ARKHAN 10Q 2009 Q1 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 March 31, 2009


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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yeso 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. (Check one):


Large accelerated filerþ		Accelerated filero		Non-accelerated filero (Do not check if a 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 May 4, 2009 was 39,345,258 shares.

ATLAS AMERICA, INC. AND SUBSIDIARIES
INDEX TO QUARTERLY REPORT
ON FORM 10-Q


	PAGE
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

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

Consolidated Statements of Operations for the Three Months Ended March 31, 2009 and 2008 (Unaudited)		4

Consolidated Statement of Stockholders’ Equity for the Three Months Ended March 31, 2009 (Unaudited)		5

Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2009 and 2008 (Unaudited)		6

Notes to Consolidated Financial Statements (Unaudited)		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		52

Item 3. Quantitative and Qualitative Disclosures About Market Risk		72

Item 4. Controls and Procedures		81

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		81

Item 1A. Risk Factors		82

Item 6. Exhibits		83

SIGNATURES		86
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

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)


	March 31,			December 31,
	2009			2008
ASSETS
Current assets:
Cash and cash equivalents	$	87,401	��	$	104,571
Accounts receivable		147,158			181,770
Current portion of derivative receivable from Partnerships		94			3,022
Current portion of derivative asset		144,435			152,726
Prepaid expenses and other		27,635			27,337
Prepaid and deferred income taxes		20,038			31,343

Total current assets		426,761			500,769

Property, plant and equipment, net		4,071,816			3,986,741
Intangible assets, net		190,799			197,485
Goodwill, net		35,166			35,166
Long-term derivative receivable from Partnerships		8			2,719
Long term derivative asset		98,132			69,451
Other assets, net		54,749			53,550

	$	4,877,431		$	4,845,881


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	154,274		$	144,845
Liabilities associated with drilling contracts		30,276			96,883
Accrued producer liabilities		39,618			67,406
Current portion of derivative liability to Partnerships		39,864			34,933
Current portion of derivative liability		71,103			73,776
APL preferred unit redemption obligation		15,000			—
Accrued liabilities		123,290			109,275
Advances from affiliate		385			108

Total current liabilities		473,810			527,226

Long-term debt		2,515,875			2,413,082
Deferred tax liability		247,355			242,058
Long-term derivative liability to Partnerships		25,049			22,581
Long-term derivative liability		25,542			59,103
Other long-term liabilities		50,265			52,263
Commitments and contingencies

Stockholders’ equity:
Preferred stock, $0.01 par value: 1,000,000 authorized shares		—			—
Common stock, $0.01 par value: 49,000,000 authorized shares		426			426
Additional paid-in capital		413,815			412,869
Treasury stock, at cost		(143,403	)		(147,621	)
Accumulated other comprehensive income		44,591			21,143
Retained earnings		127,373			124,698

		442,802			411,515
Non-controlling interests		1,096,733			1,118,053

Total stockholders’ equity		1,539,535			1,529,568

	$	4,877,431		$	4,845,881

See accompanying notes to consolidated financial statements

ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(Unaudited)


	Three Months Ended
	March 31,
	2009			2008
Revenue:
Well construction and completion	$	112,368		$	104,138
Gas and oil production		71,943			76,226
Transmission, gathering and processing		179,673			385,326
Administration and oversight		3,853			5,017
Well services		5,093			4,798
Gain (loss) on mark-to-market derivatives		316			(88,781	)

Total revenue		373,246			486,724


Costs and expenses:
Well construction and completion		95,397			90,555
Gas and oil production		11,286			10,668
Transmission, gathering and processing		157,277			295,532
Well services		2,424			2,412
General and administrative		27,755			21,008
Net expense reimbursement — affiliate		482			250
Depreciation, depletion and amortization		52,707			43,652
Asset impairment		—			3,981

Total costs and expenses		347,328			468,058


Operating income		25,918			18,666

Other income (expense):
Interest expense		(34,646	)		(34,098	)
Other, net		4,880			2,030

Total other expense		(29,766	)		(32,068	)


Loss before income taxes		(3,848	)		(13,402	)
Income tax expense		(2,993	)		(3,841	)

Net loss		(6,841	)		(17,243	)
Loss attributable to non-controlling interests		11,484			23,665

Net income attributable to common shareholders	$	4,643		$	6,422


Net income attributable to common shareholders per share:
Basic	$	0.12		$	0.16

Diluted	$	0.11		$	0.15

Weighted average common shares outstanding:
Basic		39,281			40,324

Diluted		42,278			42,067

See accompanying notes to consolidated financial statements

ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

FOR THE THREE MONTHS ENDED MARCH 31, 2009

(in thousands, except share data)

(Unaudited)


													Accumulated
					Additional								Other					Non-			Total
	Common Stock				Paid-In		Treasury Stock						Comprehensive		Retained			controlling			Stockholders’
	Shares		Amount		Capital		Shares			Amount			Income		Earnings			Interests			Equity
Balance at January 1, 2009		42,503,119	$	426	$	412,869		(3,252,861	)	$	(147,621	)	$	21,143	$	124,698		$	1,118,053		$	1,529,568
Common stock issuance		—		—		—		95,000			4,218			—		—			—			4,218
Other comprehensive income		—		—		—		—			—			23,448		—			50,670			74,118
Stock option compensation expense		—		—		946		—			—			—		—			—			946
Dividends paid		—		—		—		—			—			—		(1,968	)		—			(1,968	)
Distributions to non-controlling interests		—		—		—		—			—			—		—			(36,319	)		(36,319	)
Non-controlling interests’ capital contributions		—		—		—		—			—			—		—			(24,187	)		(24,187	)
Net income (loss)		—		—		—		—			—			—		4,643			(11,484	)		(6,841	)

Balance at March 31, 2009		42,503,119	$	426	$	413,815		(3,157,861	)	$	(143,403	)	$	44,591	$	127,373		$	1,096,733		$	1,539,535

See accompanying notes to consolidated financial statements

ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)


	Three Months Ended
	March 31,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(6,841	)	$	(17,243	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		52,707			43,652
Asset impairment		—			3,981
Amortization of deferred finance costs		1,713			1,479
Non-cash loss on derivative value, net		45,490			79,842
Non-cash compensation expense		2,270			192
Gain on asset sales and dispositions		(7	)		(144	)
Distributions paid to non-controlling interests		(36,319	)		(52,650	)
Deferred income taxes		1,612			4,317
Changes in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable and prepaid expenses and other		38,636			(24,693	)
Accounts payable and accrued liabilities		(73,971	)		(71,683	)
Accounts payable and accounts receivable — affiliate		277			363
Other operating assets/liabilities		156			1,126

Net cash provided by (used in) operating activities		25,723			(31,461	)


CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(130,120	)		(139,686	)
Acquisition purchase price adjustment		—			1,281
Investment in Lightfoot Capital Partners, L.P.		(2	)		(440	)
Proceeds from sale of assets		114			—
Other		(38	)		(232	)

Net cash used in investing activities		(130,046	)		(139,077	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under Atlas Energy Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P. credit facilities		310,000			173,000
Repayments under Atlas Energy Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P. credit facilities		(217,000	)		(274,008	)
Issuance of Atlas Energy Resources, LLC long-term debt		—			250,000
Dividends paid		(1,968	)		(1,344	)
Deferred financing costs and other		(3,879	)		(6,259	)

Net cash provided by financing activities		87,153			141,389


Net change in cash and cash equivalents		(17,170	)		(29,149	)
Cash and cash equivalents, beginning of period		104,571			145,535

Cash and cash equivalents, end of period	$	87,401		$	116,386

See accompanying notes to consolidated financial statements

ATLAS AMERICA, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

NOTE 1 — BASIS OF PRESENTATION

Atlas America, Inc. (the “Company”) is a publicly traded (NASDAQ:ATLS) Delaware corporation whose assets consist primarily of cash and its ownership interests in the following entities as of March 31, 2009:

	•		Atlas Energy Resources, LLC (“Atlas Energy” or “ATN”), a publicly traded Delaware limited liability company (NYSE: ATN) which focuses on natural gas development and production in northern Michigan’s Antrim Shale, Indiana’s New Albany Shale and the Appalachian Basin, which the Company manages through its subsidiary, Atlas Energy Management, Inc., under the supervision of ATN’s board of directors. At March 31, 2009, the Company had a 48.3% ownership interest and owned all of the management incentive interests of ATN;

	•		Atlas Pipeline Partners, L.P. (“Atlas Pipeline Partners” or “APL”), a publicly traded Delaware limited partnership (NYSE: APL) and midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachia regions (NYSE:APL). At March 31, 2009, the Company had a 2.3% direct ownership interest in APL;

	•		Atlas Pipeline Holdings, L.P. (“Atlas Pipeline Holdings” or “AHD”), a publicly traded Delaware limited partnership (NYSE: AHD) and owner of the general partner of APL. Through the Company’s ownership of AHD’s general partner, it manages AHD. AHD’s cash generating assets currently consist solely of its interests in APL. At March 31, 2009, the Company owned approximately 64.4% of the outstanding common units of AHD. AHD owned a 2% general partner interest, all of the incentive distribution rights, an approximate 12.5% common limited partner interest, and 15,000 $1,000 par value 12.0% Class B cumulative preferred limited partner units; and

	•		Lightfoot Capital Partners, LP (“Lightfoot LP”) and Lightfoot Capital Partners GP LLC, (“Lightfoot GP”), the general partner of Lightfoot (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. 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 March 31, 2009, 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, 2008 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008. The results of operations for the three month period ended March 31, 2009 may not necessarily be indicative of the results of operations for the full year ending December 31, 2009. Certain amounts in the prior year’s consolidated financial statements have been reclassified to conform to the current year presentation, including $18.8 million of pre-development costs shown as component of “Property, plant, and equipment, net” which was previously combined with “Liabilities associated with drilling contracts” on the Company’s consolidated balance sheets.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Principles of Consolidation and Non-controlling Interest

The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly-owned except for ATN and AHD, which are controlled by the Company, and APL, which is controlled by AHD. The financial statements of AHD include its accounts and the accounts of its subsidiaries, all of which are wholly-owned except for APL. The non-controlling ownership interests in the net income (loss) of ATN, AHD and APL are reflected within non-controlling interests on the Company’s consolidated statements of operations, and the non-controlling interests in the assets and liabilities of ATN, AHD and APL are reflected as a component of stockholders’ equity on the Company’s consolidated balance sheets. All material intercompany transactions have been eliminated.

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

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

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

Use of Estimates

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

revenue and costs and expenses during the reporting periods. The Company’s consolidated financial statements are based on a number of significant estimates, including the revenue and expense accruals, deferred tax assets and liabilities, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. Actual results could differ from those estimates.

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

Impairment of Long-Lived Assets

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

The review of ATN’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on ATN’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. ATN estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, ATN’s reserve estimates for its investment in the Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include ATN’s actual capital contributions, an additional carried interest (generally 7% to 10%), a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

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

ATN’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Partnerships which ATN sponsors and owns an interest in but

does not control. ATN’s reserve quantities include reserves in excess of its proportionate share of reserves in a partnership which ATN may be unable to recover due to the partnership legal structure. ATN may have to pay additional consideration in the future as a well or Partnership becomes uneconomic under the terms of the Partnership agreement in order to recover these excess reserves and to acquire any additional residual interests in the wells held by other Partnership investors. The acquisition of any well interest from the Partnership by ATN is governed under the Partnership agreement and must be at fair market value supported by an appraisal of an independent expert selected by ATN.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate ATN will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. There were no impairments of oil and gas properties or unproved properties recorded by the Company for the three months ended March 31, 2009 and 2008.

Capitalized Interest

ATN and APL capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on combined borrowed funds by ATN and APL was 5.9% and 6.3% for the three months ended March 31, 2009 and 2008, respectively. The aggregate amount of interest capitalized by ATN and APL was $3.4 million and $2.6 million for the three months ended March 31, 2009 and 2008, respectively.

Intangible Assets

Customer contracts and relationships.APL has recorded intangible assets with finite lives in connection with natural gas gathering contracts and customer relationships assumed in certain consummated acquisitions. SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”) requires that intangible assets with finite useful lives be amortized over their estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset must be amortized over the best estimate of its useful life. At a minimum, APL will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. The estimated useful life for APL’s customer contract intangible assets is based upon the approximate average length of customer contracts in existence and expected renewals at the date of acquisition. The estimated useful life for APL’s customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition, adjusted for APL’s management’s estimate of whether the individual relationships will continue in excess or less than the average length.

Partnership management, operating contracts and non-compete agreement.ATN has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through consummated acquisitions. In addition, ATN entered into a two-year non-compete agreement in connection with the acquisition of Atlas Gas and Oil Company. ATN amortizes contracts acquired on a declining balance and straight-line method over their respective estimated useful lives.

The following table reflects the components of intangible assets being amortized at March 31, 2009 and December 31, 2008 (in thousands):


					Estimated
	March 31,		December 31,		Useful Lives
	2009		2008		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


							Estimated
	March 31,			December 31,			Useful Lives
	2009			2008			In Years
Non-compete agreement		890			890			2

	$	250,615		$	250,615


Accumulated Amortization:
Customer contracts and relationships	$	(48,124	)	$	(41,735	)
Partnership management and operating contracts		(10,913	)		(10,728	)
Non-compete agreement		(779	)		(667	)

	$	(59,816	)	$	(53,130	)


Net Carrying Amount:
Customer contracts and relationships	$	187,258		$	193,647
Partnership management and operating contracts		3,430			3,615
Non-compete agreement		111			223

	$	190,799		$	197,485

Amortization expense on intangible assets was $6.7 million for both the three months ended March 31, 2009 and 2008. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2009-$26.4 million; 2010-$26.3 million; 2011-$26.1 million; 2012-$25.7 million; and 2013-$24.6 million.

Goodwill

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


	Three Months Ended
	March 31,
	2009		2008
Balance, beginning of period	$	35,166	$	744,449
APL post-closing purchase price adjustment with seller and purchase price allocation adjustment — Chaney Dell and Midkiff/Benedum systems acquisition		—		(2,275	)
APL recovery of state sales tax initially paid on transaction — Chaney Dell and Midkiff/Benedum systems acquisition		—		(30,206	)

Balance, end of period	$	35,166	$	711,968

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

ATN tests its goodwill for impairment at each year end under the principles of SFAS No. 142 by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for its reporting units are not available, ATN’s management must apply judgment in determining the estimated fair value of these reporting units. ATN’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to ATN’s market capitalization. The principles of SFAS No. 142 and its interpretations acknowledge that the observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity’s individual equity securities. In most industries, including ATN’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, ATN also considers a control premium to the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ATN’s industry. The resultant fair values calculated for the reporting units are then compared to observable metrics on large mergers and acquisitions in ATN’s industry to determine whether those valuations appear reasonable in management’s judgment. The Company will continue to evaluate goodwill at least annually. During the three months ended March 31, 2009, no impairment indicators arose.

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

Net Income 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 16). 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
	March 31,
	2009		2008⁽¹⁾
Weighted average number of shares — basic		39,281		40,324
Add: effect of dilutive incentive awards		2,997		1,743

Weighted average number of common shares — diluted		42,278		42,067


(1)		The shares for the three months ended March 31, 2008 have been restated to reflect the three-for-two stock split on May 21, 2008.

Revenue Recognition

Atlas Energy.Certain energy activities are conducted by ATN through, and a portion of its revenues are attributable to, sponsored investment Partnerships. ATN contracts with the Partnerships to drill partnership wells. The contracts require that the Partnerships must pay ATN the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed 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 FERC-regulated transmission pipeline is comprised of firm transportation rates and, to the extent capacity is available following the reservation of firm system capacity, interruptible transportation rates and 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.

	•		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 March 31, 2009 and December 31, 2008 of $71.2 million and $92.1 million, respectively, which are included in accounts receivable within the Company’s consolidated balance sheets.

Comprehensive Income (Loss)

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


	Three Months Ended
	March 31,
	2009			2008
Net loss	$	(6,841	)	$	(17,243	)
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges, net of tax (provision) benefit of ($17,225) and $17,814 for the three months ended March 31, 2009 and 2008, respectively		73,450			(63,906	)
Less: reclassification adjustment for realized loss in net income, net of tax provision of $2,247 and $565 for the three months ended March 31, 2009 and 2008, respectively		646			11,681
Plus: amortization of additional post-retirement liability recorded upon adoption of SFAS No. 158, net of tax provision of $13 and $51 for the three months ended March 31, 2009 and 2008, respectively		22			121


Total other comprehensive income (loss), net of tax		74,118			(52,104	)

Comprehensive income (loss)		67,277			(69,347	)
Loss attributable to non-controlling interests		11,484			23,665
Other comprehensive income attributable to non-controlling interests		(50,670	)		21,449

Comprehensive income (loss) attributable to shareholders	$	28,091		$	(24,233	)

Recently Adopted Financial 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 was prohibited. All prior-period EPS data presented was adjusted retrospectively to conform to the provisions of this FSP. The Company applied the requirements of FSP EITF 03-6-1 upon its adoption on January 1, 2009 and the adoption of FSP EITF 03-6-1 had no impact on its financial position and results of operations.

