2009 in accordance with the amendment through a subordinate loan with us. AHD may not borrow additional amounts under the credit facility or issue letters of credit;

•

On June 1, 2009, in connection with its amendment of the credit facility, AHD borrowed $15.0 million from us under a subordinate loan. The maturity date of the subordinate loan is generally the day following the date that AHD repay all outstanding borrowings under its credit facility. Interest on the outstanding balance under the loan accrues quarterly at the rate of 12.0% per annum. However, prior to the maturity date of the subordinate loan, interest on the outstanding balance under the subordinate loan will not be payable in cash, but instead the principal amount of the loan will be increased by the interest amount payable.

On June 1, 2009, in connection with AHD’s amendment of the credit facility, we guaranteed the remaining balance outstanding under its credit facility under a guarantee agreement with the administrative agent of its credit facility. In consideration for this guarantee, AHD issued to us a promissory note which requires AHD to pay interest to us in an amount equal to the principal amount outstanding under its credit facility. The maturity date of the promissory note is the day following the date that AHD repays all outstanding borrowings under its credit facility. Interest on the promissory note, which is calculated on the outstanding balance under the credit facility, accrues quarterly at the rate of 3.75% per annum. However, prior to the maturity date of the promissory note, interest under the promissory note will not be payable in cash, but instead the principal amount upon which interest is calculated will be increased by the interest amount payable.

On June 1, 2009, a newly created, wholly-owned subsidiary of AHD, Atlas Pipeline Holdings II, LLC (“AHD Sub”), issued $15.0 million of $1,000 par value 12.0% Class B preferred equity (“AHD Sub Preferred Units”) to APL for cash pursuant to a certificate of designation. AHD utilized the net proceeds from the issuance to reduce borrowings under its credit facility. Distributions on the AHD Sub Preferred Units are payable quarterly on the same date as the distribution payment date for AHD’s common units. Distributions on the AHD Sub Preferred Units shall initially be paid in cash or by increasing the amount of the AHD Sub Preferred Unit equity by the amount of the distribution. However, under the terms of the certificate of designation, prior to the repayment of all outstanding borrowings under AHD’s credit facility, AHD Sub may only pay a cash distribution on the AHD Sub Preferred Units if AHD has received distributions on APL’s

12.0% Class B preferred units. After AHD has repaid all outstanding borrowings under its credit facility, all subsequent distributions declared by AHD Sub on the AHD Sub Preferred Units shall be paid in cash. AHD Sub has the option of redeeming some or all of the AHD Sub Preferred Units, subject to certain limitations under the terms of the certificate of designation. As APL owns all of the outstanding AHD Sub Preferred Units in an amount equal to the Class B Preferred Units of APL that AHD owns, the amounts eliminate in consolidation of our consolidated balance sheet as of June 30, 2009.

On May 31, 2009, APL and subsidiaries of The Williams Companies, Inc. (NYSE: WMB) (“Williams”) completed the formation of the Laurel Mountain Midstream, LLC joint venture (“Laurel Mountain”), which currently owns and operates APL’s former Appalachia Basin natural gas gathering system, excluding its Northern Tennessee operations. To Laurel Mountain, Williams contributed cash of $100.0 million, of which APL received approximately $87.8 million, net of working capital adjustments, and a note receivable of $25.5 million. APL contributed the Appalachia Basin natural gas gathering system and retained a 49% ownership interest in Laurel Mountain, which includes entitlement 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 our consolidated balance sheet at fair value and recognized a gain on sale of $105.7 million, including $79.7 million associated with the remeasurement of APL’s investment in Laurel Mountain to fair value. In addition, Atlas Energy sold to Laurel Mountain two natural gas processing plants and associated pipelines located in Southwestern Pennsylvania for $10.0 million, resulting in a $4.2 million loss which is included in gain on asset sale on our consolidated statement of operations. Upon the completion of the transaction, Laurel Mountain entered into new gas gathering agreements with Atlas Energy which superseded the existing natural gas gathering agreements and omnibus agreement between APL and Atlas Energy. Under the new gas gathering agreement, Atlas Energy will be obligated to pay Laurel Mountain all of the gathering fees it collects from its investment drilling partnerships plus any excess amount over the amount of the competitive gathering fee (which is currently defined as 13% of the gross sales price received for the partnerships’ gas). The new gathering agreement contains additional provisions which define certain obligations and options of each party to build and connect newly drilled wells to any Laurel Mountain gathering system. APL’s ownership interest in Laurel Mountain has been recognized in accordance with the equity method of accounting within our consolidated financial statements. APL used the net proceeds from the transaction to reduce borrowings under its senior secured credit facility.

On May 29, 2009, APL entered into an amendment to its credit facility agreement which, among other changes:

•

increased the applicable margin above adjusted LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank prime rate upon which borrowings under the credit facility bear interest;

•

for borrowings under the credit facility that bear interest at LIBOR plus the applicable margin, set a floor for the adjusted LIBOR interest rate of 2.0% per annum;

•

requires that APL pay no cash distributions during the remainder of the year ended December 31, 2009 and allows APL to pay cash distributions beginning January 1, 2010 if its senior secured leverage ratio is less than 2.75x and APL have minimum liquidity (as defined in the credit agreement) of at least $50.0 million;

•

generally limits APL’s annual capital expenditures to $95.0 million for the remainder of fiscal 2009 and $70.0 million each year thereafter;

•

permitted APL to retain (i) up to $135.0 million of net cash proceeds from dispositions completed in fiscal 2009 for reinvestment in similar replacement assets within 360 days, and (ii) up to $50 million of net cash proceeds from dispositions completed in any subsequent fiscal year subject to certain limitations as defined within the credit agreement; and

•

instituted 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.

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 used the net proceeds from the transaction to reduce borrowings under its senior secured term loan and revolving credit facility (see “—APL Term Loan and Revolving Credit Facility”). We have recognized the sale of the NOARK system assets as discontinued operations within our consolidated financial statements.

In May 2009, ATN received approximately $28.5 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, ATN 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 our revolving credit facility.

On May 1, 2009, ATN’s shelf registration statement was declared effective by the Securities and Exchange Commission, which permits it to periodically issue up to $500.0 million of equity and debt securities. On July 28, 2009, ATN filed an additional shelf registration in connection with our July 16, 2009 Senior Notes offering. The amount, type and timing of any additional offerings will depend upon, among other things, ATN’s funding requirements, prevailing market conditions and compliance with its credit facility and unsecured senior note covenants.

On April 27, 2009, we and ATN executed a definitive merger agreement, pursuant to which our newly formed subsidiary will merge with and into ATN, with ATN surviving as our wholly-owned subsidiary. In the merger, each Class B common unit of ATN not currently held by us will be converted into 1.16 shares of our common stock, and we will be renamed “Atlas Energy, Inc.”. Our board of directors has approved the merger agreement and has resolved to recommend that our stockholders vote in favor of the transactions contemplated by the merger agreement. ATN’s board of directors and a special committee of its directors comprised entirely of independent directors have also approved the merger agreement and have resolved to recommend that ATN’s stockholders vote in favor of the merger. Pending consummation of the merger, ATN has suspended distributions to its Class A and Class B members’ interests. ATN’s suspension of the quarterly distribution during the six months ended June 30, 2009 means that it will not comply with the terms of the 12 quarter test and, as such, we will not receive the management incentive distributions that were reserved for during previous periods. The transaction will be subject to approval by holders of a majority of our outstanding common stock, a majority of ATN’s outstanding Class B units and other customary closing conditions.

Effective April 9, 2009, ATN entered into a second amendment to its credit agreement with a syndicate of banks. Among other provisions, the amendment adjusts the credit facility borrowing base to $650.0 million (see “Subsequent Events”) and amends the definition of applicable margin to, among other

things, adjust the Eurodollar Loans rate to a range of 200 to 300 basis points and the applicable margin for base rate loans from a range of 0 to 75 basis points to a range of 112.5 to 212.5 basis points, subject to amounts drawn against the credit facility.

Subsequent Events

On July 20, 2009, ATN entered into certain natural gas derivative contracts for calendar 2013 production volume of 220,000 MMbtu per month with an average fixed price of $6.90 per MMbtu.

On July 16, 2009, ATN issued $200.0 million of 12.125% senior unsecured notes (“ATN 12.125% Senior Notes”) due 2017 at 98.116% of par value to yield 12.5% at maturity. ATN used the net proceeds of $191.7 million, net underwriting fees of $4.5 million, to repay outstanding borrowings under its revolving credit facility (see “ATN Credit Facility”). Under the terms of its credit facility, the credit facility borrowing base is automatically reduced by 25% of the stated principal amount of any senior unsecured notes offering by ATN. As such, the borrowing base of the credit facility was reduced by $50.0 million to $600.0 million upon the issuance of the ATN 12.125% Senior Notes. Interest on the ATN 12.125% Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year. The ATN 12.125% Senior Notes are redeemable at any time at certain redemption prices, together with accrued interest at the date of redemption. In addition, before August 1, 2012, ATN may redeem up to 35% of the aggregate principal amount of the ATN 12.125% Senior Notes with the proceeds of certain equity offerings at a stated redemption price of 112.125% of the principal, plus accrued interest. The ATN 12.125% Senior Notes are junior in right of payment to ATN’s secured debt, including its obligations under the revolving credit facility. The indenture governing the ATN 12.125% Senior Notes contains 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 ATN’s assets.

On July 10, 2009, ATN received the requisite consent from its lenders to amend its revolving credit facility to permit the merger with us. The material terms of the amendment are:

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The merger with us will be permitted;

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Restrictions on ATN’s ability to make payments with respect to its equity interest will be revised to permit it to make distributions to us in an amount equal to the income tax liability at the highest marginal rate attributable to ATN’s net income. In addition, ATN will be permitted to make distributions to us of up to $40.0 million per year and, to the extent that it distributes less than that amount in any year, may carry over up to $20.0 million for use in the next year; and

•

The definition of change of control will be revised to include a change of control of us.

The amendment will become effective upon consummation of the merger.

On July 7, 2009, APL received an additional $2.5 million in cash upon the delivery of audited financial statements for the NOARK system assets to Spectra in connection with the completion of the Partnership’s sale of its NOARK gas gathering and interstate pipeline system to Spectra for net proceeds of $292.0 million in cash, net of working capital adjustments (see “Recent Developments”).

Contractual Revenue Arrangements

Atlas Energy

Appalachia Natural Gas. ATN markets its natural gas, which is principally located in the Fayette County, PA area, primarily to Hess Corporation, Colonial Energy, Inc., UGI Energy Services and others. We expect that natural gas produced from ATN’s wells drilled in areas of the Appalachian Basin other than those described above will be primarily tied to the spot market price and supplied to:

•

gas marketers;

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local distribution companies;

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industrial or other end-users; and/or

•

companies generating electricity.

Michigan Natural Gas. In Michigan, ATN has natural gas sales agreements with DTE Energy Company, which are valid through December 31, 2012. DTE has the obligation to purchase all of the natural gas produced and delivered by ATN and its affiliates from specific projects at certain delivery points. Based on recent production data available to ATN, we anticipate that ATN and its affiliates will sell approximately 49% of their Michigan natural gas production during the year ending December 31, 2009 under the DTE agreements, in most cases at NYMEX pricing.

