ARKHAN 10-Q 2006 Q2 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 June 30, 2006

OR

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

For the transition period from _________ to __________

Commission file number:  333-112653

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 ¨

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   ¨ Accelerated filer   x Non-accelerated filer   ¨

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

Yes  ¨    No  x

The number of outstanding shares of the registrant’s common stock on August 1, 2006 was 19.8 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 - June 30, 2006 and December 31, 2005	3
	Consolidated Statements of Income for the Three Months and Six Months Ended June 30, 2006 and 2005	4
	Consolidated Statement of Changes in Stockholders’ Equity for the Six Months Ended June 30, 2006	5
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2006 and 2005	6
	Notes to Consolidated Financial Statements	7 - 28
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29 - 42
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	43 - 46
Item 4.	Controls and Procedures	46
PART II   OTHER INFORMATION
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 6.	Exhibits	47
SIGNATURES		48

PART I.  FINANCIAL INFORMATION

Item 1. Financial Statements

ATLAS AMERICA, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)

	June 30,			December 31,
	2006			2005
ASSETS
Current assets:
Cash and cash equivalents	$	21,088		$	55,155
Accounts receivable		77,116			89,830
Prepaid expenses		12,756			5,772
Deferred tax asset		4,984			6,249
Advances to affiliates		-			492
Total current assets		115,944			157,498
Property and equipment, net		716,236			658,347
Intangible assets, net		58,197			60,959
Other assets, net		40,067			32,832
Goodwill		176,375			146,544
	$	1,106,819		$	1,056,180
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	174		$	1,351
Accounts payable		35,467			56,769
Liabilities associated with drilling contracts		88,810			70,514
Accrued producer liabilities		28,347			32,537
Accrued hedge liability		20,233			24,107
Accrued liabilities		34,798			33,091
Advances from affiliate		370			-
Total current liabilities		208,199			218,369
Long-term debt		286,134			297,430
Deferred tax liability		31,396			29,369
Other liabilities		67,237			54,865
Minority interest		367,344			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		76,753			75,967
Treasury stock, at cost		(12,037	)		(73	)
ESOP loan receivable		(528	)		(564	)
Accumulated other comprehensive loss		(1,776	)		(5,116	)
Retained earnings		83,897			62,503
Total stockholders’ equity		146,509			132,850
	$	1,106,819		$	1,056,180

See accompanying notes to consolidated financial statements

3

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per share data)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
REVENUES
Well construction and completion	$	33,805		$	26,749		$	84,688		$	68,200
Gas and oil production		21,942			16,051			44,808			30,010
Transmission, gathering and processing		103,489			80,832			216,124			124,073
Administration and oversight		1,750			-			4,656			-
Well services		3,386			2,422			6,152			4,772
		164,372			126,054			356,428			227,055
COSTS AND EXPENSES
Well construction and completion		29,394			23,259			73,640			59,303
Gas and oil production		2,217			1,492			4,122			3,168
Transmission, gathering and processing		83,339			70,485			174,776			107,947
Well services		2,022			1,293			3,788			2,609
General and administrative		7,037			5,179			19,542			6,910
Net expense reimbursement - affiliate		281			145			696			389
Depreciation, depletion and amortization		10,614			6,506			20,716			11,287
		134,904			108,359			297,280			191,613
OPERATING INCOME		29,468			17,695			59,148			35,442
OTHER INCOME (EXPENSE)
Interest expense		(6,795	)		(4,580	)		(13,516	)		(6,203	)
Minority interest in Atlas Pipeline Partners, L.P.		(4,711	)		(1,247	)		(10,966	)		(3,747	)
Other, net		(204	)		145			1,125			(172	)
		(11,710	)		(5,682	)		(23,357	)		(10,122	)
Income before income taxes		17,758			12,013			35,791			25,320
Provision for income taxes		7,658			5,569			14,330			10,360
Net income	$	10,100		$	6,444		$	21,461		$	14,960
Net income per common share - basic
Net income per common share - basic	$	.51		$	.32		$	1.08		$	.75
Weighted average common shares outstanding		19,925			20,000			19,963			20,000
Net income per common share - diluted
Net income per common shares - diluted	$	.50		$	.32		$	1.05		$	.75
Weighted average common shares outstanding		20,368			20,009			20,410			20,008

See accompanying notes to consolidated financial statements

4

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

SIX MONTHS ENDED JUNE 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																					21,461			21,461
Other comprehensive income																		3,340						3,340
Issuance of common stock		4,532		-		130			3,172			192												322
Repurchase of common stock, at cost									(278,989	)		(12,156	)											(12,156	)
Repayment of ESOP Loan															36									36
Stock option compensation						701																		701
Three-for-two split (Note 17)		6,667,098		67		(45	)														(67	)		(45	)
Balance, June 30, 2006		20,007,661	$	200	$	76,753			(277,152	)	$	(12,037	)	$	(528	)	$	(1,776	)	$	83,897		$	146,509

See accompanying notes to consolidated financial statements

5

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

SIX MONTHS ENDED JUNE 30, 2006

(in thousands)

(Unaudited)

	Six Months Ended
	June 30,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	21,461		$	14,960
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		20,716			11,287
Amortization of deferred financing costs		1,413			1,735
Non-cash loss on derivative value		(257	)		(701	)
Preferred unit imputed dividend cost amortization		540			-
Non-cash compensation on long-term incentive plans		4,451			2,274
Minority interest in Atlas Pipeline Partners, L.P.		10,966			3,747
Distributions paid to minority interests of Atlas Pipeline Partners, L.P.		(18,217	)		(8,178	)
Gain on asset dispositions		(35	)		(23	)
Deferred income taxes		1,424			1,024
Changes in operating assets and liabilities		(2,891	)		20,386
Net cash provided by operating activities		39,571			46,511
CASH FLOWS FROM INVESTING ACTIVITIES:
Business acquisition, net of cash acquired		(30,000	)		(194,941	)
Capital expenditures		(77,779	)		(55,473	)
Proceeds from sale of assets		94			227
Decrease (increase) in other assets		(156	)		283
Net cash used in investing activities		(107,841	)		(249,904	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings		82,250			321,748
Principal payments on debt		(130,832	)		(204,074	)
Payments to affiliate		-			(13,082	)
Issuance of Atlas Pipeline Partners, L.P. common and preferred units		59,739			91,661
Issuance of Atlas Pipeline Partners, L.P. senior notes		36,655			-
Treasury shares repurchased		(12,156	)		-
Increase in other assets		(1,453	)		(3,142	)
Net cash provided by financing activities		34,203			193,111
Decrease in cash and cash equivalents		(34,067	)		(10,282	)
Cash and cash equivalents at beginning of period		55,155			29,159
Cash and cash equivalents at end of period	$	21,088		$	18,877

See accompanying notes to consolidated financial statements

6

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 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”).  Atlas Pipeline is a master limited partnership in which the Company has a combined general and limited partner interest of 13% and 19% at June 30, 2006 and 2005, respectively.