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

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

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

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements-an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 amends ARB No. 51 to establish accounting and reporting standards for the non-controlling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 also requires consolidated net income to be reported, and disclosed on the face of the consolidated statement of operations, at amounts that include the amounts attributable to both the parent and the non-controlling interest. Additionally, SFAS No. 160 establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated. The Company

adopted the requirements of SFAS No. 160 on January 1, 2009 and adjusted the presentation of its financial position and results of operations. Prior period financial positions and results of operations have been adjusted retrospectively to conform to the provisions of SFAS No. 160.

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

NOTE 3 — APL ASSET SALE AGREEMENT

On March 31, 2009, APL and ATN entered into an agreement with subsidiaries of The Williams Companies, Inc. (NYSE: WMB) (“Williams”) to form a joint venture, Laurel Mountain Midstream, LLC (“Laurel Mountain”) that will own and operated APL’s Appalachia Basin natural gas gathering system, excluding APL’s Northern Tennessee operations. To the joint venture, Williams will contribute cash of $102.0 million, of which APL will receive approximately $90.0 million and a note receivable of $25.5 million. In addition, ATN will sell certain assets to the joint venture for $12.0 million. APL will contribute its Appalachia Basin natural gas gathering system and ATN will contribute two natural gas processing plants and associated pipelines. APL will retain a 49% ownership interest in the joint venture, as well as preferred distribution rights relating to all payments on the note receivable. Williams will retain the remaining 51% ownership interest in the joint venture and will manage the day-to-day operations. Upon the completion of the sale of the APL Appalachia gathering systems to Laurel Mountain, Laurel Mountain will enter into new gas gathering agreements with Atlas Energy, which will supersede the existing natural gas gathering agreements and omnibus agreement between APL and Atlas Energy. Under the proposed gas gathering agreement, ATN will be obligated to pay Laurel Mountain all of the gathering fees it collects from its partnerships plus any excess amount over the amount of the competitive gathering fee (which is currently defined as 13% of the gross sales price received for the partnerships’ gas). The proposed gathering agreement contains additional provisions which define certain obligations and options of each party to build and connect newly drilled wells to any Laurel Mountain gathering system. APL will account for its share of earnings associated with its ownership interest in Laurel Mountain under the equity method. The transaction is expected to close during the second quarter of 2009.

NOTE 4 — PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment are stated at cost. Depreciation, depletion and amortization are based on cost less estimated salvage value primarily using the unit-of-production or straight-line methods over the asset’s estimated useful life. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.

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


							Estimated
	March 31,			December 31,			Useful Lives
	2009			2008			in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,224,341		$	1,214,991
Predevelopment costs		15,838			18,772
Wells and related equipment		918,973			872,128

Total proved properties		2,159,152			2,105,891
Unproved properties		44,291			43,749
Support equipment		9,177			9,527

Total natural gas and oil properties		2,212,620			2,159,167
Pipelines, processing and compression facilities		2,054,900			1,980,805			15 - 40
Rights of way		180,373			178,262			20 - 40
Land, buildings and improvements		24,463			24,434			10 - 40
Other		22,308			23,026			3 - 10

		4,494,664			4,365,694

Less — accumulated depreciation, depletion and amortization		(422,848	)		(378,953	)

	$	4,071,816		$	3,986,741

During the three months ended March 31, 2008, the Company recognized an impairment charge totaling $4.0 million within asset impairment loss on its consolidated statements of operations in connection with a write-off of costs related to an APL pipeline expansion project. The costs incurred consisted of a vendor deposit for the manufacture of pipeline which expired in accordance with APL’s contractual arrangement.

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

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to income. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the statements of income. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

NOTE 5 — OTHER ASSETS

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


	March 31,		December 31,
	2009		2008
Deferred finance costs, net of accumulated amortization of $24,819 and $23,106 at March 31, 2009 and December 31, 2008, respectively	$	40,154	$	38,836
Investments		12,588		12,702
Security deposits		1,877		1,719
Other		130		293

	$	54,749	$	53,550

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 7).

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

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 and related facilities. Under SFAS No. 143, the Company must currently recognize a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. SFAS No. 143 requires the Company to consider estimated salvage value in the calculation of depreciation, depletion and amortization. The Company’s asset retirement obligations consist principally of the plugging and abandonment of ATN’s oil and gas wells.

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

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


	Three Months Ended
	March 31,
	2009			2008
Asset retirement obligations, beginning of period	$	48,136		$	42,358
Liabilities incurred		430			782
Liabilities settled		(62	)		(2	)
Accretion expense		758			663

Asset retirement obligations, end of period	$	49,262		$	43,801

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):


	March 31,		December 31,
	2009		2008
ATN revolving credit facility	$	538,000	$	467,000
ATN 10.75 % senior notes — due 2018		406,472		406,655
AHD revolving credit facility		46,000		46,000
APL revolving credit facility		324,000		302,000
APL term loan		707,180		707,180
APL 8.125 % senior notes — due 2015		271,173		261,197
APL 8.75 % senior notes — due 2018		223,050		223,050

Total long-term debt		2,515,875		2,413,082
Less current maturities		—		—

Total debt	$	2,515,875	$	2,413,082

ATN Revolving Credit Facility

At March 31, 2009, ATN had a credit facility with a syndicate of banks with a borrowing base of $697.5 million that matures in June 2012. The borrowing base will be redetermined semiannually on April 1 and October 1 subject to changes in ATN’s oil and gas reserves. Up to $50.0 million of the facility may be in the form of standby letters of credit, of which $1.2 million was outstanding at March 31, 2009, which are not reflected as borrowings on the Company’s consolidated balance sheets. The facility is secured by substantially all of ATN’s assets and is guaranteed by each of its subsidiaries and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at ATN’s option. At March 31, 2009 and December 31, 2008, the weighted average interest rate on outstanding borrowings was 2.5% and 2.8%, respectively.

The base rate for any day equals the higher of the federal funds rate plus 0.50% or the J.P. Morgan prime rate or the adjusted LIBOR for a month interest period plus 1.0%. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for Eurocurrency liabilities.

The events which constitute an event of default for ATN’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against ATN in excess of a specified amount, and a change of control. In addition, the agreement limits sales, leases or transfers of assets and the incurrence of additional indebtedness. The agreement limits the distributions payable by ATN if an event of default has occurred and is continuing or would occur as a result of such distribution. ATN is in compliance with these covenants as of March 31, 2009. The credit facility also requires ATN to maintain a ratio of current assets (as defined in the credit facility) to current liabilities (as defined in the credit facility) of not less than 1.0 to 1.0, and a ratio of total debt (as defined in the credit facility) to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”, as defined in the credit facility) of 3.75 to 1.0 commencing January 1, 2009, and decreasing to 3.5 to 1.0 commencing January 1, 2010 and thereafter. According to the definitions contained in ATN’s credit facility, ATN’s ratio of current assets to current liabilities was 1.2 to 1.0 and its ratio of total debt to EBITDA was 3.2 to 1.0 at March 31, 2009.

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. Both issues of senior unsecured notes 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. ATN is in compliance with these covenants as of March 31, 2009.

AHD Credit Facility

At March 31, 2009, AHD had $46.0 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. 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 March 31, 2009 was 3.2%. 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 Atlas Pipeline GP’s interests in APL, and are guaranteed by Atlas Pipeline GP and AHD’s other subsidiaries (excluding APL and its subsidiaries). AHD’s credit facility contains customary covenants, including restrictions on its ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to AHD’s unitholders if an event of default exists or would result from such distribution or enter into a merger or sale of substantially all of AHD’s property or assets, including the sale or transfer of interests in its subsidiaries. AHD is in compliance with these covenants as of March 31, 2009.

The events which constitute an event of default under AHD’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreements, adverse judgments against AHD in excess of a specified amount, a change of control of 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 March 31, 2009, AHD’s combined leverage ratio was 5.1 to 1.0, its funded debt to EBITDA was 1.5 to 1.0, and its interest coverage ratio was 16.8 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 March 31, 2009, APL had a senior secured credit facility with a syndicate of banks which consisted of a term loan which matures in July 2014 and a $380.0 million revolving credit facility which matures in July 2013. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding APL revolving credit facility borrowings at March 31, 2009 was 2.8%, and the weighted average interest rate on the outstanding APL term loan borrowings at March 31, 2009 was 3.3%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $5.4 million was outstanding at March 31, 2009. These outstanding letter of credit amounts are 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 derivative contracts (see Note 8) in calculating its Consolidated EBITDA. Pursuant to this amendment, in June 2008, APL repaid $122.8 million of its outstanding term loan and repaid $120.0 million of outstanding borrowings under the credit facility with proceeds from its issuance of $250.0 million of 10-year, 8.75% senior unsecured notes (see “APL Senior Notes”). Additionally, pursuant to this amendment, 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 March 31, 2009. Mandatory prepayments of the amounts borrowed under the term loan portion of the credit facility are required from the net cash proceeds of debt and equity 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 entering into the credit facility, APL agreed to remit an underwriting fee to the lead underwriting bank based upon the aggregate principal amount of the term loan outstanding, subject to adjustments as stated in the agreement. APL recorded an obligation for this fee of approximately $2.9 million within other assets and accrued liabilities on the Company’s consolidated balance sheet at March 31, 2009. APL has recognized this amount as a non-cash transaction within the Company’s consolidated statement of cash flows for the three months ended March 31, 2009.

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 March 31, 2009, APL’s ratio of funded debt to EBITDA was 4.9 to 1.0 and its interest coverage ratio was 4.0 to 1.0.

APL is unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement.

APL Senior Notes

At March 31, 2009, APL had $223.1 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“APL 8.75% Senior Notes”) and $270.5 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 $0.6 million of unamortized premium received as of March 31, 2009. Interest on the APL Senior Notes in the aggregate is payable semi-annually in arrears on June 15 and December 15. The APL Senior Notes are redeemable at any time at certain redemption prices, together with accrued and unpaid interest to the date of redemption. Prior to June 15, 2011, APL may redeem up to 35% of the aggregate principal amount of the APL 8.75% Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The APL 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.

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

Indentures governing the APL Senior Notes in the aggregate contain covenants, including limitations of APL’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. APL is in compliance with these covenants as of March 31, 2009.

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

NOTE 8 — DERIVATIVE INSTRUMENTS

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

The Company and its subsidiaries formally document all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity and interest derivative contracts to the forecasted transactions. The Company and its subsidiaries assess, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Company and its subsidiaries will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by the Company and its subsidiaries through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s consolidated statements of operations. For derivatives qualifying as hedges, the Company and its subsidiaries recognize the effective portion of changes in fair value in stockholders’ equity as accumulated other comprehensive income and reclassifies the portion relating to commodity derivatives to gas and oil production revenues for ATN derivatives, gathering, transmission and processing revenues for APL derivatives, and the portion relating to interest rate derivatives to interest expense within the Company’s consolidated statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Company and its subsidiaries recognize changes in fair value within gain (loss) on mark-to-market derivatives in its consolidated statements of operations as they occur.

Derivatives are recorded on the Company’s consolidated balance sheet as assets or liabilities at fair value. The Company reflected net derivative assets on its consolidated balance sheets of $145.9 million and $89.3 million at March 31, 2009 and December 31, 2008, respectively. Of the $44.6 million of net gain in accumulated other comprehensive income within stockholders’ equity on the Company’s consolidated balance sheet at March 31, 2009, if the fair values of the instruments remain at current market values, the Company will reclassify $26.5 million of gains to the Company’s consolidated statements of operations over the next twelve month period as these contracts expire, consisting of $30.5 million of gains primarily to gas and oil production revenues, $2.5 million of losses to gathering, transmission and processing revenues and $1.5 million of losses to interest expense. Aggregate gains of $18.3 million will be reclassified to the Company’s consolidated statements of operations in later periods as these remaining contracts expire, consisting of $21.8 million of gains to gas and oil production revenues, $2.4 million of losses to gathering, transmission and processing revenues and $1.1 million of losses to interest expense. Actual amounts that will be reclassified will vary as a result of future price changes.

Atlas Energy

Commodity Risk Hedging Program. Forward contracts on natural gas and oil are entered into to manage the price risk associated with forecasted sales of natural gas and crude oil. Interest rate swaps are entered into to manage interest rate risk associated with the Company’s variable rate borrowings. In accordance with

SFAS No. 133, the Company designates these derivatives as cash flow hedges and the derivative instruments have been recorded as either assets or liabilities at fair value in the consolidated balance sheet. The effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified to earnings in the same period during which the hedged transaction affects earnings. The following table summarizes the fair value of derivative instruments as of March 31, 2009 and December 31, 2008, as well as the gain or loss recognized for the three months ended March 31, 2009 and 2008. There were no gains or losses recognized in income for ineffective derivative instruments for the three months ended March 31, 2009 and 2008.

Fair Value of Derivative Instruments


	March 31, 2009
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives in SFAS No. 133 Cash Flow Hedging Relationships:
Commodity contracts	Current portion of derivative asset	$	144,435	Current portion of derivative liability	$	(344	)
	Long-term asset		98,132	Long-term liability		(31	)

			242,567			(375	)

Interest rate contracts	Current portion of derivative asset		—	Current portion of derivative liability		(3,494	)
	Long-term derivative asset		—	Long-term derivative liability		(2,219	)

			—			(5,713	)


Total derivatives under SFAS No. 133		$	242,567		$	(6,088	)

Effects of Derivative Instruments on Consolidated Statements of Operations:


	March 31, 2009
				Location of
				Gain/(Loss)
	Gain/(Loss)			Reclassified from	Gain/(Loss)
	Recognized in OCI			Accumulated OCI	Reclassified from
	on Derivatives			into Income	OCI into Income
	(Effective Portion)			(Effective Portion)	(Effective Portion)
Derivatives in SFAS No. 133 Cash Flow Hedging Relationships:
Commodity contracts	$	86,814		Gas and oil production	$	15,518
Interest rate contracts		(873	)	Interest expense		(1,002	)

	$	85,941			$	(14,516	)

As of March 31, 2009, ATN had the following interest rate and commodity derivatives:

Interest Fixed Rate Swap


				Contract
	Notional			Period Ended	Fair Value
Term	Amount		Option Type	December 31,	Liability
					(in thousands)
January 2008 — January 2011	$	150,000,000	Pay 3.11% - Receive LIBOR	2009	$	(2,649	)
				2010		(2,877	)
				2011		(187	)

					$	(5,713	)

Natural Gas Fixed Price Swaps


Production
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset⁽¹⁾
	(MMBtu)		(per MMBtu)		(in thousands)
2009		31,020,000	$	8.24	$	122,338
2010		26,360,000	$	8.11		56,679
2011		18,680,000	$	7.84		21,031
2012		13,800,000	$	8.06		14,349
2013		1,500,000	$	8.73		2,225

					$	216,622

Natural Gas Costless Collars


Production
Period Ending				Average		Fair Value
December 31,	Option Type	Volumes		Floor and Cap		Asset⁽¹⁾
		(MMBtu)		(per MMBtu)		(in thousands)
2009	Puts purchased		180,000	$	11.00	$	1,201
2009	Calls sold		180,000	$	15.35		—
2010	Puts purchased		3,360,000	$	7.84		7,034
2010	Calls sold		3,360,000	$	9.01		—
2011	Puts purchased		7,500,000	$	7.48		7,750
2011	Calls sold		7,500,000	$	8.44		—
2012	Puts purchased		1,020,000	$	7.00		407
2012	Calls sold		1,020,000	$	8.32		—
2013	Puts purchased		300,000	$	7.00		69
2013	Calls sold		300,000	$	8.25		—

						$	16,461

Crude Oil Fixed Price Swaps


Production
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset⁽²⁾
	(Bbl)		(per Bbl)		(in thousands)
2009		47,300	$	99.73	$	2,206
2010		48,900	$	97.40		1,725
2011		42,600	$	96.44		1,226
2012		33,500	$	96.00		833
2013		10,000	$	96.06		232

					$	6,222

Crude Oil Costless Collars


Production
Period Ending				Average		Fair Value
December 31,	Option Type	Volumes		Floor and Cap		Asset⁽²⁾
		(Bbl)		(per Bbl)		(in thousands)
2009	Puts purchased		29,000	$	85.00	$	944
2009	Calls sold		29,000	$	117.48		—
2010	Puts purchased		31,000	$	85.00		817
2010	Calls sold		31,000	$	112.92		—
2011	Puts purchased		27,000	$	85.00		603
2011	Calls sold		27,000	$	110.81		—
2012	Puts purchased		21,500	$	85.00		416
2012	Calls sold		21,500	$	110.06		—
2013	Puts purchased		6,000	$	85.00		107
2013	Calls sold		6,000	$	110.09		—

						$	2,887

		Total ATN net asset				$	236,479


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

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

ATN’s commodity price risk management includes estimated future natural gas and crude oil production of the Partnerships. Therefore, a portion of any unrealized derivative gain or loss is allocable to the limited partners of the Partnerships based on their share of estimated future gas and oil production related to the hedges not yet settled. At March 31, 2009 and December 31, 2008, unrealized derivative liabilities of $64.8 million and $51.8 million are payable to the limited partners in the Partnerships and are included in the consolidated balance sheets as follows (in thousands):


	March 31,			December 31,
	2009			2008
Unrealized derivative loss — short-term	$	94		$	3,022
Other assets — long-term		8			2,719
Accrued liabilities — short-term		(39,864	)		(34,933	)
Unrealized derivative gain — long-term		(25,049	)		(22,581	)

	$	(64,811	)	$	(51,773	)

Interest Rate Risk Hedging Program. At March 31, 2009, ATN had debt outstanding of $538.0 million under its revolving credit facility. In January 2008, ATN entered into derivative contracts in the form of interest rate swaps to reduce the impact of volatility of changes in the London interbank offered rate (“LIBOR”). ATN has LIBOR interest rate swaps at a three-year fixed swap rate of 3.11% on $150.0 million of outstanding debt through January 2011. The swaps have been designated as cash flow hedges to minimize the risk associated with changes in the designated benchmark interest rate (in this case, LIBOR) related to forecasted payments associated with interest on the credit facility. ATN has accounted for the interest rate swaps under the “long-haul” method to measure ineffectiveness under SFAS No. 133. Using the change in variable cash flow method, no hedge ineffectiveness was identified. The value of ATN’s cash flow hedges included in accumulated other comprehensive income was a net unrecognized loss of approximately $5.7

million and $5.8 million at March 31, 2009 and December 31, 2008, respectively. ATN recognized a loss on settled swaps of $1.0 million and a gain of $0.1 million for the three months ended March 31, 2009 and 2008, respectively.

