ARKHAN 10Q 2006 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2006

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

For the transition period from _________ to __________

Commission file number: 001-32169

ATLAS AMERICA, INC.

(Exact name of registrant as specified in its charter)

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

311 Rouser Road
Moon Township, PA		15108
(Address of principal executive offices)		(Zip code)

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

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

Accelerated filer x

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, 2006 was 19.3 million shares.

ATLAS AMERICA, INC.

INDEX TO QUARTERLY REPORT ON FORM 10-Q


		Page
PART I	FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)

	Consolidated Balance Sheets - September 30, 2006 and December 31, 2005	3

	Consolidated Statements of Operations for the Three Months and Nine Months Ended September 30, 2006 and 2005	4

	Consolidated Statement of Changes in Stockholders’ Equity for the Nine Months Ended September 30, 2006	5

	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2006 and 2005	6

	Notes to Consolidated Financial Statements	7 - 30

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31 - 46

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	46 - 51

Item 4.	Controls and Procedures	51

PART II	OTHER INFORMATION

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	52

Item 6.	Exhibits	52

SIGNATURES		53

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ATLAS AMERICA, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)

	September 30,			December 31,
	2006			2005
ASSETS
Current assets:
Cash and cash equivalents	$	64,692		$	55,155
Accounts receivable		91,605			89,830
Prepaid expenses		12,198			5,772
Deferred tax asset		4,678			6,249
Advances to affiliate		—			492
Total current assets		173,173			157,498

Property and equipment, net		840,518			658,347
Intangible assets, net		31,564			60,959
Other assets, net		43,101			32,832
Goodwill		98,606			146,544
	$	1,186,962		$	1,056,180
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	144		$	1,351
Accounts payable		41,498			56,769
Liabilities associated with drilling contracts		76,883			70,514
Accrued producer liabilities		29,748			32,537
Accrued hedge liability		16,819			24,107
Accrued liabilities		42,774			27,763
Accrued income taxes		31,566			5,328
Advances from affiliate		265			—
Total current liabilities		239,697			218,369

Long-term debt		299,586			297,430
Deferred tax liability		28,615			29,369
Other liabilities		52,662			54,865

Minority interest		446,488			323,297

Commitments and contingencies (Note 9)

Stockholders’ equity:
Preferred stock, $0.01 par value: 1,000,000 authorized shares		—			—
Common stock, $0.01 par value: 49,000,000 authorized shares		200			133
Additional paid-in capital		77,066			75,967
Treasury stock, at cost		(29,514	)		(73	)
ESOP loan receivable		(509	)		(564	)
Accumulated other comprehensive income (loss)		8,650			(5,116	)
Retained earnings		64,021			62,503
Total stockholders’ equity		119,914			132,850
	$	1,186,962		$	1,056,180

See accompanying notes to consolidated financial statements

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
REVENUES
Well construction and completion	$	50,641		$	35,580		$	135,329		$	103,780
Gas and oil production		21,888			18,830			66,696			48,840
Transmission, gathering and processing		111,752			97,414			327,876			221,487
Administration and oversight		2,990			1,852			8,487			7,436
Well services		3,346			2,532			9,498			7,304
		190,617			156,208			547,886			388,847

COSTS AND EXPENSES
Well construction and completion		44,037			30,940			117,677			90,243
Gas and oil production		2,315			1,681			6,437			4,849
Transmission, gathering and processing		96,205			86,189			270,981			194,136
Well services		1,752			1,367			5,540			3,976
General and administrative		12,814			7,314			33,197			19,808
Net expense reimbursement - affiliate		345			—			1,041			389
Depreciation, depletion and amortization		12,442			7,736			33,158			19,023
		169,910			135,227			468,031			332,424

OPERATING INCOME		20,707			20,981			79,855			56,423

OTHER INCOME (EXPENSE)
Interest expense		(5,932	)		(3,574	)		(19,448	)		(9,777	)
Minority interests		(2,021	)		(3,806	)		(12,987	)		(7,553	)
Other, net		3,518			143			4,643			(29	)
		(4,435	)		(7,237	)		(27,792	)		(17,359	)

Income before income taxes and extraordinary item		16,272			13,744			52,063			39,064
Provision for income taxes		(6,302	)		(4,656	)		(20,632	)		(15,016	)
Income before extraordinary item		9,970			9,088			31,431			24,048
Extraordinary tax on gain on Atlas Pipeline Holdings, L.P.		(29,846	)		—			(29,846	)		—
Net income (loss)	$	(19,876	)	$	9,088		$	1,585		$	24,048

Net income (loss) per common share - basic
Net income before extraordinary item - basic	$	0.51		$	0.45		$	1.58		$	1.20
Extraordinary item		(1.52	)		—			(1.50	)		—
	$	(1.01	)	$	0.45		$	0.08		$	1.20
Weighted average common shares outstanding - basic		19,597			20,001			19,839			20,000

Net income (loss) per common share - diluted
Net income before extraordinary item - diluted	$	0.50		$	0.45		$	1.55		$	1.20
Extraordinary item		(1.49	)		—			(1.47	)		—
	$	(.99	)	$	0.45		$	0.08		$	1.20
Weighted average common shares outstanding - diluted		20,000			20,174			20,272			20,064

See accompanying notes to consolidated financial statements

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

NINE MONTHS ENDED SEPTEMBER 30, 2006

(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, 2006		13,336,031	$	133	$	75,967			(1,335	)	$	(73	)	$	(564	)	$	(5,116	)	$	62,503		$	132,850
Net Income																					1,585			1,585
Other comprehensive income																		13,766						13,766
Issuance of common stock		6,665		—		65			6,711			415												480
Repurchase of common stock, at cost									(667,342	)		(29,856	)											(29,856	)
Repayment of ESOP Loan															55									55
Stock option compensation						1,079																		1,079
Three-for-two split (Note 16)		6,664,598		67		(45	)														(67	)		(45	)
Balance, September 30, 2006		20,007,294	$	200	$	77,066			(661,966	)	$	(29,514	)	$	(509	)	$	8,650		$	64,021		$	119,914

See accompanying notes to consolidated financial statements

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2006

(in thousands)

(Unaudited)

	Nine Months Ended
	September 30,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,585		$	24,048
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		33,158			19,023
Amortization of deferred financing costs		2,008			2,138
Non-cash loss on derivative value		(990	)		(2,682	)
Non-cash compensation on long-term incentive plans		6,312			3,051
Minority interests		12,987			7,553
Distributions paid to minority interests of Atlas Pipeline Partners, L.P.		(27,940	)		(14,234	)
Gain on asset dispositions		(2,738	)		(80	)
Write down of note receivable		−			487
Deferred income taxes		(7,686	)		1,550
Changes in operating assets and liabilities		27,149			21,605
Net cash provided by operating activities		43,845			62,459

CASH FLOWS FROM INVESTING ACTIVITIES:
Business acquisition, net of cash acquired		(30,000	)		(195,262	)
Capital expenditures		(115,819	)		(82,303	)
Proceeds from sale of assets		7,602			135
Decrease (increase) in other assets		174			(287	)
Net cash used in investing activities		(138,043	)		(277,717	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings		109,750			358,248
Principal payments on debt		(144,805	)		(229,034	)
Payments to affiliate		—			(13,082	)
Issuance of Atlas Pipeline Partners, L.P. common and preferred units		59,610			91,720
Issuance of Atlas Pipeline Partners, L.P. senior notes		36,610			—
Proceeds from sale of Atlas Pipeline Holdings, L.P. initial public offering		74,492			—
Treasury shares repurchased		(29,856	)		—
Decrease in other assets		(2,066	)		(3,472	)
Net cash provided by financing activities		103,735			204,380

Increase (decrease) in cash and cash equivalents		9,537			(10,878	)
Cash and cash equivalents at beginning of period		55,155			29,159
Cash and cash equivalents at end of period	$	64,692		$	18,281

See accompanying notes to consolidated financial statements

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2006

(Unaudited)

NOTE 1 - BASIS OF PRESENTATION

Principles of Consolidation

The consolidated financial statements include the accounts of Atlas America, Inc. (the “Company” or “ATLS”) and all of its subsidiaries, which are wholly owned except for Atlas Pipeline Partners, L.P. (“Atlas Pipeline” or “APL”) and Atlas Pipeline Holdings, L.P. (“APL Holdings”). Atlas Pipeline is a master limited partnership in which the Company has a combined general and limited partner interest of 11% and 15% at September 30, 2006 and 2005, respectively. Ownership at September 30, 2006 is through APL Holdings, as on July 26, 2006, the Company contributed its ownership interest in Atlas Pipeline to APL Holdings. Concurrent with this transaction, APL Holdings issued 3,600,000 common units representing a 17.1% ownership interest. As a result, the Company now owns an 82.9% interest in APL Holdings, a limited partnership which owns a 2% general partner interest in Atlas Pipeline, all the incentive distribution rights in APL and 1,641,026 common units of APL.

The consolidated financial statements and the information and tables contained in the notes to the consolidated financial statements as of September 30, 2006 and for the three and nine months ended September 30, 2006 and 2005 are unaudited. 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 nine months ended September 30, 2006 may not necessarily be indicative of the results of operations for the full year ending December 31, 2006.

Change in Fiscal Year End

On June 15, 2006, the Company’s Board of Directors approved the change of the Company’s fiscal year end to December 31 from September 30. On July 24, 2006, the Company filed a transition report on Form 10-Q for the quarter ended December 31, 2005 pursuant to Rule 13a-10 of the Securities Exchange Act for transition period reporting. Accordingly, these consolidated financial statements reflect the Company’s new year end of December 31 and year-to-date amounts are for the nine month periods ended September 30, 2006 and 2005.

Reclassifications

Certain previously reported amounts in the three months and nine months ended September 30, 2005 consolidated financial statements have been reclassified to conform to the September 30, 2006 consolidated financial statement presentation. The reclassifications reflect the following changes summarized as follows:

•

Transmission, gathering, and processing revenue and gas and oil production expense have been reduced by the Company’s proportionate well ownership in these revenues and costs.

•

Administration and oversight revenue previously reported as general and administration reimbursements are now being reported as separate line items on the consolidated financial statements in accordance with a change in the Company's drilling agreements.

•

Exploration costs previously combined with gas and oil production expense are now being combined with general and administrative expense due to the immaterial amount of total costs incurred in relation to other line items on the consolidated financial statements.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2006

(Unaudited)

NOTE 1 - BASIS OF PRESENTATION - (Continued)

	Three Months Ended September 30, 2005
	(in thousands)
	Previously					Current
	Reported		Reclassification			Presentation
Transmission, gathering and processing revenue		97,992		(578	)		97,414
Administration and oversight revenue		285		1,567			1,852
Total revenue reclassification				989
Gas and oil production expense		2,403		(722	)		1,681
General and administrative expense		5,603		1,711			7,314
Total expense reclassification				989

	Nine Months Ended September 30, 2005
	(in thousands)
		Previously					Current
		Reported		Reclassification			Presentation
Transmission, gathering and processing revenue		223,055		(1,568	)		221,487
Administration and oversight revenue		285		7,151			7,436
Total revenue reclassification				5,583
Gas and oil production expense		7,268		(2,419	)		4,849
General and administrative expense		11,806		8,002			19,808
Total expense reclassification				5,583

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Reference is hereby made to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 2005, 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 quarterly report included herein.

Recently Issued Financial Accounting Standard

In September 2006, the SEC staff issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (“SAB 108”). SAB 108 was issued to provide consistency in how registrants quantify financial statement misstatements. The Company is required to and will initially apply SAB 108 in connection with the preparation of its annual financial statements for the year ending December 31, 2006. The Company does not expect the application of SAB 108 to have a material effect on its financial position and results of operations.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

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

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 158, Employer’s Accounting for Defined Benefit Pension and Other Post Retirement Plans (“SFAS 158”). SFAS 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit post retirement plan as an asset or liability, by recording the difference between the plan assets fair value and the benefit obligation. The employer must recognize after-tax gains and losses as a result of changes in the funded status as a component of other comprehensive income. The employer is also required to measure the funded status of a plan as of the date of its year end statements, and disclose in the notes to the statements additional information regarding the net periodic benefit costs. SFAS 158 is effective for the Company beginning January 1, 2007. The Company is currently evaluating the impact of its adoption of SFAS 158 on its financial position and 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 its adoption of SFAS 157 on its financial position and results of operations.

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements and provides guidance on the recognition, de-recognition and measurement of benefits related to an entity’s uncertain tax positions. FIN 48 is effective for the Company beginning January 1, 2007. The Company is currently evaluating the impact of its adoption of FIN 48 on its financial position and results of operations.

