10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 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.)
Westpointe Corporate Center
1550 Coraopolis Heights Rd, 2nd FL 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 November 1, 2007 was 26.9 million shares.

ATLAS AMERICA, INC.

INDEX TO QUARTERLY REPORT ON FORM 10-Q

		Page
PART I	FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Balance Sheets - September 30, 2007 and December 31, 2006	3
	Consolidated Statements of Income for the Three Months and Nine Months Ended September 30, 2007 and 2006	4
	Consolidated Statement of Changes in Stockholders’ Equity for the Nine Months Ended September 30, 2007	5
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2007 and 2006	6
	Notes to Consolidated Financial Statements	7 - 29
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30- 41
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	42- 46
Item 4.	Controls and Procedures	47
PART II	OTHER INFORMATION
Item 6.	Exhibits	48
SIGNATURES		49

PART I. FINANCIAL INFORMATION

Item 1.Financial Statements

ATLAS AMERICA, INC.

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)

	September 30,			December 31,
	2007			2006
	(Unaudited)			(Audited)
ASSETS
Current assets:
Cash and cash equivalents	$	113,812		$	185,401
Accounts receivable		169,841			82,954
Current portion of derivative asset		40,385			33,150
Prepaid expenses		15,067			13,738
Deferred tax asset		10,434			7,934
Total current assets		349,539			323,177
Property and equipment, net		4,189,603			884,812
Other assets, net		74,036			42,501
Intangible assets, net		28,728			30,741
Goodwill, net		98,607			98,607
	$	4,740,513		$	1,379,838
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	77		$	109
Accounts payable		75,440			56,438
Liabilities associated with drilling contracts		63,090			86,765
Accrued producer liabilities		65,121			32,766
Accrued hedge liability		55,162			17,535
Accrued liabilities		66,715			49,035
Advances from affiliate		112			117
Total current liabilities		325,717			242,765
Long-term debt		1,921,968			324,042
Deferred tax liability		199,422			82,307
Long-term hedge liability		50,692			12,340
Other liabilities		51,197			40,656
Minority interest		1,766,011			406,387
Stockholders’ equity:
Preferred stock, $0.01 par value: 1,000,000 authorized shares		—			—
Common stock, $0.01 par value: 49,000,000 authorized shares		290			200
Additional paid-in capital		390,013			186,696
Treasury stock, at cost		(109,137	)		(29,349	)
ESOP loan receivable		(435	)		(490	)
Accumulated other comprehensive income (loss)		4,028			8,426
Retained earnings		140,747			105,858
Total stockholders’ equity		425,506			271,341
	$	4,740,513		$	1,379,838

See accompanying notes to consolidated financial statements

3

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per share data)

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
				(Restated)						(Restated)
REVENUES
Well construction and completion	$	103,324		$	50,641		$	240,841		$	135,329
Gas and oil production		63,265			21,888			109,840			66,696
Transmission, gathering and processing		246,195			111,019			480,594			326,886
Administration and oversight		5,364			2,990			13,347			8,487
Well services		4,845			3,346			12,721			9,498
Gain/ (loss) on mark-to-market derivatives		(11,467	)		733			(16,036	)		990
		411,526			190,617			841,307			547,886
COSTS AND EXPENSES
Well construction and completion		89,847			44,037			209,427			117,677
Gas and oil production		9,887			2,315			14,412			6,437
Transmission, gathering and processing		187,416			96,205			377,740			270,981
Well services		2,515			1,752			6,705			5,540
General and administrative		48,923			13,159			85,229			34,238
Depreciation, depletion and amortization		35,187			12,442			61,064			33,158
		373,775			169,910			754,577			468,031
OPERATING INCOME		37,751			20,707			86,730			79,855
OTHER INCOME (EXPENSE)
Interest expense		(37,480	)		(5,932	)		(53,681	)		(19,448	)
Minority interests		6,402			(2,021	)		14,992			(12,987	)
Other, net		3,526			3,518			6,425			4,643
		(27,552	)		(4,435	)		(32,264	)		(27,792	)
Income before income taxes		10,199			16,272			54,466			52,063
Provision for income taxes		(3,096	)		(6,302	)		(17,249	)		(20,632	)
Net income	$	7,103		$	9,970		$	37,217		$	31,431
Net income per common share–basic
Net income per common share–basic		.26			.34			1.36			1.06
Weighted average common shares outstanding-basic		26,853			29,396			27,345			29,759
Net income per common share–diluted
Net income per common share–diluted	$	.25		$	.33		$	1.31		$	1.03
Weighted average common shares outstanding–diluted		27,979			30,000			28,348			30,409

See accompanying notes to consolidated financial statements

4

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

NINE MONTHS ENDED SEPTEMBER 30, 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																				37,217			37,217
Dividends–common shares																				(2,238	)		(2,238	)
Other comprehensive income (loss)																	(4,398	)					(4,398	)
Issuance of common stock		56,736		—		1,113		13,942			661												1,774
Repurchase of common stock, at cost								(1,486,605	)		(80,449	)											(80,449	)
Three-for-two stock split		8,938,057		90																(90	)		—
Repayment of ESOP loan														55									55
Stock option compensation						1,308																	1,308
Gain on sale of subsidiary units						200,896																	200,896
Balance, September 30, 2007		29,003,212	$	290	$	390,013		(2,131,798	)	$	(109,137	)	$	(435	)	$	4,028		$	140,747		$	425,506

See accompanying notes to consolidated financial statements

5

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Nine Months Ended
	September 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	37,217		$	31,431
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation, depletion and amortization		61,064			33,158
Amortization of deferred finance costs		7,626			2,008
Non-cash loss (gain) on derivative value		19,501			(990	)
Non-cash compensation on long-term incentive plans		43,506			6,312
Minority interests		(14,992	)		12,987
Distributions paid to minority interests		(32,853	)		(27,940	)
Gain (loss) on asset dispositions		119			(2,738	)
Deferred income taxes		(4,145	)		(37,532	)
Changes in operating assets and liabilities (net of acquisition):
(Increase) decrease in accounts receivable and prepaid expenses		(53,273	)		1,455
Increase in accounts payable and accrued liabilities		30,974			29,558
(Decrease) increase in accounts payable/receivable from affiliates		(4	)		265
Changes in other operating assets and liabilities		645			(4,129	)
Net cash provided by operating activities		95,385			43,845
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in Lightfoot Capital Partners, L.P		(10,379	)		—
Business acquisitions, net of cash acquired		(3,141,680	)		(30,000	)
Capital expenditures		(219,088	)		(115,819	)
Proceeds from sale of assets		1,071			7,602
Decrease (increase) in other assets		(813	)		174
Net cash used in investing activities		(3,370,889	)		(138,043	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings		1,931,509			109,750
Principal payments on debt		(345,922	)		(144,805	)
Issuance of Atlas Pipeline Partners, L.P. common and preferred units		946,555			59,610
Net proceeds from Atlas Energy equity offering		597,500			—
Net proceeds from Atlas Pipeline Holdings equity offering		167,033			74,492
Treasury shares purchased		(80,449	)		(29,856	)
Issuance of Atlas Pipeline Senior notes		—			36,610
Dividends paid		(2,238	)		—
(Increase) in deferred financing costs and other		(10,073	)		(2,066	)
Net cash provided by financing activities		3,203,915			103,735
(Decrease) increase in cash and cash equivalents		(71,589	)		9,537
Cash and cash equivalents at beginning of period		185,401			55,155
Cash and cash equivalents at end of period	$	113,812		$	64,692

See accompanying notes to consolidated financial statements

6

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2007

(Unaudited)

NOTE 1 - BASIS OF PRESENTATION

Company Overview

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. (“APL or 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. In July 2007, AHD sold 6,250,000 common units through private placement and used the net proceeds from the sale to purchase 3,835,227 units of APL. As a result, AHD, through its ownership of Atlas Pipeline GP, owns a 2% general partner interest and 5,476,253 common units constituting a 13.6% limited partner interest for a total partnership interest of 15.6% in Atlas Pipeline. Because AHD controls the decisions and operations of APL, 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. Atlas Energy Management, Inc., a wholly owned subsidiary of the Company, is the managing member of Atlas Energy and owns 1,238,986 Class A units, or a 2% interest which it manages and effectively controls Atlas Energy. On June 29, 2007, Atlas Energy completed a private placement of 7,298,181 Class B common units and 16,702,828 Class D units to a group of institutional investors to fund the acquisition of DTE Gas and Oil Company (See Note 4). After completion of the offering and private placement, the Company owns approximately 49.4% of Atlas Energy.

The consolidated financial statements and the information and tables contained in the notes to the consolidated financial statements as of September 30, 2007 and for the three months and nine months ended September 30, 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 and nine months ended September 30, 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 and nine months ended September 30, 2006 to conform to the presentation as of and for the three months and nine months ended September 30, 2007.

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 September 30, 2007 and for the three months and nine months ended September 30, 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.

7

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 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 September 30, 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 September 30, 2007 and December 31, 2006 of $123.0 million and $40.2 million which are included in accounts receivable on its consolidated balance sheets.

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 $29.8 million income tax valuation allowance recorded in July 2006 related to the gain on sale of AHD’s common units.

The following table reconciles net income and earnings per share as previously reported to restated amounts for the three months and nine months ended September 30, 2006 (in thousands, except per share data):

	Three Months Ended September 30, 2006
	Previously
	Reported			Adjustment		Restated
Net income (loss)	$	(19,876	)	$	29,846	$	9,970
Net income per common share - basic	$	(0.68	)	$	1.02	$	0.34
Net income per common share - diluted	$	(0.66	)	$	0.99	$	0.33

	Nine Months Ended September 30, 2006
	Previously
	Reported		Adjustment		Restated
Net income	$	1,585	$	29,846	$	31,431
Net income per common share - basic	$	0.05	$	1.01	$	1.06
Net income per common share - diluted	$	0.05	$	0.98	$	1.03

Recently Issued Financial Accounting Standards

In April 2007, the Financial Accounting Standards Board (“FASB”) issued FASB interpretation No. 39-1, Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts, (“FIN 39-1”). FIN 39-1 amends FIN 39, which allows an entity to offset fair value amounts for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. FIN 39-1 is effective for fiscal years beginning after November 15, 2007. The Company does not expect the adoption of FIN 39-1 to have an impact on its financial position or results of operations.

In February 2007, the 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 December 2006, the FASB issued FASB Staff Position (FSP) EITF 00-19-2, Accounting for Registration Payment Arrangements. FSP EITF 00-19-2 requires an issuer of financial instruments, such as debt, convertible debt, equity shares or warrants, to account for a contingent obligation to transfer consideration under a registration payment arrangement in accordance with Statement 5, Accounting for Contingencies, and FASB Interpretation 14, Reasonable Estimation of the Amount of a Loss. That accounting applies regardless of whether the registration payment arrangement is a provision in a financial instrument or a separate agreement. The FSP requires issuers to make certain disclosures for each registration payment arrangement or group of similar arrangements. The FSP is effective immediately for registration payment arrangements and financial instruments subject to those arrangements that are entered into or modified subsequent to December 21, 2006, the date FSP EITF 00-19-2 was issued. The Company applied the consensus in FSP EITF 00-19-2 effective January 1, 2007. The Company reviewed the penalty terms in the registration rights agreement related to AHD's, Atlas Pipline's, and Atlas Energy’s respective private placements entered into during the nine months ended September 30, 2007, pursuant to the guidance in the FSP, and determined that the probability of payment is remote under Statement 5 based upon the Company’s status of current related filings. As a result, the application of FSP EITF 00-19-2 did not have an effect on the Company’s 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.

8

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

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

The Company adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, (“FIN 48”), on January 1, 2007, and FASB Interpretation No. 48-1, Definition of Settlement in FASB Interpretation No. 48, (“FIN 48-1”). 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. FIN 48-1 amends FIN 48 to provide guidance on how an enterprise should determine whether a tax provision is effectively settled for the purpose of recognizing previously unrecognized tax benefits. As a result of the implementation of FIN 48 and FIN 48-1, the Company determined that it had no liability for unrecognized income tax benefits, upon adoption and through September 30, 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.

