ARKHAN 10-Q 2008 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2008

OR

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

For the transition period from            to            

Commission file number: 001-32169

ATLAS AMERICA, INC.

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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

The number of outstanding shares of the registrant’s common stock on May 7, 2008 was 40.3 million 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, 2008 and December 31, 2007 (Unaudited)	3
	Consolidated Statements of Income for the Three Months Ended March 31, 2008 (Unaudited)	4
	Consolidated Statement of Stockholders’ Equity for the Three Months Ended March 31, 2008 (Unaudited)	5
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2008 and 2007 (Unaudited)	6
	Notes to Financial Statements (Unaudited)	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	43
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	61
Item 4.	Controls and Procedures	68
PART II. OTHER INFORMATION
Item 1A.	Risk Factors	68
Item 6.	Exhibits	68
SIGNATURES		69

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, 2008			December 31, 2007
ASSETS
Current assets:
Cash and cash equivalents	$	116,386		$	145,535
Accounts receivable		275,241			204,900
Current portion of derivative asset		179			38,181
Prepaid expenses and other		27,112			22,939
Prepaid and deferred income taxes		36,031			20,641
Total current assets		454,949			432,196
Property, plant and equipment, net		3,544,974			3,442,036
Intangible assets, net		217,569			224,264
Goodwill, net		711,968			744,449
Other assets, net		69,211			63,584
	$	4,998,671		$	4,906,529
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	48		$	64
Accounts payable		78,181			75,524
Liabilities associated with drilling contracts		48,407			132,517
Accrued producer liabilities		104,757			80,697
Accrued derivative liability		177,864			111,223
Accrued liabilities		79,330			99,468
Advances from affiliate		421			58
Total current liabilities		489,008			499,551
Long-term debt		2,143,365			1,994,392
Deferred tax liability		198,006			197,106
Long-term derivative liability		233,527			157,850
Other long-term liabilities		49,062			46,524
Minority interests		1,496,549			1,597,943
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		290			290
Additional paid-in capital		391,700			390,591
Treasury stock, at cost		(108,445	)		(108,886	)
ESOP loan receivable		(398	)		(417	)
Accumulated other comprehensive loss		(36,591	)		(5,935	)
Retained earnings		142,598			137,520
Total stockholders’ equity		389,154			413,163
	$	4,998,671		$	4,906,529

See accompanying notes to consolidated financial statements

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ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per share data)

(Unaudited)

	Three Months Ended March 31,
	2008			2007
Revenue:
Well construction and completion	$	104,138		$	72,378
Gas and oil production		76,226			21,260
Transmission, gathering and processing		385,326			115,290
Administration and oversight		5,017			4,544
Well services		4,798			3,721
Loss on mark-to-market derivatives		(88,781	)		(2,278	)
Total revenue		486,724			214,915
Costs and expenses:
Well construction and completion		90,555			62,932
Gas and oil production		10,668			2,034
Transmission, gathering and processing		295,532			95,475
Well services		2,412			2,043
General and administrative		21,008			14,457
Net expense reimbursement – affiliate		250			308
Depreciation, depletion and amortization		47,633			12,401
Total costs and expenses		468,058			189,650
Operating income		18,666			25,265
Other income (expense):
Interest expense		(34,098	)		(7,256	)
Minority interests		23,665			(3,186	)
Other, net		2,030			1,444
Total other income (expense)		(8,403	)		(8,998	)
Income before income taxes		10,263			16,267
Provision for income taxes		(3,841	)		(6,019	)
Net income	$	6,422		$	10,248
Net income per common share:
Basic	$	0.24		$	0.36
Diluted	$	0.23		$	0.35
Weighted average common shares outstanding:
Basic		26,882			28,386
Diluted		28,054			29,217

See accompanying notes to consolidated financial statements

4

ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

FOR THE THREE MONTHS ENDED MARCH 31, 2008

(in thousands, except share data)

(Unaudited)

	Common Stock			Additional Paid-In Capital		Treasury Stock					ESOP Loan Receivable			Accumulated Other Comprehensive Loss			Retained Earnings			Total Stockholders’ Equity
	Shares	$				Shares		$
Balance at January 1, 2008	29,003,212	$	290	$	390,591	(2,126,055	)	$	(108,886	)	$	(417	)	$	(5,935	)	$	137,520		$	413,163
Issuance of common units	—		—		110	10,135			441			—			—			—			551
Other comprehensive loss	—		—		—	—			—			—			(30,656	)		—			(30,656	)
Repayment of ESOP loan	—		—		—	—			—			19			—			—			19
Stock option compensation expense	—		—		999	—			—			—			—			—			999
Dividends paid	—		—		—	—			—			—			—			(1,344	)		(1,344	)
Net income	—		—		—	—			—			—			—			6,422			6,422
Balance at March 31, 2008	29,003,212	$	290	$	391,700	(2,115,920	)	$	(108,445	)	$	(398	)	$	(36,591	)	$	142,598		$	389,154

See accompanying notes to consolidated financial statements

5

ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Three Months Ended March 31,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	6,422		$	10,248
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation, depletion and amortization		47,633			12,401
Amortization of deferred finance costs		1,479			571
Non-cash loss on derivative value		79,842			2,277
Non-cash compensation expense		192			4,036
Minority interests		(23,665	)		3,186
Gain on asset dispositions		(144	)		(26	)
Distributions paid to minority interests		(52,650	)		(11,174	)
Deferred income taxes		4,317			(1,221	)
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable and prepaid expenses and other		(24,693	)		15,543
Accounts payable and accrued liabilities		(71,683	)		(84,846	)
Accounts payable and accounts receivable – affiliates		363			330
Other operating assets/liabilities		1,126			—
Net cash used in operating activities		(31,461	)		(48,675	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition purchase price adjustment		1,281			—
Capital expenditures		(139,686	)		(38,706	)
Investment in Lightfoot Capital Partners, L.P.		(440	)		(931	)
Other		(232	)		(38	)
Net cash used in investing activities		(139,077	)		(39,675	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of Atlas Energy Resources, LLC long-term debt		250,000			—
Borrowings under Atlas Pipeline Partners, L.P., Atlas Pipeline Holdings, L.P., and Atlas Energy Resources, LLC credit facilities		173,000			117,000
Repayments under Atlas Pipeline Partners, L.P., Atlas Pipeline Holdings, L.P., and Atlas Energy Resources, LLC credit facilities		(274,008	)		(45,572	)
Dividends paid		(1,344	)		—
Purchase of treasury stock		—			(80,351	)
Other		(6,259	)		253
Net cash provided by (used in) financing activities		141,389			(8,670	)
Net change in cash and cash equivalents		(29,149	)		(97,020	)
Cash and cash equivalents, beginning of period		145,535			185,401
Cash and cash equivalents, end of period	$	116,386		$	88,381

See accompanying notes to consolidated financial statements

6

ATLAS AMERICA, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2008

(Unaudited)

NOTE 1 – BASIS OF PRESENTATION

Atlas America, Inc. (the “Company”) is a publicly traded (NASDAQ:ATLS) Delaware corporation whose assets consist primarily of cash and its ownership interests in the following entities as of March 31, 2008:

• Atlas Energy Resources, LLC (“Atlas Energy” or “ATN”), a publicly traded Delaware limited liability company (NYSE: ATN) focuses on natural gas development and production in northern Michigan’s Antrim Shale 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, 2008, the Company owned approximately 49.4% of the outstanding Class A and common units and all of the management incentive interests of ATN;

• 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 Atlas Pipeline Partners, L.P. (“Atlas Pipeline” or “APL”), a midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachia regions (NYSE:APL). Through the Company’s ownership of its general partner, it manages AHD. At March 31, 2008, the Company owned approximately 64.0% of the outstanding common units of AHD. In addition, AHD owned a 2% general partner interest, all of the incentive distribution rights, and an approximate 13.5% limited partner interest in APL at March 31, 2008; and

• Lightfoot Capital Partners LP and Lightfoot Capital Partners GP, LLC, 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 12% ownership interest in Lightfoot and a commitment to invest a total of $20.0 million in Lightfoot.

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

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

In addition to matters discussed further within this note, a more thorough discussion of the Company’s significant accounting policies is included in its audited consolidated financial statements and notes thereto in its annual report on Form 10-K for the year ended December 31, 2007.

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Principles of Consolidation and Minority Interest

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

In accordance with established practice in the oil and gas industry, the Company’s financial statements include its pro-rata share of assets, liabilities, revenues, and costs and expenses of the energy partnerships in which ATN has an interest. Such interests typically range from 30% to 35%.

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

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

Use of Estimates

The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Company’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Company’s consolidated financial statements are based on a number of significant estimates, including the revenue and expense accruals, deferred tax assets and liabilities, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions, stock compensation, and the allocation of purchase price to the fair value of assets acquired. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results were recorded using estimated volumes and commodity 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, 2008 represent actual results in all material respects (see “– Revenue Recognition” accounting policy for further description).

8

Revenue Recognition

Atlas Energy.Certain energy activities are conducted by ATN through, and a portion of its revenues are attributable to, sponsored energy limited partnerships. ATN contracts with the energy partnerships to drill partnership wells. The contracts require that the energy partnerships must pay ATN the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed in less than 60 days. On an uncompleted contract, ATN classifies the difference between the contract payments it has received and the revenue earned as a current liability titled “Liabilities Associated with Drilling Contracts” on the Company’s consolidated balance sheets. ATN recognizes well services revenues at the time the services are performed. ATN is also entitled to receive management fees according to the respective partnership agreements, and recognizes such fees as income when earned and includes them in administration and oversight revenues.

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

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

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

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

• 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

9

upon volumetric data from APL’s and ATN’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, 2008 and December 31, 2007 of $148.7 million and $131.7 million, respectively, which are included in accounts receivable within the Company’s consolidated balance sheets.

Net Income Per Share

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

	Three Months Ended March 31,
	2008	2007
Weighted average number of common shares – basic	26,882	28,386
Add: effect of dilutive incentive awards(1)	1,172	831
Weighted average number of common shares – diluted	28,054	29,217

⁽¹⁾ For the three months ended March 31, 2008, approximately 10,000 stock options were excluded from the computation of diluted net income per share because the inclusion of such shares would have been anti-dilutive.

Comprehensive Loss

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

	Three Months Ended March 31,
	2008			2007
Net income	$	6,422		$	10,248
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges, net of tax of $17,814 and $7,155 for the three months ended March 31, 2008 and 2007, respectively		(29,830	)		(11,320	)
Less: reclassification adjustment for realized losses (gains) in net income, net of tax of $565 and ($400) for the three months ended March 31, 2008 and 2007, respectively		(947	)		680
Plus: amortization of additional post-retirement liability recorded upon adoption of SFAS No. 158, net of tax of $51 and $27 for the three months ended March 31, 2008 and 2007, respectively		121			42
Total other comprehensive loss		(30,656	)		(10,598	)
Comprehensive loss	$	(24,234	)	$	(350	)

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Capitalized Interest

ATN and APL capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds by ATN and APL was 6.3% and 7.9% for the three months ended March 31, 2008 and 2007, respectively, and the amount of interest capitalized was $2.6 million and $0.8 million for the three months ended March 31, 2008 and 2007, respectively.

Intangible Assets

Customer contracts and relationships.APL has recorded intangible assets with finite lives in connection with natural gas gathering contracts and customer relationships assumed in certain consummated acquisitions (see Note 3). Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”) requires that intangible assets with finite useful lives be amortized over their estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset must be amortized over the best estimate of its useful life. At a minimum, APL will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. The estimated useful life for APL’s customer contract intangible assets is based upon the approximate average length of customer contracts in existence at the date of acquisition. The estimated useful life for APL’s customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition.

Partnership management, operating contracts and non-compete agreement.ATN has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through consummated acquisitions. In addition, ATN entered into a two year non-compete agreement in connection with the acquisition of AGO (see Note 3). ATN amortizes contracts acquired on a declining balance and straight-line method over their respective estimated useful lives.

The following table reflects the components of intangible assets being amortized at March 31, 2008 and December 31, 2007 (in thousands):

	March 31, 2008			December 31, 2007			Estimated Useful Lives In Years
Gross Carrying Amount:
Customer contracts and relationships	$	235,382		$	235,382		7 – 20
Partnership management and operating contracts		14,343			14,343		2 – 13
Non-compete agreement		890			890		2
	$	250,615		$	250,615
Accumulated Amortization:
Customer contracts and relationships	$	(22,567	)	$	(16,179	)
Partnership management and operating contracts		(10,145	)		(9,949	)
Non-compete agreement		(334	)		(223	)
	$	(33,046	)	$	(26,351	)
Net Carrying Amount:
Customer contracts and relationships	$	212,815		$	219,203
Partnership management and operating contracts		4,198			4,394
Non-compete agreement		556			667
	$	217,569		$	224,264

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Amortization expense on intangible assets was $6.7 million and $0.8 million for the three months ended March 31, 2008 and 2007, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2008-$26.8 million; 2009-$26.5 million; 2010-$26.3 million; 2011-$26.2 million; and 2012-$25.7 million.

Goodwill

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

	Three Months Ended March 31,
	2008			2007
Balance, beginning of period	$	744,449		$	98,607
Post-closing purchase price adjustment with seller and purchase price allocation adjustment – Chaney Dell and Midkiff/Benedum systems acquisition		(2,275	)		—
Recovery of state sales tax initially paid on transaction – Chaney Dell and Midkiff/Benedum systems acquisition		(30,206	)		—
Balance, end of period	$	711,968		$	98,607

During the fourth quarter 2007 and first quarter of 2008, APL adjusted its preliminary purchase price allocation by increasing the estimated amount allocated to goodwill and intangible assets and reducing amounts initially allocated to property, plant and equipment (see Note 3 and Note 4). Also, in April 2008, APL received a $30.2 million cash reimbursement for sales tax initially paid on its transaction to acquire the Chaney Dell and Midkiff/Benedum systems in July 2007. The $30.2 million was initially capitalized as an acquisition cost and allocated to the assets acquired, including goodwill, based upon their estimated fair values at the date of acquisition. At March 31, 2008, based upon the reimbursement of the sales tax paid in April 2008, APL reduced goodwill recognized in connection with the acquisition and recorded $30.2 million within accounts receivable on the Company’s consolidated balance sheet (see Notes 3 and 19). Due to the recent date of the Chaney Dell and Midkiff/Benedum acquisition, the purchase price allocation is based upon preliminary data that remains subject to adjustment and could further change as APL continues to evaluate this allocation. Other items could further adjust amounts allocated to goodwill in future periods, although no such items are currently anticipated by APL management.