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 energy customers. At September 30, 2006 and December 31, 2005, 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, 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, 2006 and December 31, 2005 of $48.5 million and $71.6 million, respectively which are included in Accounts Receivable on its Consolidated Balance Sheets.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

NOTE 3 - COMPREHENSIVE INCOME

Comprehensive income 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 only changes in the fair value, net of taxes, of unrealized hedging gains and losses. A reconciliation of the Company’s comprehensive income for the periods indicated is as follows (in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006		2005
Net income (loss)	$	(19,876	)	$	9,088		$	1,585	$	24,048
Other comprehensive income (loss):
Unrealized holding gain (loss) on hedging contracts, net of tax of ($5,817), $2,253, ($8,088) and $3,803		9,873			(4,006	)		13,515		(6,762	)
Less reclassification adjustment for (gains) losses realized in net income, net of tax of ($324), ($406), ($215) and ($759)		553			722			251		1,349
Total other comprehensive income (loss)		10,426			(3,284	)		13,766		(5,413	)
Comprehensive income (loss)	$	(9,450	)	$	5,804		$	15,351	$	18,635

NOTE 4 - EARNINGS PER SHARE

Basic earnings per share is determined by dividing net income by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share 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 (shown in thousands).

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2006			2005		2006		2005
Net income (loss)	$	(19,876	)	$	9,088	$	1,585	$	24,048

Weighted average common shares outstanding-basic ⁽¹⁾		19,597			20,001		19,839		20,000
Dilutive effect of stock option and award plan ⁽¹⁾		403			173		433		64
Weighted average common shares-diluted ⁽¹⁾		20,000			20,174		20,272		20,064


(1)	The shares for the three months and nine months ended September 30, 2005 have been restated to reflect the three for two stock split on March 10, 2006.

NOTE 5 - PROPERTY AND EQUIPMENT

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

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

NOTE 5 - PROPERTY AND EQUIPMENT - (Continued)

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

	September 30,			December 31,
	2006			2005
Mineral interests:
Proved properties	$	1,443		$	2,308
Unproved properties		1,002			1,002
Wells and related equipment		323,930			273,725
Pipelines, processing and compression facilities		589,653			445,859
Rights-of-way		29,906			15,769
Land, building and improvements		8,431			7,799
Support equipment		5,226			4,201
Other		9,706			6,292
		969,297			756,955
Accumulated depreciation, depletion and amortization:
Oil and gas properties and pipelines		(123,244	)		(94,105	)
Other		(5,535	)		(4,503	)
		(128,779	)		(98,608	)
	$	840,518		$	658,347

On May 2, 2006, Atlas Pipeline acquired the remaining 25% ownership interest in NOARK for $69.0 million in cash, including the repayment of the $39.0 million of NOARK notes at the date of acquisition (see Note 13). Atlas Pipeline acquired the initial 75% ownership interest in NOARK for approximately $179.8 million in October 2005 (see Note 13). Due to the recent date of both acquisitions, the purchase price allocation is subject to adjustment and could change significantly as Atlas Pipeline continues to evaluate this allocation.

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,
	2006		2005
Deferred financing costs, net of accumulated amortization of $5,071 and $3,063	$	14,579	$	15,654
Investments		1,545		1,647
Security deposits		1,601		1,725
Long-term hedge receivable from Partnerships		1,156		9,340
Long-term hedge receivable		24,097		4,387
Other		123		79
	$	43,101	$	32,832

Deferred financing costs are recorded at cost and are amortized over the terms of the related loan agreements which range from three to ten years. Long-term hedge receivable from Partnerships represents amounts due from affiliated partnerships for unrealized long-term holding losses from hedging activities allocated to them.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

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

Intangible Assets

Customer contracts and relationships. At September 30, 2006, Atlas Pipeline had $26.1 million of intangible assets, net of accumulated amortization of $3.5 million which was recorded in connection with natural gas gathering contracts and customer relationships assumed in its acquisition of Elk City (see Note 13). 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. During the third quarter of 2006, Atlas Pipeline adjusted the preliminary purchase price allocation for NOARK and eliminated the previously estimated allocated value of customer contracts and customer relationships related to this acquisition based upon a preliminary finding by an independent valuation firm. Amortization expense on the customer contract and relationships intangible assets related to Elk City, which have estimated lives of eight and twenty years, respectively, and are being amortized on a straight-line basis, was $1.4 million and $492,000 for the nine months ended September 30, 2006 and 2005, respectively.

Partnership management and operating contracts. Included in intangible assets are partnership management and operating contracts acquired through acquisitions which are recorded at fair value on their acquisition dates. The Company 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, 2006 and 2005 was $659,000 and $467,000, respectively.

Aggregate estimated annual amortization expense for all of the contracts described above for the next five fiscal periods ending September 30 is as follows: 2007-$3.2 million; 2008-$3.2 million; 2009-$3.2 million; 2010-$3.1 million and 2011-$3.1 million.

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

	September 30, 2006					December 31, 2005
			Accumulated					Accumulated
	Cost		Amortization			Cost		Amortization
Customer contracts and relations	$	29,650	$	(3,517	)	$	56,950	$	(2,081	)
Partnership management and operating contracts		14,343		(8,912	)		14,343		(8,253	)
	$	43,993	$	(12,429	)	$	71,293	$	(10,334	)

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

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

Goodwill

The Company applies the provisions of SFAS No. 142 which requires that goodwill no longer be amortized, but instead evaluated for impairment at least annually. The evaluation of impairment under SFAS 142 requires the use of projections, estimates and assumptions as to the future performance of the Company’s operations, including anticipated future revenues, expected future operating costs and the discount factor used. Actual results could differ from projections, resulting in revisions to the Company’s assumptions and, if required, recognition of an impairment loss. The Company’s evaluation of goodwill at September 30, 2005 (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. A reconciliation of the Company’s goodwill for the periods indicated is as follows (in thousands).

	September 30,			December 31,
	2006			2005
Goodwill at beginning of period, net of accumulated amortization of $4,532	$	146,544		$	37,470
Adjustment to goodwill related to Atlas Pipeline acquisitions (see Note 13)		(47,938	)		109,074
Goodwill at end of period, net of accumulated amortization of $4,532	$	98,606		$	146,544

NOTE 7 - ASSET RETIREMENT OBLIGATIONS

The Company accounts for the estimated plugging and abandonment costs for its oil and gas properties in accordance with SFAS 143, Accounting for Asset Retirement Obligations.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
Asset retirement obligations, beginning of period	$	19,760		$	7,151		$	18,499		$	5,618
Liabilities incurred		490			―			1,616			120
Liabilities settled		(67	)		(53	)		(180	)		(133	)
Revision in estimates		―			10,501			―			11,789
Accretion expense		124			52			372			257
Asset retirement obligations, end of period	$	20,307		$	17,651		$	20,307		$	17,651

The above accretion expense is included in depreciation, depletion and amortization in the Company’s consolidated statements of operations and the asset retirement obligation liabilities are included in other liabilities in the Company’s consolidated balance sheets. The revision in estimate for the three months and nine months ended September 30, 2005 was due to increased estimated costs of plugging and abandoning wells.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

NOTE 8 - DEBT

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

	September 30,		December 31,
	2006		2005
Senior notes - Atlas Pipeline	$	286,005	$	250,000
Revolving credit facility - Atlas Pipeline		13,500		9,500
Installment notes - NOARK		—		39,000
Other debt		225		281
		299,730		298,781
Less current maturities		144		1,351
	$	299,586	$	297,430

Atlas Pipeline

Credit Facility. Atlas Pipeline has a $225.0 million credit facility with a syndicate of banks which matures in June 2011. The credit facility bears interest, at Atlas Pipeline’s option, at either (i) adjusted London Interbank Offered Rate (“LIBOR”) plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding credit facility borrowings at September 30, 2006 was 7.1%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $10.1 million was outstanding at September 30, 2006. These outstanding letter of credit amounts were not reflected as borrowings on the Company’s consolidated balance sheets. Borrowings under the credit facility are secured by a lien on and security interest in all of Atlas Pipeline’s property and that of its subsidiaries, and by the guaranty of each of its subsidiaries. The credit facility contains customary covenants, including restrictions on Atlas Pipeline’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; and enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. Atlas Pipeline is in compliance with these covenants as of September 30, 2006.

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

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

NOTE 8 - DEBT (Continued)

Senior Notes. In December 2005, Atlas Pipeline, issued $250.0 million of 10-year, 8.125% senior unsecured notes (“Senior Notes”) in a private placement transaction pursuant to Rule 144A and Regulation S under the Securities Act of 1933 for net proceeds of $243.1 million, after underwriting commissions and other transaction costs. In May 2006, Atlas Pipeline issued an additional $35.0 million of senior unsecured notes at 103% par value, with a resulting effective yield of approximately 7.6%, for net proceeds of $36.6 million including accrued interest and net of initial purchaser’s discount and other transaction costs. Interest on the Senior Notes is payable semi-annually in arrears on June 15 and December 15. The Senior Notes are redeemable at any time on or after December 15, 2010 at certain redemption prices, together with accrued unpaid interest to the date of redemption. In addition, prior to December 15, 2008, Atlas Pipeline may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The Senior Notes are also subject to repurchase by Atlas Pipeline at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales for which the net proceeds are not reinvested into Atlas Pipeline within 360 days. The Senior Notes are junior in right of payment to Atlas Pipeline’s secured debt, including Atlas Pipeline’s obligations under its credit facility.

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, 2006.

In connection with a Senior Notes registration rights agreement entered into by Atlas Pipeline, it agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission for the Senior Notes by April 19, 2006, (b) cause the exchange offer registration statement to be declared effective by the Securities and Exchange Commission by July 18, 2006, and (c) cause the exchange offer to be consummated by August 17, 2006. If Atlas Pipeline had not met the aforementioned deadlines, the Senior Notes would have been subject to additional interest, up to 1% per annum, until such time that the deadlines had been met. On April 19, 2006, Atlas Pipeline filed an exchange offer registration statement for the Senior Notes with the Securities and Exchange Commission, which was declared effective on July 11, 2006. The exchange offer was consummated on August 17, 2006, thereby fulfilling all of the requirements of the Senior Notes registration rights agreement by the specified dates.

Atlas America

Revolving Credit Facility. In April 2006, the Company increased its credit facility, which is led by Wachovia Bank, N.A. (“Wachovia”), to a maximum of $200.0 million. The revolving credit facility has a current borrowing base of $150.0 million which may be redetermined subject to changes in the Company’s oil and gas reserves. Up to $50.0 million of the facility may be in the form of standby letters of credit. The facility is secured by the Company’s assets and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at the Company’s option.

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

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

NOTE 8 - DEBT (Continued)

The Wachovia credit facility requires the Company to maintain specified ratios of current assets to current liabilities, interest coverage (as defined), and debt to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”). In addition, the facility limits sales, leases or transfers of assets and the incurrence of additional indebtedness. The facility limits the dividends payable by the Company, on a cumulative basis, to 50% of the Company’s net income from October 1, 2005 to the date of determination plus $5.0 million. The Company is in compliance with these covenants as of September 30, 2006. The facility terminates in April 2011, when all outstanding borrowings must be repaid. At September 30, 2006 and December 31, 2005, $1.5 million and $16.5 million, respectively, was outstanding under this facility under letters of credit which are not reflected as borrowings on the Company’s consolidated balance sheet.

On July 26, 2006, Atlas Pipeline Holding, L.P. (“AHD”), as borrower, and Atlas Pipeline GP, as guarantor, entered into a $50.0 million revolving credit facility (-0- outstanding at September 30, 2006) with Wachovia Bank, National Association, 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 Bank, National Association 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, 2006.

Annual debt principal payments over the next five years ending September 30 are as follows (in thousands):

2007	$	144
2008		67
2009		14
2010		—
2011 and thereafter		299,505
	$	299,730

NOTE 9 ─ 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 the Company’s financial condition or results of operations.

In October 2006, the Company tentatively settled a class action lawsuit filed in February 2000 in New York pertaining to the payment of royalty revenues to landowners. Under the terms of the settlement, the Company has agreed to pay $300,000, upgrade certain gathering systems and cap certain transportation expenses chargeable to the landowners.

At September 30, 2006, Atlas Pipeline is committed to expend approximately $23.2 million on pipeline extensions, compressor station upgrades and processing facility upgrades, including $2.1 million related to the Sweetwater gas plant, Atlas Pipeline's new gas processing plant which commenced operations in Beckham County, Oklahoma in September 2006.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

NOTE 10 - DERIVATIVE INSTRUMENTS

Atlas America. The Company from time to time enters into financial hedges in the form of natural gas futures and option contracts to hedge its exposure to changes in natural gas prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts 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 Company’s risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas 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. Derivatives are recorded on the balance sheet as assets and liabilities at fair value. 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 operations in the month the hedged gas is settled. 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.

At September 30, 2006, the Company had 119 open natural gas futures contracts related to natural gas sales covering 38.1 million mmbtus of natural gas, maturing through December 31, 2009 at a combined average settlement price of $8.85 per mmbtu. The Company recognized a gain of $2.0 million and $4.9 million on settled contracts covering natural gas production for the three months and nine months ended September 30, 2006, respectively, which is included within gas and oil production on the Company’s consolidated statements of operations. The Company recognized no gains or losses during the three months and nine months ended September 30, 2006 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges. The Company did not have any hedge gain or loss in 2005.