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				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Weighted average common shares outstanding-basic(1)		26,853		29,396		27,345		29,759
Dilutive effect of stock option and award plan(1)		1,126		604		1,003		650
Weighted average common shares-diluted(1)		27,979		30,000		28,348		30,409

⁽¹⁾ The shares for the three months and nine months ended September 30, 2006 have been restated to reflect the three-for-two-stock split on May 25, 2007.

9

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

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 holding gains and losses on hedging contracts and post-retirement plan liabilities. The following table reconciles net income to comprehensive income (loss) (in thousands):

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2007			2006		2007			2006
Net income	$	7,103		$	9,970	$	37,217		$	31,431
Other comprehensive income:
Unrealized holding gain (loss) on hedging contracts, net of tax of $(4,948), ($5,817), $2,377, and ($8,088)		8,424			9,873		(3,184	)		13,515
Less: reclassification adjustment for (gains) losses realized in net income, net of tax of $687, ($324), $786, and ($215)		(1,170	)		553		(1,339	)		251
Plus: amortization of additional post-retirement liability recorded upon adoption of SFAS 158, net of taxes of ($27) and ($80)		41			—		125			—
		7,295			10,426		(4,398	)		13,766
Comprehensive income	$	14,398		$	20,396	$	32,819		$	45,197

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

	September 30, 2007			December 31, 2006
Unrealized holding gain on hedging contracts	$	4,319		$	8,842
Additional post-retirement liability		(291	)		(416	)
	$	4,028		$	8,426

NOTE 4 - ACQUISITIONS

Anadarko-Chaney Dell and Midkiff/Benedum

On July 27, 2007, APL acquired control of Anadarko’s 100% interest in the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and its 72.8% undivided joint venture interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (the “Assets”). The Chaney Dell System includes 3,470 miles of gathering pipeline and three processing plants, while the Midkiff/Benedum System includes 2,500 miles of gathering pipeline and two processing plants. The transaction was effected by the formation of two joint venture companies which own the respective systems, to which APL contributed $1.9 billion and Anadarko contributed the Assets.

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

10

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

Note 4 - ACQUISITIONS (Continued)

APL funded the purchase price in part from the private placement of 25.6 million common limited partner units at a negotiated purchase price of $44.00 per unit, generating gross proceeds of $1.125 billion. AHD purchased 3.8 million of the 25.6 million common limited partner units issued by Atlas Pipeline for $168.8 million and funded this through the privateplacement of 6.25 million of its common units to investors at a negotiated price of $27.00 per unit, yielding gross proceeds of $168.8 million (or net proceeds of $167.0 million, after underwriting fees and other transaction costs). Atlas Pipeline also received a capital contribution from AHD of $23.1 million in order for AHD to maintain its 2.0% general partner interest in Atlas Pipeline. AHD funded this capital contribution and the underwriting fees and other transaction costs related to its private placement of common units through borrowings under its revolving credit facility of $25.0 million (see Note 8). AHD, which holds all of the incentive distribution rights as General Partner, has also agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter (see Note 14). APL funded the remaining purchase price from an $830.0 million senior secured term loan which matures in July 2014 and a new $300.0 million senior secured revolving credit facility that matures in July 2013 (see Note 8). APL’s acquisition was accounted for using the purchase method of accounting under SFAS No. 141, “Business Combinations” (“SFAS No. 141”). The following table presents the preliminary purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed in the acquisition, based on their fair values at the date of the acquisition (in thousands):

Prepaid expenses and other	$	1,254
Property, plant and equipment		1,879,581
Total assets acquired		1,880,835
Accounts payable and accrued liabilities		(2,209	)
Net cash paid for acquisition	$	1,878,626

Due to the recent date of the acquisition, the purchase price allocation for the acquisition is based upon preliminary data that remains subject to adjustment and could further change significantly as APL continues to evaluate this allocation. The results of Chaney Dell’s and Midkiff/Benedum’s operations are included within the Partnership’s consolidated financial statements from the date of acquisition.

DTE Gas and Oil Company (DGO)

On June 29, 2007, Atlas Energy acquired all of the outstanding equity interests of DTE Gas & Oil Company (“DGO”) from DTE Energy Company (NYSE:DTE) and MCN Energy Enterprises for $1.268 billion, including adjustments for working capital of $10.4 million and current year capital expenditures of $19.0 million. Assets acquired include interests in approximately 2,150 natural gas wells with estimated proved reserves of approximately 613.7 billion cubic feet of natural gas equivalents, located in the northern lower peninsula of Michigan, 228,000 developed acres and 66,000 undeveloped acres. Subsequent to the acquisition of DGO, Atlas Energy changed its name to Atlas Gas & Oil Company (“AGO”). With this acquisition, the Company increased its natural gas and production as well as entered into a new region that offers additional opportunities to expand its operations.

To fund the acquisition, Atlas Energy borrowed $713.9 million on its new credit facility (See Note 8) and completed a private placement of 7,298,181 Class B common units and 16,702,828 Class D units to a group of institutional investors at a weighted average price of $25.00 per unit for net proceeds of $597.5 million. Proceeds of $52.5 million were used to pay the outstanding balance of Atlas Energy’s credit facility with Wachovia Bank.

11

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

Note 4 - ACQUISITIONS (Continued)

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

Accounts receivable	$	33,412
Prepaid expenses		515
Leaseholds, wells and related equipment		1,269,839
Total assets acquired		1,303,766
Accounts payable and accrued liabilities		(21,869	)
Asset retirement obligations		(13,920	)
		(35,789	)
Net assets acquired	$	1,267,977

Due to its recent date of acquisition, the purchase price allocation is based on preliminary data that is subject to adjustment and could change significantly as the Company continues to evaluate this allocation. DGO’s operations are included within the Company’s consolidated financial statements beginning June 29, 2007.

The following data presents pro forma revenues, net income and basic and diluted net income per share for the Company as if the AGO and Anadarko acquisitions and related debt (see Note 8) and equity financing had occurred on January 1, 2006. The Company has prepared these pro forma financial results for comparative purposes only which may not be indicative of the results that would have occurred if the Company had completed the acquisition at January 1, 2006, or the results that will be attained in the future (in thousands, except per share amounts):

	Nine Months Ended
	September 30, 2007
	As		Pro Forma			Pro
	Reported		Adjustments			Forma
Revenues	$	841,307	$	337,120		$	1,178,427
Net income	$	37,217	$	(20,788	)	$	16,429
Net income per common unit outstanding–basic	$	1.36	$	(0.76	)	$	.60
Weighted average common units–outstanding basic		27,345		—			27,345
Net income per common share–diluted	$	1.31	$	(0.71	)	$	.60
Weighted average common shares–outstanding diluted		28,348		—			28,348

	Three Months Ended						Nine Months Ended
	September 30, 2006						September 30, 2006
	As		Pro Forma		Pro		As		Pro Forma		Pro
	Reported		Adjustments		Forma		Reported		Adjustments		Forma
Revenues	$	190,617	$	273,115	$	463,732	$	547,886	$	727,374	$	1,275,260
Net income		9,970		18,066		28,036		31,431		34,189		65,620
Net income per common unit outstanding–basic	$	.34	$	.61	$	.95	$	1.06	$	1.15	$	2.21
Weighted average common units–outstanding basic		29,396		—		29,396		29,759		—		29,759
Net income per common share–diluted	$	.33	$	.60	$	.93	$	1.03	$	1.12	$	2.16
Weighted average common shares–outstanding diluted		30,000		—		30,000		30,409		—		30,409

Pro forma adjustments to revenues include substantial losses on derivatives realized by AGO. All such derivatives were canceled upon the acquisition of AGO by Atlas Energy and Atlas Energy entered into new derivative contracts covering future AGO production.

12

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

NOTE 5 - 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):

	September 30,			December 31,
	2007			2006
Mineral interests:
Proved properties	$	12,870		$	1,290
Unproved properties		1,002			1,002
Leaseholds, wells and related equipment		1,729,282			348,592
Pipelines, processing and compression facilities		2,289,411			611,212
Rights-of-way		313,165			30,401
Land, building and improvements		8,868			8,451
Support equipment		9,210			5,604
Other		14,178			9,902
		4,377,986			1,016,454
Accumulated depreciation, depletion and amortization:
Oil and gas properties and pipelines		(181,540	)		(125,550	)
Other		(6,843	)		(6,092	)
		(188,383	)		(131,642	)
	$	4,189,603		$	884,812

On July 27, 2007, Atlas Pipeline acquired control of the Chaney Dell and Midkiff/Benedum systems for approximately $1.88 billion. On June 29, 2007, Atlas Energy acquired all of the outstanding equity interests in DTE Gas & Oil Company for approximately $1.268 billion, including acquisition costs of $11.0 million (See Note 4). Due to the recent date of the acquisitions, the purchase price allocations are based upon estimated values and could change significantly as Atlas Pipeline and Atlas Energy continue to evaluate the preliminary allocations. At September 30, 2007, Atlas Pipeline recorded the portion of the purchase price of $1.88 billion allocable to pipelines, processing and compression facilities within the above table. Atlas Energy recorded the portion of the purchase price of $1.27 billion allocable to leaseholds, wells and related equipment within the above table.

NOTE 6 - OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL

Other Assets

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

	September 30,		December 31,
	2007		2006
Deferred finance costs, net of accumulated amortization of $2,434 and $6,862	$	28,277	$	13,040
Investments		12,110		1,553
Security deposits		2,046		1,538
Long-term hedge receivable from Partnerships		6,731		2,131
Unrealized hedge gain–long term		23,854		24,148
Other		1,018		91
	$	74,036	$	42,501

13

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

NOTE 6 - OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL - (Continued)

Deferred finance costs are recorded at cost and are amortized according to the terms of the related loan agreements which range from five to ten years. Investments include the Company’s $10.4 million investment in Lightfoot Capital Partners, L.P. (“Lightfoot”) (See Note 11). Long-term hedge receivable from Partnerships represents the portion of the long-term unrealized loss on contracts that has been allocated to affiliated energy partnerships.

Intangible Assets

Customer contracts and relationships. At September 30, 2007, Atlas Pipeline had $24.1 million of intangible assets, net of accumulated amortization of $5.9 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. The customer contracts and relationship intangible assets, which have estimated lives of eight and twenty years, respectively, are being amortized on a straight-line basis. Amortization expense on intangible assets was $600,000 and $(900,000) for the three months ended September 30, 2007 and 2006 respectively. Amortization expense was $1.8 million and $1.4 million for the nine months ended September 30, 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 nine months ended September 30, 2007 and 2006 was $614,000 and $659,000 respectively.

Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending September 30 is as follows: 2008 - $3.2 million; 2009 - $3.2 million; 2010 - $3.1 million; 2011 - $3.1 million and 2012 - $2.7 million.

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

	September 30,					December 31,
	2007					2006
			Accumulated					Accumulated
	Cost		Amortization			Cost		Amortization
Customer contracts and relationships	$	30,070	$	(5,939	)	$	29,650	$	(4,120	)
Partnership management and operating contracts		14,343		(9,746	)		14,343		(9,132	)
Intangible assets, net	$	44,413	$	(15,685	)	$	43,993	$	(13,252	)

Goodwill

The Company applies the provisions of Statement of Financial Accounting Standards, (“SFAS”), No. 142, Goodwill and Other Intangible Assets”, 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 September 30, 2007 and December 31, 2006 the Company had goodwill of $98.6 million, net of accumulated amortization of $4.5 million.

