ARKHAN 10-Q/A 2007 Q1 Quarterly report (amended)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

(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, 2007

OR

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

For the transition period from _________ to __________

Commission file number:  001-32169

ATLAS AMERICA, INC.

(Exact name of registrant as specified in its charter)

Delaware	51-0404430
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
311 Rouser Road
Moon Township, PA	15108
(Address of principal executive offices)	(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 xNo o

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

Large accelerated filer x Accelerated filer   o Non-accelerated filer o

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

Yes o No x

The number of outstanding shares of the registrant’s common stock on May 1, 2007 was 17.9 million shares.

Explanatory Note

The Company is filing this Amendment No.1 to its Quarterly Report on Form 10-Q (“Amendment No.1”) for the quarter ended March 31, 2007. The Quarterly Report on Form 10-Q was originally filed on May 10, 2007 (the “Original Filing”). Amendment No. 1 is being filed to recognize changes to the beginning balance sheet related to an amendment to the Company’s Form 10K/A for the year ended December 31, 2006 for its accounting treatment of stock sales by its subsidiaries. Amendment No. 1 amends Item 1 of the Original Filing to reflect the changes to the beginning and ending balance sheets as a result of the Company’s amendment to its Form 10K/A for the year ended December 31, 2006 and for the convenience of the reader, sets forth the remainder of the Original Filing in its entirety.

Except as described above, no other information in Amendment No. 1 is amended hereby. Amendment No. 1 does not reflect events occurring after the filing of the Original Filing or modify or update those disclosures affected by subsequent events. Accordingly, Amendment No. 1 should be read in conjunction with our other filings made with the SEC subsequent to the filing of the Original Filing. In addition, Item 6 of Part II of Amendment No. 1 has been amended to contain, in accordance with the rules of the SEC, currently-dated certifications from our Chief Executive Officer and Chief Financial Officer. The certifications of our Chief Executive Officer and Chief Financial Officer are attached to Amendment No. 1 as Exhibits 31.1, 31.2, 32.1 and 32.2, respectively.

ATLAS AMERICA, INC.

INDEX TO QUARTERLY REPORT ON FORM 10-Q

		Page
PART I	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Consolidated Balance Sheets - March 31, 2007 and December 31, 2006	4
	Consolidated Statements of Income for the Three Months Ended March 31, 2007 and 2006	5
	Consolidated Statement of Changes in Stockholders’ Equity for the Three Months Ended March 31, 2007	6
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2007 and 2006	7
	Notes to Consolidated Financial Statements	8 - 25
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26 - 34
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	34 - 38
Item 4.	Controls and Procedures	39
PART II	OTHER INFORMATION
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
Item 6.	Exhibits	39
SIGNATURES		40

PART I. FINANCIAL INFORMATION

Item 1.Financial Statements

ATLAS AMERICA, INC.

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)

(Unaudited)

	March 31,			December 31,
	2007			2006
	(Restated)
ASSETS
Current assets:
Cash and cash equivalents	$	88,381		$	185,401
Accounts receivable		71,987			82,954
Current portion of derivative asset		11,103			33,150
Prepaid expenses		9,161			13,738
Deferred tax asset		5,905			7,934
Total current assets		186,537			323,177
Property and equipment, net		913,014			884,812
Intangible assets, net		29,934			30,741
Other assets, net		34,725			42,501
Goodwill		98,607			98,607
	$	1,262,817		$	1,379,838
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	81		$	109
Accounts payable		46,048			56,438
Liabilities associated with drilling contracts		19,681			92,449
Accrued producer liabilities		30,534			32,766
Accrued hedge liability		24,834			17,535
Accrued liabilities		32,331			49,035
Advances from affiliate		447			117
Total current liabilities		153,956			242,765
Long-term debt		395,498			324,042
Deferred tax liability		72,331			82,307
Other liabilities		56,771			52,996
Minority interest		392,704			406,387
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		200			200
Additional paid-in capital		187,291			186,696
Treasury stock, at cost		(109,396	)		(29,349	)
ESOP loan receivable		(472	)		(490	)
Accumulated other comprehensive income (loss)		(2,172	)		8,426
Retained earnings		116,106			105,858
Total stockholders’ equity		191,557			271,341
	$	1,262,817		$	1,379,838

See accompanying notes to consolidated financial statements

4

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per share data)

(Unaudited)

	Three Months Ended
	March 31,
	2007			2006
REVENUES
Well construction and completion	$	72,378		$	50,883
Gas and oil production		21,260			22,866
Transmission, gathering and processing		113,012			112,635
Administration and oversight		4,544			3,309
Well services		3,721			2,766
		214,915			192,459
COSTS AND EXPENSES
Well construction and completion		62,932			44,246
Gas and oil production		2,034			1,905
Transmission, gathering and processing		95,475			91,437
Well services		2,043			1,766
General and administrative		14,457			12,908
Net expense reimbursement - affiliate		308			415
Depreciation, depletion and amortization		12,401			10,102
		189,650			162,779
OPERATING INCOME		25,265			29,680
OTHER INCOME (EXPENSE)
Interest expense		(7,256	)		(6,721	)
Minority interests		(3,186	)		(6,255	)
Other, net		1,444			1,329
		(8,998	)		(11,647	)
Income before income taxes		16,267			18,033
Provision for income taxes		6,019			6,672
Net income	$	10,248		$	11,361
Net income per common share - basic
Net income per common share-basic	$	.54		$	.57
Weighted average common shares outstanding		18,924			20,001
Net income per common share - diluted
Net income per common share - diluted	$	.53		$	.56
Weighted average common shares outstanding		19,478			20,453

See accompanying notes to consolidated financial statements

5

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

THREE MONTHS ENDED MARCH 31, 2007

(in thousands, except share data)

(Unaudited)

																Accumulated
					Additional								ESOP			other					Total
	Common stock				paid-in		Treasury stock						loan			comprehensive			Retained		stockholders’
	Shares		Amount		capital		Shares			Amount			receivable			income (loss)			earnings		equity
Balance, January 1, 2007, Restated		20,008,419	$	200	$	186,696		(659,135	)	$	(29,349	)	$	(490	)	$	8,426		$	105,858	$	271,341
Net income																				10,248		10,248
Other comprehensive income (loss)																	(10,598	)				(10,598	)
Issuance of common stock		3,750		-		227		6,607			304											531
Repurchase of common stock, at cost								(1,486,605	)		(80,351	)										(80,351	)
Repayment of ESOP loan														18								18
Stock option compensation						368																368
Balance, March 31, 2007, Restated		20,012,169	$	200	$	187,291		(2,139,133	)	$	(109,396	)	$	(472	)	$	(2,172	)	$	116,106	$	191,557

See accompanying notes to consolidated financial statements

6

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Three Months Ended
	March 31,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	10,248		$	11,361
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation, depletion and amortization		12,401			10,102
Amortization of deferred finance costs		571			738
Non-cash loss on derivative value		2,277			512
Non-cash compensation on long-term incentive plans		4,036			2,747
Minority interests		3,186			6,255
Distributions paid to minority interests		(11,174	)		(9,054	)
Gain on asset dispositions		(26	)		(26	)
Deferred income taxes		(1,221	)		1,001
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable and prepaid expenses		15,543			(5,881	)
Decrease in accounts payable and accrued liabilities		(83,098	)		(66,795	)
Increase in accounts payable/receivable from affiliates		330			859
Net cash used in operating activities		(46,927	)		(48,181	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in Lightfoot Capital Partners, L.P.		(931	)		-
Capital expenditures		(40,454	)		(30,233	)
Proceeds from sale of assets		35			30
Decrease (increase) in other assets		(73	)		84
Net cash used in investing activities		(41,423	)		(30,119	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings		117,000			65,250
Principal payments on debt		(45,572	)		(28,771	)
Issuance of Atlas Pipeline Partners, L.P. common and preferred units		-			29,994
Treasury shares purchased		(80,351	)		(475	)
Other		253			(55	)
Net cash provided by (used in) financing activities		(8,670	)		65,943
Decrease in cash and cash equivalents		(97,020	)		(12,357	)
Cash and cash equivalents at beginning of period		185,401			55,155
Cash and cash equivalents at end of period	$	88,381		$	42,798

See accompanying notes to consolidated financial statements

7

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2007

(Unaudited)

NOTE 1 — BASIS OF PRESENTATION

Company Overview and Principles of Consolidation

The consolidated financial statements include the accounts of Atlas America, Inc. (the “Company” or “ATLS”) and its subsidiaries, all of which are wholly owned except for Atlas Pipeline Holdings, L.P. (“AHD”), Atlas Pipeline Partners, L.P. (“Atlas Pipeline”) and Atlas Energy Resources, LLC (“Atlas Energy”). 

 In July 2006, the Company contributed its ownership interests in Atlas Pipeline Partners GP, LLC, its then wholly-owned subsidiary, and the general partner of Atlas Pipeline, to AHD. Concurrent with this transaction, AHD issued 3,600,000 common units, representing a 17.1% ownership interest in it, in an initial public offering. AHD, through its ownership of Atlas Pipeline GP, owns a 2% general partner interest and 1,641,026 common units constituting an 11.4% limited partner interest for a total partnership interest of 13.4% in Atlas Pipeline. Because AHD controls the decisions and operations of Atlas Pipeline, Atlas Pipeline is consolidated in the Company’s financial statements.

In December 2006, the Company contributed substantially all of its natural gas and oil assets and its investment partnership management business to Atlas Energy, a then wholly-owned subsidiary. Concurrent with this transaction, Atlas Energy issued 7,273,750 common units, representing a 19.4% ownership interest, in an initial public offering. After completion of the offering, the Company owns approximately 80.6% of Atlas Energy.

The consolidated financial statements and the information and tables contained in the notes to the consolidated financial statements as of March 31, 2007 and for the three months ended March 31, 2007 and 2006 are unaudited except that the balance sheet at December 31, 2006 is derived from audited financial statements.  Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted in these statements pursuant to the rules and regulations of the Securities and Exchange Commission.  However, in the opinion of management, these interim financial statements include all the necessary adjustments to fairly present the results of the interim periods presented.  The results of operations for the three months ended March 31, 2007 may not necessarily be indicative of the results of operations for the full fiscal year ending December 31, 2007. Certain reclassifications have been made to the consolidated financial statements as of December 31, 2006 and for the three months ended March 31, 2006 to conform to the presentation as of and for the three months ended March 31, 2007.

Restatement

The Company has restated its beginning balance sheet related to an amendment to its Form 10-K for the year ended December 31, 2006 for its accounting treatment of stock sales by its subsidiaries. This restatement decreased Minority Interest by $188.3 million, increased Deferred Taxes by $79.1 million and increased Paid-in Capital by $109.2 million at December 31, 2006 and March 31, 2007. The restatement resulted in the reversal of the income tax provision recorded in July 2006, and as a result, Retained Earnings has been increased by $29.8 million.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Reference is hereby made to the Company's Annual Report on Form 10-K/A for the fiscal year ended December 31, 2006, which contains a summary of significant accounting policies followed by the Company in the preparation of its consolidated financial statements.  These policies were also followed in preparing the consolidated financial statements as of March 31, 2007 and for the three months ended March 31, 2007 and 2006.

