ARKHAN 10Q 2006 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2006

[ ]	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 May 1, 2006 was 20.0 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 - March 31, 2006 and September 30, 2005	3

	Consolidated Statements of Income for the Three Months and Six Months Ended March 31, 2006 and 2005	4

	Consolidated Statement of Changes in Stockholders’ Equity for the Six Months Ended March 31, 2006	5

	Consolidated Statements of Cash Flows for the Six Months Ended March 31, 2006 and 2005	6

	Notes to Consolidated Financial Statements	7 - 26

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27- 37

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	38- 41

Item 4.	Controls and Procedures	41

PART II	OTHER INFORMATION

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41

Item 6.	Exhibits	42

SIGNATURES		43

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ATLAS AMERICA, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)

	March 31,			September 30,
	2006			2005
ASSETS
Current assets:
Cash and cash equivalents	$	42,798		$	18,281
Accounts receivable		86,510			73,996
Prepaid expenses		11,031			5,063
Deferred tax asset		5,294			6,970
Total current assets		145,633			104,310

Property and equipment, net		678,298			505,967
Intangible assets, net		59,578			18,708
Other assets, net		30,586			15,360
Goodwill		145,797			115,366
	$	1,059,892		$	759,711
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	1,365		$	122
Accounts payable		35,285			31,477
Liabilities associated with drilling contracts		24,862			60,971
Accrued producer liabilities		28,317			32,543
Accrued hedge liability		13,052			37,663
Accrued liabilities		40,575			18,231
Advances from affiliate		367			111
Total current liabilities		143,823			181,118

Long-term debt		333,945			191,605
Deferred tax liability		30,735			28,903
Other liabilities		52,430			47,612

Minority interest		352,498			190,122

Commitments and contingencies		-			-

Stockholders’ equity:
Preferred stock, $0.01 par value: 1,000,000 authorized shares		-			-
Common stock, $0.01 par value: 49,000,000 authorized shares		200			133
Additional paid-in capital		76,425			75,637
Treasury stock, at cost		(548	)		-
ESOP loan receivable		(546	)		(583	)
Accumulated other comprehensive loss		(2,867	)		(5,615	)
Retained earnings		73,797			50,779
Total stockholders’ equity		146,461			120,351
	$	1,059,892		$	759,711

See accompanying notes to consolidated financial statements

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per share data)

(Unaudited)

	Three Months Ended						Six Months Ended
	March 31,						March 31,
	2006			2005			2006			2005

REVENUES
Well drilling	$	50,883		$	41,451		$	93,028		$	72,009
Gas and oil production		22,866			13,959			46,952			28,618
Transmission, gathering and processing		112,635			43,241			241,375			86,470
Drilling management fee		2,906			-			4,482			-
Well services		2,766			2,350			5,327			4,598
		192,056			101,001			391,164			191,695

COSTS AND EXPENSES
Well drilling		44,246			36,044			80,894			62,617
Gas and oil production and exploration		4,209			1,913			5,947			3,162
Transmission, gathering and processing		91,437			37,462			201,326			73,142
Well services		1,766			1,316			3,253			2,507
General and administrative		10,201			1,494			18,249			3,154
Compensation reimbursement - affiliate		415			244			578			457
Depreciation, depletion and amortization		10,102			4,781			20,426			10,653
		162,376			83,254			330,673			155,692

OPERATING INCOME		29,680			17,747			60,491			36,003

OTHER INCOME (EXPENSE)
Interest expense		(6,721	)		(1,623	)		(12,868	)		(3,313	)
Minority interest in Atlas Pipeline Partners, L.P.		(6,255	)		(2,500	)		(13,000	)		(9,720	)
Arbitration settlement, net		-			(136	)		-			4,310
Other, net		1,329			(181	)		2,020			(79	)
		(11,647	)		(4,440	)		(23,848	)		(8,802	)

Income before income taxes		18,033			13,307			36,643			27,201
Provision for income taxes		6,672			4,791			13,558			9,793
Net income	$	11,361		$	8,516		$	23,085		$	17,408

Net income per common share - basic
Net income per common share - basic	$	.57		$	.43		$	1.15		$	.87
Weighted average common shares outstanding		20,001			20,000			20,002			20,000

Net income per common share - diluted
Net income per common shares - diluted	$	.56		$	.43		$	1.14		$	.87
Weighted average common shares outstanding		20,453			20,007			20,334			20,007

See accompanying notes to consolidated financial statements

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

SIX MONTHS ENDED MARCH 31, 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, October 1, 2005		13,334,703	$	133	$	75,637		-		$	-		$	(583	)	$	(5,615	)	$	50,779		$	120,351
Net Income																				23,085			23,085
Other comprehensive income																	2,748						2,748
Issuance of common stock		3,928		-		255																	255
Repurchase of common stock, at cost								(8,835	)		(548	)											(548	)
Repayment of ESOP Loan														37									37
Stock option compensation						533																	533
Three-for-two split (Note 16)		6,667,098		67		-		-			-			-			-			(67	)		−
Balance, March 31, 2006		20,005,729	$	200	$	76,425		(8,835	)	$	(548	)	$	(546	)	$	(2,867	)	$	73,797		$	146,461

See accompanying notes to consolidated financial statements

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

SIX MONTHS ENDED MARCH 31, 2006

(in thousands)

(Unaudited)

