ARKHAN 10-Q 2008 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2008

OR

o 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 (State or other jurisdiction of incorporation or organization)	51-0404430 (I.R.S. Employer Identification No.)
1550 Coraopolis Heights Road Moon Township, Pennsylvania (Address of principal executive office)	15108 (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. Yesþ Noo

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 filerþ	Accelerated filero
Non-accelerated filero (Do not check if smaller reporting company)	Smaller reporting companyo

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yeso Noþ

The number of outstanding shares of the registrant’s common stock on November 5, 2008 was 39,246,039 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 September 30, 2008 and December 31, 2007 (Unaudited)		3
	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2008 and 2007 (Unaudited)		4
	Consolidated Statement of Stockholders’ Equity for the Nine Months Ended September 30, 2008 (Unaudited)		5
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2008 and 2007 (Unaudited)		6
	Notes to Consolidated Financial Statements (Unaudited)		7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		51
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.		72
Item 4.	Controls and Procedures		80
PART II. OTHER INFORMATION			81
Item 1.	Legal Proceedings		81
Item 1A.	Risk Factors		81
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		82
Item 6.	Exhibits		83
SIGNATURES			84
EX-31.1
EX-31.2
EX-32.1
EX-32.2

2

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)

	September 30,			December 31,
ASSETS	2008			2007
Current assets:
Cash and cash equivalents	$	125,306		$	145,535
Accounts receivable		203,376			204,900
Derivative receivable from Partnerships		851			213
Current portion of derivative asset		32,303			37,968
Prepaid expenses and other		35,180			22,939
Prepaid and deferred income taxes		39,840			20,642
Total current assets		436,856			432,197
Property, plant and equipment, net		3,817,012			3,442,036
Intangible assets, net		204,180			224,264
Goodwill, net		712,026			744,449
Derivative receivable — long term from Partnerships		14,038			13,542
Derivative receivable — long term		11,401			6,882
Other assets, net		55,917			40,997
	$	5,251,430		$	4,904,367
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	13		$	64
Accounts payable		143,146			75,524
Liabilities associated with drilling contracts		32,626			132,517
Accrued producer liabilities		75,941			80,697
Derivative liability		93,256			111,223
Accrued liabilities		122,111			99,468
Advances from affiliate		105			58
Total current liabilities		467,198			499,551
Long-term debt		2,326,328			1,994,392
Deferred tax liability		245,070			197,106
Long-term derivative liability		177,288			157,850
Other long-term liabilities		54,342			46,524
Minority interests		1,565,894			1,595,781
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		425			290
Additional paid-in capital		411,511			390,591
Treasury stock, at cost		(142,455	)		(108,886	)
ESOP loan receivable		(361	)		(417	)
Accumulated other comprehensive loss		(9,383	)		(5,935	)
Retained earnings		155,573			137,520
Total stockholders’ equity		415,310			413,163
	$	5,251,430		$	4,904,367

See accompanying notes to consolidated financial statements

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ATLAS AMERICA, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Revenue:
Well construction and completion	$	116,987		$	103,324		$	343,466		$	240,841
Gas and oil production		81,235			63,265			236,417			109,840
Transmission, gathering and processing		424,413			246,195			1,264,190			480,594
Administration and oversight		5,216			5,364			15,370			13,347
Well services		5,299			4,845			15,363			12,721
Gain (loss) on mark-to-market derivatives		147,505			(11,467	)		(257,344	)		(16,036	)
Total revenue		780,655			411,526			1,617,462			841,307
Costs and expenses:
Well construction and completion		101,727			89,847			298,666			209,427
Gas and oil production		12,688			9,887			35,735			14,412
Transmission, gathering and processing		338,475			187,416			1,003,252			377,740
Well services		2,753			2,515			7,815			6,705
General and administrative		13,278			48,677			59,633			84,454
Net expense reimbursement — affiliate		255			246			689			775
Depreciation, depletion and amortization.		46,134			35,187			142,910			61,064
Total costs and expenses		515,310			373,775			1,548,700			754,577
Operating income		265,345			37,751			68,762			86,730
Other income (expense):
Interest expense		(37,079	)		(37,480	)		(105,487	)		(53,681	)
Minority interests		(194,054	)		6,402			60,777			14,992
Other, net		3,815			3,526			11,838			6,425
Total other income (expense)		(227,318	)		(27,552	)		(32,872	)		(32,264	)
Income before income taxes		38,027			10,199			35,890			54,466
Provision for income taxes		(13,924	)		(3,096	)		(13,136	)		(17,249	)
Net income	$	24,103		$	7,103		$	22,754		$	37,217
Net income per common share:
Basic	$	0.60		$	0.18		$	0.57		$	0.91
Diluted	$	0.58		$	0.17		$	0.54		$	0.88
Weighted average common shares outstanding:
Basic		40,093			40,280			40,251			41,018
Diluted		41,731			41,969			42,048			42,522

See accompanying notes to consolidated financial statements

4

ATLAS AMERICA, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2008
(in thousands, except share data)
(Unaudited)

																	Accumulated
					Additional									ESOP			Other						Total
	Common Stock				Paid-In			Treasury Stock						Loan			Comprehensive			Retained			Stockholders'
	Shares		$		Capital			Shares			$			Receivable			Loss			Earnings			Equity
Balance at January 1, 2008		29,003,212	$	290	$	390,591			(2,126,055	)	$	(108,886	)	$	(417	)	$	(5,935	)	$	137,520		$	413,163
Issuance of common units		28,403		-		367			28,777			1,292			-			-			-			1,659
Other comprehensive loss		-		-		-			-			-			-			(3,448	)		-			(3,448	)
Repayment of ESOP loan		-		-		-			-			-			56			-			-			56
Treasury stock purchase		-		-		-			(1,002,877	)		(34,861	)		-			-			-			(34,861	)
Stock option compensation expense		-		-		3,019			-			-			-			-			-			3,019
Three-for-two stock split		13,470,021		135		(135	)		-			-			-			-			-			-
Dividends paid		-		-		-			-			-			-			-			(4,701	)		(4,701	)
Gain on sale of subsidiary units		-		-		17,669			-			-			-			-			-			17,669
Net income		-		-		-			-			-			-			-			22,754			22,754
Balance at September 30, 2008		42,501,636	$	425	$	411,511			(3,100,155	)	$	(142,455	)	$	(361	)	$	(9,383	)	$	155,573		$	415,310

See accompanying notes to consolidated financial statements

5

ATLAS AMERICA, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)

	Nine Months Ended
	September 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	22,754		$	37,217
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		142,910			61,064
Amortization of deferred finance costs		5,925			7,626
Non-cash (gain) loss on derivative value, net		(45,872	)		19,501
Non-cash compensation (income) expense		(4,132	)		43,506
Minority interests		(60,777	)		(14,992	)
Distributions paid to minority interests		(177,934	)		(32,853	)
Deferred income taxes (benefit)		15,621			(4,145	)
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable and prepaid expenses and other		(6,886	)		(70,505	)
Accounts payable and accrued liabilities		(36,021	)		30,974
Accounts payable and accounts receivable — affiliates		47			-
Other operating assets/liabilities		685			760
Net cash provided by (used in) operating activities		(143,680	)		78,153
CASH FLOWS FROM INVESTING ACTIVITIES:
Net cash paid for acquisitions		-			(3,141,680	)
Acquisition purchase price adjustment		31,429			-
Capital expenditures		(469,385	)		(201,856	)
Investment in Lightfoot Capital Partners, L.P.		(437	)		(10,379	)
Proceeds from sale of assets		63			1,071
Other		851			(813	)
Net cash used in investing activities		(437,479	)		(3,353,657	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of Atlas Energy long-term debt		407,125			-
Issuance of Atlas Pipeline long-term debt		244,854			-
Borrowings under Atlas Pipeline Partners, L.P., Atlas Pipeline Holdings, and Atlas Energy credit facilities		908,000			1,931,509
Repayments under Atlas Pipeline Partners, L.P., Atlas Pipeline Holdings, and Atlas Energy credit facilities		(1,110,025	)		(345,922	)
Repayments under Atlas Pipeline Partners, L.P. term loan		(122,847	)		-
Net proceeds from Atlas Pipeline Partners L.P. equity offerings		206,901			946,555
Net proceeds from Atlas Energy equity offering		82,514			597,500
Net proceeds from Atlas Pipeline Holdings equity offering		-			167,033
Dividends paid		(4,701	)		(2,238	)
Purchase of treasury stock		(34,861	)		(80,449	)
Deferred financing costs and other		(16,030	)		(10,073	)
Net cash provided by financing activities		560,930			3,203,915
Net change in cash and cash equivalents		(20,229	)		(71,589	)
Cash and cash equivalents, beginning of period		145,535			185,401
Cash and cash equivalents, end of period	$	125,306		$	113,812

See accompanying notes to consolidated financial statements

6

ATLAS AMERICA, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2008
(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 September 30, 2008:

• Atlas Energy Resources, LLC (“Atlas Energy” or “ATN”), a publicly traded Delaware limited liability company (NYSE: ATN) 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. In May 2008, the Company purchased an additional 600,000 ATN Class B common units in a private placement transaction at a price of $42.00 per unit (see Note 14). At September 30, 2008, the Company owned approximately 48.3% of the outstanding Class A and common units and all of the management incentive interests of ATN;

• Atlas Pipeline Partners, L.P. (“Atlas Pipeline Partners” or “APL”), a midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachia regions (NYSE:APL). In June 2008, the Company purchased 1,112,000 APL common limited partnership units in a private placement transaction at a net price of $36.02 per common unit (see Note 14). At September 30, 2008, 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. In June 2008, the Company purchased an additional 308,109 common limited partner units in a private placement transaction at a price of $32.50 per unit (see Note 14). At September 30, 2008, 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, and an approximate 12.3% limited partner interest in APL at September 30, 2008; 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 September 30, 2008, the Company has invested $10.7 million in Lightfoot LP.

     The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2007 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007. The results of operations for the three and nine month periods ended September 30, 2008 may not necessarily be indicative of the results of operations for the full year ending December 31, 2008. Certain amounts in the prior year’s consolidated financial statements have been reclassified to conform to the current year presentation.

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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, 2007.

Principles of Consolidation and Minority 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. 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 minority ownership interests in the net income (loss) of ATN, AHD and APL are reflected within minority interests on the Company’s consolidated statements of operations, and the minority interests in the assets and liabilities of ATN, AHD and APL are reflected as a liability 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, revenues, and costs and expenses of the energy partnerships in which ATN has an interest. Such interests typically range from 30% 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 to its own economics as further explained under the heading “Oil and Gas Properties,” below. All material intercompany transactions have been eliminated.

     The Company’s consolidated financial statements also include the operations of APL’s Chaney Dell natural gas gathering system and processing plants located in Oklahoma (“Chaney Dell system”) and APL’s Midkiff/Benedum natural gas gathering system and processing plants located in Texas (“Midkiff/Benedum system”). In July 2007, APL acquired control of Anadarko Petroleum Corporation’s (NYSE: APC) (“Anadarko”) 100% interest in the Chaney Dell system and its 72.8% undivided joint venture interest in the Midkiff/Benedum system (see Note 3). The transaction was effected by the formation of two joint venture companies which own the respective systems, of which APL has a 95% interest and Anadarko has a 5% interest in each. APL consolidates 100% of these joint ventures. The Company reflects Anadarko’s 5% interest in the net income of these joint ventures as minority interest on its statements of operations. The Company also reflects Anadarko’s investment in the net assets of the joint ventures as minority interest on its consolidated balance sheets. In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems, the joint ventures issued cash to Anadarko of $1.9 billion in return for a note receivable. This note receivable is reflected within minority interests on the Company’s consolidated balance sheets.

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

Use of Estimates

     The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Company’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Company’s consolidated financial

8

statements are based on a number of significant estimates, including the revenue and expense accruals, deferred tax assets and liabilities, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions, stock compensation, 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 month’s financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following months’ financial results. Management believes that the operating results presented for the three and nine months ended September 30, 2008 represent actual results in all material respects (see “— Revenue Recognition” accounting policy for further description).

Revenue Recognition

     Atlas Energy.Certain energy activities are conducted by ATN through, and a portion of its revenues are attributable to, sponsored energy limited partnerships. ATN contracts with the energy partnerships to drill partnership wells. The contracts require that the energy 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 in less than 60 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 APL’s regulated transmission pipeline is recognized at the time the transportation service is provided. 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.

9

• 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 September 30, 2008 and December 31, 2007 of $142.3 million and $131.7 million, respectively, which are included in accounts receivable within the Company’s consolidated balance sheets.

Net Income Per Share

     Basic net income per share is computed by dividing net income by the weighted average number of common stock outstanding during the period. Diluted net income per share is calculated by dividing net income by the sum of the weighted average number of common 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 per share with those used to compute diluted net income per share (in thousands):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007(1)		2008		2007(1)
Weighted average number of shares — basic		40,093		40,280		40,251		41,018
Add: effect of dilutive incentive awards		1,638		1,689		1,797		1,504
Weighted average number of common shares — diluted		41,731		41,969		42,048		42,522

(1) The shares for the three and nine months ended September 30, 2007 have been restated to reflect the three for two stock split on May 21, 2008.

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 include 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 taxes). The following table sets forth the calculation of the Company’s comprehensive income (loss) (in thousands):

10

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2008		2007			2008			2007
Net income	$	24,103	$	7,103		$	22,754		$	37,217
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges, net of tax provision (benefit) of $53,888 and $4,948 for the three months ended September 30, 2008 and 2007, respectively, and ($9,428) and ($2,377) for the nine months ended September 30, 2008 and 2007, respectively		84,283		8,424			(14,332	)		(3,184	)
Less: reclassification adjustment for realized losses (gains) in net income, net of tax of $5,633 and ($687) for the three months ended September 30, 2008 and 2007, respectively, and $6,810 and ($786) for the nine months ended September 30, 2008 and 2007, respectively		8,810		(1,170	)		10,588			(1,339	)
Plus: amortization of additional post-retirement liability recorded upon adoption of SFAS No. 158, net of tax of $51 and $27 for the three months ended September 30, 2008 and 2007, respectively, and $153 and $80 for the nine months ended September 30, 2008 and 2007, respectively		87		41			296			125
Total other comprehensive income (loss)		93,180		7,295			(3,448	)		(4,398	)
Comprehensive income	$	117,283	$	14,398		$	19,306		$	32,819

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 combined borrowed funds by ATN and APL was 5.7% and 7.7% for the three months ended September 30, 2008 and 2007, respectively, and 5.9% and 7.4% for the nine months ended September 30, 2008 and 2007, respectively. The aggregate amount of interest capitalized by ATN and APL was $2.9 million and $1.5 million for the three months ended September 30, 2008 and 2007, respectively, and $8.3 million and $3.3 million for the nine months ended September 30, 2008 and 2007, 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 (see Note 3). Statement of Financial Accounting Standards (“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 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.

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     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 AGO (see Note 3). 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 September 30, 2008 and December 31, 2007 (in thousands):

							Estimated
	September 30,			December 31,			Useful Lives
	2008			2007			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	$	(35,346	)	$	(16,179	)
Partnership management and operating contracts		(10,533	)		(9,949	)
Non-compete agreement		(556	)		(223	)
	$	(46,435	)	$	(26,351	)
Net Carrying Amount:
Customer contracts and relationships	$	200,036		$	219,203
Partnership management and operating contracts		3,810			4,394
Non-compete agreement		334			667
	$	204,180		$	224,264

     Amortization expense on intangible assets was $6.7 million and $6.0 million for the three months ended September 30, 2008 and 2007, respectively, and $20.1 million and $7.6 million for the nine months ended September 30, 2008 and 2007, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2009-$26.8 million; 2010-$26.5 million; 2011-$26.3 million; 2012-$26.2 million; and 2013-$25.7 million.

Goodwill

     ATN and APL have recognized goodwill recorded in connection with consummated acquisitions (see Note 3). SFAS No. 142 requires that goodwill is not amortized, but instead evaluated for impairment at least annually by comparing reporting unit fair values to carrying values. The evaluation of impairment under SFAS No. 142 requires the use of projections, estimates and assumptions as to the future performance of ATN’s and APL’s operations, including anticipated future revenues, expected future operating costs and the discount factor used. Actual results could differ from projections, resulting in revisions to ATN’s and APL’s assumptions and, if required, recognition of an impairment loss. ATN’s and APL’s tests of goodwill at December 31, 2007 resulted in no impairment and no impairment indicators have been noted as of September 30, 2008. ATN and APL will continue to evaluate its goodwill at least annually and if impairment indicators arise, and will reflect the impairment of goodwill, if any, within the Company’s consolidated statement of operations for the period in which the impairment is indicated. The changes in the carrying amount of goodwill for the nine months ended September 30, 2008 and 2007 were as follows (in thousands):

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	Nine Months Ended
	September 30,
	2008			2007
Balance, beginning of period	$	744,449		$	98,607
Post-closing purchase price adjustment with seller and purchase price allocation adjustment — Chaney Dell and Midkiff/Benedum systems acquisition		(2,217	)		—
Recovery of state sales tax initially paid on transaction — Chaney Dell and Midkiff/Benedum systems acquisition		(30,206	)		—
Balance, end of period	$	712,026		$	98,607

     During the fourth quarter 2007 and first quarter of 2008, APL adjusted its preliminary purchase price allocation for the acquisition of its Chaney Dell and Midkiff/Benedum systems since its July 2007 acquisition date by increasing the estimated amount allocated to goodwill and intangible assets and reducing amounts initially allocated to property, plant and equipment (see Note 3 and Note 4). Also, 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.

Impairment of Long-Lived Assets

     The Company’s long-lived assets are reviewed for impairment annually or whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets.

     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 at December 31, 2007, 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 partnership’s 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.

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     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 Partnership’s 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.

New and Recently Adopted Accounting Standards

     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 is prohibited. All prior-period EPS data presented shall be adjusted retrospectively to conform to the provisions of this FSP. The Company will apply the requirements of FSP EITF 03-6-1 upon its adoption on January 1, 2009 and it does not believe the adoption of FSP EITF 03-6-1 will have a material impact on its financial position or results of operations.

     In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162, “The Hierarchy of Generally Accepted Accounting Policies” (“SFAS 162”), which reorganizes the sources of accounting principles into a Generally Accepted Accounting Principles (“GAAP”) hierarchy in order of authority. The purpose of the new standard is to improve financial reporting by providing a consistent framework for determining what accounting principles should be used when preparing U.S. GAAP financial statements. The standard is effective 60 days after the SEC’s approval of the PCAOB’s amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” The adoption of SFAS 162 will not have a material impact on the Company’s financial position or 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

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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)”). 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 is 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 will apply the requirements of FSP FAS 142-3 upon its adoption on January 1, 2009 and it does not believe the adoption of FSP FAS 142-3 will have a material impact on its financial position or results of operations.

     In March 2008, the FASB ratified the Emerging Issues Task Force (“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 requires retrospective application of the guidance to all periods presented. Early adoption is prohibited. The Company currently does not expect the adoption of EITF 07-4 to have an impact on its financial position and 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 Statement of Financial Accounting Standards 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 is currently evaluating the impact the adoption of SFAS No. 161 will have on the disclosures regarding its derivative instruments.