14

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

NOTE 7 - 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, (“FIN 47”). 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						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Asset retirement obligations, beginning of period	$	41,792		$	19,760		$	26,726		$	18,499
Liabilities acquired (See Note 4)		505			—			13,920			—
Liabilities incurred		997			490			2,024			1,616
Liabilities settled		(9	)		(67	)		(30	)		(180	)
Accretion expense		673			124			1,318			372
Asset retirement obligations, end of period	$	43,958		$	20,307		$	43,958		$	20,307

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 8 - DEBT

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

	September 30,		December 31,
	2007		2006
Senior notes–Atlas Pipeline	$	294,419	$	285,977
Term credit facility–Atlas Pipeline		830,000		—
Revolving credit facility–Atlas Pipeline		33,500		38,000
Revolving credit facility–Atlas Energy		739,000		—
Revolving credit facility–Atlas Pipeline Holdings		25,000		—
Other debt		126		174
		1,922,045		324,151
Less current maturities		77		109
	$	1,921,968	$	324,042

Atlas Pipeline Credit Facility. At September 30, 2007, Atlas Pipeline had a new credit facility, comprised of an $830.0 senior secured term loan (“term loan”) which matures in July 2014 and a $300.0 million senior secured revolving credit facility which matures in July 2013. The Partnership borrowed $830.0 million under the term loan and $15.0 million under the revolving credit facility to finance a portion of the Anadarko acquisition and to repay indebtedness under its prior revolving credit facility. 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 September 30, 2007 was 8.0%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $7.1 million was outstanding at September 30, 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, other than joint venture companies. 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 September 30, 2007.

15

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

NOTE 8 - DEBT - (Continued)

Atlas Pipeline Senior Notes. At September 30, 2007, Atlas Pipeline has $293.5 million of 10-year, 8.125% senior unsecured notes (“Senior Notes”) outstanding, net of unamortized premium received of $900,000. 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 and unpaid interest to the date of redemption. The Senior Notes are also redeemable at any time prior to December 15, 2010 at stated redemption prices, together with accrued and 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 if Atlas Pipeline does not reinvest the net proceeds 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.

On April 18, 2007, Atlas Pipeline issued to Sunlight Capital, $8.5 million of its 8.125% Senior Notes due April 18, 2015 (the “Notes”), in consideration of Sunlight Capital’s consent to the amendment of Atlas Pipeline’s preferred unit agreement. Atlas Pipeline filed, pursuant to the Registration Rights Agreement, an exchange offer registration statement to exchange the Notes for publicly tradable notes. The registration statement was declared effective by the SEC on July 17, 2007. Atlas Pipeline must complete the exchange offer by September 15, 2007. If Atlas Pipeline fails to meet this deadline, the Notes will accrue additional interest of 1% per annum for each 90-day period Atlas Pipeline is in default, up to a maximum amount of 3% per annum.

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 September 30, 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 ($25.0 million outstanding borrowings at September 30, 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 September 30, 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. Upon the closing of its acquisition of DTE Gas & Oil Company (See Note 4), Atlas Energy replaced its Wachovia Bank Credit facility with a new 5-year, $850.0 million credit facility with JP Morgan Chase Bank, N.A. (“JP Morgan”) as administrative agent, Wachovia Bank, National Association as syndication agent, and other lenders. The revolving credit facility has a current borrowing base of $850.0 million which will be redetermined semi-annually on April 1 and October 1 subject to changes in Atlas Energy’s oil and gas reserves. The initial borrowing base is also scheduled to be reduced to $735.0 million less 25% of the amount of any issuance of equity or debt securities by Atlas Energy at the earlier of June 29, 2008 or the issuance by Atlas Energy of equity or debt securities of at least $200.0 million. Up to $50.0 million of the facility may be in the form of standby letters of credit. The facility is secured by 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 September 30, 2007, the weighted average interest rate on outstanding borrowings was 7.5 %.

16

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

NOTE 8 - DEBT - (Continued)

The base rate for any day equals the higher of the federal funds rate plus 0.50% or the JP Morgan prime rate. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for Eurocurrency liabilities. The applicable margin ranges from 0.0% to 1.25% for base rate loans and 1.00% to 2.25% for LIBOR loans.

The JP Morgan credit facility requires Atlas Energy to maintain specified financial ratios of current assets to current liabilities 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 September 30, 2007. The facility terminates in June 2012, when all outstanding borrowings must be repaid. At September 30, 2007 and December 31, 2006, $739 million and $0.0, respectively, were outstanding under this facility and the previous Wachovia Bank credit facility. In addition, letters of credit of $ 1.1 million and $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 September 30 are as follows (in thousands):

2008	$	77
2009		26
2010		25,011
2011		12
2012 and thereafter		1,896,919
	$	1,922,045

NOTE 9 - DERIVATIVE INSTRUMENTS

The Company, through its subsidiaries, enters into financial swap and option instruments to hedge its exposure to changes in commodity prices which are classified as cash flow hedges in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activity (“SFAS No. 133”).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, the Company receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. 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.

The Company 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 futures and options contracts to the forecasted transactions. The Company 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 New York Mercantile Exchange. Such gains and losses are charged or credited to accumulated other comprehensive income (loss) and recognized as a component of 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, the Company will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings.

17

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

NOTE 9 - DERIVATIVE INSTRUMENTS - (Continued)

On May 18, 2007, Atlas Energy signed a definitive agreement to acquire AGO (see Note 4). In connection with the financing of this transaction, Atlas Energy agreed as a condition precedent to closing that it would hedge 80% of its projected natural gas volumes for no less than three years from the closing date of the transaction. During May 2007, Atlas Energy entered into derivative instruments to hedge 80% of the projected production of the assets to be acquired as required under the financing agreement. The production volume of the assets to be acquired was not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition of the assets had not yet been completed. Accordingly, Atlas Energy recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within revenues in the Company’s consolidated statements of income. Atlas Energy recognized non-cash income of $26.3 million related to the change in value of these derivatives from May 22, 2007 to June 28, 2007, which is shown as “Gain on mark-to-market derivatives” in the Combined and Consolidated Statements of Income for the nine months ended September 30, 2007. Upon closing of the acquisition on June 29, 2007, the production volume of the assets acquired was considered “probable forecasted production” under SFAS No. 133 and Atlas Energy evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133.

At September 30, 2007, Atlas Energy had 384 open natural futures contracts related to natural gas sales covering 147.5 million MMBtus of natural gas maturing through September 30, 2012 at a combined average settlement price of $8.04 per MMBtu. At September 30, 2007 and December 31, 2006, Atlas Energy reflected net derivative assets of $50.4 million and $47.5 million, respectively. In addition, Atlas Energy recognized gains on settled contracts covering natural gas production of $4.9 million and $2.0 million for the three months ended September 30, 2007 and 2006, and $9.6 million and $4.9 million for nine months ended September 30, 2007 and 2006, respectively. There were no gains or losses recognized during the three months and nine months ended September 30, 2006 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

On June 3, 2007, Atlas Pipeline signed definitive agreements to acquire control of certain natural gas gathering systems and processing plants located in Oklahoma and Texas (see Note 4). In connection with the financing of this transaction, Atlas Pipeline agreed as a condition precedent to closing that it would hedge 80% of its projected natural gas, NGL and condensate production volume for no less than three years from the closing date of the transaction. During June 2007, Atlas Pipeline entered into derivative instruments to hedge 80% of the projected production of the assets to be acquired as required under the financing agreements. The production volume of the assets to be acquired was not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition of the assets had not yet been completed. Accordingly, Atlas Pipeline recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within revenues in the Company’s consolidated statements of income. APL recognized a non-cash loss of $19.8 million related to the change in value of these derivatives for the three and nine months ended September 30, 2007. Upon closing of the acquisition in July 2007, the production volume of the assets acquired was considered “probable forecasted production” under SFAS No. 133 and Atlas Pipeline evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133.

At September 30, 2007 and December 31, 2006, Atlas Pipeline reflected net derivative liabilities of $92.0 million and $20.1 million, respectively. Atlas Pipeline recognized losses of $12.9 million and $4.9 million for the three months ended September 30, 2007 and 2006, respectively, and losses of $23.5 million and $10.5 million for the nine months ended September 30, 2007 and 2006, respectively, within natural gas and liquids revenue in its consolidated statements of income related to the settlement of qualifying hedge instruments. Atlas Pipeline recognized a loss of $8.4 million and a gain of $3.7 million within “Other, net” on the Company’s consolidated statements of income related to the change in market value of non-qualifying derivatives and the ineffective portion of qualifying derivatives, respectively, for the three months ended September 30, 2007. Atlas Pipeline recognized a loss of $39.3 million and a gain of $4.6 million within “Other, net” in the Company’s consolidated statements of income related to the change in market value of non-qualifying derivatives and the ineffective portion of qualifying derivatives, respectively, for the nine months ended September 30, 2007. Atlas Pipeline recognized losses of $3.0 million for the three and nine months ended September 30, 2007, within “Other, net” in its consolidated statements of income related to loss from cash settlement of non-qualifying derivatives. There were no gains or losses recognized for the three months or nine months ended September 30, 2006 related to cash settlements of non-qualifying derivatives..

18

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

NOTE 9 - DERIVATIVE INSTRUMENTS - (Continued)

At September 30, 2007 and December 31, 2006, the Company reflected a net hedging liability and asset on its balance sheets of $41.6 million and $27.3 million, respectively, when combining the above hedges of Atlas Energy and Atlas Pipeline. Of the $4.0 million net gain in accumulated other comprehensive income at September 30, 2007, the Company will reclassify $2.8 million of gain to its consolidated statements of income over the next twelve month period as these contracts expire, and $1.2 million of gain 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 September 30, 2007, the Company had the following financial hedges in place:

ATLAS ENERGY RESOURCES HEDGES

Natural Gas Fixed Price Swaps

Twelve Month
Period Ending			Average		Fair Value
September 30,	Volumes		Fixed Price		Asset/(Liability) (3)
	(MMBtu) (1)		(per MMBtu)		(in thousands)
2008		35,470,000	$	8.15	$	37,289
2009		33,530,000	$	8.32		11,310
2010		25,430,000	$	8.02		517
2011		18,950,000	$	7.75		( 790	)
2012		11,150,000	$	7.62		821
2013		2,250,000	$	7.67		346
					$	49,493

Natural Gas Costless Collars

Twelve Month
Period Ending					Average		Fair Value
September 30,	Option Type		Volumes		Floor and Cap		Asset/(Liability) (3)
			(MMBtu) (1)		(per MMBtu)		(in thousands)
2008		Puts purchased		450,000	$	7.50	$	314
2008		Calls sold		450,000	$	8.60		—
2008		Puts purchased		1,170,000	$	7.50		325
2008		Calls sold		1,170,000	$	9.40		—
2009		Puts purchased		390,000	$	7.50		—
2009		Calls sold		390,000	$	9.40		(32	)
2010		Puts purchased		2,160,000	$	7.75		144
2010		Calls sold		2,160,000	$	8.75		—
2011		Puts purchased		720,000	$	7.75		(4	)
2011		Calls sold		720,000	$	8.75		—
2011		Puts purchased		5,400,000	$	7.50		240
2011		Calls sold		5,400,000	$	8.45		—
2012		Puts purchased		1,800,000	$	7.50		—
2012		Calls sold		1,800,000	$	8.45		(25	)
2012		Puts purchased		6,480,000	$	7.50		—
2012		Calls sold		6,480,000	$	8.45		(24	)
2013		Puts purchased		2,160,000	$	7.00		—
2013		Calls sold		2,160,000	$	8.37		(19	)
							$	919
	Total Atlas Energy Resources net asset						$	50,412

19

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

NOTE 9 - DERIVATIVE INSTRUMENTS - (Continued)

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		42,651,000	$	0.893	$	(10,739	)
2008		61,362,000		0.706		(13,556	)
2009		8,568,000		0.746		(1,752	)
					$	(26,047	)

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		1,449,000	$	8.197	$	1,736
2008		5,484,000	$	8.795		4,608
2009		5,724,000	$	8.611		1,958
2010		2,820,000	$	8.635		1,132
					$	9,434

Natural Gas Basis Swaps (Sales)

Production
Period Ended			Average			Fair Value
December 31,	Volumes		Fixed Price			Asset/(Liability) (3)
	(MMBtu) (1)		(per MMBtu)			(in thousands)
2007		1,449,000	$	(0.729	)	$	135
2008		5,484,000	$	(0.727	)		388
2009		5,724,000	$	(0.513	)		550
2010		2,820,000	$	(0.572	)		435
						$	1,508