The consolidated financial statements and the information and tables contained in the notes to the consolidated financial statements as of June 30, 2006 and for the six months ended June 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 six months ended June 30, 2006 may not necessarily be indicative of the results of operations for the full year ending December 31, 2006. Certain reclassifications have been made to the consolidated financial statements as of December 31, 2005 and for the six months ended June 30, 2005 to conform to the presentation as of and for the six months ended June 30, 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 six month periods ended June 30, 2006 and 2005.

Spin-off from Resource America, Inc.

On June 30, 2005, Resource America, Inc. (“RAI”) (NASDAQ: REXI) distributed its remaining 10.7 million shares of the Company to its stockholders in the form of a tax-free dividend. Each stockholder of RAI received 0.59367 shares of the Company’s common stock for each share of RAI common stock owned as of June 24, 2005, the record date. Although the distribution itself is tax-free to RAI stockholders, as a result of the deconsolidation there may be some tax liability arising from prior unrelated corporate transactions among the Company and some of its subsidiaries. Any liability arising from this transaction will be paid by the Company to RAI. As of July 1, 2005, RAI no longer includes the company in its consolidated financial statements or tax returns. In connection with the spin-off, RAI and the Company entered into a series of agreements, including a tax matters agreement and a transition services agreement, which govern the future contractual obligations between the two companies.

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.

7

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2006

(Unaudited)

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

Recently Issued Financial Accounting Standard

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 June 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 June 30, 2006 and December 31, 2005 of $55.4 million and $71.6 million, respectively which are included in Accounts Receivable on its Consolidated Balance Sheets.

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):

8

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2006

(Unaudited)

NOTE 3 - COMPREHENSIVE INCOME - (Continued)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Net income	$	10,100		$	6,444		$	21,461		$	14,960
Other comprehensive income (loss):
Unrealized holding gain (loss) on hedging contracts,net of tax of ($795), $778, ($2,271) and $1,550		1,127			(1,383	)		3,642			(2,756	)
Less: reclassification adjustment for (gains) losses realized in net income, net of tax of $(46), ($295),$109 and ($353)		(36	)		525			(302	)		627
		1,091			(858	)		3,340			(2,129	)
Comprehensive income	$	11,191		$	5,586		$	24,801		$	12,831

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. Earnings per share - diluted is computed by dividing net income by the sum of the weighted average number of shares of common stock outstanding and dilutive potential shares issuable during the period. Dilutive potential shares of common stock consist of the excess of shares issuable under the terms of the Company’s stock incentive plan over the number of such shares that could have been reacquired (at the weighted average price of shares during the period) with the proceeds received from the exercise of the options (shown in thousands).

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Net income	$	10,100	$	6,444	$	21,461	$	14,960
Weighted average common shares outstanding-basic(1)		19,925		20,000		19,963		20,000
Dilutive effect of stock option and award plan (1)		443		9		447		8
Weighted average common shares-diluted (1)		20,368		20,009		20,410		20,008

______________________

(1) The shares for the three months and six months ended June 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.

9

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2006

(Unaudited)

NOTE 5 - PROPERTY AND EQUIPMENT - (Continued)

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

	June 30,			December 31,
	2006			2005
Mineral interests:
Proved properties	$	1,799		$	2,308
Unproved properties		1,002			1,002
Wells and related equipment		311,855			273,725
Pipelines, processing and compression facilities		475,481			445,859
Rights-of-way		20,465			15,769
Land, building and improvements		8,253			7,799
Support equipment		4,885			4,201
Other		8,752			6,292
		832,492			756,955
Accumulated depreciation, depletion and amortization:
Oil and gas properties and pipelines		(110,647	)		(94,105	)
Other		(5,609	)		(4,503	)
		(116,256	)		(98,608	)
	$	716,236		$	658,347

In October 2005, Atlas Pipeline completed the acquisition of a 75% interest in NOARK Pipeline System, Limited Partnership (“NOARK”) for approximately $179.8 million (see Note 13). On May 2, 2006, Atlas Pipeline acquired the remaining 25% interest in NOARK for $69.0 million in cash, including the repayment of the $39 million NOARK notes at the date of acquisition. (See Note 13). Due to the recent date of both acquisitions, the purchase price allocation is based upon estimated values, which are subject to adjustment and could change significantly as Atlas Pipeline continues to evaluate this preliminary allocation. At June 30, 2006, the portion of the purchase price allocated to property, plant and equipment for NOARK was included in the pipelines, processing and compression facilities category within the above table.

NOTE 6 - OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL

Other Assets

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

	June 30,		December 31,
	2006		2005
Deferred financing costs, net of accumulated amortization of $4,476 and $3,063	$	14,718	$	15,654
Investments		1,545		1,647
Security deposits		1,660		1,725
Long-term hedge receivable from Partnerships		8,695		9,340
Long-term hedge receivable		13,057		4,387
Other		392		79
	$	40,067	$	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 the allocated affiliate amounts due on the Company’s unrealized long-term holding loss from hedging activities.

10

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2006

(Unaudited)

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

Intangible Assets

Customer contracts and relations. At June 30, 2006, Atlas Pipeline had $52.5 million of intangible assets, net of accumulated amortization of $4.4 million which was recorded in connection with natural gas gathering contracts and customer relations assumed in its acquisitions of Elk City and NOARK (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. Amortization expense on the customer contract and relations intangible assets, which have estimated lives of eight and twenty years, respectively, and are being amortized on a straight-line basis, was $2.3 million and $0 for the six months ended June 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 six months ended June 30, 2006 and 2005 was $439,000 and $467,000, respectively.

Aggregate estimated annual amortization expense for these contracts for the next five fiscal periods ending June 30 is as follows: 2007-$5.5 million: 2008-$5.4 million; 2009-$5.4 million: 2010-$5.4 million and 2011-$5.3 million.

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

	June 30, 2006					December 31, 2005
	Cost		Accumulated Amortization			Cost		Accumulated Amortization
Customer contracts and relations	$	56,950	$	(4,404	)	$	56,950	$	(2,081	)
Partnership management and operating contracts		14,343		(8,692	)		14,343		(8,253	)
	$	71,293	$	(13,096	)	$	71,293	$	(10,334	)

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).

11

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2006

(Unaudited)

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

	June 30,		December 31,
	2006		2005
Goodwill at beginning of period, net of accumulated amortization of $4,532	$	146,544	$	37,470
Additions to goodwill related to Atlas Pipeline acquisitions (see Note 13)		29,831		109,074
Goodwill at end of period, net of accumulated amortization of $4,532	$	176,375	$	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						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Asset retirement obligations, beginning of period	$	19,299		$	6,707		$	18,499		$	5,618
Liabilities incurred		450			400			1,126			1,409
Liabilities settled		(113	)		(52	)		(113	)		(80	)
Accretion expense		124			96			248			204
Asset retirement obligations, end of period	$	19,760		$	7,151		$	19,760		$	7,151

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

NOTE 8 - DEBT

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

	June 30,		December 31,
	2006		2005
Senior notes - Atlas Pipeline	$	286,032	$	250,000
Revolving credit facility - Atlas Pipeline		-		9,500
Installment notes - NOARK		-		39,000
Other debt		276		281
		286,308		298,781
Less current maturities		174		1,351
	$	286,134	$	297,430

12

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2006

(Unaudited)

NOTE 8 - DEBT - (Continued)

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 applicable margin ranges from 0.25% to 1.5% for base rate loans and 1.25% to 2.5% for LIBOR loans. There were no amounts outstanding under the credit facility at June 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 June 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 June 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.