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New and Recently Adopted Accounting Standards

In March 2008, the Financial Accounting Standards Board (“FASB”) ratified the Emerging Issues Task Force (“EITF”) consensus on EITF Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF No. 07-4”), an update of EITF No. 03-6, “Participating Securities and the Two-Class Method Under FASB Statement No. 128” (“EITF No. 03-6”). EITF No. 07-4 requires the calculation of a Master Limited Partnership’s net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings as if all of the earnings for that period had been distributed. In periods with undistributed earnings above specified levels, the calculation per the two-class method results in an increased allocation of such undistributed earnings to the general partner and a dilution of earnings to the limited partners. EITF No. 07-4 is effective for fiscal years beginning after December 15, 2008, including interim periods within those fiscal years, and requires retrospective application of the guidance to all periods presented. Early adoption is prohibited. The Company’s subsidiaries, APL, AHD and ATN, do not believe the adoption of EITF No. 07-4 will have any impact on its financial position or results of operations.

In March 2008, the Financial Accounting Standards Board (“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 to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, with early adoption encouraged. The Company is currently evaluating the impact the adoption of SFAS No. 161 will have on the disclosures regarding its derivative instruments.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 amends ARB No. 51 to establish accounting and reporting standards for the noncontrolling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 also requires consolidated net income to be reported, and disclosed on the face of the consolidated statement of income, at amounts that include the amounts attributable to both the parent and the noncontrolling interest. Additionally, SFAS No. 160 establishes a single method for accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. The Company will apply the requirements of SFAS No. 160 upon its adoption on January 1, 2009 and is currently evaluating whether SFAS No. 160 will have an impact on its financial position and results of operations.

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

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

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

NOTE 3 – ACQUISITIONS

APL’s Chaney Dell and Midkiff/Benedum Acquisition

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

In connection with this acquisition, APL has reached an agreement with Pioneer, which currently holds a 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer will have an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system beginning on June 15, 2008 and ending on November 1, 2008, and an additional 7.4% interest beginning on June 15, 2009 and ending on November 1, 2009 (the aggregate 22.0% additional interest can be entirely purchased during the period beginning June 15, 2009 and ending on November 1, 2009). If the option is fully exercised, Pioneer would increase its interest in the system to approximately 49.2%. Pioneer would pay approximately $230 million, subject to certain adjustments, for the additional 22% interest if fully exercised. APL will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercises the purchase options.

APL funded the purchase price in part from the private placement of 25.6 million common limited partner units at a negotiated purchase price of $44.00 per unit, generating gross proceeds of $1.125 billion. AHD purchased 3.8 million of the 25.6 million common limited partner units issued by APL for $168.8 million and funded this through the private placement of 6.25 million of its common units to investors at a negotiated price of $27.00 per unit, yielding gross proceeds of $168.8 million (or net proceeds of $167.0 million, after underwriting fees and other transaction costs). APL also received a capital contribution from

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AHD of $23.1 million in order for AHD to maintain its 2.0% general partner interest in APL. AHD funded this capital contribution and the underwriting fees and other transaction costs related to its private placement of common units through borrowings under its revolving credit facility of $25.0 million (see Note 7). AHD, which holds all of the incentive distribution rights of APL as general partner, has also agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. AHD also agreed that the resulting allocation of incentive distribution rights back to APL would be after AHD receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter (see Note 15). APL funded the remaining purchase price from an $830.0 million senior secured term loan which matures in July 2014 and a $300.0 million senior secured revolving credit facility that matures in July 2013 (see Note 7).

APL’s acquisition was accounted for using the purchase method of accounting under SFAS No. 141, “Business Combinations”. The following table presents the preliminary purchase price allocation as of March 31, 2008, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed in the acquisition, based on their fair values at the date of the acquisition (in thousands):

Accounts receivable	$	745
Prepaid expenses and other		4,587
Property, plant and equipment		1,030,464
Intangible assets – customer relationships		205,312
Goodwill		613,362
Total assets acquired		1,854,470
Accounts payable and accrued liabilities		(1,499	)
Net cash paid for acquisition	$	1,852,971

APL recorded goodwill in connection with this acquisition as a result of Chaney Dell’s and Midkiff/Benedum’s significant cash flow and strategic industry position. In April 2008, APL received a $30.2 million cash reimbursement for state sales tax initially paid on its transaction to acquire the Chaney Dell and Midkiff/Benedum systems. The $30.2 million was initially capitalized as an acquisition cost and allocated to the assets acquired, including goodwill, based upon their estimated fair values at the date of acquisition. At March 31, 2008, based upon the reimbursement of sales tax paid in April 2008, APL reduced goodwill recognized in connection with its acquisition and recorded $30.2 million within accounts receivable on the Company’s consolidated balance sheet. Due to the recent date of the acquisition, the purchase price allocation for the acquisition is based upon preliminary data that remains subject to adjustment and could change as APL continues to evaluate this allocation. Other items could further adjust the amounts allocated to goodwill, although no such items are currently anticipated by APL management. The results of Chaney Dell’s and Midkiff/Benedum’s operations are included within the Company’s consolidated financial statements from the date of acquisition.

ATN’s DTE Gas and Oil Company Acquisition

On June 29, 2007, ATN acquired all of the outstanding equity interests of DTE Gas & Oil Company (“DGO”) from DTE Energy Company (NYSE: DTE) and MCN Energy Enterprises for $1.273 billion, including adjustments for working capital of $15.0 million and current year capital expenditures of $19.0 million. Assets acquired include interests in approximately 2,150 natural gas wells with estimated proved reserves of approximately 610.6 billion cubic feet of natural gas equivalents located in the northern lower peninsula of Michigan, 228,000 developed acres, and 66,000 undeveloped acres. With this acquisition, the Company increased its natural gas and oil production as well as entered into a new region that offers additional opportunities to expand its operations. Subsequent to the acquisition of DGO, the Company changed DGO’s name to Atlas Gas & Oil Company (“AGO”).

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

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

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

The following data presents pro forma revenue, net income and net income per share for the Company for the three months ended 2007, as if the ATN and APL acquisitions discussed above and related financing transactions had occurred on January 1, 2007. Actual financial data for the three months ended March 31, 2008 is also presented. The Company has prepared these unaudited pro forma financial results for comparative purposes only. These pro forma financial results may not be indicative of the results that would have occurred if ATN and APL had completed these acquisitions and financing transactions at the beginning of the periods shown below or the results that will be attained in the future (in thousands, except per share data):

	Three Months Ended March 31,
	2008		2007
Revenue	$	486,724	$	338,760
Net income (loss)	$	6,422	$	(12,193	)
Net income (loss) per share:
Basic	$	0.24	$	(0.43	)
Diluted	$	0.23	$	(0.42	)

NOTE 4 – PROPERTY, PLANT AND EQUIPMENT

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

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

	March 31, 2008			December 31, 2007			Estimated Useful Lives in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,064,705		$	1,043,687
Wells and related equipment		799,708			752,184
Total proved properties		1,864,413			1,795,871
Unproved properties		9,724			16,380
Support equipment		7,636			6,936
Total natural gas and oil properties		1,881,773			1,819,187
Pipelines, processing and compression facilities		1,711,590			1,638,845		15 – 40
Rights of way		169,453			168,359		20 – 40
Land, buildings and improvements		23,312			21,742		10 – 40
Other		19,021			17,730		3 – 10
		3,805,149			3,665,863
Less – accumulated depreciation, depletion and amortization		(260,175	)		(223,827	)
	$	3,544,974		$	3,442,036

In July 2007, APL acquired control of the Chaney Dell and Midkiff/Benedum systems (see Note 3). During the fourth quarter of 2007 and first quarter of 2008, APL adjusted its preliminary purchase price allocation by adjusting the estimated amounts allocated to goodwill and property, plant, and equipment. Due to the recent date of acquisition, the purchase price allocation is based upon estimated values determined by APL, which are subject to adjustment and could change as APL continues to evaluate this allocation. Other items could further adjust amounts allocated to goodwill and property, plant and equipment in future periods, although no such items are currently anticipated by APL management.

ATN follows the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil is converted to gas equivalent basis (“Mcfe”) at the rate 1 barrel equals 6 Mcf. Depletion is provided on the units-of-production method.

Upon the sale or retirement of a complete or partial unit of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to accumulated 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 consolidated 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, 2008		December 31, 2007
Deferred finance costs, net of accumulated amortization of $15,692 and $14,213 at March 31, 2008 and December 31, 2007, respectively	$	30,757	$	26,118
Investments		11,757		12,061
Security deposits		2,802		2,630
Long-term derivative receivable from investment partnerships		21,709		13,542
Long-term derivative receivable		1,963		6,882
Other		223		2,351
	$	69,211	$	63,584

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Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (see Note 7). Long-term hedge receivable from Partnerships represents the portion of long-term unrealized hedge on contracts that has been allocated to them based on their share of total production volume sold. ATN also has a $19.5 and $0.2 million short-term hedge receivable from Partnerships as of March 31, 2008 and December 31, 2007, respectively, representing the short-term unrealized hedge on contracts that have been allocated to them, which is included as part of the Company’s accounts receivable.

NOTE 6 – ASSET RETIREMENT OBLIGATIONS

The Company follows SFAS No 143, “Accounting for Retirement Asset Obligations” (“SFAS No. 143”) and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), which requires the Company to recognize an estimated liability for the plugging and abandonment of ATN’s oil and gas wells. Under SFAS 143, the Company must currently recognize a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. SFAS 143 requires the Company to consider estimated salvage value in the calculation of depreciation, depletion and amortization. The Company’s asset retirement obligations consist principally of the plugging and abandonment of ATN’s oil and gas wells.

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

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

	Three Months Ended March 31,
	2008			2007
Asset retirement obligations, beginning of period	$	42,358		$	26,726
Liabilities incurred		782			520
Liabilities settled		(2	)		(21	)
Accretion expense		663			365
Asset retirement obligations, end of period	$	43,801		$	27,590

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

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NOTE 7 – DEBT

Total debt consists of the following (in thousands):

	March 31, 2008			December 31, 2007
ATN revolving credit facility	$	579,000		$	740,000
ATN senior notes		250,000			—
AHD revolving credit facility		25,000			25,000
APL revolving credit facility		165,000			105,000
APL term loan		830,000			830,000
APL senior notes		294,365			294,392
Other debt		48			64
		2,143,413			1,994,456
Less current maturities		(48	)		(64	)
Total long-term debt	$	2,143,365		$	1,994,392

ATN Revolving Credit Facility

Upon the closing of its acquisition of DTE Gas & Oil (see Note 3), ATN replaced its existing credit facility with a new 5-year credit facility with an initial borrowing base of $850.0 with a syndicate of banks. The revolving credit facility’s borrowing base will be redetermined semiannually on April 1 and October 1 subject to changes in ATN’s oil and gas reserves. The initial borrowing base was reduced to $672.5 million in January 2008 upon the issuance by ATN of $250.0 million in senior unsecured notes and subsequently redetermined on April 30, 2008 to a borrowing base of $735.0 million. Up to $50.0 million of the facility may be in the form of standby letters of credit. The facility is secured by ATN’s assets 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, 2008, the weighted average interest rate on outstanding borrowings was 4.3%.

The base rate for any day equals the higher of the federal funds rate plus 0.50% or the J.P. Morgan prime rate. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for Eurocurrency liabilities. The applicable margin ranges from 0.0% to 0.75% for base rate loans and 1.00% to 1.75% for LIBOR loans.

The credit facility requires ATN to maintain specified financial ratios of current assets to current liabilities and debt to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”) as disclosed in the loan agreement. In addition, the facility 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, 2008. The facility terminates in June 2012, when all outstanding borrowings must be repaid. At March 31, 2008 and December 31, 2007, letters of credit of $1.1 million were outstanding, which are not reflected as borrowings on the Company’s consolidated balance sheets.

ATN Senior Notes

In January 2008, ATN issued $250.0 million of 10-year, 10.75% senior unsecured notes due 2018. ATN used the proceeds of the note offering to reduce the balance outstanding on its senior secured credit facility. Interest on the ATN senior notes is payable semi-annually in arrears on February 1 and August 1 of each year. The ATN senior notes are redeemable at any time at certain 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 ATN senior notes with the proceeds of certain equity offerings at a stated redemption price. The ATN senior notes are also subject to repurchase by us at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if ATN does not reinvest the net proceeds within 360 days. The ATN senior notes are junior in right of payment to ATN’s secured debt, including ATN’s obligations under its credit facility.

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The indenture governing the ATN senior notes contains covenants, including limitations of ATN’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. ATN is in compliance with these covenants as of March 31, 2008. In connection with a Senior Notes registration rights agreement entered into by ATN, it filed an exchange offer registration statement with the Securities and Exchange Commission on March 28, 2008.

AHD Credit Facility

AHD has a $50.0 million revolving credit facility with a syndicate of banks. At March 31, 2008, AHD had $25.0 million outstanding under its revolving credit facility, which was utilized to fund its capital contribution to APL to maintain its 2.0% general partner interest, underwriter fees and other transaction costs related to its July 2007 private placement of common units (see Note 3). AHD’s credit facility matures in April 2010 and bears interest, at its option, at either (i) adjusted LIBOR (plus the applicable margin, as defined in the credit facility) or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank, National Association prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding credit facility borrowings at March 31, 2008 was 5.0%. Borrowings under AHD’s credit facility are secured by a first-priority lien on a security interest in all of AHD’s assets, including a pledge of its interests in APL, and are guaranteed by AHD’s subsidiaries (excluding APL and its subsidiaries). AHD’s credit facility contains customary covenants, including restrictions on its ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to AHD’s unitholders if an event of default exists or would result from such distribution; or enter into a merger or sale of substantially all of AHD’s property or assets, including the sale or transfer of interests in its subsidiaries. AHD is in compliance with these covenants as of March 31, 2008.