     In December 2007, the FASB issued SFAS No. 160, “Noncontrolling 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 noncontrolling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling 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 noncontrolling interest. Additionally, SFAS No. 160 establishes a single method for 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 is effective for fiscal years beginning on or after December 15, 2008. The Company will apply the requirements of SFAS No. 160 upon its adoption on January 1, 2009 and is currently evaluating whether SFAS No. 160 will have a material impact on its financial position or results of operations.

     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

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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 noncontrolling 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 noncontrolling 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 will apply the requirements of SFAS No. 141(R) upon its adoption on January 1, 2009 and is currently evaluating whether SFAS No. 141(R) will have a material impact on its financial position or results of operations.

     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment to FASB Statement No. 115” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 is effective at the inception of an entity’s first fiscal year beginning after November 15, 2007 and offers various options in electing to apply its provisions. The Company adopted SFAS No. 159 at January 1, 2008, and has elected not to apply the fair value option to any of its financial instruments not already carried at fair value in accordance with other accounting standards.

     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosures about fair value statements. In February 2008, the FASB issued FASB Staff Position SFAS No. 157-b, “Effective Date of FASB Statement No. 157”, which provides for a one-year deferral of the effective date of SFAS No. 157 with regard to an entity’s non-financial assets, non-financial liabilities, initial recognition of asset retirement obligations or any non-recurring fair value measurement. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. The Company adopted SFAS No. 157 at January 1, 2008 with respect to its subsidiaries’ derivative instruments, which are measured at fair value within its financial statements. The provisions of SFAS No. 157 have not been applied to the Company’s non-financial assets and non-financial liabilities. See Note 9 for disclosures pertaining to the provisions of SFAS No. 157 with regard to the Company’s subsidiaries’ financial instruments.

NOTE 3 — ACQUISITIONS

     APL’s Chaney Dell and Midkiff/Benedum Acquisition

     In July 2007, APL acquired control of Anadarko’s 100% interest in the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and its 72.8% undivided joint venture interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (the “Anadarko Assets”). The Chaney Dell System includes 3,470 miles of gathering pipeline and three processing plants, while the Midkiff/Benedum System includes 2,500 miles of gathering pipeline and two processing plants. The transaction was effected by the formation of two joint venture companies which own the respective systems, to which APL contributed $1.9 billion and Anadarko contributed the Anadarko Assets.

     In connection with this acquisition, APL reached an agreement with Pioneer, which currently holds a 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer has an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system, which began on June 15, 2008 and ended on November 1, 2008, and an additional 7.4% interest beginning on June 15, 2009 and ending on November 1, 2009 (the aggregate 22.0% additional interest can be entirely purchased during the period beginning June

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15, 2009 and ending 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 million, subject to certain adjustments, for the additional 22% interest if fully exercised. APL will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercises the purchase options.

     APL funded the purchase price in part from the private placement of $1.125 billion of its common units to investors at a negotiated purchase price of $44.00 per unit. Of the $1.125 billion, $168.8 million of these units were purchased by AHD. AHD funded this purchased through the private placement of $168.8 million of its common units to investors. APL also received a capital contribution from AHD of $23.1 million in order for AHD to maintain its 2.0% general partner interest in APL. AHD funded this capital contribution and the underwriting fees and other transaction costs related to its private placement of common units through borrowings under its revolving credit facility of $25.0 million (see Note 7). AHD, which holds all of the incentive distribution rights of APL as general partner, has also 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 (see Note 15). APL funded the remaining purchase price from $830.0 million of proceeds from a senior secured term loan which matures in July 2014 and borrowings from its senior secured revolving credit facility that matures in July 2013 (see Note 7).

     APL’s acquisition was accounted for using the purchase method of accounting under SFAS No. 141. The following table presents the purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed in the acquisition, based on their fair values at the date of the acquisition (in thousands):

Accounts receivable	$	745
Prepaid expenses and other		4,587
Property, plant and equipment		1,030,464
Intangible assets — customer relationships		205,312
Goodwill		613,420
Total assets acquired		1,854,528
Accounts payable and accrued liabilities		(1,499	)
Net cash paid for acquisition	$	1,853,029

     APL recorded goodwill in connection with this acquisition as a result of Chaney Dell’s and Midkiff/Benedum’s significant cash flow and strategic industry position. In April 2008, APL received a $30.2 million cash reimbursement for state sales tax initially paid on its transaction to acquire the Chaney Dell and Midkiff/Benedum systems. 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. The results of Chaney Dell’s and Midkiff/Benedum’s operations are included within the Company’s consolidated financial statements from the date of acquisition.

     ATN’s DTE Gas and Oil Company Acquisition

     On June 29, 2007, ATN acquired all of the outstanding equity interests of DTE Gas & Oil Company (“DGO”) from DTE Energy Company (NYSE: DTE) and MCN Energy Enterprises for $1.3 billion, including adjustments for working capital of $15.0 million and current year capital expenditures of $19.0 million. Assets acquired include interests in approximately 2,150 natural gas wells with estimated proved reserves of approximately 610.6 billion cubic feet of natural gas equivalents located in the northern lower peninsula of Michigan, 228,000 developed acres, and 66,000 undeveloped acres. With this acquisition, the Company increased its natural gas and oil production as well as entered into a new region that offers additional

17

opportunities to expand its operations. Subsequent to the acquisition of DGO, the Company changed DGO’s name to Atlas Gas & Oil Company, LLC (“AGO”).

     To fund the acquisition, ATN borrowed $713.9 million on its new credit facility (see Note 7) and received net proceeds of $597.5 million from a private placement of its Class B common and new Class D units. Proceeds of $52.5 million were used to pay the outstanding balance of ATN’s previous credit facility. The acquisition was accounted for using the purchase method of accounting under SFAS No. 141. The following table presents the purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed based on their estimated fair market value at the date of acquisition (in thousands):

Accounts receivable	$	33,764
Prepaid expenses		515
Other assets		890
Natural gas and oil properties		1,267,901
Total assets acquired		1,303,070
Accounts payable and accrued liabilities		(19,233	)
Other liabilities		(210	)
Asset retirement obligations		(11,109	)
Total liabilities assumed		(30,552	)
Net assets acquired	$	1,272,518

     The results of AGO’s operations are included within the Company’s consolidated financial statements from the date of acquisition.

     The following data presents pro forma revenue, net income and net income per share for the Company for the three and nine months ended September 30, 2007 as if the ATN and APL acquisitions discussed above and related financing transactions had occurred on January 1, 2007. Actual financial data for the three and nine month periods ended September 30, 2008 is also presented. The Company has prepared these unaudited pro forma financial results for comparative purposes only. These pro forma financial results may not be indicative of the results that would have occurred if ATN and APL had completed these acquisitions and financing transactions at the beginning of the periods shown below or the results that will be attained in the future (in thousands, except per share data):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
Revenue	$	780,655	$	411,526	$	1,617,462	$	1,178,427
Net income	$	24,103	$	7,103	$	22,754	$	16,429
Net income per share:
Basic	$	0.60	$	0.18	$	0.57	$	0.40
Diluted	$	0.58	$	0.17	$	0.54	$	0.39

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NOTE 4 — PROPERTY, PLANT AND EQUIPMENT

     Property, plant and equipment is 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):

							Estimated
	September 30,			December 31,			Useful Lives
	2008			2007			in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,208,014		$	1,043,687
Wells and related equipment		816,130			752,184
Total proved properties		2,024,144			1,795,871
Unproved properties		17,625			16,380
Support equipment		9,265			6,936
Total natural gas and oil properties		2,051,034			1,819,187
Pipelines, processing and compression facilities		1,884,819			1,638,845		15 -- 40
Rights of way		172,016			168,359		20 -- 40
Land, buildings and improvements		24,581			21,742		10 -- 40
Other		21,225			17,730		3 -- 10
		4,153,675			3,665,863
Less — accumulated depreciation, depletion and amortization		(336,663	)		(223,827	)
	$	3,817,012		$	3,442,036

     In July 2007, APL acquired control of the Chaney Dell and Midkiff/Benedum systems (see Note 3). During the fourth quarter of 2007 and first quarter of 2008, APL adjusted its preliminary purchase price allocation by adjusting the estimated amounts allocated to goodwill and property, plant, and equipment.

     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 are based on estimated proved reserves and depletion, depreciation and amortization rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include ATN’s costs of property interests in uncontrolled, but proportionately consolidated from investment partnerships, wells drilled solely by ATN, 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.

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NOTE 5 — OTHER ASSETS

     The following is a summary of other assets (in thousands):

	September 30,		December 31,
	2008		2007
Deferred finance costs, net of accumulated amortization of $20,138 and $14,213 at September 30, 2008 and December 31, 2007, respectively	$	41,681	$	26,118
Investments		11,635		12,061
Security deposits		2,118		2,630
Other		483		188
	$	55,917	$	40,997

     Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 7). 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. In July 2007, APL recorded $5.0 million of accelerated amortization of deferred financing costs associated with the replacement of its previous credit facility with a new facility (see Note 7).

     Derivatives receivable from drilling partnerships represents the portion of long-term unrealized derivative loss on contracts that has been allocated to the investment partnerships based on their share of total production volumes sold. ATN also has a short-term derivative receivable from drilling partnerships of $0.9 million and $0.2 million as of September 30, 2008 and December 31, 2007, respectively, and a long-term derivative receivable from drilling partnerships of $14.0 million and $13.5 million, respectively, representing the short- and long-term unrealized derivative loss on contracts that have been allocated to them, which is included as part of the Company’s accounts receivable on its consolidated balance sheets.

NOTE 6 — 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. Under SFAS 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 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 the ATN’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):

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	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Asset retirement obligations, beginning of period	$	45,334		$	41,792		$	42,358		$	26,726
Liabilities acquired (See Note 3)		—			505			—			13,920
Liabilities incurred		975			997			2,615			2,024
Liabilities settled		(36	)		(9	)		(38	)		(30	)
Accretion expense		687			673			2,025			1,318
Asset retirement obligations, end of period	$	46,960		$	43,958		$	46,960		$	43,958

     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 7 — DEBT

     Total debt consists of the following (in thousands):

	September 30,			December 31,
	2008			2007
ATN revolving credit facility	$	462,000		$	740,000
ATN 10.75% senior notes — due 2018.		406,838			—
AHD revolving credit facility		31,000			25,000
APL revolving credit facility		175,000			105,000
APL term loan		707,180			830,000
APL 8.125% senior notes — due 2015.		294,310			294,392
APL 8.75% senior notes — due 2018		250,000			—
Other debt		13			64
		2,326,341			1,994,456
Less current maturities		(13	)		(64	)
Total long-term debt	$	2,326,328		$	1,994,392

ATN Revolving Credit Facility

     Upon the closing of its acquisition of DTE Gas & Oil (See Note 3), ATN replaced its credit facility with a new 5-year credit facility with an initial borrowing base of $850.0 million with a syndicate of banks. The borrowing base is redetermined semiannually on April 1 and October 1 subject to changes in ATN’s oil and gas reserves and also reduced by 25% of the amount of any issuance of senior unsecured notes by ATN. The borrowing base at September 30, 2008 was $697.5 million. Up to $50.0 million of the facility may be in the form of standby letters of credit. The facility is secured by substantially all of ATN’s assets and is guaranteed by each of ATN’s subsidiaries (other than Anthem Securities, Inc.) 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. At September 30, 2008, the weighted average interest rate on outstanding borrowings was 4.9%.

     The base rate for any day equals the higher of the federal funds rate plus 0.50% or the J.P. Morgan prime rate. 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 applicable margin ranges from 0.0% to 0.75% for base rate loans and 1.00% to 1.75% for LIBOR loans.

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     The credit facility requires ATN to maintain specified financial ratios of current assets to current liabilities and debt to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”) as disclosed in the credit agreement. In addition, the credit agreement limits sales, leases or transfers of assets and the incurrence of additional indebtedness. The credit 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 September 30, 2008. The facility terminates in June 2012, when all outstanding borrowings must be repaid. At September 30, 2008 and December 31, 2007, $462.0 million and $740.0 million, respectively, were outstanding under this facility. In addition, letters of credit of $1.2 million and $1.1 million were outstanding at each date, which are not reflected as borrowings on the Company’s consolidated balance sheets.

ATN Senior Notes

     In January 2008, ATN completed a private placement of $250.0 million of its 10.75% senior unsecured notes due 2018 to institutional buyers pursuant to rule 144A. under the Securities Act of 1933. In May 2008 ATN issued an additional $150.0 million of senior notes at 104.75% to par to yield 9.85% to the par call on February 1, 2016. ATN intends to treat these issuances as a single class of debt securities, which were subsequently registered for resale on September 19, 2008. ATN received proceeds of approximately $398.0 million from these offerings, including a $7.1 million premium and net of $9.2 million in underwriting fees. In addition, ATN received approximately $4.7 million related to accrued interest. ATN used the net proceeds to reduce the balance outstanding on its revolving credit facility. Interest on the senior notes is payable semi-annually in arrears on February 1 and August 1 of each year. The 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 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 senior notes are junior in right of payment to ATN’s secured debt, including its obligations under its credit facility. The indenture governing the 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.

AHD Credit Facility

     At September 30, 2008, AHD had a $50.0 million revolving credit facility with a syndicate of banks. At September 30, 2008, AHD had $31.0 million outstanding under its revolving credit facility, which was utilized to fund its capital contribution to APL to maintain its 2.0% general partner interest, underwriter fees and other transaction costs related to its July 2007 private placement of common units (see Note 3). AHD’s credit facility matures in April 2010 and bears interest, at its option, at either (i) adjusted LIBOR (plus the applicable margin, as defined in the credit facility) or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank, National Association prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding credit facility borrowings at September 30, 2008 was 6.0%. Borrowings under AHD’s credit facility are secured by a first-priority lien on a security interest in all of AHD’s assets, including a pledge of its interests in APL, and are guaranteed by AHD’s 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 interests in its subsidiaries. AHD is in compliance with these covenants as of September 30, 2008.

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     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 us, AHD’s general partner or any other obligor, and termination of a material agreement and occurrence of a material adverse effect. AHD’s credit facility requires it to maintain a combined leverage ratio, defined as the ratio of the sum of (i) AHD’s funded debt (as defined in its credit facility) and (ii) APL’s funded debt (as defined in APL’s credit facility) to APL’s EBITDA (as defined in APL’s credit facility) of not more than 5.5 to 1.0. In addition, AHD’s credit facility requires it to maintain a funded debt (as defined in its credit facility) to EBITDA ratio of not more than 3.5 to 1.0; and an interest coverage ratio (as defined in its credit facility) of not less than 3.0 to 1.0. AHD’s credit facility defines EBITDA for any period of four fiscal quarters as the sum of (i) four times the amount of cash distributions payable with respect to the last fiscal quarter in such period by APL to AHD in respect of AHD’s general partner interest, limited partner interest and incentive distribution rights in APL and (ii) AHD’s consolidated net income (as defined in its credit facility and as adjusted as provided in its credit facility). As of September 30, 2008, AHD’s combined leverage ratio was 5.0 to 1.0, its funded debt to EBITDA was 0.5 to 1.0, and its interest coverage ratio was 34.1 to 1.0.

     AHD may borrow under its credit facility (i) for general business purposes, including for working capital, to purchase debt or limited partnership units of APL, to fund general partner contributions from it to APL and to make permitted acquisitions, (ii) to pay fees and expenses related to its credit facility and (iii) for letters of credit.

APL Term Loan and Credit Facility

     At September 30, 2008, APL had a senior secured credit facility with a syndicate of banks which consisted of a term loan maturing in July 2014 and a $380.0 revolving credit facility which matures in July 2013. Borrowings under the 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 September 30, 2008 was 4.9%, and the weighted average interest rate on the outstanding APL term loan borrowings at September 30, 2008 was 6.2%. Up to $50.0 million of the APL credit facility may be utilized for letters of credit, of which $8.1 million was outstanding at September 30, 2008. These outstanding letter of credit amounts were not reflected as borrowings on the Company’s consolidated balance sheet.

     In June 2008, APL entered into an amendment to its revolving credit facility and term loan agreement to revise the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to APL’s early termination of certain crude oil derivative contracts (see Note 8) in calculating its Consolidated EBITDA. In June 2008, APL repaid $122.8 million of its outstanding term loan and repaid $120.0 million of outstanding borrowings under the credit facility with proceeds from its issuance of $250.0 million of 10-year, 8.75% senior unsecured notes (see “Senior Notes”). Additionally, in June 2008 APL’s lenders increased their commitments for its revolving credit facility by $80.0 million to $380.0 million.

     Borrowings under the APL 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 the Chaney Dell and Midkiff/Benedum joint ventures, and by the guaranty of each of its 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 in compliance with these covenants as of September 30, 2008. Mandatory prepayments of the amounts borrowed under the term loan portion of the credit facility are required from the net cash proceeds of debt issuances, and of dispositions of assets that exceed $50.0 million in the aggregate in any fiscal year that are not reinvested in replacement assets within 360 days. In connection with the new credit facility, APL agreed to remit an underwriting fee to the lead underwriting bank of the

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credit facility of 0.75% of the aggregate principal amount of the term loan outstanding on January 23, 2008. In January 2008, APL and the underwriting bank agreed to extend the agreement through June 30, 2008. In June 2008, APL and the underwriting bank agreed to extend the agreement through November 30, 2008 and amend the underwriting fee to be 0.50% of the aggregate principal amount of the term loan outstanding as of that date.

     The events which constitute an event of default for APL’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 APL in excess of a specified amount, and a change of control of APL’s General Partner. APL’s credit facility requires it to maintain a ratio of funded debt (as defined in the credit facility) to EBITDA (as defined in the credit facility) ratio of not more than 5.25 to 1.0, and an interest coverage ratio (as defined in the credit facility) of not less than 2.75 to 1.0. During a Specified Acquisition Period (as defined in the credit facility), for the first 2 full fiscal quarters subsequent to the closing of an acquisition with total consideration in excess of $75.0 million, the ratio of funded debt to EBITDA will be permitted to step up to 5.75 to 1.0. As of September 30, 2008, APL’s ratio of funded debt to EBITDA was 4.9 to 1.0 and its interest coverage ratio was 3.6 to 1.0.

APL Senior Notes

     At September 30, 2008, APL had $250.0 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“APL 8.75% Senior Notes”) and $293.5 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 $0.8 million of unamortized premium received as of September 30, 2008. The APL 8.75% Senior Notes were issued in June 2008 in a private placement transaction pursuant to Rule 144A and Regulation S under the Securities Act of 1933 for net proceeds of $244.9 million, after underwriting commissions and other transaction costs. 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. A similar redemption option exists prior to December 15, 2008 with respect to the APL 8.125% Senior Notes. The Senior Notes in the aggregate are also subject to repurchase by APL at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if APL does not reinvest the net proceeds within 360 days. The APL Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its credit facility.

     Indentures governing the APL Senior Notes in the aggregate contain covenants, including limitations of APL’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. APL is in compliance with these covenants as of September 30, 2008.

     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 does not meet the aforementioned deadline, the APL 8.75% Senior Notes will be subject to additional interest, up to 1% per annum, until such time that APL has caused the exchange offer to be consummated.