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

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

NOTE 10 - DERIVATIVE INSTRUMENTS (Continued)

Atlas Pipeline formally documents all relationships between hedging instruments and the items being hedged, including the risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. Atlas 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 Atlas Pipeline determines that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of correlation between the hedging instrument and the underlying commodity, Atlas Pipeline will discontinue hedge accounting for the derivative, and subsequent changes in fair value for the derivative, which is determined through the utilization of market data, will be recognized immediately into earnings.

Ineffective hedge gains or losses are recorded in the Company’s consolidated statements of operations while the hedge contracts are open and may increase or decrease until settlement of the contract. Atlas Pipeline recognized losses of $4.9 million and $2.5 million for the three months ended September 30, 2006 and 2005, respectively, and losses of $10.5 million and $4.4 million for the nine months ended September 30, 2006 and 2005, respectively, related to the settlement of qualifying hedge instruments. Atlas Pipeline also recognized a gain of $2.6 million and a loss of $800,000 for the three months ended September 30, 2006 and 2005, respectively, and a gain of $3.5 million and a loss of $700,000 for the nine months ended September 30, 2006 and 2005, respectively, related to the change in market value of non-qualifying or ineffective hedges. Such gains and losses are included within transmission, gathering and processing in the Company’s consolidated statements of operations.

At September 30, 2006 and December 31, 2005, the Company reflected a net hedging asset and liability on its balance sheets of $10.7 million and $41.5 million, respectively. Of the $8.7 million net gain in accumulated other comprehensive income at September 30, 2006, the Company will reclassify $4.5 million of gains to its consolidated statements of operations over the next twelve month period as these contracts expire, and $4.2 million of gains will be reclassified in later periods if the fair values of the instruments remain at current market values. Actual amounts that will be reclassified will vary as a result of future price changes.

At September 30, 2006, the Company (including Atlas Pipeline) had the following financial hedges in place:

Natural Gas Fixed-Price Swaps - Atlas⁽¹⁾

Twelve Month			Average		Fair Value
Period Ended	Volumes		Fixed Price		Asset⁽³⁾
September 30,	(MMBTU)⁽²⁾		(per MMBTU)		(in thousands)
2007		10,110,000	$	9.26	$	20,116
2008		14,640,000		8.75		9,945
2009		10,950,000		8.65		7,862
2010		2,430,000		8.61		1,650
					$	39,573

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

NOTE 10 - DERIVATIVE INSTRUMENTS (Continued)

Natural Gas Liquids Sales

Production			Average		Fair Value
Period Ended	Volumes		Fixed Price		Liability⁽⁴⁾
December 31,	(gallons)		(per gallon)		(in thousands)
2006		17,262,000	$	0.788	$	(1,908	)
2007		84,924,000		0.849		(2,344	)
2008		33,012,000		0.697		(5,659	)
2009		8,568,000		0.746		(1,244	)
					$	(11,155	)

Crude Oil Sales Options (associated with NGL volume)

			Associated		Average
Production	Crude		NGL		Crude		Fair Value
Period Ended	Volume		Volume		Strike Price		Liability⁽³⁾		Option Type
December 31,	(barrels)		(gallons)		(per barrel)		(in thousands)
2008		720,000		40,219,000	$	60.00	$	-		Puts purchased
2008		720,000		40,219,000		84.00		-		Calls sold
2009		720,000		40,219,000		60.00		-		Puts purchased
2009		720,000		40,219,000		81.00		-		Calls sold
							$	-

Natural Gas Sales

Production			Average		Fair Value
Period Ended	Volumes		Fixed Price		Liability⁽³⁾
December 31,	(MMBTU)⁽²⁾		(per MMBTU)		(in thousands)
2006		200,000	$	7.019	$	107
2007		1,080,000		7.255		(451	)
2008		240,000		7.270		(223	)
					$	(567	)

Natural Gas Basis Sales

Production			Average			Fair Value
Period Ended	Volumes		Fixed Price			Asset⁽³⁾
December 31,	(MMBTU)⁽²⁾		(per MMBTU)			(in thousands)
2006		300,000	$	(0.525	)	$	49
2007		1,080,000		(0.535	)		369
2008		240,000		(0.555	)		131
						$	549

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

NOTE 10 - DERIVATIVE INSTRUMENTS (Continued)

Natural Gas Purchases

Production			Average			Fair Value
Period Ended	Volumes		Fixed Price			Liability⁽³⁾
December 31,	(MMBTU)⁽²⁾		(per MMBTU)			(in thousands)
2006		720,000	$	8.384		$	(1,369	)
2007		6,960,000		8.855	⁽⁵⁾		(10,084	)
2008		3,336,000		8.872	⁽⁶⁾		(3,553	)
2009		2,400,000		8.450			(1,682	)
						$	(16,688	)

Natural Gas Basis Purchases

Production			Average			Fair Value
Period Ended	Volumes		Fixed Price			Asset⁽³⁾
December 31,	(MMBTU)⁽²⁾		(per MMBTU)			(in thousands)
2006		1,080,000	$	(0.835	)	$	189
2007		6,960,000		(0.903	)		272
2008		3,336,000		(1.042	)		272
2009		2,400,000		(0.600	)		130
						$	863

Crude Oil Sales

Production			Average		Fair Value
Period Ended	Volumes		Strike Price		Liability⁽³⁾
December 31,	(barrels)		(per barrel)		(in thousands)
2006		17,800	$	53.358	$	(179	)
2007		77,900		56.175		(900	)
2008		65,400		59.424		(621	)
2009		33,000		62.700		(159	)
					$	(1,859	)

Crude Oil Sales Options

Production			Average		Fair Value
Period Ended	Volumes		Strike Price		Liability⁽³⁾
December 31,	(barrels)		(per barrel)		(in thousands)		Option Type
2006		3,300	$	60.000	$	-		Puts purchased
2006		3,300		73.380		-		Calls sold
2007		13,200		60.000		-		Puts purchased
2007		13,200		73.380		-		Calls sold
2008		17,400		60.000		-		Puts purchased
2008		17,400		72.807		-		Calls sold
2009		30,000		60.000		-		Puts purchased
2009		30,000		71.250		-		Calls sold
					$	-
	Total net asset				$	10,716

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

NOTE 10 - DERIVATIVE INSTRUMENTS (Continued)

(1)		Represents ATLS’ hedged volumes. All others are related to Atlas Pipeline.
(2)		MMBTU represents million British Thermal Units.
(3)		Fair value based on forward NYMEX natural gas and light crude prices, as applicable.
(4)		Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas, light crude prices and propane prices.
(5)		Includes Atlas Pipelines’ premium received from its sale of an option for it to sell 4,800,000 mmbtu of natural gas at an average price of $15.25 per mmbtu for the year ended December 31, 2007, partially offset by its premium paid from its purchase of an option to purchase 1,200,000 mmbtu of natural gas at $26.00 per mmbtu.
(6)		Includes Atlas Pipelines’ premium received from its sale of an option for it to sell 936,000 mmbtu of natural gas for the year ended December 31, 2008 at $15.50 per mmbtu.

The following table sets forth the fair values of derivative instruments at the dates indicated (in thousands):

	September 30, 2006
	Book Value			Fair Value
Assets
Derivative instruments	$	47,838		$	47,838
	$	47,838		$	47,838

Liabilities
Derivative instruments		(37,122	)		(37,122	)
	$	(37,122	)	$	(37,122	)
	$	10,716		$	10,716

The fair value of the derivatives are included in the combined balance sheets as follows:

Unrealized hedge gains - short term	$	23,742
Other assets - long term (see Note 6)		24,097
Unrealized hedge loss - short term		(16,819	)
Unrealized hedge loss - long term		(20,304	)
	$	10,716

Of the $10.7 million net unrealized hedge gain, the Company’s retained portion of $8.7 million is included in accumulated other comprehensive income, and $2.1 million is reallocated to the Partnerships, to Minority Interest - Atlas Pipeline, and Deferred Tax Payable, and included in the balance sheet as components of:

Other assets (see Note 6)	$	1,156
Accrued liabilities - short term		(11,265	)
Unrealized hedge loss - long term		(12,052	)
Minority interest - Atlas Pipeline		25,593
Deferred income tax		(5,498	)
	$	(2,066	)

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

NOTE 11 - 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,
	2006			2005			2006			2005
Gas & Oil Production
Revenues	$	21,888		$	18,830		$	66,696		$	48,840
Costs and expenses		(2,315	)		(1,681	)		(6,437	)		(4,849	)
Segment profit	$	19,573		$	17,149		$	60,259		$	43,991

Partnership Management (a)
Revenues	$	59,449		$	41,126		$	160,323		$	121,685
Costs and expenses		(45,814	)		(32,323	)		(123,376	)		(94,250	)
Segment profit	$	13,635		$	8,803		$	36,947		$	27,435

Atlas Pipeline (b)
Revenues	$	109,280		$	96,252		$	320,867		$	218,322
Costs and expenses		(96,180	)		(86,173	)		(270,822	)		(194,105	)
Segment profit	$	13,100		$	10,079		$	50,045		$	24,217

Reconciliation of segment profit to net income before tax
Segment profit
Gas & Oil Production	$	19,573		$	17,149		$	60,259		$	43,991
Partnership Management		13,635			8,803			36,947			27,435
Atlas Pipeline		13,100			10,079			50,045			24,217
Total segment profit		46,308			36,031			147,251			95,643
General and administrative expenses		(12,814	)		(7,314	)		(33,197	)		(19,808	)
Compensation reimbursement-affiliate		(345	)		-			(1,041	)		(389	)
Depreciation, depletion and amortization		(12,442	)		(7,736	)		(33,158	)		(19,023	)
Other income (expense) - net		(4,435	)		(7,237	)		(27,792	)		(17,359	)
Net Income before tax	$	16,272		$	13,744		$	52,063		$	39,064

Balance Sheet	September 30,		December 31,
Goodwill	2006		2005
Gas & Oil Production	$	21,527	$	21,527
Partnership Management		13,639		13,639
Atlas Pipeline		63,440		111,378
	$	98,606	$	146,544
Total Assets
Gas & Oil Production	$	306,963	$	255,494
Partnership Management		45,684		34,321
Atlas Pipeline		769,413		736,977
Corporate other		64,902		29,388
	$	1,186,962	$	1,056,180

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

NOTE 11 - OPERATING SEGMENT INFORMATION (Continued)

(a)		Includes revenues and expenses from well construction, completion and services, administration and oversight and the Company’s transportation operations which do not meet the quantitative threshold for reporting segment information.

(b)		Includes revenues and expenses from Atlas Pipeline’s Appalachian and Mid-Continent operations, less revenues from affiliates of $6.2 million and $7.1 million for the three months ended September 30, 2005 and 2006, and revenues from affiliates of $16.6 million and $22.8 million for the nine months ended September 30, 2005 and 2006, respectively.

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

NOTE 12 - BENEFIT PLANS

Stock Incentive Plan. The Company adopted a Stock Incentive Plan (the “Plan”) in fiscal 2004 which authorized the granting of up to 2.0 million shares of the Company’s common stock to employees, affiliates, consultants and directors of the Company in the form of incentive stock options (“ISOs”), non-qualified stock options, stock appreciation rights (“SARs”), restricted stock and deferred units.

Prior to October 1, 2005, the Company accounted for stock-based compensation in accordance with the intrinsic value method as prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”). Accordingly, no compensation expense was recognized upon issuance of stock options under the Company’s stock incentive plan; however, compensation expense was recognized in connection with the issuance of deferred units granted under the incentive plan.

Adoption of SFAS No. 123R. In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment (“SFAS No. 123R”), a revision of SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS No. 123”). SFAS 123R supersedes APB No. 25 and its related implementation guidance, and requires entities to recognize compensation expense for awards of equity instruments to employees based on the grant-date fair value of those awards (with limited exceptions). SFAS No. 123R also requires the benefits of tax deductions in excess of recognized compensation expense to be reported as a financing cash flow, rather than as an operating cash flow as prescribed under the prior accounting rules.

The adoption of SFAS No. 123R at October 1, 2005 primarily resulted in a change in the Company’s method of recognizing the fair value of share-based compensation. Specifically, the adoption of SFAS No. 123R resulted in the recording of compensation expense for employee stock options. Results for the three months and nine months ended September 30, 2005 have not been restated. Had compensation expense for employee stock options granted under the Company’s stock incentive plan been determined based on fair value at the grant date consistent with SFAS No. 123, the Company’s net income for the three months and nine months ended September 30, 2005 would have been reduced to the pro forma amounts indicated below (in thousands, except per share data):

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

NOTE 12 - BENEFIT PLANS (Continued)

	Three Months Ended			Nine Months Ended
	September 30, 2005			September 30, 2005

Net income, as reported	$	9,088		$	24,048
Stock-based employee compensation expense reported in net income		—			—
Stock-based employee compensation expense determined under the fair value-based method for all awards, net of income taxes		(7,032	)		(7,147	)
Pro forma net income	$	2,056		$	16,901

Net income per common share:
Basic - as reported	$	.45		$	1.20
Basic - pro forma	$	.10		$	.85
Diluted - as reported	$	.45		$	1.20
Diluted - pro forma	$	.10		$	.84

Stock Options. In July 2005, options for 1,166,250 shares were issued under the Plan. Options under the Plan become exercisable as to 25% of the optioned shares each year after the date of grant, except options totaling 750,000 shares awarded to Messrs. Edward Cohen and Jonathan Cohen which are immediately exercisable, and expire not later than ten years after the date of grant. Additional options issued in January and April 2006 also vest over a service period of four years, expiring ten years from date of grant. Compensation cost is recorded on a graded-vesting schedule. For the three months and nine months ended September 30, 2006, the Company recorded compensation expense of $361,000 and $1.0 million, respectively for these options. At September 30, 2006, the Company had unamortized compensation expense of $4.5 million.