Atlas Pipeline Holdings and Atlas Pipeline Partners

Beginning July 1, 2008, APL discontinued hedge accounting for its existing commodity derivatives which were qualified as hedges under SFAS No. 133. As such, subsequent changes in fair value of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s consolidated statements of operations. The fair value of these commodity derivative instruments at June 30, 2008, which was recognized in accumulated other comprehensive income within stockholders’ equity on the Company’s consolidated balance sheet, will be reclassified to the Company’s consolidated statements of operations in the future at the time the originally hedged physical transactions affect earnings.

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


	Early Termination of Derivative
	Contracts for the
	Three Months Ended March 31,
	2009			2008
Net cash derivative expense included within gain (loss) on mark-to-market derivatives, net	$	(5,000	)	$	—
Net non-cash derivative income included within gain (loss) on mark-to-market derivatives, net		12,103			—
Net non-cash derivative expense included within gathering, transmission and processing revenue		(21,944	)		—

At March 31, 2009, AHD had an interest rate derivative contract having an aggregate notional principal amount of $25.0 million, which was designated as a cash flow hedge. Under the terms of the agreement, AHD will pay an interest rate of 3.01%, plus the applicable margin as defined under the terms of its revolving credit facility (see Note 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 is effective at March 31, 2009 and expires on May 28, 2010.

At March 31, 2009, APL had 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 the APL’s floating rate debt under the term loan and revolving credit facility to fixed-rate debt. The APL interest rate swap agreements were effective as of March 31, 2009 and expire during periods ranging from January 30, 2010 through April 30, 2010.

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


	Three Months Ended
	March 31,
	2009			2008
Loss from cash and non-cash settlement of qualifying derivative instruments⁽¹⁾	$	(20,175	)	$	(17,643	)
Loss from change in market value of non-qualifying derivatives⁽²⁾		(44,990	)		(71,196	)
Gain (loss) from change in market value of ineffective portion of qualifying derivatives⁽²⁾		10,813			(5,660	)
Gain (loss) from cash and non-cash settlement of non-qualifying derivatives⁽²⁾		34,495			(11,925	)
Loss from cash settlement of interest rate derivatives⁽³⁾		(3,055	)		—


(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 on the Company’s consolidated statements of operations.

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

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


	March 31, 2009
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Current portion of derivative asset	$	—	Current portion of derivative liability	$	(10,252	)
Interest rate contracts	Long-term derivative asset		—	Long-term derivative liability		(523	)
Derivatives not designated as hedging instruments under SFAS No. 133:
Commodity contracts	Current portion of derivative liability		3,977	Current portion of derivative liability		(60,991	)
Commodity contracts	Long-term derivative liability		2,380	Long-term derivative liability		(25,147	)

		$	6,357		$	(96,913	)

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


	March 31, 2009
			Gain (Loss)	Location of Gain
			Recognized in	(Loss) Recognized in
			Income on	Income on
	Amount of Gain		Derivative	Derivative
	(Loss) Reclassified	Location of Gain	(Ineffective	(Ineffective Portion
	from	(Loss) Reclassified	Portion and	and Amount
	Accumulated OCI	from Accumulated	Amount Excluded	Excluded from
	into Income	OCI into Income	from Effectiveness	Effectiveness
	(Effective Portion)	(Effective Portion)	Testing)	Testing)
Derivatives in SFAS No. 133 Cash Flow Hedging Relationships:
Interest rate contracts	$ (3,055)	Interest expense	$ —	N/A
Derivatives not designated as hedging instruments under SFAS No. 133:
Commodity contracts⁽¹⁾	(15,970)	Transmission, gathering and processing revenue	(9,527)	Gain (loss) on mark-to-market derivatives
Commodity contracts⁽²⁾	—		39,820	Gain (loss) on mark-to-market derivatives

	$(19,025)		$30,293


(1)		Hedges previously designated as cash flow hedges

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

As of March 31, 2009, AHD had the following interest rate derivatives:

Interest Fixed-Rate Swap


	Notional			Contract Period	Fair Value
Term	Amount		Type	Ended December 31,	Liability⁽¹⁾
					(in thousands)
May 2008- May 2010	$	25,000,000	Pay 3.01% —Receive LIBOR	2009	$	(444	)
				2010		(204	)

Total AHD net liability					$	(648	)


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

As of March 31, 2009, 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,	Liability⁽¹⁾
					(in thousands)
January 2008- January 2010	$	200,000,000	Pay 2.88% —Receive LIBOR	2009	$	(3,374	)
				2010		(304	)

					$	(3,678	)


April 2008- April 2010	$	250,000,000	Pay 3.14% —Receive LIBOR	2009	$	(4,715	)
				2010		(1,734	)

					$	(6,449	)

Natural Gas Liquids Sales — Fixed Price Swaps

Production Period

Average

Fair Value

Ended December 31,

Volumes

Fixed Price

Asset⁽²⁾

(gallons)

(per gallon)

(in thousands)

2009

13,230,000

0.745

1,579

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)⁽¹⁾			Option Type
	(barrels)		(gallons)		(per barrel)		(in thousands)
2009		152,100		13,542,984	$	111.53	$	(11,171	)	Puts sold⁽⁴⁾
2009		152,100		13,542,984	$	157.82		—		Calls purchased⁽⁴⁾
2009		1,588,500		88,643,058	$	84.69		(2,019	)	Calls sold
2010		3,127,500		213,088,050	$	86.20		(13,035	)	Calls sold
2010		714,000		45,415,440	$	132.17		638		Calls purchased⁽⁴⁾
2011		606,000		33,145,560	$	100.70		(3,071	)	Calls sold
2011		252,000		13,547,520	$	133.16		665		Calls purchased⁽⁴⁾
2012		450,000		25,893,000	$	102.71		(2,822	)	Calls sold
2012		180,000		9,676,800	$	134.27		657		Calls purchased⁽⁴⁾

							$	(30,158	)

Natural Gas Sales — Fixed Price Swaps

Production Period

Average

Fair Value

Ended December 31,

Volumes

Fixed Price

Asset⁽³⁾

(mmbtu)⁽⁵⁾

(per mmbtu)⁽⁵⁾

(in thousands)

2009

360,000

8.000

1,337

Natural Gas Basis Sales


Production Period			Average			Fair Value
Ended December 31,	Volumes		Fixed Price			Asset⁽³⁾
	(mmbtu)⁽⁵⁾		(per mmbtu)⁽⁵⁾			(in thousands)
2009		3,690,000	$	(0.558	)	$	673
2010		2,220,000	$	(0.575	)		301

						$	974

Natural Gas Purchases — Fixed Price Swaps


Production Period			Average		Fair Value
Ended December 31,	Volumes		Fixed Price		Liability⁽³⁾
	(mmbtu)⁽⁵⁾		(per mmbtu)⁽⁵⁾		(in thousands)
2009		7,740,000	$	8.687	$	(34,069	)
2010		4,380,000	$	8.635		(12,806	)

					$	(46,875	)

Natural Gas Basis Purchases


Production Period			Average			Fair Value
Ended December 31,	Volumes		Fixed Price			Liability⁽³⁾
	(mmbtu)⁽⁵⁾		(per mmbtu)⁽⁵⁾			(in thousands)
2009		11,070,000	$	(0.659	)	$	(2,837	)
2010		6,600,000	$	(0.560	)		(1,783	)

						$	(4,620	)

Ethane Put Options

Production Period

Associated

Average

Ended

NGL

Crude

Fair Value

December 31,

Volume

Strike Price

Asset⁽¹⁾

Option Type

(gallons)

(per gallon)

(in thousands)

2009

630,000

0.340

Puts purchased

Isobutane Put Options

Production Period

Associated

Average

Ended

NGL

Crude

Fair Value

December 31,

Volume

Strike Price

Liablity⁽¹⁾

Option Type

(gallons)

(per gallon)

(in thousands)

2009

126,000

0.589

(10

)

Puts purchased

Normal Butane Put Options

Production Period

Associated

Average

Ended

NGL

Crude

Fair Value

December 31,

Volume

Strike Price

Liablity⁽¹⁾

Option Type

(gallons)

(per gallon)

(in thousands)

2009

126,000

0.577

(10

)

Puts purchased

Natural Gasoline Put Options

Production Period

Associated

Average

Ended

NGL

Crude

Fair Value

December 31,

Volume

Strike Price

Liablity⁽¹⁾

Option Type

(gallons)

(per gallon)

(in thousands)

2009

126,000

0.762

(10

)

Puts purchased

Crude Oil Sales


Production Period			Average		Fair Value
Ended December 31,	Volumes		Fixed Price		Asset⁽³⁾
	(barrels)		(per barrel)		(in thousands)
2009		24,000	$	62.700	$	205

Crude Oil Sales Options


Production Period			Average		Fair Value
Ended December 31,	Volumes		Strike Price		Liability⁽¹⁾			Option Type
	(barrels)		(per barrel)		(in thousands)
2009		229,500	$	84.802	$	(314	)	Calls sold
2010		234,000	$	88.088		(912	)	Calls sold
2011		72,000	$	93.109		(502	)	Calls sold
2012		48,000	$	90.314		(478	)	Calls sold

					$	(2,206	)


Total APL net liability					$	(89,909	)


⁽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 for 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.

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


	March 31,			December 31,
	2009			2008
Current portion of derivative asset	$	144,435		$	152,726
Long-term derivative asset		98,132			69,451
Current portion of derivative liability		(71,103	)		(73,776	)
Long-term derivative liability		(25,542	)		(59,103	)

Total Company net asset	$	145,922		$	89,298

NOTE 9 — FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company applies the provisions of SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”) at January 1, 2008 to its financial instruments. SFAS No. 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS No. 157’s hierarchy defines three levels of inputs that may be used to measure fair value:

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Company uses the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities for ATN’s, APL’s and AHD’s outstanding commodity derivative contracts (see Note 8) and the Company’s Supplemental Employment Retirement Plan (“SERP” — see Note 16). 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, 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 March 31, 2009 (in thousands):


	Level 1		Level 2			Level 3			Total
SERP liability	$	—	$	(126	)	$	—		$	(126	)
Interest rate derivatives		—		(16,488	)		—			(16,488	)
APL commodity-based derivatives		—		(48,978	)		(30,803	)		(79,781	)
ATN commodity-based derivatives		—	$	242,192			—		$	242,192

Total	$	—	$	176,600		$	(30,803	)	$	145,797

APL’s Level 3 fair value amount relates to its derivative contracts on NGL fixed price swaps and crude oil options. The following table provides a summary of changes in fair value of APL’s Level 3 derivative instruments as of March 31, 2009 (in thousands):


				Crude Oil
				Sales
	NGL			Options
	Fixed			(associated			Crude Oil
	Price			with NGL			Sales			NGL Sales
	Swaps			Volume)			Options			Options			Total
Balance — December 31, 2008	$	1,509		$	(15,867	)	$	(7,569	)	$	12,316		$	(9,611	)
New options contracts		459			—			—			—			459
Cash settlements from unrealized gain (loss)⁽¹⁾		(2,240	)		(30,189	)		(7,482	)		(11,410	)		(51,321	)
Cash settlements from other comprehensive income⁽¹⁾		1,895			7,952			3,666			—			13,513
Net change in unrealized gain (loss)⁽²⁾		(44	)		9,008			5,878			(982	)		13,860
Deferred option premium recognition		—			(1,062	)		3,301			58			2,297
Net change in other comprehensive income		—			—			—			—			—

Balance — March 31, 2009	$	1,579		$	(30,158	)	$	(2,206	)	$	(18	)	$	(30,803	)


(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 on the Company’s consolidated statements of operations.

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

The Company estimates the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements; the credit-adjusted risk-free rate of the Company; and estimated inflation rates. See Note 4 — “Asset Retirement Obligations” for a summary of activity for the three months ended March 31, 2009 and 2008.

Information for assets that are measured at fair value on a nonrecurring basis for the three months ended March 31, 2009 and 2008 is as follows (in thousands):


	Three Months Ended				Three Months Ended
	March 31, 2009				March 31, 2008
	Level 3		Total		Level 3		Total
Asset retirement obligations incurred in current period	$	430	$	430	$	782	$	782

Total	$	430	$	430	$	782	$	782

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, the Partnerships. ATN serves as general partner of the Partnerships and assumes customary rights and obligations for the Partnerships. As the general partner, ATN is liable for the Partnerships’ liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Partnerships. ATN is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Partnerships’ revenue, and costs and expenses according to the respective Partnership agreements.

Relationship with Resource America, Inc.The Company has two agreements that govern its ongoing relationship with Resource America, Inc. (“RAI”), its former parent, that are still in effect at March 31, 2009. These agreements are the tax matters agreement and the transition services agreement. The tax matters agreement governs the respective rights, responsibilities and obligations of the Company and RAI with respect to tax liabilities and benefits, tax attributes, tax contests and other matters regarding income taxes, non-income taxes and related tax matters. The transition services agreement governs the provision of support services by the Company to RAI and by RAI to the Company, such general and administrative functions. The Company reimburses RAI for various costs and expenses it incurs for these services on behalf of the Company, primarily payroll and rent. For the three months ended March 31, 2009 and 2008, the Company’s reimbursements to RAI totaled $0.3 million and $0.3 million, respectively. At March 31, 2009 and December 31, 2008, reimbursements to RAI totaling $0.4 million and $0.1 million, respectively, which remain to be settled between the parties, were reflected in the Company’s consolidated balance sheets as advances to/from affiliate.

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 the Company, as managing general partner. ATN is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on past experience, the 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. For the three months ended March 31, 2009, $0.2 million of the Company’s net revenues were subordinated, which reduced its cash distribution received in April 2009. No subordination was required for the three months ended March 31, 2008.

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

As of March 31, 2009, the Company and its subsidiaries are committed to expend approximately $56.7 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. On December 15, 2008, the Chancery Court dismissed the matter in its entirety, holding that there had been no breach of the contract by Miller and, therefore, that Atlas America could not have tortuously interfered with the contract. The Chancery Court dismissed all claims against the Company; however, CNX has appealed this decision.

In January 2009, in the matter captioned “Elk City Oklahoma Pipeline, L.P. v. Northern Natural Gas Company”, (District Court of Tulsa County, Oklahoma), Elk City Oklahoma Pipeline, L.P. (“Elk City”), a subsidiary of APL’s, filed a petition against Northern Natural Gas Company (“NNG”), seeking a declaratory judgment related to the interpretation of a Purchase and Sale Agreement for certain pipeline and assets in Western Oklahoma which was entered into between the two parties on June 12, 2008 (the “PSA”). In March 2009, NNG filed a petition together with a motion for summary judgment alleging breach of the PSA for Elk City’s failure to complete the purchase and seeking specific performance or, alternatively, damages, in the matter captioned “Northern Natural Gas Company vs. Elk City Oklahoma Pipeline, L.P.”, (District Court of Tulsa County, Oklahoma). Both matters are currently pending. APL believes that the claims are without merit and intend to pursue its action and defend against NNG’s claims. Additionally, APL believes that the ultimate resolution of these matters will not consequently have a material impact on our financial position and results of operations.

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

NOTE 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 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 applies the provisions of FASB Interpretation 48, Accounting for Uncertainty in Income Taxes (“FIN 48”)to its income tax positions. As required by FIN 48, which clarifies Statement 109,Accounting for Income Taxes,the Company recognizes the financial statement benefit of a tax position after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. The Company had applied FIN 48 to all tax positions for which the statute of limitation remains open, and there were no additions, reductions or settlements in unrecognized tax benefits during the three months ended March 31, 2009 and 2008. The Company has no material uncertain tax positions at March 31, 2009.

The Company is subject to income taxes in the U.S. federal jurisdiction and various states. Tax regulations within each jurisdiction are subject to the interpretations of the related tax laws and regulations and require significant judgment to apply. With few exceptions, the Company is no longer subject to U.S. federal, state, and local, or non-U.S. income tax examinations by tax authorities for the years before 2005. The Company’s policy is to reflect interest and penalties related to uncertain tax positions as part of the income tax expense, when and if they become applicable.