Crude Oil. Crude oil produced from ATN’s wells flows directly into storage tanks where it is picked up by an oil company, a common carrier or pipeline companies acting for an oil company, which is purchasing the crude oil. ATN sells any oil produced by its 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. ATN generally funds its drilling activities through sponsorship of tax-advantaged investment partnerships. In addition to providing capital for its drilling activities, ATN’s 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, ATN receives the following fees:

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

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Administration and oversight.For each well drilled by an investment partnership, ATN receives a fixed fee of approximately $15,000 ($62,000 for Marcellus wells). Additionally, the partnership pays ATN a monthly per well administrative fee of $75 for the life of the well. Because ATN coinvests in the partnerships, the net fee that it receives is reduced by its proportionate interest in the well.

•

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

Atlas Pipeline Partners

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:

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.

Recent Trends and Uncertainties

Currently, there is an unprecedented uncertainty in the financial markets. This uncertainty presents additional potential risks to us and our subsidiaries. These risks include the availability and costs associated with our and our subsidiaries’ borrowing capabilities and raising additional capital, and an increase in the volatility of our and our subsidiaries’ common equity market price. While we and our subsidiaries do not currently have any plans to access the capital markets, should we decide to do so in the near future, the terms, size and cost of new debt or equity could be less favorable than in previous transactions.

Atlas Energy. Realized pricing of ATN’s 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. Significant factors that may impact future commodity prices include developments in the issues currently impacting Iraq and Iran and the Middle East in general; the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil supply through export quotas; and overall North American gas supply and demand fundamentals, including the impact of increasing liquefied natural gas deliveries to the United States. Although we cannot predict the occurrence of events that will affect future commodity prices or the degree to which these prices will be affected, the prices for commodities that ATN produces will generally approximate market prices in the geographic region of the production. In order to address, in part, volatility in commodity prices, ATN has implemented a hedging program that is intended to reduce the volatility in its revenues. This program mitigates, but does not eliminate, ATN’s sensitivity to short-term changes in commodity prices. See Item 3, “Quantitative and Qualitative Disclosures About Market Risk”.

Although the number of natural gas wells drilled in the United States has increased overall in recent years, a corresponding increase in production has not been realized, primarily as a result of smaller discoveries and the decline in production from existing wells. We believe that an increase in United States drilling activity, additional sources of supply such as liquefied natural gas and imports of natural gas will be required for the natural gas industry to meet the expected increased demand for, and to compensate for the slowing production of, natural gas in the United States. The areas in which ATN operates are experiencing significant drilling activity as a result of new drilling for deeper natural gas formations and the implementation of new exploration and production techniques.

While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which ATN operates, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas reserves. Drilling activity generally decreases as natural gas prices decrease. We have no control over the level of drilling activity in the areas of ATN’s operations.

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

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

As a result of APL’s POP and keep-whole contracts, its results of operations and financial condition substantially depend upon the price of natural gas and NGLs. APL believes that future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. Based on historical trends, APL generally expects NGL prices to follow changes in crude oil prices over the long term, which we believe will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. However, energy market uncertainty has negatively impacted North American drilling activity in the recent past. Lower drilling levels and shut-in wells over a sustained period would have a negative effect on natural gas volumes gathered and processed.

Results of Operations

The following table illustrates selected operational information for the periods indicated:


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Atlas Energy:
Production revenues (in thousands):
Gas	$	66,897	$	74,216	$	136,771	$	147,091
Oil⁽¹⁾	$	3,082	$	4,740	$	5,151	$	8,091
Production volume⁽²⁾⁽³⁾:
Gas (mcfd)		98,828		92,026		98,495		90,683
Oil (bpd)		482		434		441		420

Total (mcfed)		101,720		94,630		101,141		93,203
Average sales prices⁽³⁾:
Gas (per mcf)⁽⁴⁾⁽⁵⁾	$	7.49	$	9.21	$	7.77	$	9.39
Oil (per bbl)⁽⁶⁾	$	70.23	$	125.99	$	67.66	$	109.12
Production costs (per Mcfe)⁽³⁾⁽⁷⁾:
Lease operating expenses	$	0.78	$	0.83	$	0.84	$	0.81
Production taxes		0.14		0.43		0.17		0.38
Transportation and compression		0.45		0.50		0.48		0.48

Total production costs per mcf	$	1.37	$	1.76	$	1.49	$	1.67
Atlas Pipeline:
Appalachia system throughput volume (mcfd)⁽³⁾⁽⁸⁾		107,428		84,475		103,003		80,054
Velma system gathered gas volume (mcfd)⁽³⁾		80,068		65,519		73,050		63,960
Elk City/Sweetwater system gathered gas volume (mcfd)⁽³⁾		221,192		292,544		237,445		298,961
Chaney Dell system gathered gas volume (mcfd)⁽³⁾		276,901		284,528		289,889		268,008
Midkiff/Benedum system gathered gas volume (mcfd)⁽³⁾		161,355		150,157		157,687		146,350

Combined throughput volume (mcfd)⁽³⁾		846,944		877,223		861,074		857,333

(1)	Excludes sales of natural gas liquids.

(2)

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

(3)

“Mcf” and “mcfd” represents thousand cubic feet and thousand cubic feet per day; “mcfe” and “mcfed” represents thousand cubic feet equivalent and thousand cubic feet equivalent per day, and “bbl” and “bpd” represents barrels and barrels per day. Barrels are converted to mcfe using the ratio of six mcf’s to one barrel.

(4)	Atlas Energy’s average sales price before the effects of financial hedging was $3.50 per Mcf and $11.21 per Mcf for the three months ended June 30, 2009 and 2008, respectively, and $4.29 per Mcf and $9.79 per Mcf for the six months ended June 30, 2009 and 2008, respectively.

(5)

Includes $0.5 million and $2.9 million of derivative proceeds which were not included as revenue for the three months ended June 30, 2009 and 2008, respectively, and $2.0 million and $7.0 million of derivative proceeds which were not included as revenue for the six months ended June 30, 2009 and 2008, respectively.

(6)

Atlas Energy’s average sales price for oil before the effects of financial hedging was $57.16 per barrel and $120.01 per barrel for the three months ended June 30, 2009 and 2008, respectively, and $46.26 per barrel and $106.02 per barrel for the six months ended June 30, 2009 and 2008, respectively.

(7)	Production costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, severance taxes, insurance and production overhead.

(8)	Includes 100% of the throughput volume of Laurel Mountain, a joint venture in which APL has a 49% ownership interest, for the period from May 31, 2009, its date of inception, through June 30, 2009.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008

Natural Gas and Oil Production. Our natural gas and oil production revenues were $70.0 million for the three months ended June 30, 2009, compared to $79.0 million for the comparable prior year period. The $9.0 million decrease was primarily due to a 20% decrease in the average realized sales price offset by a 7% increase in production volumes. The increase in production volumes was attributable to a 8,511 Mcf/day increase in ATN’s Appalachia natural gas volumes related to increased Marcellus Shale drilling operations.

Natural gas and oil production expenses were $9.8 million for the three months ended June 30, 2009, a decrease of $2.6 million from $12.4 million for the comparable prior year period. The decrease was principally attributable to a decrease of $3.5 million in Michigan/Indiana production costs due in part to a $3.0 reduction in production taxes resulting from a decrease in state production tax rate. The decrease was partially offset by an increase of $0.8 million in Appalachia water hauling and disposal costs associated with an increase in the number of Marcellus Shale wells ATN drilled.

Well Construction and Completion. Our well construction and completion segment margin was $9.7 million for the three months ended June 30, 2009, a decrease of $6.3 million from $16.0 million for the three months ended June 30, 2008. The decrease of $6.3 million in segment margin was attributable to a $56.4 million decrease related to the number of wells drilled, partially offset by an increase of $50.1 million in the gross profit per well. Since our drilling contracts 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. Our average cost and revenue per well have increased due to a shift from drilling less expensive shallow wells to more expensive deep or horizontal shale wells in Appalachia and in Michigan/Indiana during the three and six months ended June 30, 2009 in comparison to the prior year comparable periods.

As of June 30, 2009, “Liabilities associated with drilling contracts” on our consolidated balance sheet includes $88.9 million of funds raised that have not been applied to the completion of wells as of June 30, 2009 due to the timing of ATN’s drilling operations and thus have not been recognized as well construction and completion revenue. We expect to recognize this amount as revenue in the third quarter of 2009.

Administration and Oversight and Well Services. Administration and oversight fee revenues were $2.6 million for the three months ended June 30, 2009 compared with $5.1 million for the three months ended June 30, 2009, a decrease of $2.5 million. Well services revenues were $4.8 million for the three months ended June 30, 2009 compared with $5.3 million for the comparable prior year period, a decrease of $0.5 million. Well services expenses were $2.1 million for the three months ended June 30, 2009, compared with $2.7 million for the comparable prior year period. The decrease in administration and oversight fee revenue was due to a decrease in the number of wells drilled during the period, while the decrease in well service revenue was due to the decrease in shallow wells drilled since June 30, 2008.

Transmission, Gathering and Processing. Our transmission, gathering and processing revenues were $186.1 million for the three months ended June 30, 2009, a decrease of $252.4 million from $438.5 million for the comparable prior year period. The decline was primarily attributable to decreases in production revenue from the APL’s Chaney Dell system of $98.3 million, APL’s Midkiff/Benedum system of $72.4 million, APL’s Velma system of $42.5 million and APL’s Elk City/Sweetwater system of $39.3 million, which were all impacted principally by significantly lower average commodity prices in comparison to the prior year comparable period. Processed natural gas volume on the Elk City/Sweetwater system averaged 216.8 MMcfd for the three months ended June 30, 2009, a decrease of 5.6% from the comparable prior year period. However, NGL production volume for the Elk City/Sweetwater system was 11,581 bpd, an increase of 10.8% from the comparable prior year period, representing an increase in plant production efficiency. The Midkiff/Benedum system had processed natural gas volume of 150.1 MMcfd for the three months ended June 30, 2009, an increase of 6.3% compared to 141.2 MMcfd for the comparable prior year period. Processed natural gas volume averaged 77.3 MMcfd on the Velma system for the three months ended June 30, 2009, an increase of 24.4% from the comparable prior year period. The Velma system’s NGL production volume increased 21.5% from the comparable prior year period to 8,497 bpd. Processed natural gas volume on the Chaney Dell system was 219.1 MMcfd for the three months ended June 30, 2009, a decrease of 14.7% compared to 256.8 MMcfd for the comparable prior year period. However, the Chaney Dell system’s NGL production volume increased 2.3% from the comparable prior year period to 13,663 bpd for the three months ended June 30, 2009.