	Six Months Ended
	March 31,
		2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	23,085		$	17,408
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		20,426			10,653
Amortization of deferred financing costs		1,282			621
Non-cash loss on derivative value		650			720
Preferred unit imputed dividend cost amortization		95			-
Non-cash compensation on long-term incentive plans		4,067			922
Minority interest in Atlas Pipeline Partners, L.P.		13,000			9,720
Distributions paid to minority interests of Atlas Pipeline Partners, L.P.		(15,435	)		(7,845	)
Gain on asset dispositions		(28	)		(36	)
Deferred income taxes		2,034			1,420
Changes in operating assets and liabilities		(42,612	)		(1,621	)
Net cash provided by operating activities		6,564			31,962

CASH FLOWS FROM INVESTING ACTIVITIES:
Business acquisition, net of cash acquired		(163,630	)		-
Capital expenditures		(64,018	)		(40,867	)
Proceeds from sale of assets		33			66
Decrease (increase) in other assets		579			(789	)
Net cash used in investing activities		(227,036	)		(41,590	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings		282,091			86,252
Principal payments on debt		(428,138	)		(67,910	)
Payments to affiliate		-			(19,448	)
Issuance of Atlas Pipeline Partners, L.P. common and preferred units		151,002			-
Issuance of Atlas Pipeline Partners, L.P.senior notes		243,102			-
Increase in other assets		(3,068	)		(1,397	)
Net cash provided by (used in) financing activities		244,989			(2,503	)

Increase (decrease) in cash and cash equivalents		24,517			(12,131	)
Cash and cash equivalents at beginning of period		18,281			29,192
Cash and cash equivalents at end of period	$	42,798		$	17,061

See accompanying notes to consolidated financial statements

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 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 partnership interest of 14% and 24% at March 31, 2006 and 2005, respectively.

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

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.

Recently Issued Financial Accounting Standards

In May 2005, the Financial Accounting Standards Board, (“FASB”) issued Statement No. 154, Accounting Changes and Error Corrections (“SFAS 154”). SFAS 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle. It also requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than being reported in an income statement. The statement will be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but management does not currently expect SFAS 154 to have a material impact on the Company’s financial position or results of operations.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2006

(Unaudited)

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

In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (“FIN 47”), which will result in (a) more consistent recognition of liabilities relating to asset retirement obligations, (b) more information about expected future cash outflows associated with those obligations, and (c) more information about investments in long-lived assets because additional asset retirement costs will be recognized as part of the carrying amounts of the assets. FIN 47 clarifies that the term conditional asset retirement obligation as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists.

FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. Retrospective application of interim financial information is permitted but is not required. Early adoption of this interpretation is encouraged. Management does not believe the interpretation will have a significant impact on the Company’s financial position or 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 March 31, 2006 and September 30, 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 March 31, 2006 and September 30, 2005 of $46.5 million and $57.1 million 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 (shown in thousands).

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2006

(Unaudited)

NOTE 3 - COMPREHENSIVE INCOME - (Continued)

	Three Months Ended						Six Months Ended
	March 31,						March 31,
		2006			2005			2006		2005
Net income	$	11,361		$	8,516		$	23,085	$	17,408
Other comprehensive income (loss):
Unrealized holding gain (loss) on hedging contracts, net of tax of ($1,476) $772, ($823) and ($579)		2,515			(1,373	)		1,403		1,029
Less: reclassification adjustment for (gains) losses realized in net income, net of tax of $155, ($58), ($791) and ($29)		(266	)		102			1,345		51
		2,249			(1,271	)		2,748		1,080
Comprehensive income	$	13,610		$	7,245		$	25,833	$	18,488

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
	March 31,				March 31,
		2006		2005		2006		2005
Net income	$	11,361	$	8,516	$	23,085	$	17,408
Weighted average common shares outstanding-basic⁽¹⁾		20,001		20,000		20,002		20,000
Dilutive effect of stock option and award plan ⁽¹⁾		452		7		332		7
Weighted average common shares-diluted ⁽¹⁾		20,453		20,007		20,334		20,007

(1)

The shares for the three months and six months ended March 31, 2005 have been restated to reflect the three for two stock split on March 10, 2006.

NOTE 5 - PROPERTY AND EQUIPMENT

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

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2006

(Unaudited)

NOTE 5 - PROPERTY AND EQUIPMENT - (Continued)

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

	March 31,			September 30,
	2006			2005

Mineral interests:
Proved properties	$	2,099		$	2,852
Unproved properties		1,002			1,002
Wells and related equipment		287,025			255,879
Pipelines, processing and compression facilities		455,271			304,523
Rights-of-way		19,841			15,110
Land, building and improvements		8,052			7,793
Support equipment		4,416			3,675
Other		7,566			5,251
		785,272			596,085
Accumulated depreciation, depletion and amortization:
Oil and gas properties and pipelines		(102,210	)		(85,824	)
Other		(4,764	)		(4,294	)
		(106,974	)		(90,118	)
	$	678,298		$	505,967

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 12). The purchase price allocations for this acquisition is based on estimated fair values determined by Atlas Pipeline, which are subject to adjustment and could change significantly as they are further evaluated. At March 31, 2006, the portion of the purchase price allocated to property, plant and equipment for NOARK is 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):

	March 31,		September 30,
		2006		2005
Deferred financing costs, net of accumulated amortization of $3,801 and $2,519	$	15,071	$	5,524
Investments		1,547		1,647
Security deposits		1,715		1,779
Hedge receivable - long term		12,235		5,970
Other		18		440
	$	30,586	$	15,360

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2006

(Unaudited)

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

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.