Transactions for stock options issued under the Plan are summarized as follows:

						Weighted
						Average		Aggregate
				Weighted		Remaining		Intrinsic
				Average		Contractual		Value
	Shares			Exercise Price		Term (in Years)		(in Thousands)
Outstanding at December 31, 2005		1,166,250		$	25.47		9.5
Granted		65,000		$	46.68		9.6
Exercised		(150	)	$	25.47		8.7
Forfeited or expired		(450	)	$	25.47		8.7
Outstanding at September 30, 2006		1,230,650		$	26.59		8.8	$	19,781
Options exercisable at September 30, 2006		853,913
Available for grant		754,348

The per share weighted average fair value of stock options granted during 2006 was calculated using the binomial (lattice) model with the following weighted average assumptions: (a) expected dividend yield 0%, (b) risk-free interest rate of 5.1%, (c) volatility of 37%, and (d) an expected life of 6.5 years.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

NOTE 12 - BENEFIT PLANS (Continued)

Deferred Stock Units. Under the Plan, non-employee directors of the Company are awarded deferred units that vest over a four year period. Each unit represents the right to receive one share of the Company’s common stock upon vesting. Units will vest sooner upon a change in control of the Company or death or disability of a grantee, provided the grantee has completed at least six month’s service. The fair value of the grants is based on the closing stock price on the grant date, and is being charged to operations over the requisite service periods using a straight-line attribution method. Upon termination of service by a grantee, all unvested units are forfeited. Non-cash compensation expense recognized during the three months ended September 30, 2006 and 2005 with respect to these units was $12,700 and $6,200, respectively. Non-cash compensation recognized during the nine months ended September 30, 2006 and 2005 was $29,400 and $14,600, respectively. Unamortized expense as of September 30, 2006 for deferred stock units is $181,000.

The following table summarizes the activity of deferred units for the nine months ended September 30, 2006:

						Weighted
				Weighted		Average		Aggregate
				Average		Remaining		Intrinsic
				Grant Date		Contractual		Value
	Units			Fair Value		Term (in Years)		(in Thousands)
Non-vested shares outstanding at December 31, 2005		10,985		$	13.65		2.8
Granted		1,916		$	46.97		3.7
Vested		(2,415	)	$	10.34		2.0
Forfeited		-		$	-		-
Non-vested shares outstanding at September 30, 2006		10,486		$	20.51		2.6	$	448

Restricted Stock Units. Restricted stock units are granted from time to time to employees of the Company. Each unit represents the right to receive one share of the Company’s common stock upon vesting. The units are issued to the Restricted Stock Plan when granted, and paid out to the employees on vesting. The units vest one-fourth at each anniversary date over a four year service period. The fair value of the grant is based on the closing price on the grant date, and is being expensed over the requisite service period using a straight line attribution method. Non-cash compensation expense recognized during the three and nine months ended September 30, 2006 with respect to these units was $4,400 and $11,700, respectively. There was no such expense in 2005. Unamortized expense as of September 30, 2006 for restricted units is $58,000.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

NOTE 12 - BENEFIT PLANS (Continued)

The following table summarizes the activity of restricted units for the nine months ended September 30, 2006:

					Weighted
			Weighted		Average		Aggregate
			Average		Remaining		Intrinsic
			Grant Date		Contractual		Value
	Units		Fair Value		Term (in Years)		(in Thousands)
Non-vested shares outstanding at December 31, 2005		-		-		-
Granted		1,500	$	46.71		3.3
Vested		-		-		-
Forfeited		-		-		-
Non-vested shares outstanding at September 30, 2006		1,500	$	46.71		3.3	$	64

Atlas Pipeline Long-Term Incentive Plan. Atlas Pipeline has a Long-Term Incentive Plan (“LTIP”), in which officers, employees and non-employee managing board members of its general partner and employees of the general partner’s affiliates are eligible to participate. Atlas Pipeline recognized $450,000 and $651,000 in compensation expense related to these grants and their associated distributions for the three months ended September 30, 2006 and 2005, respectively, and $1.3 million and $1.7 million for the nine months ended September 30, 2006 and 2005, respectively. At September 30, 2006, Atlas Pipeline had approximately $2.7 million of unrecognized compensation expense related to the unvested portion of these awards.

The following table represents the LTIP phantom unit activity for the periods indicated:

	Nine Months Ended
	September 30,
	2006			2005
Outstanding - beginning of period		110,128			58,329
Granted ⁽¹⁾		34,091			67,399
Vested		(31,152	)		(14,581	)
Forfeited		-			(1,019	)
Outstanding - end of period		113,067			110,128

⁽¹⁾

The weighted average price for phantom unit awards on the date of grant, which is utilized in the calculation of compensation expense and does not represent an exercise price to be paid by the recipient, was $43.05 for awards granted for the three months ended September 30, 2006, and $42.99 and $48.59 for awards granted for the nine months ended September 30, 2006 and 2005, respectively.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

NOTE 12 - BENEFIT PLANS (Continued)

Atlas Pipeline also has incentive compensation agreements which have granted awards to certain key employees retained from previously consummated acquisitions. These individuals are entitled to receive common units of Atlas Pipeline upon achievement of pre-determined performance targets. Atlas Pipeline recognized $1.2 million and $100,000 in compensation expense for the three months ended September 30, 2006 and 2005, respectively, and $3.8 million and $1.1 million for the nine months ended September 30, 2006 and 2005, respectively. At September 30, 2006, Atlas Pipeline had approximately $4.0 million of unrecognized compensation expense related to the unvested portion of these awards based on management’s estimate of probable outcomes of performance targets.

Employee Stock Ownership Plan. On June 30, 2005, the Company was spun-off from Resource America, Inc. (“RAI”) (NASDAQ:REXI), its former parent, in the form of a tax-free dividend to RAI shareholders. In connection with the spin-off from RAI, the Company established an Employee Stock Ownership Plan ("ESOP") in June 2005. The ESOP, which is a qualified non-contributory retirement plan, was established to acquire shares of the Company's common stock for the benefit of all employees who are 21 years of age or older and have completed 1,000 hours of service for the Company. In addition, as a result of the spin-off, the ESOP holds 181,000 shares of RAI stock, all of which are allocated to participants. In June 2006, 107,800 RAI shares in the Company’s ESOP were transferred to the RAI ESOP for 45,800 shares of Atlas America common stock in an even exchange. The Company loaned $602,000 (payable in quarterly installments of $18,508 plus interest at 7.5%) to the ESOP, which was used by the ESOP to acquire the remaining unallocated 40,375 shares of RAI common stock. Contributions to the ESOP are made at the discretion of the Company's Board of Directors. The cost of shares purchased by the ESOP but not yet allocated to participants is shown as a reduction of stockholders’ equity. The unearned benefits expense (a reduction in stockholders' equity) will be reduced by the amount of any loan principal payments made by the ESOP to the Company. Any dividends which may be paid on allocated shares will reduce retained earnings; dividends on unearned ESOP shares will be used to service the related debt.

The common stock purchased by the ESOP with the money borrowed is held by the ESOP trustee in a suspense account. On an annual basis, as the ESOP loan is paid down, a portion of the common stock will be released from the suspense account and allocated to participating employees. As of September 30, 2006, there were 250,400 shares allocated to participants and 51,000 shares which are unallocated. Compensation expense related to the plan amounted to $28,800 and $86,600 for the three months and nine months ended September 30, 2006, respectively. The fair value of unearned ESOP shares was $2.2 million at September 30, 2006.

Supplemental Employment Retirement Plan (“SERP”). In May 2004, the Company entered into an employment agreement with its Chairman of the Board, Chief Executive Officer and President, Edward E. Cohen, pursuant to which the Company has agreed to provide him with a SERP and with certain financial benefits upon termination of his employment. Under the SERP, Mr. Cohen will be paid an annual benefit equal to the product of (a) 6.5% multiplied by, (b) his base salary at the time of his retirement, death or other termination of employment with the Company, multiplied by, (c) the amount of years he shall be employed by the Company commencing upon the effective date of the SERP agreement, limited to an annual maximum benefit of 65% of his final base salary and a minimum of 26% of his final base salary. During the three months ended September 30, 2006 and 2005, operations were charged $40,300 and $40,000, and during the nine months ended September 30, 2006 and 2005, operations were charged $120,900 and $119,000, respectively, with respect to this commitment.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

NOTE 13 − ACQUISITIONS BY ATLAS PIPELINE

NOARK. On May 2, 2006, Atlas Pipeline acquired the remaining 25% equity ownership interest in NOARK from Southwestern, a wholly-owned subsidiary of Southwestern Energy Company (NYSE: SWN), for a net purchase price of $65.5 million, consisting of $69.0 million of cash to the seller (including the repayment of $39.0 million of outstanding NOARK notes at the date of acquisition), less the seller’s interest in NOARK’s working capital (including cash on hand and net payables to the seller) at the date of acquisition of $3.5 million, which was funded through borrowings under Atlas Pipeline’s senior secured credit facility. In October 2005, Atlas Pipeline acquired from Enogex, Inc., a wholly-owned subsidiary of OGE Energy Corp. (NYSE: OGE), all of the outstanding equity of Atlas Arkansas Pipeline, LLC, which owned the initial 75% interest in NOARK, for total consideration of $179.8 million, including $16.8 million for working capital adjustments and other related transaction costs. Atlas Pipeline funded this acquisition through borrowings under its senior secured credit facility. NOARK’s assets included a Federal Energy Regulatory Commission (“FERC”)-regulated interstate pipeline and an unregulated natural gas gathering system. 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 fair values at the date of acquisition (in thousands):

Cash and cash equivalents	$	16,215
Accounts receivable		11,091
Prepaid expenses		497
Property, plant and equipment		232,576
Other assets		140
Total assets acquired		260,519
Accounts payable and accrued liabilities		(50,689	)
Net assets acquired		209,830
Less: Cash and cash equivalents acquired		(16,215	)
Net cash paid for acquisition	$	193,615

Due to its recent date of both acquisitions, the purchase price allocation for NOARK is based upon preliminary data that is subject to adjustment and could change significantly as Atlas Pipeline continues to evaluate this allocation. Atlas Pipeline’s ownership interest in the results of NOARK’s operations associated with each acquisition is included within the Company’s consolidated financial statements from the respective date of acquisition.

Elk City. In April 2005, Atlas Pipeline acquired all of the outstanding equity interests in ETC Oklahoma Pipeline, Ltd. (“Elk City”), a Texas limited partnership, for $196.0 million, including related transaction costs. Elk City’s principal assets included approximately 300 miles of natural gas pipelines located in the Anadarko Basin in western Oklahoma, a natural gas processing facility in Elk City, Oklahoma and a gas treatment facility in Prentiss, Oklahoma. The acquisition was accounted for using the purchase method of accounting under SFAS No. 141. The following table presents the purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed, based on their fair values at the date of acquisition (in thousands):

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

NOTE 13 − ACQUISITIONS BY ATLAS PIPELINE (Continued)

Accounts receivable	$	5,587
Other assets		497
Property, plant and equipment		104,106
Intangible assets - customer contracts		12,390
Intangible assets - customer relationships		17,260
Goodwill		61,136
Total assets acquired		200,976
Accounts payable and accrued liabilities		(4,970	)
Net assets acquired	$	196,006

Atlas Pipeline recorded goodwill in connection with this acquisition as a result of Elk City’s significant cash flow and its strategic industry position. Elk City’s results of operations are included within Atlas Pipeline’s consolidated financial statements from its date of acquisition.

The following data presents unaudited pro forma revenues, net income and basic and diluted net income per share of common stock for the Company as if the acquisitions discussed above, Atlas Pipeline's equity offerings, the net proceeds of which were utilized to repay debt borrowed to finance the acquisitions (see Note 14), and the issuance of $286.0 million of 8.125% senior notes (See Note 8), had occurred on January 1, 2005. The Company has prepared these pro forma financial results for comparative purposes only. These pro forma financial results may not be indicative of the results that would have occurred if Atlas Pipeline had completed these acquisitions at January 1, 2005 or the results that will be attained in the future (in thousands, except per share amounts):

	Three Months Ended						Nine Months Ended
	September 30, 2005						September 30, 2005
	As		Pro Forma		Pro		As		Pro Forma		Pro
	Reported		Adjustments		Forma		Reported		Adjustments		Forma
Revenues	$	156,208	$	21,739	$	177,947	$	388,847	$	98,196	$	487,043
Net income		9,088		422		9,510		24,048		103		24,151
Net income per common share outstanding - basic		0.45		0.03		0.48		1.20		0.01		1.21
Weighted average common shares - outstanding basic		20,001		20,001		20,001		20,000		20,000		20,000
Net income per common share - diluted		0.45		0.02		0.47		1.20		0.00		1.20
Weighted average common shares - outstanding diluted		20,174		20,174		20,174		20,064		20,064		20,064

NOTE 14 - EQUITY OFFERINGS

On July 26, 2006, the Company contributed its ownership interests in Atlas Pipeline Partners GP, LLC, its wholly-owned subsidiary and the general partner of Atlas Pipeline, to Atlas Pipeline Holdings, L.P. (NYSE: AHD), a wholly-owned subsidiary. Concurrent with this transaction, Atlas Pipeline Holdings, L.P. issued 3,600,000 common units, representing a 17.1% ownership interest, in an initial public offering at a price of $23.00 per unit. The net proceeds of approximately $74.1 million after underwriting discounts and commissions were distributed to the Company.