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NOTE 8 — DERIVATIVE INSTRUMENTS

     APL and ATN 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 (loss), 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. At September 30, 2008 and December 31, 2007, the Company reflected net derivative liabilities on its consolidated balance sheets of $211.9 million and $210.6 million, respectively. Of the $9.4 million of net loss in accumulated other comprehensive loss within stockholders’ equity on the Company’s consolidated balance sheet at September 30, 2008, if the fair values of the instruments remain at current market values, the Company will reclassify $4.7 million of losses to the Company’s consolidated statements of operations over the next twelve month period as these contracts expire, consisting of $0.7 million of losses primarily to gas and oil production revenues, $4.0 million of losses to gathering, transmission and processing revenues, and $0.2 million of gains to interest expense. Aggregate losses of $4.6 million will be reclassified to the Company’s consolidated statements of operations in later periods as these remaining contracts expire, consisting of $1.0 million of losses to gas and oil production revenues, $3.9 million of losses to gathering, transmission and processing revenues, and $0.2 million of gains to interest expense. Actual amounts that will be reclassified will vary as a result of future price changes.

Atlas Energy

     Commodity Risk Hedging Program — ATN enters into natural gas and crude oil future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in natural gas prices and oil prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts

25

with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

     At September 30, 2008, ATN had 693 natural gas and 165 crude oil futures contracts related to natural gas and oil sales covering 145 million MMbtus and 346,000 Bbls of natural gas and crude oil, respectively, maturing through June 30, 2013 at a combined average settlement price of $8.29 per MMBtu and $97.61 per Bbl, respectively.

     ATN has a $5.6 million unrealized net liability related to financial hedges on its gas and oil production shown as a component of accumulated other comprehensive loss at September 30, 2008. If the fair values of the instruments remain at current market values, ATN will reclassify $16.5 million of unrealized gains to its consolidated statements of income over the next twelve-month period as these contracts settle and $22.1 million of unrealized losses will be reclassified in later periods.

     ATN recognized a loss of $27.2 million and a gain of $4.9 million of ($27.2) million and $4.9 million for the three months ended September 30, 2008 and 2007, respectively, and a loss of $25.6 million and a gain of $9.6 million for the nine months ended September 30, 2008 and 2007, respectively, on settled contracts covering natural gas production. ATN recognized losses of $380,000 and $412,000 on settled oil production for the three months and nine months ended September 30, 2008. There were no gains or losses on oil settlements for the three months and nine months ended September 30, 2007. As the underlying prices and terms in ATN’s hedge contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three months and nine months ended September 30, 2008 and 2007 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

     In May 2007, ATN signed a definitive agreement to acquire AGO (see Note 3). In connection with the financing of this transaction, ATN agreed as a condition precedent to closing that it would hedge 80% of its projected natural gas volumes for no less than three years from the closing date of the transaction. During May 2007, ATN entered into derivative instruments to hedge 80% of the projected production of the assets to be acquired as required under the financing agreement. The production volume of the assets to be acquired was not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives ere entered into because the acquisition of the assets had not yet been completed. Accordingly, ATN recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within revenues in its consolidated statements of income. ATN recognized non-cash income of $26.3 million related to the change in value of these derivatives from May 22, 2007 through June 28, 2007. Upon closing of the acquisition on June 29, 2007, the production volume of the assets acquired was considered “probable forecasted production” under SFAS No. 133, and ATN evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133.

     As of September 30, 2008, ATN had the following natural gas and oil volumes hedged:

Natural Gas Fixed Price Swaps

Production
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset/(Liability)
	(MMbtu)		(per MMbtu)		(in thousands) (1)
2008		9,890,000	$	8.87	$	13,683
2009		45,060,000	$	8.56		16,077
2010		33,660,000	$	8.14		(11,620	)
2011		25,980,000	$	7.91		(11,840	)

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Production
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset/(Liability)
	(MMbtu)		(per MMbtu)		(in thousands) (1)
2012		17,440,000	$	8.13		(4,196	)
2013		1,500,000	$	8.73		443
					$	2,547

Natural Gas Costless Collars

Production
Period Ending				Average		Fair Value
December 31,	Option Type	Volumes		Floor and Cap		Asset/ (Liability)
		(MMbtu)		(per MMbtu)		(in thousands)(1)
2008	Puts purchased		390,000	$	7.50	$	80
2008	Calls sold		390,000	$	9.40		—
2009	Puts purchased		240,000	$	11.00		714
2009	Calls sold		240,000	$	15.35		—
2010	Puts purchased		3,120,000	$	7.92		—
2010	Calls sold		3,120,000	$	9.10		(604	)
2011	Puts purchased		7,200,000	$	7.50		—
2011	Calls sold		7,200,000	$	8.45		(3,804	)
2012	Puts purchased		720,000	$	7.00		—
2012	Calls sold		720,000	$	8.37		(468	)
						$	(4,082	)

Crude Oil Fixed Price Swaps

Production
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset/ (Liability)
	(Bbl)		(per Bbl)		(in thousands) (2)
2008		22,400	$	103.67	$	47
2009		58,900	$	99.92		(148	)
2010		48,900	$	97.31		(344	)
2011		40,400	$	96.43		(327	)
2012		33,500	$	96.00		(280	)
2013		9,000	$	95.95		(75	)
					$	(1,127	)

Crude Oil Costless Collars

Production
Period Ending				Average		Fair Value
December 31,	Option Type	Volumes		Floor and Cap		Asset/ (Liability)
		(Bbl)		(per Bbl)		(in thousands)(2)
2008	Puts purchased		10,500	$	85.00	$	2
2008	Calls sold		10,500	$	126.44		—
2009	Puts purchased		36,500	$	85.00		—
2009	Calls sold		36,500	$	118.63		(86	)
2010	Puts purchased		31,000	$	85.00		—
2010	Calls sold		31,000	$	112.92		(190	)

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Production
Period Ending				Average		Fair Value
December 31,	Option Type	Volumes		Floor and Cap		Asset/ (Liability)
		(Bbl)		(per Bbl)		(in thousands)(2)
2011	Puts purchased		27,000	$	85.00		—
2011	Calls sold		27,000	$	110.81		(196	)
2012	Puts purchased		21,500	$	85.00		—
2012	Calls sold		21,500	$	110.06		(165	)
2013	Puts purchased		6,000	$	85.00		—
2013	Calls sold		6,000	$	110.09		(47	)
						$	(682	)
Total ATN net derivative liability						$	(3,344	)

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

     Interest Rate Risk Hedging Program — At September 30, 2008, ATN had debt outstanding of $462.0 million under its revolving credit facility. During the nine months ended September 30, 2008, ATN entered into hedging arrangements 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 133. Using the change in variable cash flow method, no hedge ineffectiveness was identified. The value of ATN’s cash flow hedges included in accumulated other comprehensive income was a net unrecognized gain of approximately $961,000 at September 30, 2008. ATN recognized losses on settled swaps of $0.3 million for both the three months and nine months ended September 30, 2008. ATN did not enter into any interest rate swaps in the three months or nine months ended September 30, 2007.

     Atlas Pipeline Holdings and Atlas Pipeline Partners.On July 1, 2008, APL elected to discontinue 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 will be recognized immediately within other income (loss) in the Company’s consolidated statements of operations. The fair value of these commodity derivative instruments at June 30, 2008, which was recognized in accumulated other comprehensive loss within partners’ capital 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 transaction affects earnings.

     During June and July 2008, APL made net payments of $264.0 million related to the early termination of crude oil derivative contracts that it entered into as proxy hedges for the prices received on the ethane and propane portion of its NGL equity volume. These derivative contracts were put into place simultaneously with 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 nine months ended September 30, 2008, the Company recognized the following derivative activity related to APL’s termination of these derivative instruments (amounts in thousands):

	Early Termination of Derivative Contracts
	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2008			2007		2008			2007
Net cash derivative expense included within gain (loss) on mark-to-market derivatives on the Company’s consolidated statements of operations	$	(70,258	)	$	—	$	(186,068	)	$	—

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	Early Termination of Derivative Contracts
	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2008			2007		2008			2007
Net cash derivative expense included within transmission, gathering and processing revenue on the Company’s consolidated statements of operations		(1,258	)		—		(1,573	)		—
Net non-cash derivative income (expense) included within gain (loss) on mark-to-market, net on the Company’s consolidated statements of operations		6,488			—		(39,857	)		—
Net non-cash derivative expense included within transmission, gathering and processing revenue on the Company’s consolidated statements of operations		(19,514	)		—		(19,514	)		—

     At September 30, 2008, 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 7), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. This derivative effectively converts $25.0 million of AHD’s floating rate debt under the revolving credit facility to fixed-rate debt. The interest rate swap agreement began on May 30, 2008 and expires on May 28, 2010.

     At September 30, 2008, APL has interest rate derivative contracts having aggregate notional principal amounts of $450.0 million, which were designated as cash flow hedges. 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 (see Note 7), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. These derivatives effectively convert $450.0 million of APL’s floating rate debt under its term loan and revolving credit facility to fixed-rate debt. The APL interest rate swap agreements are effective as of September 30, 2008 and expire during periods ranging from January 30, 2010 through April 30, 2010.

     On June 3, 2007, APL signed definitive agreements to acquire control of the Chaney Dell and Midkiff/Benedum systems (see Note 3). In connection with certain additional agreements entered into to finance this transaction, APL agreed as a condition precedent to closing that it would hedge 80% of its projected natural gas, NGL and condensate production volume for no less than three years from the closing date of the transaction. During June 2007, APL entered into derivative instruments to hedge 80% of the projected production of the Anadarko Assets to be acquired as required under the financing agreements. The production volume of the Anadarko Assets to be acquired was not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition of the Anadarko Assets had not yet been completed. Accordingly, APL recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within gain (loss) on mark-to-market derivatives in the Company’s consolidated statements of operations. The Company recognized a non-cash loss of $18.8 million related to the change in value of derivatives entered into specifically for the Chaney Dell and Midkiff/Benedum systems from the time the derivative instruments were entered into to the date of closing of the acquisition during the year ended December 31, 2007. Upon closing of the acquisition in July 2007, the production volume of the Anadarko Assets acquired was considered “probable forecasted production” under SFAS No. 133. APL designated many of these instruments as cash flow hedges and evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Loss from cash settlement of qualifying hedge instruments(1)	$	(27,419	)	$	(12,850	)	$	(78,214	)	$	(23,548	)
Gain/(loss) from change in market value of non-qualifying derivatives(2)		(190,013	)		(15,595	)		17,919			(35,731	)
Gain/(loss) from change in market value of ineffective portion of qualifying derivatives(2)		(44,997	)		7,164			(41,271	)		(3,526	)
Loss from cash settlement of non-qualifying derivatives(2)		(84,207	)		(3,037	)		(280,696	)		(3,037	)
Loss from cash settlement of interest rate derivatives(3)		(708	)		—			(915	)		—

(1)	Included within transmission, gathering and processing revenue on the Company’s consolidated statements of operations.
(2)	Included within gain (loss) on mark-to-market derivatives, net on the Company’s consolidated statements of operations.
(3)	Included within interest expense on the Company’s consolidated statements of operations.

     As of September 30, 2008, AHD had the following interest rate derivatives:

     Interest Fixed-Rate Swap

	Notional			Contract Period	Fair Value
Term	Amount		Type	Ended December 31,	Asset/(Liability)(1)
					(in thousands)
May 2008-May 2010	$	25,000,000	Pay 3.01% —Receive LIBOR	2008	$	46
				2009		(4	)
				2010		40
Total AHD net derivative asset					$	82

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

     As of September 30, 2008, APL had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

     Interest Fixed-Rate Swap

	Notional			Contract Period		Fair Value
Term	Amount		Type	Ended December 31,		Asset/(Liability)(1)
						(in thousands)
January 2008-January 2010	$	200,000,000	Pay 2.88% —Receive LIBOR	2008	��	$	413
				2009			238
				2010			65
						$	716
April 2008-April 2010	$	250,000,000	Pay 3.14% —Receive LIBOR	2008		$	365
				2009			(339	)
				2010			197
						$	223

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     Natural Gas Liquids Sales — Fixed Price Swaps

Production Period			Average		Fair Value
Ended December 31,	Volumes		Fixed Price		Liability(2)
	(gallons)		(per gallon)		(in thousands)
2008		7,434,000	$	0.697	$	(3,642	)
2009		8,568,000	$	0.746		(3,607	)
					$	(7,249	)

     Crude Oil Sales Options (associated with NGL volume)

Production Period			Associated		Average
Ended	Crude		NGL		Crude		Fair Value
December 31,	Volume		Volume		Strike Price		Asset/(Liability)(3)			Option Type
	(barrels)		(gallons)		(per barrel)		(in thousands)
2008		536,400		29,972,124	$	70.16	$	110		Puts purchased
2008		126,000		11,219,040	$	127.55		(3,531	)	Puts sold(4)
2008		126,000		11,219,040	$	140.00		65		Calls purchased(4)
2008		473,400		25,764,984	$	80.13		(10,104	)	Calls sold
2009		1,584,000		85,038,534	$	80.00		2,372		Puts purchased
2009		304,200		27,085,968	$	126.05		(9,082	)	Puts sold(4)
2009		304,200		27,085,968	$	143.00		1,026		Calls purchased(4)
2009		2,121,600		114,072,336	$	81.01		(51,161	)	Calls sold
2010		3,127,500		202,370,490	$	81.09		(90,981	)	Calls sold
2010		714,000		45,415,440	$	120.00		8,966		Calls purchased(4)
2011		606,000		32,578,560	$	95.56		(13,597	)	Calls sold
2011		252,000		13,547,520	$	120.00		3,462		Calls purchased(4)
2012		450,000		24,192,000	$	97.10		(9,981	)	Calls sold
2012		180,000		9,676,800	$	120.00		2,629		Calls purchased(4)
							$	(169,807	)

     Natural Gas Sales — Fixed Price Swaps

Production Period			Average		Fair Value
Ended December 31,	Volumes		Fixed Price		Asset/(Liability)(3)
	(mmbtu)(5)		(per mmbtu)(5)		(in thousands)
2008		1,371,000	$	8.823	$	1,722
2009		5,724,000	$	8.611		2,667
2010		4,560,000	$	8.526		(269	)
2011		2,160,000	$	8.270		(583	)
2012		1,560,000	$	8.250		(251	)
					$	3,286

Natural Gas Basis Sales

Production Period			Average			Fair Value
Ended December 31,	Volumes		Fixed Price			Asset(3)
	(mmbtu)(5)		(per mmbtu)(5)			(in thousands)
2008		1,371,000	$	(0.744	)	$	2,042
2009		5,724,000	$	(0.558	)		1,599
2010		4,560,000	$	(0.622	)		732
2011		2,160,000	$	(0.664	)		217
2012		1,560,000	$	(0.601	)		97
						$	4,687

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     Natural Gas Purchases — Fixed Price Swaps

Production Period			Average			Fair Value
Ended December 31,	Volumes		Fixed Price			Asset/(Liability)(3)
	(mmbtu)(5)		(per mmbtu)(5)			(in thousands)
2008		4,065,000	$	8.274	(6)	$	(5,622	)
2009		15,564,000	$	8.680			(8,329	)
2010		8,940,000	$	8.580			196
2011		2,160,000	$	8.270			583
2012		1,560,000	$	8.250			251
						$	(12,921	)

     Natural Gas Basis Purchases

Production Period			Average			Fair Value
Ended December 31,	Volumes		Fixed Price			Liability(3)
	(mmbtu)(5)		(per mmbtu)(5)			(in thousands)
2008		4,065,000	$	(1.114	)	$	(6,761	)
2009		15,564,000	$	(0.654	)		(5,362	)
2010		8,940,000	$	(0.600	)		(2,118	)
2011		2,160,000	$	(0.700	)		(50	)
2012		1,560,000	$	(0.610	)		(49	)
						$	(14,340	)

     Ethane Put Options

Production Period	Associated		Average
Ended	NGL		Crude		Fair Value
December 31,	Volume		Strike Price		Asset(2)		Option Type
(gallons)			(per gallon)		(in thousands)
2008		7,560,000	$	0.7885	$	399	Puts purchased
2009		16,254,000	$	0.6928		196	Puts purchased
					$	595

     Propane Put Options

Production Period	Associated		Average
Ended	NGL		Crude		Fair Value
December 31,	Volume		Strike Price		Asset(2)		Option Type
	(gallons)		(per gallon)		(in thousands)
2008		8,946,000	$	1.4752	$	174	Puts purchased
2009		23,310,000	$	1.3935		368	Puts purchased
					$	542

     Crude Oil Sales

Production Period			Average		Fair Value
Ended December 31,	Volumes		Fixed Price		Liability(3)
	(barrels)		(per barrel)		(in thousands)
2008		14,100	$	60.569	$	(563	)
2009		33,000	$	62.700		(1,305	)
					$	(1,868	)

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     Crude Oil Sales Options

Production Period			Average		Fair Value
Ended December 31,	Volumes		Strike Price		Asset/(Liability)(3)			Option Type
	(barrels)		(per barrel)		(in thousands)
2008		69,000	$	68.000	$	10		Puts purchased
2008		69,000	$	78.055		(1,589	)	Calls sold
2009		168,000	$	90.000		253		Puts purchased
2009		306,000	$	80.017		(13,525	)	Calls sold
2010		234,000	$	83.027		(9,382	)	Calls sold
2011		72,000	$	87.296		(1,938	)	Calls sold
2012		48,000	$	83.944		(1,380	)	Calls sold
					$	(27,551	)
Total APL net derivative liability					$	(223,687	)
Total Company net derivative liability					$	(226,949	)

(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)	Puts sold and calls purchased in 2008 and 2009 represent costless collars entered into by APL as offsetting positions for the calls sold related to ethane and propane production. In addition, calls were purchased by APL for 2010 through 2012 to offset 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.
(5)	Mmbtu represents million British Thermal Units.
(6)	Includes APL’s premium received from its sale of an option for it to sell 234,000 mmbtu of natural gas for the year ended December 31, 2008 at $18.00 per mmbtu.

NOTE 9 — FAIR VALUE OF FINANCIAL INSTRUMENTS

     The Company adopted the provisions of SFAS No. 157 at January 1, 2008. 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.

     The Company uses 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 commodity hedges and interest rate swaps (see Note 8) 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 crude oil collars, are calculated based on observable market data related to the change in price of the underlying commodity and

33

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. 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 accordance with SFAS No. 157, the following table represents the Company’s assets and liabilities recorded at fair value as of September 30, 2008 (in thousands):

	Level 1		Level 2			Level 3			Total
SERP liability	$	—	$	(3,132	)	$	—		$	(3,132	)
Interest rate swap-based derivatives		—		1,982			—			1,982
APL commodity-based derivatives		—		(21,154	)		(203,472	)		(224,626	)
ATN commodity-based derivatives		—		(3,344	)		—			(3,344	)
Total	$	—	$	(25,648	)	$	(203,472	)	$	(229,120	)

     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 September 30, 2008 (in thousands):

				Crude Oil
				Sales Options
	NGL Fixed			(assoc. with			Crude Oil
	Price Swaps			NGL Volume)			Sales Options			Total
Balance — December 31, 2007	$	(33,624	)	$	(24,740	)	$	(145,418	)	$	(203,782	)
New options contracts		—			262			7,134			7,396
Cash settlements from unrealized gain (loss)		(168	)		1,871			254,511			256,214
Cash settlements from other comprehensive income (1)		27,057			10,664			83,645			121,366
Net change in unrealized gain (loss) (2)		8,173			19,831			(219,637	)		(191,633	)
Deferred option premium recognition		—			228			403			631
Net change in other comprehensive loss		(8,687	)		(35,667	)		(149,310	)		(193,664	)
Balance — September 30, 2008	$	(7,249	)	$	(27,551	)	$	(168,672	)	$	(203,472	)

(1)	Included within transmission, gathering and processing revenue revenue on the Company’s consolidated statements of operations.
(2)	Included within gain (loss) on mark-to-market derivatives on the Company’s consolidated statements of operations.