Intangible Assets

Customer contracts and relations. At March 31, 2006, Atlas Pipeline had $53.7 million of intangible assets, net of accumulated amortization of $3.2 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 12). 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 $2.8 million and $0 for the six months ended March 31, 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 March 31, 2006 and 2005 was $439,000 and $466,000, respectively.

The aggregate estimated annual amortization expense of customer relations and partnership management and operating contracts is approximately $5.4 million for each of the succeeding five-years ended March 31.

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

	March 31,					September 30,
	2006					2005
			Accumulated					Accumulated
		Cost		Amortization			Cost		Amortization
Customer contracts and relations	$	56,950	$	(3,242	)	$	12,891	$	(492	)
Partnership management and operating contracts		14,343		(8,473	)		14,343		(8,034	)
Intangible assets	$	71,293	$	(11,715	)	$	27,234	$	(8,526	)

Goodwill

The Company applies the provisions of SFAS No. 142, which require that goodwill no longer be amortized, but instead evaluated for impairment at least annually. The Company performs such evaluations 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).

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2006

(Unaudited)

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

	March 31,		September 30,
		2006		2005
Goodwill at beginning of period, net of accumulated amortization of $4,532	$	115,366	$	37,470
Additions to goodwill related to Atlas Pipeline acquisitions (see Note 12)		30,431		77,896
Goodwill at end of period, net of accumulated amortization of $4,532	$	145,797	$	115,366

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
	March 31,					March 31,
		2006		2005			2006		2005
Asset retirement obligations, beginning of period	$	18,499	$	5,618		$	17,651	$	4,888
Liabilities incurred		676		1,008			1,401		1,658
Liabilities settled		-		(28	)		-		(32	)
Accretion expense		124		109			247		193
Asset retirement obligations, end of period	$	19,299	$	6,707		$	19,299	$	6,707

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):

	March 31,		September 30,
		2006		2005
Senior notes - Atlas Pipeline	$	250,000	$	-
Revolving credit facility - Atlas Pipeline		-		183,500
Revolving credit facility		46,000		8,000
Installment notes - NOARK		39,000		-
Other debt		310		227
		335,310		191,727
Less current maturities		1,365		122
	$	333,945	$	191,605

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2006

(Unaudited)

NOTE 8 - DEBT - (Continued)

Atlas Pipeline Senior Notes. In December 2005, Atlas Pipeline issued $250.0 million of 10-year, 8.125% senior unsecured notes (“Senior Notes”) in a private placement transaction pursuant to Rule 144A and Regulation S under the Securities Act of 1933 for net proceeds of approximately $243.1 million, after underwriting commissions and other transaction costs. The Senior Notes are guaranteed by all of Atlas Pipeline’s existing subsidiaries, other than NOARK (see Note 18). Interest on the Senior Notes is payable semi-annually in arrears on June 15 and December 15, commencing on June 15, 2006. The Senior Notes are redeemable at any time on or after December 15, 2010 at specified 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 a make-whole redemption price. 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 of Atlas Pipeline, upon certain asset sales if the net proceeds are not reinvested into Atlas Pipeline within specified time periods. The Senior Notes are junior in right of payment to the Atlas Pipeline secured debt, including Atlas Pipeline’s obligations under its credit facility.

The indenture governing the Senior Notes contains covenants, including limitations of Atlas Pipeline’s ability to: incur liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions; redeem, repurchase or retire equity interests or subordinated indebtedness; make investments; or merge, consolidate or sell substantially all of its assets. Atlas Pipeline is in compliance with these covenants as of March 31, 2006.

In connection with a registration rights agreement entered into by Atlas Pipeline upon issuance of the Senior Notes, Atlas Pipeline agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission by April 19, 2006, (b) cause the exchange offer registration statement to be declared effective by the Securities and Exchange Commission (“SEC”) 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 (See Note 18). Atlas Pipeline filed the exchange offer registration statement with the SEC on April 19, 2006.

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 $130.0 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 the adjusted London Interbank Offered Rate (“LIBOR”) plus the applicable margin, elected at the Company’s option.

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

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2006

(Unaudited)

NOTE 8 - DEBT - (Continued)

The Wachovia credit facility requires the Company to maintain specified ratios of current assets to current liabilities and debt to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”). In addition, the facility limits sales, leases or transfers of assets and the incurrence of additional indebtedness. The facility limits the dividends payable by 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 facility terminates in April 2011, when all outstanding borrowings must be repaid. At March 31, 2006 and September 30, 2005, $52.5 million and $9.5 million, respectively, were outstanding under this facility, including $6.5 million and $1.5 million, respectively, under letters of credit which are not reflected as borrowings on the Company’s consolidated balance sheet. At March 31, 2006 the Company’s weighted average interest rate on outstanding borrowings was 7.7%.