On May 12, 2006, Atlas Pipeline sold 500,000 common units to Wachovia Securities, which offered the common units to public investors. The units, which were issued under Atlas Pipeline’s previously filed shelf registration statement, resulted in net proceeds of approximately $19.7 million, after underwriting commissions and other transaction costs. Atlas Pipeline utilized the net proceeds from the sale to partially repay borrowings under its credit facility made in connection with its recent acquisition of the remaining 25% interest in NOARK.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

September 30, 2006

(Unaudited)

NOTE 14 - ATLAS PIPELINE OFFERINGS (Continued)

On March 13, 2006, Atlas Pipeline sold 30,000 6.5% cumulative convertible preferred units representing limited partner interests to Sunlight Capital Partners, LLC, an affiliate of Elliott & Associates, for aggregate proceeds of $30.0 million. Atlas Pipeline also sold an additional 10,000 6.5% cumulative preferred units to Sunlight Capital Partners for $10.0 million on May 19, 2006, pursuant to Atlas Pipeline’s right to require Sunlight Capital Partners to purchase such additional units under the purchase agreement with Sunlight. The preferred units are entitled to receive dividends of 6.5% per annum commencing on March 13, 2007, which will accrue and be paid quarterly on the same date as the distribution payment date for Atlas Pipeline’s common units. The preferred units are convertible, at the holder’s option, into Atlas Pipeline’s common units commencing on the date immediately following the first record date after March 13, 2007 at a conversion price equal to the lesser of $41.00 or 95% of the market price of Atlas Pipeline’s common units as of the date of the notice of conversion. Atlas Pipeline may elect to pay cash rather than issue common units in satisfaction of a conversion request. Atlas Pipeline has the right to call the preferred units at a specified premium. Atlas Pipeline has filed a registration statement to cover the resale of the common units underlying the preferred units. The net proceeds from the initial issuance of the preferred units were used to fund a portion of Atlas Pipeline’s capital expenditures in 2006, including the construction of the Sweetwater gas plant and related gathering system. The proceeds from the issuance of the additional 10,000 preferred units were used to reduce indebtedness under Atlas Pipeline’s credit facility incurred in connection with the acquisition of the remaining 25% interest in NOARK.

NOTE 15 - REPURCHASE OF COMMON SHARES

In November 2005, the Company announced that its Board of Directors authorized a repurchase program through which the Company may repurchase up to $50.0 million of its common stock. Repurchases may be made from time to time through open market purchases or privately negotiated transactions at the discretion of the Company and in accordance with the rules of the Securities and Exchange Commission, as applicable. The amount and timing of any repurchases will depend on market and other relevant conditions. The Company repurchased 667,342 shares at a cost of $29.9 million during the nine months ended September 30, 2006.

NOTE 16 - COMMON STOCK SPLIT

On February 6, 2006, the Company’s Board of Directors approved a three-for-two split of the Company’s common stock effected in the form of a 50% stock dividend. All shareholders of record as of February 28, 2006 received one additional share of common stock for every two shares held on that date. The additional shares of common stock were distributed on March 10, 2006, in the form of a stock dividend. 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.

NOTE 17 - ATLAS ENERGY OFFERING

On July 28, 2006, the Company’s wholly-owned subsidiary, Atlas Energy Resources, LLC (“Atlas Energy”), filed a registration statement with the Securities and Exchange Commission for an initial public offering of 5,750,000 common units, representing an approximate 16.9% limited partner interest in it. Atlas Energy will own substantially all of the Company’s natural gas and oil exploration and production assets. The Company will enter into a management agreement with Atlas Energy and be responsible for its day-to-day operations.

NOTE 18 - EXTRAORDINARY ITEM

The Company received $74.5 million in proceeds associated with an initial public offering of Atlas Pipeline Holdings, L.P. (NYSE: AHD - “Atlas Holdings”) units on July 26, 2006. Although this transaction did not generate a gain in accordance with generally accepted accounting principles, the distribution of the net proceeds of $74.1 million to us generated a taxable gain which resulted in an extraordinary tax charge of $29.8 million, or $1.49 and $1.47 per share-diluted in the quarter and nine months ended September 30, 2006, respectively.

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 for fiscal 2005. 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.

General

Energy Development and Production

We focus on the development and production of natural gas and, to a lesser extent, oil principally in the Appalachian Basin. We sponsor and manage tax-advantaged investment partnerships, in which we co-invest, to finance the exploitation and development of our acreage.

As of September 30, 2006, our energy development and production assets consisted generally of:

•

interests in over 7,000 gross producing wells;

•

equity interests in 91 investment partnerships;

•

approximately 569,000 gross (516,000 net) acres, primarily in the Appalachian Basin, over half of which, or 308,000 gross (295,000 net) acres, are undeveloped; and

•

an interest in a joint venture that gives us the right to drill up to 300 net wells before June 30, 2007 on approximately 209,000 acres in Tennessee.

For the nine month period ended September 30, 2006, we produced 26,554 Mcfe/d. As of September 30, 2006, we had identified over 500 proved undeveloped drilling locations and over 2,400 additional potential drilling locations on our acreage and our Tennessee joint venture acreage.

We fund the drilling of natural gas and oil wells on our acreage by sponsoring and managing tax-advantaged investment partnerships. We generally structure our investment partnerships so that, upon formation of a partnership, we co-invest in and contribute leasehold acreage to it, enter into drilling and well operating agreements with it and become its managing general partner.

We derive our energy development and production revenues from our equity interest in the oil and gas produced by the investment partnerships as well as the fees paid by them to us for acting as the managing general partner as follows:

•	Gas and oil production. We receive an interest in each investment partnership proportionate to the value of our co-investment in it and the value of the acreage we contribute to it, typically 27% to 30% of the overall capitalization of a particular partnership. We also receive an incremental interest in each partnership, typically 7%, for which we do not make any additional capital contribution. Consequently, our equity interest in the reserves and production of each partnership is typically between 34% and 37%.

•	Partnership management. As managing general partner of our investment partnerships, we receive the following fees:

	•	Well construction and completion. For each well that is drilled by an investment partnership, we are reimbursed for the total cost to drill and complete the well and receive a 15% mark-up on those costs.

	•	Administration and oversight. For each well drilled by an investment partnership, we receive a fixed fee of approximately $15,000. Additionally, the partnerships pay us a monthly per well administrative fee of $75 for the life of the well. Because we co-invest in these partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

	•	Well services. Each partnership pays us a monthly per well operating fee, currently $275 to $285 (subject to inflationary increases), for the life of the well. Because we co-invest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

	•	Gathering. Each partnership pays us a gathering fee, generally equal to 10% of the gas sales price. We pay gathering fees, generally equal to 16% of the gas sales price, to Atlas Pipeline.

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Historically, natural gas and oil prices have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital.

Higher natural gas and oil prices have led to higher demand for drilling rigs, operating personnel and field supplies and services and have caused increases in the costs of those goods and services. To date, the higher sales prices have more than offset the higher drilling and operating costs.

We face the challenge of natural production declines. As initial reservoir pressures are depleted, natural gas production from a given well decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend in part on our ability to continue to add reserves in excess of production. Our business strategy for increasing our reserve base includes acquisitions of undeveloped properties or companies with significant amounts of undeveloped property. At September 30, 2006, we had $148.5 million available under our credit facility, which could be employed to finance such acquisitions.

Atlas Pipeline

In addition to our energy development and production business, we own 11% of Atlas Pipeline through our general partner interest and limited partner units.

Atlas Pipeline is active in the transmission, gathering and processing segments of the midstream natural gas industry. In the Mid-Continent region of Oklahoma, Arkansas, northern Texas, and the Texas panhandle, Atlas Pipeline owns and operates approximately 1,900 miles of active intrastate gas gathering pipelines and a 565-mile interstate natural gas pipeline. Atlas Pipeline also operates two gas processing plants and a treating facility in Velma, Elk City, Sweetwater, and Prentiss, Oklahoma where natural gas liquids and impurities are removed. In Appalachia, it owns and operates approximately 1,500 miles of natural gas gathering pipelines in western Pennsylvania, western New York, and eastern Ohio.

Recent Developments

The Company

On November 1, 2006, our wholly-owned subsidiary, Atlas Energy Resources, LLC (“Atlas Energy”), filed a second amendment to its registration statement with the Securities and Exchange Commission for an initial public offering of 6,075,000 common units, representing an approximate 16.9% limited partner interest in it. Atlas Energy will own substantially all of our natural gas and oil exploration and production assets. We will enter into a management agreement with Atlas Energy and be responsible for its day-to-day operations.

On June 15, 2006, our Board of Directors approved the change of our year end to December 31 from September 30. On July 24, 2006, we filed a transition report on Form 10-Q for the quarter ended December 31, 2005 pursuant to Rule 13a-10 of the Securities and Exchange Commission for transition period reporting. Accordingly, our consolidated financial statements reflect our new year end of December 31 and year-to-date amounts are for the nine month periods ended September 30, 2006 and 2005. We will file our 2006 calendar year Form 10-K on or before March 16, 2007.

In April 2006, we increased our credit facility, which is led by Wachovia Bank, N.A. (“Wachovia”), to a maximum of $200.0 million. The revolving credit facility has a current borrowing base of $150.0 million which may be redetermined subject to changes in our oil and gas reserves. Up to $50.0 million of the facility may be in the form of standby letters of credit. The facility is secured by our assets and bears interest at either the base rate plus the applicable margin or at the adjusted London Interbank Offered Rate (“LIBOR”) plus the applicable margin, elected at our option.

The Wachovia credit facility requires us to maintain specified ratios of current assets to current liabilities, interest coverage (as defined) and debt to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”). In addition, the facility limits sales, leases or transfers of assets and the incurrence of additional indebtedness. The facility limits the dividends payable by us, on a cumulative basis, to 50% of our net income from October 1, 2005 to the date of determination plus $5.0 million. The facility terminates in April 2011, when all outstanding borrowings must be repaid. At September 30, 2006 and December 31, 2005, $1.5 million was outstanding under this facility in the form of letters of credit which are not reflected as borrowings on the Company’s consolidated balance sheet.

On February 6, 2006, our Board of Directors approved a three-for-two stock split effected in the form of a 50% stock dividend. Shareholders of record as of February 28, 2006, received one additional share of common stock for each two shares of common stock they owned on that date. The shares were distributed on March 10, 2006. After the split, there were approximately 20.0 million shares of our common stock outstanding and the adjusted per-share stock price was reported by the Nasdaq Stock Market, effective March 13, 2006.

Atlas Pipeline Holdings

On July 26, 2006, we contributed our ownership interests in Atlas Pipeline Partners GP, LLC, our wholly-owned subsidiary to Atlas Pipeline Holdings, L.P. (NYSE: AHD), a wholly-owned subsidiary. Concurrent with this transaction, Atlas Pipeline Holdings, L.P. issued 3,600,000 common units, representing a 17.1% ownership interest, in an initial public offering at a price of $23.00 per unit. Substantially all of the net proceeds from this offering were distributed to us.

On. July 26, 2006, Atlas Pipeline Holding, L.P., as borrower, and Atlas Pipe GP, as guarantor, entered into a $50.0 million revolving credit facility (-0- outstanding at September 30, 2006) with Wachovia Bank, National Association, 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 Bank, National Association prime rate, except that no more than five LIBOR loans may be outstanding at any time. Borrowings under thecredit 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, 2006.

Atlas Pipeline

On September 27, 2006, Atlas Pipeline announced the commencement of operations of its new gas processing plant and gathering system, or Sweetwater plant, in Beckham County, Oklahoma. The Sweetwater plant, with a processing capacity of 120 MMcf/d, is located west of its Elk City gas plant, and was built to further access natural gas production actively being developed in western Oklahoma and the Texas panhandle.

In May 2006, Atlas Pipeline acquired the remaining 25% equity ownership interest in NOARK from Southwestern for a net purchase price of $65.5 million, consisting of $69.0 million of cash to the seller (including the repayment of $39.0 million of outstanding NOARK notes at the date of acquisition), less the seller’s interest in working capital at the date of acquisition of $3.5 million. In October 2005, Atlas Pipeline acquired from Enogex, a wholly-owned subsidiary of OGE Energy Corp., all of the outstanding equity of Atlas Arkansas, which owned the initial 75% interest in NOARK, for $163.0 million, plus $16.8 million for working capital adjustments and related transaction costs. NOARK’s principal assets include the Ozark Gas Transmission system, a 565-mile interstate natural gas pipeline, and Ozark Gas Gathering, a 365-mile natural gas gathering system.