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, 2008, AHD’s combined leverage ratio was 4.7 to 1.0, its funded debt to EBITDA was 0.7 to 1.0, and its interest coverage ratio was 28.0 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

In connection with APL’s July 2007 acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 3), APL entered into a new credit facility, comprised of an $830.0 million senior secured term loan (“term loan”) which matures in July 2014 and a $300.0 million senior secured revolving credit facility which matures in July 2013. Borrowings under the APL credit facility bear interest, at APL’s option,

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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 APL’s outstanding revolving credit facility borrowings at March 31, 2008 was 4.9%, and the weighted average interest rate on the outstanding term loan borrowings at March 31, 2008 was 5.5%. Up to $50.0 million of the APL credit facility may be utilized for letters of credit, of which $14.0 million was outstanding at March 31, 2008. These outstanding letter of credit amounts were not reflected as borrowings on the Company’s consolidated balance sheet. 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 APL 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, 2008. Mandatory prepayments of the amounts borrowed under the term loan portion of the APL credit facility are required from the net cash proceeds of debt issuances, and of dispositions of assets that exceed $50.0 million in the aggregate in any fiscal year that are not reinvested in replacement assets within 360 days. In connection with the new credit facility, APL agreed to remit an underwriting fee to the lead underwriting bank of the credit facility of 0.75% of the aggregate principal amount of the term loan outstanding on January 23, 2008. In January 2008, APL and the underwriting bank agreed to extend the agreement through June 30, 2008.

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 2.5 to 1.0, increasing to 2.75 to 1.0 commencing September 30, 2008. 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, 2008, APL’s ratio of funded debt to EBITDA was 4.6 to 1.0 and its interest coverage ratio was 3.4 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, 2008, APL has $293.5 million of 10-year, 8.125% senior unsecured notes due 2015 outstanding, net of unamortized premium received of $0.9 million. Interest on the APL senior notes 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. In addition, prior to December 15, 2008, APL may redeem up to 35% of the aggregate principal amount of the APL senior notes with the proceeds of certain equity offerings at a stated redemption price. The APL senior notes 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.

The indenture governing the APL senior notes contains 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, 2008.

21

NOTE 8 – DERIVATIVE INSTRUMENTS

APL and ATN use a number of different derivative instruments, principally swaps and options, in connection with its commodity price and interest rate risk management activities. The Company and its subsidiaries enter into financial swap and option 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. These financial swap and option instruments are generally classified as cash flow hedges in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”).

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 income. For derivatives qualifying as hedges, the Company and its subsidiaries recognize the effective portion of changes in fair value in stockholders’ equity as accumulated other comprehensive income (loss), and reclassifies the portion relating to commodity derivatives to gas and oil production revenues for ATN derivatives, gathering, transmission and processing revenues for APL derivatives, and the portion relating to interest rate derivatives to interest expense within the company’s consolidated statements of income 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 income as they occur.

Derivatives are recorded on the Company’s consolidated balance sheet as assets or liabilities at fair value. At March 31, 2008 and December 31, 2007, the Company reflected net derivative liabilities on its consolidated balance sheets of $411.4 million and $224.0 million, respectively. Of the $36.9 million of net loss in accumulated other comprehensive loss within stockholders’ equity on the Company’s consolidated balance sheet at March 31, 2008, if the fair values of the instruments remain at current market values, the Company will reclassify $16.0 million of losses to the Company’s consolidated statements of income over the next twelve month period as these contracts expire, consisting of $14.6 million of losses to gas and oil production revenues, $1.0 million of losses to gathering, transmission and processing revenues, and $0.4 million of losses to interest expense. Aggregate losses of $20.9 million will be reclassified to the Company’s consolidated statements of income in later periods as these remaining contracts expire, consisting of $19.0 million of losses to gas and oil production revenues, $1.4 million of losses to gathering, transmission and processing revenues, and $0.5 million of losses to interest expense. Actual amounts that will be reclassified will vary as a result of future price changes.

22

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

ATN recognized gains on settled contracts covering natural gas production of $6.5 million and $2.4 million for the three months ended March 31, 2008 and 2007, respectively. There were no oil settlements for the three months ended March 31, 2008 or 2007. As the underlying prices and terms in the ATN’s hedge contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three months ended March 31, 2008 and 2007 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

As of March 31, 2008, ATN had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swap

Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Asset/(Liability)(1)
					(in thousands)
January 2008 - January 2011	$	150,000,000	Pay 3.11%—Receive LIBOR	2008	$	(982	)
				2009		(1,225	)
				2010		23
				2011		57
					$	(2,127	)

Natural Gas Fixed Price Swaps

Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value (Liability)
	(MMbtu) (4)	(per MMbtu) (4)		(in thousands) (2)
2008	29,670,000	$	8.72	$	(44,667	)
2009	37,760,000	$	8.54		(41,732	)
2010	26,360,000	$	8.11		(22,838	)
2011	18,680,000	$	7.90		(15,482	)
2012	13,800,000	$	8.20		(7,813	)
2013	1,500,000	$	8.73		(132	)
				$	(132,664	)

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Natural Gas Costless Collars

Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value (Liability)
		(MMbtu) (4)	(per MMbtu) (4)		(in thousands) (2)
2008	Puts purchased	1,170,000	$	7.50	$	—
2008	Calls sold	1,170,000	$	9.40		(1,423	)
2010	Puts purchased	2,880,000	$	7.75		—
2010	Calls sold	2,880,000	$	8.75		(2,055	)
2011	Puts purchased	7,200,000	$	7.50		—
2011	Calls sold	7,200,000	$	8.45		(4,968	)
2012	Puts purchased	720,000	$	7.00		—
2012	Calls sold	720,000	$	8.37		(633	)
					$	(9,079	)

Crude Oil Fixed Price Swaps

Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset
		(per Bbl)		(in thousands) (3)
2008	33,000	$	103.25	$	125
2009	36,000	$	99.03		117
2010	31,000	$	96.52		76
2011	25,000	$	95.79		52
2012	21,500	$	95.35		36
2013	6,000	$	95.35		9
				$	415

Crude Oil Costless Collars

Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset
			(per Bbl)		(in thousands) (3)
2008	Puts purchased	30,500	$	85.00	$	15
2008	Calls sold	30,500	$	127.13		—
2009	Puts purchased	36,500	$	85.00		50
2009	Calls sold	36,500	$	118.63		—
2010	Puts purchased	31,000	$	85.00		44
2010	Calls sold	31,000	$	112.92		—
2011	Puts purchased	27,000	$	85.00		35
2011	Calls sold	27,000	$	110.81		—
2012	Puts purchased	21,500	$	85.00		25
2012	Calls sold	21,500	$	110.06		—
2013	Puts purchased	6,000	$	85.00		7
2013	Calls sold	6,000	$	110.09		—
					$	176
				Total ATN net liability	$	(143,279	)

⁽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 on forward NYMEX natural gas prices, as applicable.

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

⁽⁴⁾ Mmbtu represents million British Thermal Units.

24

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

In connection with its Chaney Dell and Midkiff/Benedum acquisition, APL reached an agreement with Pioneer which grants Pioneer an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system beginning on June 15, 2008 and ending on November 1, 2008, and an additional 7.4% interest beginning on June 15, 2009 and ending on November 1, 2009 (the aggregate 22.0% additional interest can be entirely purchased during the period beginning June 15, 2009 and ending on November 1, 2009; see Note 3). At March 31, 2008, APL has received no indication that Pioneer will exercise either of its options under the agreement. If Pioneer does exercise either of these options, APL will discontinue hedge accounting for the derivative instruments covering the portion of the forecasted production of the Midkiff/Benedum system sold to Pioneer and will evaluate these derivative instruments to determine if they can be documented to match other forecasted production APL may have.

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

	Three Months Ended March 31,
	2008			2007
Loss from cash settlement of qualifying hedge instruments(1)	$	(17,643	)	$	(3,047	)
Loss from change in market value of non-qualifying derivatives(2)		(71,196	)		(1,302	)
Loss from change in market value of ineffective portion of qualifying derivatives(2)		(5,660	)		(975	)
Loss from cash settlement of non-qualifying derivatives(2)		(11,925	)		—

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

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

25

As of March 31, 2008, APL had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swap

Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Liability(1)
					(in thousands)
January 2008 - January 2010	$	200,000,000	Pay 2.88%—Receive LIBOR	2008	$	(973	)
				2009		(1,161	)
				2010		(15	)
					$	(2,149	)

Natural Gas Liquids Sales – Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability(2)
	(gallons)	(per gallon)		(in thousands)
2008	23,940,000	$	0.697	$	(13,911	)
2009	8,568,000	$	0.746		(4,574	)
				$	(18,485	)

Crude Oil Sales Options (associated with NGL volume)

Production Period Ended December 31,	Crude Volume	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset/(Liability)(3)			Option Type
	(barrels)	(gallons)	(per barrel)		(in thousands)
2008	3,517,200	240,141,888	$	60.00	$	359		Puts purchased
2008	3,517,200	240,141,888	$	79.08		(69,908	)	Calls sold
2009	5,184,000	354,533,760	$	60.00		3,999		Puts purchased
2009	5,184,000	354,533,760	$	78.88		(101,264	)	Calls sold
2010	3,127,500	213,088,050	$	61.08		5,325		Puts purchased
2010	3,127,500	213,088,050	$	81.09		(58,437	)	Calls sold
2011	606,000	34,869,240	$	70.59		3,057		Puts purchased
2011	606,000	34,869,240	$	95.56		(7,655	)	Calls sold
2012	450,000	25,893,000	$	70.80		2,636		Puts purchased
2012	450,000	25,893,000	$	97.10		(5,719	)	Calls sold
					$	(227,607	)

Natural Gas Sales – Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability(3)
	(mmbtu)(4)	(per mmbtu) (4)		(in thousands)
2008	4,113,000	$	8.804	$	(6,161	)
2009	5,724,000	$	8.611		(6,491	)
2010	4,560,000	$	8.526		(2,570	)
2011	2,160,000	$	8.270		(1,064	)
2012	1,560,000	$	8.250		(733	)
				$	(17,019	)

Natural Gas Basis Sales

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset(3)
	(mmbtu)(4)	(per mmbtu)(4)			(in thousands)
2008	4,113,000	$	(0.732	)	$	592
2009	5,724,000	$	(0.558	)		1,674
2010	4,560,000	$	(0.622	)		763
2011	2,160,000	$	(0.664	)		196
2012	1,560,000	$	(0.601	)		81
					$	3,306

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Natural Gas Purchases – Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset(3)
	(mmbtu)(4)	(per mmbtu)(4)			(in thousands)
2008	12,195,000	$	8.978	(5)	$	16,358
2009	15,564,000	$	8.680			16,570
2010	8,940,000	$	8.580			5,277
2011	2,160,000	$	8.270			1,064
2012	1,560,000	$	8.250			733
					$	40,002

Natural Gas Basis Purchases

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Liability(3)
	(mmbtu)(4)	(per mmbtu)(4)			(in thousands)
2008	12,195,000	$	(1.114	)	$	(2,732	)
2009	15,564,000	$	(0.654	)		(8,222	)
2010	8,940,000	$	(0.600	)		(4,227	)
2011	2,160,000	$	(0.700	)		(221	)
2012	1,560,000	$	(0.610	)		(55	)
					$	(15,457	)

Crude Oil Sales

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability(3)
	(barrels)	(per barrel)		(in thousands)
2008	45,300	$	59.664	$	(1,821	)
2009	33,000	$	62.700		(1,103	)
				$	(2,924	)

Crude Oil Sales Options

Production Period Ended December 31,	Volumes	Average Strike Price		Fair Value Asset/(Liability)(3)			Option Type
	(barrels)	(per barrel)		(in thousands)
2008	204,900	$	60.000	$	(31	)	Puts purchased
2008	204,900	$	78.128		(9,481	)	Calls sold
2009	306,000	$	60.000		735		Puts purchased
2009	306,000	$	80.017		(11,235	)	Calls sold
2010	234,000	$	61.795		816		Puts purchased
2010	234,000	$	83.027		(6,956	)	Calls sold
2011	30,000	$	60.000		296		Puts purchased
2011	30,000	$	74.500		(1,211	)	Calls sold
2012	30,000	$	60.000		209		Puts purchased
2012	30,000	$	73.900		(908	)	Calls sold
				$	(27,766	)
	Total APL net liability			$	(268,099	)
	Total net liability			$	(411,378	)

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

27

⁽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⁾ Mmbtu represents million British Thermal Units.

⁽⁵⁾ Includes APL’s premium received from the its sale of an option for it to sell 936,000 mmbtu of natural gas for the year ended December 31, 2008 at $15.50 per mmbtu.

NOTE 9 – FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company adopted the provisions of SFAS No. 157 at January 1, 2008. SFAS No. 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS No. 157’s hierarchy defines three levels of inputs that may be used to measure fair value:

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

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

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

The Company uses the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities recorded at fair value, including ATN’s and APL’s commodity hedges and interest rate swaps (see Note 8) and the Company’s Supplemental Employment Retirement Plan (“SERP”) (see Note 17). ATN’s and APL’s commodity hedges, with the exception of APL’s NGL fixed price swaps and crude oil collars are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. ATN’s and APL’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model, and are therefore defined as Level 2 fair value measurements. 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, 2008 (in thousands):

	Level 1		Level 2			Level 3			Total
SERP liability	$	—	$	(2,694	)	$	—		$	(2,694	)
APL commodity-based derivatives		—		7,907			(273,857	)		(265,950	)
APL interest rate swap-based derivatives		—		(2,149	)		—			(2,149	)
ATN commodity-based derivatives		—		(141,152	)		—			(141,152	)
ATN interest rate swap-based derivatives		—		(2,127	)		—			(2,127	)
Total	$	—	$	(140,215	)	$	(273,857	)	$	(414,072	)

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

28

	NGL Fixed Price Swaps			Crude Oil Sales Options (assoc. with NGL Volume)			Crude Oil Sales Options			Total
Balance – December 31, 2007	$	(33,624	)	$	(24,740	)	$	(145,418	)	$	(203,782	)
Cash settlements from unrealized gain(1)		804			2,025			9,847			12,676
Cash settlements from other comprehensive income (loss)(1)		13,300			1,139			(139	)		14,300
Net change in unrealized gain (loss)(2)		(98	)		92			(87,936	)		(87,942	)
Net change in other comprehensive income (loss)		1,133			(6,282	)		(3,960	)		(9,109	)
Balance – March 31, 2008	$	(18,485	)	$	(27,766	)	$	(227,607	)	$	(273,857	)

derivative instruments as of March 31, 2008 (in thousands):

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

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

NOTE 10 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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

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

Relationship with Resource America, Inc.On June 30, 2005, Resource America, Inc. (“RAI”) completed its spin-off of the Company. The Company reimburses RAI for various costs and expenses it incurs on behalf of the Company, primarily payroll and rent. For the three months ended March 31, 2008 and 2007, these costs totaled $250,000 and $308,000, respectively.