Installment notes - NOARK. At March 31, 2006, NOARK’s subsidiary, NOARK Pipeline Finance, L.L.C., had $39.0 million in principal amount outstanding of 7.15% notes due in 2018. The notes were acquired as part of Atlas Pipeline’s acquisition of NOARK on October 31, 2005 and are allocated severally 100% to Southwestern (See Note 12). The notes are governed by an indenture dated June 1, 1998 for which UMB Bank, N.A. serves as trustee. Interest on the notes is payable semi-annually, in cash, in arrears on June 1 and December 1 of each year. The notes are subject to semi-annual redemption in installments of $0.6 million, plus accrued and unpaid interest. Additionally, at Southwestern’s option, these notes may be redeemed as of a particular payment date at their redemption price plus a make-whole premium and unpaid interest accrued to that date by giving the trustee at least 60 days notice. Under the NOARK partnership agreement, payments on the notes will be made from amounts otherwise distributable to Southwestern and, if those amounts are insufficient, Southwestern is required to make a capital contribution to NOARK. NOARK distributes available cash to the partners in accordance with their ownership interests after deduction of their respective portion of amounts payable on the notes (see Note 18).

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

2007	$	1,365
2008		1,323
2009		1,222
2010		1,200
2011 and thereafter		330,200
	$	335,310

NOTE 9 - 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.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2006

(Unaudited)

NOTE 9 - DERIVATIVE INSTRUMENTS - (Continued)

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 March 31, 2006, the Company had 108 open natural gas futures contracts related to natural gas sales covering 11,452,000 dekatherms (“Dth”) (net to the Company) of natural gas, maturing through December 31, 2009 at a combined average settlement price of $8.94 per Dth. The Company recognized a gain of $1.4 million on settled contracts covering natural gas production for the three months and six months ended March 31, 2006. The Company recognized no gains or losses during the three months and six months ended March 31, 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 $2.4 million and $669,000 related to the settlement of qualifying hedge instruments which are included in the Company’s consolidated statement of income for the three months ended March 31, 2006 and 2005, respectively. Atlas Pipeline also recognized a gain of $1.2 million and a loss of $224,000 related to the change in market value of non-qualifying or ineffective hedges which are included in the Company’s consolidated statement of income for the three months ended March 31, 2006 and 2005, respectively. Atlas Pipeline recognized losses of $8.0 million and $645,000 related to the settlement of qualifying hedge instruments which are included in the Company’s consolidated statement of income for the six months ended March 31, 2006 and 2005, respectively. Atlas Pipeline also recognized a gain of $860,000 and $216,000 related to the change in market value of non-qualifying or ineffective hedges which are included in the Company’s consolidated statement of income for the six months ended March 31, 2006 and 2005, respectively.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2006

(Unaudited)

NOTE 9 - DERIVATIVE INSTRUMENTS - (Continued)

At March 31, 2006 and September 30, 2005, the Company reflected net hedging liabilities on its balance sheets of $30.3 million and $46.7 million, respectively. Of the $2.9 million net loss in accumulated other comprehensive income (loss) at March 31, 2006, the Company will reclassify $800,000 of gains to its consolidated statements of income over the next twelve month period as these contracts expire, and $3.7 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.

As of March 31, 2006, the Company (including Atlas Pipeline) had the following financial hedges in place:

Natural Gas Liquids Fixed - Price Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽¹⁾
Ended March 31,		(gallons)		(per gallon		(in thousands
2007		49,077,000	$	0.733	$	(9,269	)
2008		36,099,000		0.712		(7,343	)
2009		26,082,000		0.701		(5,208	)
2010		6,426,000		0.746		(1,113	)
					$	(22,933	)

Natural Gas Fixed - Price Swaps - Atlas⁽⁴⁾

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽³⁾
Ended March 31,	(MMBTU)⁽²⁾		(per MMBTU)		(in thousands)
2007		1,349,700	$	10.760	$	8,299
2008		4,842,900		8.760		(11,153	)
2009		4,039,100		8.710		(495	)
2010		1,220,700		8.350		1,244
					$	(2,105	)

Natural Gas Fixed - Price Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽³⁾
Ended March 31,	(MMBTU)⁽²⁾		(per MMBTU)		(in thousands)
2007		3,530,000	$	7.530	$	(466	)
2008		930,000		7.257		(2,021	)
2009		120,000		7.270		(132	)
					$	(2,619	)

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2006

(Unaudited)

NOTE 9 - DERIVATIVE INSTRUMENTS - (Continued)

Natural Gas Basis Swaps

Production			Average			Fair Value
Period	Volumes		Fixed Price			Asset⁽³⁾
Ended March 31,		(MMBTU)⁽²⁾		(per MMBTU)			(in thousands)
2007		3,870,000	$	(0.673	)	$	(409	)
2008		930,000		(0.538	)		541
2009		120,000		(0.555	)		45
						$	177

Crude Oil Fixed - Price Swaps

Production			Average		Fair Value
Period	Volumes		Strike Price		Liability⁽³⁾
Ended March 31,		(barrels)		(per barrel)		(in thousand
2007		76,100	$	53.149	$	(1,198	)
2008		80,400		56.759		(1,029	)
2009		51,300		60.019		(437	)
2010		27,000		62.700		(130	)
					$	(2,794	)

Crude Oil Options

Production			Average		Fair Value
Period	Volumes		Strike Price		Liability⁽³⁾
Ended March 31,		(barrels)		(per barrel)		(in thousands)		Option Type
2007		9,900	$	60.000	$	-		Puts purchased
2007		9,900		73.380		-		Calls sold
2008		13,200		60.000		-		Puts purchased
2008		13,200		73.380		-		Calls sold
2009		21,600		60.000		-		Puts purchased
2009		21,600		72.178		-		Calls sold
2010		22,500		60.000		-		Puts purchased
2010		22,500		71.250		-		Calls sold
					$	-
	Total net liability				$	(30,274	)