NOTE 13 — COMMON STOCK

Treasury Shares Contribution

In March 2009, the Company issued 95,000 common shares from treasury to the trustee of its 401(k) plan so that the shares may be utilized for future employee purchases of the Company’s stock through the 401(k) plan. As a result of the transaction, the Company has recorded $4.2 million within prepaid expenses and other and an increase in common stock within stockholders’ equity on its consolidated balance sheet as of March 31, 2009. The average price per share for the common shares issued was $44.40 based upon the weighted average price that the shares were repurchased at into treasury on a first-in, first-out basis. The Company has recognized the $4.2 million as a non-cash transaction within its consolidated statement of cash flows for the three months ended March 31, 2009.

Stock Repurchase Plan

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

Stock Splits

On April 22, 2008, the Company’s Board of Directors approved a three-for-two stock split of the Company’s common stock effected in the form of a 50% stock dividend. All shareholders of record as of May 21, 2008 received one additional share of common stock for every two shares of common stock held on that date. The additional shares of common stock were distributed on May 30, 2008. Information pertaining to shares and earnings per share has been restated for the three months ended March 31, 2008 in the

accompanying consolidated financial statements and notes to the consolidated financial statements to reflect this split.

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”) and SFAS No. 160. The Company has adopted a policy to recognize gains on such transactions as a credit to equity rather than as income. These gains represent the Company’s portion of the excess net offering price per unit of each of its subsidiary’s units to the book carrying amount per unit.

On March 30, 2009, AHD, pursuant to its right within the APL Class B Preferred Units Certificate of Designation, purchased an additional 5,000 APL Class B Preferred Units at Face Value. APL used the proceeds from the sale of the APL Class B Preferred Units for general partnership purposes. The APL Class B Preferred Units receive distributions of 12.0% per annum, paid quarterly on the same date as the distribution payment date for APL’s common units. The record date of determination for holders entitled to receive distributions of the APL Class B Preferred Units will be the same as the record date of determination for APL’s common unit holders entitled to receive quarterly distributions. Additionally, on March 30, 2009, APL and AHD agreed to amend the terms of the APL Class B Preferred Units Certificate of Designation to remove the conversion feature, thus the APL Class B Preferred Units are not convertible into APL common units. The amended APL Class B Preferred Units Certificate of Designation also gives APL the right at any time to redeem some or all of the outstanding APL Class B Preferred Units for cash at an amount equal to the APL Class B Preferred Unit Liquidation Value being redeemed, provided that such redemption must be exercised for no less than the lesser of a) 2,500 APL Class B Preferred Units or b) the number of remaining outstanding APL Class B Preferred Units.

In June 2008, APL sold 5,750,000 common limited partner units in a public offering at a price of $37.52 per unit, yielding net proceeds of approximately $206.6 million. Also in June 2008, the Company purchased 308,109 AHD common units and 1,112,000 APL common limited partner units through a private placement transaction at a price of $32.50 and $36.02 per unit, respectively, for net proceeds of approximately $10.0 million and $40.1 million, respectively. AHD utilized the net proceeds from the sale to purchase 278,000 common units of APL, which in turn utilized the proceeds to partially fund the early termination of certain derivative agreements (see Note 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 and SFAS No. 160 was recorded in consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $26.4 million to non-controlling interest, during the year ended December 31, 2008.

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

NOTE 15 — CASH DISTRIBUTIONS

Atlas Energy Resources Cash Distributions.ATN is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its limited liability company agreement) for that quarter to its Class A and Class B common unitholders in accordance with their respective percentage interests. If Class A and Class B common unit distributions exceed specified target levels in any quarter during or subsequent to the completion of certain tests set forth in ATN’s limited liability company agreement, the

Company will receive management incentive distributions of between 15% and 50% of the distributions to Class A and Class B common unitholders in excess of the specified target levels. The tests include a 12-quarter test which requires, among other things, that ATN pay a quarterly cash distribution per unit that on average exceeds $0.42 per unit for 12 full, consecutive, non-overlapping calendar quarters and does not have a calendar quarter during which the distribution per unit was reduced. Effective April 27, 2009, ATN has suspended further distributions pursuant to its merger agreement with the Company (see Note 18). ATN’s suspension of the quarterly distribution during the three months ended March 31, 2009 means that it will not comply with the terms of the 12 quarter test and, as such, the Company will not receive the management incentive distributions that were reserved for during previous periods. Distributions declared by ATN from January 1, 2008 through March 31, 2009 are as follows:


		Cash
		Distribution	Total Cash
Date Cash		Per	Distribution
Distribution		Common	to the
Paid or Payable	For Quarter Ended	Unit	Company
			(in thousands)
February 14, 2008	December 31, 2007	$0.57	$17,437

May 15, 2008	March 31, 2008	$0.59	$18,410
August 14, 2008	June 30, 2008	$0.61	$19,060
November 14, 2008	September 30, 2008	$0.61	$19,060
February 13, 2009	December 31, 2008	$0.61	$19,060

Atlas Pipeline Partners Cash Distributions.APL is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders and AHD, as general partner. If APL’s common unit distributions in any quarter exceed specified target levels, AHD will receive between 15% and 50% of such distributions in excess of the specified target levels. Distributions declared by APL for the period from January 1, 2008 through March 31, 2009 were as follows (in thousands, except per unit amounts):


		APL Cash	Total APL Cash	Total APL Cash
		Distribution	Distribution	Distribution
Date Cash		per Common	to Common	to the
Distribution	For Quarter	Limited	Limited	General
Paid	Ended	Partner Unit	Partners	Partner
February 14, 2008	December 31, 2007	$0.93	$36,051	$5,092

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


(1)		Declared subsequent to March 31, 2009 (see Note 18).

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

back to APL would be after AHD receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter.

Atlas Pipeline Holdings Cash Distributions.AHD has a cash distribution policy under which it distributes, within 50 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders. Distributions declared by AHD for the period from January 1, 2008 through March 31, 2009 were as follows (in thousands except per unit amounts):



		Cash Distribution	Total Cash
Date Cash		per	Distribution to the
Distribution Paid or	For Quarter	Common Limited	Company (in
Payable	Ended	Partner Unit	thousands)
February 19, 2008	December 31, 2007	$0.34	$5,950

May 20, 2008	March 31, 2008	$0.43	$7,525
August 19, 2008	June 30, 2008	$0.51	$9,082
November 19, 2008	September 30, 2008	$0.51	$9,082
February 19, 2009	December 31, 2008	$0.06	$1,068

There was no distribution declared by AHD for the quarter ended March 31, 2009.

NOTE 16 — BENEFIT PLANS

Incentive Bonus Plan

The Company’s shareholders approved an Incentive Bonus Plan (“Bonus Plan”) for the benefit of its senior executive officers. The total amount of cash bonus awards to be made under the Bonus Plan for any plan year will be based on performance goals related to objective business criteria for such year. For any plan year, the Company’s performance must achieve levels targeted by the Company’s compensation committee, as established at the beginning of each year, for any bonus awards to be made. Aggregate bonus awards to all participants under the Bonus Plan may not exceed a limit as set by the compensation committee. The compensation committee has the authority to reduce the total amount of bonus awards, if any, to be made to the eligible employees for any plan year based on its assessment of personal performance or other factors as the Board may determine to be relevant or appropriate. The compensation committee may permit participants to elect to defer awards. For the three months period ended March 31, 2009 and 2008, the Company recognized $1.7 million and $1.5 million, respectively, of estimated expenses under the plan.

Stock Incentive Plan

The Company has a Stock Incentive Plan (the “Plan”) which authorizes the granting of up to 4,499,999 shares of the Company’s common stock to employees, affiliates, consultants and directors of the Company in the form of incentive stock options (“ISOs”), non-qualified stock options, stock appreciation rights (“SARs”), restricted stock and deferred units. The Company and its subsidiaries follow the provisions of SFAS No. 123(R), “Share-Based Payment”, as revised (“SFAS No. 123(R)”), for their stock compensation. Generally, the approach to accounting in SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.

Stock Options. Options under the Plan become exercisable as to 25% of the optioned shares each year after the date of grant, except options totaling 1,687,500 shares awarded in fiscal 2005 to Messrs. Edward Cohen and Jonathan Cohen, which are immediately exercisable, and expire not later than ten years after the date of grant. Compensation cost is recorded on a straight-line basis. The Company issues new shares when

stock options are exercised or units are converted to shares. There were no options exercised during the three months ended March 31, 2009 and 2008, respectively.

The following tables set forth the Plan activity for the three months ended March 31, 2009 and 2008:


				Three Months Ended
	March 31,
	2009					2008
				Weighted				Weighted
	Number			Average		Number		Average
	of Unit			Exercise		of Unit		Exercise
	Options			Price		Options		Price
Outstanding, beginning of period		3,495,351		$	16.97		2,715,381	$	12.10
Granted		100,000		$	13.35		825,000	$	32.67
Exercised⁽¹⁾		—			—		—		—
Cancelled		(15,187	)	$	11.32		—		—
Forfeited		(21,938	)	$	11.32		—		—

Outstanding, end of period⁽²⁾⁽³⁾		3,558,226		$	16.92		3,540,381	$	16.89


Options exercisable, end of period⁽⁴⁾		2,552,330		$	13.34		2,116,525	$	11.51


Non-cash compensation expense recognized (in thousands)	$	920				$	974


Available for grant at March 31, 2009		760,095


(1)		There were no options exercised for the three months ended March 31, 2009 and 2008, respectively.

(2)		The weighted average remaining contractual term of options outstanding at March 31, 2009 is 7.2 years.

(3)		The aggregate intrinsic value for options outstanding at March 31, 2008 was $82.8 million. There was no aggregate intrinsic value for options outstanding at March 31, 2009.

(4)		The weighted average remaining contractual term of options exercisable at March 31, 2009 is 6.5 years.

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


	Three Months Ended
	March 31,
	2009			2008
Expected dividend yield		0.6	%		0.4	%
Expected stock price volatility		36	%		33	%
Risk-free interest rate		2.2	%		2.6	%
Expected term (in years)		6.25			6.25
Fair value of stock options granted	$	4.89		$	11.75

Deferred Units and Restricted Shares

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

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

The following table summarizes the activity of deferred and restricted units for the three months ended March 31, 2009 and 2008:


				Three Months Ended
	March 31,
	2009					2008
				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		12,512		$	24.05		21,114		$	14.61
Granted		—			—		—			—
Matured		(842	)	$	20.76		(845	)	$	20.76
Forfeited		—			—		—			—

Non-vested shares outstanding, end of period		11,670		$	24.29		20,269		$	14.36


(1)		The intrinsic values for phantom unit awards vested during the three months ended at March 31, 2009 and 2008 were $10,000 and $28,000, respectively.

(2)		The aggregate intrinsic values for phantom unit awards outstanding at March 31, 2009 and 2008 were $0.1 million and $0.8 million, respectively.

(3)		The non-cash compensation expense recognized for phantom unit awards was $26,000 and $24,000 for each of the three months ending March 31, 2009 and 2008.

For the three months ended March 31, 2009 and 2008, the Company recorded non cash compensation expense of $1.0 million and $0.9 million, respectively, for the Company’s options and units. At March 31, 2009, the Company had unamortized compensation expense related to its unvested portion of the options and units of $8.2 million that the Company expects to recognize over the next four years.

Employee Stock Ownership Plan

The Company has an Employee Stock Ownership Plan (“ESOP”), which is a qualified non-contributory retirement plan, that was established to acquire shares of the Company’s common stock for the benefit of all employees who are 21 years of age or older and have completed 1,000 hours of service. The Company loaned $0.6 million (payable in quarterly installments of $18,508 plus interest at 7.5%) to the ESOP, which was used by the ESOP to acquire shares of the Company’s common stock. Contributions to the ESOP are made at the

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

The common stock purchased by the ESOP 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 March 31, 2009, there were 767,378 shares allocated to participants and 49,861 shares which are unallocated. In December 2008, the remaining loan balance was forgiven by the Company’s Board of Directors. As a result, all unallocated shares will be allocated to participating employees at the end of the ESOP’s fiscal year on September 30, 2009. Participants will receive shares upon vesting, which occurs over a five year period, beginning after the participant’s second year of service. Compensation expense related to the plan was $26,000 for the three months ended March 31, 2008. No compensation expense was recorded during the three months ended March 31, 2009 related to the plan. The fair value of unearned ESOP shares was $0.4 million at March 31, 2009.

Supplemental Employment Retirement Plan (“SERP”)

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. During the three months ended March 31, 2009 and 2008, expense recognized with respect to this commitment was $0.2 million and $0.4 million, respectively.

During the three months ended March 31, 2009, the Company funded $3.2 million of the outstanding liability with a financial institution in a rabbi trust. As of March 31, 2009 and December 31, 2008, the actuarial present value of the expected postretirement obligation due under this the SERP was $0.1 million and $3.2 million, respectively, which is included in other long-term liabilities on the Company’s consolidated balance sheets. The discount rate used was 7% at December 31, 2008.

The following table provides information about amounts recognized in the Company’s consolidated balance sheets at the dates indicated (in thousands):


	March 31,			December 31,
	2009			2008
Other liabilities	$	(126	)	$	(3,209	)
Accumulated other comprehensive income		232			255
Deferred income tax asset		136			150

Net amount recognized	$	242		$	(2,804	)

The estimated amount that will be amortized from accumulated other comprehensive income into expense for the year ended December 31, 2009 is $0.1 million.

AHD Long-Term Incentive Plan

The Board of Directors of AHD approved and adopted AHD’s Long-Term Incentive Plan (“AHD LTIP”), which provides performance incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for AHD. The AHD LTIP is administered by a committee (the “AHD LTIP Committee”), appointed by AHD’s board. Under the AHD LTIP, phantom units and/or unit options may be granted, at the discretion of the AHD LTIP Committee, to all or designated Participants, at the discretion of the AHD LTIP

Committee. The AHD LTIP Committee may grant such awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units. At March 31, 2009, AHD had 1,136,300 phantom units and unit options outstanding under the AHD LTIP, with 962,650 phantom units and unit options available for grant.

AHD Phantom Units.A phantom unit entitles a Participant to receive a common unit of AHD, without payment of an exercise price, upon vesting of the phantom unit or, at the discretion of the AHD LTIP Committee, cash equivalent to the then fair market value of a common limited partner unit of AHD. In tandem with phantom unit grants, the AHD LTIP Committee may grant a Participant a distribution equivalent right (“DER”), which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions AHD makes on a common unit during the period such phantom unit is outstanding. The AHD LTIP Committee will determine the vesting period for phantom units. Through March 31, 2009, phantom units granted under the AHD LTIP generally will vest 25% three years from the date of grant and 100% four years from the date of grant. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the AHD LTIP Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control of AHD, as defined in the AHD LTIP. Of the phantom units outstanding under the AHD LTIP at March 31, 2009, 44,425 units will vest within the following twelve months. All phantom units outstanding under the AHD LTIP at March 31, 2009 include DERs granted to the Participants by the AHD LTIP Committee. The amount paid with respect to AHD’s LTIP DERs was $14,000 and $0.1 million for the three months ended March 31, 2009 and 2008, respectively. These amounts were recorded as an adjustment of non-controlling interests on the Company’s consolidated balance sheet.

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


	Three Months Ended
	March 31,
	2009			2008
Outstanding, beginning of period		226,300			220,825
Granted⁽¹⁾		—			4,650
Matured⁽²⁾		—			—
Forfeited		(45,000	)		—

Outstanding, end of period⁽³⁾		181,300			225,475


Non-cash compensation income (expense) recognized (in thousands)	$	(308	)	$	366


⁽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 awards granted for the three months ended March 31, 2008. There were no awards granted during the three months ended March 31, 2009.

⁽²⁾		There were no phantom units exercised for the three months ended March 31, 2009 and 2008, respectively.

⁽³⁾		The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2009 is $0.3 million.

At March 31, 2009, AHD had approximately $1.5 million of unrecognized compensation expense related to unvested phantom units outstanding under AHD’s LTIP based upon the fair value of the awards.

AHD Unit Options.A unit option entitles a Participant to receive a common unit of AHD upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price

of the unit option may be equal to or more than the fair market value of AHD’s common unit as determined by the AHD LTIP Committee on the date of grant of the option. The AHD LTIP Committee also shall determine how the exercise price may be paid by the Participant. The AHD LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through March 31, 2009, unit options granted under the AHD LTIP generally will vest 25% three years from the date of grant and 100% four years from the date of grant. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by AHD’s LTIP Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control of AHD, as defined in the AHD LTIP. There are 213,750 unit options outstanding under the AHD LTIP at March 31, 2009 that will vest within the following twelve months. The following table sets forth the AHD LTIP unit option activity for the periods indicated:


	Three Months Ended March 31,
	2009					2008
				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		100,000		$	3.24		—		—
Matured		—			—		—		—
Forfeited		(360,000	)	$	22.56		—		—

Outstanding, end of period^(1)(2)(3)		955,000		$	20.54		1,215,000	$	22.56


Options exercisable, end of period		—			—		—		—


Weighted average fair value of unit options per unit granted during the quarter		100,000		$	0.61		—		—


Non-cash compensation income (expense) recognized (in thousands)	$	(573	)			$	309


(1)		The weighted average remaining contractual lives for outstanding options at March 31, 2009 and 2008 were 7.8 years and 8.6 years, respectively.