Use of Estimates

Preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and costs and expenses during the reporting period. Actual results could differ from these estimates.

8

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Receivables

In evaluating its allowance for possible losses, the Company performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness, as determined by the Company’s review of its customers’ credit information. The Company extends credit on an unsecured basis to many of its customers. At March 31, 2007 and December 31, 2006, the Company’s credit evaluation indicated that it has no need for an allowance for possible losses.

Revenue Recognition

Because there are timing differences between the delivery of natural gas, natural gas liquids ("NGLs") and oil and the Company’s receipt of a delivery statement, the Company has unbilled revenues. These revenues are accrued based upon volumetric data from the Company’s records and the Company’s estimates of the related transportation and compression fees which are, in turn, based upon applicable product prices. The Company had unbilled trade receivables at March 31, 2007 and December 31, 2006 of $29.9 million and $40.2 million which are included in accounts receivable on its Consolidated Balance Sheets.

Recently Issued Financial Accounting Standards

In February 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, (“SFAS 159”). SFAS 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. The Statement will be effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. The Statement offers various options in electing to apply the provisions of this Statement, and at this time the Company has not made any decisions on its application to its financial position or results of operations.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurement, (“SFAS 157”). SFAS 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements. SFAS 157 is effective for the Company beginning January 1, 2008. The Company is currently evaluating the impact of the adoption of SFAS 157 on its financial position and results of operations.

The Company adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, (“FIN 48”), on January 1, 2007. Previously, the Company had accounted for tax contingencies in accordance with Statement of Financial Accounting Standards No.5, Accounting for Contingencies. FIN 48 clarifies the accounting for income taxes, by prescribing a minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. As a result of the implementation of FIN 48, the Company determined that it had no liability for unrecognized income tax benefits, upon adoption and through March 31, 2007.

The Company files numerous consolidated and separate income tax returns in the United States Federal jurisdiction and in many state jurisdictions. The Company is no longer subject to United States Federal income tax examinations for periods ending before September 30, 2003 and is no longer subject to state and local income tax examinations by tax authorities for periods ending before September 30, 2002.

The Company’s policy is to recognize potential accrued interest and penalties related to unrecognized tax benefits in income tax expense.

The Company does not anticipate that total unrecognized tax benefits will significantly change within the next twelve months.

9

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Earnings Per Share

Basic earnings per share are determined by dividing net income by the weighted average number of shares of common stock outstanding during the period.  Earnings per share - diluted is computed by dividing net income by the sum of the weighted average number of shares of common stock outstanding and dilutive potential shares issuable during the period.  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 price of shares during the period) with the proceeds received from the exercise of the options. The following table sets forth the reconciliation of the Company’s weighted average number of common shares at the dates indicated (in thousands):

	Three Months Ended
	March 31,
	2007		2006
Weighted average common shares outstanding-basic		18,924		20,001
Dilutive effect of stock option and award plan		554		452
Weighted average common shares-diluted		19,478		20,453

NOTE 3 — COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) includes net income and other gains and losses affecting stockholders’ equity from non-owner sources that, under accounting principles generally accepted in the United States of America, have not been recognized in the calculation of net income. For the Company, this includes changes in the fair values, net of taxes, of unrealized hedging gains and losses and post-retirement plan liabilities. The following table reconciles net income to comprehensive income (loss) (in thousands):

	Three Months Ended
	March 31,
	2007			2006
Net income	$	10,248		$	11,361
Other comprehensive income (loss):
Unrealized holding gain (loss) on hedging contracts, net of tax of $7,155 and ($1,476)		(11,320	)		2,515
Less: reclassification adjustment for (gains) losses realized in net income, net of tax of ($400) and $155		680			(266	)
Plus: amortization of additional post-retirement liability recorded upon adoption of SFAS 158, net of taxes of ($27)		42			-
		(10,598	)		2,249
Comprehensive income (loss)	$	(350	)	$	13,610

Components of Accumulated other comprehensive income (loss) at the dates indicated are as follows (in thousands):

	March 31, 2007			December 31, 2006
Unrealized holding gain (loss) on hedging contracts	$	(1,798	)	$	8,842
Additional post-retirement liability		(374	)		(416	)
	$	(2,172	)	$	8,426

10

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 4 — PROPERTY AND EQUIPMENT

Property 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 lives. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.

Property and equipment consists of the following at the dates indicated (in thousands):

	March 31,			December 31,
	2007			2006
Mineral interests:
Proved properties	$	4,765		$	1,290
Unproved properties		1,002			1,002
Wells and related equipment		365,526			348,592
Pipelines, processing and compression facilities		628,664			611,212
Rights-of-way		30,984			30,401
Land, building and improvements		8,598			8,451
Support equipment		6,044			5,604
Other		10,288			9,902
		1,055,871			1,016,454
Accumulated depreciation, depletion and amortization:
Oil and gas properties and pipelines		(136,381	)		(125,550	)
Other		(6,476	)		(6,092	)
		(142,857	)		(131,642	)
	$	913,014		$	884,812

NOTE 5 — OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL

Other Assets

The following table provides information about Other assets at the dates indicated (in thousands):

	March 31,		December 31,
	2007		2006
Deferred finance costs, net of accumulated amortization of $7,433 and $6,862	$	12,617	$	13,040
Investments		2,641		1,553
Security deposits		1,485		1,538
Long-term hedge receivable from Partnerships		6,476		2,131
Unrealized hedge gain-long term		11,445		24,148
Other		61		91
	$	34,725	$	42,501

Deferred finance costs are recorded at cost and are amortized over the terms of the related loan agreements which range from three to ten years. Investments include Atlas America’s investment in Lightfoot Capital Partners, L.P. (“Lightfoot”). Long-term hedge receivable from Partnerships represents the portion of the long-term unrealized loss on contracts that has been allocated to affiliated oil and gas partnerships.

11

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 5 — OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL - (Continued)

Intangible Assets

Customer contracts and relationships. At March 31, 2007, Atlas Pipeline had $24.9 million of intangible assets, net of accumulated amortization of $4.7 million which was recorded in connection with natural gas gathering contracts and customer relations assumed in its acquisitions of Elk City and NOARK. Statement of Financial Accounting Standard No. 142, Goodwill and Other Intangible Assets (“SFAS 142”), requires that intangible assets such as these gas gathering contracts and customer relations with finite useful lives be amortized over their respective 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 shall be amortized over the best estimate of its useful life. At a minimum, Atlas Pipeline will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. Amortization expense on the customer contract and relationship intangible assets, which have estimated lives of eight and twenty years, respectively, and are being amortized on a straight-line basis, was $603,000 and $1.2 million for the three months ended March 31, 2007 and 2006, respectively.

Partnership management and operating contracts. Included in intangible assets are partnership management and operating contracts acquired by Atlas Energy through acquisitions which are recorded at fair value on their acquisition dates.  Atlas Energy amortizes contracts acquired on the declining balance and straight-line methods, over their respective estimated lives, ranging from five to thirteen years.  Amortization expense for these contracts for the three months ended March 31, 2007 and 2006 was $204,000 and $220,000, respectively.

Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending March 31 is as follows: 2008 - $3.2 million; 2009 - $3.2 million; 2010 - $3.1million; 2011 - $3.1 million and 2012 - $2.9 million.

The following table provides information about the Company’s intangible assets at the dates indicated (in thousands):

	March 31,					December 31,
	2007					2006
			Accumulated					Accumulated
	Cost		Amortization			Cost		Amortization
Customer contracts and relationships	$	29,650	$	(4,723	)	$	29,650	$	(4,120	)
Partnership management and operating contracts		14,343		(9,336	)		14,343		(9,132	)
Intangible assets, net	$	43,993	$	(14,059	)	$	43,993	$	(13,252	)

Goodwill

The Company applies the provisions of Statement of Financial Accounting Standards, ("SFAS") No. 142 which requires that goodwill no longer be amortized, but instead evaluated for impairment at least annually. The evaluation of impairment under SFAS 142 requires the use of projections, estimates and assumptions as to the future performance of the Company’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 the Company’s assumptions and, if required, recognition of an impairment loss. The Company’s evaluation of goodwill at December 31, 2006 (the most recent valuation date) indicated there was no impairment loss and no impairment indicators have arisen since that date. The Company will continue to evaluate its goodwill at least annually or when impairment indicators arise, and will reflect the impairment of goodwill, if any, within the Consolidated Statements of Income in the period in which the impairment is indicated. At March 31, 2007 and December 31, 2006 the Company had goodwill of $98.6 million, net of accumulated amortization of $4.5 million.

12

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 6 — ASSET RETIREMENT OBLIGATIONS

The Company accounts for its estimated plugging and abandonment of its oil and gas properties in accordance with SFAS 143, Accounting for Asset Retirement Obligations and FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations. A reconciliation of the Company’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):

	Three Months Ended
	March 31,
	2007			2006
Asset retirement obligations, beginning of period	$	26,726		$	18,499
Liabilities incurred		520			676
Liabilities settled		(21	)		-
Accretion expense		365			124
Asset retirement obligations, end of period	$	27,590		$	19,299

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 liabilities” in the Company’s Consolidated Balance Sheets.

NOTE 7 — DEBT

Total debt consists of the following at the dates indicated (in thousands):

	March 31,		December 31,
	2007		2006
Senior notes - Atlas Pipeline	$	285,950	$	285,977
Revolving credit facility - Atlas Pipeline		53,000		38,000
Revolving credit facility - Atlas Energy		56,500		-
Other debt		129		174
		395,579		324,151
Less current maturities		81		109
	$	395,498	$	324,042

Atlas Pipeline Credit Facility. Atlas Pipeline has a $225.0 million credit facility with a syndicate of banks which matures in June 2011. The credit facility bears interest, at Atlas Pipeline’s option, at either (i) adjusted London Interbank Offered Rate (“LIBOR”) plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank, National Association’s (“Wachovia”) prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding credit facility borrowings at March 31, 2007 was 7.4%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $7.1 million was outstanding at March 31, 2007. These outstanding letter of credit amounts were not reflected as borrowings on the Company’s consolidated balance sheets. Borrowings under the credit facility are secured by a lien on and security interest in all of Atlas Pipeline’s property and that of its subsidiaries, and by the guaranty of each of its subsidiaries. The credit facility contains customary covenants, including restrictions on Atlas Pipeline’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; and enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. Atlas Pipeline is in compliance with these covenants as of March 31, 2007.

13

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 7 — DEBT - (Continued)

The events which constitute an event of default are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreements, adverse judgments against Atlas Pipeline in excess of a specified amount and a change of control of the general partner.