As of March 31, 2008 and December 31, 2007, certain operating expenditures totaling $421,000 and $58,000, respectively, that remain to be settled between the Company and RAI are reflected in the Company’s consolidated balance sheets as advances from affiliate.

NOTE 11 – COMMITMENTS AND CONTINGENCIES

The Company, through ATN, is the managing general partner of various energy partnerships, and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of partnership assets. Subject to certain conditions, investor partners in certain energy partnerships have the right to present their interests for purchase by ATN, as managing general partner. ATN is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on past experience, the Company believes that any liability incurred would not be material.

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ATN may be required to subordinate a part of its net partnership revenues from its energy partnerships to the receipt by investor partners of cash distributions from the energy partnerships equal to at least 10% of their subscriptions determined on a cumulative basis, in accordance with the terms of the partnership agreements.

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

As of March 31, 2008, the Company is committed to expend approximately $163.8 million on pipeline extensions, compressor station upgrades, and processing facility upgrades.

The Company is also 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 adopted the provisions of FASB Interpretation 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”) on January 1, 2007. As required by FIN 48, which clarifies SFAS 109, the Company recognizes the financial statement benefit of a tax position after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater then 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. At the adoption date, the Company applied FIN 48 to all tax positions for which the statute of limitation remained open. During the quarter ended March 31, 2008, there were no additions, reductions or settlements in unrecognized tax benefits. The Company has no material uncertain tax positions and the implementation of FIN 48 did not have a significant impact on the consolidated financial statements of the Company.

The Company is subject to income taxes in the U.S. federal jurisdiction and various states. Tax regulations within each jurisdiction are subject to the interpretations of the related tax laws and regulations and require significant judgment to apply. With few exceptions, the Company is no longer subject to U.S. federal, state, and local, or non-U.S. income tax examinations by tax authorities for the years before 2004. The Company’s policy is to reflect interest and penalties related to uncertain tax positions as part of the income tax expense, when and if they become applicable.

NOTE 13 – COMMON STOCK

Stock splits

On April 27, 2007, the Company’s Board of Directors approved a 3-for-2 stock split of the Company’s common stock effected in the form of a 50% stock dividend. All shareholders of record as of May 15, 2007 received one additional share of common stock for every two shares of common stock held on

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that date. The additional shares of common stock were distributed on May 25, 2007. Information pertaining to shares and earnings per share has been restated, for the three months ended March 31, 2007 in the accompanying financial statements and notes to the consolidated financial statements to reflect this split.

Dutch Auction Tender Offer

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

NOTE 14 – ISSUANCE OF SUBSIDIARY UNITS

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

In July 2007, APL sold 25.6 million common units through a private placement to investors at a negotiated purchase price of $44.00 per unit, yielding net proceeds of approximately $1.125 billion. Of the 25.6 million common units sold by APL, 3.8 million common units were purchased by AHD for $168.8 million. APL also received a capital contribution from AHD of $23.1 million for AHD to maintain its 2.0% general partner interest in APL. AHD funded this capital contribution, underwriting fees and other transaction costs related to its private placement of common units through borrowings under its revolving credit facility of $25.0 million. APL utilized the net proceeds from the sale to partially fund the acquisition of control of the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and a 72.8% interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (see Note 3).

In July 2007, AHD issued 6.25 million common units (an approximate 27% interest in it) for net proceeds of $167.0 million after offering costs in a private placement offering. In addition, in July 2007 APL issued 25.6 million common units through a private placement to investors, of which 3.8 million common units were purchased by AHD. The Company has accounted for these offerings in accordance with SAB 51. Accordingly, a gain of $53.0 million, net of an income tax provision of $34.3 million, was recorded in consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $87.3 million to minority interest, during the year ended December 31, 2007. The Company has adopted a policy to recognize gains on such transactions as an increase directly to equity rather than as income. This gain represents the Company’s portion of the excess net offering price per unit of each of its subsidiary’s units to the book carrying amount per unit.

In June 2007, ATN issued 24.0 million Class B common and Class D units (an approximate 31% interest in ATN at that time) for net proceeds of $597.5 million after offering costs in a private placement offering. The Company has accounted for this offering in accordance with SAB 51. Accordingly, a gain of $147.9 million, net of an income tax provision of $87.5 million, was recorded in consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $235.4 million to minority interest, in the year ended December 31, 2007. This gain represents the Company’s portion of the excess net offering price per unit of its subsidiary’s units to the book carrying amount per unit.

NOTE 15 – CASH DISTRIBUTIONS

Atlas Pipeline Partners Cash Distributions.APL is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its

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common unitholders and AHD, as general partner. If APL’s common unit distributions in any quarter exceed specified target levels, AHD will receive between 15% and 50% of such distributions in excess of the specified target levels. Distributions declared by APL for the period from January 1, 2007 through March 31, 2008 were as follows:

Date Cash Distribution Paid or Payable	For Quarter Ended	APL Cash Distribution per Common Limited Partner Unit		Total APL Cash Distribution to Common Limited Partners		Total APL Cash Distribution to AHD
				(in thousands)		(in thousands)
February 14, 2007	December 31, 2006	$	0.86	$	11,249	$	4,193
May 15, 2007	March 31, 2007	$	0.86	$	11,249	$	4,193
August 14, 2007	June 30, 2007	$	0.87	$	11,380	$	4,326
November 14, 2007	September 30, 2007	$	0.91	$	35,205	$	4,498
February 14, 2008	December 31, 2007	$	0.93	$	36,051	$	5,092
May 15, 2008(1)	March 31, 2008	$	0.94	$	36,450	$	7,891

(1) Declared subsequent to March 31, 2008 (see Note 19)

In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 3), AHD, which holds all of the incentive distribution rights in APL, agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. AHD also agreed that the resulting allocation of incentive distribution rights back to APL would be after AHD receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter (“IDR Adjustment Agreement”).

The Company does not receive any cash distributions directly from APL, however, it receives quarterly cash distributions from AHD according to the policies described below.

Atlas Pipeline Holdings Cash Distributions.AHD has a cash distribution policy under which it distributes, within 50 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders. Distributions declared by AHD for the period from January 1, 2007 through March 31, 2008 were as follows:

Date Cash Distribution Paid or Payable	For Quarter Ended	Cash Distribution per Common Limited Partner Unit		Total Cash Distribution to the Company (in thousands)
February 19, 2007	December 31, 2006	$	0.25	$	4,375
May 18, 2007	March 31, 2007	$	0.25	$	4,375
August 17, 2007	June 30, 2007	$	0.26	$	4,550
November 19, 2007	September 30, 2007	$	0.32	$	5,600
February 19, 2008	December 31, 2007	$	0.34	$	5,950
May 20, 2008(1)	March 31, 2008	$	0.43	$	7,525

(1) Declared subsequent to March 31, 2008 (see Note 19)

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

Date Cash Distribution Paid or Payable	For Quarter Ended	Cash Distribution Per Common Unit			Total Cash Distribution to the Company		Manager Incentive Distribution Earned(3)
					(in thousands)		(in thousands)
February 14, 2007	December 31, 2006	$	0.06	(1)	$	1,806	$	—
May 15, 2007	March 31, 2007	$	0.43		$	12,944	$	—
August 14, 2007	June 30, 2007	$	0.43		$	12,944	$	—
November 14, 2007	September 30, 2007	$	0.55		$	16,825	$	784
February 14 , 2008	December 31, 2007	$	0.57		$	17,437	$	965
May 15 , 2008(2)	March 31, 2008	$	0.59		$	18,410	$	1,251

(1) Represents a pro-rated cash distribution of $0.42 per unit for the period from December 18, 2006, the date of ATN’s initial public offering, through December 31, 2006.

(2) Declared subsequent to March 31, 2008 (see Note 19).

(3) Payable to the Company in 2010, provided ATN meets certain distribution levels.

NOTE 16 – INVESTMENT IN LIGHTFOOT

In 2007, the Company’s subsidiary, Atlas Lightfoot, LLC, invested $10.4 million in Lightfoot and owns, directly and indirectly, approximately 12% of the entity of whom Jonathan Cohen, Vice Chairman of the Company’s Board of Directors, is the Chairman of the Board. The Company committed to invest a total of $20.0 million in Lightfoot. The Company will also receive certain co-investment rights until such point as Lightfoot raises additional capital through a private offering to institutional investors or a public offering. Lightfoot has an initial equity funding commitments of approximately $160.0 million and intends to focus its investments primarily on incubating new master limited partnerships and providing capital to existing MLPs in need of additional equity or structured debt. Lightfoot will concentrate on assets that are MLP-qualified such as infrastructure, coal, and other asset categories and intends to form new MLPs in partnership with premier management teams in sectors that have been under-utilized by the MLP structure. The Company accounts for its investment in Lightfoot under the equity method of accounting.

NOTE 17 – BENEFIT PLANS

Incentive Bonus Plan

The Company’s shareholders approved an Incentive Bonus Plan (“Bonus Plan”) in 2007 for the benefit of its senior executive officers. The total amount of cash bonus awards to be made under the Bonus Plan for any plan year will be based on performance goals related to objective business criteria for such year. For any plan year, the Company’s performance must achieve levels targeted by the Company’s compensation committee, as established at the beginning of each year, for any bonus awards to be made. Aggregate bonus awards to all participants under the Bonus Plan may not exceed a limit as set by the compensation committee. The compensation committee has the authority to reduce the total amount of bonus awards, if any, to be made to the eligible employees for any plan year based on its assessment of personal performance or other factors as the Board may determine to be relevant or appropriate. The compensation committee may permit participants to elect to defer awards.

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Stock Incentive Plan

The Company has a Stock Incentive Plan (the “Plan”) which authorizes the granting of up to 3.0 million 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 1,125,000 shares awarded in fiscal 2005 to Messrs. Edward Cohen and Jonathan Cohen which are immediately exercisable, and expire not later than ten years after the date of grant. Compensation cost is recorded on a straight-line basis. The Company issues new shares when stock options are exercised or units are converted to shares. For the three months ended March 31, 2007, the Company received $95,500 from the exercise of stock options. There were no stock options exercised during the three months ended March 31, 2008.

The following table sets forth the Plan activity for the three months ended March 31, 2008 and 2007:

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in Years)	Aggregate Intrinsic Value (in thousands)
Outstanding at December 31, 2007	1,810,254		$	18.15
Granted	550,000		$	49.01
Exercised	—			—
Forfeited or expired	—			—
Outstanding at March 31, 2008	2,360,254		$	25.34	8.0	$	82,844
Options exercisable at March 31, 2008	1,411,017		$	17.27	7.3
Available for grant at March 31, 2008	562,565
Outstanding at December 31, 2006	1,844,288		$	17.73
Granted	—			—
Exercised	(5,625	)	$	16.98
Forfeited or expired	—			—
Outstanding at March 31, 2007	1,838,663		$	17.73

The Company used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted during the three months ended March 31, 2008. The following weighted average assumptions were used:

	Three Months Ended March 31, 2008
Expected dividend yield		0.4	%
Expected stock price volatility		33	%
Risk-free interest rate		2.6	%
Expected term (in years)		6.25
Fair value of stock options granted	$	17.62

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Deferred and Restricted Units. 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 units are granted from time to time to employees of the Company. Each unit represents the right to receive one share of the Company’s common stock upon vesting. The units are issued to the Restricted Stock Plan when granted, and paid to the Company’s employees 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 sets forth the deferred and restricted units activity for the three months ended March 31, 2008:

	Units		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2007	14,263		$	21.98
Granted	—			—
Vested	(750	)	$	31.14
Forfeited	—			—
Non-vested shares outstanding at March 31, 2008	13,513		$	21.47

For the three months ended March 31, 2008 and 2007, the Company recorded non-cash compensation expense of $1.0 million and $0.5 million, respectively, for the Company’s options and units. At March 31, 2008, the Company had unamortized compensation expense related to its unvested portion of the options and units of $11.6 million that the Company expects to recognize over four years.

Employee Stock Ownership Plan

In connection with the spin-off from RAI, the Company established an Employee Stock Ownership Plan (“ESOP”) in June 2005. The ESOP, which is a qualified non-contributory retirement plan, was established to acquire shares of the Company’s common stock for the benefit of all employees who are 21 years of age or older and have completed 1,000 hours of service. These shares have been converted to the Company’s common stock from RAI stock in an even exchange. The Company loaned $602,000 (payable in quarterly installments of $18,508 plus interest at 7.5%) to the ESOP, which was used by the ESOP to acquire the remaining 40,375 unallocated shares of RAI common stock. Contributions to the ESOP are made at the discretion of the Company’s Board of Directors. The cost of shares purchased by the ESOP but not yet allocated to participants is shown as a reduction of stockholders’ equity. The unearned benefits expense (a reduction in stockholders’ equity) will be reduced by the amount of any loan principal payments made by the ESOP to the Company. Any dividends which may be paid on allocated shares will reduce retained earnings; dividends on unearned ESOP shares will be used to service the related debt.

The common stock purchased by the ESOP with the money borrowed is held by the ESOP trustee in a suspense account. On an annual basis, as the ESOP loan is paid down, a portion of the common stock will be released from the suspense account and allocated to participating employees. As of March 31, 2008, there were 497,735 shares allocated to participants and 47,655 shares which are unallocated. The fair value of unearned ESOP shares was $2.9 million at March 31, 2008.

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Supplemental Employment Retirement Plan

In May 2004, the Company entered into an employment agreement with its Chairman of the Board, Chief Executive Officer and President, Edward E. Cohen, pursuant to which the Company has agreed to provide him with a SERP and with certain financial benefits upon termination of his employment. Under the SERP, Mr. Cohen will be paid an annual benefit equal to the product of (a) 6.5% multiplied by, (b) his base salary at the time of his retirement, death or other termination of employment with the Company, multiplied by, (c) the amount of years he shall be employed by the Company commencing upon the effective date of the SERP agreement, limited to an annual maximum benefit of 65% of his final base salary and a minimum of 26% of his final base salary. For the three months ended March 31, 2008 and 2007, expense recognized with respect to this commitment was $0.2 million for both periods. As of March 31, 2008, the present value of the expected postretirement obligation due under the SERP was $2.7 million, which is included in other long-term liabilities on the Company’s consolidated balance sheet. The following table provides information about amounts recognized in the Company’s consolidated balance sheets at the dates indicated (in thousands):

	March 31, 2008			December 31, 2007
Other liabilities	$	(2,694	)	$	(2,475	)
Accumulated other comprehensive loss		379			466
Deferred income tax asset		223			274
Net amount recognized	$	(2,092	)	$	(1,735	)

The estimated amount that will be amortized from accumulated other comprehensive loss into expense in 2008 is $0.9 million.