(2)		There was no aggregate intrinsic value of options outstanding at March 31, 2009. The aggregate intrinsic value of options outstanding at March 31, 2008 was approximately $5.6 million.

(3)		There were no options exercised during the three months ended March 31, 2009 and 2008, respectively.

At March 31, 2009, AHD had approximately $1.2 million of unrecognized compensation expense related to unvested unit options outstanding under AHD’s LTIP based upon the fair value of the awards.

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


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

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.

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 March 31, 2009, phantom units granted under the APL LTIP generally had vesting periods of four years. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the APL LTIP Committee, although no awards currently outstanding contain any such provision. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards will automatically vest upon a change of control, as defined in the APL LTIP. Of the units outstanding under the APL LTIP at March 31, 2009, 31,607 units will vest within the following twelve months. All phantom units outstanding under the APL LTIP at March 31, 2009 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL LTIP DERs were $48,000 and $0.1 million for the three months ended March 31, 2009 and 2008, respectively. These amounts were recorded as reductions of non-controlling interest on the Company’s consolidated balance sheet.

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


	Three Months Ended
	March 31,
	2009			2008
Outstanding, beginning of year		126,565			129,746
Granted⁽¹⁾		1,500			53,951
Matured⁽²⁾		(9,886	)		(11,860	)
Forfeited		(16,250	)		(750	)

Outstanding, end of period⁽³⁾		101,929			171,087


Non-cash compensation income (expense) recognized (in thousands)	$	(95	)	$	486


⁽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 $4.60 and $44.44 for awards granted for the three months ended March 31, 2009 and 2008, respectively.

⁽²⁾		The intrinsic values for phantom unit awards exercised during the three months ended March 31, 2009 and 2008 were $0.1 million and $0.2 million, respectively.

⁽³⁾		The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2009 was $0.4 million.

At March 31, 2009, APL had approximately $1.4 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIP based upon the fair value of the awards.

APL Unit Options.A unit option entitles a participant to receive a common unit of APL upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of APL’s common unit as determined by the APL LTIP Committee on the date of grant of the option. The APL LTIP Committee also shall determine how the exercise price may be paid by the Participant. The APL LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through March 31, 2009, unit options granted under APL’s LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the APL LTIP Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control of APL, as defined in the APL’s LTIP. There were 25,000 unit options outstanding under APL’s LTIP at March 31, 2009 that will vest within the following twelve months. The following table sets forth the APL LTIP unit option activity for the periods indicated:


	Three Months Ended March 31,
	2009				2008
			Weighted				Weighted
	Number		Average		Number		Average
	of Unit		Exercise		of Unit		Exercise
	Options		Price		Options		Price
Outstanding, beginning of period		—		—		—		—
Granted		100,000	$	6.24		—		—
Matured		—		—		—		—
Forfeited		—		—		—		—

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


Options exercisable, end of period⁽³⁾		—		—		—		—


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


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


(1)		The weighted average remaining contractual life for outstanding options at March 31, 2009 was 9.8 years.

(2)		There was no aggregate intrinsic value of options outstanding at March 31, 2009.

(3)		There were no options exercised during the three months ended March 31, 2009 and 2008, respectively.

At March 31, 2009, APL had approximately $12,000 of unrecognized compensation expense related to unvested unit options outstanding under the APL’s LTIP based upon the fair value of the awards.

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


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

APL Incentive Compensation Agreements

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

As of December 31, 2008, APL recognized in full within its consolidated statements of operations the compensation expense associated with the vesting of awards to be issued under its incentive compensation agreements, therefore no compensation expense was recognized during the three months ended March 31, 2009. APL recognized a reduction of compensation expense of $3.3 million for the three months ended March 31, 2008 related to the vesting of awards under its incentive compensation agreements. The non-cash compensation expense adjustments for the three months ended March 31, 2008 were principally attributable to changes in APL’s common unit market price, which was utilized in the calculation of the non-cash compensation expense for these awards, at March 31, 2008 when compared with the common unit market price at earlier periods and adjustments based upon the achievement of actual financial performance targets through March 31, 2008. APL follows SFAS No. 123(R) and recognized compensation expense related to these awards based upon the fair value method. During the three months ended March 31, 2009, APL issued 209,172 common units to the certain key employees covered under APL’s incentive compensation agreements. APL will issue an additional 139,448 common units during the second quarter 2009 to fulfill its obligations under the terms of the agreements. No additional common units will be issued with regard to these agreements.

Atlas Energy Resources, LLC Long-Term Incentive Plan

ATN previously adopted 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 ATN’s compensation committee, which may grant awards of restricted units, phantom units or unit options. Awards for a total of 3,742,000 common units may

be granted under the LTIP. Awards granted in 2008 and 2007 vest 25% after three years and 100% upon the four year anniversary of grant, except for 1,500 awards granted to board members which vest 25% per year over four years. Awards granted in 2006 vest 25% per year over four years. Upon termination of service by a grantee, all unvested awards are forfeited. A restricted stock or phantom unit entitles a grantee to receive a common unit of the Company upon vesting of the unit or, at the discretion of the Company’s compensation committee, cash equivalent to the then fair market value of a common unit of ATN. In tandem with phantom unit grants, ATN’s compensation committee may grant a distribution equivalent right (“DER”), which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions ATN makes on a common unit during the period such phantom unit is outstanding.

ATN Restricted Stock and Phantom Units.Under the ATN LTIP, 17,000 and 12,375 units of restricted stock and phantom units were awarded in the three months ended March 31, 2009 and 2008, respectively. The fair value of the grants is based on the closing stock price on the grant date, and is being charged to operations over the requisite service periods using a straight-line attribution method.

The following table summarizes the activity of restricted stock and phantom units for the periods indicated:


				Weighted
				Average
				Grant Date
	Units			Fair Value
Non-vested shares outstanding at December 31, 2008		768,829		$	23.86
Granted		17,000			14.18
Vested		(1,168	)		28.82
Forfeited		—			—

Non-vested shares outstanding at March 31, 2009		784,661			23.65

Stock Options. There were no unit options granted in the three months ended March 31, 2009 under the ATN LTIP. For the three months ended March 31, 2008, 6,500 unit options were awarded under the ATN LTIP. Option awards expire 10 years from the date of grant and are generally granted with an exercise price equal to the market price of ATN’s stock at the date of grant. ATN uses the Black-Scholes option pricing model to estimate the weighted average fair value per option granted with the following assumptions:

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


						Weighted
						Average
				Weighted		Remaining		Aggregate
				Average		Contractual		Intrinsic
				Exercise		Term		Value
	Shares			Price		(in years)		(in thousands)
Outstanding at December 31, 2008		1,902,902		$	24.17
Granted		—			—
Exercised		—			—
Forfeited or expired		(900	)		23.06

Outstanding at March 31, 2009		1,902,002		$	24.17		7.7	$	0

Options exercisable at March 31, 2009		186,876		$	21.00		7.0

Available for grant at March 31, 2009		1,029,986

The following tables summarize information about stock options outstanding and exercisable at March 31, 2009:


	Options Outstanding						Options Exercisable
			Weighted
			Average		Weighted
	Number of		Remaining		Average		Number of		Weighted
Range of	Shares		Contractual		Exercise		Shares		Average
Exercise Prices	Outstanding		Life in Years		Price		Exercisable		Exercise Price
$21.00 — 23.06		1,653,902		7.6	$	22.59		186,876	$	21.00
$30.24 — 35.00		240,600		8.3	$	34.53		—		—
$37.79 and above		7,500		8.8	$	39.79		—		—

		1,902,002		7.7	$	24.17		186,876	$	21.00

ATN recognized $1.5 million and 1.3 million of compensation expense related to restricted stock units, phantom units and unit options for the three months ended March 31, 2009 and 2008, respectively. ATN paid $0.4 million and $0.3 million with respect to its LTIP DERs for the three months ended March 31, 2009 and 2008, respectively. This amount was recorded as a reduction of non-controlling interests’ equity on the Company’s consolidated balance sheet. At March 31, 2009, ATN had approximately $12.4 million of unrecognized compensation expense related to the unvested portion of the restricted stock units, phantom units and options.

NOTE 17 — 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
	March 31,
	2009			2008
Gas and oil production:
Revenues	$	71,943		$	76,226
Costs and expenses		(11,286	)		(10,668	)

Segment income	$	60,657		$	65,558


Well construction and completion:
Revenues	$	112,368		$	104,138
Costs and expenses		(95,397	)		(90,555	)

Segment income	$	16,971		$	13,583


Atlas Pipeline:
Revenues (a)	$	175,266		$	292,135
Revenues — affiliates		10,149			9,224
Costs and expenses		(156,650	)		(299,392	)

Segment income	$	28,765		$	1,967


Other(b):
Revenues	$	3,520		$	5,001
Costs and expenses		(3,051	)		(2,533	)

Segment income	$	469		$	2,468


	Three Months Ended
	March 31,
	2009			2008
Reconciliation of segment income to net income (loss) before income tax provision (benefit):
Segment income (loss) Gas and oil production	$	60,657		$	65,558
Well construction and completion		16,971			13,583
Atlas Pipeline		28,765			1,967
Other		469			2,468

Total segment income (loss)		106,862			83,576
General and administrative expenses		(27,755	)		(21,008	)
Net expense reimbursement — affiliate		(482	)		(250	)
Depreciation, depletion and amortization		(52,707	)		(43,652	)
Interest expense		(34,646	)		(34,098	)
Other income — net		4,880			2,030

Net income (loss) before income tax provision (benefit)	$	(3,848	)	$	(13,402	)


Capital expenditures:
Gas and oil production	$	49,618		$	54,474
Well construction and completion		—			—
Atlas Pipeline		72,913			84,069
Corporate and other		7,589			1,143

Total capital expenditures	$	130,120		$	139,686


	March 31,		December 31,
	2009		2008
Balance sheet:
Goodwill:
Gas and oil production	$	21,527	$	21,527
Well construction and completion		13,639		13,639
Atlas Pipeline		—		—

	$	35,166	$	35,166


Total assets:
Gas and oil production	$	2,294,264	$	2,210,563
Well construction and completion		13,826		16,399
Atlas Pipeline		2,382,231		2,413,196
Corporate and other		187,110		205,723

	$	4,877,431	$	4,845,881


(a)		Includes a gain of $0.3 million and a loss of $88.8 million on mark-to-market derivatives for three months ended March 31, 2009 and 2008, respectively.

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

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

NOTE 18 — SUBSEQUENT EVENTS

On April 1, 2009, APL redeemed 10,000 of the Class A Preferred Units held by Sunlight Capital Partners, LLC (“Sunlight”) for cash at the liquidation value of $1,000 per unit, or $10.0 million, pursuant to the terms of the amended preferred units’ certificate of designation. Additionally on April 1, 2009, APL paid Sunlight a preferred dividend of $0.3 million, representing the quarterly dividend on the 10,000 APL Class A Preferred Units held by Sunlight prior to APL’s redemption. On April 13, 2009, Sunlight exercised its right to convert 5,000 APL Class A Preferred Units into 1,465,653 APL common limited partner units, which was

based on 95% of the market value of APL’s closing common unit price for the 10 business days prior to and including March 31, 2009.

On April 7, 2009, APL entered into an agreement with Spectra Energy Partners OLP, LP (NYSE: SEP) (“Spectra”) related to the sale of its NOARK gas gathering and interstate pipeline system, including Ozark Gas Transmission, LLC and Ozark Gas Gathering, LLC, for $300.0 million cash. The purchase price was subject to an adjustment based on the working capital of the NOARK system during the periods between the signing date and closing dates. The Company will account for the sale of the NOARK system assets as discontinued operations within the Company’s consolidated financial statements in the future. The transaction closed on May 4, 2009 and APL used the net proceeds from the transaction to reduce borrowings under its senior secured term loan and credit facility (see Note 7).

Effective April 9, 2009, ATN entered into a second amendment to its credit agreement with a syndicate of banks. Among other provisions, the amendment adjusts the credit facility borrowing base to $650.0 million and amends the definition of applicable margin to, among other things, adjust the Eurodollar Loans rate to a range of 200 to 300 basis points, subject to amounts drawn against the facility.

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

On April 30, 2009, a complaint seeking class certification was filed in the Court of Chancery of the State of Delaware against the Company, ATN and its board of directors. The plaintiff seeks to represent persons who owned ATN’s common units as of April 27, 2009, the date of execution of the definitive merger agreement with ATN. The complaint alleges that the Company, as a majority unitholder of ATN, ATN and its board of directors, breached their fiduciary duties and asserts that the consideration to be paid by the Company in the proposed merger is inadequate. The action seeks a preliminary and permanent injunction from proceeding with the merger, compensatory damages in an unspecified amount, including plaintiff’s costs and expenses, and an order directing defendants to account to the plaintiffs for their damages. The Company believes that the allegations and purported claims in the complaint lack merit and that the Company has meritorious defenses to them, and the Company intends to contest the lawsuit vigorously. The Company is not presently able to estimate the impact, or potential losses, if any, related to this lawsuit.

On May 1, 2009, APL announced that its Board of Directors had declared a cash distribution of $0.15 per common limited partner unit, payable on May 15, 2009 to holders of record on May 11, 2009.

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

On May 5, 2009, APL redeemed the remaining 5,000 of the Class A Preferred Units held by Sunlight Capital for cash at the liquidation value of $1,000 per unit, or $5.0 million, pursuant to the terms of the amended preferred units’ certificate of designation. Additionally on May 5, 2009, APL paid Sunlight a preferred dividend of $0.2 million, representing the quarterly dividend on the 5,000 APL Class A Preferred Units held by Sunlight prior to APL’s redemption.

In May 2009, ATN received approximately $28.5 million in proceeds from the early settlement of natural gas hedge positions related to periods from 2011 through 2013. In conjunction with the hedge monetization, these hedge positions were effectively replaced with similar hedge contracts at current prevailing prices. The net proceeds from the hedge monetization were used to reduce indebtedness.

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 the year ended December 31, 2008. These risks and uncertainties could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of thisForm 10-Q or to reflect the occurrence of unanticipated events.

General

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

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

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

	•		Atlas Pipeline Partners, L.P. (“Atlas Pipeline Partners” or “APL”), a publicly traded Delaware limited partnership (NYSE: APL) and midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachia regions;

	•		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 LP.

Our ownership interest in ATN consists of the following:

	•		all of the outstanding Class A units, representing 1,293,486 units at March 31, 2009, which entitles us to receive 2% of the cash distributed by ATN without any obligation to make future capital contributions to ATN;

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

	•		29,952,996 common units, representing approximately 47.3% of the outstanding common units at March 31, 2009, or a 46.3% ownership interest in ATN.

Our ownership of ATN’s management incentive interests entitles us to receive an increasing percentage of cash distributed by ATN as it reaches certain target distribution levels after ATN has met the tests set forth within its limited liability company agreement (see “-Subsequent Events”). 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 March 31, 2009, or a 2.3% ownership interest.

Our ownership interest in AHD consists of 17,808,109 common units, representing approximately 64.4% of the outstanding common units of AHD at March 31, 2009. AHD’s general partner, which is a wholly-owned subsidiary of ours, does not have an economic interest in AHD, and AHD’s capital structure does not include incentive distribution rights. AHD’s ownership interest in APL consists of the following:

•

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

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

	•		5,754,253 common units, representing approximately 12.5% of the outstanding common units at March 31, 2009, or a 11.8% ownership interest in APL; and

	•		15,000 $1,000 par value 12.0% cumulative preferred limited partner units at March 31, 2009.

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

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

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

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

Financial Presentation

Our principal operating activities are conducted primarily through ATN, AHD, and APL, and our cash flows consist primarily of distributions received from ATN, APL and AHD on our ownership interests. Our consolidated financial statements contain the consolidated financial statements of ATN and AHD, and AHD’s consolidated financial statements include the consolidated financial statements of APL. The non-controlling interests in ATN, AHD and APL are reflected as loss attributable to non-controlling interests in our consolidated statements of operations and as a component of stockholders’ equity on our consolidated balance sheets. Throughout this section, when we refer to “our” consolidated financial statements, we are referring to the consolidated results for us and our wholly-owned subsidiaries and the consolidated results of ATN and AHD, including APL’s financial results, adjusted for non-controlling interests in ATN’s, AHD’s and APL’s net income (loss).

Atlas Energy

ATN is an independent developer and producer of natural gas and oil, with operations in northern Michigan’s Antrim Shale, the Appalachian Basin region of the United States, principally in western New York, eastern Ohio, western Pennsylvania and Tennessee, and Indiana’s New Albany Shale. ATN is also a leading sponsor and manager of tax-advantaged direct investment natural gas and oil partnerships in the United States. ATN funds the drilling of natural gas and oil wells on its acreage by sponsoring and managing tax advantaged investment partnerships. It generally structures its investment partnerships so that, upon formation of a partnership, ATN co-invests in and contributes leasehold acreage to it, enters into drilling and well operating agreements with it and becomes its managing general partner. ATN is managed by Atlas Energy Management, Inc., our wholly-owned subsidiary, through which we provide ATN with the personnel necessary to manage its assets and raise capital.