(1)		Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas and light crude prices.
(2)		MMBTU represents million British Thermal Units.
(3)		Fair value based on forward NYMEX natural gas and light crude prices, as applicable.
(4)		Represents ATLS’ hedged volumes. All others are related to Atlas Pipeline.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2006

(Unaudited)

NOTE 9 - DERIVATIVE INSTRUMENTS - (Continued)

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

	March 31, 2006				September 30, 2005
	Book Value		Fair Value		Book Value		Fair Value
Assets
Derivative instruments	$	15,909	$	15,909	$	20,963	$	20,963
	$	15,909	$	15,909	$	20,963	$	20,963
Liabilities
Derivative instruments	$	(46,183)	$	(46,183)	$	(67,625)	$	(67,625)
	$	(46,183)	$	(46,183)	$	(67,625)	$	(67,625)
	$	(30,274)	$	(30,274)	$	(46,662)	$	(46,662)

NOTE 10 - OPERATING SEGMENT INFORMATION

The Company’s operations include four 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:

Three Months Ended March 31, 2006 (in thousands):

			Production		Transmission,
	Well		And		Gathering and
		Drilling		Exploration		Processing^(a)		Other^(b)			Total
Revenues from external customers	$	50,883	$	22,866	$	110,349	$	7,958		$	192,056
Revenues from internal customers		-		-		7,893		-			-
Interest income		-		-		253		42			295
Interest expense		-		-		6,316		405			6,721
Depreciation, depletion and amortization		-		4,200		5,441		461			10,102
Segment profit (loss)		5,970		14,305		10,158		(12,400	)		18,033
Goodwill		6,389		21,527		110,632		7,249			145,797
Segment assets		8,224		268,511		740,025		43,132			1,059,892

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2006

NOTE 10 - OPERATING SEGMENT INFORMATION - (Continued)

Three Months Ended March 31, 2005 (in thousands):
			Production		Transmission,
	Well		And		Gathering and
		Drilling		Exploration		Processing^(a)		Other^(b)			Total
Revenues from external customers	$	41,451	$	13,959	$	42,344	$	3,247		$	101,001
Revenues from internal customers		-		-		5,019		-			-
Interest income		-		-		76		6			82
Interest expense		-		-		1,134		489			1,623
Depreciation, depletion and amortization		-		3,114		1,561		106			4,781
Segment profit (loss)		4,892		8,893		4,668		(5,146	)		13,307
Goodwill		6,389		21,527		2,305		7,249			37,470
Segment assets		9,263		194,287		214,923		32,961			451,434

Six Months Ended March 31, 2006 (in thousands):

				Production		Transmission,
		Well		And		Gathering and
		Drilling		Exploration		Processing^(a)		Other^(b)			Total
Revenues from external customers	$	93,028	$	46,952	$	237,682	$	13,502		$	391,164
Revenues from internal customers		-		-		15,823		-			-
Interest income		-		-		681		63			744
Interest expense		-		-		12,033		835			12,868
Depreciation, depletion and amortization		-		8,677		10,851		898			20,426
Segment profit (loss)		10,982		32,114		20,358		(26,811	)		36,643
Goodwill		6,389		21,527		110,632		7,249			145,797
Segment assets		8,224		268,511		740,025		43,132			1,059,892

Six Months Ended March 31, 2005 (in thousands):

				Production		Transmission,
		Well		And		Gathering and
		Drilling		Exploration		Processing^(a)		Other^(b)			Total
Revenues from external customers	$	72,009	$	28,618	$	84,414	$	6,654		$	191,695
Revenues from internal customers		-		-		10,300		-			-
Interest income		-		-		139		56			195
Interest expense		-		-		2,304		1,009			3,313
Depreciation, depletion and amortization		-		5,918		4,268		467			10,653
Segment profit (loss)		8,570		19,559		15,361		(16,289	)		27,201
Goodwill		6,389		21,527		2,305		7,249			37,470
Segment assets		9,263		194,287		214,923		32,961			451,434

(a)		Includes revenues and expenses from Atlas Pipeline’s Appalachia 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.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2006

(Unaudited)

NOTE 10 - 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 11 - 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 March 31, 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 March 31, 2005 would have been reduced to the pro forma amounts indicated below (in thousands, except per share data):

	Three Months Ended			Six Months Ended
	March 31, 2005			March 31, 2005

Net income, as reported	$	8,516		$	17,408
Stock-based employee compensation expense reported in net income		-			-

Stock-based employee compensation expense determined under the fair value-based method for all awards, net of income taxes		(78	)		(214	)
Pro forma net income	$	8,438		$	17,194

Net income per common share:
Basic - as reported	$	.43		$	.87
Basic - pro forma	$	.42		$	.86
Diluted - as reported	$	.43		$	.87
Diluted - pro forma	$	.42		$	.86

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2006

(Unaudited)

NOTE 11 - 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 this Plan. In January 2006, additional options for 15,000 shares were issued. 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. For the three months and six months ended March 31, 2006, the Company recorded compensation expense of $266,000 and $533,000. At March 31, 2006, the Company had unamortized compensation expense of $3.7 million.