NOTE 10 — 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, energy limited partnerships (“Investment Partnerships”). ATN serves as general partner of the Investment Partnerships and assumes customary rights and obligations for the Investment Partnerships. As the general partner, ATN is liable for the Investment Partnerships’ liabilities and can be liable to limited partners if it breaches its responsibilities with respect to

34

the operations of the Investment Partnerships. ATN is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Investment Partnerships’ revenue, and costs and expenses according to the respective Investment Partnership agreements.

     Relationship with Resource America, Inc.In June 2005, Resource America, Inc. (“RAI”) completed its spin-off of the Company. The Company reimburses RAI for various costs and expenses it incurs on behalf of the Company, primarily payroll and rent. For the three months ended September 30, 2008 and 2007, these costs totaled $255,000 and $246,000, respectively, and for the nine months ended September 30, 2008 and 2007, these costs totaled $689,000 and $775,000, respectively.

     As of September 30, 2008 and December 31, 2007, certain operating expenditures totaling $105,000 and $58,000, respectively, which remain to be settled between the Company and RAI, are reflected in the Company’s consolidated balance sheets as advances from affiliate.

NOTE 11 — 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 ATN, 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 Company 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.

     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 September 30, 2008, the Company is committed to expend approximately $153.9 million on pipeline extensions, compressor station upgrades, and processing facility upgrades.

Legal Proceedings

     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 the Company 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. ATN acted in good faith and believes that the outcome of the litigation will be resolved in its favor.

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

NOTE 12 — 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

35

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.

     The Company adopted the provisions of FASB Interpretation 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”) on January 1, 2007. As required by FIN 48, which clarifies SFAS 109, 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. At the adoption date, the Company applied FIN 48 to all tax positions for which the statute of limitation remained open. During the quarter ended September 30, 2008, there were no additions, reductions or settlements in unrecognized tax benefits. The Company has no material uncertain tax positions and the implementation of FIN 48 did not have a significant impact on the consolidated financial statements of the Company.

     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 2004. 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 13 — COMMON STOCK

Stock Repurchase Plan

     On September 9, 2008, the Company’s Board of Directors approved a stock repurchase agreement 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 442,586 of its shares during September 2008 for a total price of $14.9 million under this program. In addition, the Company utilized the remaining $20.0 million of availability under a stock repurchase agreement approved on September 12, 2005 to purchase 560,291 shares in August and September 2008. The average price for the shares purchased during the quarter was $34.76 per share (see Item 2).

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 nine months ended September 30, 2008 and 2007 in the accompanying financial statements and notes to the consolidated financial statements to reflect this split.

     On April 27, 2007, 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 15, 2007 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 25, 2007. Information pertaining

36

to shares and earnings per share has been restated for the three and nine months ended September 30, 2007 in the accompanying financial statements and notes to the consolidated financial statements to reflect this split.

Dutch Auction Tender Offer

     On January 30, 2007, the Company announced that the Board of Directors had authorized a “Dutch Auction” tender offer for up to 1,950,000 shares of the Company’s common stock at an anticipated offer range of between $52.00 and $54.00 per share. The tender offer commenced on February 8, 2007 and expired on March 9, 2007. In connection with this offering, the Company purchased 1,486,605 shares at a cost of $80.4 million, including expenses.

NOTE 14 — 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”). 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 crude oil derivative agreements (see Note 8).

     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 was recorded in consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $26.4 million to minority interest, during the nine months ended September 30, 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.

     In July 2007, APL sold 25,568,175 common units through a private placement to investors at a negotiated purchase price of $44.00 per unit, yielding net proceeds of approximately $1.125 billion. Of the 25,568,175 common units sold by APL, 3,835,227 common units were purchased by AHD for $168.8 million. APL also received a capital contribution from AHD of $23.1 million for AHD to maintain its 2.0% general partner interest in APL. AHD funded this capital contribution and other transaction costs through borrowings under its revolving credit facility of $25.0 million. APL utilized the net proceeds from the sale to partially fund the acquisition of control of the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and a 72.8% interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (see Note 3).

     In July 2007, AHD issued 6,249,995 common units (an approximate 27% interest in it) for net proceeds of $167.0 million after offering costs in a private placement offering. In addition, in July 2007 APL issued 25,568,175 common units through a private placement to investors, of which 3,835,227 common units were purchased by AHD. A gain of $53.0 million, net of an income tax provision of $34.3 million, in

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accordance with SAB 51 was recorded in consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $87.3 million to minority interest, during the year ended December 31, 2007.

     In June 2007, ATN issued 24,001,009 Class B common (an approximate 31% interest in ATN at that time) for net proceeds of $597.5 million after offering costs in a private placement offering. A gain of $147.9 million, net of an income tax provision of $87.5 million, in accordance with SAB 51 was recorded in consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $235.4 million to minority interest, during the year ended December 31, 2007.

NOTE 15 — CASH DISTRIBUTIONS

     Atlas Pipeline Partners Cash Distributions.APL is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders and AHD, as general partner. If APL’s common unit distributions in any quarter exceed specified target levels, AHD will receive between 15% and 50% of such distributions in excess of the specified target levels. Distributions declared by APL for the period from January 1, 2007 through September 30, 2008 were as follows:

		APL Cash		Total APL Cash
		Distribution		Distribution
Date Cash		per Common		to Common		Total APL Cash
Distribution	For Quarter	Limited		Limited		Distribution
Paid or Payable	Ended	Partner Unit		Partners		to AHD
				(in thousands)		(in thousands)
February 14, 2007	December 31, 2006	$	0.86	$	11,249	$	4,193
May 15, 2007	March 31, 2007	$	0.86	$	11,249	$	4,193
August 14, 2007	June 30, 2007	$	0.87	$	11,380	$	4,326
November 14, 2007	September 30, 2007	$	0.91	$	35,205	$	4,498
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(1)	September 30, 2008	$	0.96	$	44,105	$	9,312

(1) Declared subsequent to September 30, 2008 (see Note 19)

     In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 3), 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.

     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, 2007 through September 30, 2008 were as follows:

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Date Cash		Cash Distribution per		Total Cash
Distribution Paid	For Quarter	Common Limited		Distribution to the
or Payable	Ended	Partner Unit		Company (in thousands)
February 19, 2007	December 31, 2006	$	0.25	$	4,375
May 18, 2007	March 31, 2007	$	0.25	$	4,375
August 17, 2007	June 30, 2007	$	0.26	$	4,550
November 19, 2007	September 30, 2007	$	0.32	$	5,600
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(1)	September 30, 2008	$	0.51	$	9,082

(1) Declared subsequent to September 30, 2008 (see Note 19)

     Atlas Energy Resources Cash Distributions.Upon completion of its initial public offering, ATN adopted a cash distribution policy under which it distributes, within 45 days after the end of each quarter, all of its available cash (as defined in its limited liability agreement) for that quarter. Distributions declared by ATN and paid to the Company from inception are as follows:

		Cash
		Distribution			Total Cash		Manager
Date Cash		Per			Distribution		Incentive
Distribution	For Quarter	Common			to the		Distribution
Paid or Payable	Ended	Unit			Company		Earned(3)
					(in thousands)		(in thousands)
February 14, 2007	December 31, 2006	$	0.06	(1)	$	1,806	$	—
May 15, 2007	March 31, 2007	$	0.43		$	12,944	$	—
August 14, 2007	June 30, 2007	$	0.43		$	12,944	$	—
November 14, 2007	September 30, 2007	$	0.55		$	16,825	$	784
February 14 , 2008	December 31, 2007	$	0.57		$	17,437	$	965
May 15 , 2008	March 31, 2008	$	0.59		$	18,410	$	1,214
August 14 , 2008	June 30, 2008	$	0.61		$	19,060	$	1,687
November 14 , 2008(2)	September 30, 2008	$	0.61		$	19,060	$	1,687

(1)	Represents a pro-rated cash distribution of $0.42 per unit for the period from December 18, 2006, the date of ATN’s initial public offering, through December 31, 2006.
(2)	Declared subsequent to September 30, 2008 (see Note 19).
(3)	Payable to the Company in 2010, provided ATN meets certain criteria within its partnership agreements.

NOTE 16 — INVESTMENT IN LIGHTFOOT

     At September 30, 2008, the Company’s subsidiary, Atlas Lightfoot, LLC, had invested an aggregate $10.7 million in Lightfoot LP and owns, directly and indirectly, approximately 13% of Lightfoot LP, an entity of whom 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-

39

qualified such as infrastructure, coal, and other asset categories. The Company accounts for its investment in Lightfoot under the equity method of accounting.

NOTE 17 — BENEFIT PLANS

Incentive Bonus Plan

     The Company’s shareholders approved an Incentive Bonus Plan (“Bonus Plan”) in May 2007 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.

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. For the three and nine months ended September 30, 2007, the Company received $0.8 million and $0.9 million from the exercise of stock options, respectively. For both the three and nine months ended September 30, 2008, the Company received $0.3 million from the exercise of stock options.

     The following tables set forth the Plan activity for the three and nine months ended September 30, 2008 and 2007:

	Three Months Ended
	September 30,
	2008					2007
				Weighted					Weighted
	Number			Average		Number			Average
	of Unit			Exercise		of Unit			Exercise
	Options			Price		Options			Price
Outstanding, beginning of period		3,540,380		$	16.89		2,787,151		$	12.08
Granted		—			—		—			—
Matured		(28,155	)	$	11.32		(71,770	)	$	11.32
Forfeited		—			—		—			—

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	Three Months Ended
	September 30,
	2008				2007
			Weighted				Weighted
	Number		Average		Number		Average
	of Unit		Exercise		of Unit		Exercise
	Options		Price		Options		Price
Outstanding, end of period(1)(2)		3,512,225	$	16.94		2,715,381	$	12.10
Options exercisable, end of period		2,350,298	$	11.61		2,108,088	$	11.49
Non-cash compensation expense recognized (in thousands)	$	983			$	378

	Nine Months Ended
	September 30,
	2008					2007
				Weighted					Weighted
	Number			Average		Number			Average
	of Unit			Exercise		of Unit			Exercise
	Options			Price		Options			Price
Outstanding, beginning of period		2,715,380		$	12.10		2,766,432		$	11.82
Granted		825,000		$	32.68		30,000		$	35.82
Matured		(28,155	)	$	11.32		(81,051	)	$	11.32
Forfeited		—			—		—			—
Outstanding, end of period(1)(2)		3,512,225		$	16.94		2,715,381		$	12.10
Options exercisable, end of period(3)(4)		2,350,298		$	11.61		2,108,088		$	11.49
Non-cash compensation expense recognized (in thousands)	$	2,941				$	1,077

(1)	The weighted average remaining contractual lives for outstanding options at September 30, 2008 and 2007 were 7.6 years and 7.8 years, respectively.
(2)	The aggregate intrinsic values of options outstanding at September 30, 2008 and 2007 were approximately $60.3 million and $60.6 million, respectively.
(3)	The number of options available for grant at September 30, 2008 was 841,704.
(4)	The weighted average outstanding contractual life of exercisable options at September 30, 2008 is 6.8 years.

     The Company used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted during the three and nine months ended September 30, 2008 and 2007. The following weighted average assumptions were used (there were no options granted during both the three months ended September 30, 2008 and 2007:

	Nine Months Ended
	September 30,
	2008			2007
Expected dividend yield		0.4	%		0.4	%
Expected stock price volatility		33	%		35	%
Risk-free interest rate		2.6	%		4.7	%
Expected term (in years)		6.25			6.25
Fair value of stock options granted	$	11.75		$	15.08

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     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. 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 tables set forth the deferred and restricted units activity for the three and nine months ended September 30, 2008 and 2007:

	Three Months Ended
	September 30,
	2008					2007
				Weighted				Weighted
				Average				Average
	Number			Grant Date		Number		Grant Date
	of Units			Fair Value		of Units		Fair Value
Non-vested shares outstanding, beginning of period		12,083		$	23.60		20,676	$	14.20
Granted		397		$	37.69		438	$	34.25
Matured		(248	)	$	20.14		—		—
Forfeited		—			—		—		—
Non-vested shares outstanding, end of period		12,232		$	24.13		21,114	$	14.61

	Nine Months Ended
	September 30,
	2008					2007
				Weighted					Weighted
				Average					Average
	Number			Grant Date		Number			Grant Date
	of Units			Fair Value		of Units			Fair Value
Non-vested shares outstanding, beginning of period		21,114		$	14.61		26,967		$	10.61
Granted		1,920		$	46.87		3,221		$	27.93
Matured		(10,802	)	$	9.57		(9,074	)	$	7.43
Forfeited		—			—		—			—
Non-vested shares outstanding, end of period		12,232		$	24.13		21,114		$	14.61

     For the three months ended September 30, 2008 and 2007, the Company recorded non-cash compensation expense of $1.0 million and $0.4 million, respectively, for the Company’s options and units.

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For the nine months ended September 30, 2008 and 2007, the Company recorded non-cash compensation expense of $3.0 million and $1.1 million, respectively, for the Company’s options and units. At September 30, 2008, the Company had unamortized compensation expense related to its unvested portion of the options and units of $9.7 million that the Company expects to recognize over four years.

Employee Stock Ownership Plan

     In connection with the spin-off from RAI, the Company established an Employee Stock Ownership Plan (“ESOP”) in June 2005. The ESOP, which is a qualified non-contributory retirement plan, 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. These shares have been converted to the Company’s common stock from RAI stock in an even exchange. The Company loaned $602,000 (payable in quarterly installments of $18,508 plus interest at 7.5%) to the ESOP, which was used by the ESOP to acquire the remaining 40,375 unallocated shares of RAI common stock. Contributions to the ESOP are made at the discretion of the Company’s Board of Directors. The cost of shares purchased by the ESOP but not yet allocated to participants is shown as a reduction of stockholders’ equity. The unearned benefits expense (a reduction in stockholders’ equity) will be reduced by the amount of any loan principal payments made by the ESOP to the Company. 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 with the money borrowed is held by the ESOP trustee in a suspense account. On an annual basis, as the ESOP loan is paid down, a portion of the common stock will be released from the suspense account and allocated to participating employees. As of September 30, 2008, there were 497,735 shares allocated to participants and 47,655 shares which are unallocated. The fair value of unearned ESOP shares was $1.6 million at September 30, 2008.

Supplemental Employment Retirement Plan

     In May 2004, 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. For both the three months ended September 30, 2008 and 2007, expense recognized with respect to this commitment was $0.4 million, and the expense recognized for the nine months ended September 30, 2008 and 2007 was $1.1 million and $0.5 million, respectively. As of September 30, 2008, the present value of the expected postretirement obligation due under the SERP was $3.1 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):

	September 30,			December 31,
	2008			2007
Other liabilities	$	(3,132	)	$	(2,475	)
Accumulated other comprehensive loss		204			638
Deferred income tax asset		120			375
Net amount recognized	$	(2,808	)	$	(1,462	)

     The estimated amount that will be amortized from accumulated other comprehensive loss into expense for the year ended December 31, 2008 is $0.3 million.

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AHD Long-Term Incentive Plan

     AHD has a 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 September 30, 2008, AHD had 1,440,475 phantom units and unit options outstanding under the AHD LTIP, with 659,150 phantom units and unit options available for grant.

     AHD Phantom Units.A phantom unit entitles a Participant to receive a common unit of AHD, 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 September 30, 2008, 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 September 30, 2008, 675 units will vest within the following twelve months. All phantom units outstanding under the AHD LTIP at September 30, 2008 include DERs granted to the Participants by the AHD LTIP Committee. The amount paid with respect to the AHD LTIP DERs was $0.1 million for both the three months ended September 30, 2008 and 2007, and $0.3 million and $0.2 million for the nine months ended September 30, 2008 and 2007, respectively. This amount was recorded as an adjustment of minority 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				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
Outstanding, beginning of period		225,475		220,000		220,825		220,492
Granted(1)		—		—		4,650		—
Unit Adjustment		—		—		—		(492	)
Matured		—		—		—		—
Forfeited		—		—		—		—
Outstanding, end of period(2)		225,475		220,000		225,475		220,000
Non-cash compensation expense recognized (in thousands)	$	354	$	385	$	1,092	$	1,224

⁽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 nine months ended September 30, 2008. There were no grants of phantom units during the three months ended September 30, 2008 and 2007, and the nine months ended September 30, 2007.

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⁽²⁾ The aggregate intrinsic value for phantom unit awards outstanding as of September 30, 2008 was $5.4 million.

     At September 30, 2008, AHD had approximately $2.6 million of unrecognized compensation expense related to unvested phantom units outstanding under the AHD LTIP based upon the fair value of the awards.

     AHD Unit Options.A unit option entitles a Participant to receive a common unit of AHD upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of AHD’s common unit as determined by AHD’s LTIP Committee on the date of grant of the option. AHD’s LTIP Committee also shall determine how the exercise price may be paid by the Participant. AHD’s LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through September 30, 2008, unit options granted under AHD’s 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 AHD’s LTIP. There are no unit options outstanding under AHD’s LTIP at September 30, 2008 that will vest within the following twelve months. The following table sets forth the LTIP unit option activity for the periods indicated:

	Three Months Ended September 30,
	2008				2007
			Weighted				Weighted
	Number		Average		Number		Average
	of Unit		Exercise		of Unit		Exercise
	Options		Price		Options		Price
Outstanding, beginning of period		1,215,000	$	22.56		1,215,000	$	22.56
Granted		—		—		—		—
Matured		—		—		—		—
Forfeited		—		—		—		—
Outstanding, end of period(1)(2)		1,215,000	$	22.56		1,215,000	$	22.56
Options exercisable, end of period		—		—		—		—
Non-cash compensation expense recognized (in thousands)	$	309			$	309

	Nine Months Ended September 30,
	2008				2007
			Weighted				Weighted
	Number		Average		Number		Average
	of Unit		Exercise		of Unit		Exercise
	Options		Price		Options		Price
Outstanding, beginning of period		1,215,000	$	22.56		1,215,000	$	22.56
Granted		—		—		—		—
Matured		—		—		—		—
Forfeited		—		—		—		—
Outstanding, end of period(1)(2)		1,215,000	$	22.56		1,215,000	$	22.56

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	Nine Months Ended September 30,
	2008				2007
			Weighted				Weighted
	Number		Average		Number		Average
	of Unit		Exercise		of Unit		Exercise
	Options		Price		Options		Price
Options exercisable, end of period(3)		—		—		—		—
Non-cash compensation expense recognized (in thousands)	$	928			$	928

(1)	The weighted average remaining contractual life for outstanding options at September 30, 2008 was 8.1 years.
(2)	The aggregate intrinsic value of options outstanding at September 30, 2008 was approximately $1.9 million.
(3)	There were no options exercised during the three and nine months ended September 30, 2008 and 2007.