As of and for the three months ended March 31, 2009, ATN had the following key assets:

Appalachia gas and oil operations

	•		direct and indirect working interests in approximately 8,602 gross producing gas and oil wells;

	•		overriding royalty interests in approximately 628 gross producing gas and oil wells;

	•		net daily production of 42.3 million cubic feet equivalents per day (“MMcfed”); and

	•		approximately 952,000 gross (906,000 net) acres, of which approximately 640,000 gross (633,000 net) acres, are undeveloped. Included in the undeveloped acreage is 546,000 Marcellus Shale acres in Pennsylvania, New York and West Virginia, of which approximately 274,000 acres are located in ATN’s core Marcellus Shale position in southwestern Pennsylvania.

Michigan gas and oil operations

	•		direct and indirect working interests in approximately 2,479 gross producing gas and oil wells;

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

	•		net daily production of 58.1 MMcfed; and

	•		approximately 345,400 gross (273,000 net) acres, of which approximately 39,400 gross (30,500 net) acres, are undeveloped.

Indiana gas and oil operations

	•		direct and indirect working interests in approximately 5 gross producing gas and oil wells;

	•		net daily production of 0.2 Mmcfed; and

	•		approximately 245,200 gross (118,900 net) acres, of which approximately 244,600 gross (118,400 net) acres, are undeveloped.

Partnership management business

•

ATN investment partnership business, which includes equity interests in 94 investment partnerships and a registered broker-dealer which acts as the dealer-manager of ATN’s investment partnership offerings.

Atlas Pipeline Holdings and Atlas Pipeline Partners

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

APL is a leading provider of natural gas gathering services in the Anadarko, 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.

As of March 31, 2009, through its Mid-Continent operations, APL owns and operates:

	•		a Federal Energy Regulatory Commission (“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 500 MMcfd;

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

	•		9,100 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.

As of March 31, 2009, through its Appalachian operations, APL owns and operates 1,835 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 April 1, 2009, APL redeemed 10,000 of the Class A Preferred Units held by Sunlight Capital for cash at the liquidation value of $1,000 per unit, or $10.0 million, pursuant to the terms of the amended preferred units’ certificate of designation. Additionally on April 1, 2009, APL paid Sunlight a preferred dividend of $0.3 million, representing the quarterly dividend on the 10,000 APL Class A Preferred Units held by Sunlight prior to APL’s redemption. On April 13, 2009, Sunlight exercised its right to convert 5,000 APL Class A Preferred Units into 1,465,653 APL common limited partner units, which was based on 95% of the market value of APL’s closing common unit price for the 10 business days prior to and including March 31, 2009.

On April 7, 2009, APL entered into an agreement with Spectra Energy Partners OLP, LP (NYSE: SEP) (“Spectra”) to sell its NOARK gas gathering and interstate pipeline system, including Ozark Gas Transmission, LLC and Ozark Gas Gathering, LLC, for $300.0 million cash. The purchase price was subject to an adjustment based on the working capital of the NOARK system during the periods between the signing date and closing dates. We will account for the sale of the NOARK system assets as discontinued operations within our consolidated financial statements in the future. The transaction closed on May 4, 2009 and APL used the net proceeds from the transaction to reduce borrowings under its senior secured term loan and credit facility.

On April 27, 2009, we and ATN executed a definitive merger agreement, pursuant to which our newly formed subsidiary will merge with and into ATN, with ATN surviving as our wholly-owned subsidiary. In the merger, each Class B common unit of ATN not currently held by us will be converted into 1.16 shares of our common stock, and we will be renamed “Atlas Energy, Inc.”. Our board of directors has approved the merger agreement and has resolved to recommend that our stockholders vote in favor of the transactions contemplated by the merger agreement. ATN’s board of directors and a special committee of its directors comprised entirely of independent directors have also approved the merger agreement and have resolved to recommend that ATN’s stockholders vote in favor of the merger. Pending consummation of the merger, ATN has suspended distributions to its Class A and Class B members’ interests. ATN’s suspension of the quarterly distribution during the three months ended March 31, 2009 means that it will not comply with the terms of the 12 quarter test and, as such, the Company will not receive the management incentive distributions that were reserved for during previous periods. The transaction will be subject to approval by holders of a majority of our outstanding common stock, a majority of ATN’s outstanding Class B units, and a majority of the lenders under the ATN’s credit agreement and other customary closing conditions.

On April 30, 2009, a complaint seeking class certification was filed in the Court of Chancery of the State of Delaware against us, ATN and its board of directors. The plaintiff seeks to represent persons who owned ATN’s common units as of April 27, 2009, the date of execution of the definitive merger agreement with ATN. The complaint alleges that we, as a majority unitholder of ATN, ATN and its board of directors, breached their fiduciary duties and asserts that the consideration to be paid by us in the proposed merger is inadequate. The action seeks a preliminary and permanent injunction from proceeding with the merger, compensatory damages in an unspecified amount, including plaintiff’s costs and expenses, and an order directing defendants to account to the plaintiffs for their damages. We believe that the allegations and purported claims in the complaint lack merit and that we have meritorious defenses to them, and we intend to contest the lawsuit vigorously. We are not presently able to estimate the impact, or potential losses, if any, related to this lawsuit.

On May 1, 2009, APL announced that its Board of Directors had declared a cash distribution of $0.15 per common limited partner unit payable on May 15, 2009 to holders of record on May 11, 2009.

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

On May 5, 2009, APL redeemed the remaining 5,000 of the Class A Preferred Units held by Sunlight Capital for cash at the liquidation value of $1,000 per unit, or $5.0 million, pursuant to the terms of the amended preferred units certificate of designation. Additionally on May 5, 2009, APL paid Sunlight a preferred dividend of $0.2 million, representing the quarterly dividend on the 5,000 APL Class A Preferred Units held by Sunlight prior to APL’s redemption.

Recent Developments

On March 31, 2009, APL and ATN entered into an agreement with subsidiaries of The Williams Companies, Inc. (NYSE: WMB) (“Williams”) to form a joint venture, Laurel Mountain Midstream, LLC (“Laurel Mountain”), that will own and operate APL’s Appalachia Basin natural gas gathering system, excluding APL’s northern Tennessee operations. To the joint venture, Williams will contribute cash of $102.0 million, of which APL will receive approximately $90.0 million and a note receivable of $25.5 million. In addition, ATN will sell certain assets to Laurel Mountain for $12.0 million. APL will contribute its Appalachia Basin natural gas gathering system, and ATN will contribute two natural gas processing plants and associated pipelines. APL will retain a 49% ownership interest in the joint venture, as well as preferred distribution rights relating to all payments on the note receivable. Williams will retain the remaining 51% ownership interest in the joint venture. The transaction is expected to close during the second quarter of 2009. APL and ATN will use their net proceeds from the transaction to reduce borrowings under their respective credit facilities. Upon the completion of the sale of the Appalachia gathering systems to Laurel Mountain, Laurel Mountain will enter into new gas gathering agreements with ATN which will supersede the existing natural gas gathering agreements and omnibus agreement between APL and ATN. Under the proposed gas gathering agreement, ATN will be obligated to pay Laurel Mountain all of the gathering fees it collects from its partnerships plus any excess amount over the amount of the competitive gathering fee (which is currently defined as 13% of the gross sales price received for the partnerships gas). The proposed gathering agreement contains additional provisions which define certain obligations and options of each party to build and connect newly drilled wells to any Laurel Mountain gathering system.

On March 30, 2009, AHD, pursuant to its right within the Class B Preferred Units Certificate of Designation, purchased an additional 5,000 of APL’s 12% Class B Preferred Units of limited partner interests (the “Class B Preferred Units”) for cash consideration of $1,000 per Class B Preferred Unit. APL used the proceeds from the sale of the Class B Preferred Units for general partnership purposes. The Class B Preferred Units will receive distributions of 12.0% per annum, paid quarterly to it on the same date as APL’s distribution payment date for its common units. Additionally, on March 30, 2009, AHD and APL agreed to amend the terms of the Class B Preferred Units Certificate of Designation to remove the conversion feature, thus the Class B Preferred Units Certificate of Designation are not convertible into APL common units. The amended Class B Preferred Units also give APL the right at any time to redeem some or all of the outstanding Class B Preferred Units for cash, or an amount equal to the Class B Preferred Unit Liquidation Value being redeemed, provided that such redemption must be exercised for no less than the lesser of a) 2,500 Class B Preferred Units or b) the number of remaining outstanding Class B Preferred Units.

In January 2009, APL and Sunlight agreed to amend certain terms of the APL Class A Preferred Units Certificate of Designation, which were issued in March 2006. The amendment (a) increased the dividend yield from 6.5% to 12.0% per annum, effective January 1, 2009, (b) established a new conversion commencement date on the outstanding APL Class A Preferred Units of April 1, 2009, (c) established Sunlight Capital’s new conversion option price of $22.00, enabling the APL Class A Preferred Units to be converted at the lesser of $22.00 or 95% of the market value of APL common units, and (d) established a new price for APL’s call redemption right of $27.25. In addition, the amendment required that APL issue Sunlight Capital $15.0 million of its 8.125% senior unsecured notes due 2015 to redeem 10,000 APL Class A Preferred Units. The amendment of the preferred unit agreement certificate of designation also required redemption of 15,000 of the APL Class A Preferred Units for cash in future periods. As such, $15.0 million of the $20.0 million of APL Class A Preferred Units outstanding at March 31, 2009 was reclassified from non-controlling interest within stockholders’ equity to APL preferred unit redemption obligation on our consolidated balance sheet. In April 2009, APL and Sunlight Capital agreed that APL would convert 5,000 of the APL Class A Preferred Units into its common units (see “-Subsequent Events”).

Contractual Revenue Arrangements

Atlas Energy

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

	•		gas marketers;

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

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

Investment Partnerships.ATN generally funds its drilling activities through sponsorship of tax-advantaged investment partnerships. In addition to providing capital for its drilling activities, ATN’s investment partnerships are a source of fee-based revenues, which are not directly dependent on natural gas and oil prices. As managing general partner of the investment partnerships, ATN receives the following fees:

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

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

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

Atlas Pipeline Partners

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

recognized upon physical delivery of the natural gas. In connection with its gathering and processing operations, APL enters into the following types of contractual relationships with its producers and shippers:

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

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

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

Recent Trends and Uncertainties

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

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

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

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

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

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

As a result of APL’s POP and keep-whole contracts, its results of operations and financial condition substantially depend upon the price of natural gas and NGLs. APL believes that future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. Based on historical trends, APL generally expects NGL prices to follow changes in crude oil prices over the long term, which we believe will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. 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.

Results of Operations

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


	Three Months
	Ended March 31,
	2009		2008
Atlas Energy:
Production revenues (in thousands):
Gas	$	69,874	$	72,874
Oil⁽¹⁾		2,069		3,351

Production volume^{(2) (3)}:
Gas (mcfd)		98,158		89,342


	Three Months
	Ended March 31,
	2009		2008
Oil (bpd)		398		405
Total (mcfed) Oil(bpd)		100,546		91,772

Average sales prices⁽³⁾:
Gas (per mcf)⁽⁴⁾⁽⁵⁾	$	8.09	$	9.58
Oil (per bbl)⁽⁶⁾ Gas(mcfd)	$	64.52	$	91.03

Production costs⁽⁷⁾:
Lease operating expenses per mcfe	$	0.91	$	0.78
Production taxes per mcfe		0.19		0.32

Total production costs per mcfe	$	1.10	$	1.10


Atlas Pipeline Partners:
Appalachia system throughput volume (mcfd)⁽³⁾		98,529		75,632

Velma system gathered gas volume (mcfd)⁽³⁾		65,955		62,400

Elk City/Sweetwater system gathered gas volume (mcfd)⁽³⁾		253,878		305,377

Chaney Dell system gathered gas volume (mcfd)⁽³⁾		303,022		251,487

Midkiff/Benedum system gathered gas volume (mcfd)⁽³⁾		153,978		142,542

NOARK Ozark Gas Transmission throughput volume (mcfd)⁽³⁾		482,471		390,293


Combined throughput volume (mcfd)⁽³⁾		1,357,833		1,227,731


(1)		Excludes sales of natural gas liquids.

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

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

(4)		Atlas Energy’s average sales price before the effects of financial hedging was $5.21 and $8.32 for the three months ended March 31, 2009 and 2008, respectively.

(5)		Includes cash proceeds received from the settlement of derivative contracts of $1.6 million and $5.0 million for the three months ended March 31, 2009 and 2008, respectively. The cash proceeds received from the settlement of derivative contracts were not included as gas revenue for the respective periods.

(6)		Atlas Energy’s average sales price for oil before the effects of financial hedging were $37.54 per barrel for the three months ended March 31, 2009. ATN had no crude oil hedges in effect during the three months ended March 31, 2008.

(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.

Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008

Natural Gas and Oil Production. Our natural gas and oil production revenues were $71.9 million for the three months ended March 31, 2009, compared to $76.2 million for the comparable prior year period. The $4.3 million decrease was primarily due to a 16% decrease in the average realized sales price offset by a 10% increase in production volumes. The increase in production volumes was attributable to a 9,622 Mcf/day increase in ATN’s Appalachia natural gas volumes related to increased Marcellus Shale drilling operations.

Natural gas and oil production expenses were $11.3 million for the three months ended March 31, 2009, an increase of $0.6 million from $10.7 million for the comparable prior year period. The increase was principally attributable to an increase of $1.0 million in Appalachia transportation and compression costs and

$0.9 million in Appalachia water hauling and disposal costs associated with an increase in the number of Marcellus Shale wells ATN drilled partially offset by a decrease in the production tax rate on ATN’s Michigan production.

Well Construction and Completion. Our well construction and completion revenues were $112.4 million for the three months ended March 31, 2009, an increase of $8.3 million from $104.1 million for the comparable prior year period. Well construction and completion expenses increased $4.8 million to $95.4 million for the three months ended March 31, 2009 from $90.6 million from the comparable prior year period. The increase in well drilling margin during the three months ended March 31, 2009 in comparison to the prior year comparable period was due to an increase in gross margin per well, partially offset by a decrease in the number of wells drilled. For a majority of the wells that it drills, ATN receives an 18% mark-up on those costs incurred to drill and complete the well in connection with its partnership management activities. The increase in well construction and completion revenues and expenses was due to ATN’s shift from drilling less expensive shallow wells to more expensive deep, horizontal shale wells in Appalachia and in Michigan/Indiana during the current quarter.

As of March 31, 2009, “Liabilities associated with drilling contracts” on our consolidated balance sheet includes $30.3 million of funds raised that have not been applied to the completion of wells as of March 31, 2009 due to the timing of ATN’s drilling operations and thus have not been recognized as well construction and completion revenue. We expect to recognize this amount as revenue in the second quarter of 2009.

Administration and Oversight and Well Services. Administration and oversight fee revenues were $3.9 million for the three months ended March 31, 2009 compared with $5.0 million for the three months ended March 31, 2009, a decrease of $1.1 million or 23%. Well services revenues were $5.1 million for the three months ended March 31, 2009 compared with $4.8 million for the comparable prior year period, an increase of $0.3 million or 6%. Well services expenses were $2.4 million for both the three months ended March 31, 2009 and 2008. The decrease in administration and oversight fee revenue was due to a decrease in the number of wells drilled during the period, while the increase in well service revenue was due to the increase in wells drilled since March 31, 2008.

Transmission, Gathering and Processing. Our transmission, gathering and processing revenues were $179.7 million for the three months ended March 31, 2009, a decrease of $205.6 million from $385.3 million for the comparable prior year period. The decline was primarily attributable to decreases in production revenue from APL’s Chaney Dell system of $69.8 million, APL’s Midkiff/Benedum system of $55.5 million, APL’s Elk City/Sweetwater system of $43.0 million and APL’s Velma system of $35.6 million due to significantly lower average commodity prices in comparison to the prior year comparable period partially offset by an overall increase in processing volumes and plant production efficiency. Processed natural gas volume on the Elk City/Sweetwater system averaged 253.9 MMcfd for the three months ended March 31, 2009, an increase of 7.4% from the comparable prior year period. NGL production volume for the Elk City/Sweetwater system was 11,719 bpd, an increase of 9.8% from the comparable prior year period, as production efficiency of the processing plants increased. The Midkiff/Benedum system had processed natural gas volume of 146.1 MMcfd for the three months ended March 31, 2009, an increase of 6.9% compared to 136.7 MMcfd for the comparable prior year period. NGL production volume for the Midkiff/Benedum system was 22,650 bpd, an increase of 11.3% from the comparable prior year period, as production efficiency of the processing plants increased. Processed natural gas volume averaged 63.9 MMcfd on the Velma system for the three months ended March 31, 2009, an increase of 6.7% from the comparable prior year period. Processed natural gas volume on the Chaney Dell system was 227.9 MMcfd for the three months ended March 31, 2009, a decrease of 8.1% compared to 247.9 MMcfd for the comparable prior year period. However, the Chaney Dell system’s NGL production volume increased 25.2% from the comparable prior year period to 15,531 bpd for the three months ended March 31, 2009, representing an increase in production efficiency. 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.