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 $36.7 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 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.

13

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2006

(Unaudited)

NOTE 8 - DEBT - (Continued)

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 June 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 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. Management of Atlas Pipeline expects to consummate the exchange offer by August 17, 2006 and thereby fulfill 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.

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 June 30, 2006. The facility terminates in April 2011, when all outstanding borrowings must be repaid. At June 30, 2006 and December 31, 2005, $1.5 million was outstanding under this facility under letters of credit which are not reflected as borrowings on the Company’s consolidated balance sheet.

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

2007	$	174
2008		88
2009		14
2010		-
2011 and thereafter		286,032
	$	286,308

14

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2006

(Unaudited)

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.

On March 9, 2004, the Oklahoma Tax Commission (“OTC”) filed a petition against Spectrum Field Services, Inc. (“Spectrum”) alleging that Spectrum, prior to its acquisition by Atlas Pipeline, underpaid gross production taxes beginning in June 2000. The OTC is seeking a settlement of $5.0 million plus interest and penalties. Atlas Pipeline plans on defending itself against this allegation vigorously. In addition, under the terms of the Spectrum purchase agreement, $14.0 million has been placed in escrow to cover the costs of any adverse settlement resulting from the petition and other indemnification obligations of the purchase agreement.

At June 30, 2006, Atlas Pipeline is committed to expend approximately $25.4 million on pipeline extensions, compressor station upgrades and processing facility upgrades, including $9.2 million related to the Sweetwater gas plant, a new cryogenic gas processing plant Atlas Pipeline is constructing in Beckham County, Oklahoma. Atlas Pipeline expects the plant to be completed in third quarter of 2006.

NOTE 10 - DERIVATIVE INSTRUMENTS

Atlas America. The Company from time to time enters into 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 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, 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 June 30, 2006, the Company had 117 open natural gas futures contracts related to natural gas sales covering 38.4 million dekatherms (“Dth”) of natural gas, maturing through December 31, 2009 at a combined average settlement price of $8.88 per Dth. The Company recognized a gain of $1.5 million and $2.9 million on settled contracts covering natural gas production for the three months and six months ended June 30, 2006, which is included within gas and oil production on the Company’s consolidated statements of income. The Company recognized no gains or losses during the three months and six months ended June 30, 2006 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges.

15

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2006

(Unaudited)

NOTE 10 - DERIVATIVE INSTRUMENTS - (Continued)

Atlas Pipeline. Atlas Pipeline also enters into certain 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 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 will be recognized immediately into earnings.

Ineffective hedge gains or losses are recorded in the Company’s consolidated statements of income while the hedge contracts are open and may increase or decrease until settlement of the contract. Atlas Pipeline recognized losses of $3.2 million and $1.3 million for the three months ended June 30, 2006 and 2005, respectively, and losses of $5.6 million and $1.9 million for the six months ended June 30, 2006 and 2005, respectively, related to the settlement of qualifying hedge instruments. Atlas Pipeline also recognized gains of $400,000 and $300,000 for the three months ended June 30, 2006 and 2005, respectively, and gains of $900,000 and $100,000 for the six months ended June 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 income.

At June 30, 2006 and December 31, 2005, the Company reflected net hedging liabilities on its balance sheets of $36.6 million and $41.5 million, respectively. Of the $1.8 million net loss in accumulated other comprehensive income (loss) at June 30, 2006, the Company will reclassify $2.7 million of gains to its consolidated statements of income over the next twelve month period as these contracts expire, and $4.4 million of losses will be reclassified in later periods if the fair values of the instruments remain at current market values. Actual amounts that will be reclassified will vary as a result of future price changes.

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

Natural Gas Fixed-Price Swaps - Atlas⁽¹⁾

Twelve Month Period	Volumes		Average Fixed Price		Fair Value Liability(3)
Ended June 30,	(MMBTU)(2)		(per MMBTU)		(in thousands)
2007		6,720,000	$	9.67	$	9,362
2008		14,640,000		8.76		(5,489	)
2009		12,180,000		8.69		479
2010		4,860,000		8.61		2,074
					$	6,426

16

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2006

(Unaudited)

NOTE 10 - DERIVATIVE INSTRUMENTS - (Continued)

Natural Gas Liquids Sales

Twelve Month Period	Volumes		Average Fixed Price		Fair Value Liability(4)
Ended December 31,	(gallons)		(per gallon)		(in thousands)
2006		31,122,000	$	0.758	$	(9,751	)
2007		36,036,000		0.717		(12,238	)
2008		33,012,000		0.697		(11,491	)
2009		8,568,000		0.746		(2,750	)
					$	(36,230	)

Natural Gas Sales

Twelve Month Period	Volumes		Average Fixed Price		Fair Value Liability(3)
Ended December 31,	(MMBTU)(2)		(per MMBTU)		(in thousands)
2006		500,000	$	7.019	$	(194	)
2007		1,080,000		7.255		(2,080	)
2008		240,000		7.270		(487	)
					$	(2,761	)

Natural Gas Basis Sales

Twelve Month Period	Volumes		Average Fixed Price			Fair Value Asset(3)
Ended December 31,	(MMBTU)(2)		(per MMBTU)			(in thousands)
2006		600,000	$	(0.525	)	$	376
2007		1,080,000		(0.535	)		739
2008		240,000		(0.555	)		146
						$	1,261

Natural Gas Purchases

Twelve Month Period	Volumes		Average Fixed Price		Fair Value Liability(3)
Ended December 31,	(MMBTU)(2)		(per MMBTU)		(in thousands)
2006		1,800,000	$	7.857	$	(810	)
					$	(810	)

17

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2006

(Unaudited)

NOTE 10 - DERIVATIVE INSTRUMENTS - (Continued)

Natural Gas Basis Purchases

Twelve Month Period	Volumes		Average Fixed Price			Fair Value Liability(3)
Ended December 31,	(MMBTU)(2)		(per MMBTU)			(in thousands)
2006		2,160,000	$	(0.781	)	$	(738	)
						$	(738	)

Crude Oil Sales

Twelve Month Period	Volumes		Average Strike Price		Fair Value Liability(3)
Ended December 31,	(barrels)		(per barrel)		(in thousands)
2006		35,400	$	52.956	$	(776	)
2007		80,400		56.069		(1,613	)
2008		62,400		59.267		(933	)
2009		36,000		62.700		(335	)
					$	(3,657	)

Crude Oil Sales Options

Twelve Month Period	Volumes		Average Strike Price		Fair Value Liability(3)
Ended December 31,	(barrels)		(per barrel)		(in thousands)			Option Type
2006		6,600	$	60.000	$	-		Puts purchased
2006		6,600		73.380		(10	)	Calls sold
2007		13,200		60.000		-		Puts purchased
2007		13,200		73.380		(36	)	Calls sold
2008		17,400		60.000		-		Puts purchased
2008		17,400		72.807		(19	)	Calls sold
2009		30,000		60.000		-		Puts purchased
2009		30,000		71.250		(23	)	Calls sold
					$	(88	)
Total net liability					$	(36,597	)

_____________________________

(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 and light crude prices.