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		3,909,000	$	8.633	(4)	$	(6,819	)
2008		16,260,000	$	8.923	(5)		(16,293	)
2009		15,564,000	$	8.680			(6,402	)
2010		7,200,000	$	8.635			(2,891	)
						$	(32,405	)

20

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

NOTE 9 - DERIVATIVE INSTRUMENTS - (Continued)

Natural Gas Basis (Purchase)

Production
Period Ended			Average			Fair Value
December 31,	Volumes		Fixed Price			Liability (3)
	(MMBtu) (1)		(per MMBtu)			(in thousands)
2007		3,909,000	$	(1.048	)	$	161
2008		15,276,000	$	(1.186	)		(1,820	)
2009		14,820,000	$	(0.686	)		(5,485	)
2010		7,200,000	$	(0.560	)		(2,930	)
						$	(10,074	)

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		17,600	$	56.477	$	(427	)
2008		65,400	$	59.424		(1,133	)
2009		33,000	$	62.700		(362	)
					$	(1,922	)

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		189,300	$	60.000	$	(39	)
2007		Calls sold		189,300	$	75.363		(998	)
2008		Puts purchased		691,800	$	60.000		675
2008		Calls sold		691,800	$	78.004		(3,266	)
2009		Puts purchased		738,000	$	60.000		2,060
2009		Calls sold		738,000	$	80.622		(3,038	)
2010		Puts purchased		402,000	$	60.000		1,308
2010		Calls sold		402,000	$	79.341		(1,804	)
2011		Puts purchased		30,000	$	60.000		124
2011		Calls sold		30,000	$	74.500		(193	)
2012		Puts purchased		30,000	$	60.000		138
2012		Calls sold		30,000	$	73.900		(211	)
							$	(5,244	)

21

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

NOTE 9 - DERIVATIVE INSTRUMENTS - (Continued)

Crude Oil Sales Options (associated with NGL volumes)

Production
Period Ended			Associated NGL		Crude		Average crude		Fair Value
December 31,	Option Type		Volumes		Volumes		Strike Price		Asset/(Liability) (3)
			(gallons)		(barrels)		(per barrel)		(in thousands)
2007		Puts purchased		25,789,680		390,000	$	60.00	$	58
2007		Calls sold		25,789,680		390,000	$	75.15		(2,513	)
2008		Puts purchased		249,257,484		3,744,600	$	60.00		5,119
2008		Calls sold		249,257,484		3,744,600	$	79.38		(15,961	)
2009		Puts purchased		324,233,280		4,752,000	$	60.00		13,292
2009		Calls sold		324,233,280		4,752,000	$	78.68		(22,694	)
2010		Puts purchased		169,282,890		2,413,500	$	60.00		8,064
2010		Calls sold		169,282,890		2,413,500	$	77.28		(12,643	)
									$	(27,278	)
	Total Atlas Pipeline net liability								$	(92,028	)
	Total Atlas America net liability								$	(41,616	)

(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 1,200,000 MMBtu of natural gas at an average price of $17.00 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.

22

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

NOTE 10 - OPERATING SEGMENT INFORMATION

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Gas and oil production
Revenues (a)	$	63,265		$	21,888		$	136,097		$	66,696
Costs and expenses		(9,887	)		(2,315	)		(14,412	)		(6,437	)
Segment profit	$	53,378		$	19,573		$	121,685		$	60,259
Well construction and completion
Revenues (a)	$	103,324		$	50,641		$	240,841		$	135,329
Costs and expenses		(89,847	)		(44,037	)		(209,427	)		(117,677	)
Segment profit	$	13,477		$	6,604		$	31,414		$	17,652
Atlas Pipeline
Revenues	$	231,257		$	108,434		$	427,792		$	319,983
Revenues - affiliates		8,610			6,974			24,821			22,719
Costs and expenses		(187,389	)		(96,180	)		(377,668	)		(270,822	)
Segment profit	$	52,478		$	19,228		$	74,945		$	71,880
Reconciliation of segment profit to net income before taxes
Segment profit
Gas and oil production	$	53,378		$	19,573		$	121,685		$	60,259
Well construction and completion		13,477			6,604			31,414			17,652
Atlas Pipeline		52,478			19,228			74,945			71,880
Total segment profit		119,333			45,405			228,044			149,791
General and administrative expenses		(48,923	)		(13,159	)		(85,229	)		(34,238	)
Depreciation, depletion and amortization		(35,187	)		(12,442	)		(61,064	)		(33,158	)
Other income (expense) - net (b)		(25,024	)		(3,532	)		(27,285	)		(30,332	)
Net income before taxes	$	10,199		$	16,272		$	54,466		$	52,063
Capital expenditures
Gas and oil production							$	1,391,888		$	52,533
Well construction and completion								-			-
Atlas Pipeline								1,973,241			91,743
Corporate and other								3,380			1,543
							$	3,368,509		$	145,819

	September 30, 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	$	1,782,990	$	377,807
Well construction and completion		9,966		8,335
Atlas Pipeline		2,807,966		787,128
Corporate and other		139,591		206,568
	$	4,740,513	$	1,379,838

(a) Includes gain (loss) on mark-to-market derivatives.

(b) Includes revenue and expense from well services, transportation and administration and oversight of $2.5 million and $903,000 in the three months ended September 30, 2007 and 2006, respectively, and $5.0 million and ($2.5) million in the nine months ended September 30, 2007 and 2006, respectively, that do not meet the quantitative threshold for reporting segment information.

23

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

NOTE 10 - OPERATING SEGMENT INFORMATION (Continued)

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.

NOTE 11 - 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 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 paid $300,000 in May 2007, upgraded certain gathering systems and capped certain transportation expenses chargeable to the land owners.

Atlas Gas & Oil Company LLC, as successor to DTE Gas & Oil Company, is one of four defendants in a personal injury action filed in Antrim County Circuit Court in northern Michigan in August, 2006.  The complaint alleges that plaintiff suffered serious personal injuries as a result of the defendants’ negligence. A tentative settlement of this lawsuit was reached, the terms of which are subject to final approval by the court. Pursuant to the settlement terms, the Company paid $125,000 to the plaintiff in October 2007.

As of September 30, 2007, Atlas Pipeline is committed to expend approximately $91.3 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

The Company has begun construction of a new $2.9 million field operations building and yard in Fayette County, Pennsylvania of which $1.7 million remains committed at September 30, 2007.

The Company, through its subsidiary, Atlas Lightfoot, LLC, has committed to invest $20 million ($10.4 million invested at September 30, 2007) in Lightfoot Capital Partners, LP ("Lightfoot") and will own approximately 18% of Lightfoot Capital Partners GP, LLC. The Company uses the equity method to account for these investments and 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 been under-utilized by the MLP structure.

24

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

NOTE 12 — 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 $34.6 million and $4.5 for the three months ended September 30, 2007 and 2006, respectively, and $43.5 million and $6.3 million for the nine months ended September 30, 2007 and 2006, respectively. At September 30, 2007, the Company had unamortized compensation expense of $31.4 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.

Atlas America Long Term Incentive Plan. The Company adopted a Stock Incentive Plan (the “Plan”) in 2004 which authorized the granting of up to 3.0 million shares of the Company’s common stock. The Company awarded 20,000 options and 2,147 grants in the nine months ended September 30, 2007. During this period, the Company received $917,000 from the exercise of 54,034 options. There were 1,810,254 options and 14,076 restricted and deferred shares outstanding as of September 30, 2007.

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

Pursuant to the plan, options that expire 10 years from the date of grant and vest over a four year service period have been awarded. ATN uses the Black-Scholes option pricing model to estimate the weighted average fair value per option granted with the following assumptions:

Date Granted	Options Granted		Expected Dividend Yield			Risk-Free Interest Rate			Expected Volatility			Expected Life		Weighted Average Fair Value
December 2006		373,752		8.0	%		4.4	%		25.0	%		6.25 years	$	2.14
January 2007		1,296,400		8.0	%		4.7	%		25.0	%		6.25 years	$	2.41
June 2007		100,000		5.1	%		4.7	%		25.0	%		6.25 years	$	5.93
July 2007		135,600		5.1	%		4.7	%		25.0	%		6.25 years	$	6.07

The following table summarizes the activity of options for the nine months ended September 30, 2007:

						Weighted
						Average		Aggregate
				Weighted		Remaining		Intrinsic
				Average		Contractual		Value
	Units			Exercise Price		Term (in years)		(in thousands)
Outstanding, December 31, 2006		373,752		$	21.00		8.50
Granted		1,532,000			24.84		9.33
Forfeited or expired		(10,100	)		23.06		-
Outstanding, September 30, 2007		1,895,652		$	24.09		9.16	$	19,119
Options exercisable, September 30, 2007		93,438
Available for grant		1,209,779

25

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

NOTE 12 — BENEFIT PLANS (continued)

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 nine months ended September 30, 2007:

				Weighted
				Average
				Grant Date
	Units			Fair Value
Non-vested units outstanding, December 31, 2006		47,619		$	21.00
Granted		590,950			24.63
Vested		(11,904	)		21.00
Forfeited		(2,000	)		23.06
Non-vested units outstanding, September 30, 2007		624,665		$	24.42

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 2.1 million common units. At September 30, 2007, the Company had 1,435,000 phantom units and unit options outstanding under the AHD LTIP, with 665,000 phantom units and unit options available for grant.

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 September 30, 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 nine months ended September 30, 2007:

	Shares			Weighted Average Grant Date Fair Value
Outstanding, beginning of period		159,067		$	45.51
Granted		25,095		$	50.09
Matured		(38,401	)	$	51.15
Forfeited		(1,000	)	$	43.05
Outstanding, end of period		144,761		$	44.75

Atlas Pipeline Incentive Compensation Agreements. Atlas Pipeline 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 the vesting of the awards, which is dependent upon the achievement of certain predetermined performance targets through September 30, 2007. At September 30, 2007, the predetermined performance targets were achieved and all of the awards under the incentive compensation agreements vested. Of the total common units to be issued under the incentive compensation agreements, 58,824 common units will be issued prior to December 31, 2007. The remaining common units to be issued under the incentive compensation agreements will be determined based upon the financial performance of certain Atlas Pipeline assets for the year ended December 31, 2008.

Atlas Pipeline recognized compensation expense of $31.2 million and $1.2 million for the three months ended September 30, 2007 and 2006, respectively, and $33.6 million and $2.8 million for the nine months ended September 30, 2007 and 2006, respectively, related to the vesting of awards under these incentive compensation agreements. The increase in non-cash compensation expense was due to an increase in common unit awards estimated by Atlas Pipeline’s management to be issued under incentive compensation agreements to certain key employees as a result of Atlas Pipeline’s acquisition of the Chaney Dell and

26

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

NOTE 12 — BENEFIT PLANS (continued)

Midkiff/Benedum systems. The ultimate number of common units estimated to be issued under the incentive compensation agreements will be determined by the financial performance of certain APL assets for the year ended December 31, 2008. The vesting period for such awards concluded on September 30, 2007 and all compensation expense related to the awards was recorded as of that date. Atlas Pipeline’s management anticipates that adjustments will be recorded in future periods with respect to the awards under the incentive compensation agreements based upon the actual financial performance of the assets in future periods in comparison to their estimated performance. Based upon Atlas Pipeline’s management estimate of the probable outcome of the performance targets at September 30, 2007, 877,543 common unit awards are ultimately expected to be issued under these agreements, which represents the amount of common units expected to be issued under the incentive compensation agreements. Atlas Pipeline follows SFAS No. 123(R) and recognized compensation expense related to these awards based upon the fair value method.

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 September 30, 2007 and 2006 operations were charged $161,000 and $40,000 respectively, and during the nine months ended September 30, 2007 and 2006 operations were charged $484,000 and $121,000, respectively, with respect to this commitment.

NOTE 13 - COMMON STOCK

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.

Stock Split

On April 27, 2007, the Company’s Board of Directors approved a 3-for-2 stock split of the Company’s common stock effected in the form of a 50% stock dividend. All shareholders of record as of May 15, 2007 received one additional share of common stock for every two shares of common stock held on that date. The additional shares of common stock were distributed on May 25, 2007. Information pertaining to shares and earnings per share has been restated in the accompanying financial statements and notes to the consolidated financial statements to reflect this split.