     At September 30, 2008, AHD had approximately $2.2 million of unrecognized compensation expense related to unvested unit options outstanding under AHD’s LTIP based upon the fair value of the awards.

APL Long-Term Incentive Plan

     APL has a Long-Term Incentive Plan (“APL LTIP”), in which officers, employees and non-employee managing board members of the General Partner and employees of the General Partner’s affiliates and consultants are eligible to participate. The APL LTIP is administered by a committee (the “APL LTIP Committee”) appointed by AHD’s managing board. The APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 435,000 common units. Only phantom units have been granted under the APL LTIP through September 30, 2008.

     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 September 30, 2008, 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 September 30, 2008, 55,103 units will vest within the following twelve months. All units outstanding under the APL LTIP at September 30, 2008 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL LTIP DERs were $0.1 million and $0.2 million for the three month periods ended September 30, 2008 and 2007, respectively, and $0.4 million and $0.5 million for the nine month periods ended September 30, 2008 and 2007, respectively. These amounts were recorded as reductions of minority 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						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Outstanding, beginning of period		149,923			184,162			129,746			159,067
Granted(1)		—			—			54,296			25,095
Matured(2)		(10,860	)		(38,401	)		(44,229	)		(38,401	)

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	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Forfeited		(1,000	)		(1,000	)		(1,750	)		(1,000	)
Outstanding, end of period(3)		138,063			144,761			138,063			144,761
Non-cash compensation expense recognized (in thousands)	$	600		$	592		$	1,783		$	2,466

(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 $44.43 and $50.09 for awards granted for the nine months ended September 30, 2008 and 2007, respectively. There were no awards granted for the three months ended September 30, 2008 and 2007, respectively.
(2)	The intrinsic values for phantom unit awards exercised during the three months ended September 30, 2008 and 2007, were approximately $0.4 million and $2.0 million, respectively, and $1.8 million and $2.0 million during the nine months ended September 30, 2008 and 2007, respectively.
(3)	The aggregate intrinsic value for phantom unit awards outstanding as of September 30, 2008 was $3.5 million.

     At September 30, 2008, APL had approximately $2.7 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIP based upon the fair value of the awards.

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 estimated to be issued under the incentive compensation agreements will be determined principally by the financial performance of certain APL assets for 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.

     APL recognized a reduction of compensation expense of $13.3 million and $31.2 million for the three months ended September 30, 2008 and 2007, respectively, and $16.1 million and $33.6 million for the nine months ended September 30, 2008 and 2007, respectively, related to the vesting of awards under these incentive compensation agreements. The non-cash compensation expense adjustments for the nine months ended September 30, 2008 were principally attributable to changes in APL’s common unit market price, which is utilized in the estimation of its non-cash compensation expense for these awards, at September 30, 2008 when compared with APL’s price at earlier periods and adjustments based upon the achievement of actual financial performance targets through September 30, 2008. The vesting period for such awards concluded on September 30, 2007. APL’s Management anticipates that adjustments will be recorded in future periods with respect to the awards under the incentive compensation agreements based upon the actual financial performance of the assets in future periods in comparison to their estimated performance and the movement in the market value of APL’s common units. Based upon APL’s management’s estimate of the probable outcome of the performance targets at September 30, 2008, 924,978 common unit awards are ultimately expected to be issued under these agreements during the year ended December 31, 2009, which represents the total amount of common units expected to be issued under the incentive compensation agreements. APL follows SFAS No. 123(R) and recognized compensation expense related to these awards based upon the fair value method.

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ATN 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 ATN LTIP is administered by its compensation committee, which may grant awards of either restricted stock units, phantom units or unit options for an aggregate of 3,742,000 common units. Awards granted vest 25% after three years and 100% upon the four year anniversary of grant, except for awards granted to board members which 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 restricted 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, 35,793 units of restricted stock and phantom units were awarded in the nine months ended September 30, 2008. 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 nine months ended September 30, 2008:

				Weighted
				Average
				Grant Date
	Units			Fair Value
Non-vested shares outstanding at December 31, 2007		624,665		$	24.42
Granted		35,793			31.62
Vested		(12,279	)		21.06
Forfeited		(100	)		35.00
Non-vested shares outstanding at September 30, 2008		648,079		$	24.88

     Stock Options. In the nine months ended September 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 common units at the date of grant. ATN uses the Black-Scholes option pricing model to estimate the weighted average fair value per option granted with the following assumptions:

	Assumptions
	Grant Date			Grant Date
	June 2008			January 2008
Options granted		7,500			6,500
Expected life (years)		6.25			6.25
Expected volatility		34	%		27	%
Risk-free interest rate		4.0	%		2.8	%
Expected dividend yield		6.2	%		7.0	%
Weighted average fair value of stock options granted	$	7.66		$	3.41

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     The following table sets forth option activity for the nine months ended September 30, 2008:

						Weighted
						Average
				Weighted		Remaining		Aggregate
				Average		Contractual		Intrinsic
				Exercise		Term		Value
	Shares			Price		(in years)		(in thousands)
Outstanding at December 31, 2007		1,895,052		$	24.09		8.9
Granted		14,000		$	35.36
Exercised		—			—
Forfeited or expired		(4,850	)	$	26.75
Outstanding at September 30, 2008		1,904,202		$	24.17		8.2	$	3,102
Options exercisable at September 30, 2008		93,438		$	21.00		7.5
Available for grant at September 30, 2008		1,165,536

     ATN recognized $1.4 million and $1.3 million in compensation expense related to restricted stock units, phantom units and stock options for the three months ended September 30, 2008 and 2007, respectively. ATN recognized $4.0 million and $3.4 million in related compensation expense for the nine months ended September 30, 2008 and 2007, respectively. ATN paid $0.4 million and $0.2 million with respect to its LTIP DERs for the three months ended September 30, 2008 and 2007, respectively, and $1.0 million and $0.5 million with respect to its LTIP DER’s for the nine months ended September 30, 2008 and 2007, respectively. These amounts were recorded as a reduction of minority interest on the Company’s consolidated balance sheets. At September 30, 2008, ATN had approximately $13.0 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 September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Gas and oil production
Revenues(a)	$	81,235		$	63,265		$	236,417		$	136,097
Costs and expenses		(12,688	)		(9,887	)		(35,735	)		(14,412	)
Segment income	$	68,547		$	53,378		$	200,682		$	121,685
Well construction and completion
Revenues	$	116,987		$	103,324		$	343,466		$	240,841
Costs and expenses		(101,727	)		(89,847	)		(298,666	)		(209,427	)
Segment income	$	15,260		$	13,477		$	44,800		$	31,414
Atlas Pipeline
Revenues (b)	$	567,032		$	231,257		$	991,695		$	427,792
Revenues — affiliates		12,021			8,610			32,768			24,821
Costs and expenses		(338,338	)		(187,390	)		(1,002,861	)		(377,669	)
Segment income	$	240,715		$	52,477		$	21,602		$	74,944
Other(c)
Revenues	$	3,380		$	5,070		$	13,116		$	11,756
Costs and expenses		(2,890	)		(2,541	)		(8,206	)		(6,776	)
Segment income	$	490		$	2,529		$	4,910		$	4,980
Reconciliation of segment income to net income before income tax provision
Segment income
Gas and oil production	$	68,547		$	53,378		$	200,682		$	121,685
Well construction and completion		15,260			13,477			44,800			31,414

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Atlas Pipeline		240,715			52,477			21,602			74,944
Other		490			2,529			4,910			4,980
Total segment income		325,012			121,861			271,994			233,023
General and administrative expenses		(13,278	)		(48,677	)		(59,633	)		(84,454	)
Net expense reimbursement — affiliate		(255	)		(246	)		(689	)		(775	)
Depreciation, depletion and amortization		(46,134	)		(35,187	)		(142,910	)		(61,064	)
Interest expense		(37,079	)		(37,480	)		(105,487	)		(53,681	)
Minority interest income (expense)		(194,054	)		6,402			60,777			14,992
Other income — net		3,815			3,526			11,838			6,425
Net income before income tax provision	$	38,027		$	10,199		$	35,890		$	54,466
Capital expenditures
Gas and oil production	$	89,434		$	68,768		$	219,953		$	122,049
Well construction and completion		—			—			—			—
Atlas Pipeline		89,124			34,544			246,394			76,428
Corporate and other		1,182			1,578			3,038			3,379
Total capital expenditures	$	179,740		$	104,890		$	469,385		$	201,856

	September 30,		December 31,
	2008		2007
Balance sheet
Goodwill
Gas and oil production	$	21,527	$	21,527
Well construction and completion		6,389		6,389
Atlas Pipeline		676,860		709,283
Corporate and other		7,250		7,250
	$	712,026	$	744,449
Total assets
Gas and oil production	$	2,002,268	$	1,821,631
Well construction and completion		13,854		11,138
Atlas Pipeline		3,056,762		2,877,614
Corporate and other		178,546		193,984
	$	5,251,430	$	4,904,367

(a)	Revenues for the nine months ended September 30, 2007 include non-cash gains of $26.3 million related to non-qualifying hedges associated with the acquisition of AGO (see Note 3).
(b)	Includes gain (loss) on mark-to-market derivatives of $147.5 million and $14.8 million for the three months ended September 30, 2008 and 2007, respectively, and ($257.3) million and ($16.0) million for the nine months ended September 30, 2008 and 2007, respectively.
(c)	Includes revenues and expenses from well services, transportation and administration and oversight that do not meet the quantitative threshold for reporting segment information for the three and nine months ended September 30, 2008 and 2007, respectively.

     Operating profit (loss) per segment represents total revenues less costs and expenses attributable thereto, excluding interest, provision for possible losses and depreciation, depletion and amortization, minority interests and general corporate expenses.

NOTE 19 — SUBSEQUENT EVENTS

     On October 29, 2008, the Company’s Board of Directors declared a cash dividend of $0.05 per share, payable on November 19, 2008 to shareholders of record on November 10, 2008.

     On October 29, 2008, ATN declared a quarterly cash distribution of $0.61 per unit on its outstanding common units, representing the cash distribution for the quarter ended September 30, 2008. This distribution is payable on November 14, 2008 to unitholders of record on November 10, 2008.

     On October 27, 2008, APL declared a quarterly cash distribution of $0.96 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2008. The $53.4 million distribution, including $9.3 million to AHD for its general partner interest after the allocation of $5.0 million of its incentive distribution rights back to APL, will be paid on November 14, 2008 to unitholders of record at the close of business on November 10, 2008.

     On October 27, 2008, AHD declared a quarterly cash distribution of $0.51 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2008. This distribution is payable on November 19, 2008 to unitholders of record on November 10, 2008.

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

Forward-Looking Statements

     When used in thisForm 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 onForm 10-K for 2007. 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 thisForm 10-Q or to reflect the occurrence of unanticipated events.

     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.

General

     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 and the Appalachian Basin, which we manage through our subsidiary, Atlas Energy Management, Inc., under the supervision of ATN’s board of directors;

• Atlas Pipeline Partners, L.P. (“Atlas Pipeline Partners” or “APL”), a midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachia regions (NYSE: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 our ownership of its general partner, we manage AHD; and

• Lightfoot Capital Partners LP (“Lightfoot LP”) and Lightfoot Capital Partners GP, LLC, (“Lightfoot GP”) the general partner of Lightfoot (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. We have an approximate direct and indirect 18% ownership interest in Lightfoot GP 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 L.P.

     Our ownership interest in ATN consists of the following:

• all of the outstanding Class A units, representing 1,293,486 units at September 30, 2008, 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

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	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, including 600,000 purchased in May 2008 in a private placement, representing approximately 47.3% of the outstanding common units at September 30, 2008, 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 must:

• 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.

     Our ownership interest in APL consists of 1,112,000 common units, purchased in June 2008 in a private placement transaction, representing approximately 2.4% of the outstanding common units of APL at September 30, 2008, or a 2.3% ownership interest (see “Recent Developments”).

     Our ownership interest in AHD consists of 17,808,109 common units, including 308,109 purchased in a June 2008 private placement, representing approximately 64.4% of the outstanding common units of AHD at September 30, 2008. 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. In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems, 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. 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 (“IDR Adjustment Agreement”); and

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• 5,754,253 common units, representing approximately 12.5% of the outstanding common units at September 30, 2008, or a 12.3% ownership interest in APL.

     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 principally through ATN, AHD, and APL, and our cash flows consist primarily of distributions received from ATN and AHD on our partnership 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 minority interests in ATN, AHD and APL are reflected as income (expense) in our consolidated statements of operations and as a liability on our consolidated balance sheet. 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 minority interests in ATN’s, AHD’s and APL’s net income (loss).

Atlas Energy

     ATN was formed in December 2006 through our contribution of substantially all of our natural gas and oil assets and our investment partnership management business to it in connection with ATN’s initial public offering. ATN is an independent developer and producer of natural gas and oil, with operations in northern Michigan’s Antrim Shale and the Appalachian Basin region of the United States, principally in western New York, eastern Ohio, western Pennsylvania and Tennessee. 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.

     ATN had the following key assets at September 30, 2008:

     Gas and oil operations

• direct and indirect working interests in over 11,400 gross producing gas and oil wells;

• net average daily production of 94.2 million cubic feet equivalents (“MMcfe”) per day for the nine months ended September 30, 2008; and

• over 1.2 million net acres, of which over 0.8 million net acres are undeveloped.

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     Partnership management business

• ATN investment partnership business, which includes equity interests in 93 investment partnerships and a registered broker-dealer which acts as the dealer-manager of ATN’s investment partnership offerings; and

Atlas Pipeline Holdings and Atlas Pipeline Partners

     AHD was formed in July 2006 through our contribution of ownership interests in Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP”), the general partner of APL, to it in connection with AHD’s initial public offering. AHD’s cash generating assets currently consist solely of its interests in APL.

     APL is a leading provider of natural gas gathering services in the Anadarko, Arkoma 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 also provides interstate gas transmission services in southeastern Oklahoma, Arkansas, southern Kansas and southeastern Missouri. 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.

     Through its Mid-Continent operations, APL owns and operates:

• a FERC-regulated, 565-mile interstate pipeline system (“Ozark Gas Transmission”) that extends from southeastern Oklahoma through Arkansas and into southeastern Missouri and which has throughput capacity of approximately 400 million cubic feet per day (“MMcfd”);

• eight active natural gas processing plants with aggregate capacity of approximately 750 MMcfd and one treating facility with a capacity of approximately 200 MMcfd, located in Oklahoma and Texas; and

• 7,870 miles of active natural gas gathering systems located in Oklahoma, Arkansas, 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 Ozark Gas Transmission, as well as third party pipelines.

     Through its Appalachian operations, APL owns and operates 1,600 miles of natural gas gathering systems located in eastern Ohio, western New York, western Pennsylvania and northeastern Tennessee. Through an omnibus agreement and other agreements between us, APL and ATN, APL gathers substantially all of the natural gas for its Appalachian Basin operations from wells operated by ATN. Among other things, the omnibus agreement requires ATN to connect to APL’s gathering systems wells it operates that are located within 2,500 feet of APL’s gathering systems. APL is also party to natural gas gathering agreements with us and ATN under which it receives gathering fees generally equal to a percentage, typically 16%, of the selling price of the natural gas it transports.

Subsequent Events

     On October 29, 2008, our Board of Directors declared a cash dividend of $0.05 per share, payable on November 19, 2008 to shareholders of record on November 10, 2008.

     On October 29, 2008, ATN declared a quarterly cash distribution of $0.61 per unit on its outstanding common units, representing the cash distribution for the quarter ended September 30, 2008. This distribution is payable on November 14, 2008 to unitholders of record on November 10, 2008.

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     On October 27, 2008, APL declared a quarterly cash distribution of $0.96 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2008. The $53.4 million distribution, including $9.3 million to AHD for its general partner interest after the allocation of $5.0 million of its incentive distribution rights back to APL, will be paid on November 14, 2008 to unitholders of record at the close of business on November 10, 2008.

     On October 27, 2008, AHD declared a quarterly cash distribution of $0.51 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2008. This distribution is payable on November 19, 2008 to unitholders of record on November 10, 2008.

Recent Developments

     In September 2008, our Board of Directors approved a stock repurchase agreement 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. We purchased 442,586 of its shares during September 2008 for a total purchase price of $14.9 million under this program. In addition, we utilized the remaining $20.0 million of availability under a stock repurchase agreement approved on September 12, 2005 to purchase 560,291 shares in August and September 2008. The average purchase price for the shares repurchased during the quarter was $34.76 per share (see Item 2).

     In June 2008, we purchased 1,112,000 APL common limited partner units and 308,109 AHD common limited partner units in a private placement transaction at per unit amounts of $36.02 and $32.50, respectively. APL used the proceeds of $40.1 million to fund the early termination of certain crude oil derivative agreements. AHD used the proceeds of $10.0 million to fund the purchase of an additional 278,000 APL common units.

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

     Atlas Energy.In October 2008, ATN acquired 21,300 acres in Sullivan County, Indiana and a 50% undivided interest in a gas gathering system with related compression and fluid disposal facilities for approximately $5.7 million. Combined with additional individual purchases of leasehold acreage during the quarter ended September 30, 2008, ATN currently leases approximately 112,000 undeveloped net acres in the New Albany Shale for total costs invested of approximately $15.0 million.

     In June 2008, ATN entered into a $19.6 million agreement with Miller Petroleum, Inc. (“Miller”) whereby Miller assigned (i) 100% of the working interest in its oil and gas leases comprising 27,620 acres in the Koppers North and Koppers South section of Campbell County, Tennessee, (ii) 100% of the working interest in 8 existing wells, and (iii) 100% of the working interest in its oil and gas leases comprising 1,952 acres adjacent to the Koppers acreage. The agreement also provides Miller with an option to participate up to 25% in up to 10 wells to be drilled on the assigned acreage. In addition, ATN entered into two agreements with Miller whereby (i) Miller will provide drilling services to it for a two-year term and (ii) whereby ATN will transport and process natural gas for Miller from its existing wells.

     Atlas Pipeline and Atlas Pipeline Holdings.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. Concurrently, APL sold 278,000 common limited partner units to AHD in a private placement transaction at a price of $36.02 per unit, resulting in net proceeds of approximately $10.0 million. APL also received a capital contribution from AHD of $5.4 million for it to maintain its 2.0% general partner interest in APL. APL utilized the net proceeds from the sale and the capital contribution to fund the early termination of certain crude oil derivative agreements. In order to fund its purchase of APL’s common limited partner units,

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AHD sold 308,109 of its common limited partner units to us in a private placement transaction at a price of $32.50 per unit for net proceeds of $10.0 million.

     The net proceeds from the public and private placement offerings of APL’s common units were utilized to fund the early termination of a majority of its crude oil derivative contracts that it entered into as proxy hedges for the prices it receives for the ethane and propane portion of its NGL equity volume. These hedges, which related to production periods ranging from the end of second quarter of 2008 through the fourth quarter of 2009, were put in place simultaneously with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 and have become less effective as a result of significant increases in the price of crude oil and less significant increases in the price of ethane and propane. APL estimates that it incurred a charge during the second quarter 2008 of approximately $10.6 million due to the decline in the price correlation of crude oil and ethane and propane. APL terminated these derivative contracts during June and July 2008 at an aggregate net cost of approximately $264.0 million. Our net loss for the nine months ended September 30, 2008 includes a $187.6 million cash derivative expense resulting from APL’s aggregate net payments of $264.0 million to unwind a portion of these derivative contracts.