Transmission, gathering and processing expenses of $150.4 million for the three months ended June 30, 2009 represented a decrease of $217.1 million from the prior year comparable period due primarily to a significant decrease in APL’s average commodity prices in comparison to the prior year period. APL’s plant operating expenses of $14.1 million for the three months ended June 30, 2009 represented a decrease of $0.7 million from the prior year comparable period due primarily to a $0.8 million decrease associated with APL’s Chaney Dell system resulting from lower operating and maintenance costs. APL’s transportation and compression expenses increased slightly to $2.8 million for the three months ended June 30, 2009 compared with $2.6 million for the prior year comparable period due to higher APL Appalachia system operating and maintenance expenses as a result of increased capacity in comparison to the prior year period.

Gain on asset sale. Gain on asset sale of $105.7 million for the three months ended June 30, 2009 represents the gain recognized on APL’s sale of a 51% ownership interest in its Appalachia natural gas gathering system (see “—Recent Developments”).

Equity income of $0.7 million for the three months ended June 30, 2009 represents APL’s ownership interest in the net income of Laurel Mountain, a joint venture in which APL owns a 49% interest (see “—Recent Developments”), for the period from formation on May 31, 2009 through June 30, 2009.

Loss on Mark-to-Market Derivatives. Loss on mark-to-market derivatives was $18.6 million for the three months ended June 30, 2009 compared with $316.1 million for the comparable prior year period. This favorable movement of $297.5 million was due primarily to a $137.3 million favorable movement in non-cash mark-to-market adjustments on APL’s derivatives, the absence in the current year period of $115.8 million of net cash derivative expense related to APL’s early termination of a portion of its derivative contracts during June 2008 and a favorable movement of $53.5 million for non-cash derivative gains related to APL’s early termination of a portion of its derivative contracts, partially offset by a $5.8 million unfavorable movement related to cash settlements on APL’s derivatives that were not designated as hedges. The $137.3 million favorable movement in non-cash mark-to-market adjustments on derivatives was due principally to the recognition of a $134.8 million loss during the three months ended June 30, 2008, which was due to an increase in forward crude oil market prices from March 31, 2008 to June 30, 2008 and their unfavorable mark-to-market impact on certain non-hedge derivative contracts APL had for production volumes in future periods. For example, average forward crude oil prices, which are the basis for adjusting the fair value of APL’s crude oil derivative contracts, at June 30, 2008 were $140.26 per barrel, an increase of $43.32 per barrel from average forward crude oil market prices at March 31, 2008 of $96.94 per barrel. APL enters into derivative instruments solely to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under Item 3, “Quantitative and Qualitative Discussion about Market Risk”.

Other Income, Costs and Expenses.General and administrative expenses, including amounts reimbursed to affiliates, decreased $3.4 million to $21.7 million for the three months ended June 30, 2009 compared with $25.1 million for the comparable prior year period. The decrease was primarily related to a $1.7 million decrease in non-cash compensation expense and a $1.7 million decrease to salaries and wages.

Depreciation, depletion and amortization increased to $50.3 million for the three months ended June 30, 2009 compared with $43.4 million for the comparable prior year period due primarily to an increase in ATN’s depletable basis and production volumes and APL’s expansion capital expenditures incurred between the periods.

Interest expense increased to $41.9 million for the three months ended June 30, 2009 as compared with $34.7 million for the comparable prior year period. This $7.2 million increase was primarily due to an increase in borrowings from ATN and APL, partially offset by lower unhedged interest rates. APL issued additional senior unsecured notes during June 2008 and made a partial repayment of its senior secured term loan in June 2008. ATN issued additional senior unsecured notes in May 2008 and increased its borrowing under its credit facility.

Income tax expense was $3.6 million for the three months ended June 30, 2009 compared with an income tax benefit of $5.0 million for the comparable prior year period. Our effective income tax rate attributable to common shareholders of Atlas America Inc. was 39.1% and 37.3% for the three months ended June 30, 2009 and 2008, respectively. The increase in our effective income tax rate between periods is a result of a reduction in tax benefits related to depletion and tax-exempt interest income relative to income (loss) before taxes. Currently, it is our expectation that our effective income tax rate will approximate 39% for the year ended December 31, 2009.

Income from discontinued operations consists of amounts associated with APL’s NOARK gas gathering and interstate pipeline system, which it sold on May 4, 2009 (see “—Recent Developments”). Income from discontinued operations increased to $51.2 million for the three months ended June 30, 2009 compared with $7.8 million for the comparable prior year period. The increase was due to the $48.8 million gain, net of $2.2 million of income tax expense, APL recognized on the sale of the NOARK system, partially offset by a $5.4 million decrease in the operating results of the NOARK system, net of income taxes, due to the sale of the system on May 4, 2009.

Income (loss) attributable to non-controlling interest in APL, which represents the allocation of ATN’s, AHD’s and APL’s earnings to its non-controlling interests, was a loss of $124.3 million for the three months ended June 30, 2009 compared with income of $231.2 million for the prior year comparable period. This change was primarily due to an increase in ATN’s and APL’s net earnings between periods.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Natural Gas and Oil Production. Our natural gas and oil production revenues were $141.9 million for the six months ended June 30, 2009, compared to $155.2 million for the comparable prior year period. The $13.3 million decrease was primarily due to an 18% decrease in the average realized sales price offset by a 9% increase in production volumes. The increase in production volumes was attributable to a 9,069 Mcf/day increase in ATN’s Appalachia natural gas volumes related to increased Marcellus Shale drilling operations.

Natural gas and oil production expenses were $21.1 million for the six months ended June 30, 2009, a decrease of $1.9 million from $23.0 million for the comparable prior year period. The decrease was principally attributable to a decrease of $4.4 million in Michigan/Indiana production costs due in part to a $3.4 reduction in production taxes resulting from a decrease in state production tax rate. The decrease was partially offset by an increase of $1.7 million in Appalachia water hauling and disposal costs associated with an increase in the number of Marcellus Shale wells ATN drilled.

Well Construction and Completion. Our well construction and completion segment margin was $26.6 million for the six months ended June 30, 2009, a decrease of $2.9 million from $29.5 million for the six months ended June 30, 2008. The decrease of $2.9 million in segment margin was attributable to a $56.4 million decrease related to the number of wells drilled, partially offset by an increase of $53.5 million in the gross profit per well. Since our drilling contracts 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. Our average cost and revenue per well have increased due to a shift from drilling less expensive shallow wells to more expensive deep or horizontal shale wells in Appalachia and in Michigan/Indiana during the three and six months ended June 30, 2009 in comparison to the prior year comparable periods.

Administration and Oversight and Well Services. Administration and oversight fee revenues were $6.5 million for the six months ended June 30, 2009 compared with $10.2 million for the six months ended June 30, 2009, a decrease of $3.7 million. Well services revenues were $9.9 million for the six months ended June 30, 2009 compared with $10.1 million for the comparable prior year period, an increase of $0.2 million. Well services expenses were $4.5 million for the three months ended June 30, 2009, compared with $5.1 million for the comparable prior year period. The decrease in administration and oversight fee revenue was due to a decrease in the number of wells drilled during the period, while the decrease in well service revenue was due to the decrease in shallow wells drilled since June 30, 2008.

Transmission, Gathering and Processing. Our transmission, gathering and processing revenues were $349.7 million for the six months ended June 30, 2009, a decrease of $457.7 million from $807.4 million for the comparable prior year period. The decline was primarily attributable to decreases in production revenue from APL’s Chaney Dell system of $168.1 million, APL’s Midkiff/Benedum system of $127.9 million, APL’s Elk City/Sweetwater system of $82.3 million and APL’s Velma system of $78.1 million, which were all impacted principally by significantly lower average commodity prices in comparison to the prior year comparable period. Processed natural gas volume on the Elk City/Sweetwater system averaged 235.3 MMcfd for the six months ended June 30, 2009, an increase of 1.0% from the comparable prior year period. However, NGL production volume for the Elk City/Sweetwater system was 11,650 bpd, an increase of 10.3% from the comparable prior year period, representing an increase in plant production efficiency. The Midkiff/Benedum system had processed natural gas volume of 148.1 MMcfd for the six months ended June 30, 2009, an increase of 6.6% compared to 138.9 MMcfd for the comparable prior year period. NGL production volume for the Midkiff/Benedum system was 21,555 bpd, an increase of 4.7% from the comparable prior year period. Processed natural gas volume averaged 70.6 MMcfd on the Velma system for the six months ended June 30, 2009, an increase of 15.8% from the comparable prior year period. The Velma system’s NGL production volume increased 13.6% from the comparable prior year period to 7,770 bpd. Processed natural gas volume on the Chaney Dell system was 223.5 MMcfd for the six months ended June 30, 2009, a decrease of 11.4% compared to 252.3 MMcfd for the comparable prior year period. However, the Chaney Dell system’s NGL production volume increased 6.2% from the comparable prior year period to 13,674 bpd for the six months ended June 30, 2009.

Transmission, gathering and processing expenses of $302.9 million for the six months ended June 30, 2009 represented a decrease of $355.6 million from the prior year comparable period due primarily to a significant decrease in APL’s average commodity prices in comparison to the prior year period. APL’s plant operating expenses of $28.0 million for the six months ended June 30, 2009 represented a decrease of $1.8 million from the prior year comparable period due primarily to a $1.4 million decrease associated with APL’s Midkiff/Benedum system resulting from lower operating and maintenance costs. APL’s transportation and compression expenses increased slightly to $6.1 million for the six months ended June 30, 2009 compared with $5.0 million for the prior year comparable period due to higher APL Appalachia system operating and maintenance expenses as a result of increased capacity in comparison to the prior year period.

Gain on asset sale. Gain on asset sale of $105.7 million for the six months ended June 30, 2009 represents the gain recognized on APL’s sale of a 51% ownership interest in its Appalachia natural gas gathering system (see “—Recent Developments”).

Equity income of $0.7 million for the six months ended June 30, 2009 represents APL’s ownership interest in the net income of Laurel Mountain, a joint venture in which APL owns a 49% interest (see “—Recent Developments”), for the period from formation on May 31, 2009 through June 30, 2009.

Loss on Mark-to-Market Derivatives. Loss on mark-to-market derivatives was $18.3 million for the six months ended June 30, 2009 compared with $404.8 for the comparable prior year period. This favorable movement of $386.5 million was due primarily to a $180.0 million favorable movement in non-cash mark-to-market adjustments on APL’s derivatives, the absence in the current year period of $115.8 million of net cash derivative expense related to APL’s early termination of a portion of its derivative contracts during June 2008, a favorable movement of $65.6 million for non-cash derivative gains related to APL’s early termination of a portion of its derivative contracts and a $33.5 million favorable movement related to cash settlements on APL derivatives that were not designated as hedges. The $180.0 million favorable movement in non-cash mark-to-market adjustments on derivatives was due principally to the recognition of a $211.7 million loss during the six months ended June 30, 2008, which was due to an increase in forward crude oil market prices from December 31, 2007 to June 30, 2008 and their unfavorable mark-to-market impact on certain non-hedge derivative contracts APL had for production volumes in future periods. For example, average forward crude oil prices, which are the basis for adjusting the fair value of APL’s crude oil derivative contracts, at June 30, 2008 were $140.26 per barrel, an increase of $50.37 per barrel from average forward crude oil market prices at December 31, 2007 of $89.89 per barrel. APL enters into derivative instruments solely to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under Item 3, “Quantitative and Qualitative Discussion About Market Risk”.