Atlas Pipeline Senior Notes. In December 2005, Atlas Pipeline, issued $250.0 million of 10-year, 8.125% senior unsecured notes (“Senior Notes”) in a private placement transaction pursuant to Rule 144A and Regulation S under the Securities Act of 1933 for net proceeds of $243.1 million, after underwriting commissions and other transaction costs. In May 2006, Atlas Pipeline issued an additional $35.0 million of senior unsecured notes at 103% par value, with a resulting effective yield of approximately 7.6%, for net proceeds of $36.6 million including accrued interest and net of initial purchaser’s discount and other transaction costs. Interest on the Senior Notes is payable semi-annually in arrears on June 15 and December 15. The Senior Notes are redeemable at any time on or after December 15, 2010 at certain redemption prices, together with accrued unpaid interest to the date of redemption. In addition, prior to December 15, 2008, Atlas Pipeline 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 Atlas Pipeline 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 for which the net proceeds are not reinvested into Atlas Pipeline within 360 days. The Senior Notes are junior in right of payment to Atlas Pipeline’s secured debt, including Atlas Pipeline’s obligations under its credit facility. At March 31, 2007, all of Atlas Pipeline’s outstanding Senior Notes have been registered with the Securities and Exchange Commission.

The indenture governing the Senior Notes contains covenants, including limitations of Atlas Pipeline’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. Atlas Pipeline is in compliance with these covenants as of March 31, 2007.

Atlas Pipeline Holdings Credit Facility. On July 26, 2006, AHD, as borrower, and Atlas Pipeline GP, as guarantor, entered into a $50.0 million revolving credit facility (no outstanding borrowings at March 31, 2007) with Wachovia as administrative agent and issuing bank, and a syndicate of banks. AHD’s credit facility matures in April 2010 and bears interest, at its option, at either (i) adjusted LIBOR (as defined in the credit facility) or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia prime rate, except that no more than five LIBOR loans may be outstanding at any time. Borrowings under the credit facility are secured by a first-priority lien on a security interest in all of the AHD’s assets, including a pledge of Atlas Pipeline GP’s interests in Atlas Pipeline, and are guaranteed by Atlas Pipeline GP and AHD’s other subsidiaries (excluding Atlas Pipeline and its subsidiaries). The 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, 2007. AHD may borrow under its credit facility (i) for general business purposes, including for working capital, to purchase debt or limited partnership units of Atlas Pipeline, to fund general partner contributions from AHD to Atlas Pipeline and to make permitted acquisitions, (ii) to pay fees and expenses related to its credit facility and (iii) for letters of credit.

Atlas Energy Resources Credit Facility. In December 2006, Atlas Energy entered into a new $250.0 million credit facility, which is led by Wachovia. The revolving credit facility has a current borrowing base of $175.0 million which may be redetermined subject to changes in Atlas Energy’s oil and gas reserves. Up to $50.0 million of the facility may be in the form of standby letters of credit. The facility is secured by Atlas Energy’s assets and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at Atlas Energy’s option. At March 31, 2007, the weighted average interest rate on outstanding borrowings was 8.5%.

The base rate for any day equals the higher of the federal funds rate plus 0.50% or the Wachovia 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 Euro currency funding. The applicable margin ranges from 0.0% to 0.75% for base rate loans and 1.00% to 1.75% for LIBOR loans.

14

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 7 — DEBT - (Continued)

The Wachovia credit facility requires Atlas Energy to maintain specified ratios of current assets to current liabilities, interest coverage (as defined), and debt to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”). In addition, the facility limits sales, leases or transfers of assets and the incurrence of additional indebtedness. The facility limits the dividends payable by Atlas Energy if an event of default has occurred and is continuing or would occur as a result of such distribution. Atlas Energy is in compliance with these covenants as of March 31, 2007. The facility terminates in December 2011, when all outstanding borrowings must be repaid. At March 31, 2007 and December 31, 2006, $56.5 million and $0, respectively, were outstanding under this facility. In addition, letters of credit of $495,000 were outstanding at each date which are not reflected as borrowings on the Company’s Consolidated Balance Sheets.

Annual debt principal payments over the next five years ending March 31 are as follows (in thousands):

2008		81
2009		48
2010		—
2011		—
2012 and thereafter		395,450
	$	395,579

NOTE 8 — DERIVATIVE INSTRUMENTS

Atlas Energy Resources. From time to time, Atlas Energy enters into natural gas futures, option, and collar contracts to hedge its exposure to changes in natural gas prices which are classified as cash flow hedges in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activity. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas.

Atlas Energy formally documents all relationships between hedging instruments and the items being hedged, including the risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. Atlas Energy assesses, both at the inception of the hedge 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 the New York Mercantile Exchange ("NYMEX"). Such gains and losses are charged or credited to Accumulated Other Comprehensive Income (Loss) and recognized as a component of sales revenue in the month the hedged gas 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 gas reference prices under a hedging instrument and actual gas prices, Atlas Energy will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings. A portion of Atlas Energy’s future natural gas sales is periodically hedged through the use of swaps and collar contracts. Realized gains and losses on the derivative instruments that are classified as effective hedges are reflected in the contract month being hedged as an adjustment to revenue.

At March 31, 2007 and December 31, 2006, Atlas Energy had net hedging assets of $687,000 and $47.4 million, respectively. At March 31, 2007, Atlas Energy had 293 open natural gas futures contracts related to natural gas sales covering 60.8 million MMBtu, or Million British Thermal Units ("MMBtu"), of natural gas, maturing through March 31, 2012 at a combined average settlement price of $8.31 per MMBtu. Atlas Energy recognized a gain of $2.4 million and $1.4 million on settled contracts covering natural gas production for the three months ended March 31, 2007 and 2006, respectively. There were no gains or losses recognized during the three months ended March 31, 2007 or 2006 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges. Of the $687,000 net unrealized hedge gain at March 31, 2007, Atlas Energy’s portion is $292,000 and $395,000 has been reallocated to the investment partnerships.

15

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 8 — DERIVATIVE INSTRUMENTS - (Continued)

Atlas Pipeline. Atlas Pipeline also enters into certain financial swaps and option instruments, which qualify as cash flow hedges in accordance with SFAS No. 133, to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate is sold. Under these swap agreements, Atlas Pipeline receives a fixed price and remits a floating price based on certain indices for the relevant contract period.

Atlas Pipeline 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 natural gas futures and options contracts to the forecasted transactions. Atlas Pipeline assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives are effective in offsetting changes in the forecasted cash flow of hedged items. 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 correlation between the hedging instrument and the underlying commodity, Atlas Pipeline will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined through the utilization of market data, will be recognized immediately within its consolidated statements of income. A portion of Atlas Pipeline’s future natural gas sales is periodically hedged through the use of swaps and collar contracts. Realized gains and losses on the derivative instruments that are classified as effective hedges are reflected in the contract month being hedged as an adjustment to revenue.

At March 31, 2007 and December 31, 2006, Atlas Pipeline had a net hedging liability of $28.0 million and $20.1 million, respectively. Ineffective hedge gains or losses recorded by Atlas Pipeline are included in the Company’s Consolidated Statements of Income while the hedge contracts are open and may increase or decrease until settlement of the contract. Atlas Pipeline recognized losses of $3.0 million and $2.4 million, for the three months ended March 31, 2007 and 2006, respectively, related to the settlement of qualifying hedge instruments. Atlas Pipeline also recognized losses of $1.3 million and a gain of $1.0 million for the three months ended March 31, 2007 and 2006, respectively, related to the change in market value of non-qualifying or ineffective hedges. Such gains and losses are included within transmission, gathering and processing in the Company’s Consolidated Statements of Income.

Derivatives are recorded on the Company’s Consolidated Balance Sheets as assets or liabilities at fair value. At March 31, 2007 and December 31, 2006, the Company reflected a net hedging liability and asset on its balance sheets of $27.3 million, respectively, when combining the above hedges of Atlas Energy and Atlas Pipeline. Of the $1.8 million net loss in accumulated other comprehensive income at March 31, 2007, the Company will reclassify $1.2 million of losses to its Consolidated Statements of Income over the next twelve month period as these contracts expire, and $600,000 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.

16

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 8 — DERIVATIVE INSTRUMENTS - (Continued)

As of March 31, 2007, the Company had the following financial hedges in place:

ATLAS ENERGY RESOURCES HEDGES

Natural Gas Fixed Price Swaps

Twelve Month Period Ending March 31	Volumes		Average Fixed Price		Fair Value Asset/(Liability)(3)
	(MMBtu) (1)		(per MMBtu)		(in thousands)
2008		16,380,000	$	8.676	$	1,342
2009		16,080,000		8.599		611
2010		14,040,000		8.195		1,133
2011		7,950,000		7.572		(1,440	)
2012		3,600,000		7.365		(46	)
					$	1,600

Natural Gas Costless Collars

Twelve Month
Period Ending					Average		Fair Value
March 31	Option Type		Volumes		Floor and Cap		Asset/(Liability) (3)
			(MMBtu) (1)		(per MMBtu)		(in thousands)
2008		Puts purchased		1,200,000	$	7.500	$	—
2008		Calls sold		1,200,000		8.600		(364	)
2008		Puts purchased		390,000		7.500		—
2008		Calls sold		390,000		9.400		(465	)
2009		Puts purchased		1,170,000		7.500		—
2009		Calls sold		1,170,000		9.400		(84	)
							$	(913	)
Total Atlas Energy Resources net asset							$	687

ATLAS PIPELINE HEDGES

Natural Gas Fixed - Price Swaps (Liquids Sales)

Production
Period Ended			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset/(Liability) (2)
	(gallons)		(per gallon)		(in thousands)
2007		71,631,000	$	0.901	$	(9,221	)
2008		33,012,000		0.697		(9,076	)
2009		8,568,000		0.746		(2,113	)
					$	(20,410	)

Natural Gas Fixed - Price Swaps (Sales)

Production
Period Ended			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset/(Liability) (3)
	(MMBtu) (1)		(per MMBtu)		(in thousands)
2007		810,000	$	7.255	$	(798	)
2008		240,000		7.270		(395	)
2009		480,000		8.000		(162	)
					$	(1,355	)

17

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

 

Natural Gas Basis Swaps (Sales)

Production
Period Ended			Average			Fair Value
December 31,	Volumes		Fixed Price			Asset (3)
	(MMBtu) (1)		(per MMBtu)			(in thousands)
2007		810,000	$	(0.535	)	$	362
2008		240,000		(0.555	)		150
2009		480,000		(0.540	)		50
						$	562

Natural Gas Fixed Price (Purchase)

Production
Period Ended			Average			Fair Value
December 31,	Volumes		Fixed Price			Liability (3)
	(MMBtu) (1)		(per MMBtu)			(in thousands)
2007		5,220,000	$	8.854	(4)	$	(4,926	)
2008		4,056,000		8.719	(5)		(733	)
2009		2,088,000		8.343			(19	)
						$	(5,678	)