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

	Three Months and Six Months
	Ended March 31,
	2006
			Weighted		Weighted
			Average		Average
	Shares		Exercise		Contractual
				Price		Life (Years)
Outstanding - beginning of period		1,166,250	$	25.47
Granted		15,000	$	42.76
Exercised		-	$	-0-
Forfeited		-	$	-0-
Outstanding - end of period		1,181,250	$	25.69		9.5

Exercisable, at end of period		500,000	$	25.47		9.5
Available for grant		681,250
Weighted average fair value per share of options granted during the period			$	20.00

The per share weighted average fair value of stock options granted during fiscal 2006 were 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 three months and six months ended March 31, 2005.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2006

(Unaudited)

NOTE 11 - BENEFIT PLANS - (Continued)

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 March 31, 2006 and 2005 with respect to these units was $6,300 and $3,200, respectively. Non-cash compensation recognized during the six months ended March 31, 2006 and 2005 was $12,500 and $6,300, respectively.

The following table summarizes the activity of deferred units for the period:

	Units		Weighted Average Grant Date Fair Value

Outstanding - beginning of period		10,980	$	13.67
Granted		1,500	$	46.71
Vested		-		-
Forfeited		-		-
Outstanding - end of period		12,480	$	17.64

Atlas Pipeline Long-Term Incentive Plan. Atlas Pipeline has a Long-Term Incentive Plan (“LTIP”) in which officers, employees and non-employee managing board members of its general partner and employees of the general partner's affiliates and consultants are eligable to participate. 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 $2.2 million and $449,000 in compensation expense related to these grants and their associated distributions for the three months ended March 31, 2006 and 2005, respectively, and $3.1 million and $808,000 for the six months ended March 31, 2006 and 2005, respectively.

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

	Three Months Ended					Six Months Ended
	March 31,					March 31,
	2006		2005			2006		2005

Outstanding - beginning of period		110,128		58,329			109,706		58,329
Granted		728		66,977			1,150		66,977
Vested		-		(105	)		-		(105	)
Forfeited		-		(679	)		-		(679	)
Outstanding - end of period		110,856		124,522			110,856		124,522

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 167,000 shares of RAI stock, of which 127,000 are allocated to participants. 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 March 31, 2006, there were 76,500 shares allocated to participants and 22,500 shares which are unallocated. Compensation expense related to the plan amounted to $29,000 and $58,000 for the three months and six months ended March 31, 2006, respectively. The fair value of unearned ESOP shares was $2.0 million at March 31, 2006.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2006

(Unaudited)

NOTE 11 - BENEFIT PLANS - (Continued)

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 March 31, 2006 and 2005, operations were charged $40,000 and $39,000, and during the six months ended March 31, 2006 and 2005, operations were charged $81,000 and $79,000, respectively, with respect to this commitment.

NOTE 12 − ACQUISITIONS BY ATLAS PIPELINE

NOARK

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 owns a 75% interest in NOARK. NOARK’s assets included a Federal Energy Regulatory Commission (“FERC”)-regulated interstate pipeline and an unregulated natural gas gathering system. The remaining 25% interest in NOARK is owned by Southwestern, a wholly-owned subsidiary of Southwestern Energy Company (NYSE: SWN) (see Note 18). Total consideration of $179.8 million, including $16.8 million for working capital adjustments and other related transaction costs, was funded through borrowings under Atlas Pipeline’s credit facility. The acquisition was accounted for using the purchase method of accounting under Statement of Financial Accounting Standards 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		126,238
Other assets		1,515
Intangible assets - customer contracts		11,600
Intangible assets - customer relationships		15,700
Goodwill		48,843
Total assets acquired		231,699
Accounts payable and accrued liabilities		(12,269	)
Total debt		(39,600	)
Total liabilities assumed		(51,869	)
Net assets acquired		179,830
Less: Cash and cash equivalents acquired		(16,215	)
Net cash paid for acquisition	$	163,615

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2006

(Unaudited)

NOTE 12 − ACQUISITIONS BY ATLAS PIPELINE - (Continued)

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 75% ownership interest in the results of NOARK’s operations is included within its consolidated financial statements from its date of acquisition.

Elk City

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

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 13), and the issuance of $250.0 million of 8.125% senior notes (See Note 8), had occurred on October 1, 2004. 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 October 1, 2004 or the results that will be attained in the future (shown in thousands except per share amounts):

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2006

(Unaudited)

NOTE 12 − ACQUISITIONS BY ATLAS PIPELINE - (Continued)

	Three Months Ended							Six Months Ended
	March 31, 2005							March 31, 2005
	As		Pro Forma			Pro		As		Pro Forma			Pro
	Reported		Adjustments			Forma		Reported		Adjustments			Forma
Revenues	$	101,001	$	58,661		$	159,662	$	191,695	$	135,408		$	327,103
Net income		8,516		(318	)		8,198		17,408		(536	)		16,872
Net income per common share outstanding - basic		.43		(.02	)		.41		.87		(.03	)		.84
Weighted average common shares - outstanding basic		20,000		-			20,000		20,000		-			20,000
Net income per common share - diluted		.43		(.02	)		.41		.87		(.03	)		.84
Weighted average common shares - outstanding diluted		20,007		-			20,007		20,007		-			20,007

NOTE 13 - ATLAS PIPELINE OFFERINGS

In November 2005, Atlas Pipeline sold 2.7 million common units, plus 330,000 common units in December 2005 pursuant to an option exercised by the underwriters. The sale of the units resulted in net proceeds of $123.7 million, including a $2.7 million contribution from the Company as general partner and after deducting underwriting discounts, commissions and estimated offering expenses of $6.4 million. Atlas Pipeline used the net proceeds of the offering to repay a portion of the amounts outstanding under its credit facility.