     In June 2008, APL issued $250.0 million of 10-year, 8.75% senior unsecured notes (the “APL 8.75% Notes”) in a private placement transaction pursuant to Rule 144A and Regulation S under the Securities Act of 1933. The sale of the APL 8.75% Senior Notes generated net proceeds of approximately $244.9 million, which APL utilized to repay indebtedness under its senior secured term loan and revolving credit facility.

     In June 2008, APL obtained $80.0 million of increased commitments to its senior secured revolving credit facility, increasing its aggregate lender commitments to $380.0 million. In connection with this and the previously mentioned transactions, APL also amended its senior secured credit facility to, among other things, exclude from the calculation of Consolidated EBITDA the costs associated with its termination of hedging agreements to the extent such costs are financed with or paid out of the net proceeds of an equity offering. In addition, consistent with several other recent energy master limited partnership agreements, APL’s general partner’s managing board and conflicts committee approved an amendment to its limited partnership agreement which will allow the cash expenditure to terminate derivative contracts to not reduce APL’s distributable cash flow.

Acquisitions

     Atlas Energy.In June 2007, ATN acquired DTE Gas & Oil Company from DTE Energy Company (“DTE” — NYSE: DTE) for $1.3 billion in cash. The assets acquired, which consisted principally of interests in natural gas wells in the Antrim Shale, are the basis for the formation of ATN’s Michigan gas and oil operations. ATN funded the purchase price in part from its private placement of $181.2 million of its Class B common units and $416.3 million of its Class D units to investors at a weighted average negotiated price of $25.00. ATN funded the remaining purchase price from borrowings under its credit facility.

     Atlas Pipeline Partners.In July 2007, APL acquired control of Anadarko Petroleum Corporation’s (“Anadarko” — NYSE: APC) 100% interest in the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and its 72.8% undivided joint venture interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (the “Anadarko Assets”). The transaction was effected by the formation of two joint venture companies which own the respective systems, to which APL contributed $1.9 billion and Anadarko contributed the Anadarko Assets. APL funded the purchase price, in part, from its private placement of $1.125 billion of its common units to investors at a negotiated purchase price of $44.00 per unit. Of the $1.125 billion, AHD purchased $168.8 million of these APL units, which was funded through its issuance of 6,249,995 of its common units in a private placement transaction at a negotiated purchase price of $27.00 per unit. AHD, as general partner and holder all of APL’s incentive distribution rights, also 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

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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 funded the remaining purchase price from $830.0 million of proceeds from a senior secured term loan which matures in July 2014 and borrowings under its senior secured revolving credit facility that matures in July 2013.

     In connection with this acquisition, APL reached an agreement with Pioneer Natural Resources Company (“Pioneer” — NYSE: PXD), which currently holds an approximate 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer will have an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system, which began on June 15, 2008 and ended on November 1, 2008, and up to an additional 7.4% interest beginning on June 15, 2009 and ending on November 1, 2009 (the aggregate 22.0% additional interest can be entirely purchased during the period beginning June 15, 2009 and ending 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 million, subject to certain adjustments, for the additional 22% interest if fully exercised. APL will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercised the purchase options.

Contractual Revenue Arrangements

Atlas Energy

     Appalachia Natural Gas. ATN has a natural gas supply agreement with Hess Corporation (“Hess”) which is valid through March 31, 2009. Subject to certain exceptions, Hess has a last right of refusal to buy all of the natural gas produced and delivered by ATN and its affiliates, including its investment partnerships, at certain delivery points. Based on recent production data available to ATN, we anticipate that ATN and its affiliates, including its investment partnerships, will sell approximately 18% of their Appalachian natural gas production during the year ending December 31, 2008 under the Hess agreement. The agreement requires the parties to negotiate a new pricing arrangement at each annual delivery point. If, at the end of any applicable period, the parties cannot agree to a new price for any delivery point, then ATN may solicit offers from third parties to buy the natural gas for that delivery point. If Hess does not match this price, then ATN may sell the natural gas to the third party. ATN markets the remainder of its natural gas, which is principally located in the Fayette County, PA area, primarily to 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;

• local distribution companies;

• industrial or other end-users; and/or

• companies generating electricity.

     Michigan Natural Gas. In Michigan, ATN has natural gas sales agreements with DTE, 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 50% of their Michigan natural gas production during the year ending December 31, 2008 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

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companies at the prevailing spot market price for Appalachian crude oil. In Michigan, the property operator typically markets the oil produced.

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 APL’s regulated transmission pipeline is recognized at the time the transportation service is provided. Revenue associated with the physical sale of natural gas is comprised of firm transportation rates and to the extent capacity is available following the reservation of firm system capacity, interruptible transportation rates, and 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.

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 debt or equity 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 we produce will generally approximate market prices in the

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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”.

     We believe that current natural gas prices will continue to cause relatively high levels of natural gas-related drilling in the United States as producers seek to increase their level of natural gas production. 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 recent high natural gas prices, new increased 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 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. We believe 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, we generally expect 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. The number of active oil and gas rigs has increased in recent years, mainly due to recent significant increases in natural gas prices, which could result in sustained increases in drilling activity during the current and future periods. However, energy market uncertainty could negatively impact North American drilling activity in the short term. Lower drilling levels over a sustained period would have a negative effect on natural gas volumes gathered and processed.

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Results of Operations

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Atlas Energy:
Production revenues (in thousands)
Gas(1)	$	77,253		$	60,302		$	224,345		$	102,439
Oil	$	3,956		$	2,938		$	12,014		$	7,357
Production volume(1) (2) (3) (4)
Gas (mcfd)		93,664			88,628			91,684			85,545
Oil (bpd)		424			446			421			425
Total (mcfed) Oil(bpd)		96,209			91,304			94,210			88,095
Average sales prices(3)(5):
Gas (per mcf)(6)	$	9.26		$	8.19		$	9.35		$	8.55
Oil (per bbl) (9) Gas(mcfd)	$	101.34		$	71.63		$	104.15		$	63.75
Production costs(3) (7):
Lease operating expenses	$	0.85		$	0.74		$	0.82		$	0.78
As a percent of production revenues per mcf		9	%		10	%		9	%		10	%
Production taxes per mcfe		0.41			0.25			0.39			0.17
Total production costs per mcfe	$	1.26		$	0.99		$	1.21		$	0.95
Depletion per Mcfe(3)	$	2.57		$	2.19		$	2.55		$	2.24
Atlas Pipeline Partners:
Appalachia system throughput volume (mcfd)(3)		91,829			71,876			84,007			66,888
Velma system gathered gas volume (mcfd)(3).		64,386			63,757			64,103			62,531
Elk City/Sweetwater system gathered gas volume (mcfd)(3)		279,145			299,450			292,307			298,724
Chaney Dell system gathered gas volume (mcfd)(3) (8)		300,467			255,649			278,906			255,649
Midkiff/Benedum system gathered gas volume (mcfd)(3) (8)		143,224			150,061			145,300			150,061
NOARK Ozark Gas Transmission throughput volume (mcfd)(3)		445,708			325,652			412,634			311,562
Combined throughput volume (mcfd)(3)		1,324,759			1,166,445			1,277,257			1,145,415

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(1)	Excludes sales of residual gas and sales to landowners.
(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 acquired AGO on June 29, 2007, and production volume from these assets have only been included from that date.
(5)	Atlas Energy’s average sales price before the effects of financial hedging was $10.49 and $6.55 for the three months ended September 30, 2008 and 2007, respectively, and $10.03 and $7.12 per Mcf for the nine months ended September 30, 2008 and 2007, respectively.
(6)	Includes $2.6 million and $6.5 million of derivative proceeds which were not included as revenue in the three months ended September 20, 2008 and 2007, respectively, and $10.5 million and $6.5 million in the nine months ended September 30, 2008 and 2007, 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)	Atlas Pipeline acquired the Chaney Dell and Midkiff/Benedum systems on July 27, 2007, and production volume from these systems has only been included from that date.
(9)	Atlas Energy’s average sales price for oil before the effects of financial hedging were $106.94 and $108.09 per barrel for the three months and nine months ended September 30, 2008. There were no oil financial hedges for the three months and nine months ended September 30, 2007.

Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

     Natural Gas and Oil Production. Our natural gas and oil production revenues consist of ATN’s production and sale of natural gas and crude oil to unaffiliated third-party customers. Natural gas and oil production expenses include labor to operate wells and related equipment, repairs and maintenance, materials and supplies, property taxes, severance taxes and other related costs. Our natural gas and oil production revenues were $81.2 million for the three months ended September 30, 2008, an increase of $17.9 million from $63.3 million for the prior year comparable period. Total production volume increased to 96.2 mmcfe per day for the three months ended September 30, 2008 compared with 91.3 mmcfe per day for the prior year comparable period. ATN’s Michigan assets, acquired in June 2007, accounted for $46.9 million of natural gas and oil production revenue for the three months ended September 30, 2008, an increase of $10.3 million compared with the third quarter 2007. ATN’s Appalachian assets had natural gas and oil production revenue of $34.3 million for the third quarter 2008, an increase of $7.7 million compared with revenue of $26.6 million for the third quarter 2007. The increase in revenue related to ATN’s Michigan and Appalachia assets is primarily related to increased prices (after the effect of financial hedges), as well as an increase in volumes of 1.2 mmcfe per day or 2.0% and 3.7 mmcfe per day or 11.7%.

     Natural gas and oil production expenses were $12.7 million for the three months ended September 30, 2008, an increase of $2.8 million from $9.9 million for the prior year comparable period. The increase was attributable to $1.2 million of production expenses in ATN’s Appalachia assets and a $1.5 million increase in Michigan production expenses due to an increase in the number of wells ATN owns.

     Well Construction and Completion. Our well construction and completion revenues and expenses represent fees generated and costs incurred associated with the completion of wells for drilling investments partnerships ATN sponsors. ATN’s drilling contracts are on a “cost plus” basis (typically cost plus 15%) and, as such, an increase in well drilling costs also results in an increase in well drilling revenues. Our well construction and completion revenues were $117.0 million for the three months ended September 30, 2008, an increase of $13.7 million from $103.3 million for the prior year comparable period. The increase is primarily due to the increase in the number of Marcellus Shale wells drilled for the three months ended September 30, 2008, which are drilled at a higher cost than other ATN Appalachian wells. ATN drilled 242 net wells for the third quarter 2008 compared with 286 for the prior year third quarter. At September 30, 2008, the balance in “Liabilities associated with drilling contracts” on our consolidated balance sheet includes $12.9 million of funds raised in ATN’s drilling investment programs that have not been applied to the completion of wells as of September 30, 2008 due to the timing of drilling operations, and thus have not been recognized as well construction and completion revenue.

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     Administration and Oversight and Well Services. Administration and oversight revenues consist of fees ATN receives from the investment drilling partnerships upon drilling of well ($15,000 to $60,000) and on a monthly basis afterwards ($75 per month) for administration services provided for the remaining life of the well. Well services revenues consist of monthly operating fees ATN receives from the investment drilling partnerships for the remaining life of the well. Administration and oversight fee revenues were $5.2 million for the third quarter 2008 compared with $5.4 million for the third quarter 2007. Well services revenues were $5.3 million for the third quarter 2008 compared with $4.8 million for the third quarter 2007, an increase of $0.5 million or 10.4%. The increase in well services revenue was due to an increase in the number of wells operated for our investment partnerships.

     Transmission, Gathering and Processing. Transmission, gathering and processing revenues principally include revenues earned by APL through its transportation and sale of natural gas, NGLs and condensate in its Appalachian and Mid-Continent business segments, and expenses within this category primarily include cost of sales of the commodities sold and related operating expenses. APL’s Appalachia business segment earns revenues under its master gas gathering agreement with us and ATN through gathering services provided, which are eliminated against the corresponding transmission, gathering and processing expenses recognized by us and ATN. These amounts are eliminated upon consolidation in our financial statements. Transmission, gathering and processing revenues also include gathering service fees received from its investment partnerships.

     Our transmission, gathering and processing revenues were $424.4 million for the three months ended September 30, 2008, an increase of $178.2 million from $246.2 million for the prior year comparable period. Transmission, gathering and processing expenses were $338.5 million for the three months ended September 30, 2008, an increase of $151.1 million from $187.4 million for the prior year comparable period. These increases were due principally to the revenues and expenses associated with APL’s Chaney Dell and Midkiff/Benedum systems, which were acquired in late July 2007, and the effect of higher realized commodity prices and higher volumes on its other systems. APL’s average gross natural gas gathered volume for the three months ended September 30, 2008 was 1.3 billion cubic feet per day (“bcfd”) compared with 1.2 bcfd for the prior year comparable period, an increase of 0.1 bcfd due principally to the acquisition of the Chaney Dell and Midkiff/Benedum systems.

     Gain (Loss) on Mark-to-Market Derivatives. Gain on mark-to-market derivatives was $147.5 million for the three months ended September 30, 2008 compared with a loss of $11.5 million for the prior year comparable period. This favorable movement was primarily due to a $243.4 million favorable movement in APL’s non-cash mark-to-market adjustments, partially offset by a $70.3 million net cash derivative expense related to APL’s early termination of a portion of its crude oil derivative contracts (see “Recent Developments”) and an unfavorable movement of $17.4 million related to APL’s non-qualified derivative cash settlements. The $243.4 million favorable movement in APL’s non-cash mark-to-market adjustments was due principally to a decrease in forward crude oil market prices from June 30, 2008 to September 30, 2008 and their favorable mark-to-market impact on certain non-qualified derivative contracts APL has for production volumes in future periods. Average forward crude oil market prices, which are the basis for adjusting the fair value of APL’s crude oil derivative contracts, at September 30, 2008 were $102.50 per barrel, a decrease of $37.76 from average forward crude oil market prices at June 30, 2008 of $140.26 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 Disclosures About Market Risk”.

     Other Income, Costs and Expenses.General and administrative expenses, including amounts reimbursed to affiliates, decreased $35.4 million to $13.5 million for the three months ended September 30, 2008 compared with $48.9 million for the prior year comparable period. This decrease was primarily related to a $43.9 million decrease in non-cash compensation expense, partially offset by higher costs of managing our operations. The decrease in non-cash compensation expense was principally attributable to a $13.3

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million mark-to-market gain recognized for certain APL common unit awards for which the ultimate amount to be issued will be determined after the completion of our 2008 fiscal year and is based upon the financial performance of APL’s acquired assets. The mark-to-market gain was the result of a significant change in APL’s common unit market price at September 30, 2008 when compared with the June 30, 2008 price, which is utilized in the estimate of APL’s non-cash compensation expense for these awards. Non-cash compensation expense of $31.8 million for the three months ended September 30, 2007 included $31.2 million recognized in connection with these common unit awards as a result of the effect APL’s Chaney Dell and Midkiff/Benedum acquisition had on the calculation of the awards.

     Depreciation, depletion and amortization increased to $46.1 million for the three months ended September 30, 2008 compared with $35.2 million for the three months ended September 30, 2007 due primarily to the depreciation and depletion associated with ATN’s acquired DGO assets and APL’s acquired Chaney Dell and Midkiff/Benedum system assets and ATN’s and APL’s expansion capital expenditures incurred between the periods.

     Interest expense decreased to $37.1 million for the three months ended September 30, 2008 as compared with $37.5 million for the comparable prior year period. This $0.4 million decrease was primarily due to a $1.7 million decrease in amortization expense related to deferred financing costs, partially offset by additional interest expense on increased borrowings by ATN and APL.

     Minority interest income (expense) for the three months ended September 30, 2008, which represents non-controlling, non-affiliated ownership interests in ATN, AHD and APL, was a loss of $194.1 million compared with income of $6.4 million for the prior year comparable period. The change between periods is principally due to a $223.1 million increase in APL’s net income and a $6.6 million increase in ATN’s net income between periods. These amounts were partially offset by a decrease in our ownership interest in AHD to 64.4% for the three months ended September 30, 2008 compared with 83% for the prior year comparable period. The increase in APL’s net income was the result of a favorable movement of $243.4 million in the impact of certain net losses recognized on derivatives from the prior year comparable period. ATN’s increase in net income between periods was principally due to an increase in production volumes and higher partnership management fees. The decrease in our ownership interest in AHD was due to its public issuances of common units in July 2007.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

     Natural Gas and Oil Production. Our natural gas and oil production revenues were $236.4 million for the nine months ended September 30, 2008, an increase of $126.6 million from $109.8 million for the prior year comparable period. Total production volumes increased to 94.2 mmcfe per day for the nine months ended September 30, 2008 compared with 88.1 mmcfe per day for the prior year comparable period. ATN’s Michigan assets, acquired on June 29, 2007, accounted for $139.2 million of natural gas and oil production revenue for the nine months ended September 30, 2008, an increase of $75.5 million when compared with the prior year nine month period. ATN’s Appalachian assets had natural gas and oil production revenue of $97.2 million for the nine months ended September 30, 2008, an increase of $24.8 million, or 34.3% compared with $72.4 million for the comparable prior year period. The increase in revenue related to ATN’s Appalachia assets is primarily related to an increase in volumes of 5.6 mmcfe per day, or 19.7% when compared with the prior year period.

     Natural gas and oil production expenses were $35.7 million for the nine months ended September 30, 2008, an increase of $21.3 million from $14.4 million for the prior year comparable period. The increase was attributable to an increase of $18.8 million in ATN’s Michigan assets and a $2.5 million increase in Appalachia production expenses due to an increase in the number of wells ATN owns.

     Well Construction and Completion. Our well construction and completion revenues were $343.4 million for the nine months ended September 30, 2008, an increase of $102.6 million from $240.8 million for

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the prior year comparable period. The increase is primarily due to the increase in the number of Marcellus Shale wells drilled for the nine months ended September 30, 2008, which are drilled at a higher cost than other ATN Appalachian wells. ATN drilled 672 net wells for the nine months ended September 30, 2008 compared with 748 for the prior year comparable period.

     Administration and Oversight and Well Services. Administration and oversight fee revenues were $15.4 million for the nine months ended September 30, 2008 compared with $13.3 million for the nine months ended September 30, 2007, an increase of $2.1 million or 15.2%. Well services revenues were $15.4 million for the nine months ended September 30, 2008 compared with $12.7 million for the nine months ended September 30, 2007, an increase of $2.7 million or 20.8%. The increase in administration and oversight fee revenue was due to an increase in the number of Marcellus shale wells drilled, while the increase in well services revenue was due to an increase in the number of wells operated by our drilling partnerships.

     Transmission, Gathering and Processing. Our transmission, gathering and processing revenues were $1,264.2 million for the nine months ended September 30, 2008, an increase of $783.6 million from $480.6 million for the prior year comparable period. Transmission, gathering and processing expenses were $1,003.3 million for the nine months ended September 30, 2008, an increase of $625.6 million from $377.7 million for the prior year comparable period. These increases were due principally to the revenues and expenses associated with APL’s Chaney Dell and Midkiff/Benedum systems and the effect of higher realized commodity prices and higher volumes on its other systems. APL’s average gross natural gas gathered volume for the nine months ended September 30, 2008 was 1.3 billion cubic feet per day (“bcfd”) compared with 1.1 bcfd for the prior year comparable period, an increase of 0.2 bcfd due principally to the acquisition of the Chaney Dell and Midkiff/Benedum systems.