Natural Gas Basis (Purchase)

Production
Period Ended			Average			Fair Value
December 31,	Volumes		Fixed Price			Liability (3)
	(MMBtu) (1)		(per MMBtu)			(in thousands)
2007		5,220,000	$	(0.907	)	$	(322	)
2008		4,056,000		(1.028	)		(211	)
2009		2,880,000		(0.592	)		(150	)
						$	(683	)

Crude Oil Fixed - Price Swaps (Sales)

Production
Period Ended			Average		Fair Value
December 31,	Volumes		Fixed Price		Liability (3)
	(barrels)		(per barrel)		(in thousands)
2007		57,800	$	56.192	$	(717	)
2008		65,400		59.424		(689	)
2009		33,000		62.700		(207	)
					$	(1,613	)

Crude Oil Options (Sales)

Production
Period Ended					Average		Fair Value
December 31,	Option Type		Volumes		Strike Price		Asset/(Liability) (3)
			(MMBtu) (1)		(per MMBtu)		(in thousands)
2007		Puts purchased		9,900	$	60.000	$	13
2007		Calls sold		9,900		73.380		(27	)
2008		Puts purchased		43,800		60.000		(25	)
2008		Calls sold		43,800		79.544		(166	)
2009		Puts purchased		30,000		60.000		122
2009		Calls sold		30,000		71.250		(196	)
							$	(279	)

18

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 8 — DERIVATIVE INSTRUMENTS - (Continued)

Crude Oil Sales Options (associated with NGL volumes)

Production									Fair Value
Period Ended			Crude		Associated		Average crude		Asset/
December 31,	Option Type		Volumes		NGL Volumes		Strike Price		(Liability) (3)
			(barrels)		(gallons)		(per barrel)		(in thousands)
2008		Puts purchased		693,600		38,744,000	$	60.000		2,526
2008		Calls sold		693,600		38,744,000		84.000		(2,570	)
2009		Puts purchased		720,000		40,219,000		60.000		3,314
2009		Calls sold		720,000		40,219,000		81.000		(1,838	)
									$	1,432
		Total Atlas Pipeline net liability							$	(28,024	)
		Total Atlas America net liability							$	(27,337	)

(1)	MMBtu represents million British Thermal Units.
(2)	Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas and light crude prices.
(3)	Fair value based on forward NYMEX natural gas and light crude prices, as applicable.
(4)	Includes Atlas Pipeline’s premium received from its sale of an option for it to sell 3,600,000 mmbtu of natural gas at an average price of $14.33 per MMBtu for the year ended December 31, 2007.
(5)	Includes Atlas Pipeline’s premium received from 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.
	The following table sets forth the book and estimated fair values of derivative instruments at the dates indicated (in thousands):

	March 31, 2007						December 31, 2006
	Book Value			Fair Value			Book Value			Fair Value
Assets
Derivative instruments	$	18,684		$	18,684		$	57,203		$	57,203
	$	18,684		$	18,684		$	57,203		$	57,203
Liabilities
Derivative instruments	$	(46,021	)	$	(46,021	)	$	(29,874	)	$	(29,874	)
	$	(46,021	)	$	(46,021	)	$	(29,874	)	$	(29,874	)
	$	(27,337	)	$	(27,337	)	$	27,329		$	27,329

19

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 9 — OPERATING SEGMENT INFORMATION

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

	Three Months Ended March 31,
	2007			2006
Gas and oil production
Revenues	$	21,260		$	22,866
Costs and expenses		(2,034	)		(1,905	)
Segment profit	$	19,226		$	20,961
Well construction and completion
Revenues	$	72,378		$	50,883
Costs and expenses		(62,932	)		(44,246	)
Segment profit	$	9,446		$	6,637
Atlas Pipeline
Revenues	$	109,724		$	110,348
Revenues - affiliates		7,733			7,894
Costs and expenses		(95,451	)		(91,342	)
Segment profit	$	22,006		$	26,900
Reconciliation of segment profit to net income before taxes
Segment profit
Gas and oil production	$	19,226		$	20,961
Well construction and completion		9,446			6,637
Atlas Pipeline		22,006			26,900
Total segment profit		50,678			54,498
General and administrative expenses		(14,457	)		(12,908	)
Compensation reimbursement - affiliate		(308	)		(415	)
Depreciation, depletion and amortization		(12,401	)		(10,102	)
Other income (expense) - net (a)		(7,245	)		(13,040	)
Net income before taxes	$	16,267		$	18,033
Capital expenditures
Gas and oil production	$	21,494		$	14,881
Well construction and completion		-			-
Atlas Pipeline		18,377			14,943
Corporate and other		583			409
	$	40,454		$	30,233
		March 31, 2007			December 31, 2006
Balance sheet
Goodwill
Gas and oil production	$	21,527		$	21,527
Well construction and completion		6,389			6,389
Atlas Pipeline		63,441			63,441
Corporate and other		7,250			7,250
	$	98,607		$	98,607
Total assets
Gas and oil production	$	358,959		$	377,807
Well construction and completion		8,558			8,335
Atlas Pipeline		784,740			787,128
Corporate and other		110,560			206,568
	$	1,262,817		$	1,379,838

(a) Includes revenue and expense from well services, transportation and administration and oversight of $1,753 and ($1,393) that do not meet the quantitative threshold for reporting segment information for the three months ended March 31, 2007 and 2006, respectively.

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

20

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 10 — COMMITMENTS AND CONTINGENCIES

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

One of the Company’s subsidiaries, Resource Energy, LLC, together with Resource America, Inc. (the Company’s former parent) was a defendant in a class action originally filed in February 2000 in the New York Supreme Court, Chautauqua County, by individuals, putatively on their own behalf and on behalf of similarly situated individuals, who leased property to the Company. The complaint alleged that the Company was not paying landowners the proper amount of royalty revenues with respect to natural gas produced from the leased properties. The complaint was seeking damages in an unspecified amount for the alleged difference between the amount of royalties actually paid and the amount of royalties that allegedly should have been paid. In April 2007, a settlement of this lawsuit was approved by the court. Pursuant to the settlement terms, the Company has agreed to pay $300,000, upgrade certain gathering systems and cap certain transportation expenses chargeable to the land owners.

As of March 31, 2007, Atlas Pipeline is committed to expend approximately $50.5 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

NOTE 11 — BENEFIT PLANS

The Company follows the provisions of SFAS No. 123(R), Share-Based Payment, as revised (“SFAS No. 123(R)”), to account for stock incentive compensation plans. 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. Under various plans described below, employees and non-employee directors have received stock/unit options and stock/unit grants, and as a result, the Company charged to General and administrative expenses compensation cost of $4.0 million and $2.7 for the three months ended March 31, 2007 and 2006, respectively. At March 31, 2007, the Company had unamortized compensation expense of $34.2 million that the Company expects to recognize over approximately four years. The Company issues new shares when options are exercised or units are converted to shares. Summarized information related to each of the Company’s stock incentive compensation plans is described in the following paragraphs.

21

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 11 — BENEFIT PLANS - (Continued)

Atlas America Long Term Incentive Plan. The Company adopted a Stock Incentive Plan (the “Plan”) in 2004 which authorized the granting of up to 2.0 million shares of the Company’s common stock.

No options or grants were awarded in the three months ended March 31, 2007. During this period, the Company received $95,500 from the exercise of 3,750 options. There were 1,225,775 options and 11,612 restricted and deferred units outstanding as of March 31, 2007.

Atlas Energy Resources Long-Term Incentive Plan. In December 2006, Atlas Energy Resources LLC adopted a Long-Term Incentive Plan (“ATN LTIP”), which authorized the granting of 3,742,000 Atlas Energy Class B common units.

In January, 2007 Atlas Energy granted unit option awards that expire 10 years from the date of grant, and will vest over a four year service period. The Black-Scholes option pricing model was used to estimate the fair value of $2.41 per option with the following assumptions (a) expected dividend yield of 8.0%, (b) risk-free interest rate of 4.7%, (c) expected volatility of 25%, and (d) an expected life of 6.25 years. The following table sets forth the ATN LTIP option activity for the three months ended March 31, 2007:

					Weighted Average		Aggregate
			Weighted Average		Remaining		Intrinsic
	Shares		Exercise Price		Contractual Term		Value
					(in Years)		(in Thousands)
Outstanding at December 31, 2006		373,752	$	21.00		9.3
Granted		1,297,600	$	23.06		9.8
Outstanding at March 31, 2007		1,671,352	$	22.60		9.6	$	6,769
Options exercisable at March 31, 2007		-	$	-		-	$	-
Available for grant		1,512,029

In addition, Atlas Energy has granted restricted and phantom units that vest over a four year period. Each unit entitles the grantee to one common unit upon vesting, as well as distribution equivalent rights during the period the unit is outstanding. The following table sets forth the ATN LTIP restricted and phantom unit activity for the three months ended March 31, 2007:

			Weighted Average
	Units		Grant Date Fair Value
Outstanding at December 31, 2006		47,619	$	21.00
Granted		511,000	$	23.06
Outstanding at March 31, 2007		558,619	$	22.88

Atlas Pipeline Holdings, L.P. Long-Term Incentive Plan. In November 2006, AHD adopted a Long-Term Incentive Plan (“AHD LTIP”), which authorized the grant of 2,100,000 common units. No options or grants were awarded or were exercised in the three months ended March 31, 2007. There were 1,215,000 options and 220,000 phantom units outstanding as of March 31, 2007.

Atlas Pipeline Long-Term Incentive Plan. Atlas Pipeline has a Long-Term Incentive Plan (“APL LTIP”), which authorized the grant of 435,000 common units. Only phantom units that vest over a four year service period have been granted under the APL LTIP through March 31, 2007. Each unit entitles the grantee to one common unit upon vesting, as well as distribution equivalent rights during the period the unit is outstanding. The following table represents the APL LTIP phantom unit activity for the three months ended March 31, 2007:

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ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

MARCH 31, 2007

(Unaudited)

NOTE 11 — BENEFIT PLANS - (Continued)

			Weighted Average
	Units		Grant Date Fair Value
Outstanding at December 31, 2006		159,067	$	45.51
Granted		24,792	$	50.10
Outstanding at March 31, 2007		183,859	$	46.11

Atlas Pipeline also has incentive compensation agreements which have granted awards to certain key employees retained from previously consummated acquisitions. These individuals are entitled to receive common units of Atlas Pipeline upon achievement of pre-determined performance. Based on Atlas Pipeline management’s estimate of the probable outcome of the performance targets, 223,039 common units are ultimately expected to be issued under these agreements, during the period September 2007 through December 2008.

Supplemental Employment Retirement Plan (“SERP”). The Company has 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 is employed by the Company commencing upon the effective date of the SERP agreement, limited to an annual maximum benefit of 65% of his final base salary and a minimum of 26% of his final base salary. During the three months ended March 31, 2007 and 2006 operations were charged $162,000 and $40,000, respectively, with respect to this commitment.