18

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2006

(Unaudited)

NOTE 10 - DERIVATIVE INSTRUMENTS - (Continued)

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

	June 30, 2006			December 31, 2005
Assets
Unrealized hedge gain - short term	$	11,006		$	14,578
Other assets - long term (Note 6)		13,057			4,387
	$	24,063		$	18,965
Liabilities
Unrealized hedge loss - short term	$	(20,233	)	$	(24,107	)
Unrealized hedge loss - long term		(40,427	)		(36,366	)
	$	(60,660	)	$	(60,473	)
	$	(36,597	)	$	(41,508	)

NOTE 11 - OPERATING SEGMENT INFORMATION

The Company’s operations include three reportable operating segments. In addition to the reportable operating segments, certain other activities are reported in the “Other” category. 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 June 30, 2006

	Well Construction And Completion		Production And Exploration		Transmission, Gathering and Processing(a)		Other(b)			Total
Revenues from third parties	$	33,805	$	21,942	$	101,218	$	7,407		$	164,372
Revenues from affiliates		-		-		7,835		-			7,835
Interest income		-		-		351		65			416
Interest expense		-		-		6,154		641			6,795
Depreciation, depletion & amortization		-		5,059		5,091		464			10,614
Segment profit (loss)		3,637		16,048		9,693		(11,620	)		17,758
Goodwill		6,389		21,527		141,209		7,250			176,375
Segment assets		8,558		290,022		751,907		56,332			1,106,819

19

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2006

NOTE 11 - OPERATING SEGMENT INFORMATION - (Continued)

Three Months Ended June 30, 2005:

	Well Construction And Completion		Production And Exploration		Transmission, Gathering and Processing(a)		Other(b)			Total
Revenues from third parties	$	26,749	$	16,051	$	79,723	$	3,531		$	126,054
Revenues from affiliates		-		-		5,352		-			5,352
Interest income		-		-		87		11			98
Interest expense		-		-		4,177		403			4,580
Depreciation, depletion & amortization		-		3,145		3,128		233			6,506
Segment profit (loss)		2,807		10,700		3,588		(5,082	)		12,013
Goodwill		6,389		21,527		62,304		7,250			97,470
Segment assets		8,618		211,436		444,322		24,292			688,668

Six Months Ended June 30, 2006:

	Well Construction And Completion		Production And Exploration		Transmission, Gathering and Processing(a)		Other(b)			Total
Revenues from third parties	$	84,688	$	44,808	$	211,586	$	15,346		$	356,428
Revenues from affiliates		-		-		15,708		-			15,708
Interest income		-		-		604		107			711
Interest expense		-		-		12,470		1,046			13,516
Depreciation, depletion & amortization		-		9,259		10,532		925			20,716
Segment profit (loss)		9,607		30,353		19,851		(24,020	)		35,791
Goodwill		6,389		21,527		141,209		7,250			176,375
Segment assets		8,558		290,022		751,907		56,332			1,106,819

Six Months Ended June 30, 2005:

	Well Construction And Completion		Production And Exploration		Transmission, Gathering and Processing(a)		Other(b)			Total
Revenues from third parties	$	68,200	$	30,010	$	122,239	$	6,606		$	227,055
Revenues from affiliates		-		-		10,199		-			10,199
Interest income		-		-		163		17			180
Interest expense		-		-		5,311		892			6,203
Depreciation, depletion & amortization		-		6,259		4,689		339			11,287
Segment profit (loss)		7,699		19,593		8,256		(10,228	)		25,320
Goodwill		6,389		21,527		62,304		7,250			97,470
Segment assets		8,618		211,436		444,322		24,292			688,668

___________________

(a) Includes revenues and expenses from Atlas Pipeline’s Appalachian and Mid-Continent operations.

(b) Includes revenues and expenses from well services and the Company’s transportation operations which do not meet the quantitative threshold for reporting segment information and general corporate expenses not allocable to any particular segment.

20

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2006

(Unaudited)

NOTE 11 - OPERATING SEGMENT INFORMATION - (Continued)

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

NOTE 12 - BENEFIT PLANS

In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment (“SFAS No. 123R”). SFAS No. 123R is a revision of SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS No. 123”), and supersedes Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”), and its related implementation guidance. On October 1, 2005 the Company adopted the provisions of SFAS No. 123R using the modified prospective method. SFAS No. 123R focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. The Statement 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. This requirement reduces net operating cash flows and increases net financing cash flows in periods after adoption. Total cash flow remains unchanged from what would have been reported under prior accounting rules.

Prior to the adoption of SFAS No. 123R, the Company followed the intrinsic value method in accordance with APB No. 25 to account for its employee stock options. Accordingly, no compensation expense was recognized upon the 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. The adoption of SFAS No. 123R 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 six months ended June 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 six months ended June 30, 2005 would have been reduced to the pro forma amounts indicated below (in thousands, except per share data):

	Three Months Ended			Six Months Ended
	June 30, 2005			June 30, 2005
Net income, as reported	$	6,444		$	14,960
Stock-based employee compensation expense reported in net income
Stock-based employee compensation expense determined under thefair value-based method for all awards, net of income taxes		(37	)		(115	)
Pro forma net income	$	6,407		$	14,845
Net income per common share:
Basic - as reported	$	.32		$	.75
Basic - pro forma	$	.32		$	.74
Diluted - as reported	$	.32		$	.75
Diluted - pro forma	$	.32		$	.74

21

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2006

(Unaudited)

NOTE 12 - BENEFIT PLANS - (Continued)

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. 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 were issued in January and April 2006 as well. For the three months and six months ended June 30, 2006, the Company recorded compensation expense of $382,000 and $648,000, respectively for these options. At June 30, 2006, the Company had unamortized compensation expense of $4.6 million.

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

	Three Months Ended				Six Months Ended
	June 30, 2006				June 30, 2006
	Shares		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
Outstanding - beginning of period		1,181,250	$	25.69		1,166,250	$	25.47
Granted		50,000	$	47.86		65,000	$	46.68
Outstanding - end of period		1,231,250	$	26.59		1,231,250	$	26.59
Exercisable, at end of period		750,000				750,000	$	25.47
Available for grant		754,679				754,679
Weighted average fair value per share of options granted during the period			$	24.00			$	23.40
Weighted average contractual life of outstanding options		9.0 years				9.0 years
Weighted average contractual life of options exercisable		9.0 years				9.0 years

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. There were no stock options issued in the six months ended June 30, 2005.

Additionally, under the Plan, employees and 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 months service. The fair value of the grants awarded in total each year is being charged to operations over the requisite service periods. Upon termination of service by a grantee, all unvested units are forfeited. Non-cash compensation expense recognized during the three months ended June 30, 2006 and 2005 with respect to these units was $17,700 and $5,200, respectively. Non-cash compensation recognized during the six months ended June 30, 2006 and 2005 was $24,000 and $8,400, respectively.