The preferred units are reflected on the Company’s consolidated balance sheet in Minority Interest and recorded at the amount of net proceeds received less an imputed dividend cost. The imputed dividend cost is the result of preferred units not having a dividend yield during the first year after their issuance on March 13, 2006. The initial imputed dividend cost of $1.9 million on the preferred units was recorded within accrued liabilities on the consolidated balance sheet and is based upon the present value of the net proceeds received using the 6.5% stated yield commencing March 13, 2007. The imputed dividend cost will be amortized for the period from issuance of the preferred units through March 13, 2007, and the amortization will be presented as a reduction of net income. Amortization of the imputed dividend cost for the three months ended March 31, 2006 was $95,000. 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 in determining net income attributable to common unitholders and the general partner.

NOTE 14 - 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. Through March 31, 2006, the Company repurchased 8,835 shares at a cost of $548,000.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

March 31, 2006

(Unaudited)

NOTE 15 - ATLAS PIPELINE HOLDINGS INITIAL PUBLIC OFFERING

In January 2006, the Company's wholly-owned subsidiary, Atlas Pipeline Holdings, L.P. ("AP Holdings"), filed a registration statement with the Securities and Exchange Commission for an initial public offering of 3,600,000 common units, representing an approximate 17.1% limited partner interest in it. Upon completion of this offering, AP Holdings will own the general partner interest, all of the incentive distribution rights and an approximate 12% limited partner interest in Atlas Pipeline.

NOTE 16 - COMMON STOCK SPLIT

On February 6, 2006, the Company’s Board of Directors authorized 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 - PROPOSED PUBLIC OFFERING

On February 27, 2006, the Company announced that it intends to transfer to a newly-formed wholly-owned limited liability company subsidiary of the Company substantially all of its natural gas and oil exploration and production assets. The Company intends to make a registered initial public offering of a minority interest, estimated to be 20%, in the newly-formed subsidiary.

NOTE 18 - SUBSEQUENT EVENTS

On May 2, 2006, Atlas Pipeline acquired the remaining 25% equity interest in NOARK from Southwestern Energy Company. Prior to this transaction, Atlas Pipeline owned a 75% equity ownership interest in NOARK, which was acquired in October 2005 from Enogex, Inc. Total consideration for the acquisition of $65.5 million, net of approximately $3.5 million for working capital purposes, was funded through borrowings under Atlas Pipeline’s credit facility. In connection with this acquisition, Southwestern Energy Company acquired the issuer of the NOARK notes and agreed to retain the obligation for the outstanding NOARK notes. As a result, neither NOARK nor Atlas Pipeline have any further liability in connection with the installment notes.

On May 4, 2006, Atlas Pipeline issued an additional $35.0 million of senior unsecured notes due 2015 in a private placement at 103% of par value for net proceeds of $36.6 million, including accrued interest and net of initial purchaser’s discount and other transaction costs. Atlas Pipeline used the net proceeds from the private placement to partially repay borrowings under its credit facility made in connection with the recent acquisition of the remaining 25% interest in NOARK. As part of the offering, NOARK and its subsidiaries became guarantors of the senior notes.

On May 9, 2006, Atlas Pipeline has agreed to sell approximately $20.0 million of its common units in a public offering under its previously filed shelf registration statement. Atlas Pipeline will primarily utilize the net proceeds from the sale to repay a portion of borrowings under its credit facility in connection with its recent aquisition of the remaining 25% interest in NOARK.

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

During the three months and six months ended March 31, 2006, we continued to grow our operations, increasing our total assets, revenues, number of wells drilled and number of wells operated.

Our gross revenues depend, to a significant extent, on the price of natural gas and oil, which can fluctuate significantly. We seek to balance this volatility with the more stable net income from our well drilling and well servicing operations which are principally fee-based. Our business strategy for increasing our reserve base includes acquisitions of undeveloped properties or companies with significant amounts of undeveloped property. At March 31, 2006, we had $77.5 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.

Recent Developments

The Company

On January 12, 2006, our subsidiary, Atlas Pipeline Holdings, L.P. (“Atlas Holdings”), filed a registration statement with the Securities and Exchange Commission for an initial public offering of 3.6 million common units, representing an approximate 17% limited partner interest in it. Upon completion of this offering, Atlas Holdings will own the general partner interest, all of the incentive distribution rights and an approximate 12.8% limited partner interest in Atlas Pipeline.

On February 6, 2006, our Board of Directors approved a three-for-two stock split effected in the form of a 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.

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 $130.0 million which may be redetermined subject to changes in our oil and gas reserves. Up to $50.0 million of the facility may be in the form of standby letters of credit. The facility is secured by our assets and bears interest at either the base rate plus the applicable margin or at the adjusted London Interbank Offered Rate (“LIBOR”) plus the applicable margin, elected at our option.

The Wachovia credit facility requires us to maintain specified ratios of current assets to current liabilities 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 March 31, 2006 and September 30, 2005, $52.5 million and $9.5 million, respectively, were outstanding under this facility, including $6.5 million and $1.5 million, respectively, under letters of credit which are not reflected as borrowings on the Company’s consolidated balance sheet. At March 31, 2006, the Company’s weighted average interest rate on outstanding borrowings was 7.7%.