27

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

NOTE 14 - 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 unit holders. Distributions declared by AHD and paid to the Company from inception are as follows:

Date Cash Distribution Paid or Payable	For Quarter Ended		Cash Distribution per Common Limited Partner Unit			Total Cash Distribution to the Company (in thousands)
November 19, 2006		September 30, 2006	$	0.17	(1)	$	2,975
February 19, 2007		December 31, 2006	$	0.25		$	4,375
May 18, 2007		March 31, 2007	$	0.25		$	4,375
August 17, 2007		June 30, 2007	$	0.26		$	4,550
November 19, 2007 (2)		September 30, 2007	$	0.32		$	5,600

__________________________

(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.

(2) Declared subsequent to September 30, 2007.

In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 4), the Partnership, which holds all of the incentive distribution rights in APL, agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter.

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 or Payable	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
May 15, 2007		March 31, 2007	$	0.43		$	12,944
August 14, 2007		June 30, 2007	$	0.43		$	12,944
November 14, 2007 (3)		September 30, 2007	$	0.55		$	16,825	(2)

__________________________

(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.

(2) Does not include a $784,000 incentive distribution which will not be payable to the Company until 2010, provided the Atlas Energy meets certain minimum distribution levels.

(3) Declared subsequent to September 30, 2007.

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ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2007

(Unaudited)

NOTE 15 - ISSUANCE OF SUBSIDIARY UNITS

In July 2007, Atlas Pipeline Holdings issued 6.5 million common units (an approximate 27% interest in it) for net proceeds of $167.2 million after offering costs in a private placement offering. In addition, in July 2007 Atlas Pipeline issued 25.6 million common units through a private placement to investors, of which 3.8 million units were purchased by Atlas Pipeline Holdings. The Company has accounted for these offerings in accordance with Staff Accounting Bulletin No. 51, Accounting by the Parent in Consolidation for Sales of Stock by a Subsidiary, (“SAB No. 51”). Accordingly, a gain of $53.0 million, net of an income tax provision of $34.3 million was recorded in consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $87.3 million to minority interest, in the three months ended September 30, 2007.  The Company has adopted a policy to recognize gains on such transactions as an increase directly to equity rather than as income.  This gain represents the Company’s portion of the excess net offering price per unit of each of its subsidiary’s units to the book carrying amount per unit.

In June 2007, Atlas Energy issued 24.0 million Class B common and Class D units (an approximate 31% interest in it) for net proceeds of $597.5 million after offering costs in a private placement offering. The Company has accounted for this offering in accordance with Staff Accounting Bulletin No. 51, Accounting by the Parent in Consolidation for Sales of Stock by a Subsidiary, (“SAB No. 51”). Accordingly, a gain of $147.9 million, net of an income tax provision of $87.5 million was recorded in consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $235.4 million to minority interest, in the six months ended June 30, 2007. This gain represents the Company’s portion of the excess net offering price per unit of its subsidiary’s units to the book carrying amount per unit.

NOTE 16 - SUBSEQUENT EVENT

Stock Dividend. On October 25, 2007, the Company announced that its Board of Directors had declared a cash dividend of $0.05 per share of common stock, payable on November 14, 2007, to holders of record on November 7, 2007.

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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 a publicly traded energy company engaged, through subsidiaries, in the development, production, gathering and processing of natural gas.

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 49.4%. Atlas Energy has focused its operations in the Appalachian Basin, and has expanded into Michigan after its acquisition of AGO on June 29, 2007.

We conduct our natural gas gathering 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 a 64% interest. Atlas Pipeline GP has a 2% general partner interest, an 13.6% limited partner interest and all the incentive distribution rights in Atlas Pipeline.

Recent Developments

Atlas Pipeline Acquisition. On July 27, 2007, Atlas Pipeline acquired control of Anadarko Petroleum Corporation’s (NYSE: APC) (“Anadarko”) 100% interest in the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and its approximate 73% interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (the “Assets”). The Chaney Dell System includes 3,470 miles of gathering pipeline and three processing plants, while the Midkiff/Benedum System includes 2,500 miles of gathering pipeline and two processing plants. The transaction was effected by the formation of two joint venture companies which will own the respective systems, to which Atlas Pipeline has contributed $1.85 billion and Anadarko contributed the Assets.

In connection with this acquisition, APL has reached an agreement with Pioneer Natural Resources Company (NYSE: PXD - “Pioneer”), which currently holds an approximate 27.2% interest in the Midkiff/Benedum system, whereby Pioneer will have an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system on June 15, 2008, and up to an additional 7.4% interest on June 15, 2009. If the option is fully exercised, Pioneer would increase its interest in the system to approximately 49%. Pioneer would pay approximately $230 million for the additional 22% interest if fully exercised. APL will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercises the purchase options.

APL funded the purchase price in part from the private placement of 25.6 million common limited partner units at a negotiated purchase price of $44.00 per unit, generating gross proceeds of $1.125 billion. AHD purchased 3.8 million of the 25.6 million common limited partner units issued by APL for $168.8 million and funded this through the private placement of 6.25 million of its common units to investors at a negotiated price of $27.00 per unit, yielding gross proceeds of $168.8 million (or net proceeds of $167.0 million, after underwriting fees and other transaction costs). APL also received a capital contribution from AHD of $23.1 million in order for AHD to maintain its 2.0% general partner interest in APL. AHD funded this capital contribution and the underwriting fees and other transaction costs related to its private placement of common units through borrowings under its revolving credit facility of $25.0 million. AHD, which holds all of the incentive distribution rights as the General Partner of APL, has also agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. APL funded the remaining purchase price from an $830.0 million senior secured term loan which matures in July 2014 and a new $300.0 million senior secured revolving credit facility that matures in July 2013.

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Atlas Energy Acquisition. On June 29, 2007, Atlas Energy acquired DTE Gas & Oil Company, or DGO, for a purchase price of $1.268 billion, including related expenses, adjustments for working capital of $10.4 million and current year capital expenditures of $19.0 million. Assets acquired include interests in approximately 2,210 natural gas wells with estimated proved reserves of approximately 610.6 billion cubic feet of natural gas equivalents, located in the northern lower peninsula of Michigan, 299,500 net developed acres and 65,600 net undeveloped acres. Subsequent to the acquisition, DGO changed its name to Atlas Gas & Oil Company, or AGO. With this acquisition, Atlas Energy increased its natural gas and oil production as well as entered into a new region that offers additional opportunities to expand its operations. In order to produce methane from the Antrim Shale, water must be drawn off first, a process that takes 3 to 12 months. As a result, we don’t believe our Michigan business unit wells are compatible with our investment partnership and intend to drill those wells for our own account.

To fund the acquisition, Atlas Energy borrowed $713.9 million on its new credit facility and completed a private placement of 7,298,181 Class B common units and 16,702,828 Class D units to a group of institutional investors at a weighted average price of $25.00 per unit for net proceeds of $597.5 million. Proceeds of $52.5 million were used to pay the outstanding balance of Atlas Energy’s credit facility with Wachovia Bank.

Investment by Atlas Lightfoot, LLC. Through September 30, 2007, our subsidiary, Atlas Lightfoot, LLC, has invested $10.4 million in Lightfoot Capital Partners LP, or Lightfoot, and will own 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 are under-utilized by the MLP structure.

Gains on sales of subsidiary units. In July 2007, Atlas Pipeline Holdings issued 6.5 million common units (an approximate 27% interest in it) for net proceeds of $167.2 million after offering costs in a private placement offering. In addition, in July 2007 Atlas Pipeline issued 25.6 million common units through a private placement to investors, of which 3.8 million units were purchased by Atlas Pipeline Holdings. The Company has accounted for these offerings in accordance with Staff Accounting Bulletin No. 51, Accounting by the Parent in Consolidation for Sales of Stock by a Subsidiary, (“SAB No. 51”). Accordingly, a gain of $53.0 million, net of an income tax provision of $34.3 million was recorded in consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $87.3 million to minority interest, in the three months and nine months ended September 30, 2007. The Company has adopted a policy to recognize gains on such transactions as increases directly to equity rather than as income. This gain represents the Company’s portion of the excess net offering price per unit of AHD’s units to the book carrying amount per unit.

In June 2007, Atlas Energy issued 24.0 million Class B common and Class D units (an approximate 31% interest in it) for net proceeds of $597.5 million after offering costs in a private placement offering. The Company has accounted for this offering in accordance with Staff Accounting Bulletin No. 51, Accounting by the Parent in Consolidation for Sales of Stock by a Subsidiary, (“SAB No. 51”). Accordingly, a gain of $147.9 million, net of an income tax provision of $87.5 million was recorded in consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $235.4 million to minority interest, in the six months ended June 30, 2007. This gain represents the Company’s portion of the excess net offering price per unit of Atlas Energy’s units to the book carrying amount per unit.

Cash Dividend. On October 25, 2007, our Board of Directors declared a cash dividend of $.05 per share, payable on November 14, 2007, to shareholders of record on November 7, 2007.

Business Segments

We operate two primary business segments:

· Our development and production segment which consists of our interest in Atlas Energy and includes well construction and completion and production from our interests in oil and gas properties.

· Our natural gas gathering and processing segment, which consists of our interest in AHD, who owns the general partner of APL, a midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachian regions.

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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, and 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.

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. Significant factors that may impact future commodity prices include developments in the issues currently impacting Iraq and Iran and the Middle East in general; the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil supply through export quotas; and overall North American gas supply and demand fundamentals, including the impact of increasing liquefied natural gas deliveries to the United States. Although Atlas Energy cannot predict the occurrence of events that will affect future commodity prices or the degree to which these prices will be affected, the prices for commodities that it produces will generally approximate market prices in the geographic region of the production.

In order to address, in part, volatility in commodity prices, Atlas Energy has implemented a hedging program that is intended to reduce the volatility in its gas production revenues. Under that program, Atlas Energy has financial hedges in place for approximately 84% of its expected production for the twelve months ended September 30, 2008. This policy mitigates, but does not eliminate, its sensitivity to short-term changes in commodity prices. Please read “— Quantitative and Qualitative Disclosures About Market Risk.”

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

While Atlas Energy anticipates continued high levels of exploration and production activities in the areas in which it operates, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas reserves. Drilling activity generally decreases as natural gas prices decrease.

Inflation in the United States did not have a material impact on our results of operations for the nine month periods ended September 30, 2007 and 2006. It may in the future, however, increase the cost to acquire or replace property, plant and equipment, and may increase the costs of labor and supplies. To the extent permitted by competition and our existing agreements, we have and will continue to pass along increased costs to our investors and customers in the form of higher fees.

Results of Operations

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						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Average construction and completion revenue per well	$	361		$	301		$	322		$	295
Average construction and completion cost per well		314			262			280			256
Average construction and completion gross profit per well	$	47		$	39		$	42		$	39
Gross profit margin	$	13,477		$	6,604		$	31,414		$	17,652
Gross profit percent		13	%		13	%		13	%		13	%
Net wells drilled		286			168			748			459

Our well construction and completion segment margin was $13.5 million and $31.4 million in the three months and nine months ended September 30, 2007 respectively, an increase of $6.9 million (104%) and $13.7 million (78%) from $6.6 million and $17.7 million in the three months and nine months ended September 30, 2006, respectively. During the three months ended September 30, 2007, the increase of $6.9 million in segment margin was attributable to an increase in the number of wells drilled ($5.6 million) and an increase in the gross profit per well ($1.3 million). During the nine months ended September 30, 2007, the increase of $13.7 million in segment margin was attributable to an increase in the number of wells drilled ($12.1 million) and an increase in the gross profit per well ($1.6 million). The increase in the number of wells drilled of 289 in the nine months ended September 30, 2007 as compared to September 30, 2006 is the result of an increase in our fundraising in 2007. It should be noted that “Liabilities associated with drilling contracts” on our balance sheet includes $37.7 million of funds raised in the first nine months of calendar 2007 that have not been applied to the completion of wells as of September 30, 2007 due to the timing of drilling operations, and thus had not been recognized as well construction and completion revenue.  We expect to recognize this amount as revenue in the fourth quarter of fiscal 2007. During fiscal 2006 we raised $218.5 million and plan to raise approximately $340.0 million in 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.