Other Income, Costs and Expenses.General and administrative expenses, including amounts reimbursed to affiliates, increased $3.7 million to $49.6 million for the six months ended June 30, 2009 compared with $45.9 million for the comparable prior year period. The increase was primarily related to $2.8 million of non-recurring severance and other related costs incurred during the first quarter of 2009 for the termination of certain positions within APL’s Mid-Continent segment and $0.6 million in professional fees related to our anticipated merger with ATN (see “Recent Developments”).

Depreciation, depletion and amortization increased to $101.0 million for the six months ended June 30, 2009 compared with $85.2 million for the comparable prior year period due primarily to an increase in ATN’s depletable basis and production volumes and APL’s expansion capital expenditures incurred between the periods.

Interest expense increased to $76.6 million for the six months ended June 30, 2009 as compared with $69.2 million for the comparable prior year period. This $7.4 million increase was primarily due to an increase in borrowings from ATN and APL, partially offset by lower unhedged interest rates. APL issued additional senior unsecured notes during June 2008 and made a partial repayment of its senior secured term loan in June 2008, and a partial repayment of it term loan and credit facility during second quarter 2009. ATN issued additional senior unsecured notes in May 2008 and increased its borrowing under its credit facility.

Income tax expense was $6.3 million for the six months ended June 30, 2009 compared with income tax benefit of $1.4 million for the comparable prior year period. Our effective income tax rate attributable to common shareholders of Atlas America Inc. was 39.1% and 36.9% for the six months ended June 30, 2009 and 2008, respectively. The increase in our effective income tax rate between periods is a result of a reduction in tax benefits related to depletion and tax-exempt interest income relative to income (loss) before taxes. Currently, it is our expectation that our effective income tax rate will approximate 39% for the year ended December 31, 2009.

Income from discontinued operations consists of amounts associated with APL’s NOARK gas gathering and interstate pipeline system, which it sold on May 4, 2009 (see “—Recent Developments”). Income from discontinued operations increased to $59.8 million for the six months ended June 30, 2009 compared with $13.8 million for the comparable prior year period. The increase was due to the $48.8 million gain, net of $2.2 million of income tax expense, APL recognized on the sale of the NOARK system, partially offset by a $2.9 million decrease in the operating results of the NOARK system, net of income taxes, due to the sale of the system on May 4, 2009.

Income (loss) attributable to non-controlling interest in APL, which represents the allocation of ATN’s, AHD’s and APL’s earnings to its non-controlling interests, was a loss of $112.9 million for the six months ended June 30, 2009 compared with income of $254.8 million for the prior year comparable period. This change was primarily due to an increase in ATN’s and APL’s net earnings between periods.

Liquidity and Capital Resources

General

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

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

•

cash distributions and maintenance capital expenditures through existing cash, cash flows from operating activities, and the temporary use of funds raised in its investment partnerships in the period before it invests these funds;

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expansion capital expenditures and working capital deficits through the retention of cash, additional borrowings and capital raised through investment partnerships; and

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

At June 30, 2009, ATN had $196.0 million available committed capacity under its credit facility, subject to covenant limitations, to fund working capital obligations. On July 16, 2009, ATN issued $200.0 million of 12.125% senior unsecured notes due 2017 at 98.116% of par value to yield 12.5% at maturity (see “Subsequent Events”). ATN used the net proceeds of $191.7 million, net underwriting fees of $4.5 million, to repay outstanding borrowings under our revolving credit facility. Under the terms of its credit facility (see “Recent Developments”), the credit facility borrowing base is automatically reduced by 25% of the stated principal amount of any senior unsecured notes offering by ATN. As such, the borrowing base of its credit facility was reduced by $50.0 million to $600.0 million upon the issuance of the 12.125% Senior Notes.

Atlas Pipeline Holdings. AHD’s primary sources of liquidity are distributions received with respect to its ownership interests in APL and cash on hand. AHD’s primary cash requirements are for its general and administrative expenses, including expenses as a result of being a publicly traded partnership, capital contributions to APL to maintain or increase its ownership interest and quarterly distributions to its common unitholders. AHD expects to fund its general and administrative expenses through the retention of cash and its capital contributions to APL through the retention of cash from distributions received from APL. On May 29, 2009, APL entered into an amendment to its senior secured credit facility (see “Recent Developments”) which, among other changes, requires that it pay no cash distributions during the remainder of the year ended December 31, 2009 and allows it to pay cash distributions beginning January 1, 2010 if its senior secured leverage ratio is above certain thresholds and it has minimum liquidity (both as defined in the credit agreement) of at least $50.0 million.

At June 30, 2009, AHD had $16.0 million outstanding under its credit facility (see “Recent Developments”) and was in compliance with its credit facility covenants. AHD believes that it will have sufficient liquid assets, including its ownership of 5.8 million limited partner units in APL, cash on hand and borrowing ability, including borrowings from us, to meet its financial commitments, debt service obligations and possible contingencies for at least the next twelve-month period. However, AHD is subject to business and other risks that could adversely affect its cash flow. AHD may need to supplement its cash generation with proceeds from financing activities, including other borrowings and the issuance of additional limited partner units and the sale of its ownership interests in APL.

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

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

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expansion capital expenditures and working capital deficits through the retention of cash and additional borrowings; and

•

debt principal payments through additional borrowings as they become due or by the issuance of additional limited partner units or APL asset sales.

At June 30, 2009, APL had $322.0 million of outstanding borrowings under its $380.0 million credit facility and $3.5 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheet, with $54.5 million of remaining committed capacity under its credit facility, subject to covenant limitations (see “Recent Developments”). APL was in compliance with its credit facility covenants at June 30, 2009. We believe that APL will have sufficient liquid assets, cash from operations and borrowing capacity to meet its financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve-month period. However, APL is subject to business, operational and other risks that could adversely affect its cash flow. APL may need to supplement its cash generation with proceeds from financing activities, including borrowings under its credit facility and other borrowings, the issuance of additional limited partner units and the sale of its assets.

We believe that we and our subsidiaries will have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve-month period. However, we and our subsidiaries are subject to business, operational and other risks that could adversely affect our cash flow. We and our subsidiaries may supplement our cash generation with proceeds from financing activities, including borrowings under our subsidiaries’ credit facilities and other borrowings, the issuance of additional common shares and units and the sale of assets.

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 subsidiaries’ ability to raise capital and reduce the amount of cash available to fund its operations. Our subsidiaries rely on their cash flow from operations and their credit facilities to execute their growth strategy and to meet their financial commitments and other short-term liquidity needs. We cannot be certain that additional capital will be available to our subsidiaries to the extent required and on acceptable terms. We believe that we and our subsidiaries will have sufficient liquid assets, cash from operations and borrowing capacity to meet our and their financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve month period.

Cash Flows – Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Net cash provided by operating activities of $119.7 million for the six months ended June 30, 2009 represented a favorable movement of $104.2 million from net cash provided by operating activities of $15.5 million for the comparable prior year period. The increase was derived principally from a $103.8 million increase in net income excluding non-cash items and a $69.0 million favorable movement in distributions paid to non-controlling interest holders, partially offset by a $67.4 million unfavorable movement in working capital changes and a $7.4 million unfavorable movement in cash provided by discontinued operations. The non-cash charges which impacted net income include favorable movements in income from continuing operations of $284.7, partially offset by favorable decreases in non-cash loss on derivatives of $145.2 million. The increase in net income excluding non-cash charges was principally due to the absence in the current year period of $115.8 million of net cash derivative expense related to APL’s early termination of a portion of its derivative contracts during June 2008 (see Note 9 to the consolidated financial statements in Item 1, “Financial Statements”). The movement in cash distributions to non-controlling interest holders is due mainly to decreases in ATN’s, AHD’s and APL’s cash distributions. The movement in working capital was principally due to a $158.8 million unfavorable movement in accounts payable, partially offset by a $74.8 million favorable movement in accounts receivable and other current assets. The movement in non-cash derivative losses resulted from decreases in commodity prices during the six months ended June 30, 2009 and their favorable impact on the fair value of derivative contracts ATN and APL have for future periods.

Net cash provided by investing activities of $153.8 million for the six months ended June 30, 2009 represented a favorable movement of $415.4 million from $261.6 million used in investing activities for the comparable prior year period. This favorable movement was principally due to a $305.7 million favorable movement in cash provided by discontinued operations, a $97.9 million increase in proceeds from sale of assets related to the sale of APL’s Appalachia segment assets to the Laurel Mountain joint venture, and a decrease in capital expenditures for ATN and APL of $50.8 million, partially offset by a $31.4 million decrease in cash proceeds from acquisition purchase price adjustment. The $305.7 million favorable movement in cash provided by discontinued operations was principally the result of $292.0 million of net cash proceeds from the sale of APL’s NOARK system assets. See further discussion of capital expenditures under “—Capital Requirements”.

Net cash used in financing activities of $296.6 million for the six months ended June 30, 2009 represented an unfavorable movement of $638.3 million from $341.7 million of net cash provided by financing activities for the comparable prior year period. This unfavorable movement was principally due to a $651.9 million reduction in net proceeds from APL and ATN’s issuance of debt and a $289.6 reduction in net proceeds from APL and ATN’s issuance of equity. This decrease was partially offset by a $186.0 million favorable movement in subsidiary borrowings under their respective credit facilities and a $122.8 million repayment of APL’s senior secured term loan.

Capital Requirements

Our principal assets are our ownership interests in ATN, APL and AHD, through which our operating activities occur. As such, we do not have any separate capital requirements apart from those entities, other than our commitment to invest a maximum of $20.0 million in Lightfoot, of which we had already invested $10.7 million at June 30, 2009. AHD, whose principal assets are its ownership interests in APL, does not have any separate capital requirements apart from APL. A more detailed discussion of ATN’s and APL’s capital requirements is provided below.

Atlas Energy. ATN’s capital requirements consist primarily of:

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maintenance capital expenditures — capital expenditures ATN makes on an ongoing basis to maintain its capital asset base and its current production volumes at a steady level; and

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expansion capital expenditures — capital expenditures ATN makes to expand its capital asset base for longer than the short-term and include new leasehold interests and the development and exploitation of existing leasehold interests through acquisitions and investments in its drilling partnerships.