NOTE 12 — 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.

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ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 13 — CASH DISTRIBUTIONS

The Company receives quarterly cash distributions from Atlas Pipeline Holdings and Atlas Energy Resources according to the policies described below.

Atlas Pipeline Holdings Cash Distributions. Upon completion of its initial public offering, AHD adopted 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 and paid to the Company from inception are as follows:

Date Cash Distribution Paid	For Quarter Ended		Cash Distribution per Common Limited Partner Unit			Total Cash Distribution to the Company (in thousands)
November 19, 2006		September 30, 2006	$	0.17	(1)	$	2,975
February 19, 2007		December 31, 2006	$	0.25		$	4,375

__________________________

⁽¹⁾ Represents a pro-rated cash distribution of $0.24 per common unit for the period from July 26, 2006, the date of the AHD’s initial public offering, through September 30, 2006.

On April 26, 2007, AHD declared a cash distribution of $0.25 per unit on its outstanding common limited partner units. The $4.4 million distribution to the Company will be paid on May 18, 2007.

Atlas Energy Resources Cash Distributions. Upon completion of its initial public offering, Atlas Energy 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 Atlas Energy and paid to the Company from inception are as follows:

Date Cash Distribution Paid	For Quarter Ended		Cash Distribution per Common Unit			Total Cash Distribution to the Company (in thousands)
February 14, 2007		December 31, 2006	$	0.06	(1)	$	1,806

__________________________

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

On April 26, 2007, Atlas Energy declared a cash distribution of $0.43 per unit on its outstanding common units, representing the cash distribution for the quarter ended March 31, 2007. The $12.9 million distribution to the Company will be paid on May 15, 2007.

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ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2007

(Unaudited)

NOTE 14 — SUBSEQUENT EVENTS

On April 27, 2007, the Company announced that its Board of Directors had approved a 3-for-2 stock split to be effected in the form of a stock dividend. Shareholders of record as of May 15, 2007 will receive one additional share of common stock for each two shares of common stock they own on that date. The shares will be distributed on or about May 25, 2007. Information pertaining to shares and earnings per share has not been restated in the accompanying financial statements and notes to the consolidated financial statements to reflect this split. This information will be presented effective after the stock dividend is distributed (in the Company’s June 30, 2007 interim financial statements).

On April 27, 2007, the Company also announced that its Board of Directors has declared its first quarterly cash dividend of $0.05 per share of common stock, payable on May 15, 2007, to shareholders of record on May 8, 2007.

On April 18, 2007, Atlas Pipeline amended the terms of its $40.0 million of preferred limited partner unit financing arrangement with Sunlight Capital Partners (“Sunlight”). Under the amended provisions of the financing arrangement, the stated 6.5% per annum dividend on the preferred units will accrue, but not be payable until March 13, 2008. The conversion of the preferred units, at Sunlight’s option, will be postponed until the date immediately following the first common unit distribution record date after March 13, 2008. In addition, the conversion price for the preferred units was increased to the lesser of $43.00 or 95% of the market price of Atlas Pipeline’s common units as of the date of notice of conversion. In connection with this amended arrangement, Atlas Pipeline provided Sunlight a premium on its preferred units through the issuance of approximately $8.5 million of its 8.125% senior unsecured notes at 103% of their par value.

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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Unaudited)

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, under the caption “Risk Factors”, in our annual report on Form 10-K/A for fiscal 2006.  These risks and uncertainties could cause actual results to differ materially.  Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof.  We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events, except as may be requested by applicable law.

General

We are an energy company engaged, through subsidiaries, in the development, production and transportation of natural gas and, to a lesser extent, oil.

We conduct our development and production operations through Atlas Energy Resources, LLC (NYSE: ATN), which we refer to as Atlas Energy, or ATN, in which we own approximately 80% of the common units. Atlas Energy focuses its operations in the Appalachian Basin.

We conduct our natural gas transportation and processing operations through Atlas Pipeline Partners, L.P. (NYSE: APL), which we refer to as Atlas Pipeline, or APL. The general partner of Atlas Pipeline is Atlas Pipeline Partners GP, LLC, which we refer to as Atlas Pipeline GP, a wholly-owned subsidiary of Atlas Pipeline Holdings, L.P. (NYSE: AHD), which we refer to as Atlas Pipeline Holdings, or AHD, in which we own an 82.9% interest. Atlas Pipeline GP has a 2% general partner interest, a 12.5% limited partner interest and all the incentive distribution rights in Atlas Pipeline.

On June 15, 2006, our Board of Directors changed our year end from September 30 to December 31. Accordingly, these consolidated financial statements reflect the Company’s new year-end of December 31 and year-to-date amounts are for the three month periods ended March 31, 2007 and 2006.

Recent Developments

Stock and Cash Dividend. On April 27, 2007, our Board of Directors approved a 3-for-2 stock split to be effected in the form of a stock dividend. Shareholders of record as of May 15, 2007 will receive one additional share of common stock for each two shares of common stock they own on that date. The shares will be distributed on or about May 25, 2007. Also, on April 27, 2007, our Board of Directors declared a cash dividend of $.05 per share, payable on May 15, 2007, to shareholders of record on May 8, 2007.

Investment by Atlas Lightfoot, LLC. On February 21, 2007, our subsidiary, Atlas Lightfoot, LLC, invested $931,000 in Lightfoot Capital Partners LP, or Lightfoot, and will own, directly and indirectly, approximately 18% of Lightfoot Capital Partners GP, LLC, the general partner of Lightfoot. We have committed to invest a total of $20.0 million in Lightfoot. We 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 initial equity funding commitments of approximately $160.0 million and intends to focus its investments primarily on incubating new master limited partnerships, or MLPs, 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 management teams in sectors that have under-utilized by the MLP structure.

Dutch Tender Offer. On January 30, 2007, we 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, we purchased 1,486,605 shares at a cost of $80.4 million, including expenses.

General Trends and Outlook

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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Atlas Pipeline 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, and maintenance of high-quality customer relationships. Many of Atlas Pipeline’s competitors operate as master limited partnerships and enjoy a cost of capital comparable to and, in some cases lower than, theirs. Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than theirs. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. Atlas Pipeline believes the primary difference between it and some of its competitors is that they provide an integrated and responsive package of midstream services, while some of their competitors provide only certain services. Atlas Pipeline believes that offering an integrated package of services, while remaining flexible in the types of contractual arrangements that it offers producers, allows it to compete more effectively for new natural gas supplies in their regions of operations.

As a result of Atlas Pipeline’s POP and keep-whole contracts, its results of operations and financial condition substantially depend upon the price of natural gas and NGLs. Atlas Pipeline believes that future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. Based on historical trends, Atlas Pipeline generally expects NGL prices to follow changes in crude oil prices over the long term, which it believes 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.

Atlas Energy. As a driller for and producer of natural gas, Atlas Energy’s results of operations and financial condition, like those of Atlas Pipeline, substantially depend on the price of natural gas and are affected by the same factors. Because of the current high levels of natural gas prices Atlas Energy expects that not withstanding short-term market uncertainty that may cause short-term declines in drilling activity, there will continue to be relatively high levels of natural gas-related drilling in the United States as producers seek to increase their level of natural gas production. However fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas reserves including investments in our drilling investment partnerships. Drilling activity generally decreases as natural gas prices decrease. Atlas Energy has no control over the level of drilling activity in the areas of its operations.

Results of Operations for the Three Months Ended March 31, 2007 Compared to the Three Months Ended March 31, 2006

Well Construction and Completion

Our well construction and completion revenues and costs and expenses incurred represent the billings and costs associated with the completion of wells for drilling investment partnerships we sponsor.  The following table sets forth information relating to these revenues and the related costs, gross profit margins and number of net wells drilled during the periods indicated (dollars in thousands):

	Three Months Ended
	March 31,
	2007		2006
Average construction and completion revenue per well	$	299	$	291
Average construction and completion cost per well		260		253
Average construction and completion gross profit per well	$	39	$	38
Gross profit margin	$	9,446	$	6,637
Net wells drilled		242		175

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Our well construction and completion segment margin was $9.4 million in the three months ended March 31, 2007, an increase of $2.8 million (42%) from $6.6 million in the three months ended March 31, 2006.  During the three months ended March 31, 2007, the increase of $2.8 million in segment margin was attributable to an increase in the number of wells drilled ($2.5 million) and an increase in the gross profit per well ($268,000). The increase in the number of wells drilled is the result of an increase in our fundraising in fiscal 2006. It should be noted that “Liabilities associated with drilling contracts” on our balance sheet includes $6.9 million of funds raised in our drilling investment programs in calendar 2006 that have not been applied to the completion of wells as of March 31, 2007 due to the timing of drilling operations, and thus had not been recognized as well drilling revenue.  We expect to recognize this amount as revenue in the second quarter of fiscal 2007. During fiscal 2006 we raised $218.5 million and plan to raise approximately $270.0 million fiscal 2007. We anticipate favorable oil and gas prices will continue to favorably impact our fundraising and therefore our drilling revenues in the remainder of fiscal 2007.

Gas and Oil Production

The following table sets forth information relating to our production revenues, production volumes, sales prices, production costs and depletion for the periods indicated:

	Three Months Ended
	March 31,
	2007			2006
Production revenues (in thousands):
Gas (1)	$	19,427		$	20,492
Oil	$	1,826		$	2,365
Production volumes (2):
Gas (mcf/day) (1)		23,681			20,866
Oil (bbls/day)		359			423
Total (mcfe/day) (3)		25,835			23,404
Average sales prices:
Gas (per mcf) (3)	$	9.12		$	10.91
Oil (per bbl) (3)	$	56.52		$	62.13
Production costs (4):
As a percent of production revenues		10	%		8	%
Per mcfe	$	.87		$	.90
Depletion per mcfe	$	2.31		$	1.98

(1)	Excludes sales of residual gas and sales to landowners.
(2)	Production quantities consist of the sum of (i) our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells, and (ii) our proportionate share of production from wells owned by the investment partnerships in which we have an interest, based on our equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells.
(3)	Our average sales price before the effects of financial hedging was $7.85 and $9.37 per mcf for the three months ended March 31 2007 and 2006, respectively.
(4)	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.

Our natural gas revenues were $19.4 million in the three months ended March 31, 2007, a decrease of $1.1 million (5%) from $20.5 million in the three months ended March 31, 2006. The decrease was attributable to a 16% decrease in the average sales price of natural gas partially offset by a 13% increase in production volumes. The $1.1 million decrease in natural gas revenues consisted of a $3.4 million decrease attributable to decreases in natural gas sales prices and a $2.3 million increase attributable to increased production volumes.

The increase in our gas production volumes of 2,815 Mcf/d resulted from production associated with new wells drilled for our investment partnerships. We believe that gas volumes will continue to be favorably impacted in the remainder of 2007 as ongoing projects to extend and enhance the gathering systems of Atlas Pipeline are completed and wells drilled are connected in these areas of expansion.