     Gain (Loss) on Mark-to-Market Derivatives. Loss on mark-to-market derivatives was $257.3 million for the nine months ended September 30, 2008 compared with $16.0 million for the prior year comparable period. This unfavorable movement was due primarily to a net cash loss of $186.1 million and a non-cash derivative loss of $39.9 million related to the APL’s early termination of a portion of its crude oil derivative contracts (see “Recent Developments”), and an unfavorable movement of $51.7 million related to APL’s non-qualified derivative cash settlements. These amounts were partially offset by a $62.6 million favorable movement in APL’s non-cash mark-to-market adjustments. APL enters into derivative instruments principally 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 Disclosures About Market Risk”.

     Other Income, Costs and Expenses.General and administrative expenses, including amounts reimbursed to affiliates, decreased $24.9 million to $60.3 million for the nine months ended September 30, 2008 compared with $85.2 million for the prior year comparable period. The decrease was primarily related to a $47.6 million decrease in non-cash compensation expense, partially offset by higher costs of managing our operations. The decrease in non-cash compensation expense was principally attributable to a $49.7 million mark-to-market gain recognized for certain APL common unit awards for which the ultimate amount to be issued will be determined after the completion of our 2008 fiscal year and is based upon the financial performance of APL’s acquired assets. The mark-to-market gain was the result of a significant change in APL’s common unit market price at September 30, 2008 when compared with the December 31, 2007 price, which is utilized in the estimate of the non-cash compensation expense for these awards. Non-cash compensation expense of $43.5 million for the nine months ended September 30, 2007 included $33.6 million recognized in connection with these common unit awards as a result of the effect APL’s Chaney Dell and Midkiff/Benedum acquisition had on the calculation of the awards.

     Depreciation, depletion and amortization increased to $142.9 million for the nine months ended September 30, 2008 compared with $61.1 million for the nine months ended September 30, 2007 due primarily to the depreciation and depletion associated with ATN’s acquired DGO assets and APL’s acquired

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Chaney Dell and Midkiff/Benedum system assets and ATN’s and APL’s expansion capital expenditures incurred between the periods.

     Interest expense increased to $105.5 million for the nine months ended September 30, 2008 as compared with $53.7 million for the comparable prior year period. This $51.8 million increase was primarily due to interest associated with additional borrowings by ATN and APL to partially finance ATN’s acquisition of DGO in June 2007 and APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems during July 2007. These amounts were partially offset by lower variable interest rates between periods.

     Minority interest income for the nine months ended September 30, 2008, which represents non-controlling, non-affiliated ownership interests in ATN, AHD and APL, was $60.8 million compared with $15.0 million for the prior year comparable period. The change between periods is principally due to a $83.1 million decrease in APL’s net income and a decrease in our ownership interest in AHD to 64% for the nine months ended September 30, 2008 compared with 83% for the prior year comparable period. These amounts were partially offset by a $20.9 million increase in ATN’s net income between periods. The decrease in APL’s net income was the result of an unfavorable movement of $215.1 million in the impact of certain net losses recognized on derivatives from the prior year comparable period. The decrease in our ownership interest in AHD was due to its private placement of common units to partially finance APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007. ATN’s increase in net income between periods was principally due to the inclusion of DGO’s operating results from its date of acquisition and higher Appalachia production volumes and prices.

Liquidity and Capital Resources

     Our primary sources of liquidity are distributions received with respect to our ownership interests in ATN, APL and AHD. Our primary cash requirements are for our general and administrative expenses and other expenditures, which we expect to fund through distributions received. 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;

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

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

     During the year ended December 31, 2007, ATN raised $145.0 million through its investment partnerships and anticipates raising between $450.0 million and $500.0 million during the current fiscal year. During the nine months ended September 30, 2008, ATN had raised $238.4 million through its investment partnerships. At September 30, 2008, ATN had $462.0 million of outstanding borrowings under its credit facility, with a borrowing base of $697.5 million. In addition to the availability under its credit facility, ATN has a universal shelf registration statement on file with the Securities and Exchange Commission, which allows it to issue an unlimited amount of equity or debt securities.

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     Atlas Pipeline Holdings. AHD’s primary sources of liquidity are distributions received with respect to its ownership interests in APL and borrowings under its credit facility. Its primary cash requirements are for its general and administrative expenses, 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 distributions received from APL and its capital contributions to APL through the retention of cash and borrowings under its credit facility. At September 30, 2008, AHD had $31.0 million outstanding and $19.0 million of remaining committed capacity under its credit facility, subject to covenant limitations (see Note 7 under Item 1, “Financial Statements”).

     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:

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

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

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

     At September 30, 2008, APL had $175.0 million of outstanding borrowings under its $380.0 million credit facility and $8.1 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheet, with $196.9 million of remaining committed capacity under its credit facility, subject to covenant limitations. In addition to the availability under its credit facility, APL has a universal shelf registration statement on file with the Securities and Exchange Commission, which allows it to issue equity or debt securities of which $136.4 million remains available for issuance at September 30, 2008.

     We believe that we and our subsidiaries have sufficient liquid assets, cash from operations and borrowing capacity to meet our and their financial commitments, debt service obligations, distribution requirements, contingencies and anticipated capital expenditures. However, we and our subsidiaries are subject to business and operational 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 and the issuance of additional common shares and units.

Cash Flows — Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

     Net cash used in operating activities of $143.7 million for the nine months ended September 30, 2008 represented a decrease of $221.8 million from $78.1 million of net cash provided by operating activities for the comparable prior year period. The decrease was derived principally from a $145.1 million increase in cash distributions paid to minority interests and a $92.5 million decrease in net income excluding non-cash items, partially offset by a $19.8 million favorable movement in deferred taxes. The decrease due to cash distributions to minority interests is due mainly to increases in ATN’s, AHD’s and APL’s common units outstanding and their cash distribution amount per common unit. The decrease in net income excluding non-cash items was principally due to the unfavorable cash impact from APL’s early termination of certain crude oil instruments during June and July 2008, partially offset by the increased profitability in other aspects of ATN’s and APL’s operations. The non-cash charges which impacted net income include unfavorable increases for minority interests in net income of $45.8 million, non-cash loss on derivatives of $65.4, and non-cash compensation related to long-term incentive plans of $47.6 million, partially offset by a favorable increase of $81.8 million for depreciation, depletion and amortization. The movement in net non-cash loss on derivative value between periods resulted from commodity price movements during the nine months ended

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September 30, 2008 and the unfavorable non-cash impact it had on our net income, which was due to the mark-to-market of derivative contracts APL has for future periods. The increase in depreciation, depletion and amortization resulted from ATN’s acquisition of DTE in June 2007 and APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007. The movement in minority interests in net income was due to a decrease in APL’s net income and a decrease in our ownership interests in AHD and ATN between periods, partially offset by an increase in ATN’s net income between periods.

     Net cash used in investing activities of $437.5 million for the nine months ended September 30, 2008 represented a decrease of $2,916.2 million from $3,353.7 million used in investing activities for the comparable prior year period. This decrease was principally due to a $3,173.1 million reduction in cash paid for acquisitions related ATN’s acquisition of AGO on June 29, 2007 and APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems, the current year post-closing purchase price adjustment of APL’s prior year acquisition of the Chaney Dell and Midkiff/Benedum systems of $31.4 million, and a $9.9 million decrease in our cash paid for investments in Lightfoot. This decrease was partially offset by a $267.5 million increase in capital expenditures. See further discussion of capital expenditures under “—Capital Requirements”.

     Net cash provided by financing activities of $560.9 million for the nine months ended September 30, 2008 represented a decrease of $2,643.0 million from $3,203.9 million of net cash provided by financing activities for the prior year comparable period. This decrease was principally due to a $1,910.5 million net reduction in APL, ATN, and AHD credit facility borrowings, and a $1,421.7 million decrease in net proceeds from APL and ATN equity offerings. These amounts are partially offset by a $652.0 million increase in net proceeds from the issuance of APL and ATN long-term debt and a decrease of $45.6 million in our purchases of our stock.

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 have already invested $10.7 million at September 30, 2008. 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:

• 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

• 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:

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

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

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     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				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
Atlas Energy
Maintenance capital expenditures	$	12,975	$	12,975	$	38,925	$	30,475
Expansion capital expenditures		77,641		57,371		184,066		94,953
Total	$	90,616	$	70,346	$	222,991	$	125,428
Atlas Pipeline Partners
Maintenance capital expenditures	$	1,711	$	2,328	$	5,375	$	3,800
Expansion capital expenditures		87,413		32,216		241,019		72,628
Total	$	89,124	$	34,544	$	246,394	$	76,428
Consolidated
Maintenance capital expenditures	$	14,686	$	15,303	$	44,300	$	34,275
Expansion capital expenditures		165,054		89,587		425,085		167,581
Total	$	179,740	$	104,890	$	469,385	$	201,856

     ATN’s expansion capital expenditures increased to $77.6 million and $184.1 million for the three and nine months ended September 30, 2008, respectively, due principally to higher capital contributions to its investment drilling partnerships and increased acquisitions of leasehold acreage. ATN maintenance capital expenditures for the three and nine months ended September 30, 2008 were $13.0 and $38.9 million, respectively, due primarily to the maintenance capital expenditures associated with the DGO acquisition, which occurred in June 2007.

     APL’s expansion capital expenditures increased to $87.4 million and $241.0 million for the three and nine months ended September 30, 2008, respectively, due principally to the expansion of APL’s gathering systems and upgrades to processing facilities and compressors to accommodate new wells drilled in its service areas, including the construction of a 60 MMcfd expansion of APL’s Sweetwater processing plant. The decrease in maintenance capital expenditures for the three months ended September 30, 2008 when compared with the prior year third quarter was due to changes in the timing of APL’s scheduled maintenance activity between periods. The increase in maintenance capital expenditures for the nine months ended September 30, 2008 when compared with the prior year comparable period was due to the maintenance capital requirements of APL’s Chaney Dell and Midkiff/Benedum systems, which it acquired in July 2007, and fluctuations in the timing of APL’s scheduled maintenance activity.

     As of September 30, 2008, we are committed to expend approximately $153.9 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

Income Taxes

     Our effective income tax rate was 36.6% and 31.7% for the nine months ended September 30, 2008 and 2007, respectively, and 36.6% and 30.4% for the three months ended September 30, 2008 and 2007, respectively. The respective increases 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 36.7% for the year ended December 31, 2008.

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Off Balance Sheet Arrangements

     As of September 30, 2008, our off balance sheet arrangements are limited to ATN’s guarantee of Crown Drilling of Pennsylvania, LLC’s $3.6 million credit agreement, ATN’s and APL’s letters of credit outstanding of $5.0 million and $8.1 million and our commitments to expend approximately $153.9 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 September 30, 2008.

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, depreciation and amortization, asset impairment, fair value of derivative instruments, stock compensation, 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, 2007 and in Note 2 under Item 1, “Financial Statements” included in this report, and there have been no material changes to these policies through September 30, 2008.

Fair Value of Financial Instruments

     We adopted the provisions of SFAS No. 157 at January 1, 2008. 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 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.

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.

     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 commodity hedges and interest rate swaps (see Note 9 under Item 1, “Financial Statements”) and our SERP (see Note 17 under Item 1, “Financial Statements”).

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ATN’s and APL’s commodity hedges, with the exception of APL’s NGL fixed price swaps and crude oil collars 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 and APL’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model, and are therefore defined as Level 2 fair value measurements. Our SERP is calculated based on observable actuarial inputs developed by a third-party actuary, and therefore is defined as a Level 2 fair value measurement. 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.

New and Recently Adopted Accounting Standards

     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 is prohibited. All prior-period EPS data presented shall be adjusted retrospectively to conform to the provisions of this FSP. We will apply the requirements of FSP EITF 03-6-1 upon its adoption on January 1, 2009 and we do not believe the adoption of FSP EITF 03-6-1 will have a material impact on our financial position or results of operations

     In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162, “The Hierarchy of Generally Accepted Accounting Policies” (“SFAS 162”), which reorganizes the sources of accounting principles into a GAAP hierarchy in order of authority. The purpose of the new standard is to improve financial reporting by providing a consistent framework for determining what accounting principles should be used when preparing U.S. GAAP financial statements. The standard is effective 60 days after the SEC’s approval of the PCAOB’s amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” The adoption of SFAS 162 will not have a material impact on our financial position or 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)”). 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 is 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 will apply the requirements of FSP FAS 142-3 upon its adoption on January 1, 2009 and we do not believe the adoption of FSP FAS 142-3 will have a material impact on our financial position or results of operations.

     In March 2008, the FASB ratified the Emerging Issues Task Force (“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

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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 requires retrospective application of the guidance to all periods presented. Early adoption is prohibited. We currently do not expect the adoption of EITF 07-4 to have an impact on our financial position and results of operations.

     In March 2008, the FASB issued Statement of Financial Accounting Standards 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 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 are currently evaluating the impact the adoption of SFAS No. 161 will have on the disclosures regarding our derivative instruments.

     In December 2007, the FASB issued SFAS No. 160, “Noncontrolling 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 noncontrolling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling 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 noncontrolling interest. Additionally, SFAS No. 160 establishes a single method for 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 is effective for fiscal years beginning on or after December 15, 2008. We will apply the requirements of SFAS No. 160 upon its adoption on January 1, 2009 and are currently evaluating whether SFAS No. 160 will have a material impact on our financial position or results of operations.

     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”, 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 noncontrolling 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 noncontrolling 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 will apply the requirements of SFAS No. 141(R) upon its adoption on January 1, 2009 and are currently evaluating whether SFAS No. 141(R) will have a material impact on our financial position or results of operations.

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     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment to FASB Statement No. 115” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 is effective at the inception of an entity’s first fiscal year beginning after November 15, 2007 and offers various options in electing to apply its provisions. We adopted SFAS No. 159 at January 1, 2008, and have elected not to apply the fair value option to any of our financial instruments not already carried at fair value in accordance with other accounting standards.

     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosures about fair value statements. In February 2008, the FASB issued FASB Staff Position SFAS No. 157-b, “Effective Date of FASB Statement No. 157”, which provides for a one-year deferral of the effective date of SFAS No. 157 with regard to an entity’s non-financial assets and non-financial liabilities, or any non-recurring fair value measurement. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We adopted SFAS No. 157 at January 1, 2008 with respect to our subsidiaries’ derivative instruments, which are measured at fair value within our financial statements. The provisions of SFAS No. 157 have not been applied to our non-financial assets and non-financial liabilities. See “—Fair Value of Financial Instruments” for disclosures pertaining to the provisions of SFAS No. 157 with regard to our subsidiaries’ financial instruments.

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. 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 September 30, 2008. 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.

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     Interest Rate Risk.At September 30, 2008, ATN had a senior secured revolving credit facility with a borrowing base of $697.5 million ($462.0 million outstanding). The weighted average interest rate for these borrowings was 4.6% at September 30, 2008. ATN also has interest rate derivative contracts at September 30, 2008 having an aggregate notional principal amount of $150.0 million. Under the terms of this agreement, ATN will pay 3.11%, 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 amount. This derivative contract effectively converts $150.0 million of ATN’s floating rate debt under the credit facility to fixed-rate debt. The interest rate swap agreement expires on January 31, 2011.

     In May 2008, AHD entered into an interest rate derivative contract having an aggregate notional principal amount of $25.0 million. Under the terms of agreement, AHD will pay an interest rate of 3.01%, plus the applicable margin as defined under the terms of its revolving credit facility, and will receive LIBOR, plus the applicable margin, on the notional principal amounts. This derivative effectively converts $25.0 million of its floating rate debt under the revolving credit facility to fixed-rate debt. The interest rate swap agreement began on May 30, 2008 and expires on May 28, 2010.

     At September 30, 2008, 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 effectively convert $450.0 million of APL’s floating rate debt under its term loan and revolving credit facility to fixed-rate debt. The APL interest rate swap agreements are effective as of September 30, 2008 and expire during periods ranging from January 30, 2010 through April 30, 2010.

     At September 30, 2008, APL had a $380.0 million senior secured revolving credit facility ($175.0 million outstanding). APL also had $707.2 million outstanding under its senior secured term loan at September 30, 2008. The weighted average interest rate for APL’s revolving credit facility borrowings was 4.9% at September 30, 2008, and the weighted average interest rate for the term loan borrowings was 6.2% at September 30, 2008.

     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 $7.5 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 prices, ATN uses financial derivative instruments for a portion of its future natural gas 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. These financial swap and option instruments are generally classified as cash flow hedges in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). A 10% change in the average price of natural gas, NGLs, condensate and oil would result in a change to our consolidated operating income (loss), excluding minority interest and income tax effects, for the twelve-month period ending September 30, 2009 of approximately $34.8 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

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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 and oil.

     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 in stockholders’ equity 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.

     As of September 30, 2008, ATN had the following interest rate and commodity derivatives:

Natural Gas Fixed Price Swaps

Production
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset/(Liability)
	(MMbtu)		(per MMbtu)		(in thousands) (1)
2008		9,890,000	$	8.87	$	13,683
2009		45,060,000	$	8.56		16,077
2010		33,660,000	$	8.14		(11,620	)
2011		25,980,000	$	7.91		(11,840	)
2012		17,440,000	$	8.13		(4,196	)
2013		1,500,000	$	8.73		443
					$	2,547

Natural Gas Costless Collars

Production
Period Ending				Average		Fair Value
December 31,	Option Type	Volumes		Floor and Cap		Asset/(Liability)
		(MMbtu)		(per MMbtu)		(in thousands) (1)
2008	Puts purchased		390,000	$	7.50	$	80
2008	Calls sold		390,000	$	9.40		—
2009	Puts purchased		240,000	$	11.00		714
2009	Calls sold		240,000	$	15.35		—
2010	Puts purchased		3,120,000	$	7.92		—
2010	Calls sold		3,120,000	$	9.10		(604	)

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Production
Period Ending				Average		Fair Value
December 31,	Option Type	Volumes		Floor and Cap		Asset/(Liability)
		(MMbtu)		(per MMbtu)		(in thousands) (1)
2011	Puts purchased		7,200,000	$	7.50		—
2011	Calls sold		7,200,000	$	8.45		(3,804	)
2012	Puts purchased		720,000	$	7.00		—
2012	Calls sold		720,000	$	8.37		(468	)
						$	(4,082	)

Crude Oil Fixed Price Swaps

Production
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset/(Liability)
	(Bbl)		(per Bbl)		(in thousands)(2)
2008		22,400	$	103.67	$	47
2009		58,900	$	99.92		(148	)
2010		48,900	$	97.31		(344	)
2011		40,400	$	96.43		(327	)
2012		33,500	$	96.00		(280	)
2013		9,000	$	95.95		(75	)
					$	(1,127	)

Crude Oil Costless Collars

Production
Period Ending				Average		Fair Value
December 31,	Option Type	Volumes		Floor and Cap		Asset/ (Liability)
		(Bbl)		(per Bbl)		(in thousands)(2)
2008	Puts purchased		10,500	$	85.00	$	2
2008	Calls sold		10,500	$	126.44		—
2009	Puts purchased		36,500	$	85.00		—
2009	Calls sold		36,500	$	118.63		(86	)
2010	Puts purchased		31,000	$	85.00		—
2010	Calls sold		31,000	$	112.92		(190	)
2011	Puts purchased		27,000	$	85.00		—
2011	Calls sold		27,000	$	110.81		(196	)
2012	Puts purchased		21,500	$	85.00		—
2012	Calls sold		21,500	$	110.06		(165	)
2013	Puts purchased		6,000	$	85.00		—
2013	Calls sold		6,000	$	110.09		(47	)
						$	(682	)
Total ATN net derivative liability						$	(3,344	)

(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.AHD and APL apply the provisions of SFAS No. 133 to our derivative instruments. AHD and APL formally document all relationships between hedging instruments and the items being hedged, including our risk management objective and strategy for undertaking the hedging transactions. This includes matching the derivative contracts to the forecasted transactions. Under SFAS No. 133, AHD and APL can assess, both at the inception of the derivative and on an ongoing basis, whether the derivative is

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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, AHD and APL will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by us and APL through the utilization of market data, will be recognized immediately within other income (loss) in our consolidated statements of operations. For APL’s derivatives qualifying as hedges, we will recognize the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive income (loss), and reclassify the portion relating to commodity derivatives to natural gas and liquids 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 APL’s non-qualifying derivatives and for the ineffective portion of qualifying derivatives, we will recognize changes in fair value within other income (loss) in our consolidated statements of operations as they occur.