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

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

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

The following table summarizes our consolidated maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008⁽¹⁾		2009		2008⁽¹⁾
Atlas Energy
Maintenance capital expenditures	$	12,975	$	12,975	$	25,950	$	25,950
Expansion capital expenditures		26,231		67,078		70,463		109,720

Total	$	39,206	$	80,053	$	96,413	$	135,670

Atlas Pipeline
Maintenance capital expenditures	$	1,557	$	1,971	$	2,101	$	3,486
Expansion capital expenditures		56,742		64,210		128,393		138,568

Total	$	58,299	$	66,181	$	130,494	$	142,054

Consolidated
Maintenance capital expenditures	$	14,532	$	14,946	$	28,051	$	29,436
Expansion capital expenditures		82,973		131,288		198,856		248,288

Total	$	97,505	$	146,234	$	226,907	$	277,724

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

Atlas Energy. During the three months ended June 30, 2009, ATN’s capital expenditures related primarily to $23.8 million of investments in its investment partnerships compared with $40.7 million for the three months ended June 30, 2008. ATN also incurred $6.5 million in leasehold costs and invested $0.4 million in wells drilled exclusively for its own account for the three months ended June 30, 2009. During the six months ended June 30, 2009, ATN’s capital expenditures related primarily to $51.6 million of investments in its investment partnerships compared with $66.4 million for the six months ended June 30, 2008. ATN also invested $12.1 million in wells drilled exclusively for its own account and incurred $16.9 million in leasehold costs for the six months ended June 30, 2009. ATN funded and expects to continue to fund these capital expenditures through cash on hand, cash flows from operations and from amounts available under its credit facility.

Atlas Pipeline Partners. APL’s expansion capital expenditures decreased to $56.7 million and $128.4 million for the three and six months ended June 30, 2009, respectively, compared with $64.2 million and $138.6 million, respectively, for the prior year comparable periods. The decrease was due principally to APL’s construction of a 60 MMcfd expansion of its Sweetwater processing plant and APL’s acquisition of a

gathering system located in Tennessee during the six months ended June 30, 2008, partially offset by APL’s continued expansion of its gathering systems and upgrades to processing facilities and compressors to accommodate new wells drilled in its service areas. The decrease in maintenance capital expenditures for the three and six months ended June 30, 2009 when compared with the comparable prior year period was due to fluctuations in the timing of APL’s scheduled maintenance activity.

As of June 30, 2009, our subsidiaries are committed to expend approximately $19.2 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

Off Balance Sheet Arrangements

As of June 30, 2009, our off balance sheet arrangements are limited to ATN’s guarantee of Crown Drilling of Pennsylvania, LLC’s $8.7 million credit agreement, ATN’s and APL’s letters of credit outstanding of $1.2 million and $3.5 million, respectively, and their commitments to expend approximately $19.2 million on capital projects. In addition, we are committed to invest a total of $20.0 million in Lightfoot, of which $10.7 million has been invested as of June 30, 2009.

Issuance of Subsidiary Common Units

We account for offerings by our subsidiaries in accordance with Staff Accounting Bulletin No. 51, “Accounting by the Parent in Consolidation for Sales of Stock by a Subsidiary” (“SAB 51”) and SFAS No. 160. We have adopted a policy to recognize gains on such transactions as a credit to equity rather than as income. These gains represent our portion of the excess net offering price per unit of each of our subsidiaries’ units to the book carrying amount per unit.

Atlas Energy

In May 2008, ATN sold 2,070,000 of its Class B common units in a public offering at $41.50 per common unit, yielding net proceeds of approximately $82.5 million. The net proceeds were used to repay a portion of ATN’s outstanding balance under its revolving credit facility. A gain of $17.7 million, net of an income tax provision of $8.7 million, was recorded in our consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $26.4 million to non-controlling interest in accordance with SAB 51 and SFAS No. 160 upon completion of the offering.

In May 2008, ATN sold 600,000 of its Class B common units to us in a private placement at $42.00 per common unit for net proceeds to ATN of $25.2 million. The net proceeds were used by ATN to repay a portion of its outstanding balance under its revolving credit facility.

Atlas Pipeline Partners and Atlas Pipeline Holdings

In June 2008, APL sold 5,750,000 common units in a public offering at a price of $37.52 per unit, yielding net proceeds of approximately $206.6 million. Also in June 2008, we purchased 308,109 AHD common units and 1,112,000 APL common limited partner units through a private placement transaction at a price of $32.50 and $36.02 per unit, respectively, for net proceeds of approximately $10.0 million and $40.1 million, respectively. APL also received a capital contribution from AHD of $5.4 million for AHD to maintain its 2.0% general partner interest in it. APL utilized the net proceeds from both the sales of common units and the capital contribution from AHD to fund the early termination of certain derivative agreements.

Dividends

We paid cash dividends of $2.0 million for the three months ended March 31, 2009, but we did not pay cash dividends 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.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include revenue and expense accruals, deferred tax assets and liabilities, depletion, depreciation and amortization, asset impairment, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. A discussion of our significant accounting policies we have adopted and followed in the preparation of our consolidated financial statements is included within our Annual Report on Form 10-K for the year ended December 31, 2008 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, 2009.

Fair Value of Financial Instruments

We applied the provisions of SFAS No. 157 “Fair Value Instruments” (“SFAS No. 157”) to our consolidated financial statements. SFAS No. 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS No. 157 (1) creates a single definition of fair value, (2) establishes a hierarchy for measuring fair value, and (3) expands disclosure requirements about items measured at fair value. SFAS No. 157 does not change existing accounting rules governing what can or what must be recognized and reported at fair value in our consolidated financial statements, or disclosed at fair value in our notes to the financial statements. As a result, we will not be required to recognize any new assets or liabilities at fair value.

SFAS No. 157’s 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 the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities recorded at fair value, including ATN’s and APL’s derivative contracts and our Supplemental Employment Retirement Plan (“SERP”). All of ATN’s and APL’s commodity derivative contracts, with the exception of APL’s NGL fixed price swaps and crude oil options, are calculated based on observable market data related to the change in price of the underlying commodity or market interest rate and, therefore, are defined as Level 2 fair value measurements. ATN’s, APL’s and AHD’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model and are therefore defined as Level 2. Our SERP is calculated based on observable actuarial inputs developed by a third-party actuary and, therefore, is defined as a Level 2 fair value

measurement. 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 crude oil options (including those associated with NGL sales) are based on forward price curves developed by the related financial institution based upon current quoted prices for crude oil futures and therefore are defined as Level 3 fair value measurements. In addition, liabilities that are required to be measured at fair value on a non-recurring basis include asset retirement obligations that are defined as Level 3. Estimates of the fair value of asset retirement obligations 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.

Recently Adopted Accounting Standards

In May 2009, the Financial Accounting Standards Board (“FASB”) issued Statement No. 165, “Subsequent Events” (“SFAS No. 165”). SFAS No. 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS No. 165 requires management of a reporting entity to evaluate events or transactions that may occur after the balance sheet date for potential recognition or disclosure in the financial statements and provides guidance for disclosures that an entity should make about those events. SFAS No. 165 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. We adopted the requirements of SFAS No. 165 on June 30, 2009 and it did not have a material impact to our financial position or results of operations or related disclosures. The adoption of SFAS 165 does not change our current practices with respect to evaluating, recording and disclosing subsequent events.

In April 2009, the FASB issued Staff Position 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP FAS 157-4”). FSP FAS 157-4 applies to all fair value measurements and provides additional clarification on estimating fair value when the market activity for an asset has declined significantly. FSP FAS 157-4 also requires an entity to disclose a change in valuation technique and related inputs to the valuation calculation and to quantify its effects, if practicable. FSP FAS 157-4 is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We adopted the requirements of FSP FAS 157-4 on April 1, 2009 and its adoption did not have a material impact on our financial position and results of operations.

In April 2009, the FASB issued Staff Position 115-2 and 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (“FSP FAS 115-2 and FAS 124-2”). FSP FAS 115-2 and FAS 124-2 change existing guidance for determining whether an impairment is other than temporary for debt securities. FSP FAS 115-2 and FAS 124-2 replaces the existing requirement that an entity’s management asses it has both the intent and ability to hold an impaired security until recovery with a requirement that management assess that it does not have the intent to sell the security and that it is more likely than not that it will not have to sell the security before recovery of its cost basis. FSP FAS 115-2 and FAS 124-2 also requires that an entity recognize noncredit losses on held-to-maturity debt securities in other comprehensive income and amortize that amount over the remaining life of the security and for the entity to present the total other-than-temporary impairment in the statement of operations with an offset for the amount recognized in other comprehensive income. FSP FAS 115-2 and FAS 124-2 are effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We adopted the requirements of FSP FAS 115-2 and FAS 124-2 on April 1, 2009 and its adoption did not have a material impact on our financial position and results of operations.

value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position. FSP FAS 107-1 APB 28-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We adopted the requirements of FSP FAS 107-1 APB 28-1 on April 1, 2009 and its adoption did not have a material impact on our financial position and results of operations.

In April 2009, the FASB issued Staff Position 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“FSP 141(R)-1”). FSP 141(R)-1 requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be recognized at fair value if fair value can be reasonably estimated. If fair value of such an asset or liability cannot be reasonably estimated, the asset or liability would generally be recognized in accordance with FASB Statement No. 5, “Accounting for Contingencies” and FASB Interpretation No. 14, “Reasonable Estimation of the Amount of a Loss”. FSP 141(R)-1 also eliminates the requirement to disclose an estimate of the range of outcomes of recognized contingencies at the acquisition date. FSP FAS 141(R)-1 is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for us). We adopted the requirements of FSP 141(R)-1 on January 1, 2009 and its adoption did not have a material impact on our financial position and results of operations.

In June 2008, the FASB issued Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-6-1 applies to the calculation of earnings per share (“EPS”) described in paragraphs 60 and 61 of FASB Statement No. 128, “Earnings per Share” for share-based payment awards with rights to dividends or dividend equivalents. It states that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption was prohibited. All prior-period EPS data presented was adjusted retrospectively to conform to the provisions of this FSP. We applied the requirements of FSP EITF 03-6-1 upon its adoption on January 1, 2009 and the adoption of FSP EITF 03-6-1 had no impact on our financial position and results of operations.

In April 2008, the FASB issued Staff Position No. 142-3, “Determination of Useful Life of Intangible Assets” (“FSP FAS 142-3”). FSP FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No 141(R), “Business Combinations” (“SFAS No. 141(R)”) and other U.S. Generally Accepted Accounting Principles. FSP FAS 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption was prohibited. The guidance for determining the useful life of a recognized intangible asset should be applied prospectively to intangible assets acquired after the effective date. The disclosure requirements should be applied prospectively to all intangible assets recognized as of, and subsequent to, the effective date. We applied the requirements of FSP FAS 142-3 upon its adoption on January 1, 2009 and the adoption of FSP FAS 142-3 had no impact on our financial position and results of operations.

contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. EITF No. 07-4 is effective for fiscal years beginning after December 15, 2008, including interim periods within those fiscal years, and required retrospective application of the guidance to all periods presented. Early adoption is prohibited. We adopted the requirements of EITF No. 07-4 on January 1, 2009, and it did not have a material impact on our financial position or results of operations.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 amends the requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”) to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, with early adoption encouraged. We adopted the requirements of SFAS No. 161 on January 1, 2009, and it resulted in additional disclosures related to our commodity and interest rate derivatives.