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Our oil revenues were $1.8 million in the three months ended March 31, 2007, a decrease of $539,000 (23%) from $2.4 million during the three months ended March 31, 2006. The decrease resulted from a 9% decrease in the average sales price of oil, and a 15% decrease in production volumes. The $539,000 decrease consisted of $214,000 attributable to decreases in sales prices, and $325,000 attributable to volume decreases, as we drill primarily for natural gas rather than oil.

Our production costs were $2.0 million in the three months March 31, 2007, an increase of $129,000 (7%) from $1.9 million in the three months ended March 31, 2006.  This increase includes an increase in pumping labor and maintenance costs associated with an increase in the number of wells we own and operate from the prior year period. The increase in production costs as a percent of production revenues in the three months ended March 31, 2007 as compared to March 31, 2006 was due to a decrease in our average sales price per mcfe.

Transmission, Gathering and Processing

The following table presents selected volumetric information related to Atlas Pipeline for the periods indicated:

	Three Months Ended
	March 31, 2007		March 31, 2006
Operating data:
Appalachia system throughput volume (mcf/day)		62,532		57,326
Velma system gathered gas volume (mcf/day)		61,017		60,715
NOARK Ozark Gas Transmission throughput volume (mcf/day)		286,891		239,151
Elk City/Sweetwater system gathered gas volume (mcf/day)		287,892		252,190
Combined throughput volume (mcf/day)		698,332		609,382

Average throughput volume on Atlas Pipeline’s Appalachia system increased by 5.2 mmcf/d (9%) for the three months ended March 31, 2007 to 62.5 mmcf/d, principally due to new wells connected to its gathering system. Gross natural gas gathered volumes averaged 61.0 mmcf/d on the Velma system for the three months ended March 31, 2007, an increase of 0.5% from the comparable prior year period. Gathered natural gas volume on the Elk City system averaged 287.9 mmcf/d for the three months ended March 31, 2007, an increase of 14% from the comparable prior year period. For the NOARK system, average Ozark Gas Transmission throughput volume was 286.9 mmcf/d for the three months ended March 31, 2007, an increase of 20% from the prior year comparable period.

Our transmission, gathering and processing revenues were $117.5 million for the three months ended March 31, 2007, a decrease of $700,000 from $118.2 million for the three months ended March 31, 2006. The decrease was attributable to a decrease of $11 million in revenue contributions from Atlas Pipeline’s NOARK system primarily due to lower natural gas sales volumes on its gathering systems, and a decrease of $2.9 million from the Velma system due to lower commodity prices compared to the prior year period. In addition, Atlas Pipeline recognized a $2.9 million increase in derivative losses from the prior year, due to unfavorable movements in commodity prices. This decrease was partially offset by an increase of $16.4 million from Atlas Pipeline’s Elk City system primarily due to an increase in volumes, which includes contributions from the newly constructed Sweetwater gas plant.

Transmission, gathering, and processing revenues above include revenues earned by Atlas Pipeline’s Appalachian segment under its master gas gathering agreement with us or Atlas Energy which is eliminated upon consolidation in our financial statements. Revenues earned under this agreement were approximately $7.7 million and $7.9 million the three months ended March 31, 2007 and 2006, respectively. This is offset by transportation revenues received by us from our investment partnerships for gathering services of $3.3 million and $2.3 million for the same periods.

Our transmission, gathering and processing costs and expenses were $95.5 million for the three months ended March 31, 2007, an increase of $4.1 million (4.5%) from $91.4 million for the three months ended March 31, 2006. The increase was primarily related to increased gathered and processed volumes on Atlas Pipeline’s Elk City system, which includes contributions from the Sweetwater processing facility, and higher NOARK and Appalachia system operating and maintenance costs as a result of additional capacity and additional well connections. These amounts were partially offset by a decrease from Atlas Pipeline’s NOARK gathering system natural gas purchases and a decrease in commodity prices on Atlas Pipeline’s Velma system.

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Administration and Oversight

Our administrative and oversight fee represents supervision and administrative fees earned for drilling wells and ongoing monthly management fees from our investment partnerships. These fees were $4.5 million in the three months ended March 31, 2007, an increase of $1.2 million (37%) from $3.3 million in the three months ended March 31, 2006. This increase is attributable to an increase in the number of wells drilled and managed for our investment partnerships in the three months ended March 31, 2007 as compared to 2006.

Well Services

Our well services revenues were $3.7 million in the three months ended March 31, 2007, an increase of $955,000 (35%) from $2.8 million in the three months ended March 31, 2006. This increase resulted from an increase in the number of wells operated for our investment partnerships due to additional wells drilled in the twelve months ended March 31, 2007.

Our well services expenses were $2.0 in the three months ended March 31, 2007, an increase of $277,000 (16%) from $1.8 million in the three months ended March 31, 2006.  This increase was attributable to an increase in wages, benefits, and field office expenses associated with an increase in employees due to the increase in the number of wells we operate for our investment partnerships.

General and Administrative

Our general and administrative expenses, including net expense reimbursements to affiliate were $14.8 million in the three months ended March 31, 2007, an increase of $1.5 million from $13.3 million in the three months ended March 31, 2006. These expenses include, among other things, salaries and benefits not allocated to a specific segment, costs of running our corporate office, partnership syndication activities and outside services. The increase of $1.5 million in the three months ended March 31, 2007 is principally attributable to general and administrative expenses related to Atlas Pipeline’s operations, which increased primarily as a result of an increase of $1.1 million related to stock compensation awards, and an increase of $445,000 in audit fees.

Depletion

Our depletion of oil and gas properties as a percentage of oil and gas revenues was 25% in the three months ended March 31, 2007, compared to 18% in the three months ended March 31, 2006. Depletion expense per mcfe was $2.31 in the three months ended March 31, 2007, an increase of $0.33 (17%) per mcfe from $1.98 in the three months ended March 31, 2006. Increases in our depletable basis and production volumes caused depletion expense to increase $1.2 million (28%) to $5.4 million in the three months ended March 31, 2007 compared to $4.2 million in the three months ended March 31, 2006. The variances from period to period are directly attributable to changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties.

Depreciation and Amortization

Depreciation and amortization increased $1.1 million (19%) to $7.0 million in the three months ended March 31, 2007 compared to $5.9 million in the three months ended March 31, 2006. This was primarily due to the increased asset base associated with Atlas Pipeline’s acquisition of the NOARK assets in 2006 and expansion capital expenditures, particularly the construction of the Sweetwater processing facility.  

Interest Expense

Our interest expense was $7.3 million in the three months ended March 31, 2007, an increase of $535,000 from $6.7 million in the three months ended March 31, 2006. This resulted primarily from an increase in interest expense of $408,000 as a result of outstanding borrowings by Atlas Energy of $56.5 million under its credit facility.

Minority Interests

At March 31, 2007, we owned 11% of the partnership interest in Atlas Pipeline through our ownership in AHD. Because we control the operations of APL, we include it in our consolidated financial statements and show the ownership by the public as minority interests. The minority interest income in AHD earnings was $695,000 for in the three months ended March 31, 2007 and an expense of $6.3 million for the three months ended March 31, 2006, a decrease of $6.9 million in the three months ended March 31, 2007. This decrease is a result of a decrease in the non-cash allocation of Atlas Pipeline’s net income to the limited partners resulting from the allocation of incentive distributions to AHD, the general partner.

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After the initial public offering of Atlas Energy on December 18, 2006, approximately 19.4% is owned by the general public. We include Atlas Energy in our consolidated financial statements and show the ownership by the pubic as a minority interest. The minority interest expense in Atlas Energy was $3.9 million for the three months ended March 31, 2007.

Liquidity and Capital Resources

General.  We fund operations from a combination of sources. Atlas Energy funds its exploration and production operations from cash generated by operations, capital raised through drilling investment partnerships and, if required, use of its credit facility. Atlas Pipeline funds its operations through a combination of cash generated by operations, its credit facility and sales of its common units.

The following table sets forth our sources and uses of cash (in thousands):

	Three Months Ended
	March 31,
	2007			2006
Used in operations	$	(46,927	)	$	(48,181	)
Used in investing activities		(41,423	)		(30,119	)
Provided by (used in) financing activities		(8,670	)		65,943
Decrease in cash and cash equivalents	$	(97,020	)	$	(12,357	)

We had $88.4 million in cash and cash equivalents on hand at March 31, 2007, as compared to $185.4 million at December 31, 2006. Our ratio of earnings from continuing operations before income taxes, minority interest and interest expense to fixed charges was 5.0 to 1.0 for the three months ended March 31, 2007 and March 31, 2006. We had working capital of $32.6 million, a decrease of $47.8 million from $80.4 at December 31, 2006. The decrease in our working capital reflects a decrease in our current assets of $136.6 million, partially offset by a decrease in our current liabilities of $88.8 million. The decrease in our current assets is primarily due to a decrease in cash of $97.0 million, a decrease in accounts receivable of $11.0 and a decrease of $22.0 million in the current portion of our hedge receivable. The decrease in cash was primarily a result of $80.4 million used to repurchase stock. The decrease in our current liabilities is primarily due to a decrease of $67.1 million in our liabilities associated with drilling contracts, related to the timing of funds raised and the subsequent use of those funds.

At March 31, 2007, the borrowing base under Atlas Energy’s credit facility is $175.0 million, and it has $118.0 million available. At March 31, 2007, Atlas Pipeline has a borrowing base of $225.0 million under its credit facility, of which $164.9 million is available. At March 31, 2007, AHD has a borrowing base of $50.0 million, with no outstanding borrowings. See Note 7 to our Consolidated Financial Statements for information on Atlas Energy’s, Atlas Pipeline’s and AHD’s credit facilities at March 31, 2007.

Cash flows from operating activities.Cash provided by operations is an important source of short-term liquidity for us.  It is directly affected by changes in commodity prices, interest rates and our ability to raise funds from our drilling investment partnerships.  Netcash used in operating activities decreased $1.3 million in the three months ended March 31, 2007 to $46.9 million from $48.2 million in the three months ended March 31, 2007, substantially as a result of the following:

• an increase in net income before depreciation and amortization of $1.0 million in the three months ended March 31, 2007 as compared to the prior year period, principally as a result of income included in our financial statements from our acquisitions, higher gross margins related to administrative and oversight and well services, and drilling profits;

• an increase in non-cash items of $3.1 million related to losses on our hedge values and compensation expense resulting from grants under long-term incentive plans;

• changes in minority interests and distributions paid to minority interests decreased by $5.2 million due to a decrease in the allocation of Atlas Pipeline’s earnings to the limited partners, offset by higher distributions paid to minority interests,

• changes in our deferred tax liability decreased by $2.2 million as compared to the three months ended March 31, 2006 which reflects the impact of timing differences between accounting and tax records, and

• changes in operating assets and liabilities increased operating cash flow by $4.6 million in the three months ended March 31, 2007, compared to the three months ended March 31, 2006.