22

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2006

(Unaudited)

NOTE 12 - BENEFIT PLANS - (Continued)

The following table summarizes the activity of deferred units for the periods indicated:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2006 Units			Weighted Average Grant Date Fair Value		2006 Units			Weighted Average Grant Date Fair Value
Outstanding - beginning of period		12,485		$	17.63		10,985		$	13.65
Granted		1,585			47.32		3,085			47.02
Vested		(2,415	)		10.34		(2,415	)		10.34
Forfeited		-			-		-			-
Outstanding - end of period		11,655		$	23.17		11,655		$	23.17

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 $321,000 and $1.7 million in compensation expense related to these grants and their associated distributions for the three months ended June 30, 2006 and 2005, respectively, and $844,000 and $2.2 million for the six months ended June 30, 2006 and 2005, respectively. At June 30, 2006, Atlas Pipeline had approximately $6.4 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:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2006		2005			2006		2005
Outstanding - beginning of period		110,856		124,522			110,128		58,329
Granted (1)		363		422			1,091		67,399
Vested		-		(14,226	)		-		(14,331	)
Forfeited		-		(340	)		-		(1,019	)
Outstanding - end of period		111,219		110,378			111,219		110,378

⁽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 $41.29 and $43.48 for awards granted for the three months ended June 30, 2006 and 2005, respectively, and $41.17 and $48.59 for awards granted for the six months ended June 30, 2006 and 2005, respectively.

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 $862,000 and $1.0 million in compensation expense for the three months ended June 30, 2006 and 2005, respectively, and $2.6 million and $1.0 million for the six months ended June 30, 2006 and 2005, respectively.

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ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2006

(Unaudited)

NOTE 12 - BENEFIT PLANS - (Continued)

Employee Stock Ownership Plan. In June 2005, in connection with the spin-off from RAI, the Company established an Employee Stock Ownership Plan ("ESOP"). 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 June 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 $57,800 for the three months and six months ended June 30, 2006, respectively. The fair value of unearned ESOP shares was $2.3 million at June 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 June 30, 2006 and 2005, operations were charged $40,600 and $40,000, and during the six months ended June 30, 2006 and 2005, operations were charged $80,600 and $79,000, respectively, with respect to this commitment.

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ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 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 include 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		126,307
Other assets		140
Intangible assets - customer contracts		11,600
Intangible assets - customer relationships		15,700
Goodwill		78,969
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 acquisition, 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 recorded goodwill in connection with this acquisition as a result of NOARK’s significant cash flow and its strategic industry and geographic position. 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 include 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):

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ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 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 $250.0 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							Six Months Ended
	June 30, 2005							June 30, 2005
	As Reported		Pro Forma Adjustments			Pro Forma		As Reported		Pro Forma Adjustments			Pro Forma
Revenues	$	126,054	$	17,796		$	143,850	$	227,055	$	76,457		$	303,512
Net income		6,444		(1	)		6,443		14,960		(319	)		14,641
Net income per common share outstanding - basic		.32		-			.32		0.75		(.02	)		.73
Weighted average common shares - outstanding basic		20,000		-			20,000		20,000		-			20,000
Net income per common share - diluted		.32		-			.32		0.75		(.02	)		.73
Weighted average common shares - outstanding diluted		20,009		-			20,009		20,008		-			20,008

NOTE 14 - ATLAS PIPELINE OFFERINGS

On May 12, 2006, Atlas Pipeline sold 500,000 common units to Wachovia Securities, which has 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 $19.8 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.

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ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 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 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 will be 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 278,989 shares at a cost of $12.2 million during the six months ended June 30, 2006.

27

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2006

(Unaudited)

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 have been restated in the accompanying financial statements and notes to the consolidated financial statements to reflect this split.

NOTE 17 - SUBSEQUENT EVENTS

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.

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 $77.0 million after underwriting discounts and commissions were distributed to the Company. The underwriters have been granted a 30-day option to purchase up to an additional 540,000 common units.

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

(unaudited)

When used in this Form 10-Q, the words “believes” “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements.  Such statements are subject to certain risks and uncertainties more particularly described in Item 1A, under the caption “Risk Factors”, in our annual report on Form 10-K 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

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 coinvest, to finance the exploitation and development of our acreage.

As of June 30, 2006, our assets consisted generally of:

• interests in approximately 6,900 gross producing wells;

• equity interests in 92 investment partnerships;

• approximately 543,400 gross (491,000 net) acres, primarily in the Appalachian Basin, over half of which, or 286,700 gross (273,200 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 six month period ended June 30, 2006, we produced 25,594 Mcfe/d. As of June 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 coinvest in and contribute leasehold acreage to it, enter into drilling and well operating agreements with it and become its managing general partner.

In addition to our earnings in Atlas Pipeline, we derive our 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:

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• Gas and oil production. We receive an interest in each investment partnership proportionate to the value of our coinvestment 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 coinvest 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 coinvest 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 June 30, 2006, we had $148.5 million available under our credit facility, which could be employed to finance such acquisitions.

Spin-off by Resource America

On June 30, 2005, Resource America, Inc. (NASDAQ: REXI), or RAI, distributed its remaining 10.7 million shares of us to its stockholders in the form of a tax-free dividend. Each stockholder of RAI received 0.59367 shares of our common stock for each share of RAI common stock owned on June 24, 2005, the record date. Although the distribution itself will be tax-free to RAI’s stockholders, as a result of the deconsolidation there may be some tax liability arising from prior unrelated corporate transactions among us and some of our subsidiaries. Any liability arising from this transaction will be paid by us to RAI. In addition, we were required to make a non-recurring income tax payment to RAI, of $1.2 million associated with the spin-off.

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Recent Developments

The Company

On July 28, 2006, our 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 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 six month periods ended June 30, 2006 and 2005.

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 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.

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 June 30, 2006 and December 31, 2005, $1.5 million was outstanding under this facility, including $1.5 million under 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

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. The underwriters have been granted a 30-day option to purchase up to an additional 540,000 common units. Substantially all of the net proceeds from this offering will be distributed to us.

31

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 units to public investors. The units, which were issued under its previously filed shelf registration statement, resulted in net proceeds of approximately $19.8 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 June 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.

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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. There were no amounts outstanding under the credit facility at June 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 June 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 June 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 $36.7 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. Atlas Pipeline expects to consummate the exchange offer by August 17, 2006 and thereby fulfill 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.

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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 six-month period ended June 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 it. 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.

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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 June 30, 2007 of approximately $1.0 million.

Results of Operations for the Three Months and Six Months Ended June 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						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Average construction and completion revenue per well	$	291		$	243		$	291		$	215
Average construction and completion cost per well		253			211			253			187
Average construction and completion gross profit per well	$	38		$	32		$	38		$	28
Gross profit margin	$	4,411		$	3,490		$	11,048		$	8,897
Gross margin percent		13	%		13	%		13	%		13	%
Net wells drilled(1)		116			110			291			317

____________________

(1) Reflects net wells drilled for investment partnerships.