On May 12, 2006, Atlas Pipeline sold 500,000 common units to Wachovia Securities, which has offered the common unit to public investors. The units, which were issued under its previously filed shelf registration statement, resulted in net proceeds of approximately $19.7 million, after underwriting commissions and other transaction costs. Atlas Pipeline utilized the net proceeds from the sale to partially repay borrowings under its credit facility made in connection with its recent acquisition of the remaining 25% interest in NOARK.

Atlas Pipeline has an effective shelf registration statement with the Securities and Exchange Commission that permits it to periodically issue equity and debt securities for a total value of up to $500 million. As of September 30, 2006, $352.1 million remains available for issuance under the shelf registration statement. However, the amount, type and timing of any offerings will depend upon, among other things, its funding requirements, prevailing market conditions, and compliance with its credit facility covenants.

On March 13, 2006, Atlas Pipeline sold 30,000 6.5% cumulative convertible preferred units representing limited partner interests to Sunlight Capital Partners, LLC, an affiliate of Elliott & Associates, for aggregate proceeds of $30.0 million. Atlas Pipeline also sold an additional 10,000 6.5% cumulative preferred units to Sunlight Capital Partners for $10.0 million on May 19, 2006, pursuant to its right to require Sunlight Capital Partners to purchase such additional units under the purchase agreement with Sunlight. The preferred units are entitled to receive dividends of 6.5% per annum commencing on March 13, 2007, which will accrue and be paid quarterly on the same date as the distribution payment date for our common units. The preferred units are convertible, at the holder’s option, into common units commencing on the date immediately following the first record date after March 13, 2007 at a conversion price equal to the lesser of $41.00 or 95% of the market price of our common units as of the date of the notice of conversion. Atlas Pipeline may elect to pay cash rather than issue common units in satisfaction of a conversion request. Atlas Pipeline has the right to call the preferred units at a specified premium. Atlas Pipeline has also agreed to file a registration statement to cover the resale of the common units underlying the preferred units. The net proceeds from the initial issuance of the preferred units was used to fund a portion of its capital expenditures in 2006, including the construction of the Sweetwater gas plant and related gathering system. The proceeds from the issuance of the additional 10,000 preferred units was used to reduce indebtedness under its credit facility incurred in connection with the acquisition of the remaining 25% interest in NOARK. The preferred units are reflected on our consolidated balance sheet as Minority Interest. Dividends accrued and paid on the preferred units and any premium paid upon their redemption, if any, will be recognized as a reduction to Atlas Pipeline’s net income.

Atlas Pipeline has a $225.0 million credit facility with a syndicate of banks which matures in June 2011. The credit facility bears interest, at its option, at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The applicable margin ranges from 0.25% to 1.5% for base rate loans and 1.25% to 2.5% for LIBOR loans. The weighted average interest rate on the outstanding borrowings under the credit facility was 7.1% at September 30, 2006. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $10.1 million was outstanding at September 30, 2006. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheet. Borrowings under the credit facility are secured by a lien on and security interest in all of its property and that of its wholly-owned subsidiaries, and by the guaranty of each of its wholly-owned subsidiaries. The credit facility contains customary covenants, including restrictions on Atlas Pipeline’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or 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, 2006.

The credit facility requires Atlas Pipeline to maintain a ratio of senior secured debt (as defined in the credit facility) to EBITDA (as defined in the credit facility) of not more than 4.0 to 1.0; a funded debt (as defined in the credit facility) to EBITDA ratio of not more than 5.25 to 1.0; and an interest coverage ratio (as defined in the credit facility) of not less than 3.0 to 1.0. The credit facility defines EBITDA to include pro forma adjustments, acceptable to the administrator of the facility, following material acquisitions.

In December 2005, Atlas Pipeline issued $250.0 million of 10-year, 8.125% senior unsecured notes (“Senior Notes”) in a private placement transaction pursuant to Rule 144A and Regulation S under the Securities Act of 1933 for net proceeds of $243.1 million, after underwriting commissions and other transaction costs. In May 2006, Atlas Pipeline issued an additional $35.0 million of senior unsecured notes at 103% par value, with a resulting effective yield of approximately 7.6%, for net proceeds of $36.6 million. 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 it at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if it does not reinvest the net proceeds within 360 days. The Senior Notes are junior in right of payment to Atlas Pipeline’s secured debt, including its obligations under the credit facility.

In connection with a Senior Notes registration rights agreement entered into by Atlas Pipeline, it agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission for the Senior Notes by April 19, 2006, (b) cause the exchange offer registration statement to be declared effective by the Securities and Exchange Commission by July 18, 2006, and (c) cause the exchange offer to be consummated by August 17, 2006. If it does not meet the aforementioned deadlines, the Senior Notes will be subject to additional interest, up to 1% per annum, until such time that the deadlines have been met. On April 19, 2006, Atlas Pipeline filed an exchange offer registration statement for the Senior Notes with the Securities and Exchange Commission, which was declared effective on July 11, 2006. The exchange offer was consummated on August 17, 2006, thereby fulfilling all of the requirements of the Senior Notes registration rights agreement by the specified dates.

General Trends and Outlook

The Company

We expect our development and production of natural gas and oil business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

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

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

Impact of inflation. Inflation in the United States did not have a material impact on our results of operations for the nine-month period ended September 30, 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.

Atlas Pipeline

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

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, flexibility, 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, its. Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours. 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 it provides an integrated and responsive package of midstream services, while some of its 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 its regions of operations.

As a result of its percentage of proceeds, or POP, and keep whole contracts, Atlas Pipeline’s 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.

Results of Operations for the Three Months and Nine Months Ended September 30, 2006 and 2005

Well Construction and Completion

Our well construction and completion revenues and costs and expenses incurred represent the billings and costs associated with completion of wells for 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,
	2006			2005			2006			2005
Average construction and completion revenue per well	$	301		$	220		$	295		$	217
Average construction and completion cost per well		262			191			256			188
Average construction and completion gross profit per well	$	39		$	29		$	39		$	29

Gross profit margin	$	6,604		$	4,640		$	17,652		$	13,537

Gross margin percent		13	%		13	%		13	%		13	%

Net wells drilled⁽¹⁾		168			162			459			479

(1)

Reflects net wells drilled for investment partnerships.

Our well construction and completion margin was $6.6 million and $17.7 million in the three months and nine months ended September 30, 2006, an increase of $2.0 million (42%) and $4.2 million (30%) from $4.6 million and $13.5 million in the three months and nine months ended September 30, 2005, respectively. During the three months ended September 30, 2006, the increase of $2.0 million in gross margin was attributable to an increase in the gross profit per well ($1.7 million) and the number of wells drilled ($238,000). In the nine months ended September 30, 2006, the increase of $4.2 million was attributable to an increase in the gross profit per well ($4.9 million) partially offset by a decrease in the number of wells drilled ($767,000). Since our drilling contracts are on a “cost plus” basis (typically cost plus 15%), an increase in our average cost per well also results in an increase in our average revenue per well. The increase in our average cost per well in the three months and nine months ended September 30, 2006 resulted from an increase in the cost of tangible equipment, leases, site preparation and reclamation expenses, as well as increased costs due to drilling into deeper formations.

It should be noted that “Liabilities associated with drilling contracts” on our balance sheet includes $71.6 million of funds raised in our investment programs during the current year that have not been applied to the completion of wells as of September 30, 2006 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 by March 31, 2007. We completed our $200.0 million registered partnership offering in August 2006 for a total of $147.6 million raised in the nine months ended September 30, 2006. We anticipate raising an additional $71.0 million in the fourth quarter 2006, for a total of $218.6 million raised in calendar year 2006.We anticipate oil and gas prices will continue to favorably impact our fundraising and therefore our well construction and completion revenues in the twelve months ending September 30, 2007.

Gas and Oil Production

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
Production revenues (in thousands):
Gas ⁽¹⁾	$	19,402		$	16,460		$	59,332		$	42,679
Oil	$	2,489		$	2,344		$	7,323		$	6,097

Production volume:
Gas (mcf/day) ^{(1) (2)(3)}		25,955			22,724			24,064			21,097
Oil (bbls/day)		416			415			415			428
Total (mcfe/day)⁽³⁾		28,451			25,214			26,554			23,665

Average sales prices:
Gas (per mcf)^{(3) (4)}	$	8.13		$	7.87		$	9.03		$	7.41
Oil (per bbl)⁽³⁾	$	65.01		$	61.37		$	64.59		$	52.23

Production costs ⁽⁵⁾:
As a percent of production revenues		11	%		9	%		10	%		10	%
Per mcfe ⁽³⁾	$	.88		$	.72		$	.89		$	.75

Depletion per mcfe ⁽³⁾	$	2.14		$	1.65		$	2.04		$	1.47

(1)	Excludes 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)	“Mcf” and “mmcf” means thousand cubic feet and million cubic feet; “mcfe” and “mmcfe” means thousand cubic feet equivalent and million cubic feet equivalent, and “bbls” means barrels. Bbls are converted to mcfe using the ratio of six mcfs to one bbl.
(4)	Our average sales price before the effects of financial hedging was $7.32 and $8.10 for the three months and nine months ended September 30, 2006. We did not have any financial hedges in the three months and nine months ended September 30, 2005.
(5)	Production costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, severance taxes, insurance and production overhead.

Our natural gas revenues were $19.4 million and $59.3 million in the three months and nine months ended September 30, 2006, an increase of $2.9 million (18%) and $16.6 million (39%) from $16.5 million and $42.7 million in the three months and nine months ended September 30, 2005. The increase in the three months and nine months ended September 30, 2006 was attributable to an increase in the volume of natural gas produced of 14% and 14% and an increase in the average sales price of natural gas of 3% and 22% in the three months and nine months ended September 30, 2006, respectively. The $2.9 million increase in gas revenues in the three months ended September 30, 2006 as compared to the prior period consisted of $2.4 million attributable to an increase in production volumes, and $527,000 attributable to increases in natural gas sales prices. The $16.6 million increase in natural gas revenues in the nine months ended September 30, 2006 as compared to the prior year period consisted of $9.3 million attributable to increases in natural gas sales prices and $7.3 million attributable to increased production volumes.

The increase in our gas production volumes resulted from production associated with new wells drilled for our investment partnerships. We believe that gas volumes will be favorably impacted in the remainder of 2006 as ongoing projects to extend and enhance our gathering systems in the Appalachian Basin are completed and wells drilled are connected in these areas of expansion.

Our oil revenues were $2.5 million and $7.3 million in the three months and nine months ended September 30, 2006, an increase of $145,000 (6%) and $1.2 million (20%) from $2.3 million and $6.1 million in the three months and nine months ended September 30, 2005, primarily due to an increase in the average sales price of oil of 6% and 24% for the three months and nine months ended September 30, 2006 as compared to the prior year similar periods. The $145,000 increase in oil revenues in three months ended September 30, 2006 as compared to the prior year period consisted of $139,000 attributable to increases in sales prices and $6,000 attributable to increased production volumes. The $1.2 million increase in oil revenues for the nine months ended September 30, 2006 as compared to the prior year period consisted of $1.4 million attributable to increases in sales prices partially offset by a decrease of $217,000 attributable to lower production volumes.

Our production costs were $2.3 million and $6.4 million in the three months and nine months ended September 30, 2006, an increase of $634,000 (38%) and $1.6 million (33%) from $1.7 million and $4.8 million in the three months and nine months ended September 30, 2005. These increases are a result of an increase in labor and maintenance costs associated with an increase in the number of wells we own and operate from the prior year period.

Transmission, Gathering and Processing

Our transmission, gathering and processing revenues and related expenses for the three months and nine months ended September 30, 2006 increased significantly from the prior year periods due to Atlas Pipeline’s acquisitions of Elk City on April 15, 2005 and NOARK on October 31, 2005 and May 2, 2006.

Our revenues increased $14.4 million (15%) and $106.4 million (48%) to $111.8 million and $327.9 million for the three months and nine months ended September 30, 2006 from $97.4 million and $221.5 million for the three months and nine months ended September 30, 2005, primarily due to contributions from Elk City and NOARK.

Our expenses increased $10.0 million (12%) and $76.9 million (40%) to $96.2 million and $271.0 million for the three months and nine months ended September 30, 2006 from $86.2 million and $194.1 million for the three months and nine months ended September 30, 2005, primarily due to acquisitions.

Administration and Oversight

Our administration and oversight fees represent supervision and administrative charges for construction and completion and ongoing administration of wells drilled for our investment partnerships. For each well drilled for our investment partnerships, we receive a fixed fee of approximately $15,000 and generally an ongoing monthly per well fee of $75. Due to a change in our more recent drilling agreements, these fees are shown as separate lines on our September 30, 2006 consolidated statements of operations rather than as reimbursement of our general and administrative costs. We have reclassified the three month and nine month ended September 30, 2005 amounts to conform to our current presentation.