AHD Long-Term Incentive Plan

AHD has a Long-Term Incentive Plan (“AHD LTIP”), which provides performance incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for AHD. The AHD LTIP is administered by a committee (the “AHD LTIP Committee”), appointed by AHD’s board. Under the AHD LTIP, phantom units and/or unit options may be granted, at the discretion of the AHD LTIP Committee, to all or designated Participants, at the discretion of the AHD LTIP Committee. The AHD LTIP Committee may grant such awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units. At March 31, 2008, AHD had 1,440,475 phantom units and unit options outstanding under the AHD LTIP, with 659,150 phantom units and unit options available for grant.

AHD Phantom Units.A phantom unit entitles a Participant to receive a common unit of AHD 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, 2008, phantom units granted under the AHD LTIP generally will vest 25% three years from the date of grant and 100% four years from the date of grant. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the AHD LTIP Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control of AHD, as defined in the AHD LTIP. Of the phantom units outstanding under the AHD LTIP at March 31, 2008, 675 units will vest within the following twelve months. All phantom units outstanding under

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the AHD LTIP at March 31, 2008 include DERs granted to the Participants by the AHD LTIP Committee. The amount paid with respect to the AHD LTIP DERs was $0.1 million for both the three months ended March 31, 2008 and 2007. This amount was recorded as an adjustment of minority interests on the Company’s consolidated balance sheet.

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

	Three Months Ended March 31,
	2008		2007
Outstanding, beginning of period		220,825		220,492
Granted(1)		4,650		—
Unit adjustment		—		(492	)
Matured		—		—
Forfeited		—		—
Outstanding, end of period		225,475		220,000
Non-cash compensation expense recognized (in thousands)	$	366	$	345

⁽¹⁾ The weighted average price for phantom unit awards on the date of grant, which is utilized in the calculation of compensation expense and does not represent an exercise price to be paid by the recipient, was $32.28 for the three months ended March 31, 2008.

At March 31, 2008, AHD had approximately $3.3 million of unrecognized compensation expense related to unvested phantom units outstanding under the AHD LTIP based upon the fair value of the awards.

AHD Unit Options.A unit option entitles a Participant to receive a common unit of AHD upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of AHD’s common unit as determined by 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, 2008, 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 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. There are no unit options outstanding under the AHD LTIP at March 31, 2008 that will vest within the following twelve months. The following table sets forth the AHD LTIP unit option activity for the periods indicated:

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	Three Months Ended March 31,
	2008				2007
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of period		1,215,000	$	22.56		1,215,000	$	22.56
Granted		—		—		—		—
Matured		—		—		—		—
Forfeited		—		—		—		—
Outstanding, end of period(1)(2)		1,215,000	$	22.56		1,215,000	$	22.56
Options exercisable, end of period		—		—		—		—
Non-cash compensation expense recognized (in thousands)	$	309			$	309

(1) The weighted average remaining contractual life for outstanding options at March 31, 2008 was 8.6 years.

(2) The aggregate intrinsic value of options outstanding at March 31, 2008 was approximately $5.8 million.

At March 31, 2008, AHD had approximately $2.8 million of unrecognized compensation expense related to unvested unit options outstanding under the AHD LTIP based upon the fair value of the awards.

APL Long-Term Incentive Plan

APL has a 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 APL’s managing board. The APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 435,000 common units. Only phantom units have been granted under the APL LTIP through March 31, 2008.

A phantom unit entitles a grantee to receive a common unit 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, 2008, phantom units granted under the APL LTIP generally had vesting periods of four years. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the APL LTIP Committee, although no awards currently outstanding contain any such provision. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards will automatically vest upon a change of control, as defined in the APL LTIP. Of the units outstanding under the APL LTIP at March 31, 2008, 69,519 units will vest within the following twelve months. All units outstanding under the APL LTIP at March 31, 2008 include DERs granted to the participants by the APL LTIP Committee. The amount paid with respect to APL LTIP DERs was $0.1 million for both the three-month periods ended March 31, 2008 and 2007. These amounts were recorded as adjustments to minority interests on the Company’s consolidated balance sheet.

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

	Three Months Ended March 31,
	2008			2007
Outstanding, beginning of period		129,746			159,067
Granted(1)		53,951			24,792
Matured		(11,860	)		—
Forfeited		(750	)		—
Outstanding, end of period		171,087			183,859
Non-cash compensation expense recognized
(in thousands)	$	486		$	901

⁽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 $44.44 and $50.10 for awards granted for the three months ended March 31, 2008 and 2007, respectively.

At March 31, 2008, APL had approximately $4.1 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIP based upon the fair value of the awards.

APL Incentive Compensation Agreements

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

APL recognized compensation expense (income) of ($3.3) million and $0.9 million for the three months ended March 31, 2008 and 2007, respectively, related to the vesting of awards under these incentive compensation agreements. The decrease in non-cash compensation expense was principally attributable to a mark-to-market gain recognized for these awards as a result of a decrease in APL’s common unit market price at March 31, 2008 when compared with the December 31, 2007 price, which is utilized in the estimation of the non-cash compensation expense for these awards. The vesting period for such awards concluded on September 30, 2007. APL management anticipates that adjustments will be recorded in future periods with respect to the awards under the incentive compensation agreements based upon the actual financial performance of the assets in future periods in comparison to their estimated performance and the movement in the market value of APL’s common units. Based upon APL management’s estimate of the probable outcome of the performance targets at March 31, 2008, 928,939 common unit awards are ultimately expected to be issued under these agreements during the year ended December 31, 2009. APL follows SFAS No. 123(R) and recognized compensation expense related to these awards based upon the fair value method.

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ATN Long-Term Incentive Plan

ATN has a Long-Term Incentive Plan (“ATN LTIP”), which provides performance incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners. The ATN LTIP is administered by its compensation committee, which may grant awards of either restricted stock units, phantom units or unit options for an aggregate of 3,742,000 common units. Awards granted in the three months ended March 31, 2008 and 2007 vest 25% after three years and 100% upon the four year anniversary of grant, except for awards of 1,500 units in each period to board members which vest 25% per year over four years. Upon termination of service by a grantee, all unvested awards are forfeited. A restricted stock or phantom unit entitles a grantee to receive a common unit of ATN upon vesting of the unit or, at the discretion of the ATN’s compensation committee, cash equivalent to the then fair market value of a common unit of ATN. In tandem with phantom unit grants, ATN’s compensation committee may grant a distribution equivalent right (“DER”), which is the right to receive cash per restricted unit in an amount equal to, and at the same time as, the cash distributions ATN makes on a common unit during the period such phantom unit is outstanding.

Restricted Stock and Phantom Units. Under the ATN LTIP, 12,375 and 511,000 units of restricted stock and phantom units were awarded in the three months ended March 31, 2008 and 2007, 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 three months ended March 31, 2008:

	Units		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2007	624,665		$	24.42
Granted	12,375			28.17
Vested	(375	)		23.06
Forfeited	(100	)		35.00
Non-vested shares outstanding at March 31, 2008	636,565		$	24.49

Stock Options. In the three months ended March 31, 2008 and 2007, 6,500 and 1,297,600 unit options, respectively, 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 the 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:

	Three Months Ended March 31,
	2008			2007
Expected life (years)		6.25			6.25
Expected volatility		27	%		25	%
Risk-free interest rate		2.8	%		4.7	%
Expected dividend yield		7.0	%		8.0	%
Weighted average fair value of stock options granted	$	3.41		$	2.41

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The following table sets forth option activity for the three months ended March 31, 2008:

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding at December 31, 2007	1,895,052		$	24.09	8.9
Granted	6,500		$	30.24
Exercised	—			—
Forfeited or expired	(1,200	)	$	26.05
Outstanding at March 31, 2008	1,900,352		$	24.11	8.7	$	13,085
Options exercisable at March 31, 2008	93,438		$	21.00	8.7
Available for grant at March 31, 2008	1,192,804

ATN recognized $1.3 million and $1.0 million in compensation expense related to restricted stock units, phantom units and stock options for the three months ended March 31, 2008 and 2007, respectively. ATN paid $320,000 and $34,000 with respect to its ATN LTIP DERs for the three months ended March 31, 2008 and 2007, respectively. These amounts were recorded as an adjustment to minority interests on the Company’s consolidated balance sheets. At March 31, 2008, ATN had approximately $14.8 million of unrecognized compensation expense related to the unvested portion of the restricted stock units, phantom units and options.

NOTE 18 – OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS

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,
	2008			2007
Gas and Oil Production
Revenues	$	76,226		$	21,260
Costs and expenses		(10,668	)		(2,034	)
Segment profit	$	65,558		$	19,226
Well Construction and Completion
Revenues	$	104,138		$	72,378
Costs and expenses		(90,555	)		(62,932	)
Segment profit	$	13,583		$	9,446
Atlas Pipeline
Revenues (a)	$	292,135		$	109,724
Revenues – affiliates		9,224			7,733
Costs and expenses		(295,411	)		(95,451	)
Segment profit	$	5,948		$	22,006
Reconciliation of segment profit to net income before tax
Segment profit:
Gas and oil production	$	65,558		$	19,226
Well construction and completion		13,583			9,446

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Atlas Pipeline		5,948			22,006
Total segment profit		85,089			50,678
General and administrative expenses		(21,008	)		(14,457	)
Net expense reimbursement – affiliate		(250	)		(308	)
Depreciation, depletion and amortization		(47,633	)		(12,401	)
Other income (expense) – net (b)		(5,935	)		(7,245	)
Net income before tax	$	10,263		$	16,267
Capital expenditures
Gas and oil production	$	54,474		$	21,494
Well construction and completion		—			—
Atlas Pipeline		84,069			16,629
Corporate and other		1,143			583
Total capital expenditures	$	139,686		$	38,706
	March 31, 2008			December 31, 2007
Balance sheet
Goodwill:
Gas and oil production	$	21,527		$	21,527
Well construction and completion		6,389			6,389
Atlas Pipeline		676,802			709,283
Corporate and other		7,250			7,250
Total goodwill	$	711,968		$	744,449
Total assets:
Gas and oil production	$	1,849,376		$	1,821,631
Well construction and completion		13,229			11,138
Atlas Pipeline		2,942,531			2,877,518
Corporate and other		193,535			196,242
Total assets	$	4,998,671		$	4,906,529

(a) Includes loss on mark-to-market derivatives of $88.8 million and $2.3 million for the three months ended March 31, 2008 and 2007, respectively.

(b) Includes revenues and expenses from well services, transportation and administration and oversight of $2.2 million and $1.8 million that do not meet the quantitative threshold for reporting segment information for the three months ended March 31, 2008 and 2007, respectively.

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

NOTE 19 – SUBSEQUENT EVENTS

On May 6, 2008, ATN issued a $150 million follow-on offering of its 10.75% senior unsecured notes due 2018. The notes priced at 104.75% of par to yield approximately 9.85% to the par call on February 1, 2016. The notes from the follow-on offering announced today and the notes issued on January 23, 2008 shall be treated as a single class of debt securities. ATN intends to use the net proceeds of the offering to repay a portion of its outstanding balance under its revolving credit facility. The increased borrowing capacity will be used to fund additional acreage acquisitions and accelerated development of the Marcellus Shale as well as further development of its other drilling programs and lease acquisition activities.

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On May 5, 2008, ATN entered into a purchase agreement with the Company and sold 600,000 common units representing Class B limited liability company interests in a private transaction exempt from the registration requirements under Section 4(2) of the Securities Act of 1933, as amended. The units were sold at $42.00, the closing price of ATN’s units on the New York Stock Exchange on May 5, 2008, for total proceeds to ATN of $25.2 million.

On April 23, 2008, the Company’s Board of Directors approved a 3-for-2 stock split of its common stock effected in the form of a 50% stock dividend. All shareholders of record as of May 21, 2008 will receive one additional share of common stock for every two shares of common stock held on that date. The additional shares of common stock will be distributed on May 30, 2008. Information pertaining to shares and earnings per share have not been restated in the accompanying consolidated financial statements and notes thereto to reflect this split, but will be presented in the Company’s interim consolidated financial statements for the period as of and ending June 30, 2008.

On April 23, 2008, the Company’s Board of Directors declared a cash dividend of $0.05 per share, payable on May 20, 2008 to shareholders of record on May 7, 2008.

On April 22, 2008, APL declared a quarterly cash distribution of $0.94 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2008. The $44.3 million distribution, including $7.9 million to AHD for its general partner interest after the allocation of $3.8 million of its incentive distribution rights back to APL, will be paid on May 15, 2008 to unitholders of record at the close of business on May 7, 2008.

On April 22, 2008, AHD declared a quarterly cash distribution of $0.43 per unit, payable on May 20, 2008 to unitholders of record on May 7, 2008.

On April 22, 2008, ATN declared a quarterly cash distribution of $0.59 per unit, payable on May 15, 2008 to unitholders of record on May 7, 2008.

During April 2008, APL entered into interest rate derivative contracts having an aggregate notional principal amount of $250.0 million. Under the terms of this agreement, APL will pay a weighted average interest rate of 3.14%, plus the applicable margin as defined under the terms of its credit facility (see Note 7), and will receive LIBOR plus the applicable margin, on the notional principal amount of $250.0 million. This hedge effectively converts $250.0 million of APL’s floating rate debt under its credit facility to fixed-rate debt. APL’s interest rate swap agreement began on April 30, 2008 and expires on April 30, 2010.

During 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. At March 31, 2008, based upon the recovery of the sales tax paid in April 2008, APL has reduced goodwill recognized in connection with the acquisition and recorded $30.2 million within accounts receivable on the Company’s consolidated balance sheet.

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

Forward-Looking Statements

When used in this Form 10-Q, the words “believes,” “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties more particularly described in Item 1A, “Risk Factors”, in our annual report on Form 10-K for 2007. These risks and uncertainties could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on

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these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

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

General

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

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

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

• Lightfoot Capital Partners LP and Lightfoot Capital Partners GP, LLC, the general partner of Lightfoot (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. We have an approximate 12% ownership interest in Lightfoot and a commitment to invest a total of $20.0 million in Lightfoot.

Our ownership interest in ATN consists of the following:

• all of the outstanding Class A units, representing 1,238,986 units at March 31, 2008, which entitles us to receive 2% of the cash distributed by ATN without any obligation to make future capital contributions to ATN;

• all of the management incentive interests in ATN, which entitle us to receive increasing percentages, up to a maximum of 25.0%, of any cash distributed by ATN as it reaches certain target 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

• 29,352,996 common units, representing approximately 48.3% of the outstanding common units at March 31, 2008, or a 49.4% ownership interest in ATN.