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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						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Production revenues (in thousands):
Gas (1) (6)	$	60,302		$	19,402		$	102,439		$	59,332
Oil	$	2,938		$	2,489		$	7,357		$	7,323
Production volume:(2)
Appalachia
Gas (Mcf/day) (1)		29,324			25,955			26,220			24,064
Oil (Bbls/day)		443			416			422			415
Michigan(5)
Gas (Mcf/day)		59,304			—			59,325			—
Oil (Bbls/day)		3			—			3			—
Total (Mcfe/day) (5)		91,304			28,451			88,095			26,554
Average sales prices:
Gas (per Mcf) (3) (7)	$	8.19		$	8.13		$	8.55		$	9.03
Oil (per Bbl)	$	71.63		$	65.01		$	63.75		$	64.59
Production costs:(4)
As a percent of production revenues		13	%		11	%		12	%		10	%
Per Mcfe	$	.99		$	.93		$	.95		$	.92
Depletion per Mcfe	$	2.19		$	2.14		$	2.24		$	2.04

(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 were $6.55 and $7.32 per Mcf for the three months ended September 30, 2007 and 2006, and $7.18 and $8.10 per Mcf for the nine months ended September 30, 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.
(5)	Amounts represent production volumes related to DGO from the acquisition date (June 29, 2007) to September 30, 2007.
(6)	Excludes non-qualifying hedge gains of $26.3 million associated with the AGO acquisition in the nine months ended September 30, 2007.
(7)	Includes $6.5 million in derivative proceeds which were not included as revenue in the three and nine months ended September 30, 2007.

Our natural gas revenues were $60.3 million and $102.4 million in the three months and nine months ended September 30, 2007, respectively, an increase of $40.9 million (211%) and $43.1million (73%) from $19.4 million and $59.3 million in the three and nine months ended September 30, 2006, respectively. The increases were attributable to volumes associated with our Michigan operations acquired on June 29, 2007 and a 13 % increase and 9% increases in production volumes in our Appalachian operating area in the three months and nine months ended September 30, 2007, respectively. The $40.9 million increase in natural gas revenues in the three months ended September 30, 2007 consisted of $42.6 million attributable to increases in production volumes and $1.7 million attributable to decreases in natural gas sales prices. The $43.1 million increase in natural gas revenues in the nine months ended September 30, 2007 consisted of $49.6 million attributable to increases in production volumes and $6.5 million attributable to decreases in natural gas sales prices.

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The increase in our gas production volumes of 62,673 Mcf/d and 61,481 Mcf/d in the three months and nine months ended September 30, 2007 as compared to September 30, 2006, resulted from the acquisition of DTE Gas & Oil Company on June 29, 2007 and 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 with our acquisition of AGO and 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.

Our oil revenues were $2.9 million and $7.4 million in the three months and nine months ended September 30, 2007, respectively, an increase of $449,000 (18%) and an increase of $34,000 (0.5%) from $2.5 million and $7.3 million during the three months and nine months ended September 30, 2006, respectively. The increase in the three months ended September 30, 2007 resulted from a 7% increase in production volumes and a 10 % increase in the average sales price of oil. The increase in the nine months ended September 30, 2007 resulted from a 1% decrease in the average sales price of oil and a 2% increase in production volumes. The $449,000 increase in the three months ended September 30, 2007 consisted of $254,000 attributable to increases in sales prices and $195,000 attributable to volume increases due to an increase in the number of new wells placed into production during the three months ended September 30, 2007. The $34,000 increase in the nine months ended September 30, 2007 consisted of $95,000 attributable to decreases in sales prices and $129,000 attributable to volume increases.

Our production costs were $12.0 million and $20.3 million in the three and nine months ended September 30, 2007, respectively, an increase of $8.3 million (222%) and $9.8 million (93%) from $3.7 million and $10.5 million in the three and nine months ended September 30, 2006, respectively. These increases include $7.4 million of production costs including, $2.0 million related to production taxes associated with our acquisition of AGO on June 29, 2007 as well as increases in transportation charges, labor and maintenance costs associated with an increase in the number of wells we own from the prior year period. The transportation fees charged to our wells connected to Atlas Pipeline’s gathering system were generally increased as a percent of gas revenues beginning in January 2007.

Transmission, Gathering and Processing

The following table presents selected volumetric information related to Atlas Pipeline for the periods indicated (in Mcf/day):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Appalachia system throughput volume		71,876		63,909		66,888		61,473
Velma system gathered gas volume		63,757		62,113		62,531		61,641
Chaney Dell system gathered gas volume		255,649		—		255,649		—
Midkiff / Benedum System gathered gas volume		150,061		—		150,061		—
NOARK Ozark Gas Transmission throughput volume		325,652		226,962		311,562		236,331
Elk City/Sweetwater system gathered gas volume		299,450		284,461		298,724		270,957
Combined throughput volume		1,166,445		637,445		1,145,415		630,402

The average throughput volume on Atlas Pipeline's gathering systems  for the three months and nine months ended September 30, 2007 respectively increased by 529,000 Mcf/day (82%) and 515,000 Mcf/day (83%) primarily due to gathered volumes on the Cheney Dell and Midkiff/ Benedum systems, which were acquired in July 2007. Average throughput volume also increased due to higher volumes for the NOARK and Elk City systems. The average Ozark Gas /Transmission volume was 325.7 MMcfd for the three months and nine months ended September 30, 2007, respectively, an increase of 43% and 32% from the prior year comparable periods. The Elk City system, which includes the newly constructed Sweetwater plant averaged 299.5 MMcfd and 298.7 MMcfd for the three months and nine months ended September 30, 2007, respectively, an increase of 5% and 10% from the comparable prior year periods.

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Atlas Pipeline’s transmission, gathering and processing revenues were $239.9 million and $452.6 million for the three months and nine months ended September 30, 2007 respectively, an increase of $124.5 million and $109.9 million from $115.4 million and $342.7 million for the three months and nine months ended September 30, 2006 respectively. The increase was primarily attributable to revenue contributions from the newly acquired Chaney Dell and Midkiff/Benedum systems of $131.3 million, and to an increase of $1.6 million and $27.6 million for the three months and nine months ended September 30, 2007, respectively, from the Elk City Sweetwater System due primarily to an increase in volumes, including processing volumes from the newly constructed Sweetwater gas plant. This was partially offset by a decrease of $20.8 million for the nine months ended September 30, 2007 from Atlas Pipeline’s NOARK system due to lower natural gas sales volumes on its gathering systems. Transportation and compression revenue increased by $7.7 million and $14.5 million for the three months and nine months ended September 30, 2007, respectively, primarily due to an increase of $3.6 million and $8.6 million from the transportation revenues associated with the NOARK system.

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 eliminated under this agreement were approximately $8.6 million and $7.0 million for the three months ended September 30, 2007 and 2006 respectively, and $24.8 million and $22.7 million for the nine months ended September 30, 2007 and 2006, respectively. In addition, we receive transportation revenues from our investment partnerships for gathering services of $3.5 million, $3.0 million, $10.5 million and $6.9 million for the same periods.

Our transmission, gathering and processing costs and expenses were $187.4 million and $377.7 million for the three months and nine months ended September 30, 2007 respectively, an increase of $91.2 million (95%) and $106.7 million (39%) from $96.2 million and $271.0 million for the three months and nine months ended September 30, 2006 respectively. The increase was primarily related to expenses from Atlas Pipelines’ Anadarko acquisition on July 27, 2007 and higher NOARK and Appalachia system operating and maintenance costs as a result of additional capacity and additional well connections.

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 $5.4 million and $13.3 million in the three months and nine months ended September 30, 2007 respectively, an increase of $2.4 million (79%) and $4.8 million (57%) from $3.0 million and $8.5 million in the three months and nine months ended September 30, 2006 respectively. These increases are attributable to an increase in the number of wells drilled and managed for our investment partnerships in the three months and nine months ended September 30, 2007 as compared to 2006.

Well Services

Our well services revenues were $4.8 million and $12.7 million in the three months and nine months ended September 30, 2007 respectively, an increase of $1.5 million (45%) and $3.2 million (34%) from $3.3 million and $9.5 million in the three months and nine months ended September 30, 2006 respectively. These increases resulted from an increase in the number of wells operated for our investment partnerships due to additional wells drilled in the twelve months ended September 30, 2007.

Our well services expenses were $2.5 million and $6.7 million in the three months and nine months ended September 30, 2007 respectively, an increase of $763,000 (44%) and $1.2 million (21%) from $1.8 million and $5.5 million in the three months and nine months ended September 30, 2006 respectively.  These increases were 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.

Gain (Loss) on Mark-to-Market Derivatives

Our gain (loss) on mark-to-market derivatives represents non-cash gains and losses recognized on Atlas Energy’s and APL’s derivatives. Atlas Energy recognized a $26.3 million non-cash gain related to the change in value of derivative contracts associated with the acquisition of AGO in the nine months ended September 30, 2007 (see Note 9). Atlas Pipeline recognized an $18.8 million non-cash loss related to the change in value of derivative contracts associated with the acquisition of Anadarko in the nine months ended September 30, 2007 (See Note 9). The contracts entered into by Atlas Energy and Atlas Pipeline were derivative contracts to hedge the projected production volume of their anticipated acquisitions (see Note 4). The production volumes of the assets to be acquired were not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition of the assets had not yet been completed. Accordingly, we recorded the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative values recorded within our consolidated statements of income. Upon closing of the acquisitions, the production volumes of the assets acquired were considered “probable forecasted production” under SFAS No. 133 and we evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133

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General and Administrative

Our general and administrative expenses were $48.9 million and $85.2million in the three months and nine months ended September 30, 2007 respectively, an increase of $35.8 million and $51.0 million from $13.1 million and $34.2 million in the three months and nine months ended September 30, 2006 respectively. 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 $35.8 million in the three months ended September 30, 2007 is principally attributable to $37.2 million related to employee costs including benefits and stock compensation awards. The increase of $51.0 million in the nine months ended September 30, 2007 is principally attributable to $45.9 million related to employee costs including benefits and stock compensation awards plus a $4.9 million increase in audit, tax and professional fees, including $3.9 million in fees related to hedges entered into associated with the AGO acquisition.

Depletion

Our depletion of oil and gas properties as a percentage of oil and gas revenues was 29% and 27% in the three months and nine months ended September 30, 2007 respectively, compared to 26% and 22% in the three months and nine months ended September 30, 2006 respectively. Depletion expense per Mcfe was $2.19 and $2.24 in the three and nine months ended September 30, 2007, an increase of $0.05 (2%) and $0.20 (9%) per Mcfe from $2.14 and $2.04 in the three and nine months ended September 30, 2006, respectively. Increases in our depletable basis and production volumes caused depletion expense to increase $12.8 million (228%) and $15.2 million (103%) to $18.4 million and $30.0 million in the three months and nine months ended September 30, 2007, respectively, compared to $5.6 million and $14.8 million in the three and nine months ended September 30, 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 $10.0 million (146%) and $12.7 million (69%) to $16.8 million and $31.0 million in the three months and nine months ended September 30, 2007 respectively compared to $6.8 million and $18.3 million in the three months and nine months ended September 30, 2006 respectively. This was primarily due to the increased asset base associated with Atlas Energy’s acquisition of AGO on June 29, 2007 and Atlas Pipeline’s acquisition of the Anadarko assets on July 27, 2007 and expansion capital expenditures, particularly the construction of the Atlas Pipeline’s Sweetwater processing facility.  