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This change in operating assets and liabilities is primarily a result of the following:

• a decrease of $16.3 million in accounts payable and accrued liabilities, including liabilities associated with our drilling contracts, our level of liabilities associated with drilling contracts is dependent upon the remaining amount of our drilling obligations at any balance sheet date, which is dependent upon the timing of funds raised through our investment partnerships; and

• an increase of $21.4 million in accounts receivable and prepaid expenses, primarily due to a decrease in Atlas Pipeline’s accounts receivable resulting from a decrease in commodity prices.

Cash flows from investing activities.Cash used in our investing activities increased $11.3 million in the three months ended March 31, 2007 to $41.4 million from $30.1 million in the three months ended March 31, 2006 primarily as a result of a $6.8 million increase in capital expenditures related to an increase in the number of wells we drilled, and a $3.4 million increase in capital expenditures related to pipeline expansions.

Cash flows from financing activities. Cash used in our financing activities increased $74.6 million in the three months ended March 31, 2007 to $8.7 million from cash provided of $65.9 million in the three months ended March 31, 2006, as a result of the following: 

• we repurchased $80.4 million of common stock in a Dutch tender offer in the three months ended March 31, 2007; repurchases were $475,000 in the three months ended March 31, 2006;

• net borrowings on debt increased by $34.9 million in the three months ended March 31, 2007 as compared to the prior year similar period principally as a result of the borrowings under Atlas Energy’s credit facility; and

• we received proceeds of $30.0 million from Atlas Pipeline’s issuance of cumulative convertible preferred units in March 2006; there were no such offerings in the three months ended March 31, 2007.

Capital Requirements: During the three months ended March 31, 2007, our capital expenditures related primarily to investments in our drilling partnerships and pipeline expansions, in which we invested $22.1 million and $18.4 million, respectively.  For the three months ended March 31, 2007 and the remaining quarters of fiscal 2007, we funded and expect to continue to fund these capital expenditures through cash on hand, borrowings under our credit facilities, and from operations.  We have established three credit facilities to fund our capital expenditures. 

The level of capital expenditures we must devote to our exploration and production operations depends upon the level of funds raised through our drilling investment partnerships.  We believe cash flows from operations and amounts available under our credit facilities will be adequate to fund our contributions to these partnerships.  However, the amount of funds we raise and the level of our capital expenditures will vary in the future depending on market conditions for natural gas and other factors.  

We continuously evaluate acquisitions of gas and oil and pipeline assets.  In order to make any acquisition, we believe we will be required to access outside capital either through debt or equity placements or through joint venture operations with other energy companies.  There can be no assurance that we will be successful in our efforts to obtain outside capital. 

Atlas Energy New Credit Facility. In December 2006, Atlas Energy entered into a new $250.0 million credit facility, with a syndicate of lenders by Wachovia Bank, N.A., or Wachovia. The revolving credit facility borrowing base was increased to $175.0 million in March 2007, which may be redetermined subject to changes in Atlas Energy’s oil and gas reserves. Up to $50.0 million of the facility may be in the form of standby letters of credit. The facility is secured by Atlas Energy’s assets and bears interest at either the base rate plus the applicable margin or at an adjusted London Interbank Offered Rate, or LIBOR plus the applicable margin, elected at Atlas Energy’s option.

The Wachovia credit facility requires Atlas Energy to maintain specified ratios of current assets to current liabilities, interest coverage (as defined), and debt to earnings before interest, taxes, depreciation, depletion and amortization, or EBITDA. In addition, the facility limits sales, leases or transfers of assets and the incurrence of additional indebtedness. The facility limits the dividends payable by Atlas Energy if an event of default has occurred and is continuing or would occur as a result of such distribution. Atlas Energy is in compliance with these covenants as of March 31, 2007. The facility terminates in December 2011, when all outstanding borrowings must be repaid. At March 31, 2007 and December 31, 2006, $57.0 million and $495,000, respectively, were outstanding under this facility including letters of credit of $495,000 at each date which are not reflected as borrowings on our Consolidated Balance Sheets. At March 31, 2007, the weighted average interest rate on outstanding borrowings was 8.5%.

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Contractual Obligations and Commercial Commitments

The following table summarizes our contractual obligations at March 31, 2007.

			Payments Due By Period
			(in thousands)
			Less than		2 - 3		4 - 5		After 5
Contractual cash obligations:	Total		1 Year		Years		Years		Years
Long-term debt(1)	$	395,579	$	81	$	48	$	109,500	$	285,950
Secured revolving credit facilities		-		-		-		-		-
Operating lease obligations		6,769		3,728		2,731		309		1
Capital lease obligations		-		-		-		-		-
Unconditional purchase obligations		-		-		-		-		-
Other long-term obligation		-		-		-		-		-
Total contractual cash obligations	$	402,348	$	3,809	$	2,779	$	109,809	$	285,951

 

(1) Not included in the table above are estimated interest payments calculated at the rates in effect at March 31, 2007 of: 2008 - $31.9 million; 2009 - $31.9 million; 2010 - $31.9 million; 2011 - $31.9 million and 2012 and after - $113.7 million.

 

			Payments due by Period
				(in thousands)
				Less than		1- 3		4 - 5	After 5
Other commercial commitments:		Total		1 Year		Years		Years	Years
Standby letters of credit	$	7,545	$	7,545	$	-	$	-	$	-
Guarantees		-		-		-		-		-
Standby replacement commitments		-		-		-		-		-
Other commercial commitments		50,532		50,532		-		-		-
Total commercial commitments	$	58,077	$	58,077	$	-	$		$	-

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America.  The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of our assets, liabilities, revenues, costs and expenses, and related disclosure of contingent assets and liabilities.  On an on-going basis, we evaluate our estimates, including those related to the provision for possible losses, deferred tax assets and liabilities, goodwill and identifiable intangible assets, and certain accrued liabilities.  We base our estimates on historical experience and on various other assumptions that we believe reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources.  Actual results may differ from these estimates under different assumptions or conditions.

For a detailed discussion on the application of policies critical to our business operations and other accounting policies, see our Annual Report on Form 10-K/A for the year ended December 31, 2006 Note 2 of the "Notes to Consolidated Financial Statements" and Note 2 to the “Notes to Consolidated Financial Statements” included in this report.

Recently Issued Financial Accounting Standards

In February 2007, the Financial Accounting Standards Board, or FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, or SFAS 159. SFAS 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. The statement will be effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. The Statement offers various options in electing to apply its provisions and at this time we have not made any decisions as to its application and are evaluating the impact of the adoption of SFAS 159 on our financial position and results of operations.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurement, or SFAS 157. SFAS 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements. SFAS 157 is effective for us beginning January 1, 2008. We are currently evaluating the impact of its adoption of SFAS 157 on our financial position and results of operations.

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We adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, or FIN 48, on January 1, 2007. Previously, we had accounted for tax contingencies in accordance with Statement of Financial Accounting Standards No.5, Accounting for Contingencies. FIN 48 clarifies the accounting for income taxes, by prescribing a minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. As a result of the implementation of FIN 48, we determined that we had no liability for unrecognized income tax benefits upon adoption and through March 31, 2007.

We file numerous Federal and State consolidated and separate income tax returns. We are no longer subject to United States Federal income tax examinations for periods ending before September 30, 2003 and we are no longer subject to state and local income tax examinations by tax authorities for periods ending before September 30, 2002.

Our policy is to recognize potential accrued interest and penalties related to unrecognized tax benefits in income tax expense.

We do not anticipate that total unrecognized tax benefits will significantly change within the next twelve months.

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.  The following discussion is not meant to be a precise indicator of expected future gains or losses, but rather an indicator of reasonable possible losses.  This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.  All of our market risk sensitive instruments were entered into for purposes other than trading.

General

We 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 manage these risks through regular operating and financing activities and periodically use derivative financial instruments.

The following analysis presents the effect on our earnings, cash flows and financial position as if the hypothetical changes in market risk factors occurred on March 31, 2007.  Only the potential impacts of hypothetical assumptions are analyzed.  The analysis does not consider other possible effects that could impact our business.

Interest Rate Risk.  At March 31, 2007, Atlas Energy had a $175.0 million revolving credit facility ($56.5 million outstanding at March 31, 2007).  The weighted average interest rate for this facility was 8.5% at March 31, 2007. 

At March 31, 2007, Atlas Pipeline had a $225.0 million revolving credit facility ($53.0 million outstanding at March 31, 2007). The weighted average interest rate for this facility was 7.4% at March 31, 2007.

Holding all other variables constant, if interest rates hypothetically increased or decreased by 10%, our net annual income would change by approximately $494,000.

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Commodity Price Risk.  Our major market risk exposure in commodities is fluctuations in the pricing of our gas and oil production.  Realized pricing is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas production.  Pricing for gas and oil production has been volatile and unpredictable for many years.  To limit our exposure to changing natural gas prices, we use hedges.  Through our hedges, we seek to provide a measure of stability in the volatile environment of natural gas prices.  These transactions are similar to NYMEX-based futures contracts, swaps and options, but also require firm delivery of the hedged quantity.  Thus, we limit these arrangements to much smaller quantities than those projected to be available at any delivery point.  For the twelve month period ending March 31, 2007, we estimate approximately 62% of our produced natural gas volumes will be sold in this manner, leaving our remaining production to be sold at contract prices in the month produced or at spot market prices. Atlas Energy also negotiates with certain purchasers for delivery of a portion of natural gas it will produce for the upcoming twelve months.  The prices under most of its gas sales contracts are negotiated on an annual basis and are index-based. Atlas Energy's risk management objective is to lock in a range of pricing for expected production volumes. Considering those volumes for which we have entered into physical or financial hedge agreements for the year ended December 31, 2007, and current indices, a theoretical 10% upward or downward change in the price of natural gas would change net income by approximately $5.2 million.

Atlas Energy also enters into natural gas futures and option contracts. At any point in time, such contracts may include regulated New York Mercantile Exchange, or NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas.

Atlas Energy  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 natural gas futures and options contracts to the forecasted transactions. We assess, both at the inception of the hedge 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 as Accumulated Other Comprehensive Income (Loss) and 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, we will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings.

At March 31, 2007 and December 31, 2006 Atlas Energy had net hedging assets of $687,000 and $47.4 million, respectively. At March 31, 2007, Atlas Energy had 293 open natural gas futures contracts related to natural gas sales covering 60.8 million MMBtus of natural gas, maturing through March 31, 2012 at a combined average settlement price of $8.31 per MMBtu. Atlas Energy recognized a gain of $2.4 million and $1.4 million on settled contracts covering natural gas production for the three months ended March 31, 2007 and 2006, respectively. There were no gains or losses recognized during the three months ended March 31, 2007 or 2006 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges. Of the $687,000 net unrealized hedge gain at March 31, 2007, Atlas Energy portion is $292,000 and $395,000 has been reallocated to the investment partnerships.