     On July 1, 2008, APL elected to discontinue 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 will be recognized immediately within gain (loss) on mark-to-market derivatives in our consolidated statements of operations. The fair value of these commodity derivative instruments at June 30, 2008, which was recognized in accumulated other comprehensive loss within stockholders’ equity on our consolidated balance sheet, will be reclassified to our consolidated statements of operations as these contracts expire.

     During June and July 2008, APL made net payments of $264.0 million related to the early termination of crude oil derivative contracts that it entered into as proxy hedges for the prices received on the ethane and propane portion of its NGL equity volume. 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 nine months ended September 30, 2008, we recognized the following derivative activity related to APL’s termination of these derivative instruments (amounts in thousands):

	Early Termination of Derivative Contracts
	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2008			2007		2008			2007
Net cash derivative expense included within gain (loss) on mark-to-market derivatives on our consolidated statements of operations	$	(70,258	)	$	—	$	(186,068	)	$	—
Net cash derivative expense included transmission, gathering and processing revenue on our consolidated statements of operations		(1,258	)		—		(1,573	)		—
Net non-cash derivative income (expense) included within gain (loss) on mark-to-market derivatives, net on our consolidated statements of operations		6,488			—		(39,857	)		—
Net non-cash derivative expense included within transmission, gathering and processing revenue on our consolidated statements of operations		(19,514	)		—		(19,514	)		—

     In connection with its Chaney Dell and Midkiff/Benedum acquisition, APL reached an agreement with Pioneer granting it an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system, which began on June 15, 2008 and ended on November 1, 2008, and an additional 7.4% interest beginning on June 15, 2009 and ending on November 1, 2009 (the aggregate 22.0% additional interest can be entirely

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purchased during the period beginning June 15, 2009 and ending on November 1, 2009; see Note 8 under Item 1, “Financial Statements”). If Pioneer does exercise either of these options, APL will discontinue hedge accounting for the derivative instruments covering the portion of the forecasted production of the Midkiff/Benedum system sold to Pioneer and will evaluate these derivative instruments to determine if they can be documented to match other forecasted production APL may have.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Loss from cash settlement of qualifying hedge instruments(1)	$	(27,419	)	$	(12,850	)	$	(78,214	)	$	(23,548	)
Gain/(loss) from change in market value of non-qualifying derivatives(2)		(190,013	)		(15,595	)		17,919			(35,731	)
Gain/(loss) from change in market value of ineffective portion of qualifying derivatives(2)		(44,997	)		7,164			(41,271	)		(3,526	)
Loss from cash settlement of non-qualifying derivatives(2)		(84,207	)		(3,037	)		(280,696	)		(3,037	)
Loss from cash settlement of interest rate derivatives(3)		(708	)		—			(915	)		—

(1)	Included within transmission, gathering and processing revenue on our consolidated statements of operations.
(2)	Included within gain (loss) on mark-to-market derivatives, net on our consolidated statements of operations.
(3)	Included within interest expense on our consolidated statements of operations.

As of September 30, 2008, AHD had the following interest rate derivatives:

     Interest Fixed-Rate Swap

	Notional			Contract Period	Fair Value
Term	Amount		Type	Ended December 31,	Asset/(Liability)(1)
					(in thousands)
May 2008- May 2010	$	25,000,000	Pay 3.01% —Receive LIBOR	2008	$	46
				2009		(4	)
				2010		40
Total AHD net derivative asset					$	82

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

     As of September 30, 2008, APL had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

     Interest Fixed-Rate Swap

	Notional			Contract Period	Fair Value
Term	Amount		Type	Ended December 31,	Asset/(Liability)(1)
					(in thousands)
January 2008- January 2010	$	200,000,000	Pay 2.88% —Receive LIBOR	2008	$	413
				2009		238
				2010		65
					$	716

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	Notional			Contract Period	Fair Value
Term	Amount		Type	Ended December 31,	Asset/(Liability)(1)
					(in thousands)
April 2008- April 2010	$	250,000,000	Pay 3.14% —Receive LIBOR	2008	$	365
				2009		(339	)
				2010		197
					$	223

Natural Gas Liquids Sales — Fixed Price Swaps

Production Period			Average		Fair Value
Ended December 31,	Volumes		Fixed Price		Liability(2)
	(gallons)		(per gallon)		(in thousands)
2008		7,434,000	$	0.697	$	(3,642	)
2009		8,568,000	$	0.746		(3,607	)
					$	(7,249	)

Crude Oil Sales Options (associated with NGL volume)

Production Period			Associated		Average
Ended	Crude		NGL		Crude		Fair Value
December 31,	Volume		Volume		Strike Price		Asset/(Liability)(3)			Option Type
	(barrels)		(gallons)		(per barrel)		(in thousands)
2008		536,400		29,972,124	$	70.16	$	110		Puts purchased
2008		126,000		11,219,040	$	127.55		(3,531	)	Puts sold(4)
2008		126,000		11,219,040	$	140.00		65		Calls purchased(4)
2008		473,400		25,764,984	$	80.13		(10,104	)	Calls sold
2009		1,584,000		85,038,534	$	80.00		2,372		Puts purchased
2009		304,200		27,085,968	$	126.05		(9,082	)	Puts sold(4)
2009		304,200		27,085,968	$	143.00		1,026		Calls purchased(4)
2009		2,121,600		114,072,336	$	81.01		(51,161	)	Calls sold
2010		3,127,500		202,370,490	$	81.09		(90,981	)	Calls sold
2010		714,000		45,415,440	$	120.00		8,966		Calls purchased(4)
2011		606,000		32,578,560	$	95.56		(13,597	)	Calls sold
2011		252,000		13,547,520	$	120.00		3,462		Calls purchased(4)
2012		450,000		24,192,000	$	97.10		(9,981	)	Calls sold
2012		180,000		9,676,800	$	120.00		2,629		Calls purchased(4)
							$	(169,807	)

Natural Gas Sales — Fixed Price Swaps

Production Period				Average		Fair Value
Ended December 31,		Volumes		Fixed Price		Asset/(Liability)(3)
		(mmbtu)(5)		(per mmbtu)(5)		(in thousands)
2008			1,371,000	$	8.823	$	1,722
2009			5,724,000	$	8.611		2,667
2010	��		4,560,000	$	8.526		(269	)
2011			2,160,000	$	8.270		(583	)
2012			1,560,000	$	8.250		(251	)
						$	3,286

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Natural Gas Basis Sales

Production Period			Average			Fair Value
Ended December 31,	Volumes		Fixed Price			Asset(3)
	(mmbtu)(5)		(per mmbtu)(5)			(in thousands)
2008		1,371,000	$	(0.744	)	$	2,042
2009		5,724,000	$	(0.558	)		1,599
2010		4,560,000	$	(0.622	)		732
2011		2,160,000	$	(0.664	)		217
2012		1,560,000	$	(0.601	)		97
						$	4,687

Natural Gas Purchases — Fixed Price Swaps

Production Period			Average			Fair Value
Ended December 31,	Volumes		Fixed Price			Asset/(Liability)(3)
	(mmbtu)(5)		(per mmbtu)(5)			(in thousands)
2008		4,065,000	$	8.274	(6)	$	(5,622	)
2009		15,564,000	$	8.680			(8,329	)
2010		8,940,000	$	8.580			196
2011		2,160,000	$	8.270			583
2012		1,560,000	$	8.250			251
						$	(12,921	)

Natural Gas Basis Purchases

Production Period			Average			Fair Value
Ended December 31,	Volumes		Fixed Price			Liability(3)
	(mmbtu)(5)		(per mmbtu)(5)			(in thousands)
2008		4,065,000	$	(1.114	)	$	(6,761	)
2009		15,564,000	$	(0.654	)		(5,362	)
2010		8,940,000	$	(0.600	)		(2,118	)
2011		2,160,000	$	(0.700	)		(50	)
2012		1,560,000	$	(0.610	)		(49	)
						$	(14,340	)

Ethane Put Options

Production Period	Associated		Average
Ended	NGL		Crude		Fair Value
December 31,	Volume		Strike Price		Asset(2)		Option Type
	(gallons)		(per gallon)		(in thousands)
2008		7,560,000	$	0.7885	$	399	Puts purchased
2009		16,254,000	$	0.6928		196	Puts purchased
					$	595

Propane Put Options

Production Period	Associated		Average
Ended	NGL		Crude		Fair Value
December 31,	Volume		Strike Price		Asset(2)		Option Type
	(gallons)		(per gallon)		(in thousands)
2008		8,946,000	$	1.4752	$	174	Puts purchased
2009		23,310,000	$	1.3935		368	Puts purchased
					$	542

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Crude Oil Sales

Production Period			Average		Fair Value
Ended December 31,	Volumes		Fixed Price		Liability(3)
	(barrels)		(per barrel)		(in thousands)
2008		14,100	$	60.569	$	(563	)
2009		33,000	$	62.700		(1,305	)
					$	(1,868	)

Crude Oil Sales Options

Production Period			Average		Fair Value
Ended December 31,	Volumes		Strike Price		Asset/(Liability)(3)			Option Type
	(barrels)		(per barrel)		(in thousands)
2008		69,000	$	68.000	$	10		Puts purchased
2008		69,000	$	78.055		(1,589	)	Calls sold
2009		168,000	$	90.000		253		Puts purchased
2009		306,000	$	80.017		(13,525	)	Calls sold
2010		234,000	$	83.027		(9,382	)	Calls sold
2011		72,000	$	87.296		(1,938	)	Calls sold
2012		48,000	$	83.944		(1,380	)	Calls sold
					$	(27,551	)
Total APL net derivative liability					$	(223,687	)
Total Company net derivative liability					$	(226,949	)

(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)	Puts sold and calls purchased in 2008 and 2009 represent costless collars entered into by APL as offsetting positions for the calls sold related to ethane and propane production. In addition, calls were purchased by APL for 2010 through 2012 to offset 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.
(5)	Mmbtu represents million British Thermal Units.
(6)	Includes APL’s premium received from its sale of an option for it to sell 234,000 mmbtu of natural gas for the year ended December 31, 2008 at $18.00 per mmbtu.

     Atlas America.At September 30, 2008 and December 31, 2007, we reflected a net hedging liability on our balance sheet of $211.9 million and $210.5 million, respectively, as a result of ATN’s, AHD’s and APL’s derivative contracts. Of the $9.4 million net loss in accumulated other comprehensive loss at September 30, 2008, we will reclassify $4.8 million of losses to our consolidated statements of operations over the next twelve month period as these contracts expire, and $4.6 million of losses 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 General Partner’s Chief Executive Officer

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and our 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 our disclosure controls and procedures are effective at the reasonable assurance level at September 30, 2008.

     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

     We are currently involved in various disputes incidental to our normal business operations. In addition, ATN has been named as a party to a certain legal action brought by CNX Gas Company, LLC which is discussed in Note 11 of the notes to the consolidated financial statements included in Part I, Item 1 of this Form 10-Q, which is incorporated herein by reference. ATN is of the opinion that the final resolution of any currently pending or threatened litigation is not likely to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

ITEM 1A. RISK FACTORS

     The risk factors set forth below should be read in conjunction with those appearing in Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

Due to the accounting of our derivative contracts, increases in prices for natural gas, crude oil and NGLs could result in non-cash balance sheet reductions.

     With the objective of enhancing the predictability of future revenues, from time to time we enter into natural gas, natural gas liquids and crude oil derivative contracts. We account for these derivative contracts by applying the provisions of SFAS No. 133. Due to the mark-to-market accounting treatment for these derivative contracts, we could recognize incremental derivative liabilities between reporting periods resulting from increases or decreases in reference prices for natural gas, crude oil and NGLs, which could result in our recognizing a non-cash loss in our consolidated statements of operations or through accumulated other comprehensive income (loss) and a consequent non-cash decrease in our stockholders’ equity between reporting periods. Any such decrease could be substantial. In addition, we may be required to make a cash payment upon the termination of any of these derivative contracts.

Our hedging activities do not eliminate our exposure to fluctuations in commodity prices and interest rates and may reduce our cash flow and subject our earnings to increased volatility.

     Our operations expose us to fluctuations in commodity prices. We utilize derivative contracts related to the future price of crude oil, natural gas and NGLs with the intent of reducing the volatility of our cash flows due to fluctuations in commodity prices. We also have exposure to interest rate fluctuations as a result of variable rate debt under our term loan and revolving credit facility. We have entered into interest rate swap

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agreements to convert a portion of this variable rate debt to a fixed rate obligation, thereby reducing our exposure to market rate fluctuations.

     We have entered into derivative transactions related to only a portion of our crude oil, natural gas and NGL volume and our variable rate debt. As a result, we will continue to have direct commodity price risk and interest rate risk with respect to the unhedged portion of these items. To the extent we hedge our commodity price and interest rate risk using certain derivative contracts, we will forego the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor.

     Even though our hedging activities are monitored by management, these activities could reduce our cash flow in some circumstances, including if the counterparty to the hedging contract defaults on its contract obligations, if there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received or, with regard to commodity derivatives, if production is less than expected. With respect to commodity derivative contracts, if the actual amount of production is lower than the amount that is subject to our derivative instruments, we might be forced to satisfy all or a portion of derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a reduction of our cash flow. In addition, we have entered into proxy hedges with respect to our NGLs, typically using crude oil derivative contracts, based upon the historical price correlation between crude oil and NGLs. Certain of these proxy hedges could become less effective as a result of significant increases in the price of crude oil and less significant increases in the price of ethane and propane. If these proxy hedges remain less effective, our settlement of the contracts could result in significant costs to us.

     The accounting standards regarding hedge accounting are complex, and even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our financial statements may reflect volatility due to these derivatives, even when there is no underlying economic impact at that point. In addition, it is not always possible for us to engage in a derivative transaction that completely mitigates our exposure to commodity prices and interest rates. Our financial statements may reflect a gain or loss arising from an exposure to commodity prices and interest rates for which we are unable to enter into a completely effective hedge transaction.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

							Maximum Number
					Shares Purchased As		of Shares that May
					Part of Publicly		Yet Be Purchased
	Total Number of		Average Price		Announced Plans		Under the Plans
	Shares Purchased		paid Per Share		or Programs		or Programs
July 1 — 31, 2008		—	$	—		—
August 1 — 31, 2008		392,791		36.35		392,791
September 1—30, 2008		610,086		34.36		610,086
Total		1,002,877	$	34.76		1,002,877	See Note 1

Note 1: In September 2008, the Company announced that its Board of Directors authorized a repurchase program through which the Company may repurchase up to $50.0 million ($35.1 million remaining at September 30, 2008) of its common stock. In addition, the Company utilized the remaining $20.0 million under a repurchase program authorized and announced in November 2005. Repurchases may be made from time to time through open market purchases or privately negotiated transactions at the discretion of the Company and in accordance with the rules of the Securities and Exchange Commission, as applicable. The amount and timing of any repurchases will depend on market and other relevant conditions. Purchases may be increased, decreased, or discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury shares.

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ITEM 6. EXHIBITS

Exhibit No.			Description
	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	(a)	Master Natural Gas Gathering Agreement, dated February 2, 2000, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, Inc. and Viking Resources Corporation(2)
	10.1	(b)	Natural Gas Gathering Agreement, dated January 1, 2002, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas Resources, Inc., Atlas Energy Group, Inc., Atlas Noble Corp., Resource Energy, Inc. and Viking Resources Corporation(2)
	10.1	(c)	Amendment to Master Natural Gas Gathering Agreement, dated October 25, 2005, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, Inc., Viking Resources Corporation, Atlas Noble Corp., and Atlas Resources, Inc.(3)
	10.1	(d)	Amendment and Joinder to Gas Gathering Agreements, dated as of December 18, 2006, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, LLC, Viking Resources, LLC, Atlas Noble LLC, Atlas Resources, LLC, Atlas Energy Resources, LLC, and Atlas Energy Operating Company, LLC.(4)
	10.2	(a)	Omnibus Agreement, dated February 2, 2000, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, Inc. and Viking Resources Corporation(2)
	10.2	(b)	Amendment and Joinder to Omnibus Agreement, dated as of December 18, 2006 among Atlas Pipeline, Atlas America, Resource Energy, LLC, Viking Resources, LLC, Atlas Energy Resources, LLC, and Atlas Energy Operating Company, LLC(4)
	10.3		Tax Matters Agreement between Atlas America, Inc. and Resource America, Inc. date May 14, 2004(5)
	10.4		Transition Services Agreement between Atlas America, Inc. and Resource America, Inc. date May 14, 2004(5)
	10.5		Employment Agreement for Edward E. Cohen dated May 14, 2004(5)
	10.6		Agreement for Services among Atlas America, Inc. and Richard Weber, dated April 5, 2006(6)
	10.7		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)
	10.8		Omnibus Agreement, dated as of December 18, 2006, between Atlas America, Inc. and Atlas Energy Resources, LLC(4)
	10.9		Management Agreement, dated as of December 18, 2006, among Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC and Atlas Energy Management, Inc. (4)
	31.1		Rule 13a-14(a)/15d-14(a) Certification
	31.2		Rule 13a-14(a)/15d-14(a) Certification
	32.1		Section 1350 Certification
	32.2		Section 1350 Certification

(1)	Previously filed as an exhibit to our Form 8-K filed June 14, 2005
(2)	Previously filed as an exhibit to our registration statement on Form S-1 (registration no. 333-112653)
(3)	Previously filed as an exhibit to our Form 8-K dated October 31, 2005
(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

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SIGNATURES

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

	ATLAS AMERICA, INC.
Date: November 7, 2008	By:	/s/ EDWARD E. COHEN
		Edward E. Cohen
		Chairman of the Board and Chief Executive Officer
Date: November 7, 2008	By:	/s/ MATTHEW A. JONES
		Matthew A. Jones
		Chief Financial Officer
Date: November 7, 2008	By:	/s/ NANCY J. MCGURK
		Nancy J. McGurk
		Senior Vice President and Chief Accounting Officer

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