Interest Expense

Our interest expense was $37.5 million and $53.7 million in the three months and nine months ended September 30, 2007 respectively, an increase of $31.6 million and $34.3 million from $5.9 million and $19.4 million in the three and nine months ended September 30, 2006 respectively. These increases resulted primarily from an increase in outstanding borrowings by Atlas Energy of $739.0 million under its credit facility, borrowings by Atlas Pipeline of its term loan of $830.0 million, and AHD’s credit facility of $25.0 million. These borrowings were used to fund Atlas Energy’s and Atlas Pipeline’s acquisitions and capital expenditures during the nine months ended September 30, 2007

Minority Interests

At September 30, 2007, we owned 10% 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’s loss was $22.5 and $43.9 million for the three and nine months ended September 30, 2007 respectively and an expense of $2.0 million and $13.0 million for the three and nine months ended September 30, 2006 respectively, a decrease of $24.5 million and $56.9 million in the three and nine months ended September 30, 2007 respectively. This decrease is a result of a decrease in Atlas Pipeline’s net income.

After the initial public offering of Atlas Energy on December 18, 2006 and the issuance of private placement Class B common and Class D units on June 29, 2007, approximately 51.0% 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 $16.1 million and $28.9 million for the three and nine months ended September 30, 2007, respectively.

Provision for Income Taxes

Our effective tax rate was 28% and 31% for the three months and nine months ended September 30, 2007 as compared to 39% and 40% for the three months and nine months ended September 30, 2006 respectively. For the three months and nine months ended September 30, 2007, our effective income tax rates decreased compared to prior year similar periods substantially due to revisions of our previous estimates as a result of anticipated state and local taxes in connection with the acquisition of AGO.  Currently, it is our expectation that our effective income tax rate will approximate 32% for the year ended December 31, 2007.

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Liquidity and Capital Resources

General.  We fund operations through our subsidiaries by a combination of sources, including cash generated by operations, capital raised through drilling investment partnerships, the issuance of units and use of our credit facilities. 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):

	Nine Months Ended
	September 30,
	2007			2006
Provided by operations	$	95,385		$	43,845
Used in investing activities		(3,370,889	)		(138,043	)
Provided by financing activities		3,203,915			103,735
Increase in cash and cash equivalents	$	(71,589	)	$	9,537

We had $113.8 million in cash and cash equivalents on hand at September 30, 2007, as compared to $185.4 million at December 31, 2006. We had a working capital of $23.8 million, a decrease of $56.6 million from working capital of $80.4 million at December 31, 2006. The decrease in our working capital relates primarily to a net increase in our cash and accounts receivable of $15.3 million and a corresponding increase in our current liabilities of $83.0 million. These increases are due primarily to the AGO and Anadarko acquisitions. Our working capital also fluctuates in relation to the level of drilling activities at any given date, which is related to the timing of funds raised and the subsequent use of those funds, and also as a result of commodity prices.

At September 30, 2007, the borrowing base under Atlas Energy’s credit facility is $850.0 million, and it has $109.9 million available. At September 30, 2007, Atlas Pipeline has a borrowing base of $300.0 million under its credit facility, of which $266.5 million is available. At September 30, 2007, AHD has a borrowing base of $50.0 million, of which $25.0 million is available. See Note 8 to our Consolidated Financial Statements for information on Atlas Energy’s, Atlas Pipeline’s and AHD’s credit facilities at September 30, 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 the price of natural gas and oil, competition for natural gas transportation and in obtaining gas supplies for our processing operations, interest rates and our ability to raise funds from our drilling investment partnerships.  Netcash provided by operating activities increased $51.5 million in the nine months ended September 30, 2007 to $95.4 million from $43.9 million in the nine months ended September 30, 2006, substantially as a result of the following:

• an increase in net income before depreciation and amortization of $39.3 million in the nine months ended September 30, 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 $57.7 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 $32.9 million due to a decrease in Atlas Pipeline’s earnings and higher distributions paid to minority interests;

• changes in our deferred tax liability increased by $33.4 million as compared to the nine months ended September 30, 2006 which reflects the impact of timing differences between accounting and tax records.  The $33.4 million increase is primarily related to the reversal of a $29.8 million income tax valuation allowance recorded in July 2006 related to the gain on sale of subsidiary units issued by AHD.

• changes in operating assets and liabilities decreased operating cash flow by $48.8 million in the nine months ended September 30, 2007, compared to the nine months ended September 30, 2006.

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

• an increase of $1.1 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;

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• a decrease of $54.7 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; and

• an increase of $4.8 million in changes in other assets and liabilities.

Cash flows from investing activities.Cash used in our investing activities increased $3.233 billion in the nine months ended September 30, 2007, to $3.371 billion from $138.0 million in the nine months ended September 30, 2006, primarily as a result of our AGO and Anadarko acquisitions for a total of $3.118 billion and a $71.4 million increase in capital expenditures related to an increase in the number of wells we drilled, and a $31.9 million increase in capital expenditures related to pipeline expansions.

Cash flows from financing activities. Cash provided by in our financing activities increased $3.100 billion in the nine months ended September 30, 2007, to $3.204 billion from $103.7 million in the nine months ended September 30, 2006, as a result of the following: 

• we repurchased $80.4 million of common stock in a Dutch tender offer in the nine months ended September 30, 2007; repurchases were $29.9 million in the nine months ended September 30, 2006;

• net borrowings on debt increased by $1.621 billion in the nine months ended September 30, 2007 as compared to the prior year similar period principally as a result of the borrowings under Atlas Energy’s and Atlas Pipeline’s credit facilities, to fund the AGO and Anadarko acquisitions:

• we received proceeds of $597.5 million from Atlas Energy’s issuance of Class B common and Class D units;

• we received proceeds of $1.114 billion from AHD’s and Atlas Pipeline’s issuance of common and preferred units in the nine months ended September 30, 2007 compared to $134.1 million received, for an increase of $979.5 million in 2006; and,

• our deferred financing costs paid increased $8.0 million.

Capital Requirements: During the nine months ended September 30, 2007, our capital expenditures related primarily to our acquisitions. Atlas Energy acquired AGO on June 29, 2007 which included $1.268 billion in oil and gas properties. Atlas Pipeline completed its Anadarko acquisition on July 27, 2007 which included $1.878 billion in gas gathering and processing plants. We also continue to invest in our drilling partnerships and expand our pipelines, in which we invested $72.5 million and $93.7 million, respectively.  For the nine months ended September 30, 2007 and the remaining quarter 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. 

New Credit Facility

Upon the closing of the acquisition of DTE Gas & Oil Company, Atlas Energy replaced its Wachovia Bank Credit facility with a new 5-year, $850.0 million credit facility, which is led by J.P. Morgan Chase Bank, N.A. (“J.P. Morgan”), as administrative agent, Wachovia Bank, National Association, as syndication agent, and other lenders. The J.P. Morgan revolving credit facility has a current borrowing base of $850.0 million which will be redetermined semi-annually on April 1 and October 1 subject to changes in our oil and gas reserves. The initial borrowing base is also scheduled to be reduced to $735.0 million less 25% of the amount of any issuance of equity or debt securities by Atlas Energy at the earlier of June 29, 2008 or the issuance by Atlas Energy of equity or debt securities of at least $200.0 million. Up to $50.0 million of the facility may be in the form of standby letters of credit. The facility is secured by our assets and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at our option. At September 30, 2007, the weighted average interest rate on outstanding borrowings was 7.5%.

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Atlas Energy is required to maintain specified ratios of current assets to current liabilities and debt (as defined in the agreement) 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 us if an event of default has occurred and is continuing or would occur as a result of such distribution. Atlas Energy was in compliance with these covenants as of September 30, 2007. At September 30, 2007, $740.1 million was outstanding under this facility including letters of credit of $1.1 million, which are not reflected as borrowings on our Consolidated Balance Sheets.

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 April 2007, the Financial Accounting Standards Board (“FASB”) issued FASB interpretation No. 39-1, Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts, (“FIN 39-1”). FIN 39-1 amends FIN 39, which allows an entity to offset fair value amounts for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. FIN 39-1 is effective for fiscal years beginning after November 15, 2007. We do not expect the adoption of FIN 39-1 to have an impact on our financial position or results of operations.

In February 2007, the 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 we have not made any decisions on its application to our financial position or results of operations.

In December 2006, the FASB issued FASB Staff Position (FSP) EITF 00-19-2, Accounting for Registration Payment Arrangements. FSP EITF 00-19-2 requires an issuer of financial instruments, such as debt, convertible debt, equity shares or warrants, to account for a contingent obligation to transfer consideration under a registration payment arrangement in accordance with Statement 5, Accounting for Contingencies, and FASB Interpretation 14, Reasonable Estimation of the Amount of a Loss. That accounting applies regardless of whether the registration payment arrangement is a provision in a financial instrument or a separate agreement. The FSP requires issuers to make certain disclosures for each registration payment arrangement or group of similar arrangements. The FSP is effective immediately for registration payment arrangements and financial instruments subject to those arrangements that are entered into or modified subsequent to December 21, 2006, the date FSP EITF 00-19-2 was issued.

We applied the consensus in FSP EITF 00-19-2 effective January 1, 2007. We reviewed the penalty terms in the registration rights agreement related to AHD's, Atlas Pipeline's, and Atlas Energy’s respective private placement entered into during the nine months ended September 30, 2007, pursuant to the guidance in the FSP, and determined that the probability of payment is remote under Statement 5 based upon our status of current related filings. As a result, the application of FSP EITF 00-19-2 did not have an effect on our 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. We are currently evaluating the impact of the 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, (“FIN 48”), on January 1, 2007, and FASB Interpretation No. 48-1, Definition of Settlement in FASB Interpretation No. 48, (“FIN 48-1”). 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. FIN 48-1 amends FIN 48 to provide guidance on how an enterprise should determine whether a tax provision is effectively settled for the purpose of recognizing previously unrecognized tax benefits. As a result of the implementation of FIN 48 and FIN 48-1, we determined that we had no liability for unrecognized income tax benefits, upon adoption and through September 30, 2007.

We file numerous consolidated and separate income tax returns in the United States Federal jurisdiction and in many state jurisdictions. 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.

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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 September 30, 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 September 30, 2007, Atlas Energy had an $850.0 million revolving credit facility ($739.0 million outstanding at September 30, 2007).  The weighted average interest rate for this facility was 7.5% at September 30, 2007. 

At September 30, 2007, Atlas Pipeline has a new comprised of a senior secured term loan of $830.0 million and a $300.0 million senior secured revolving credit facility ($33.5 million outstanding at September 30, 2007). The weighted average interest rate for this facility was 8.0% at September 30, 2007.

Atlas Pipeline Holdings has a $50.0 million revolving credit facility ($25.0 million outstanding at September 30, 2007). The weighted average interest rate for this facility was 7.4% at September 30, 2007.

Holding all other variables constant, if interest rates hypothetically increased or decreased by 10%, our net annual income would change by approximately $2.2 million.

Commodity Price Risk.  Our major market risk exposure to 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 enter 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..  Through our hedges, we seek to provide a measure of stability in the volatile environment of natural gas prices.   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 September 30, 2008, we estimate approximately 84% of Atlas Energy’s produced natural gas volumes will be sold in this manner, leaving its remaining production to be sold at contract prices in the month produced or at spot market prices.  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 financial hedge agreements for the twelve months ending September 30, 2008, and current indices, a theoretical 10% upward or downward change in the price of natural gas would change net income by approximately $3.8 million.

Atlas Energy 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. 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.

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At September 30, 2007, Atlas Energy had 384 open natural gas futures contracts related to natural gas sales covering 147.5 million MMBtus of natural gas (which includes 76.9 million MMBtu covering natural gas produced by assets acquired from AGO), maturing through June 30, 2013 at a combined average settlement price of $8.04 per MMBtu. At September 30, 2007 and December 31, 2006, Atlas Energy reflected net derivative assets of $50.4 million and $47.5 million, respectively.