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

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

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• 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 or any of such four quarters.

Our ownership interest in AHD consists of 17,500,000 common units, representing approximately 64.0% of the outstanding common units of AHD at March 31, 2008. AHD’s general partner, which is a wholly-owned subsidiary of ours, does not have an economic interest in AHD, and AHD’s capital structure does not include incentive distribution rights. AHD’s ownership interest in APL consists of the following:

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

• all of the incentive distribution rights, which entitle it to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per APL common unit in any quarter. In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems, AHD, the holder of all of the incentive distribution rights in APL, had agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. AHD also agreed that the resulting allocation of incentive distribution rights back to APL would be after AHD receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter (“IDR Adjustment Agreement”); and

• 5,476,253 common units, representing approximately 14.1% of the outstanding common units at March 31, 2008, or a 13.5% ownership interest in APL.

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

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

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

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

Financial Presentation

Our principal operating activities are conducted principally through ATN, AHD, and APL, and our cash flows consist primarily of distributions from received from ATN and AHD on our partnership interests. Our consolidated financial statements contain the consolidated financial statements of ATN and AHD, and

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AHD’s consolidated financial statements include the consolidated financial statements of APL. The non-controlling minority interests in ATN, AHD and APL are reflected as income (expense) in our consolidated statements of income (expense) and as a liability on our consolidated balance sheet. Throughout this section, when we refer to “our” consolidated financial statements, we are referring to the consolidated results for us and our wholly-owned subsidiaries and the consolidated results of ATN and AHD, including APL’s financial results, adjusted for non-controlling minority interests in ATN’s, AHD’s and APL’s net income (loss).

Atlas Energy

ATN was formed in December 2006 through our contribution of substantially all of our natural gas and oil assets and our investment partnership management business to it in connection with ATN’s initial public offering. ATN is an independent developer and producer of natural gas and oil, with operations in northern Michigan’s Antrim Shale and the Appalachian Basin region of the United States, principally in western New York, eastern Ohio, western Pennsylvania and Tennessee. ATN is also a leading sponsor and manager of tax-advantaged direct investment natural gas and oil partnerships in the United States. ATN funds the drilling of natural gas and oil wells on its acreage by sponsoring and managing tax advantaged investment partnerships. It generally structures its investment partnerships so that, upon formation of a partnership, ATN co-invests in and contributes leasehold acreage to it, enters into drilling and well operating agreements with it and becomes its managing general partner. ATN is managed by Atlas Energy Management, Inc., our wholly-owned subsidiary, through which we provide ATN with the personnel necessary to manage its assets and raise capital.

ATN had the following key assets at March 31, 2008:

Gas and oil operations

• proved reserves of almost 900 billion cubic feet equivalents (“Bcfe”) at March 31, 2008 in Appalachia and Michigan, including the reserves net to ATN’s equity interest in its investment partnerships and ATN’s direct interests in producing wells;

• direct and indirect working interests in over 10,000 gross producing gas and oil wells;

• net average daily production of 91.8 million cubic feet equivalents (“MMcfe”) per day for the three months ended March 31, 2008;

• over 1.2 million gross (over 1.1 million net) acres, of which almost 0.6 million gross and net acres are undeveloped.

Partnership management business

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

• managed total proved reserves of over 500 Bcfe.

Atlas Pipeline Holdings and Atlas Pipeline

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

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APL is a leading provider of natural gas gathering services in the Anadarko, Arkoma, Golden Trend and Permian Basins 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 services in Oklahoma and Texas. APL also provides interstate gas transmission services in southeastern Oklahoma, Arkansas and southeastern Missouri. APL’s business is conducted in the midstream segment of the natural gas industry through two reportable segments: its Mid-Continent operations and its Appalachian operations.

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

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

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

• 7,870 miles of active natural gas gathering systems located in Oklahoma, Arkansas and Texas, which transport gas from wells and central delivery points in the Mid-Continent region to APL’s natural gas processing plants or Ozark Gas Transmission.

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

Subsequent Events

On May 6, 2008, ATN issued a $150 million follow-on offering of its 10.75% senior unsecured notes due 2018. The notes priced at 104.75% of par to yield approximately 9.85% to the par call on February 1, 2016. The notes from the follow-on offering announced today and the notes issued on January 23, 2008 shall be treated as a single class of debt securities. ATN intends to use the net proceeds of the offering to repay a portion of its outstanding balance under its revolving credit facility. The increased borrowing capacity will be used to fund additional acreage acquisitions and accelerated development of the Marcellus Shale as well as further development of its other drilling programs and lease acquisition activities.

On May 5, 2008, ATN entered into a purchase agreement with us and sold 600,000 common units representing Class B limited liability company interests in a private transaction exempt from the registration requirements under Section 4(2) of the Securities Act of 1933, as amended. The units were sold at $42.00, the closing price of ATN’s units on the New York Stock Exchange on May 5, 2008, for total proceeds to ATN of $25.2 million.

On April 23, 2008, our Board of Directors approved a 3-for-2 stock split of our common stock effected in the form of a 50% stock dividend. All shareholders of record as of May 21, 2008 will receive one additional share of common stock for every two shares of common stock held on that date. The additional shares of common stock will be distributed on May 30, 2008. Information pertaining to shares and earnings per share have not been restated in the accompanying consolidated financial statements and notes thereto to reflect this split, but will be presented in our interim consolidated financial statements for the period as of and ending June 30, 2008.

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On April 23, 2008, our Board of Directors declared a cash dividend of $0.05 per share, payable on May 20, 2008 to shareholders of record on May 7, 2008.

On April 22, 2008, APL declared a quarterly cash distribution of $0.94 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2008. The $44.3 million distribution, including $7.9 million to AHD for its general partner interest after the allocation of $3.8 million of its incentive distribution rights back to APL, will be paid on May 15, 2008 to unitholders of record at the close of business on May 7, 2008.

On April 22, 2008, AHD declared a quarterly cash distribution of $0.43 per unit, payable on May 20, 2008 to unitholders of record on May 7, 2008.

On April 22, 2008, ATN declared a quarterly cash distribution of $0.59 per unit, payable on May 15, 2008 to unitholders of record on May 7, 2008.

During April 2008, APL entered into interest rate derivative contracts having an aggregate notional principal amount of $250.0 million. Under the terms of this agreement, APL will pay a weighted average interest rate of 3.14%, plus the applicable margin as defined under the terms of its credit facility (see Note 7 under Item 1, “Financial Statements”), and will receive LIBOR plus the applicable margin, on the notional principal amount of $250.0 million. This hedge effectively converts $250.0 million of APL’s floating rate debt under its credit facility to fixed-rate debt. APL’s interest rate swap agreement began on April 30, 2008 and expires on April 30, 2010.

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. At March 31, 2008, based upon the recovery of the sales tax paid in April 2008, APL has reduced goodwill recognized in connection with the acquisition and recorded $30.2 million within accounts receivable on the Company’s consolidated balance sheet.

Recent Developments

Atlas Energy.In January 2008, ATN issued $250.0 million of 10-year, 10.75% senior unsecured notes due 2018, the net proceeds of which were utilized to reduce the balance outstanding on its senior secured 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 certain 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 certain equity offerings at a stated redemption price. The senior notes are also subject to repurchase by it 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 it 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. In connection with a Senior Notes registration rights agreement entered into by ATN, ATN filed an exchange offer registration statement with the Securities and Exchange Commission on March 28, 2008.

In January 2008, ATN entered into interest rate derivative contracts having an aggregate notional principal amount of $150.0 million. Under the terms of this agreement, ATN will pay 3.11%, plus the applicable margin as defined under the terms of its credit facility, and will receive LIBOR plus the applicable

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margin, on the notional principal amount of $150.0 million. This hedge effectively converts $150.0 million of ATN’s floating rate debt under the credit facility to fixed-rate debt. The interest rate swap agreement commences in January 2008 and expires in January 2011.

Atlas Pipeline.In January 2008, APL entered into interest rate derivative contracts having an aggregate notional principal amount of $200.0 million. Under the terms of this agreement, APL will pay a weighted average interest rate of 2.88%, plus the applicable margin as defined under the terms of its credit facility, and will receive LIBOR plus the applicable margin, on the notional principal amount of $200.0 million. This hedge effectively converts $200.0 million of APL’s floating rate debt under the credit facility to fixed-rate debt. The interest rate swap agreement commences in January 2008 and expires in January 2010.

Recent Acquisitions

Atlas Energy.In June 2007, ATN acquired DTE Gas & Oil Company from DTE Energy Company (“DTE” – NYSE: DTE) for $1.3 billion in cash. The assets acquired, which consisted principally of interests in natural gas wells in the Antrim Shale, are the basis for the formation of ATN’s Michigan gas and oil operations. ATN funded the purchase price in part from its private placement of 7.3 million Class B common units and 16.7 million Class D units to investors at a weighted average negotiated price of $25.00, resulting in net proceeds of $597.5 million. ATN funded the remaining purchase price from borrowings under a new credit facility with an initial borrowing base of $850.0 million that matures in June 2012.

Atlas Pipeline.In July 2007, APL acquired control of Anadarko Petroleum Corporation’s (“Anadarko” – NYSE: APC) 100% interest in the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and its 72.8% undivided joint venture interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (the “Anadarko Assets”). The transaction was effected by the formation of two joint venture companies which own the respective systems, to which APL contributed $1.9 billion and Anadarko contributed the Anadarko Assets. In connection with this acquisition, APL reached an agreement with Pioneer Natural Resources Company (“Pioneer” – NYSE: PXD), which currently holds an approximate 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer will have an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system beginning on June 15, 2008 and ending on November 1, 2008, and up to an additional 7.4% interest beginning on June 15, 2009 and ending on November 1, 2009 (the aggregate 22.0% additional interest can be entirely purchased during the period beginning June 15, 2009 and ending on November 1, 2009) (see Note 3 under Item 1, “Financial Statements”). If the option is fully exercised, Pioneer would increase its interest in the system to approximately 49.2%. Pioneer would pay approximately $230 million, subject to certain adjustments, for the additional 22% interest if fully exercised. APL will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercised the purchase options. APL funded the purchase price, in part, from its private placement of $1.125 billion of its common units to investors at a negotiated purchase price of $44.00 per unit. Of the $1.125 billion, AHD purchased $168.8 million of these APL units, which was funded through its issuance of 6.25 million common units in a private placement at a negotiated purchase price of $27.00 per unit (see Note 14 under Item 1, “Financial Statements”) to the consolidated financial statements). AHD, as general partner and holder all of APL’s incentive distribution rights, also agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. AHD also agreed that the resulting allocation of incentive distribution rights back to APL would be after AHD receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter (“IDR Adjustment Agreement”). APL funded the remaining purchase price from an $830.0 million senior secured term loan which matures in July 2014 and a new $300.0 million senior secured revolving credit facility that matures in July 2013 (see Note 7 under Item 1, “Financial Statements”).

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Contractual Revenue Arrangements

Atlas Energy

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

We expect that natural gas produced from ATN’s wells drilled in areas of the Appalachian Basin other than those described above will be primarily tied to the spot market price and supplied to:

• gas marketers;

• local distribution companies;

• industrial or other end-users; and/or

• companies generating electricity.

Michigan Natural Gas. In Michigan, ATN has natural gas sales agreements with DTE, which are valid through December 31, 2012. DTE has the obligation to purchase all of the natural gas produced and delivered by ATN and its affiliates from specific projects at certain delivery points. Based on recent production data available to ATN, we anticipate that ATN and its affiliates will sell approximately 50% of their Michigan natural gas production during the year ending December 31, 2008 under the DTE agreements in most cases at NYMEX pricing.

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

Atlas Pipeline

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

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

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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

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

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

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

Atlas Pipeline.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.

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

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

Results of Operations

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

	Three Months Ended March 31,
	2008			2007
Atlas Energy:
Production revenues (in thousands):
Gas(1)	$	72,874		$	19,427
Oil		3,351			1,826
Production volume(1)(2)(3)(4):
Gas (mcfd)		89,342			23,681
Oil (bpd)		405			359
Total (mcfed)		91,772			25,835
Average sales prices(3)(5):
Gas (per mcf)(6)	$	9.58		$	9.12
Oil (per bbl)	$	91.03		$	56.52
Production costs(7):
As a percent of production revenues		12	%		10	%
Per Mcfe(3)	$	1.11		$	0.87
Depletion per Mcfe(3)	$	2.52		$	2.31

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Atlas Pipeline:
Appalachia system throughput volume (mcfd)(3)	75,632	62,532
Velma system gathered gas volume (mcfd)(3)	62,400	61,017
Elk City/Sweetwater system gathered gas volume (mcfd)(3)	305,377	287,892
Chaney Dell system gathered gas volume (mcfd)(3)	251,487	—
Midkiff/Benedum system gathered gas volume (mcfd)(3)	142,542	—
NOARK Ozark Gas Transmission throughput volume (mcfd)(3)	390,293	286,891
Combined throughput volume (mcfd)(3)	1,227,731	698,332

⁽¹⁾ Excludes sales of residual gas and sales to landowners.

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

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

⁽⁴⁾ Atlas Energy acquired AGO on June 29, 2007, and production volume from these assets have only been included from that date.

⁽⁵⁾ Atlas Energy’s average sales price before the effects of financial hedging was $8.32 and $7.85 for the three months ended March 31, 2008 and 2007, respectively.

⁽⁶⁾ Includes $5.0 million of derivative proceeds which were not included as revenue in the first quarter 2008. No such derivative proceeds were received during the first quarter 2007.

⁽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, 2008 Compared to Three Months Ended March 31, 2007

Natural gas and oil production. Our natural gas and oil production revenues consist of ATN’s production and sale of natural gas and crude oil to unaffiliated third-party customers. Natural gas and oil production expenses include labor to operate wells and related equipment, repairs and maintenance, materials and supplies, property taxes, severance taxes and other related costs. Our natural gas and oil production revenues were $76.2 million for the three months ended March 31, 2008, an increase of $54.9 million from $21.3 million for the prior year comparable period. Total production volume increased to 91.8 mmcfe per day for the three months ended March 31, 2008 compared with 25.8 mmcfe per day for the prior year comparable period. These increases were due principally to production volume associated with ATN’s Michigan assets, which were acquired in June 2007, higher production volumes from ATN’s Appalachian assets, and higher commodity prices. ATN’s Michigan assets accounted for $47.3 million of natural gas and oil production revenue and 59.1 mmcfe per day production volume for the three months ended March 31, 2008. ATN’s Appalachian assets had natural gas and oil production revenue of $28.9 million for the first quarter 2008, representing an increase of $7.6 million, or 36.0%, from the first quarter 2007, and total production volume of 30.7 mmcfe per day, representing an increase of 6.8 mmcfe per day, or 26.3%, from the first quarter 2007. Average realized natural gas and oil prices for the first quarter 2008 were $9.58 per mcf and $91.03 per barrel for the first quarter 2008, representing increases of approximately 5.0% and 61.1%, respectively, from the prior year comparable period.