Our revenues were $3.0 million and $8.5 million for the three months and nine months ended September 30, 2006 compared to $1.9 million and $7.4 million for the three and nine months ended September 30, 2005, an increase of $1.1 million (61%) and $1.1 (14%) primarily due to an increase in the number of wells we manage for our investment partnerships.

Well Services

Our well services revenues were $3.3 million and $9.5 million in the three months and nine months ended September 30, 2006, an increase of $814,000 (32%) and $2.2 million (30%) from $2.5 million and $7.3 million in the three months and nine months ended September 30, 2005. These increases resulted from an increase in the number of wells operated for our investment partnerships due to additional wells drilled in the three and nine months ended September 30, 2006.

Our well services expenses were $1.8 and $5.5 million in the three months and nine months ended September 30, 2006, an increase of $385,000 (28%) and $1.5 million (39%) from $1.4 million and $4.0 million in the three months and nine months ended September 30, 2005. 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.

Other Income, Costs and Expenses

Our general and administrative expenses were $12.8 million and $33.2 million in the three months and nine months ended September 30, 2006, an increase of $5.5 million and $13.4 million from $7.3 million and $19.8 million in the three months and nine months ended September 30, 2005, respectively. These expenses include, among other things, salaries and benefits not allocated to a specific energy activity, costs of running our energy corporate office, partnership syndication activities and outside services.

The increase of $5.5 million in the three months ended September 3, 2006 is principally attributable to the following:

•

exploration costs increased $1.1 million due to the increase in the costs of our land department as we acquire additional well drilling sites;

•

general and administrative expenses related to Atlas Pipeline’s min-continent operations increased $2.1 million primarily as a result of non-cash compensation expense and higher costs associated with the management of the NOARK acquisition;

•

salaries and wages increased $1.2 million due to the increase in executive salaries and in the number of employees as a result of our spin-off from RAI; and

•

professional and legal fees increased $790,000 primarily due to higher audit fees and implementation of Sarbanes-Oxley Section 404 compliance.

The increase of $13.4 million in the nine months ended September 30, 2006 is principally attributable to the following:

•

exploration costs increased $1.4 million due to the increase in the costs of our land department as we acquire additional well drilling sites;

•

general and administrative expenses related to Atlas Pipeline’s mid-continent operations increased $5.6 million primarily as a result of non-cash compensation expense and higher costs associated with the management of the NOARK acquisition;

•

salaries and wages increased $2.0 million due to the increase in executive salaries and in the number of employees as a result of our spin-off from RAI.

•

net syndication expenses increased $1.9 million as we continue to expand our syndication activities and the drilling funds we raise in our public and private partnerships;

•

professional and legal fees increased $1.6 million primarily due to higher audit fees and implementation of Sarbanes-Oxley Section 404 compliance; and

•

directors’ fees increased $900,000 as a result of our spin-off from our former RAI.

Our depletion of oil and gas properties as a percentage of oil and gas revenues was 26% and 22% in the three months and nine months ended September 30, 2006, respectively, compared to 20% and 19% in the three months and nine months ended September 30, 2005, respectively. Depletion expense per mcfe was $2.14 and $2.04 in the three months and nine months ended September 30, 2006, an increase of $.49 (30%) and $.57 (39%) per mcfe from $1.65 and $1.47 in the three months and nine months ended September 30, 2005, respectively. Increases in our depletable basis and production volumes caused depletion expense to increase $1.8 million (47%) and $5.3 million (56%) to $5.6 million and $14.8 million in the three months and nine months ended September 30, 2006, respectively, compared to $3.8 million and $9.5 million in the three months and nine months ended September 30, 2005, respectively. 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 increased $2.9 million (74%) and $8.8 million (92%), to $6.8 million and $18.3 million in the three months and nine months ended September 30, 2006, respectively, compared to $3.9 million and $9.5 million in the three months and nine months ended September 30, 2005, respectively. This was primarily due to the increased asset base associated with Atlas Pipeline’s acquisitions of Elk City and NOARK.

Our interest expense was $5.9 million and $19.4 million in the three months and nine months ended September 30, 2006, an increase of $2.3 million and $9.6 million from $3.6 million and $9.8 million in the three months and nine months ended September 30, 2005. Atlas Pipeline incurred interest expense of $5.7 million and $18.2 million in the three months and nine months ended September 30, 2006 related primarily to its May 2006 and December 2005 issuance of the Senior Notes. This increase was partially offset by a decrease in interest expense associated with borrowings under its credit facility.

At September 30, 2006, we own 11% of the partnership interest in Atlas Pipeline through our general partner interest and limited partner units. Our ownership interest decreased 8% from 19% at September 30, 2005 as a result of the sale of 17.1% of Atlas Pipeline Holdings, L.P. (“AHD”) our wholly-owned subsidiary, in an initial public offering on July 26, 2006. Our interest also decreased due to Atlas Pipeline’s issuance of $30.0 million 6.5% cumulative preferred units on March 13, 2006 and $10.0 million on May 19, 2006.

Because we control the operations of APL Holdings and Atlas Pipeline, we include them in our consolidated financial statements and show the ownership by the public as a minority interests. The minority interest in their earnings was $2.0 million and $13.0 million for the three months and nine months ended September 30, 2006, as compared to $3.8 million and $7.6 million for the three months and nine months ended September 30, 2005, a decrease of $1.8 million and an increase of $5.4 million. The increase for the nine months ended September 30, 2006 was a result of an increase in the percentage interest of public unit holders and an increase in their net income, as discussed above.

Our effective tax rate was 39% and 40% for the three months and nine months ended September 30, 2006 as compared to 34% and 38% for the three months and nine months ended September 30, 2005. In addition, we incurred a $29.8 million extraordinary income tax charge on the taxable gain associated with the receipt of $74.1 million from APL Holdings as a result of the sale of a 17.1% interest in APL Holdings for which they received $74.5 million in net proceeds after offerings costs in the three months ended September 30, 2006. For the nine months ended September 30, 2005, we incurred a $1.2 million income tax charge related to our spin-off from Resource America.

Liquidity and Capital Resources

General. We fund our development and production operations with a combination of cash generated by operations, capital raised through drilling investment partnerships and, if required, use of our credit facility. We fund our transmission, gathering and processing operations, which are conducted through Atlas Pipeline, through a combination of cash generated by operations, APL Holding’s and Atlas Pipeline’s credit facilities and the sale of their equity. The following table sets forth our sources and uses of cash (in thousands):

	Nine Months Ended
	September 30,
	2006			2005
Provided by operations	$	43,845		$	62,459
Used in investing activities		(138,043	)		(277,717	)
Provided by financing activities		103,735			204,380
Increase (decrease) in cash and cash equivalents	$	9,537		$	(10,878	)

We had $64.7 million in cash and cash equivalents at September 30, 2006, as compared to $55.2 million at December 31, 2005. Our level of cash is dependent on the timing of funds raised for our drilling investment partnerships at any balance sheet date. We raised $147.6 million during the nine months ended September 30, 2006. Our ratio of earnings from continuing operations before income taxes, minority interest and interest expense to fixed charges was 4.3 to 1 in the nine months ended September 30, 2006 as compared to 5.8 to 1 in the nine months ended September 30, 2005. We had a working capital deficit of $66.5 million at September 30, 2006, an increase of $5.6 million from the December 31, 2005 of $60.9 million.

Our long-term debt (including current maturities) was 250% and 225% of our total equity at September 30, 2006 and December 31, 2005, respectively. Since December 31, 2005, total stockholders’ equity has decreased by $12.9 million and total debt has increased by $949,000. Stockholders’ equity decreased principally due to stock repurchases of $29.9 million partially offset by a gain in other comprehensive income of $13.8 million and net income of $1.6 million for the nine months ended September 30, 2006.

On June 16, 2006 we increased the borrowing base under our credit facility to $150.0 million. At September 30, 2006, we had $148.5 million available on this credit facility. Atlas Pipeline had no outstanding balance on its $225.0 million credit facility and $214.9 million available at September 30, 2006. APL Holdings had no amounts outstanding and $50.0 million available under its credit facility at September 30, 2006.

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, interest rates and our ability to raise funds from our drilling investment partnerships. Net cash provided by operating activities decreased $18.7 million in the nine months ended September 30, 2006 to $43.8 million from $62.5 million in the nine months ended September 30, 2005, substantially as a result of the following:

	•	a decrease in net income before depreciation and amortization of $8.5 million in the nine months ended September 30, 2006 as compared to the prior year period, principally as a result of higher general and administrative expenses and a one-time extraordinary income tax charge of $29.8 million related to the distribution of proceeds to us of $74.1 million from APL Holdings upon the sale of its units;

	•	an increase in non-cash items of $4.9 million related to losses on APL’s hedge values and compensation expense resulting from grants under long-term incentive plans and gain on the sale of certain pipelines within the Velma System;

	•	changes in minority interests and distributions paid to minority interests decreased cash flow by $8.3 million due to an increase in Atlas Pipeline’s earnings and our decreased ownership percentage, offset by higher distributions paid to minority interests;

	•	changes in our deferred tax liability decreased cash flow by $9.2 million as compared to the nine months ended September 30, 2005 which reflects the impact of timing differences between accounting and tax records; and

	•	changes in operating assets and liabilities increased operating cash flow by $5.5 million in the nine months ended September 30, 2006, compared to the nine months ended September 30, 2005.

Cash flows from investing activities. Cash used in our investing activities decreased $139.7 million in the nine months ended September 30, 2006 to $138.0 million from $277.7 million in the nine months ended September 30, 2005 primarily as a result of the following:

	•	cash used by Atlas Pipeline for acquisitions decreased $165.3 million;

	•	cash proceeds from sale of assets increased $7.5 million primarily due to the sale of certain gathering pipelines within the Velma System by Atlas Pipeline; and

	•	capital expenditures increased $33.5 million due to an increase in the number of wells we drilled and expenditures related to Atlas Pipeline’s gathering system extensions.

Cash flows from financing activities. Cash provided by our financing activities decreased $100.7 million in the nine months ended September 30, 2006 to $103.7 million from $204.4 million in the nine months ended September 30, 2005, as a result of the following:

	•	we received aggregate proceeds of $59.6 million from Atlas Pipeline’s March 2006 and May 2006 common and preferred unit offerings, a decrease of $32.1 million, compared to $91.7 million received from its public offerings during the nine months ended September 30, 2005;

	•	net borrowings on debt decreased by $127.7 million in the nine months ended September 30, 2006 as compared to the prior year similar period principally as a result of the issuance of the Senior Notes partially offset by payments on borrowings associated with the acquisition of NOARK;

	•	we repurchased common stock at a cost of $29.9 million. There were no such repurchases in the nine months ended September 30, 2005.

These decreases were offset by the following:


	•	we received aggregate proceeds of $74.5 million from APL Holdings common unit offerings, which were distributed to the Company. There was no such offering in 2005.

	•	payments to affiliate primarily related to our share of income taxes included in RAI’s income tax return decreased by $13.1 million in the nine months ended September 30, 2005, as a result of our spin-off from RAI; there was no such payment made in the nine months ended September 30, 2006.

Capital Requirements: During the nine months ended September 30, 2006, our capital expenditures related primarily to investments in our drilling partnerships and pipeline expansions, in which we invested $52.5 million and $58.8 million, respectively. For the three months and nine months ended September 30, 2006 and the remaining quarter of 2006, 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 have budgeted to raise up to $219.0 million in 2006 through drilling partnerships. During the nine months ended September 30, 2006 we had raised $147.6 million. We believe cash flows from operations and amounts available under our credit facility 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.

Contractual Obligations and Commercial Commitments

The following table summarizes our contractual obligations at September 30, 2006:

			Payments Due By Period
			(in thousands)
			Less than		1 - 3		4 - 5		After 5
Contractual cash obligations	Total		1 Year		Years		Years		Years
Long-term debt ⁽¹⁾	$	299,730	$	144	$	81	$	13,500	$	286,005
Secured revolving credit facilities		-		-		-		-		-
Operating lease obligations		4,574		1,990		2,206		377		1
Capital lease obligations		-		-		-		-		-
Unconditional purchase obligations		-		-		-		-		-
Other long-term obligations		-		-		-		-		-
Total contractual cash obligations	$	304,304	$	2,134	$	2,287	$	13,877	$	286,006

(1)

Not included in the table above are estimated interest payments calculated at the rates in effect at September 30, 2006 of: 2007 - $24.1 million; 2008 - $24.1 million; 2009 - $24.1 million; 2010 - $24.1 million and 2011 - $23.9 million.

			Payments Due By Period
			(in thousands)
			Less than		1 - 3		4 - 5		After 5
Other commercial commitments	Total		1 Year		Years		Years		Years
Standby letters of credit	$	11,545	$	11,520	$	25	$	-	$	-
Guarantees		-		-		-		-		-
Standby replacement commitments		-		-		-		-		-
Other commercial commitments		23,292		23,292		-		-		-
Total commercial commitments	$	34,837	$	34,812	$	25	$	-	$	-

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 for the year ended September 30, 2005, 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 Standard

In September 2006, the SEC staff issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (“SAB 108”). SAB 108 was issued to provide consistency in how registrants quantify financial statement misstatements. We are required to and will initially apply SAB 108 in connection with the preparation of our annual financial statements for the year ending December 31, 2006. We do not expect the application of SAB 108 to have a material effect on our financial position and results of operations.