On May 18, 2007, Atlas Energy signed a definitive agreement to acquire AGO (see Note 4). In connection with the financing of this transaction, Atlas Energy agreed as a condition precedent to closing that it would hedge 80% of its projected natural gas volumes for no less than three years from the closing date of the transaction. During May 2007, Atlas Energy entered into derivative instruments to hedge 80% of the projected production of the assets to be acquired as required under the financing agreement. The production volume of the assets to be acquired was not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition of the assets had not yet been completed. Accordingly, Atlas Energy recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within revenues in the Company’s consolidated statements of income. Atlas Energy recognized non-cash income of $26.3 million related to the change in value of these derivatives from May 22, 2007 to June 28, 2007, which is shown as “Gain on mark-to-market derivatives” in the Combined and Consolidated Statements of Income for the nine months ended September 30, 2007. Upon closing of the acquisition on June 29, 2007, the production volume of the assets acquired was considered “probable forecasted production” under SFAS No. 133 and Atlas Energy evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133.

In addition, Atlas Energy recognized gains on settled contracts covering natural gas production of $4.9 million and $2.0 million for the three months ended September 30, 2007 and 2006, and $9.6 million and $4.9 million for nine months ended September 30, 2007 and 2006, respectively. As the underlying prices in the Atlas Energy hedge contracts were consistent with the indices used to sell its natural gas, there were no gains or losses recognized during the three months and nine months ended September 30, 2007 and 2006, respectively and for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

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. 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.

On June 3, 2007, Atlas Pipeline signed definitive agreements to acquire control of certain natural gas gathering systems and processing plants located in Oklahoma and Texas (see Note 16). In connection with the financing of this transaction, Atlas Pipeline agreed as a condition precedent to closing that it would hedge 80% of its projected natural gas, NGL and condensate production volume for no less than three years from the closing date of the transaction. During June 2007, Atlas Pipeline entered into derivative instruments to hedge 80% of the projected production of the assets to be acquired as required under the financing agreements. The production volume of the assets to be acquired was not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition of the assets had not yet been completed. Accordingly, Atlas Pipeline recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within revenues in the Company’s consolidated statements of income. Atlas Pipeline recognized a non-cash loss of $19.8 million related to the change in value of these derivatives for the three and nine months ended September 30, 2007. Upon closing of the acquisition in July 2007, the production volume of the assets acquired was considered “probable forecasted production” under SFAS No. 133 and Atlas Pipeline evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133.

At September 30, 2007 and December 31, 2006, Atlas Pipeline reflected net derivative liabilities of $92.0 million and $20.1 million, respectively. Atlas Pipeline recognized losses of $12.9 million and $4.9 million for the three months ended September 30, 2007 and 2006, respectively, and losses of $23.5 million and $10.5 million for the nine months ended September 30, 2007 and 2006, respectively, within natural gas and liquids revenue in its consolidated statements of income related to the settlement of qualifying hedge instruments. Atlas Pipeline recognized a loss of $8.4 million and a gain of $3.7 million within “Other, net” on the Company’s consolidated statements of income related to the change in market value of non-qualifying derivatives and the ineffective portion of qualifying derivatives, respectively, for the three months ended September 30, 2007. Atlas Pipeline recognized a loss of $39.3 million and a gain of $4.6 million within “Other, net” in the Company’s consolidated statements of income related to the change in market value of non-qualifying derivatives and the ineffective portion of qualifying derivatives, respectively, for the nine months ended September 30, 2007. Atlas Pipeline recognized losses of $3.0 million for the three and nine months ended September 30, 2007, within “Other, net” in its consolidated statements of income related to loss from cash settlement of non-qualifying derivatives. There were no gains or losses recognized for the three months or nine months ended September 30, 2006 related to cash settlements of non-qualifying derivatives.

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Derivatives are recorded on our balance sheets as assets or liabilities at fair value. At September 30, 2007 and December 31, 2006, we reflected a net hedging asset and liability on our balance sheets of $27.3 million and $41.6 million, respectively, when combining the above hedges of Atlas Energy and Atlas Pipeline. Of the $4.0 million net loss in accumulated other comprehensive income at September 30, 2007, we will reclassify $2.8 of gains to our consolidated statements of income over the next twelve-month period as these contracts expire, and $1.2 million of losses will be reclassified in later periods if the fair values of the instruments remain at current market values. Actual amounts that will be reclassified will vary as a result of future price changes.

As of September 30, 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
September 30,	Volumes		Fixed Price		Asset/(Liability) (3)
	(MMBtu) (1)		(per MMBtu)		(in thousands)
2008		35,470,000	$	8.15	$	37,289
2009		33,530,000	$	8.32		11,310
2010		25,430,000	$	8.02		517
2011		18,950,000	$	7.75		(790	)
2012		11,150,000	$	7.62		821
2013		2,250,000	$	7.67		346
					$	49,493

Natural Gas Costless Collars

Twelve Month
Period Ending					Average		Fair Value
September 30,	Option Type		Volumes		Floor and Cap		Asset/(Liability) (3)
			(MMBtu) (1)		(per MMBtu)		(in thousands)
2008		Puts purchased		450,000	$	7.50	$	314
2008		Calls sold		450,000	$	8.60		—
2008		Puts purchased		1,170,000	$	7.50		325
2008		Calls sold		1,170,000	$	9.40		—
2009		Puts purchased		390,000	$	7.50		—
2009		Calls sold		390,000	$	9.40		(32	)
2010		Puts purchased		2,160,000	$	7.75		144
2010		Calls sold		2,160,000	$	8.75		—
2011		Puts purchased		720,000	$	7.75		(4	)
2011		Calls sold		720,000	$	8.75		—
2011		Puts purchased		5,400,000	$	7.50		240
2011		Calls sold		5,400,000	$	8.45		—
2012		Puts purchased		1,800,000	$	7.50		—
2012		Calls sold		1,800,000	$	8.45		(25	)
2012		Puts purchased		6,480,000	$	7.50		—
2012		Calls sold		6,480,000	$	8.45		(24	)
2013		Puts purchased		2,160,000	$	7.00		—
2013		Calls sold		2,160,000	$	8.37		(19	)
							$	919
	Total Atlas Energy Resources net asset						$	50,412

44

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		42,651,000	$	0.893	$	(10,739	)
2008		61,362,000		0.706		(13,556	)
2009		8,568,000		0.746		(1,752	)
					$	(26,047	)

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		1,449,000	$	8.20	$	1,736
2008		5,484,000	$	8.80		4,608
2009		5,724,000	$	8,61		1,958
2010		2,820,000	$	8.64		1,132
					$	9,434

Natural Gas Basis Swaps (Sales)

Production
Period Ended			Average			Fair Value
December 31,	Volumes		Fixed Price			Asset/(Liability) (3)
	(MMBtu) (1)		(per MMBtu)			(in thousands)
2007		1,449,000	$	(0.73	)	$	135
2008		5,484,000	$	(0.73	)		388
2009		5,724,000	$	(0.51	)		550
2010		2,820,000	$	(0.57	)		435
						$	1,508

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		3,909,000	$	8.63	(4)	$	(6,819	)
2008		16,260,000	$	8.92	(5)		(16,293	)
2009		15,564,000	$	8.68			(6,402	)
2010		7,200,000	$	8.64			(2,891	)
						$	(32,405	)

Natural Gas Basis (Purchase)

Production
Period Ended			Average			Fair Value
December 31,	Volumes		Fixed Price			Liability (3)
	(MMBtu) (1)		(per MMBtu)			(in thousands)
2007		3,909,000	$	(1.05	)	$	161
2008		15,276,000	$	(1.19	)		(1,820	)
2009		14,820,000	$	(0.69	)		(5,485	)
2010		7,200,000	$	(0.56	)		(2,930	)
						$	(10,074	)

45

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		17,600	$	56.48	$	(427	)
2008		65,400	$	59.42		(1,133	)
2009		33,000	$	62.70		(362	)
					$	(1,922	)

Crude Oil Options (Sales)

Production Period Ended December 31,	Option Type		Volumes		Average Strike Price		Fair Value Asset/(Liability) (3)
			(MMBtu) (1)		(per MMBtu)		(in thousands)
2007		Puts purchased		189,300	$	60.00	$	(39	)
2007		Calls sold		189,300	$	75.36		(998	)
2008		Puts purchased		691,800	$	60.00		675
2008		Calls sold		691,800	$	78.00		(3,266	)
2009		Puts purchased		738,000	$	60.00		2,060
2009		Calls sold		738,000	$	80.62		(3,038	)
2010		Puts purchased		402,000	$	60.00		1,308
2010		Calls sold		402,000	$	79.34		(1,804	)
2011		Puts purchased		30,000	$	60.00		124
2011		Calls sold		30,000	$	74.50		(193	)
2012		Puts purchased		30,000	$	60.00		138
2012		Calls sold		30,000	$	73.90		(211	)
							$	(5,244	)

Crude Oil Sales Options (associated with NGL volumes)

Production Period Ended December 31,	Option Type		Associated NGL Volumes		Crude Volumes		Average Crude Strike Price		Fair Value Asset/(Liability) (3)
			(gallons)		(barrels)		(per barrel)		(in thousands)
2007		Puts purchased		25,789,680		390,000	$	60.00	$	58
2007		Calls sold		25,789,680		390,000	$	75.18		(2,513	)
2008		Puts purchased		249,257,484		3,744,600	$	60.00		5,119
2008		Calls sold		249,257,484		3,744,600	$	79.38		(15,961	)
2009		Puts purchased		324,233,280		4,752,000	$	60.00		13,292
2009		Calls sold		324,233,280		4,752,000	$	78.68		(22,694	)
2010		Puts purchased		169,282,890		2,413,500	$	60.00		8,064
2010		Calls sold		169,282,890		2,413,500	$	77.28		(12,643	)
									$	(27,278	)
	Total Atlas Pipeline net liability								$	(92,028	)
	Total Atlas America net liability								$	(40,616	)

(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 1,200,000 MMBtu of natural gas at an average price of $17.00 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.

46

ITEM 4.CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

In connection with the preparation of this Form 10-Q, 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 the material weakness in internal controls over financial reporting discussed below, as of September 30, 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 June 30, 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. The Company must establish a policy as to its treatment and must consistently apply this treatment to all such sales of subsidiary stock. The Company has elected to recognize gains for its three subsidiaries which have issued stock in order to record the effects in the December 31, 2006 and March 31, 2007 financial statements. The correction of the accounting treatment affected our December 31, 2006 balance sheet by increasing minority interest by $188.3 million, increasing deferred taxes by $79.1 million and increasing paid-in capital by $109.2 million from what was reported in previous filings.

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 year ended December 31, 2006 and quarterly period ended March 31, 2007 as a result of a material weakness in internal control over financial reporting related to review procedures performed in the preparation of the financial statements for these periods. The material weakness that existed was that the controls to review and validate the proper accounting treatment did not operate effectively.

A material weakness in internal control is a significant deficiency, or combination of significant deficiencies, that results in more than a remote likelihood that a material misstatement of the financial statements would not be prevented or detected on a timely basis by the Company.

To remediate this material weakness, the Company added additional review procedures including increasing the knowledge 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. The Company believes that the changes remediated the material weakness described above subsequent to June 30, 2007.

47

PART II.  OTHER INFORMATION

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.

48

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:  November 8, 2007	By:	/s/ Matthew A. Jones
		Matthew A. Jones
		Chief Financial Officer

Date:  November 8, 2007	By:	/s/Nancy J. McGurk
		Nancy J. McGurk
		Senior Vice President and Chief Accounting Officer

49

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Edward E. Cohen, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarterly period ended September 30, 2007 of Atlas America, Inc.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposed in accordance with generally accepted accounting principles;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Edward E. Cohen

Edward E. Cohen

Chairman of the Board and Chief Executive Officer

November 8, 2007

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Matthew A. Jones, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarterly period ended September 30, 2007 of Atlas America, Inc.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Matthew A. Jones

Matthew A. Jones

Chief Financial Officer

November 8, 2007

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Atlas America, Inc. (the "Company") on Form 10-Q for the quarterly period ended September 30, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Edward E. Cohen, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(2)  The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Edward E. Cohen

Edward E. Cohen

Chairman of the Board and Chief Executive Officer

November 8, 2007

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Atlas America, Inc. (the "Company") on Form 10-Q for the quarterly period ended September 30, 2007 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Matthew A. Jones, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Matthew A. Jones

Matthew A. Jones

Chief Financial Officer

November 8, 2007