Our well construction and completion gross margin was $4.4 million and $11.0 million in the three months and six months ended June 30, 2006, an increase of $921,000 (26%) and $2.2 million (24%) from $3.5 million and $8.9 million in the three months and six months ended June 30, 2005, respectively.  During the three months ended June 30, 2006, the increase of $921,000 in gross margin was attributable to an increase in the gross profit per well ($692,000) and the number of wells drilled ($229,000). In the six months ended June 30, 2006, the increase of $2.2 million was attributable to an increase in the gross profit per well ($3.1 million) partially offset by a decrease in the number of wells drilled ($987,000). 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 six months ended June 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 $75.4 million of funds raised in our investment programs during the current year that have not been applied to the completion of wells as of June 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 in the remainder of calendar 2006. We completed our fundraising for calendar 2005 in November 2005 with a total of $52.5 million raised and plan to raise approximately $148 million to complete our $200 million registered partnership offering in the third calendar quarter of 2006. Through June 30, 2006 we had raised $114.3 million of this amount. We anticipate oil and gas prices will continue to favorably impact our fundraising and therefore our well construction and completion revenues in calendar 2006.

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Gas and Oil Production

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Production revenues (in thousands):
Gas (1)	$	19,437		$	13,934		$	39,930		$	26,219
Oil	$	2,469		$	2,106		$	4,834		$	3,753
Production volume:
Gas (mcf/day) (1) (3)		25,317			21,214			23,104			20,269
Oil (bbls/day)		407			461			415			434
Total (mcfe/day) (3)		27,759			23,980			25,594			22,873
Average sales prices:
Gas (per mcf) (3) (4)	$	8.44		$	7.22		$	9.55		$	7.15
Oil (per bbl) (3)	$	66.70		$	50.15		$	64.38		$	47.78
Production costs (2):
As a percent of production revenues		10	%		12	%		9	%		11	%
Per mcfe (3)	$	.88		$	.68		$	.89		$	.76
Depletion per mcfe (3)	$	1.99		$	1.34		$	1.99		$	1.37

_________________

(1) Excludes sales to landowners.

(2) 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.

(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 $7.89 and $8.55 for the three months and six months ended June 30, 2006. There were no financial hedges in the three months and six months ended June 30, 2005.

Our natural gas revenues were $19.4 million and $39.9 million in the three months and six months ended June 30, 2006, an increase of $5.5 million (39%) and $13.7 million (52%) from $13.9 million and $26.2 million in the three months and six months ended June 30, 2005.  The increase in the three months and six months ended June 30, 2006 was attributable to an increase in the average sales price of natural gas of 17% and 34% and an increase of 19% and 14% in the volume of natural gas produced in the three months and six months ended June 30, 2006, respectively. The $5.5 million increase in gas revenues in the three months ended June 30, 2006 as compared to the prior period consisted of $2.4 million attributable to increases in natural gas sales prices, and $3.1 attributable to increased production volumes. The $13.7 million increase in natural gas revenues in the six months ended June 30, 2006 as compared to the prior year period consisted of $8.8 million attributable to increases in natural gas sales prices and $4.9 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.

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Our oil revenues were $2.5 million and $4.8 million in the three months and six months ended June 30, 2006, an increase of $363,000 (17%) and $1.1 million (29%) from $2.1 million and $3.7 million in the three months and six months ended June 30, 2005, primarily due to an increase in the average sales price of oil of 33% and 35% for the three months and six months ended June 30, 2006 as compared to the prior year similar periods. The $363,000 increase in oil revenues in three months ended June 30, 2006 as compared to the prior year period consisted of $695,000 attributable to increases in sales prices partially offset by a decrease of $332,000 attributable to decreased production volumes. The $1.1 million increase in oil revenues for the six months ended June 30, 2006 as compared to the prior year period consisted of $1.3 million attributable to increases in sales prices partially offset by a decrease of $223,000 attributable to lower production volumes.

Our production costs were $2.2 million and $4.1 million in the three months and six months ended June 30, 2006, an increase of $728,000 (44%) and $954,000 (30%) from $1.5 million and $3.2 million in the three months and six months ended June 30, 2005. The increases include an increase in pumping labor and maintenance costs associated with an increase in the number of wells we own and operate from the prior year period.

Transmission, Gathering and Processing

Our transmission, gathering and processing revenues and related expenses for the three months and six months ended June 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.

Our revenues increased $22.7 million (28%) and $92.0 million (74%) to $103.5 million and $216.1 million for the three months and six months ended June 30, 2006 from $80.8 million and $124.1 million for the three months and six months ended June 30, 2005, primarily due to contributions from Elk City and NOARK and an increase in commodity prices.

Our expenses increased $12.8 million (18%) and $66.9 million (62%) to $83.3 million and $174.8 million for the three months and six months ended June 30, 2006 from $70.5 million and $107.9 million for the three months and six months ended June 30, 2005, primarily due to acquisitions and an increase in commodity prices.

Administration and Oversight

Administration and oversight of $1.8 million and $4.7 million for the three months and six months ended June 30, 2006 represents supervision and administrative fees earned for construction and completion of wells for our investment partnerships. For each well drilled for our investment partnerships we receive a fixed fee of approximately $15,000. Due to a change in our more recent drilling agreements; we now classify these fees as revenue. In the previous year these fees were classified as reimbursements of our general and administrative costs in accordance with the then existing drilling agreements.

Well Services

Our well services revenues were $3.4 million and $6.2 million in the three months and six months ended June 30, 2006, an increase of $964,000 (40%) and $1.4 million (29%) from $2.4 million and $4.8 million in the three months and six months ended June 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 twelve months ended June 30, 2006.

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Our well services expenses were $2.0 and $3.8 million in the three months and six months ended June 30, 2006, an increase of $729,000 (56%) and $1.2 million (45%) from $1.3 million and $2.6 million in the three months and six months ended June 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 $7.0 million and $19.5 million in the three months and six months ended June 30, 2006, an increase of $1.8 million and $12.6 million from $5.2 million and $6.9 million in the three months and six months ended June 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 $1.8 million in the three months ended June 30, 2006 is principally attributable the following:

• general and administrative expense reimbursements from our investment partnerships decreased by $2.8 million as prior year expenses were reduced by reimbursements and credits from our drilling partnerships. The reimbursements are now included in revenue as administration and oversight in accordance with a change in our drilling agreements.

• general and administrative expenses related to Atlas Pipeline’s operations increased $963,000 primarily as a result of Atlas Pipeline’s acquisitions of NOARK on October 31, 2005 and increases in professional fees.