Natural gas and oil production expenses were $13.1 million for the three months ended March 31, 2008, an increase of $9.0 million from $4.1 million for the prior year comparable period. The increase was attributable to $8.1 million of production expenses for ATN’s Michigan assets and a $1.1 million increase in Appalachia production expenses due to an increase in the number of wells ATN owns.

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Well Construction and Completion. Our well construction and completion revenues and expenses represent fees generated and costs incurred associated with the completion of wells for drilling investments partnerships ATN sponsors. ATN’s drilling contracts are on a “cost plus” basis (typically cost plus 15%) and, as such, an increase in well drilling costs also results in an increase in well drilling revenues. Our well construction and completion revenues were $104.1 million for the three months ended March 31, 2008, an increase of $31.7 million from $72.4 million for the prior year comparable period. The increase is primarily due to the increase in number of Marcellus Shale wells drilled for the three months ended March 31, 2008. ATN drilled 218 net wells for the first quarter 2008 compared with 242 for the prior year first quarter. At March 31, 2008, the balance in “Liabilities associated with drilling contracts” on our consolidated balance sheet includes $31.5 million of funds raised in ATN’s drilling investment programs that have not been applied to the completion of wells as of March 31, 2008 due to the timing of drilling operations, and thus have not been recognized as well construction and completion revenue.

Administration and Oversight and Well Services. Administration and oversight revenues consist of fees ATN receives from the investment drilling partnerships upon drilling of well ($15,000 to $45,000) and on a monthly basis afterwards ($75 per month) for administration services provided for the remaining life of the well. Well services revenues consist of monthly operating fees ATN receives from the investment drilling partnerships for the remaining life of the well. Administration and oversight fee revenues were $5.0 million for the first quarter 2008 compared with $4.5 million for the first quarter 2007. Well services revenues were $4.8 million for the first quarter 2008 compared with $3.7 million for the first quarter 2007. Both increases were due to an increase in wells drilled by ATN since March 31, 2007.

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

Our transmission, gathering and processing revenues were $385.3 million for the three months ended March 31, 2008, an increase of $270.0 million from $115.3 million for the prior year comparable period. Transmission, gathering and processing expenses were $295.5 million for the three months ended March 31, 2008, an increase of $200.0 million from $95.5 million for the prior year comparable period. These increases were due principally to the revenues and expenses associated with APL’s Chaney Dell and Midkiff/Benedum systems, which were acquired in July 2007, and higher commodity prices. APL’s average gross natural gas gathered volume for the three months ended March 31, 2008 was 1.2 billion cubic feet per day (“bcfd”) compared with 0.7 bcfd for the prior year comparable period, an increase of 0.5 bcfd due principally to the acquisition of the Chaney Dell and Midkiff/Benedum systems.

Loss on mark-to-market derivatives was $88.8 million for the three months ended March 31, 2008 compared with a $2.3 million loss for the prior year comparable period. This change in non-cash derivative expense, which consists of the mark-to-market on non-qualifying derivatives and the ineffective portion of qualifying derivatives as determined in accordance with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), was the result of commodity price movements and their unfavorable impact on derivative contracts APL has for production volumes in future periods. For example, at March 31, 2008, forward crude oil prices for the duration of APL’s derivative contracts, which are the basis for adjusting the fair value of its crude oil derivative contracts, were at an average price of $96.94 per barrel compared with $89.89 per barrel at December 31, 2007, an increase of $7.05. APL enters into derivative instruments solely to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under Item 3, “— Quantitative and Qualitative Disclosures About Market Risk”.

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Other Income, Costs and Expenses.General and administrative expenses, including amounts reimbursed to affiliates, increased $6.5 million to $21.3 million for the three months ended March 31, 2008 compared with $14.8 million for the prior year comparable period. This increase was mainly due to higher costs associated with managing our and our subsidiaries’ businesses, including management time related to acquisition and capital raising opportunities, and an increase in ATN’s investment partnership syndication activities.

Depreciation, depletion and amortization increased to $47.6 million for the three months ended March 31, 2008 compared with $12.4 million for the three months ended March 31, 2007 due primarily to the depreciation and depletion associated with ATN’s acquired DGO assets and APL’s acquired Chaney Dell and Midkiff/Benedum system assets and ATN’s and APL’s expansion capital expenditures incurred between the periods.

Interest expense increased to $34.1 million for the three months ended March 31, 2008 as compared with $7.3 million for the comparable prior year period. This $26.8 million increase was primarily due to interest associated with additional borrowings by ATN and APL to partially finance ATN’s acquisition of DGO in June 2007 and APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems during July 2007. These amounts were partially offset by lower variable interest rates between periods.

Minority interest income for the three months ended March 31, 2008, which represents non-controlling, non-affiliated ownership interests in ATN, AHD and APL, was $23.7 million compared with an expense of $3.2 million for the prior year comparable period. The change between periods is principally due to a $48.4 million decrease in APL’s net income and a decrease in our ownership interest in AHD to 64% for the three months ended March 31, 2008 compared with 83% for the prior year comparable period. These amounts were partially offset by a $17.6 million increase in ATN’s net income between periods and a decrease in our ownership interest in ATN to 49.4% for the three months ended March 31, 2008 compared with 80.1% for the prior year comparable period. The decrease in APL’s net income was the result of an $86.5 million increase in non-cash mark-to-market derivative losses. The decrease in our ownership interests in ATN and AHD was due to their private placement of common units to partially finance ATN’s acquisition of DGO in June 2007 and APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007. ATN’s increase in net income between periods was principally due to the inclusion of DGO’s operating results from its date of acquisition.

Our effective income tax rates were 37.4% and 37.0% for the three months ended March 31, 2008 and 2007, respectively. The 0.4% 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 before taxes.

Liquidity and Capital Resources

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

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

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

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

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

During the year ended December 31, 2007, ATN raised $ $363.3 million through its investment partnerships and anticipates raising $400.0 million during the current year. At March 31, 2008, ATN had $579.0 million of outstanding borrowings under its credit facility. The initial borrowing base of $850.0 was reduced to $672.5 million in January 2008 upon the issuance by ATN of $250.0 million in senior unsecured notes and subsequently redetermined on April 30, 2008 to a borrowing base of $735.0 million (see Note 7 under Item 1, “financial Statements”). In addition to the availability under its credit facility, ATN has a universal shelf registration statement on file with the Securities and Exchange Commission, which allows it to issue an unlimited amount of equity or debt securities.

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, 2008, AHD had $25.0 million outstanding and $25.0 million of remaining committed capacity under its credit facility, subject to covenant limitations (see Note 7 under Item 1, “financial Statements”).

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

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

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

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

At March 31, 2008, APL had $165.0 million of outstanding borrowings under its new $300.0 million credit facility and $14.0 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheet, with $121.0 million of remaining committed capacity under its credit facility, subject to covenant limitations (see Note 7 under Item 1, “financial Statements”). In addition to the availability under its credit facility, APL has a universal shelf registration statement on file with the Securities and Exchange Commission, which allows it to issue equity or debt securities of which $352.1 million remains available for issuance at March 31, 2008.

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

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Cash Flows – Three Months Ended March 31, 2008 Compared to Three Months Ended March 31, 2007

Net cash used in operating activities of $31.5 million for the three months ended March 31, 2008 represented a decrease of $17.2 million from $48.7 million for the comparable prior year period. The increase was derived principally from a $79.2 million increase in net income excluding non-cash items, partially offset by a $41.3 million increase in cash distributions to minority interests and a $28.8 million decrease in cash flow from working capital changes. This increase in net income excluding non-cash items was principally due to the contributions from ATN’s acquisition of DTE and APL’s Chaney Dell and Midkiff/Benedum systems, which were acquired in June 2007 and July 2007, respectively. The non-cash charges which impacted net income include a $77.6 million favorable movement in ATN’s and APL’s non-cash derivative gains and losses, a $35.2 million increase in depreciation and amortization, partially offset by a $24.7 million decrease in minority interest in APL’s net income and a $3.8 million decrease in non-cash compensation expense. The movement in ATN’s and APL’s non-cash derivative gains and losses resulted from commodity price movements and their unfavorable impact on the fair value of derivative contracts APL has for future periods. The decrease in non-cash compensation expense was principally attributable to a mark-to-market gain recognized during the first quarter 2008 for certain APL common unit awards for which the ultimate amount to be issued will be determined by APL after the completion of our 2008 fiscal year. The mark-to-market gain was the result of a decrease in APL’s common unit market price at March 31, 2008 when compared with the December 31, 2007 price, which is utilized in the estimate of the non-cash compensation expense for these awards. The increase in depreciation, depletion and amortization resulted from depreciation and amortization associated with ATN’s acquisition of DTE and APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in June 2007 and July 2007, respectively. The decrease in the minority interests was due to a decrease in APL’s net income between periods, partially offset by an increase in ATN’s net income between periods. The increase in cash distributions to minority interests is due mainly to increases in ATN’s, AHD’s and APL’s limited partner units outstanding and their cash distribution amount per common limited partner per unit.

Net cash used in investing activities was $139.1 million for the three months ended March 31, 2008, an increase of $99.4 million from $39.7 million for the comparable prior year period. This increase was principally due to a $101.0 million increase in capital expenditures, partially offset by APL’s receipt of $1.3 million in connection with a post-closing purchase price adjustment of its prior year acquisition of the Chaney Dell and Midkiff/Benedum systems. See further discussion of capital expenditures under “—Capital Requirements”.

Net cash provided by financing activities was $141.4 million for the three months ended March 31, 2008, an increase of $150.1 million from $8.7 million of net cash used in financing activities for the prior year comparable period. This increase was principally due to a $250.0 million senior unsecured notes offering by ATN and an $80.4 million increase as a result of a purchase of treasury stock during the prior year comparable period, partially offset by a $172.4 million net decrease in ATN’s, AHD’s and APL’s borrowings under its respective revolving credit facilities and a $1.3 million cash distributions paid to our shareholders.

Capital Requirements

Our principal assets are our ownership interests in ATN and AHD, through which our operating activities occur. As such, we do not have any separate capital requirements apart from those entities. 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

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

Atlas Pipeline.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,
	2008		2007
Atlas Energy
Maintenance capital expenditures	$	12,975	$	8,750
Expansion capital expenditures		42,642		13,327
Total	$	55,617	$	22,077
Atlas Pipeline
Maintenance capital expenditures	$	1,619	$	772
Expansion capital expenditures		82,450		15,857
Total	$	84,069	$	16,629
Consolidated
Maintenance capital expenditures	$	14,594	$	9,522
Expansion capital expenditures		125,092		29,184
Total	$	139,686	$	38,706

ATN’s expansion capital expenditures increased $29.3 million to $42.6 million for the three months ended March 31, 2008, due principally to higher capital contributions to its investment partnerships to raise funds for additional wells drilled. Investments in the partnerships were $25.7 million for the three months ended March 31, 2008 compared with $17.5 million for the prior year comparable period. ATN maintenance capital expenditures for the three months ended March 31, 2008 increased to $13.0 million compared to $8.8 million for the prior year comparable period due primarily to the maintenance capital expenditures associated with the DGO acquisition, which occurred in June 2007.

APL’s expansion capital expenditures increased to $82.5 million for the three months ended March 31, 2008 compared with $15.9 million for the prior year first quarter due principally to the construction of a 60 MMcfd expansion of APL’s Sweetwater processing plant and the acquisition of a gathering system located in Tennessee with an approximate capacity of 20.0 MMcfd for $9.1 million. The increase in expansion

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capital expenditures also includes expansions of APL’s existing gathering systems and upgrades to processing facilities and compressors to accommodate new wells drilled in APL’s service areas. Maintenance capital expenditures for the three months ended March 31, 2008 increased to $1.6 million compared with $0.8 million for the prior year first quarter due to the maintenance capital requirements of the Chaney Dell and Midkiff/Benedum systems, which were acquired in July 2007, and fluctuations in the timing of APL’s scheduled maintenance activity.

As of March 31, 2008, we are committed to expend approximately $163.8 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include revenue and expense accruals, deferred tax assets and liabilities, depreciation and amortization, asset impairment, fair value of derivative instruments, stock compensation, and the allocation of purchase price to the fair value of assets acquired. A discussion of our significant accounting policies we have adopted and followed in the preparation of our consolidated financial statements is included within our Annual Report on Form 10-K for the year ended December 31, 2007 and in Note 2 under Item 1, “Financial Statements” included in this report, and there have been no material changes to these policies through March 31, 2008.

Fair Value of Financial Instruments

We adopted the provisions of SFAS No. 157 at January 1, 2008. SFAS No. 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS No. 157 (1) creates a single definition of fair value, (2) establishes a hierarchy for measuring fair value, and (3) expands disclosure requirements about items measured at fair value. SFAS No. 157 does not change existing accounting rules governing what can or what must be recognized and reported at fair value in our financial statements, or disclosed at fair value in our notes to the financial statements. As a result, we will not be required to recognize any new assets or liabilities at fair value.

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

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

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

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

We use the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities recorded at fair value, including ATN’s and APL’s commodity hedges and interest rate swaps (see Note 9

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under Item 1, “Financial Statements”) and our SERP (see Note 17 under Item 1, “Financial Statements”). ATN’s and APL’s commodity hedges, with the exception of APL’s NGL fixed price swaps and crude oil collars are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. ATN’s and APL’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model, and are therefore defined as Level 2 fair value measurements. Our SERP is calculated based on observable actuarial inputs developed by a third-party actuary, and therefore is defined as a Level 2 fair value measurement. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of natural gas, crude oil, and propane prices, and therefore are defined as Level 3 fair value measurements. Valuations for APL’s crude oil options (including those associated with NGL sales) are based on forward price curves developed by the related financial institution based upon current quoted prices for crude oil futures, and therefore are defined as Level 3 fair value measurements.