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements-an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 amends ARB No. 51 to establish accounting and reporting standards for the non-controlling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 also requires consolidated net income to be reported and disclosed on the face of the consolidated statement of operations, at amounts that include the amounts attributable to both the parent and the non-controlling interest. Additionally, SFAS No. 160 establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 also requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated and adjust its remaining investment, if any, at fair value. We adopted the requirements of SFAS No. 160 on January 1, 2009 and adjusted the presentation of our financial position and results of operations. Prior period financial positions and results of operations have been adjusted retrospectively to conform to the provisions of SFAS No. 160.

In December 2007, the FASB issued SFAS No 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) replaces SFAS No. 141, “Business Combinations” (“SFAS No. 141”), however retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. SFAS No. 141(R) requires an acquirer to recognize the assets acquired, liabilities assumed and any non-controlling interest in the acquiree at the acquisition date, at their fair values as of that date, with specified limited exceptions. Changes subsequent to that date are to be recognized in earnings, not goodwill. Additionally, SFAS No. 141 (R) requires costs incurred in connection with an acquisition be expensed as incurred. Restructuring costs, if any, are to be recognized separately from the acquisition. The acquirer in a business combination achieved in stages must also recognize the identifiable assets and liabilities, as well as the non-controlling interests in the acquiree, at the full amounts of their fair values. SFAS No. 141(R) is effective for business combinations occurring in fiscal years beginning on or after December 15, 2008. We adopted the requirements of SFAS No. 141(R) on January 1, 2009, and it did not have a material impact on our financial position and results of operations.

Recently Issued Accounting Standards

In June 2009, the FASB issued Statement No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – A Replacement of FASB Statement No. 162” (“SFAS No. 168”). SFAS No. 168 establishes the FASB Accounting Standards Codification (“Codification”) as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The Codification supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following SFAS No. 168, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting Standards Updates, which will serve only to update the Codification. SFAS No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We will apply the requirements of SFAS No. 168 to our financial statements for the interim period ending September 30, 2009 and we do not expect it to have a material impact to our financial position or results of operations or related disclosures.

In June 2009, the FASB issued Statement No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS No. 167”). SFAS No. 167 is a revision to FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities” and 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. SFAS No. 167 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. SFAS No. 167 is effective at the start of a reporting entity’s first fiscal year beginning after November 15, 2009 (January 1, 2010 for us). We will apply the requirements of SFAS No. 167 upon its adoption on January 1, 2010 and we do not expect it to have a material impact to our financial position or results of operations or related disclosures.

MODERNIZATION OF OIL AND GAS REPORTING

In December 2008, the SEC announced that it had approved revisions to its oil and gas reporting disclosures by adopting amendments to Rule 4-10 of Regulation S-X and Items 201, 801, and 802 of Regulation S-K. These new disclosure requirements are referred to as “Modernization of Oil and Gas Reporting” and include provisions that:

•

Permit companies to disclose their probable and possible reserves on a voluntary basis. Current rules limit disclosure to only proved reserves.

•

Update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include “by geographic area” and “reasonable certainty”.

•

Permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

•

We will begin complying with the disclosure requirements in our annual report on Form 10-K for the year ending December 31, 2009. The new rules may not be applied to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. We are currently in the process of evaluating the new requirements.

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

We and our subsidiaries are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We and our subsidiaries manage these risks through regular operating and financing activities and 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, 2009. Only the potential impact of hypothetical assumptions is 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 our subsidiaries, if any. The counterparties related to our subsidiaries’ commodity and interest-rate derivative contracts are banking institutions, who also participate in their revolving credit facilities. The creditworthiness of our subsidiaries’ 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 subsidiaries’ counterparties to perform under their contracts and believe our exposure to non-performance is remote.

Interest Rate Risk.At June 30, 2009, ATN had an outstanding balance of $456.0 million on its revolving credit facility. At June 30, 2009, ATN had interest rate derivative contracts having aggregate notional principal amounts of $150.0 million. Under the terms of this agreement, ATN will pay weighted average interest rates of 3.11% 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. These derivatives effectively convert $150.0 million of ATN’s floating rate debt under its revolving credit facility to fixed rate debt.

At June 30, 2009, AHD had a credit facility with $16.0 million outstanding. At June 30, 2009, AHD had an interest rate derivative contract having an aggregate notional principal amount of $25.0 million. Under the terms of the agreement, AHD will pay an interest rate of 3.01% plus the applicable margin as defined under the terms of its credit facility, and will receive LIBOR, plus the applicable margin, on the notional principal amounts. The interest rate swap agreement is in effect at June 30, 2009 and expires on May 28, 2010.

At June 30, 2009, APL had $322.0 million outstanding under its senior secured revolving credit facility and $459.9 million outstanding under its senior secured term loan. On May 29, 2009, APL entered into an amendment to its senior secured credit facility agreement, which, among other changes, set a floor for the LIBOR interest rate of 2.0% per annum. At June 30, 2009, APL had interest rate derivative contracts having aggregate notional principal amounts of $450.0 million. Under the terms of these agreements, APL will pay weighted average interest rates of 3.02%, 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. These derivatives are in effect as of June 30, 2009 and expire during periods ranging from January 30, 2010 through April 30, 2010.

Holding all other variables constant, including the effect of interest rate derivatives, a hypothetical 100 basis-point or 1% change in interest rates would change our consolidated interest expense by $1.5 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 its exposure to changing natural gas and oil prices, ATN uses financial derivative instruments for a portion of its future natural gas and oil production. APL is exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. APL enters into financial swap and option instruments to hedge forecasted sales against the variability in expected future cash flows attributable to changes in market prices. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate are sold. Under these swap agreements, APL receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas, NGLs and condensate at a fixed price for the relevant period. Both ATN and APL apply the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”).

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, 2010 of approximately $28.6 million.

Atlas Energy. Realized pricing of ATN’s 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 its exposure to changing natural gas prices, ATN enters 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 oil contracts are based on a West Texas Intermediate, or WTI, index.

ATN formally documents all relationships between derivative instruments and the items being hedged, including the risk management objective and strategy for undertaking the derivative transactions. This includes matching the natural gas and oil futures and options contracts to the forecasted transactions. ATN assesses, both at the inception of the derivative contract and on an ongoing basis, whether the derivatives are highly effective in offsetting changes in the fair value of hedged items. Historically these contracts have qualified and been designated as cash flow hedges and recorded at their fair values. Gains or losses on future contracts are determined as the difference between the contract price and a reference price, generally prices on NYMEX. Changes in fair value are recognized within stockholders’ equity in the consolidated balance sheets and realized gains and losses are recognized within the consolidated statements of operations in the month the hedged commodity is sold. If it is determined that a derivative is not highly effective as a hedge or it has ceased to be a highly effective hedge due to the loss of correlation between changes in reference prices underlying a hedging instrument and actual commodity prices, ATN will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings.

ATN Fair Value of Derivative Instruments:


	Asset Derivatives					Liability Derivatives
Derivatives in SFAS 133 Cash Flow Hedging Relationships	Balance Sheet Location	Fair Value				Balance Sheet Location	Fair Value
	Balance Sheet Location	June 30, 2009		December 31, 2008		Balance Sheet Location	June 30, 2009			December 31, 2008
		(in thousands)					(in thousands)
Commodity contracts:	Current assets	$	116,977	$	107,766	Current liabilities	$	(383	)	$	(9,348	)
	Long-term assets		54,465		69,451	Long-term liabilities		(29,120	)		(8,410	)

			171,442		177,217			(29,503	)		(17,758	)
Interest rate contracts:	Current assets		—		—	Current liabilities		(3,602	)		(3,481	)
	Long-term assets		—		—	Long-term liabilities		(1,213	)		(2,361	)

			—		—			(4,815	)		(5,842	)

Total derivatives under SFAS No. 133		$	171,442	$	177,217		$	(34,318	)	$	(23,600	)

Effects of ATN Derivative Instruments on Consolidated Statements of Operations:


Derivatives in SFAS 133 Cash Flow Hedging Relationships	Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) For the Three Months Ended						Location of Gain/(Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) For the Three Months Ended
	June 30, 2009			June 30, 2008				June 30, 2009			June 30, 2008
	(in thousands)							(in thousands)
Commodity contracts	$	(22,528	)	$	(212,364	)	Gas and oil production	$	31,564		$	(4,896	)
Interest rate contracts		(132	)		3,831		Interest expense		(1,030	)		(114	)

	$	(22,660	)	$	(208,533	)		$	30,534		$	(5,010	)


Derivatives in SFAS 133 Cash Flow Hedging Relationships	Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) For the Six Months Ended						Location of Gain/(Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) For the Six Months Ended
	June 30, 2009			June 30, 2008				June 30, 2009			June 30, 2008
	(in thousands)							(in thousands)
Commodity contracts	$	64,286		$	(310,522	)	Gas and oil production	$	47,082		$	1,645
Interest rate contracts		(1,005	)		1,795		Interest expense		(2,032	)		(23	)

	$	63,281		$	(308,727	)		$	45,050		$	1,622

As of June 30, 2009, ATN 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 3.11% - Receive LIBOR	2009	$	(1,932	)
				2010		(2,757	)
				2011		(126	)

					$	(4,815	)

Natural Gas Fixed Price Swaps


Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset/(Liability)⁽¹⁾
	(MMBtu)	(per MMBtu)		(in thousands)
2009	21,790,000	$	8.044	$	79,987
2010	31,880,000	$	7.708		52,270
2011	20,720,000	$	7.040		2,973
2012	19,680,000	$	7.223		1,131
2013	10,620,000	$	7.126		(1,631	)

				$	134,730

Natural Gas Costless Collars


Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset/(Liability)⁽¹⁾
		(MMBtu)	(per MMBtu)		(in thousands)
2009	Puts purchased	120,000	$	11.000	$	795
2009	Calls sold	120,000	$	15.350		—
2010	Puts purchased	3,360,000	$	7.839		6,584
2010	Calls sold	3,360,000	$	9.007		—
2011	Puts purchased	9,540,000	$	6.523		145
2011	Calls sold	9,540,000	$	7.666		—
2012	Puts purchased	4,020,000	$	6.514		—
2012	Calls sold	4,020,000	$	7.718		(978	)
2013	Puts purchased	5,340,000	$	6.516		—
2013	Calls sold	5,340,000	$	7.811		(1,737	)

					$	4,809

Crude Oil Fixed Price Swaps


Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset/(Liability)⁽²⁾
	(Bbl)	(per Bbl)		(in thousands)
2009	31,700	$	99.497	$	896
2010	48,900	$	97.400		1,079
2011	42,600	$	77.460		(30	)
2012	33,500	$	76.855		(105	)
2013	10,000	$	77.360		(35	)

				$	1,805

Crude Oil Costless Collars


Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset/(Liability)⁽²⁾
		(Bbl)	(per Bbl)		(in thousands)
2009	Puts purchased	19,500	$	85.000	$	289
2009	Calls sold	19,500	$	116.884		—
2010	Puts purchased	31,000	$	85.000		448
2010	Calls sold	31,000	$	112.918		—
2011	Puts purchased	27,000	$	67.223		—
2011	Calls sold	27,000	$	89.436		(45	)
2012	Puts purchased	21,500	$	65.506		—
2012	Calls sold	21,500	$	91.448		(73	)
2013	Puts purchased	6,000	$	65.358		—
2013	Calls sold	6,000	$	93.442		(24	)

					$	595

		Total ATN net asset			$	137,124

⁽¹⁾	Fair value based on forward NYMEX natural gas prices, as applicable.