In September 2006, the Financial Accounting Standards Board, or FASB, issued Statement of Financial Accounting Standards No. 158, Employer’s Accounting for Defined Benefit Pension and Other Post Retirement Plans, or SFAS 158. SFAS 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit post retirement plan as an asset or liability, by recording the difference between the plan assets fair value and the benefit obligation. The employer must recognize after-tax gains and losses as a result of changes in the funded status as a component of other comprehensive income. The employer is also required to measure the funded status of a plan as of the date of its year end statements, and disclose in the notes to the statements additional information regarding the net periodic benefit costs. SFAS 158 is effective for the Company beginning January 1, 2007. We are currently evaluating the impact of the adoption of SFAS 158 on our financial position and results of operations.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurement, or SFAS 157. SFAS 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements. SFAS 157 is effective for 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.

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109, or FIN 48. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements and provides guidance on the recognition, de-recognition and measurement of benefits related to an entity’s uncertain tax positions. FIN 48 is effective for us beginning January 1, 2007. We are currently evaluating the impact of the adoption on our financial position and results of operations.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and oil and gas prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of 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, 2006. 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, 2006, we had no outstanding borrowings under our $200 million credit facility. Borrowings under our credit facility in future periods will subject us to movements in interest rates, which could negatively impact our net income and cash flow.

At September 30, 2006, Atlas Pipeline had a $225.0 million revolving credit facility ($13.5 million outstanding at September 30, 2006). The weighted average interest rate for these borrowings was 7.1% at September 30, 2006, and at December 31, 2005. Holding all other variables constant, if interest rates hypothetically increased or decreased by 10% our net annual income would change by approximately $6,500.

Commodity Price Risk. Our major market risk exposure in commodities is fluctuations in the pricing of our gas and oil production. Realized pricing is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas production. Pricing for gas and oil production has been volatile and unpredictable for many years. To limit our exposure to changing natural gas prices, we use physical hedges. Through our hedges, we seek to provide a measure of stability in the volatile environment of natural gas prices. These transactions are similar to NYMEX-based futures contracts, swaps and options, but also require firm delivery of the hedged quantity. Thus, we limit these arrangements to much smaller quantities than those projected to be available at any delivery point. For the twelve month period ending September 30, 2007, we estimate approximately 76% of our produced natural gas volumes will be sold in this manner, leaving our remaining production to be sold at contract prices in the month produced or at spot market prices. We also negotiate with certain purchasers for delivery of a portion of natural gas we will produce for the upcoming twelve months. The prices under most of our gas sales contracts are negotiated on an annual basis and are index-based. Our risk management objective is to lock in a range of pricing for expected production volumes.

Atlas America. We also enter into financial hedges in the form of natural gas futures and option contracts. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas.

We formally document all relationships between hedging instruments and the items being hedged, including our risk management objective and strategy for undertaking the hedging transactions. This includes matching the 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. Derivatives are recorded on the balance sheet as assets and liabilities at fair value. 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 gas is settled. 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, we will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings.

At September 30, 2006, we had 119 open natural gas futures contracts related to natural gas sales covering 38.1 million mmbtus of natural gas, maturing through December 31, 2009 at a combined average settlement price of $8.85 per mmbtu. We recognized a gain of $2.0 million and $4.9 million on settled contracts covering natural gas production for the three months and nine months ended September 30, 2006, respectively, which is included within gas and oil production our consolidated statements of operations. We recognized no gains or losses during the three months and nine months ended September 30, 2006 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges. We did not have any hedge gain or loss in the three months and nine months ending September 30, 2005.

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 Atlas Pipeline determines that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of correlation between the hedging instrument and the underlying commodity, Atlas Pipeline will discontinue hedge accounting for the derivative, and subsequent changes in fair value for the derivative, which is determined through the utilization of market data, will be recognized immediately into earnings.

Ineffective hedge gains or losses are recorded in our consolidated statements of income while the hedge contracts are open and may increase or decrease until settlement of the contract. Atlas Pipeline recognized losses of $4.9 million and $2.5 million for the three months ended September 30, 2006 and 2005, respectively, and losses of $10.5 million and $4.4 million for the nine months ended September 30, 2006 and 2005, respectively, related to the settlement of qualifying hedge instruments. Atlas Pipeline also recognized a gain of $2.6 million and a loss of $800,000 for the three months ended September 30, 2006 and 2005, respectively, and a gain of $3.5 million and a loss of $700,000 for the nine months ended September 30, 2006 and 2005, respectively, related to the change in market value of non-qualifying or ineffective hedges. Such gains and losses are included within transmission, gathering and processing revenues in our consolidated statements of operations.

Atlas Pipeline closely monitors the risks associated with commodity price changes on its future operations and, where appropriate, uses various commodity instruments such as natural gas, crude oil and NGL contracts to hedge a portion of the value of its assets and operations from such price risks. Atlas Pipeline does not realize the full impact of commodity price changes because some of its sales volumes were previously hedged at prices different than actual market prices. Atlas Pipeline’s profitability is positively influenced by increases in natural gas and NGL prices and negatively influenced if such price decreases. A 10% change in the average price of NGLs, natural gas and condensate it processes and sells would result in a change to our consolidated income for the twelve-month period ending September 30, 2007 of approximately $1.0 million.

At September 30, 2006, the Company (including Atlas Pipeline) had the following financial hedges in place:

Natural Gas Fixed-Price Swaps - Atlas⁽¹⁾

Twelve Month			Average		Fair Value
Period Ended	Volumes		Fixed Price		Asset⁽³⁾
September 30,	(MMBTU)⁽²⁾		(per MMBTU)		(in thousands)
2007		10,110,000	$	9.26	$	20,116
2008		14,640,000		8.75		9,945
2009		10,950,000		8.65		7,862
2010		2,430,000		8.61		1,650
					$	39,573

Natural Gas Liquids Sales

Production			Average		Fair Value
Period Ended	Volumes		Fixed Price		Liability⁽⁴⁾
December 31,	(gallons)		(per gallon)		(in thousands)
2006		17,262,000	$	0.788	$	(1,908	)
2007		84,924,000		0.849		(2,344	)
2008		33,012,000		0.697		(5,659	)
2009		8,568,000		0.746		(1,244	)
					$	(11,155	)

Crude Oil Sales Options (associated with NGL volume)

			Associated		Average
Production	Crude		NGL		Crude		Fair Value
Period Ended	Volume		Volume		Strike Price		Liability⁽³⁾		Option Type
December 31,	(barrels)		(gallons)		(per barrel)		(in thousands)
2008		720,000		40,219,000	$	60.00	$	-		Puts purchased
2008		720,000		40,219,000		84.00		-		Calls sold
2009		720,000		40,219,000		60.00		-		Puts purchased
2009		720,000		40,219,000		81.00		-		Calls sold
							$	-

Natural Gas Sales

Production			Average		Fair Value
Period Ended	Volumes		Fixed Price		Liability⁽³⁾
December 31,	(MMBTU)⁽²⁾		(per MMBTU)		(in thousands)
2006		200,000	$	7.019	$	107
2007		1,080,000		7.255		(451	)
2008		240,000		7.270		(223	)
					$	(567	)

Natural Gas Basis Sales

Production			Average			Fair Value
Period Ended	Volumes		Fixed Price			Asset⁽³⁾
December 31,	(MMBTU)⁽²⁾		(per MMBTU)			(in thousands)
2006		300,000	$	(0.525	)	$	49
2007		1,080,000		(0.535	)		369
2008		240,000		(0.555	)		131
						$	549

Natural Gas Purchases

Production			Average			Fair Value
Period Ended	Volumes		Fixed Price			Liability⁽³⁾
December 31,	(MMBTU)⁽²⁾		(per MMBTU)			(in thousands)
2006		720,000	$	8.384		$	(1,369	)
2007		6,960,000		8.855	⁽⁵⁾		(10,084	)
2008		3,336,000		8.872	⁽⁶⁾		(3,553	)
2009		2,400,000		8.450			(1,682	)
						$	(16,688	)

Natural Gas Basis Purchases

Production			Average			Fair Value
Period Ended	Volumes		Fixed Price			Asset⁽³⁾
December 31,	(MMBTU)⁽²⁾		(per MMBTU)			(in thousands)
2006		1,080,000	$	(0.835	)	$	189
2007		6,960,000		(0.903	)		272
2008		3,336,000		(1,042	)		272
2009		240,000		(0.600	)		130
						$	863

Crude Oil Sales

Production			Average		Fair Value
Period Ended	Volumes		Strike Price		Liability⁽³⁾
December 31,	(barrels)		(per barrel)		(in thousands)
2006		17,800	$	53.358	$	(179	)
2007		77,900		56.175		(900	)
2008		65,400		59.424		(621	)
2009		33,000		62.700		(159	)
					$	(1,859	)

Crude Oil Sales Options

Production			Average		Fair Value
Period Ended	Volumes		Strike Price		Liability³⁾
December 31,	(barrels)		(per barrel)		(in thousands)		Option Type
2006		3,300	$	60.000	$	-		Puts purchased
2006		3,300		73.380		-		Calls sold
2007		13,200		60.000		-		Puts purchased
2007		13,200		73.380		-		Calls sold
2008		17,400		60.000		-		Puts purchased
2008		17,400		72.807		-		Calls sold
2009		30,000		60.000		-		Puts purchased
2009		30,000		71.250		-		Calls sold
					$	-
	Total net asset				$	10,716

(1)	Represents ATLS’ hedged volumes. All others are related to Atlas Pipeline.
(2)	MMBTU represents million British Thermal Units.
(3)	Fair value based on forward NYMEX natural gas and light crude prices, as applicable.
(4)	Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas, light crude prices and propane prices.
(5)	Includes Atlas Pipelines’ premium received from its sale of an option for it to sell 4,800,000 mmbtu of natural gas at an average price of $15.25 per mmbtu for the year ended December 31, 2007, partially offset by its premium paid from its purchase of an option to purchase 1,200,000 mmbtu of natural gas at $26.00 per mmbtu.
(6)	Includes Atlas Pipelines’ 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.

Item 4. Controls and Procedures

As indicated in the certifications in Exhibit 31 of this report, the Company’s principal executive officer and principal financial officer have evaluated the Company’s disclosure controls and procedures as of September 30, 2006. Based on that evaluation, these officers have concluded that the Company’s disclosure controls and procedures are effective in ensuring that material information required to be in this quarterly report is made known to them on a timely basis. There were no changes during the Company’s last fiscal quarter that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

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

Issuer Purchase of Equity Securities

					Shares Purchased As		Maximum Number of
	��				Part of Publicly		Shares that May Yet
	Total Number of		Average Price		Announced Plans		Be Purchased Under
	Shares Purchased		paid Per Share		or Programs		the Plans or Programs

July 1 - 31, 2006		3,052		41.00		3,052
August 1 - 31, 2006		165,307		45.71		165,307
September 1 - 30, 2006		219,994	$	45.46		219,994
Total		388,353	$	45.53		388,353		See Note 1

Note 1: In November 2005, the Company announced that its Board of Directors authorized a repurchase program through which the Company may repurchase up to $50.0 million ($20.1 million remaining at September 30, 2006) of its common stock. Repurchases may be made from time to time through open market purchases or privately negotiated transactions at the discretion of the Company and in accordance with the rules of the Securities and Exchange Commission, as applicable. The amount and timing of any repurchases will depend on market and other relevant conditions. Purchases may be increased, decreased, or discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury shares.

Item 6. Exhibits

Exhibit No.	Description
3.1	Amended and Restated Certificate of Incorporation ⁽¹⁾
3.2	Amended and Restated Bylaws ⁽¹⁾
3.3	Amendments to Bylaws ⁽²⁾
10.1	Amended and Restated Credit Agreement among Atlas America, Inc., Wachovia Bank, National Association and other banks party thereto, dated April 27, 2006 ⁽³⁾
10.1(a)	Consent, Limited Partner Waiver and First Amendment to Amended and Restated Credit Facility, dated as of October 6, 2006. ⁽⁴⁾
31.1	Rule 13(a)-14(a)/15d-14(a) Certification
31.2	Rule 13(a)-14(a)/15d-14(a) Certification
32.1	Section 1350 Certification
32.2	Section 1350 Certification

⁽¹⁾		Previously filed as an exhibit to our Form 8-K filed on June 14, 2005.
⁽²⁾		Previously filed as an exhibit to our Form 8K filed May 16, 2005.
⁽³⁾		Previously filed as an exhibit to our Form 10-Q for the quarter ended March 31, 2006.
⁽⁴⁾		Previously filed as an exhibit to our Form 8K filed October 12, 2006.

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, 2006	By:	/s/ Matthew A. Jones
		Matthew A. Jones
		Chief Financial Officer



Date: November 8, 2006	By:	/s/ Nancy J. McGurk
		Nancy J. McGurk
		Senior Vice President and Chief Accounting Officer

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

ARKHAN Inactive 10-Q2006 Q3 Quarterly report

Content analysis