• professional and net syndication expenses decreased $2.0 million due to the timing of our syndication and land activities related to our public and private partnerships

The increase of $12.6 million in the six months ended June 30, 2006 is principally attributable to the following:

• general and administrative expenses related to Atlas Pipeline’s operations were $10.4 million, an increase of $4.4 million primarily attributable to costs associated with the operations of Elk City and NOARK,

• our general and administrative expense reimbursements from our investment partnerships decreased by $8.2 million as prior year expenses were reduced by reimbursements and credits from our drilling partnerships. The reimbursements are now included in revenue as administration and oversight in accordance with a change in our drilling agreements,

Our depletion of oil and gas properties as a percentage of oil and gas revenues was 23% and 21% in the three months and six months ended June 30, 2006, compared to 18% and 19% in the three months and six months ended June 30, 2005. Depletion expense per mcfe was $1.99 in the three months and six months ended June 30, 2006, an increase of $.65 (49%) and $.62 (45%) per mcfe from $1.34 and $1.37 in the three months and six months ended June 30, 2005. Increases in our depletable basis and production volumes caused depletion expense to increase $2.1 million (72%) and $3.5 million (63%) to $5.0 million and $9.2 million in the three months and six months ended June 30, 2006 compared to $2.9 million and $5.7 million in the three months and six months ended June 30, 2005. 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 $2.0 million (56%) and $5.9 million (105%), to $5.6 million and $11.5 million in the three months and six months ended June 30, 2006 compared to $3.6 million and $5.6 million in the three months and six months ended June 30, 2005. This was primarily due to the increased asset base associated with Atlas Pipeline’s acquisitions.

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Our interest expense was $6.8 million and $13.5 million in the three months and six months ended June 30, 2006, an increase of $2.2 million and $7.3 million from $4.6 million and $6.2 million in the three months and six months ended June 30, 2005. Atlas Pipeline incurred interest expense of $5.7 million and $11.0 million in the three months and six months ended June 30, 2006 related 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 June 30, 2006, we own 13% of the partnership interest in Atlas Pipeline through our general partner interest and limited partner units. Our ownership interest decreased 6% from 19% at June 30, 2005 as a result of the completion by Atlas Pipeline of common unit offerings in June and November 2005. Our interest also decreased due to Atlas Pipeline’s issuance of $30 million 6.5% cumulative preferred units on March 13, 2006 and $10 million on May 19, 2006.

Because we control the operations of Atlas Pipeline, we include it in our consolidated financial statements and show the ownership by the public as a minority interest.  The minority interest in Atlas Pipeline’s earnings was $4.7 million and $11.0 million for the three months and six months ended June 30, 2006, as compared to $1.2 million and $3.7 million for the three months and six months ended June 30, 2005, an increase of $3.5 million and $7.3 million. These increases were a result of an increase in the percentage interest of public unit holders and an increase in Atlas Pipeline’s net income, as discussed above.

Our effective tax rate was 43% and 40% for the three months and six months ended June 30, 2006 as compared to 46% and 41% for the three months and six months ended June 30, 2005. For the six months ended June 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, Atlas Pipeline’s credit facility and the sale of Atlas Pipeline’s equity.  The following table sets forth our sources and uses of cash (in thousands):

	Six Months Ended
	June 30,
	2006			2005
Provided by operations	$	39,571		$	46,511
Used in investing activities		(107,841	)		(249,904	)
Provided by financing activities		34,203			193,111
Decrease in cash and cash equivalents	$	(34,067	)	$	(10,282	)

We had $21.1 million in cash and cash equivalents at June 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 $52.5 million during the quarter ended December 31, 2005. Our ratio of earnings from continuing operations before income taxes, minority interest and interest expense to fixed charges was 4.5 to 1 in the six months ended June 30, 2006 as compared to 5.7 to 1 in the six months ended June 30, 2005.  We had a working capital deficit of $92.3 million at June 30, 2006, a decrease of $31.4 million from December 31, 2005.

Our long-term debt (including current maturities) was 195% and 225% of our total equity at June 30, 2006 and December 31, 2005, respectively. Since December 31, 2005, total stockholders’ equity has increased by $13.7 million and total debt has decreased by $12.5 million. Stockholders’ equity increased principally due to net earnings of $21.5 million partially offset by stock repurchases of $12.2 million for the six months ended June 30, 2006. The increase in long-term debt relates to increased borrowings to fund Atlas Pipeline’s acquisitions and our drilling operations.

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On June 16, 2006 we increased the borrowing base under our credit facility to $150.0 million. At June 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 June 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 $6.9 million in the six months ended June 30, 2006 to $39.6 million from $46.5 million in the six months ended June 30, 2005, substantially as a result of the following:

• an increase in net income before depreciation and amortization of $15.6 million in the six months ended June 30, 2006 as compared to the prior year period, principally as a result of income included in our financial statements from our acquisitions, higher natural gas and oil prices and drilling profits;

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

• changes in minority interests and distributions paid to minority interests decreased cash flow by $2.8 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 increased cash flow by $400,000 as compared to the six months ended June 30, 2005 which reflects the impact of timing differences between accounting and tax records; and

• changes in operating assets and liabilities decreased operating cash flow by $23.3 million in the six months ended June 30, 2006, compared to the six months ended June 30, 2005.

This decrease is primarily a result of the following:

• a decrease of $49.1 million in the change in accounts payable and accrued liabilities;

• an increase of $15.3 million in liabilities associated with our drilling contracts. Our level of liabilities associated with drilling contracts is dependent upon the remaining amount of our drilling obligations at any balance sheet date, which is dependent upon the timing of funds raised through our investment partnerships; and

• an increase of $10.5 million in the change in accounts receivable and prepaid expenses.

Cash flows from investing activities.Cash used in our investing activities decreased $142.1 million in the six months ended June 30, 2006 to $107.8 million from $249.9 million in the six months ended June 30, 2005 primarily as a result of the following:

• cash used by Atlas Pipeline for acquisitions decreased $164.9 million; and

• capital expenditures increased $22.3 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 $158.9 million in the six months ended June 30, 2006 to $34.2 million from $193.1 million in the six months ended June 30, 2005, as a result of the following:

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• we received aggregate proceeds of $59.7 million from Atlas Pipeline’s March 2006 and May 2006 common and preferred unit offerings, a decrease of $32.0 million, compared to $91.7 million received from its public offerings during the six months ended June 30, 2005;

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

• net borrowings on debt increased by $129.6 million in the six months ended June 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; and

• we repurchased common stock at a cost of $12.2 million. There were no such repurchases in the six months ended June 30, 2005.

Capital Requirements: During the six months ended June 30, 2006, our capital expenditures related primarily to investments in our drilling partnerships and pipeline expansions, in which we invested $39.5 million and $35.8 million, respectively.  For the three months and six months ended June 30, 2006 and the remaining quarters of fiscal 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 two 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 $200.0 million in 2006 through drilling partnerships.  Through the six months ended June 30, 2006 we had raised $114.3 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 June 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)	$	286,308	$	174	$	102	$	-	$	286,032
Secured revolving credit facilities		-		-		-		-		-
Operating lease obligations		4,516		1,888		2,195		432		1
Capital lease obligations		-		-		-		-		-
Unconditional purchase obligations		-		-		-		-		-
Other long-term obligations		-		-		-		-		-
Total contractual cash obligations	$	290,824	$	2,062	$	2,297	$	432	$	286,033

______________

(1) Not included in the table above are estimated interest payments calculated at the rates in effect at June 30, 2006 of: 2007 - $23.2 million; 2008 - $23.2 million; 2009 - $23.2 million; 2010 - $23.2 million and 2011 - $23.2 million.