New and Recently Adopted Accounting Standards

In March 2008, the Financial Accounting Standards Board (“FASB”) ratified the Emerging Issues Task Force (“EITF”) consensus on EITF Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF No. 07-4”), an update of EITF No. 03-6, “Participating Securities and the Two-Class Method Under FASB Statement No. 128” (“EITF No. 03-6”). EITF No. 07-4 requires the calculation of a Master Limited Partnership’s net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings as if all of the earnings for that period had been distributed. In periods with undistributed earnings above specified levels, the calculation per the two-class method results in an increased allocation of such undistributed earnings to the general partner and a dilution of earnings to the limited partners. EITF No. 07-4 is effective for fiscal years beginning after December 15, 2008, including interim periods within those fiscal years, and requires retrospective application of the guidance to all periods presented. Early adoption is prohibited. Our subsidiaries, APL, AHD and ATN, do not believe the adoption of EITF No. 07-4 will have any impact on its financial position or results of operations.

In March 2008, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“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 to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, with early adoption encouraged. We are currently evaluating the impact the adoption of SFAS No. 161 will have on the disclosures regarding our derivative instruments.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 amends ARB No. 51 to establish accounting and reporting standards for the noncontrolling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 also requires consolidated net income to be reported, and disclosed on the face of the consolidated statement of income, at amounts that include the amounts attributable to both the parent and the noncontrolling interest. Additionally, SFAS No. 160 establishes a single method for accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. We will apply the requirements of SFAS No. 160 upon its adoption on January 1, 2009 and are currently evaluating whether SFAS No. 160 will have an impact on our financial position and results of operations.

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

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

General

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

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We and our subsidiaries are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We and our subsidiaries manage these risks through regular operating and financing activities and periodical use of derivative financial instruments. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on March 31, 2008. Only the potential impact of hypothetical assumptions is analyzed. The analysis does not consider other possible effects that could impact our and our subsidiaries’ business.

Interest Rate Risk.At March 31, 2008, ATN had an $850.0 million senior secured revolving credit facility ($579.0 million outstanding). The weighted average interest rate for these borrowings was 4.3% at March 31, 2008. ATN also has interest rate derivative contracts at March 31, 2008 having an aggregate notional principal amount of $150.0 million. Under the terms of this agreement, ATN will pay 3.11%, plus the applicable margin as defined under the terms of its credit facility, and will receive LIBOR plus the applicable margin, on the notional principal amount. This derivative contract effectively converts $150.0 million of ATN’s floating rate debt under the credit facility to fixed-rate debt. The interest rate swap agreement expires on January 31, 2011.

At March 31, 2008, APL had a $300.0 million senior secured revolving credit facility ($165.0 million outstanding). APL also had an $830.0 million senior secured term loan outstanding at March 31, 2008. The weighted average interest rate for APL’s revolving credit facility borrowings was 4.9% at March 31, 2008, and the weighted average interest rate for the term loan borrowings was 5.5% at March 31, 2008. APL also has interest rate derivative contracts at March 31, 2008 having an aggregate notional principal amount of $200.0 million. Under the terms of this agreement, APL will pay a weighted average interest rate of 2.88%, plus the applicable margin as defined under the terms of its credit facility, and will receive LIBOR plus the applicable margin, on the notional principal amount. This derivative contract effectively converts $200.0 million of APL’s floating rate debt under the credit facility to fixed-rate debt. The interest rate swap agreement expires on January 31, 2010.

At March 31, 2008, AHD had a $50.0 million revolving credit facility ($25.0 million outstanding). The weighted average interest rate for these borrowings was 5.0% at March 31, 2008.

Holding all other variables constant, including the effect of interest rate derivatives entered into by ATN and APL subsequent to March 31, 2008, 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 prices, ATN uses financial derivative instruments for a portion of its future natural gas production. APL is exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. APL enters into financial swap and option instruments to hedge forecasted sales against the variability in expected future cash flows attributable to changes in market prices. These financial swap and option instruments are generally classified as cash flow hedges in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). A 10% change in the average price of natural gas, NGLs, condensate and oil would result in a change to our consolidated operating income, excluding minority interest and income tax effects, for the twelve-month period ending March 31, 2009 of approximately $9.0 million.

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

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contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas and oil.

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

As of March 31, 2008, ATN had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swap

Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Asset/(Liability)(1)
					(in thousands)
January 2008 - January 2011	$	150,000,000	Pay 3.11%—Receive LIBOR	2008	$	(982	)
				2009		(1,225	)
				2010		23
				2011		57
					$	(2,127	)

Natural Gas Fixed Price Swaps

Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value (Liability)
	(MMbtu) (4)	(per MMbtu) (4)		(in thousands) (2)
2008	29,670,000	$	8.72	$	(44,667	)
2009	37,760,000	$	8.54		(41,732	)
2010	26,360,000	$	8.11		(22,838	)
2011	18,680,000	$	7.90		(15,482	)
2012	13,800,000	$	8.20		(7,813	)
2013	1,500,000	$	8.73		(132	)
				$	(132,664	)

Natural Gas Costless Collars

Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value (Liability)
		(MMbtu) (4)	(per MMbtu) (4)		(in thousands) (2)
2008	Puts purchased	1,170,000	$	7.50	$	—
2008	Calls sold	1,170,000	$	9.40		(1,423	)
2010	Puts purchased	2,880,000	$	7.75		—
2010	Calls sold	2,880,000	$	8.75		(2,055	)
2011	Puts purchased	7,200,000	$	7.50		—
2011	Calls sold	7,200,000	$	8.45		(4,968	)
2012	Puts purchased	720,000	$	7.00		—
2012	Calls sold	720,000	$	8.37		(633	)
					$	(9,079	)

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Crude Oil Fixed Price Swaps

Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset
		(per Bbl)		(in thousands) (3)
2008	33,000	$	103.25	$	125
2009	36,000	$	99.03		117
2010	31,000	$	96.52		76
2011	25,000	$	95.79		52
2012	21,500	$	95.35		36
2013	6,000	$	95.35		9
				$	415

Crude Oil Costless Collars

Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset
			(per Bbl)		(in thousands) (3)
2008	Puts purchased	30,500	$	85.00	$	15
2008	Calls sold	30,500	$	127.13		—
2009	Puts purchased	36,500	$	85.00		50
2009	Calls sold	36,500	$	118.63		—
2010	Puts purchased	31,000	$	85.00		44
2010	Calls sold	31,000	$	112.92		—
2011	Puts purchased	27,000	$	85.00		35
2011	Calls sold	27,000	$	110.81		—
2012	Puts purchased	21,500	$	85.00		25
2012	Calls sold	21,500	$	110.06		—
2013	Puts purchased	6,000	$	85.00		7
2013	Calls sold	6,000	$	110.09		—
					$	176
		Total ATN net liability			$	(143,279	)

⁽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 on forward NYMEX natural gas prices, as applicable.

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

⁽⁴⁾ Mmbtu represents million British Thermal Units.

Atlas Pipeline.APL uses a number of different derivative instruments, principally swaps and options, in connection with its commodity price and interest rate risk management activities. APL enters into financial swap and option instruments to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. APL also enters into financial swap instruments to hedge certain portions of its floating interest rate debt against the variability in

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market interest rates. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate is sold or interest payments on the underlying debt instrument is due. Under 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. Commodity-based 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 contract period. These financial swap and option instruments are generally classified as cash flow hedges in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”).

APL formally documents 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 derivative contracts to the forecasted transactions. APL assesses, 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, APL will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by APL through the utilization of market data, will be recognized immediately gain (loss) on mark-to-market derivatives in our consolidated statements of income. For APL’s derivatives qualifying as hedges, we recognize the effective portion of changes in fair value in stockholders’ equity as accumulated other comprehensive income (loss), and reclassify the portion relating to commodity derivatives to gathering, transmission and processing revenue within our consolidated statements of income and the portion relating to interest rate derivatives to interest expense within our consolidated statements of income operations as the underlying transactions are settled. For APL’s non-qualifying derivatives and for the ineffective portion of qualifying derivatives, we recognize changes in fair value within gain (loss) on mark-to-market derivatives in our consolidated statements of operations as they occur.

As of March 31, 2008, APL had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swap

Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Liability(1)
					(in thousands)
January 2008 - January 2010	$	200,000,000	Pay 2.88%—Receive LIBOR	2008	$	(973	)
				2009		(1,161	)
				2010		(15	)
					$	(2,149	)

Natural Gas Liquids Sales – Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability(2)
	(gallons)	(per gallon)		(in thousands)
2008	23,940,000	$	0.697	$	(13,911	)
2009	8,568,000	$	0.746		(4,574	)
				$	(18,485	)

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Crude Oil Sales Options (associated with NGL volume)

Production Period Ended December 31,	Crude Volume	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset/(Liability)(3)			Option Type
	(barrels)	(gallons)	(per barrel)		(in thousands)
2008	3,517,200	240,141,888	$	60.00	$	359		Puts purchased
2008	3,517,200	240,141,888	$	79.08		(69,908	)	Calls sold
2009	5,184,000	354,533,760	$	60.00		3,999		Puts purchased
2009	5,184,000	354,533,760	$	78.88		(101,264	)	Calls sold
2010	3,127,500	213,088,050	$	61.08		5,325		Puts purchased
2010	3,127,500	213,088,050	$	81.09		(58,437	)	Calls sold
2011	606,000	34,869,240	$	70.59		3,057		Puts purchased
2011	606,000	34,869,240	$	95.56		(7,655	)	Calls sold
2012	450,000	25,893,000	$	70.80		2,636		Puts purchased
2012	450,000	25,893,000	$	97.10		(5,719	)	Calls sold
					$	(227,607	)

Natural Gas Sales – Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability(3)
	(mmbtu)(4)	(per mmbtu) (4)		(in thousands)
2008	4,113,000	$	8.804	$	(6,161	)
2009	5,724,000	$	8.611		(6,491	)
2010	4,560,000	$	8.526		(2,570	)
2011	2,160,000	$	8.270		(1,064	)
2012	1,560,000	$	8.250		(733	)
				$	(17,019	)

Natural Gas Basis Sales

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset(3)
	(mmbtu)(4)	(per mmbtu)(4)			(in thousands)
2008	4,113,000	$	(0.732	)	$	592
2009	5,724,000	$	(0.558	)		1,674
2010	4,560,000	$	(0.622	)		763
2011	2,160,000	$	(0.664	)		196
2012	1,560,000	$	(0.601	)		81
					$	3,306

Natural Gas Purchases – Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset(3)
	(mmbtu)(4)	(per mmbtu)(4)			(in thousands)
2008	12,195,000	$	8.978	(5)	$	16,358
2009	15,564,000	$	8.680			16,570
2010	8,940,000	$	8.580			5,277
2011	2,160,000	$	8.270			1,064
2012	1,560,000	$	8.250			733
					$	40,002

Natural Gas Basis Purchases

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Liability(3)
	(mmbtu)(4)	(per mmbtu)(4)			(in thousands)
2008	12,195,000	$	(1.114	)	$	(2,732	)
2009	15,564,000	$	(0.654	)		(8,222	)
2010	8,940,000	$	(0.600	)		(4,227	)
2011	2,160,000	$	(0.700	)		(221	)
2012	1,560,000	$	(0.610	)		(55	)
					$	(15,457	)

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Crude Oil Sales

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability(3)
	(barrels)	(per barrel)		(in thousands)
2008	45,300	$	59.664	$	(1,821	)
2009	33,000	$	62.700		(1,103	)
				$	(2,924	)

Crude Oil Sales Options

Production Period Ended December 31,	Volumes	Average Strike Price		Fair Value Asset/(Liability)(3)			Option Type
	(barrels)	(per barrel)		(in thousands)
2008	204,900	$	60.000	$	(31	)	Puts purchased
2008	204,900	$	78.128		(9,481	)	Calls sold
2009	306,000	$	60.000		735		Puts purchased
2009	306,000	$	80.017		(11,235	)	Calls sold
2010	234,000	$	61.795		816		Puts purchased
2010	234,000	$	83.027		(6,956	)	Calls sold
2011	30,000	$	60.000		296		Puts purchased
2011	30,000	$	74.500		(1,211	)	Calls sold
2012	30,000	$	60.000		209		Puts purchased
2012	30,000	$	73.900		(908	)	Calls sold
				$	(27,766	)
	Total APL net liability			$	(268,099	)
	Total net liability			$	(411,378	)

⁽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⁾ Mmbtu represents million British Thermal Units.

⁽⁵⁾ Includes APL’s premium received from the its sale of an option for it to sell 936,000 mmbtu of natural gas for the year ended December 31, 2008 at $15.50 per mmbtu.

Atlas America.At March 31, 2008 and December 31, 2007, we reflected a net hedging liability and asset on our balance sheet of $411.4 million and $224.0 million, respectively, as a result of ATN’s and APL’s derivative contracts. Of the $36.9 million net loss in accumulated other comprehensive loss at March 31, 2008, we will reclassify $16.0 million of gains to our consolidated statements of income over the next twelve month period as these contracts expire, and $20.9 million of losses will be reclassified in later periods if the fair values of the instruments remain at current market values. Actual amounts that will be reclassified will vary as a result of future price changes.

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ITEM 4. CONTROLS AND PROCEDURES

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

Under the supervision of our Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective at the reasonable assurance level at March 31, 2008.

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

PART II. OTHER INFORMATION

ITEM 1A. RISK FACTORS

There have been no material changes in our risk factors from those disclosed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2007.

ITEM 6. EXHIBITS

Exhibit No.	Description
3.1	Amended and Restated Certificate of Incorporation (1)
3.2	Amended and Restated Bylaws (1)
4.1	Form of Stock Certificate(2)
31.1	Rule 13a-14(a)/15d-14(a) Certification
31.2	Rule 13a-14(a)/15d-14(a) Certification
32.1	Section 1350 Certification
32.2	Section 1350 Certification

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

⁽²⁾ Previously filed as an exhibit to our registration statement on Form S-1 (registration no. 333-112652)

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SIGNATURES

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

	ATLAS AMERICA, INC.
Date: May 9, 2008	By:	/s/ EDWARD E. COHEN
		Edward E. Cohen
		Chairman of the Board and Chief Executive Officer
Date: May 9, 2008	By:	/s/ MATTHEW A. JONES
		Matthew A. Jones
		Chief Financial Officer
Date: May 9, 2008	By:	/s/ NANCY J. MCGURK
		Nancy J. McGurk
		Senior Vice President and Chief Accounting Officer

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