Gain (Loss) on Mark-to-Market Derivatives. Gain on mark-to-market derivatives was $0.3 million for the three months ended March 31, 2009 compared with a loss of $88.8 million for the comparable prior year period. This favorable movement of $89.1 million was due primarily to a $42.7 million favorable movement in APL’s non-cash mark-to-market adjustments on derivatives, a favorable movement of $39.3 million related to APL’s cash settlements on derivatives that were not designated as hedges and a non-cash derivative gain of $12.1 million related to APL’s early termination of a portion of its derivative contracts during 2008, partially offset by a net cash loss of $5.0 million related to APL’s early termination of a portion of these derivative contracts. The $42.7 million favorable movement in non-cash mark-to-market adjustments on APL’s derivatives was due principally to a decrease in forward crude oil market prices from December 31, 2008 to March 31, 2009 and their favorable mark-to-market impact on certain non-hedge derivative contracts APL has for production volumes in future periods. For example, average forward crude oil prices, which are the basis for adjusting the fair value of APL’s crude oil derivative contracts, at March 31, 2009, were $54.05 per barrel, a decrease of $2.89 per barrel from average forward crude oil market prices at December 31, 2008 of $56.94 per barrel. APL enters into derivative instruments solely to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under Item 3, “Quantitative and Qualitative Discussion About Market Risk”.

Other Income, Costs and Expenses.General and administrative expenses, including amounts reimbursed to affiliates, increased $6.9 million to $28.2 million for the three months ended March 31, 2009 compared with $21.3 million for the comparable prior year period. The increase was primarily related to $2.8 million of non-recurring severance and other related costs incurred during the first quarter 2009 for the termination of certain positions within APL’s Mid-Continent segment and a $3.3 million non-cash compensation net gain recognized during the first quarter 2008 principally associated with the vesting of certain APL common unit awards that were based on the financial performance of certain APL assets during 2008, partially offset by a $1.7 million increase in ATN salaries and wages. A portion of these common unit awards were issued during the first quarter 2009 with the remainder to be issued by APL during the second quarter 2009.

Depreciation, depletion and amortization increased to $52.7 million for the three months ended March 31, 2009 compared with $43.7 million for the comparable prior year period due primarily to an increase in ATN’s depletable basis and production volumes and APL’s expansion capital expenditures incurred between the periods.

Asset impairment of $4.0 million for the three months ended March 31, 2008 consisted of a write-off of costs related to an APL pipeline expansion project. The write-off of costs incurred consisted of a vendor deposit for the manufacture of pipeline which expired in accordance with APL’s contractual arrangement.

Interest expense increased to $34.6 million for the three months ended March 31, 2009 as compared with $34.1 million for the comparable prior year period. This $0.5 million increase was primarily due to an increase in borrowings from ATN and APL, partially offset by lower unhedged interest rates. APL issued additional senior unsecured notes during June 2008 and made a partial repayment of its senior secured term loan in June 2008. ATN issued additional senior unsecured notes in May 2008 and increased its borrowing under its credit facility.

Income tax expense was $3.0 million for the three months ended March 31, 2009 compared with $3.8 million for the comparable prior year period. Our effective income tax rate attributable to common shareholders of Atlas America Inc. was 39.2% and 37.4% for the three months ended March 31, 2009 and 2008, respectively. The increase in our effective income tax rate between periods is a result of a reduction in tax benefits related to depletion and tax-exempt interest income relative to income (loss) before taxes. Currently, it is our expectation that our effective income tax rate will approximate 39% for the year ended December 31, 2009.

Liquidity and Capital Resources

General

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 and cash on hand. Our operations principally occur through our subsidiaries, whose sources of liquidity are discussed in more detail below.

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

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

	•		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.

At March 31, 2009, ATN had $538.0 million of outstanding borrowings under its credit facility, with a borrowing base of $697.5 million. Effective April 9, 2009, the borrowing base was redetermined to $650.0 million (see “Subsequent Events”). In addition to the availability under its credit facility, ATN has an effective shelf registration statement with the Securities and Exchange Commission, which permits it to periodically issue up to $500.0 million of equity or debt securities. The amount, type and timing of any offerings will depend upon, among other things, ATN’s funding requirements, prevailing market conditions and compliance with its credit facility and unsecured senior note covenants.

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 March 31, 2009, AHD had $46.0 million outstanding and $4.0 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 or APL asset sales.

At March 31, 2009, APL had $324.0 million of outstanding borrowings under its $380.0 million credit facility and $5.4 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheet, with $50.6 million of remaining committed capacity under its credit facility, subject to covenant limitations.

However, we and our subsidiaries are subject to business, operational and other risks that could adversely affect our cash flow. We and our subsidiaries may supplement our cash generation with proceeds from financing activities, including borrowings under our subsidiaries’ credit facilities and other borrowings and the issuance of additional common shares and units and sale of assets.

Recent instability in the financial markets, as a result of recession or otherwise, has increased the cost of capital while the availability of funds has diminished significantly. This may affect our subsidiaries’ ability to raise capital and reduce the amount of cash available to fund its operations. Our subsidiaries rely on their cash flow from operations and their credit facilities to execute their growth strategy and to meet their financial commitments and other short-term liquidity needs. We cannot be certain that additional capital will be available to our subsidiaries to the extent required and on acceptable terms. We believe that we and our subsidiaries will have sufficient liquid assets, cash from operations and borrowing capacity to meet our and their financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve month period.

Cash Flows — Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008

Net cash provided by operating activities of $25.7 million for the three months ended March 31, 2009 represented an increase of $57.2 million from $31.5 million of net cash used in operating activities for the comparable prior year period. The decrease was derived principally from a $60.6 million increase in working capital changes and a $16.3 million favorable movement in distributions paid to non-controlling interest holders, partially offset by a $17.1 million decrease in net income excluding non-cash items. The movement in cash distributions to non-controlling interest holders is due mainly to decreases in AHD’s and APL’s cash distributions per unit. The non-cash charges which impacted net income include unfavorable decreases in non-cash loss on derivatives of $34.4 million and in asset impairments of $4.0 million, partially offset by favorable increases of $10.4 million in net loss and of $9.0 million for depreciation, depletion and amortization. The movement in non-cash derivative losses resulted from decreases in commodity prices during the three months ended March 31, 2009 and their favorable impact on the fair value of derivative contracts ATN and APL have for future periods. The increase in depreciation and amortization principally resulted from depreciation associated with ATN’s and APL’s expansion capital expenditures incurred subsequent to March 31, 2008.

Net cash used in investing activities of $130.0 million for the three months ended March 31, 2009 represented a decrease of $9.1 million from $139.1 million used in investing activities for the comparable prior year period. This decrease was principally due to a $9.6 million decrease in capital expenditures for ATN and APL. See further discussion of capital expenditures under "—Capital Requirements”.

Net cash provided by financing activities of $87.2 million for the three months ended March 31, 2009 represented a decrease of $54.2 million from $141.4 million of net cash provided by financing activities for the comparable prior year period. This decrease was principally due to a $250.0 million reduction in net proceeds from the issuance of debt related to ATN partially offset by a $194.0 million net increase in APL, ATN and AHD credit facility borrowings. These amounts were partially offset by a $4.2 million increase in the releases of treasury 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 had already invested $10.7 million at March 31, 2009. AHD, whose principal assets are its ownership interests in APL, does not have any separate capital requirements apart from APL. A more detailed discussion of ATN’s and APL’s capital requirements is provided below.

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

	•		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.

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
	March 31,
	2009		2008
Atlas Energy
Maintenance capital expenditures	$	12,975	$	12,975
Expansion capital expenditures		44,232		42,642

Total	$	57,207	$	55,617


Atlas Pipeline Partners
Maintenance capital expenditures	$	695	$	1,619
Expansion capital expenditures		72,218		82,450

Total	$	72,913	$	84,069


Consolidated
Maintenance capital expenditures	$	13,670	$	14,594
Expansion capital expenditures		116,450		125,092

Total	$	130,120	$	139,686

Atlas Energy. ATN’s capital expenditures increased to $57.2 million for the three months ended March 31, 2009 compared with $55.6 million for the prior year comparable period. The $57.2 million of capital expenditures for the three months ended March 31, 2009 consist principally of $27.8 million of investments in

ATN’s investment partnerships, compared with $25.7 million for the prior year comparable period, $11.7 million for wells drilled exclusively for its own account and $10.1 million of leasehold costs.

Atlas Pipeline Partners. APL’s expansion capital expenditures decreased to $72.2 million for the three months ended March 31, 2009 compared with $82.5 million for the prior year first quarter due principally to APL’s construction of a 60MMcfd expansion of its Sweetwater processing plant and APL’s acquisition of a gathering system located in Tennessee during the first quarter of 2008 partially offset by APL’s continued expansion of its gathering systems and upgrades to processing facilities and compressors to accommodate new wells drilled in its service areas. The decrease in maintenance capital expenditures for the three months ended March 31, 2009 when compared with the comparable prior year period was due to fluctuations in the timing of APL’s scheduled maintenance activity.

As of March 31, 2009, our subsidiaries are committed to expend approximately $56.7 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

Off Balance Sheet Arrangements

As of March 31, 2009, our off balance sheet arrangements are limited to ATN’s guarantee of Crown Drilling of Pennsylvania, LLC’s $9.2 million credit agreement, ATN’s and APL’s letters of credit outstanding of $1.2 million and $5.4 million, respectively, and their commitments to expend approximately $56.7 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 March 31, 2009.

Issuance of Subsidiary Common Units

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

Atlas Energy

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

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

Atlas Pipeline Partners and Atlas Pipeline Holdings

APL and AHD agreed to amend the terms of the APL Class B Preferred Units Certificate of Designation to remove the conversion feature, thus the APL Class B Preferred Units are not convertible into APL common units. The amended APL Class B Preferred Units Certificate of Designation also gives APL the right at any time to redeem some or all of the outstanding APL Class B Preferred Units for cash at an amount equal to the APL Class B Preferred Unit Liquidation Value being redeemed, provided that such redemption must be exercised for no less than the lesser of a) 2,500 APL Class B Preferred Units or b) the number of remaining outstanding APL Class B Preferred Units.

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

Dividends

We paid cash dividends of $2.0 million and $1.3 million for the three months ended March 31, 2009 and 2008, respectively. The determination of the amount of future cash dividends, if any, is at the sole discretion of our board of directors and will depend on the various factors affecting our financial condition and other matters the board of directors deems relevant.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include revenue and expense accruals, deferred tax assets and liabilities, depletion, depreciation and amortization, asset impairment, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. A discussion of our significant accounting policies we have adopted and followed in the preparation of our consolidated financial statements is included within our Annual Report on Form 10-K for the year ended December 31, 2008 and in Note 2 under Item 1, “Financial Statements” included in this report, and there have been no material changes to these policies through March 31, 2009.

Fair Value of Financial Instruments

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

SFAS No. 157’s hierarchy defines three levels of inputs that may be used to measure fair value:

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

We use the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities recorded at fair value, including ATN’s and APL’s derivative contracts and our Supplemental Employment Retirement Plan (“SERP”). All of ATN’s and APL’s commodity derivative contracts, with the exception of APL’s NGL fixed price swaps and crude oil options, are calculated based on observable market data related to the change in price of the underlying commodity or market interest rate and, therefore, are defined as Level 2 fair value measurements. ATN’s, APL’s and AHD’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model and are therefore defined as Level 2. Our SERP is calculated based on observable actuarial inputs developed by a third-party actuary and, therefore, is defined as a Level 2 fair value measurement. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of natural gas, crude oil and propane prices, and, therefore, are defined as Level 3 fair value measurements. Valuations for APL’s crude oil options (including those associated with NGL sales) are based on forward price curves developed by the related financial institution based upon current quoted prices for crude oil futures and therefore are defined as Level 3 fair value measurements. In addition, liabilities that are required to be measured at fair value on a non-recurring basis include asset retirement obligations that are defined as Level 3. Estimates of the fair value of asset retirement obligations are based on discounted cash flows using numerous estimates, assumptions, and judgments regarding the cost, timing of settlement, our credit-adjusted risk-free rate and inflation rates.

Recently Adopted Accounting Standards

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

interim periods within those fiscal years. Early adoption was prohibited. The guidance for determining the useful life of a recognized intangible asset should be applied prospectively to intangible assets acquired after the effective date. The disclosure requirements should be applied prospectively to all intangible assets recognized as of, and subsequent to, the effective date. We applied the requirements of FSP FAS 142-3 upon its adoption on January 1, 2009 and the adoption of FSP FAS 142-3 had no impact on our financial position and results of operations.

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

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

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

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

ITEM 3: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

General

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

We and our subsidiaries are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We and our subsidiaries manage these risks through regular operating and financing activities and periodical use of derivative financial instruments such as forward contracts and interest rate cap and swap agreements. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on March 31, 2009. Only the potential impact of hypothetical assumptions is analyzed. The analysis does not consider other possible effects that could impact our and our subsidiaries’ business.

Current market conditions elevate our and our subsidiaries’ concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to our subsidiaries, if any. The counterparties related to our subsidiaries’ commodity and interest-rate derivative contracts are banking institutions, who also participate in their revolving credit facilities. The creditworthiness of our subsidiaries’ counterparties is constantly monitored, and we currently believe them to be financially viable. We are not aware of any inability on the part of our subsidiaries’ counterparties to perform under their contracts and believe our exposure to non-performance is remote.

Interest Rate Risk.At March 31, 2009, ATN had an outstanding balance of $538.0 million on its revolving credit facility. The borrowing base was redetermined to $650.0 million effective April 9, 2009 with the execution of a second amendment to its credit facility. Effective with the second amendment, ATN’s applicable margins increased to a range of 1.125% to 2.125% for base rate loans and a range of 2.00% to 3.00% for LIBOR loans, dependent upon borrowing base utilization levels. The weighted average interest rate for borrowings under ATN’s credit facility was 2.5% at March 31, 2009. At March 31, 2009, ATN had interest rate derivative contracts having aggregate notional principal amounts of $150.0 million. Under the terms of this agreement, ATN will pay weighted average interest rates of 3.11% plus the applicable margin as defined under the terms of its revolving credit facility, and will receive LIBOR, plus the applicable margin on

the notional principal amounts. These derivatives effectively convert $150.0 million of ATN’s floating rate debt under its revolving credit facility to fixed rate debt.

At March 31, 2009, AHD had a $50.0 million senior secured revolving credit facility ($46.0 million outstanding). The weighted average interest rate for AHD’s revolving credit facility borrowings was 3.2% at March 31, 2009. 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 is effective as of March 31, 2009 and expires on May 28, 2010.

At March 31, 2009, APL had a $380.0 million senior secured revolving credit facility ($324.0 million outstanding). APL also had $707.2 million outstanding under its senior secured term loan at March 31, 2009. The weighted average interest rate for APL’s revolving credit facility borrowings was 2.8% at March 31, 2009, and the weighted average interest rate for the term loan borrowings was 3.3% at March 31, 2009. At March 31, 2009, APL had interest rate derivative contracts having aggregate notional principal amounts of $450.0 million. Under the terms of these agreements, APL will pay weighted average interest rates of 3.02%, plus the applicable margin as defined under the terms of its revolving credit facility, and will receive LIBOR, plus the applicable margin, on the notional principal amounts. These derivatives 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 March 31, 2009 and expire during periods ranging from January 30, 2010 through April 30, 2010.

Holding all other variables constant, including the effect of interest rate derivatives, a hypothetical 100 basis-point or 1% change in interest rates would change our consolidated interest expense by $9.9 million.

Commodity Price Risk. Our market risk exposure to commodities is due to the fluctuations in the price of natural gas, NGLs, condensate and oil and the impact those price movements have on the financial results of our subsidiaries. To limit its exposure to changing natural gas and oil prices, ATN uses financial derivative instruments for a portion of its future natural gas and oil production. APL is exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. APL enters into financial swap and option instruments to hedge forecasted sales against the variability in expected future cash flows attributable to changes in market prices. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate are sold. Under these swap agreements, APL receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas, NGLs and condensate at a fixed price for the relevant period. Both ATN and APL apply the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”).

Holding all other variables constant, including the effect of commodity derivatives, a 10% change in the average price of natural gas, NGLs, condensate and oil would result in a change to our consolidated operating income, excluding income tax effects, for the twelve-month period ending March 31, 2010 of approximately $35.4 million.

Atlas Energy.Realized pricing of ATN’s oil and natural gas production is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for many years. To limit its exposure to changing natural gas prices, ATN enters into natural gas and oil swap and costless collar option contracts. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX

contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas oil contracts are based on a West Texas Intermediate, or WTI, index.

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

The following table summarizes the fair value of ATN’s derivative instruments as of March 31, 2009 and December 31, 2008, as well as the gain or loss recognized for the three months ended March 31, 2009 and 2008, respectively.