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			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)	$	11,525	$	11,525	$	-	$	-	$	-
Guarantees		-		-		-		-		-
Standby replacement commitments		-		-		-		-		-
Other commercial commitments		25,376		25,376		-		-		-
Total commercial commitments	$	36,901	$	36,901	$	-	$	-	$	-

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 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 us beginning January 1, 2007. We are currently evaluating the impact of its adoption on our financial position and results of operations.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The 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 June 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 June 30, 2006, we had no outstanding borrowings under our $150 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 June 30, 2006, Atlas Pipeline had a $225.0 million revolving credit facility ($0 outstanding at June 30, 2006).

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 forward sales contracts. 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 June 30, 2007, we estimate approximately 62% of our produced natural gas volumes will be sold in this manner, leaving our remaining production to be sold at contract prices in the month produced or at spot market prices.  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 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. 

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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 income in the month the hedged gas is sold. If it is determined that a derivative is not highly effective as a hedge or it has ceased to be a highly effective hedge, due to the loss of correlation between changes in gas reference prices under a hedging instrument and actual gas prices, the Company will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings.

At June 30, 2006, the Company had 117 open natural gas futures contracts related to natural gas sales covering 38.4 million dekatherms (“Dth”) of natural gas, maturing through December 31, 2009 at a combined average settlement price of $8.88 per Dth. The Company recognized a gain of $1.5 million and $2.9 million on settled contracts covering natural gas production for the three months and six months ended June 30, 2006. The Company recognized no gains or losses during the three months and six months ended June 30, 2006 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges.

Atlas Pipeline. Atlas Pipeline also enters into certain 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 is 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 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 will be recognized immediately into earnings. Atlas Pipeline recognized losses of $3.2 million and $1.3 million related to the settlement of qualifying hedge instruments which are included in our consolidated statement of income for the three months ended June 30, 2006 and 2005, respectively. Atlas Pipeline also recognized a gain of $400,000 and $300,000 related to the change in market value of non-qualifying or ineffective hedges which are included in our consolidated statement of income for the three months ended June 30, 2006 and 2005, respectively. Atlas Pipeline recognized losses of $5.6 million and $1.9 million related to the settlement of qualifying hedge instruments which are included in our consolidated statement of income for the six months ended June 30, 2006 and 2005, respectively. Atlas Pipeline also recognized a gain of $900,000 and $100,000 related to the change in market value of non-qualifying or ineffective hedges which are included in our consolidated statement of income for the six months ended June 30, 2006 and 2005, respectively.

At June 30, 2006 and December 31, 2005, we reflected net hedging liabilities on its balance sheets of $36.6 million and $41.5 million, respectively. Of the $1.8 million net loss in accumulated other comprehensive income (loss) at June 30, 2006, we will reclassify $2.7 million of gains to our consolidated statements of income over the next twelve month period as these contracts expire, and $4.4 million of losses will be reclassified in later periods if the fair values of the instruments remain at current market values. Actual amounts that will be reclassified will vary as a result of future price changes. Ineffective hedging gains or losses are recorded within its consolidated statements of income while the hedge contract is open and may increase or decrease until settlement of the contract.

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As of June 30, 2006, we (including Atlas Pipeline) had the following financial hedges in place:

Natural Gas Sales - Atlas⁽¹⁾

Twelve Month Period	Volumes		Average Fixed Price		Fair Value Liability(3)
Ended June 30,	(MMBTU)(2)		(per MMBTU)		(in thousands)
2007		6,720,000	$	9.67	$	9,362
2008		14,640,000		8.76		(5,489	)
2009		12,180,000		8.69		479
2010		4,860,000		8.61		2,074
					$	6,426

Natural Gas Liquids Sales

Twelve Month Period	Volumes		Average Fixed Price		Fair Value Liability(4)
Ended December 31,	(gallons)		(per gallon)		(in thousands)
2006		31,122,000	$	0.758	$	(9,751	)
2007		36,036,000		0.717		(12,238	)
2008		33,012,000		0.697		(11,491	)
2009		8,568,000		0.746		(2,750	)
					$	(36,230	)

Natural Gas Sales

Twelve Month Period	Volumes		Average Fixed Price		Fair Value Liability(3)
Ended December 31,	(MMBTU)(2)		(per MMBTU)		(in thousands)
2006		500,000	$	7.019	$	(194	)
2007		1,080,000		7.255		(2,080	)
2008		240,000		7.270		(487	)
					$	(2,761	)

Natural Gas Basis Sales

Twelve Month Period	Volumes		Average Fixed Price			Fair Value Asset(3)
Ended December 31,	(MMBTU)(2)		(per MMBTU)			(in thousands)
2006		600,000	$	(0.525	)	$	376
2007		1,080,000		(0.535	)		739
2008		240,000		(0.555	)		146
						$	1,261

Natural Gas Purchases

Twelve Month Period	Volumes		Average Fixed Price		Fair Value Liability(3)
Ended December 31,	(MMBTU)(2)		(per MMBTU)		(in thousands)
2006		1,800,000	$	7.857	$	(810	)
					$	(810	)

Natural Gas Basis Purchases

Twelve Month Period	Volumes		Average Fixed Price			Fair Value Liability(3)
Ended December 31,	(MMBTU)(2)		(per MMBTU)			(in thousands)
2006		2,160,000	$	(0.781	)	$	(738	)
						$	(738	)

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Crude Oil Sales

Twelve Month Period	Volumes		Average Strike Price		Fair Value Liability(3)
Ended December 31,	(barrels)		(per barrel)		(in thousands)
2006		35,400	$	52.956	$	(776	)
2007		80,400		56.069		(1,613	)
2008		62,400		59.267		(933	)
2009		36,000		62.700		(335	)
					$	(3,657	)

Crude Oil Sales Options

Twelve Month Period	Volumes		Average Strike Price		Fair Value Liability(3)
Ended December 31,	(barrels)		(per barrel)		(in thousands)			Option Type
2006		6,600	$	60.000	$	-		Puts purchased
2006		6,600		73.380		(10	)	Calls sold
2007		13,200		60.000		-		Puts purchased
2007		13,200		73.380		(36	)	Calls sold
2008		17,400		60.000		-		Puts purchased
2008		17,400		72.807		(19	)	Calls sold
2009		30,000		60.000		-		Puts purchased
2009		30,000		71.250		(23	)	Calls sold
					$	(88	)
Total net liability					$	(36,597	)

_______________________

(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 and light crude prices.

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 June 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.

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PART II. OTHER INFORMATION

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

	Total Number of Shares Purchased		Average Price paid Per Share		Shares Purchased As Part of Publicly Announced Plans or Programs		Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
April 1 - 30, 2006		-		-		-
May 1 - 31, 2006		94,798		45.56		94,798
June 1 - 30, 2006		176,691	$	41.57		176,691
Total		271,489	$	42.96		271,489	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 ($37.8 million remaining at June 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)
10.2	Agreement for Services among Atlas America, Inc. and Richard Weber, dated April 5, 2006
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.

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SIGNATURES

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

	ATLAS AMERICA, INC.
	(Registrant)
Date: August 8, 2006	By:	/s/ Matthew A. Jones
		Matthew A. Jones
		Chief Financial Officer
Date: August 8, 2006	By:	/s/Nancy J. McGurk
		Nancy J. McGurk Senior Vice President and Chief Accounting Officer

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