⁽²⁾	Fair value based on forward WTI crude oil prices, as applicable.

Atlas Pipeline Partners and Atlas Pipeline Holdings.AHD and APL formally document all relationships between derivative instruments and the items being hedged, including their risk management objective and strategy for undertaking the derivative transactions. This includes matching the derivative contracts to the forecasted transactions. Under SFAS No. 133, AHD and APL assess, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the derivative instrument and the underlying item being hedged, AHD and APL will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by AHD and APL through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in our consolidated statements of operations. For AHD’s and APL’s derivatives qualifying as hedges, we will recognize the effective portion of changes in fair value in stockholders’ equity as accumulated other comprehensive income on our consolidated balance sheet, and reclassify the portion relating to commodity derivatives to transmission, gathering and processing revenue and the portion relating to interest rate derivatives to interest expense within our consolidated statements of operations as the underlying transactions are settled. For AHD’s and APL’s non-qualifying derivatives and for the ineffective portion of qualifying derivatives, we will recognize changes in fair value within gain (loss) on mark-to-market derivatives in our consolidated statements of operations as they occur.

The following table summarizes AHD and APL’s derivative activity for the periods indicated (amounts in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Loss from cash and non-cash settlement of qualifying hedge instruments⁽¹⁾	$	(7,327	)	$	(33,152	)	$	(27,502	)	$	(50,795	)
Gain/(loss) from change in market value of non-qualifying derivatives⁽²⁾		2,509			(136,736	)		(42,481	)		(207,932	)
Gain/(loss) from change in market value of ineffective portion of qualifying derivatives⁽²⁾		—			1,934			10,813			(3,726	)
Loss from cash and non-cash settlement of non-qualifying derivatives⁽²⁾		(21,105	)		(184,564	)		13,390			(196,489	)
Loss from cash settlement of interest rate derivatives⁽³⁾		(3,125	)		(207	)		(6,179	)		(207	)

(1)	Included within transmission, gathering and processing revenue on our consolidated statements of operations.

(2)	Included within loss on mark-to-market derivatives on our consolidated statements of operations.

(3)	Included within interest expense on our consolidated statements of operations.

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


	June 30, 2009
	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments under SFAS No. 133:
N/A		$	—		$	—
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts		$	—	Current portion of derivative liability	$	(8,715	)
Commodity contracts	Current portion of derivative asset		1,815			—
Commodity contracts	Long-term derivative asset		1,606			—
Commodity contracts	Current portion of derivative liability		6,848	Current portion of derivative liability		(56,337	)
Commodity contracts	Long-term derivative liability		3,151	Long-term derivative liability		(15,899	)

		$	13,420		$	(80,951	)

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


	Three months ended June 30, 2009
	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			Location of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)			Location of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
Derivatives in SFAS No. 133 cash flow hedging relationships:
N/A
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts	$	(3,125	)	Interest expense	$	—		N/A
Commodity contracts⁽¹⁾		(10,894	)	Natural gas and liquids revenue		(13,381	)	Other loss, net
Commodity contracts⁽²⁾		—		N/A		(4,155	)	Other loss, net

	$	(14,019	)		$	(17,536	)

(1)	Hedges previously designated as cash flow hedges

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


	Six months ended June 30, 2009
	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			Location of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)			Location of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
Derivatives in SFAS No. 133 cash flow hedging relationships:
N/A
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts	$	(6,179	)	Interest expense	$	—		N/A
Commodity contracts⁽¹⁾		(26,864	)	Natural gas and liquids revenue		(22,908	)	Other loss, net
Commodity contracts⁽²⁾		—		N/A		35,665		Other loss, net

	$	(33,043	)		$	12,757

(1)	Hedges previously designated as cash flow hedges

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

As of June 30, 2009, AHD had the following interest rate derivatives:

Interest Fixed-Rate Swap


Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Liability⁽¹⁾
					(in thousands)
May 2008-May 2010	$	25,000,000	Pay 3.01% —Receive LIBOR	2009	$	(323	)
				2010		(221	)

				Total AHD net liability	$	(544	)

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

As of June 30, 2009, APL had the following interest rate and commodity derivatives:

Interest Fixed-Rate Swap


Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Liability⁽¹⁾
					(in thousands)
January 2008-January 2010	$	200,000,000	Pay 2.88% —Receive LIBOR	2009	$	(2,480	)
				2010		(351	)

					$	(2,831	)

April 2008-April 2010	$	250,000,000	Pay 3.14% —Receive LIBOR	2009	$	(3,430	)
				2010		(1,910	)

					$	(5,340	)

Natural Gas Liquids Sales – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability⁽²⁾
	(gallons)	(per gallon)		(in thousands)
2009	11,088,000	$	0.745	$	(573	)

Crude Oil Sales Options (associated with NGL volume)


Production Period Ended December 31,	Crude Volume	Associated NGL Volume	Average *Crude Price⁽⁴⁾***		Fair Value Asset/(Liability)⁽³⁾			Option Type
	(barrels)	(gallons)	(per barrel)		(in thousands)
2009	234,000	13,185,000	$	60.97	$	1,234		Puts purchased
2009	1,055,400	59,081,820	$	84.75		(2,622	)	Calls sold
2010	486,000	27,356,700	$	61.24		3,838		Puts purchased
2010	3,127,500	213,088,050	$	86.20		(22,103	)	Calls sold
2010	714,000	45,415,440	$	132.17		708		Calls purchased⁽⁵⁾
2011	606,000	33,145,560	$	100.70		(4,065	)	Calls sold
2011	252,000	13,547,520	$	133.16		764		Calls purchased⁽⁵⁾
2012	450,000	25,893,000	$	102.71		(3,746	)	Calls sold
2012	180,000	9,676,800	$	134.27		801		Calls purchased⁽⁵⁾

					$	(25,191	)

Natural Gas Sales – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Asset⁽³⁾
	(mmbtu)⁽⁶⁾	(per mmbtu)⁽⁶⁾		(in thousands)
2009	240,000	$	8.000	$	866

Natural Gas Basis Sales


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset⁽³⁾
	(mmbtu)⁽⁶⁾	(per mmbtu)⁽⁶⁾			(in thousands)
2009	2,460,000	$	(0.558	)	$	27
2010	2,220,000	$	(0.607	)		124

					$	151

Natural Gas Purchases – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability⁽³⁾
	(mmbtu)⁽⁶⁾	(per mmbtu)⁽⁶⁾		(in thousands)
2009	5,160,000	$	8.687	$	(22,156	)
2010	4,380,000	$	8.635		(12,414	)

				$	(34,570	)

Natural Gas Basis Purchases


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Liability⁽³⁾
	(mmbtu)⁽⁶⁾	(per mmbtu)⁽⁶⁾			(in thousands)
2009	7,380,000	$	(0.659	)	$	(83	)
2010	6,600,000	$	(0.590	)		(111	)

					$	(194	)

Ethane Put Options


Production Period Ended December 31,	Associated NGL Volume	Average *Price⁽⁴⁾***		Fair Value Liability⁽¹⁾			Option Type
	(gallons)	(per gallon)		(in thousands)
2009	630,000	$	0.340	$	(40	)	Puts purchased

Propane Put Options


Production Period Ended December 31,	Associated NGL Volume	Average *Price⁽⁴⁾***		Fair Value Asset⁽¹⁾		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	15,498,000	$	0.767	$	752	Puts purchased

Isobutane Put Options


Production Period Ended December 31,	Associated NGL Volume	Average *Price⁽⁴⁾***		Fair Value Asset⁽¹⁾		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	1,134,000	$	0.969	$	20	Puts purchased

Normal Butane Put Options


Production Period Ended December 31,	Associated NGL Volume	Average Price⁽⁴⁾		Fair Value Asset⁽¹⁾		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	9,324,000	$	0.964	$	585	Puts purchased

Natural Gasoline Put Options


Production Period Ended December 31,	Associated NGL Volume	Average Price⁽⁴⁾		Fair Value Asset⁽¹⁾		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	5,796,000	$	1.267	$	358	Puts purchased

Crude Oil Sales


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability⁽³⁾
	(barrels)	(per barrel)		(in thousands)
2009	15,000	$	62.700	$	(131	)

Crude Oil Sales Options


Production Period Ended December 31,	Volumes	Average Crude Price⁽⁴⁾		Fair Value Asset(Liability)⁽³⁾			Option Type
	(barrels)	(per barrel)		(in thousands)
2009	231,000	$	63.017	$	1,100		Puts purchased
2009	153,000	$	84.881		(434	)	Calls sold
2010	174,000	$	61.111		1,361		Puts purchased
2010	234,000	$	88.088		(1,557	)	Calls sold
2011	72,000	$	93.109		(699	)	Calls sold
2012	48,000	$	90.314		(620	)	Calls sold

				$	(849	)

	Total APL net liability			$	(66,987	)

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

⁽²⁾	Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas, light crude and propane prices.

⁽³⁾	Fair value based on forward NYMEX natural gas and light crude prices, as applicable.

⁽⁴⁾	Average price of options based upon average strike price adjusted by average premium paid or received.

⁽⁵⁾	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.

⁽⁶⁾	Mmbtu represents million British Thermal Units.

The fair value of derivatives is included in our consolidated balance sheets as follows (in thousands):


	June 30, 2009			December 31, 2008
Current portion of derivative asset	$	118,792		$	152,727
Long-term derivative asset		56,071			69,451
Current portion of derivative liability		(62,189	)		(73,776	)
Long-term derivative liability		(43,081	)		(59,103	)

Total Company net asset	$	69,593		$	89,299

Atlas America.At June 30, 2009 and December 31, 2008, we reflected a net hedging asset on our consolidated balance sheets of $69.6 million and $89.3 million, respectively, as a result of ATN’s, AHD’s and APL’s derivative contracts. Of the $29.5 million gains in accumulated other comprehensive income at June 30, 2009, we will reclassify $20.6 million of gains to our consolidated statements of operations over the next twelve month period as these contracts expire, and $8.9 million of gains will be reclassified in later periods if the fair values of the instruments remain at current market values. Actual amounts that will be reclassified will vary as a result of future price changes.