Fair Value of Derivative Instruments


	March 31, 2009
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives in SFAS No. 133 Cash Flow Hedging Relationships:
Commodity contracts	Current portion of derivative asset	$	144,435	Current portion of derivative liability	$	(344	)
	Long-term asset		98,132	Long-term liability		(31	)

			242,567			(375	)

Interest rate contracts	Current portion of derivative asset		—	Current portion of derivative liability		(3,494	)
	Long-term derivative asset		—	Long-term derivative liability		(2,219	)

			—			(5,713	)


Total derivatives under SFAS No. 133		$	242,567		$	(6,088	)

Effects of Derivative Instruments on Consolidated Statements of Operations:


	March 31, 2009
				Location of
				Gain/(Loss)
	Gain/(Loss)			Reclassified from	Gain/(Loss)
	Recognized in OCI on			Accumulated OCI	Reclassified from
	Derivatives (Effective			into Income	OCI into Income
	Portion)			(Effective Portion)	(Effective Portion)
Derivatives in SFAS No. 133 Cash Flow Hedging Relationships:
Commodity contracts	$	86,814		Gas and oil production	$	15,518
Interest rate contracts		(873	)	Interest expense		(1,002	)

	$	85,941			$	(14,516	)

As of March 31, 2009, ATN had the following interest rate and commodity derivatives:

Interest Fixed Rate Swap


				Contract
	Notional			Period Ended	Fair Value
Term	Amount		Option Type	December 31,	Liability
					(in thousands)
January 2008 — January 2011	$	150,000,000	Pay 3.11% - Receive LIBOR	2009	$	(2,649	)
				2010		(2,877	)
				2011		(187	)

					$	(5,713	)

Natural Gas Fixed Price Swaps


Production
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset⁽¹⁾
	(MMBtu)		(per MMBtu)		(in thousands)
2009		31,020,000	$	8.24	$	122,338
2010		26,360,000	$	8.11		56,679
2011		18,680,000	$	7.84		21,031
2012		13,800,000	$	8.06		14,349
2013		1,500,000	$	8.73		2,225

					$	216,622

Natural Gas Costless Collars


Production
Period Ending					Average		Fair Value
December 31,		Option Type	Volumes		Floor and Cap		Asset⁽¹⁾
			(MMBtu)		(per MMBtu)		(in thousands)
	2009	Puts purchased		180,000	$	11.00	$	1,201
	2009	Calls sold		180,000	$	15.35		—
	2010	Puts purchased		3,360,000	$	7.84		7,034
	2010	Calls sold		3,360,000	$	9.01		—
	2011	Puts purchased		7,500,000	$	7.48		7,750
	2011	Calls sold		7,500,000	$	8.44		—
	2012	Puts purchased		1,020,000	$	7.00		407
	2012	Calls sold		1,020,000	$	8.32		—
	2013	Puts purchased		300,000	$	7.00		69
	2013	Calls sold		300,000	$	8.25		—

							$	16,461

Crude Oil Fixed Price Swaps


Production
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset⁽²⁾
	(Bbl)		(per Bbl)		(in thousands)
2009		47,300	$	99.73	$	2,206
2010		48,900	$	97.40		1,725
2011		42,600	$	96.44		1,226
2012		33,500	$	96.00		833
2013		10,000	$	96.06		232

					$	6,222

Crude Oil Costless Collars


Production
Period Ending				Average	Fair Value
December 31,	Option Type	Volumes		Floor and Cap	Asset⁽²⁾
		(Bbl)		(per Bbl)	(in thousands)
2009	Puts purchased		29,000	$85.00	$	944
2009	Calls sold		29,000	$117.48		—
2010	Puts purchased		31,000	$85.00		817
2010	Calls sold		31,000	$112.92		—
2011	Puts purchased		27,000	$85.00		603
2011	Calls sold		27,000	$110.81		—
2012	Puts purchased		21,500	$85.00		416
2012	Calls sold		21,500	$110.06		—
2013	Puts purchased		6,000	$85.00		107
2013	Calls sold		6,000	$110.09		—

					$	2,887

				Total ATN net asset	$	236,479


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

transmission, gathering and processing revenue and the portion relating to interest rate derivatives to interest expense within our consolidated statements of operations as the underlying transactions are settled. For AHD’s and APL’s non-qualifying derivatives and for the ineffective portion of qualifying derivatives, we will recognize changes in fair value within gain (loss) on mark-to-market derivatives in our consolidated statements of operations as they occur.

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


	March 31, 2009
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Current portion of derivative asset	$	—	Current portion of derivative liability	$	(10,252	)
Interest rate contracts	Long-term derivative asset		—	Long-term derivative liability		(523	)
Derivatives not designated as hedging instruments under SFAS No. 133:
Commodity contracts	Current portion of derivative liability		3,977	Current portion of derivative liability		(60,991	)
Commodity contracts	Long-term derivative liability		2,380	Long-term derivative liability		(25,147	)

		$	6,357		$	(96,913	)

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

March 31, 2009

Gain (Loss)

Location of Gain

Recognized in

(Loss) Recognized in

Income on

Amount of Gain

Derivative

(Loss) Reclassified

Location of Gain

(Ineffective

(Ineffective Portion

from

(Loss) Reclassified

Portion and

and Amount

Accumulated OCI

from Accumulated

Amount Excluded

Excluded from

into Income

OCI into Income

from Effectiveness

Effectiveness

(Effective Portion)

Testing)

Derivatives in SFAS No. 133 Cash Flow Hedging Relationships:

Interest rate contracts

(3,055

)

Interest expense

—

N/A

Derivatives not designated as hedging instruments under SFAS No. 133:

Commodity contracts⁽¹⁾

(15,970

)

Transmission, gathering and processing

(9,527

)

Gain (loss) on mark-to-market derivatives

Commodity contracts⁽²⁾

—

39,820

Gain (loss) on mark-to-market derivatives

(19,025

)

30,293


(1)		Hedges previously designated as cash flow hedges

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

As of March 31, 2009, AHD had the following interest rate derivatives:

Interest Fixed-Rate Swap


	Notional			Contract Period	Fair Value
Term	Amount		Type	Ended December 31,	Liability⁽¹⁾
					(in thousands)
May 2008-May 2010	$	25,000,000	Pay 3.01% —Receive LIBOR	2009	$	(444	)
				2010		(204	)

				Total AHD net liability	$	(648	)


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

As of March 31, 2009, 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,	Liability⁽¹⁾
					(in thousands)
January 2008-January 2010	$	200,000,000	Pay 2.88% —Receive LIBOR	2009	$	(3,374	)
				2010		(304	)

					$	(3,678	)



April 2008-April 2010	$	250,000,000	Pay 3.14% —Receive LIBOR	2009	$	(4,715	)
				2010		(1,734	)

					$	(6,449	)

Natural Gas Liquids Sales — Fixed Price Swaps

Production Period

Average

Fair Value

Ended December 31,

Volumes

Fixed Price

Asset⁽²⁾

(gallons)

(per gallon)

(in thousands)

2009

13,230,000

0.745

1,579

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)⁽¹⁾			Option Type
	(barrels)		(gallons)		(per barrel)		(in thousands)
2009		152,100		13,542,984	$	111.53	$	(11,171	)	Puts sold⁽⁴⁾
2009		152,100		13,542,984	$	157.82		—		Calls purchased⁽⁴⁾


Production Period			Associated		Average
Ended	Crude		NGL		Crude		Fair Value
December 31,	Volume		Volume		Strike Price		Asset/(Liability)⁽¹⁾			Option Type
	(barrels)		(gallons)		(per barrel)		(in thousands)
2009		1,588,500		88,643,058	$	84.69		(2,019	)	Calls sold
2010		3,127,500		213,088,050	$	86.20		(13,035	)	Calls sold
2010		714,000		45,415,440	$	132.17		638		Calls purchased⁽⁴⁾
2011		606,000		33,145,560	$	100.70		(3,071	)	Calls sold
2011		252,000		13,547,520	$	133.16		665		Calls purchased⁽⁴⁾
2012		450,000		25,893,000	$	102.71		(2,822	)	Calls sold
2012		180,000		9,676,800	$	134.27		657		Calls purchased⁽⁴⁾

							$	(30,158	)

Natural Gas Sales — Fixed Price Swaps

Production Period

Average

Fair Value

Ended December 31,

Volumes

Fixed Price

Asset⁽³⁾

(mmbtu)⁽⁵⁾

(per mmbtu)⁽⁵⁾

(in thousands)

2009

360,000

8.000

1,337

Natural Gas Basis Sales


Production Period			Average			Fair Value
Ended December 31,	Volumes		Fixed Price			Asset⁽³⁾
	(mmbtu)⁽⁵⁾		(per mmbtu)⁽⁵⁾			(in thousands)
2009		3,690,000	$	(0.558	)	$	673
2010		2,220,000	$	(0.575	)		301

						$	974

Natural Gas Purchases — Fixed Price Swaps


Production Period			Average		Fair Value
Ended December 31,	Volumes		Fixed Price		Liability⁽³⁾
	(mmbtu)⁽⁵⁾		(per mmbtu)⁽⁵⁾		(in thousands)
2009		7,740,000	$	8.687	$	(34,069	)
2010		4,380,000	$	8.635		(12,806	)

					$	(46,875	)

Natural Gas Basis Purchases


Production Period			Average			Fair Value
Ended December 31,	Volumes		Fixed Price			Liability⁽³⁾
	(mmbtu)⁽⁵⁾		(per mmbtu)⁽⁵⁾			(in thousands)
2009		11,070,000	$	(0.659	)	$	(2,837	)
2010		6,600,000	$	(0.560	)		(1,783	)

						$	(4,620	)

Ethane Put Options

Production Period

Associated

Average

Ended

NGL

Crude

Fair Value

December 31,

Volume

Strike Price

Asset⁽¹⁾

Option Type

(gallons)

(per gallon)

(in thousands)

2009

630,000

0.340

Puts purchased

Isobutane Put Options

Production Period

Associated

Average

Ended

NGL

Crude

Fair Value

December 31,

Volume

Strike Price

Liability⁽¹⁾

Option Type

(gallons)

(per gallon)

(in thousands)

2009

126,000

0.589

(10

)

Puts purchased

Normal Butane Put Options

Production Period

Associated

Average

Ended

NGL

Crude

Fair Value

December 31,

Volume

Strike Price

Liability⁽¹⁾

Option Type

(gallons)

(per gallon)

(in thousands)

2009

126,000

0.577

(10

)

Puts purchased

Natural Gasoline Put Options

Production Period

Associated

Average

Ended

NGL

Crude

Fair Value

December 31,

Volume

Strike Price

Liability⁽¹⁾

Option Type

(gallons)

(per gallon)

(in thousands)

2009

126,000

0.762

(10

)

Puts purchased

Crude Oil Sales

Production Period

Average

Fair Value

Ended December 31,

Volumes

Fixed Price

Asset⁽³⁾

(barrels)

(per barrel)

(in thousands)

2009

24,000

62.700

205

Crude Oil Sales Options


Production Period			Average		Fair Value
Ended December 31,	Volumes		Strike Price		Liability⁽¹⁾			Option Type
	(barrels)		(per barrel)		(in thousands)
2009		229,500	$	84.802	$	(314	)	Calls sold
2010		234,000	$	88.088		(912	)	Calls sold
2011		72,000	$	93.109		(502	)	Calls sold
2012		48,000	$	90.314		(478	)	Calls sold

					$	(2,206	)


			Total APL net liability		$	(89,909	)


⁽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 for 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.

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


	March 31,			December 31,
	2009			2008
Current portion of derivative asset	$	144,435		$	152,726
Long-term derivative asset		98,132			69,451
Current portion of derivative liability		(71,103	)		(73,776	)
Long-term derivative liability		(25,542	)		(59,103	)

Total net derivative asset	$	145,922		$	89,298

Atlas America.At March 31, 2009 and December 31, 2008, we reflected a net hedging asset on our consolidated balance sheets of $145.9 million and $89.3 million, respectively, as a result of ATN’s, AHD’s and APL’s derivative contracts. Of the $44.6 million gains in accumulated other comprehensive income at March 31, 2009, we will reclassify $26.5 million of gains to our consolidated statements of operations over the next twelve month period as these contracts expire, and $18.3 million of gains will be reclassified in later periods if the fair values of the instruments remain at current market values. Actual amounts that will be reclassified will vary as a result of future price changes.

ITEM 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2009, our disclosure controls and procedures were effective at the reasonable assurance level.

There have been no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

In January 2009, in the matter captioned “Elk City Oklahoma Pipeline, L.P. v. Northern Natural Gas

Company”, (District Court of Tulsa County, Oklahoma), Elk City Oklahoma Pipeline, L.P. (“Elk City”), a subsidiary of APL’s, filed a petition against Northern Natural Gas Company (“NNG”), seeking a declaratory judgment related to the interpretation of a Purchase and Sale Agreement for certain pipeline and assets in Western Oklahoma which was entered into between the two parties on June 12, 2008 (the “PSA”). In March 2009, NNG filed a petition together with a motion for summary judgment alleging breach of the PSA for Elk City’s failure to complete the purchase and seeking specific performance or, alternatively, damages, in the matter captioned “Northern Natural Gas Company vs. Elk City Oklahoma Pipeline, L.P.”, (District Court of Tulsa County, Oklahoma). Both matters are currently pending. APL believes that the claims are without merit and intend to pursue its action and defend against NNG’s claims. Additionally, APL believes that the ultimate resolution of these matters will not consequently have a material impact on our financial position and results of operations.

On April 30, 2009, a complaint seeking class certification was filed in the Court of Chancery of the State of Delaware against Atlas Energy Resources, its board of directors and us. The plaintiff seeks to represent persons who owned Atlas Energy Resources’ common units as of April 27, 2009, the date of execution of the definitive merger agreement with us. The complaint alleges that Atlas Energy Resources, its board of directors and us, as a majority unitholder, breached our fiduciary duties and asserts that the consideration to be paid by us in the proposed merger is inadequate. The action seeks a preliminary and permanent injunction from proceeding with the merger, compensatory damages in an unspecified amount, including plaintiff’s costs and expenses, and an order directing defendants to account to the plaintiffs for their damages. We believe that the allegations and purported claims in the complaint lack merit and that we have meritorious defenses to them, and we intend to contest the lawsuit vigorously. We are not presently able to estimate the impact, or potential losses, if any, related to this lawsuit.

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

ITEM 1A. RISK FACTORS

Our business operations and financial position are subject to various risks. These risks are described elsewhere in this report and in our most recent Form 10-K for the year ended December 31, 2008, as filed with the Securities and Exchange Commission on March 2, 2009. The risk factors identified in Item 1A, Risk Factors, of our 2008 Form 10-K have not changed in any material respect, except for the additional risk factors added below.

A decrease in natural gas prices could subject ATN’s oil and gas properties to a non-cash impairment loss under generally accepted accounting principles.Generally accepted accounting principles require oil and gas properties and other long-lived assets to be reviewed for impairment 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. ATN tests its oil and gas properties 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 own economic interests and 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 on current contracts in place at the impairment testing date, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. Accordingly, further declines in the price of natural gas may cause the carrying value of ATN’s oil and gas properties to exceed the expected future cash flows, and a non-cash impairment loss would be

required to be recognized in the financial statements for the difference between the estimated fair market value, (as determined by discounted future cash flows) and the carrying value of the assets.

Due to the accounting treatment of ATN’s and APL’s derivative contracts, increases in prices for natural gas and crude oil could result in non-cash balance sheet reductions. With the objective of enhancing the predictability of future revenues, from time to time ATN and APL enter into natural gas and crude oil derivative contracts. ATN elected to designate these derivative contracts as cash flow hedges under the provisions of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”. Due to the mark-to-market accounting treatment for these contracts, we could recognize incremental hedge liabilities between reporting periods resulting from increases in reference prices for natural gas and crude oil, which could result in our recognizing a non-cash loss in our accumulated other comprehensive income and a consequently non-cash decrease in our stockholders’ equity between reporting periods. Any such decrease could be substantial.

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
August 1 — 31, 2008		392,791	$	36.35		392,791
September 1 — 30, 2008		610,086		34.36		610,086
October 1 — 31, 2008		152,706		33.83		152,706

Total		1,155,583	$	34.76		1,155,583	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. No repurchases were made during the quarter ended March 31, 2009. 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.

ITEM 6. EXHIBITS


Exhibit No.		Description

2.1		Agreement and Plan of Merger, dated as of April 27, 2009, by and among Atlas Energy Resources, LLC, Atlas America, Inc., Atlas Energy Management, Inc. and Merger Sub, as defined therein.⁽¹¹⁾

3.1		Amended and Restated Certificate of Incorporation⁽¹⁾

3.2		Amended and Restated Bylaws⁽¹⁾

4.1		Form of stock certificate⁽²⁾


Exhibit No.		Description
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 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 dated January 1, 2002⁽²⁾

10.1	(c)	Amendment to Master Natural Gas Gathering Agreement and 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 America, 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. dated May 14, 2004⁽⁵⁾

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

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

10.5	(a)	Amendment to Employment Agreement dated as of December 31, 2008⁽¹²⁾

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

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

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

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⁾


Exhibit No.		Description
10.10		Stock Incentive Plan⁽¹²⁾

10.11		Atlas America Employee Stock Ownership Plan⁽⁸⁾

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

10.13		Form of Stock Award Agreement⁽⁹⁾

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

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

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

31.2		Rule 13(a)-14(a)/15d-14(a) Certification.

32.1		Section 1350 Certification.

32.2		Section 1350 Certification.


(1)		Previously filed as an exhibit to our Form 8-K filed June 14, 2005

(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 filed 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

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

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

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

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

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

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

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: May 11, 2009	By:	/s/ EDWARD E. COHEN
		Edward E. Cohen
		Chairman of the Board and Chief Executive Officer


Date: May 11, 2009	By:	/s/ MATTHEW A. JONES
		Matthew A. Jones
		Chief Financial Officer


Date: May 11, 2009	By:	/s/ SEAN P. MCGRATH
		Sean P. McGrath
		Chief Accounting Officer

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