Atlas Pipeline. Atlas Pipeline also enters into certain financial swaps and option instruments which qualify as cash flow hedges in accordance with SFAS No. 133 to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate is sold. Under these swap agreements, Atlas Pipeline receives a fixed price and remits a floating price based on certain indices for the relevant contract period.

Atlas Pipeline 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 natural gas futures and options contracts to the forecasted transactions. Atlas Pipeline assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives are effective in offsetting changes in the forecasted cash flow of hedged items. 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 correlation between the reference prices underlying a hedging instrument and the underlying commodity, Atlas Pipeline will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined through the utilization of market data, will be recognized immediately into earnings.

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A portion of Atlas Pipeline’s future natural gas sales is periodically hedged through the use of swaps and collar contracts. Realized gains and losses on the derivative instruments that are classified as effective hedges are reflected in the contract month being hedged as an adjustment to revenue.

At March 31, 2007 and December 31, 2006, Atlas Pipeline had a net hedging liability of $28.0 million and 20.1 million, respectively. Ineffective hedge gains or losses are recorded in Atlas Pipeline’s consolidated statements of income while the hedge contracts are open and may increase or decrease until settlement of the contract. Atlas Pipeline recognized losses of $3.0 million and $2.4 million, for the three months ended March 31, 2007 and 2006, respectively, related to the settlement of qualifying hedge instruments. Atlas Pipeline also recognized a loss of $1.3 million and a gain of $1.0 for the three months ended March 31, 2007 and 2006, respectively, related to the change in market value of non-qualifying or ineffective hedges. Such gains and losses are included within transmission, gathering and processing in the Company’s consolidated statements of income.

Derivatives are recorded on our Balance Sheets as assets or liabilities at fair value. At March 31, 2007 and December 31, 2006, we reflected a net hedging asset and liability on our balance sheets of $27.3 million, respectively, when combining the above hedges of Atlas Energy and Atlas Pipeline. Of the $1.8 million net loss in accumulated other comprehensive income at March 31, 2007, we will reclassify $1.2 million of losses to our consolidated statements of income over the next twelve month period as these contracts expire, and $600,000 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.

As of March 31, 2007, we had the following financial hedges in place:

ATLAS ENERGY RESOURCES HEDGES

Natural Gas Fixed Price Swaps

Twelve Month
Period Ending			Average		Fair Value
March 31	Volumes		Fixed Price		Asset/(Liability) (3)
	(MMBtu) (1)		(per MMBtu)		(in thousands)
2008		16,380,000	$	8.676	$	1,342
2009		16,080,000		8.599		611
2010		14,040,000		8.195		1,133
2011		7,950,000		7.572		(1,440	)
2012		3,600,000		7.365		(46	)
					$	1,600

Natural Gas Costless Collars

Twelve Month
Period Ending					Average		Fair Value
March 31	Option Type		Volumes		Floor and Cap		Asset/(Liability) (3)
			(MMBtu) (1)		(per MMBtu)		(in thousands)
2008		Puts purchased		1,200,000	$	7.500	$	—
2008		Calls sold		1,200,000		8.600		(364	)
2008		Puts purchased		390,000		7.500		—
2008		Calls sold		390,000		9.400		(465	)
2009		Puts purchased		1,170,000		7.500		—
2009		Calls sold		1,170,000		9.400		(84	)
		Total Atlas Energy Resources net asset					$	(913	)
							$	687

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ATLAS PIPELINE HEDGES

Natural Gas - Price Swaps (Liquids Sales)

Production
Period Ended			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset/(Liability) (2)
	(gallons)		(per gallon)		(in thousands)
2007		71,631,000	$	0.901	$	(9,221	)
2008		33,012,000		0.697		(9,076	)
2009		8,568,000		0.746		(2,113	)
					$	(20,410	)

Natural Gas - Price Swaps (Sales)

Production
Period Ended			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset/(Liability) (3)
	(MMBtu) (1)		(per MMBtu)		(in thousands)
2007		810,000	$	7.255	$	(798	)
2008		240,000		7.270		(395	)
2009		480,000		8.000		(162	)
					$	(1,355	)

Natural Gas Basis (Sales)

Production
Period Ended			Average			Fair Value
December 31,	Volumes		Fixed Price			Asset (3)
	(MMBtu) (1)		(per MMBtu)			(in thousands)
2007		810,000	$	(0.535	)	$	362
2008		240,000		(0.555	)		150
2009		480,000		(0.540	)		50
						$	562

Natural Gas Fixed Price (Purchase)

Production
Period Ended			Average			Fair Value
December 31,	Volumes		Fixed Price			Liability (3)
	(MMBtu) (1)		(per MMBtu)			(in thousands)
2007		5,220,000	$	8.854	(4)	$	(4,926	)
2008		4,056,000		8.719	(5)		(733	)
2009		2,088,000		8.343			(19	)
						$	(5,678	)

Natural Gas Basis (Purchase)

Production
Period Ended			Average			Fair Value
December 31,	Volumes		Fixed Price			Liability (3)
	(MMBtu) (1)		(per MMBtu)			(in thousands)
2007		5,220,000	$	(0.907	)	$	(322	)
2008		4,056,000		(1.028	)		(211	)
2009		2,880,000		(0.592	)		(150	)
						$	(683	)

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Crude Oil Fixed - Price Swaps (Sales)

Production
Period Ended			Average		Fair Value
December 31,	Volumes		Fixed Price		Liability (3)
	(barrels)		(per barrel)		(in thousands)
2007		57,800	$	56.192	$	(717	)
2008		65,400		59.424		(689	)
2009		33,000		62.700		(207	)
					$	(1,613	)

Crude Oil Options (Sales)

Production							Fair Value
Period Ended					Average		Asset/
December 31,	Option Type		Volumes		Strike Price		(Liability) (3)
			(MMBtu)(1)		(per MMBtu)		(in thousands)
2007		Puts purchased		9,900	$	60.000	$	13
2007		Calls sold		9,900		73.380		(27	)
2008		Puts purchased		43,800		60.000		(25	)
2008		Calls sold		43,800		79.544		(166	)
2009		Puts purchased		30,000		60.000		122
2009		Calls sold		30,000		71.250		(196	)
							$	(279	)

Crude Oil Sales Options (associated with NGL volumes)

Production									Fair Value
Period Ended			Crude		Associated		Average crude		Asset/
December 31,	Option Type		Volumes		NGL Volumes		Strike Price		(Liability) (3)
			(barrels)		(gallons)		(per barrel)		(in thousands)
2008		Puts purchased		693,600		38,744,000	$	60.000		2,526
2008		Calls sold		693,600		38,744,000		84.000		(2,570	)
2009		Puts purchased		720,000		40,219,000		60.000		3,314
2009		Calls sold		720,000		40,219,000		81.000		(1,838	)
									$	1,432
				Total Atlas Pipeline net liability					$	(28,024	)
				Total Atlas America net liability					$	(27,337	)

(1)	MMBtu represents million British Thermal Units.
(2)	Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas and light crude prices.
(3)	Fair value based on forward NYMEX natural gas and light crude prices, as applicable.
(4)	Includes Atlas Pipeline’s premium received from its sale of an option for it to sell 3,600,000 MMBtu of natural gas at an average price of $14.33 per MMBtu for the year ended December 31, 2007.
(5)	Includes Atlas Pipeline’s premium received from 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.

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Item 4.Controls and Procedures

Disclosure Controls and Procedures

In connection with the preparation of this Form 10-Q/A, our management, with the participation of our principal executive officer and principal financial officer, carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Based upon that evaluation, our principal executive officer and principal financial officer concluded that, because of a material weakness in internal controls over financial reporting discussed below, as of March 31, 2007 our disclosure controls and procedures were not effective.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the three months ended March 31, 2007 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting, except for the following material weakness that was identified as a result of management’s evaluation of such changes and as a result of the evaluation described above.

During the preparation of our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007, we determined that our accounting treatment for the sales of our subsidiaries' stock were subject to the provisions of Staff Accounting Bulletin No. 51, Accounting by the Parent in Consolidation for Sales of Stock by a Subsidiary, (“SAB No. 51”). SAB No. 51 requires the calculation of a gain or loss on the sale of subsidiary stock based on the change in the Parent’s share of the carrying value of equity before and after the transaction. The resulting gain or loss may be recognized through income or alternatively as an increase in paid-in capital (in the case of a gain), net of tax. SAB No. 51 requires us to establish a policy as to the treatment and we must consistently apply this treatment to all sales of subsidiary stock. We have elected to recognize gains for all sales of subsidiary stock under SAB No. 51 as an increase to paid-in capital and consequently have calculated the cumulative gains for our three subsidiaries which have issued stock in order to record the effects in the December 31, 2006 financials statements. There were no issuances of subsidiary stock in the quarter ended March 31, 2007. 

Based upon the results of our evaluation described above, which was performed in connection with the restatement of our financial statements for the year ended December 31, 2006 and quarterly period ended March 31, 2007, our principal executive officer and principal financial officer determined that the incorrect treatment of our subsidiary stock sales referenced above was not detected in our financial reporting process for the quarterly period ended March 31, 2007 as a result of a material weakness in internal control over financial reporting related to the interpretation of SAB No. 51 in the preparation of the financial statements for the year ended December 31, 2006 and three months ended March 31, 2007. The material weakness that existed was that the controls to review and validate the proper accounting treatment did not operate effectively.

To remediate this material weakness, we intend to add additional review procedures, in addition to those already in place, increasing the knowledge base of our employees responsible for reviewing accounting principles, including enhanced background research and documentation related to the accounting principles and increasing the involvement of third-party advisors in the determination of the appropriate accounting treatment. We believe that the changes will remediate the material weakness described above subsequent to June 30, 2007.

PART II.  OTHER INFORMATION

Item 2.Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchase of Equity Securities

	Total Number of Shares Purchased		Average Price paid Per Share		Shares Purchased As Part of Publicly Announced Plans or Programs		Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
January 1-31, 2007	0		0		0
February 1-28, 2007	0		0		0
March 1-31, 2007		1,486,605	$	54.05		1,486,605
Total		1,486,605	$	54.05		1,486,605		See Note 1

Note 1: On January 30, 2007, the Company announced that its 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.

Item 6.Exhibits

 Exhibit No.Description

3.1	Amended and Restated Certificate of Incorporation (1)
3.2	Amended and Restated Bylaws(1)
31.1	Rule 13(a)-14(a)/15d-14(a) Certification.
31.2	Rule 13(a)-14(a)/15d-14(a) Certification.
32.1	Section 1350 Certification.
32.2	Section 1350 Certification.

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

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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.
	(Registrant)
Date: August 14, 2007	By:/s/ Matthew A. Jones
	Matthew A. Jones
	Chief Financial Officer
Date: August 14, 2007	By:/s/Nancy J. McGurk
	Nancy J. McGurk        Senior Vice President and Chief Accounting Officer

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