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 of our Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2009, 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 agreement on April 27, 2009 between us and ATN, the following actions were filed in Delaware Chancery Court purporting to challenge the merger:

•

Alonzo v. Atlas Energy Resources, LLC, et al., C.A. No. 4553-VCN (Del. Ch. filed 4/30/09);

•

Operating Engineers Constructions Industry and Miscellaneous Pension Fund v. Atlas America, Inc., et al., C.A. No. 4589-VCN (Del. Ch. filed 5/13/09);

•

Vanderpool v. Atlas Energy Resources, LLC, et al., C.A. No. 4604-VCN (Del. Ch. filed 5/15/09);

•

Farrell v. Cohen, et al., C.A. No. 4607-VCN (Del. Ch. filed 5/19/09); and

•

Montgomery County Employees’ Retirement Fund v. Atlas Energy Resources, L.L.C., et al., C.A. No. 4613-VCN (Del. Ch. filed 5/21/09).

advances claims of breach of fiduciary duty in connection with the merger agreement, including allegations of inadequate disclosures in connection with the unitholder vote on the merger, and seeks monetary damages or injunctive relief, or both. On August 7, 2009, Plaintiffs advised the Court by letter that they are not pursuing their motion for preliminary injunction and requested that the hearing date be removed from the Court’s calendar. Plaintiffs have advised counsel for the defendants that they intend to continue to pursue the case after the merger as a claim for money damages. 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 combined company after the merger. A preliminary injunction , had plaintiffs successfully pursued it, could have delayed or jeopardized the completion of the merger, and an adverse judgment granting permanent injunctive relief could have indefinitely enjoined completion of the merger. Based on the facts known to date, the defendants believe that the claims asserted against them in this lawsuit are without merit, and intend to defend themselves vigorously against the claims.

In January 2009, in the matter captioned “Elk City Oklahoma Pipeline, L.P. v. Northern Natural Gas Company”, (District Court of Tulsa County, Oklahoma), Elk City Oklahoma Pipeline, L.P. (“Elk City”), a subsidiary of APL’s, filed a petition against Northern Natural Gas Company (“NNG”), seeking a declaratory judgment related to the interpretation of a Purchase and Sale Agreement for certain pipeline and assets in Western Oklahoma which was entered into between the two parties on June 12, 2008 (the “PSA”). In March 2009, NNG filed a petition together with a motion for summary judgment alleging breach of the PSA for Elk City’s failure to complete the purchase and seeking specific performance or, alternatively, damages, in the matter captioned “Northern Natural Gas Company vs. Elk City Oklahoma Pipeline, L.P.”, (District Court of Tulsa County, Oklahoma). These matters were previously described in our quarterly report on Form 10-Q for the quarter ended March 31, 2009. Both matters were settled by agreement dated May 19, 2009. The settlement involved a monetary payment by Elk City, but does not require Elk City to purchase the pipeline assets. The amounts Elk City agreed to pay in connection with the settlement do not have a material impact on our financial condition or results of operations.

We, Atlas Energy, Atlas Pipeline Holdings, and Atlas Pipeline and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of our collective 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 risks are described elsewhere in this report and in our most recent Form 10-K for the year ended December 31, 2008, and our Form 10-Q for the three months ended March 31, 2009. The risk factors identified there in have not changed in any material respect, except for the additional risk factors added below.

The combined company resulting from the merger may fail to realize the anticipated cost savings, growth opportunities and synergies and other benefits anticipated from the merger, which could adversely affect the value of Atlas America common stock.

We and Atlas Energy currently operate as separate public companies. The success of the merger will depend, in part, on our ability to realize the anticipated synergies and growth opportunities from combining the businesses, as well as the projected stand-alone cost savings and revenue growth trends identified by each company. In addition, on a combined basis, we expect to benefit from operational synergies resulting from the consolidation of capabilities and elimination of redundancies as well as greater efficiencies from increased scale. Management also intends to focus on revenue synergies for the combined entity. However, management must successfully combine our businesses in a manner that permits these cost savings and synergies to be realized. In addition, it must achieve the anticipated savings without adversely affecting current revenues and our investments in future growth. If it is not able to successfully achieve these objectives, the anticipated cost savings, revenue growth and synergies may not be realized fully or at all, or may take longer to realize than expected.

Lawsuits have been filed against Atlas Energy, certain officers and members of its board of directors and us challenging the merger, and any adverse judgment may prevent the merger from becoming effective or from becoming effective within the expected timeframe.

Atlas Energy, certain officers and members of its board of directors and we are named as defendants in a consolidated purported class action lawsuit brought by our unitholders in Delaware Chancery Court challenging the proposed merger, seeking, among other things, to enjoin the defendants from consummating the merger on the agreed-upon terms. Plaintiffs initially filed five separate purported class actions, and the Chancery Court issued an order of consolidation on June 15, 2009. Plaintiffs filed a Verified Consolidated Class Action Complaint on July 1, 2009, which has superseded all prior complaints. On July 27, 2009, the Chancery Court granted the parties’ scheduling stipulation, setting a preliminary injunction hearing for September 4, 2009. The complaint advances claims of breach of fiduciary duty in connection with the merger agreement, including allegations of inadequate disclosures in connection with the Atlas Energy unitholder vote on the merger, and seeks monetary damages or injunctive relief, or both. Predicting the outcome of this lawsuit is difficult.

One of the conditions to the completion of the merger is that no judgment, order, injunction, decision, opinion or decree issued by a court or other governmental entity that makes the merger illegal or prohibits the consummation of the merger shall be in effect. A preliminary injunction could delay or jeopardize the completion of the merger, and an adverse judgment granting permanent injunctive relief could indefinitely enjoin completion of the merger. An adverse judgment for monetary damages could have a material adverse effect on the operations of the combined company after the merger.

The merger is subject to various closing conditions, and any delay in completing the merger may reduce or eliminate the benefits expected.

The merger is subject to the satisfaction of a number of other conditions beyond the parties’ control that may prevent, delay or otherwise materially adversely affect the completion of the transaction. On May 15, 2009, early termination of the waiting period under the HSR Act was granted. In July 2009, two other conditions to completion of the merger were satisfied. On July 10, 2009, Atlas Energy received the requisite consent from its lenders to amend its credit agreement to permit the merger, and on July 13, 2009, our stockholders approved an amendment to our charter to increase the number of authorized shares of common stock so that we have sufficient authorized shares to complete the merger. We cannot predict with certainty, however, whether and when any of the other conditions to completion of the merger will be satisfied. Any delay in completing the merger could cause the combined company not to realize, or delay the realization, of some or all of the benefits that the companies expect to achieve from the transaction.

100

Failure to complete the merger or delays in completing the merger could negatively affect the price of our common stock and each company’s future business and operations.

If the merger is not completed for any reason, Atlas Energy and we may be subject to a number of material risks, including the following:

•

the individual companies will not realize the benefits expected from the merger, including a potentially enhanced financial and competitive position;

•

the price of the our common stock may decline to the extent that the current market price of these securities reflects a market assumption that the merger will be completed; and

•

some costs relating to the merger must be paid even if the merger is not completed.

The issuance of shares of our common stock to Atlas Energy unitholders in the merger will substantially reduce the percentage ownership interests of our stockholders in us.

If the merger is completed, we expect that, based on Atlas Energy common units outstanding as of , 2009, we will issue approximately million shares of common stock in the merger. In addition, approximately 3.0 million shares of common stock will be reserved for issuance upon conversion of former Atlas Energy equity awards. As a result, the former Atlas Energy unitholders (other than us) are expected to own approximately [50.4%] of our outstanding shares of common stock outstanding after the merger, and our stockholders as of immediately prior to the merger are expected to own approximately [49.6%] of our outstanding shares of common stock outstanding after the merger. The merger will therefore result in a significant reduction in the relative percentage interests of our current stockholders in earnings, voting, liquidation value and book and market value.

ITEM 6.

EXHIBITS


Exhibit No.		Description

2.1		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⁽¹¹⁾

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		Tax Matters Agreement between Atlas America, Inc. and Resource America, Inc. dated May 14, 2004⁽⁵⁾

10.2		Transition Services Agreement between Atlas America, Inc. and Resource America, Inc. dated May 14, 2004⁽⁵⁾

10.3(a)		Employment Agreement for Edward E. Cohen dated May 14, 2004⁽⁵⁾

10.3(b)		Amendment to Employment Agreement dated as of December 31, 2008⁽¹²⁾

10.4(a)		Agreement for Services among Atlas America, Inc. and Richard Weber, dated April 5, 2006⁽⁶⁾

10.4(b)		Amendment No. 1 to Agreement for Services dated as of April 26, 2007⁽⁷⁾

101



10.4(c)		Amendment No. 2 to Agreement for Services dated as of December 18, 2008⁽¹²⁾

10.5		Contribution, Conveyance and Assumption Agreement, dated as of December 18, 2006, among Atlas America, Inc., Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC⁽⁴⁾

10.6		Omnibus Agreement, dated as of December 18, 2006, between Atlas America, Inc. and Atlas Energy Resources, LLC⁽⁴⁾

10.7		Management Agreement, dated as of December 18, 2006, among Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC and Atlas Energy Management, Inc.⁽⁴⁾

10.8		Stock Incentive Plan⁽¹²⁾

10.9		Atlas America Employee Stock Ownership Plan⁽⁸⁾

10.10		Atlas America, Inc. Investment Savings Plan⁽⁸⁾

10.11		Form of Stock Award Agreement⁽⁹⁾

10.12		Amended and Restated Annual Incentive Plan for Senior Executives⁽¹⁰⁾

10.13		Employment Agreement between Atlas America, Inc. and Jonathan Z. Cohen dated as of January 30, 2009⁽¹²⁾

10.14		Securities Purchase Agreement dated April 7, 2009, by and between Atlas Pipeline Mid-Continent, LLC and Spectra Energy Partners OLP, LP

10.15(a)		Revolving Credit Agreement dated as of July 26, 2006 by and among Atlas Pipeline Holdings, L.P., Atlas Pipeline Partners GP, LLC, Wachovia Bank, National Association and the lenders thereto

10.15(b)		First Amendment to Revolving Credit Agreement dated as of June 1, 2009⁽¹³⁾

10.16		Promissory Note dated as of June 1, 2009 by Atlas Pipeline Holdings, L.P.⁽¹³⁾

10.17		Guaranty Note dated as of June 1, 2009 by Atlas Pipeline Holdings, L.P.⁽¹³⁾

10.18		Guaranty, Subordination and Cash Collateral Agreement dated as of June 1, 2009 in favor of Wachovia Bank, National Association⁽¹³⁾

10.19		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⁽¹⁴⁾

10.20		Amended and Restated Limited Liability Company Agreement of Laurel Mountain Midstream, LLC dated as of June 1, 2009⁽¹⁴⁾

10.21		Employment Agreement for Matthew A. Jones dated July 1, 2009

31.1		Rule 13(a)-14(a)/15d-14(a) Certification

31.2		Rule 13(a)-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 June 14, 2005.

102

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

(3)	[Intentionally Omitted]

(4)	Previously filed as an exhibit to our Form 10-K for the year ended December 31, 2006

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

(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 June 2, 2009

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

103

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 AMERICA, INC.

Date: August 10, 2009	By:	/s/ EDWARD E. COHEN
		Edward E. Cohen Chairman of the Board and Chief Executive Officer

Date: August 10, 2009	By:	/s/ MATTHEW A. JONES
		Matthew A. Jones Chief Financial Officer

Date: August 10, 2009	By:	/s/ SEAN P. MCGRATH
		Sean P. McGrath Chief Accounting Officer

104

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. sophomore Avg

ARKHAN Inactive 10-Q2009 Q2 Quarterly report

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