Atlas Pipeline

On October 31, 2005, Atlas Pipeline acquired all of the outstanding equity interests in a subsidiary of OGE Energy Corp., which owns a 75% operating interest in NOARK Pipeline System, Limited Partnership, or NOARK. NOARK’s assets include a FERC-regulated interstate pipeline and an unregulated natural gas gathering system. Total consideration of $179.8 million, including $16.8 million for working capital adjustments and other related transaction costs, was funded through borrowings under Atlas Pipeline’s amended credit facility. The remaining 25% interest in NOARK is owned by Southwestern Energy Pipeline Company (“Southwestern”), a wholly-owned subsidiary of Southwestern Energy Company.

On November 28, 2005, Atlas Pipeline sold 2,700,000 limited partner units in a public offering for gross proceeds of $113.4 million. In addition, pursuant to an option granted to the underwriters of the offering, Atlas Pipeline sold 330,000 limited partner units on December 27, 2005 for gross proceeds of $13.9 million, or aggregate total gross proceeds of $127.3 million including the November 2005 offering. The units were issued under Atlas Pipeline’s previously filed Form S-3 shelf registration statement. The sale of the units resulted in net proceeds of approximately $120.9 million, after underwriting commissions and other transaction costs. Atlas Pipeline primarily utilized the net proceeds from the sale of the units to repay a portion of the amounts due under its credit facility.

In December 2005, the Atlas Pipeline issued $250.0 million of 10-year, 8.125% senior unsecured notes, or Senior Notes, in a private placement transaction pursuant to Rule 144A and Regulation S under the Securities Act of 1933 for net proceeds of approximately $243.1 million, after underwriting commissions and other transaction costs. Interest on the Senior Notes is payable semi-annually in arrears on June 15 and December 15, commencing on June 15, 2006. The Senior Notes are redeemable at any time on or after December 15, 2010 at certain redemption prices, together with accrued an unpaid interest to the date of redemption. The Senior Notes are also redeemable at any time prior to December 15, 2010 at a make-whole redemption price. 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 with which the net proceeds are not reinvested into Atlas Pipeline. The Senior Notes are junior in right of payment to the Atlas Pipeline secured debt, including Atlas Pipeline’s obligations under is credit facility. Atlas Pipeline utilized the net proceeds principally to repay indebtedness under its credit facility.

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, with aggregate proceeds of $30.0 million. Atlas Pipeline has the right, subject to specified conditions, before June 11, 2006, to require Sunlight Capital Partners to purchase an additional 10,000 preferred units on the same terms. 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 issuance of the preferred units will be used to fund a portion of its capital expenditures in 2006, including the construction of the Sweetwater gas plant and related gathering system.

The preferred units are reflected on our consolidated balance sheets in Minority Interest and recorded at the amount of net proceeds received less an imputed dividend cost. The imputed dividend cost is the result of preferred units not having a dividend yield during the first year after their issuance on March 13, 2006. The initial imputed dividend cost of $1.9 million on the preferred units was recorded within accrued liabilities on the consolidated balance sheet and is based upon the present value of the net proceeds received using the 6.5% stated yield commencing March 13, 2007. The imputed dividend cost will be amortized for the period from issuance of the preferred units through March 13, 2007, and the amortization will be presented as a reduction of net income. Amortization of the imputed dividend cost for the three months ended March 31, 2005 was $95,000. Distributions 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 in determining net income attributable to common unitholders and the general partner.

Results of Operations for the Three Months and Six Months Ended March 31, 2006 and 2005

Well Drilling

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

	Three Months Ended				Six Months Ended
	March 31,				March 31,
		2006		2005		2006		2005
Average drilling revenue per well	$	291	$	200	$	257	$	210
Average drilling cost per well		253		174		223		183
Average drilling gross profit per well	$	38	$	26	$	34	$	27

Gross profit margin	$	6,637	$	5,407	$	12,134	$	9,392

Gross margin percent		13%		13%		13%		13%

Net wells drilled⁽¹⁾		175		207		362		343

(1)		Reflects net wells drilled for investment partnerships.

Our well drilling gross margin was $6.6 million and $12.1 million in the three months and six months ended March 31, 2006, an increase of $1.2 million (23%) and $2.7 million (29%) from $5.4 million and $9.4 million in the three months and six months ended March 31, 2005. During the three months ended March 31, 2006, the increase of $1.2 million in gross margin was attributable to an increase in the gross profit per well ($2.4 million) partially offset by a decrease in the number of wells drilled ($1.2 million). In the six months ended March 31, 2006, the increase of $2.7 million was attributable to an increase in the gross profit per well ($2.1 million) and an increase in the number of wells drilled ($637,000). 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 March 31, 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. In addition, it should be noted that “Liabilities associated with drilling contracts” on our balance sheet includes $8.8 million of funds raised in our drilling investment programs in calendar 2005 that have not been applied to the completion of wells as of March 31, 2006 due to the timing of drilling operations, and thus had not been recognized as well drilling revenue. We expect to recognize this amount as revenue in the remainder of fiscal 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 fiscal quarter of 2006. We anticipate favorable oil and gas prices will continue to favorably impact our fundraising and therefore our drilling revenues in fiscal 2006.

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
	March 31,						March 31,
		2006			2005			2006			2005
Production revenues (in thousands):
Gas ⁽¹⁾	$	20,492		$	12,285		$	42,344		$	24,982
Oil	$	2,365		$	1,647		$	4,592		$	3,589

Production volume:
Gas (mcf/day) ^{(1) (3)}		20,866			19,315			21,170			19,806
Oil (bbls/day)		423			406			427			427
Total (mcfe/day)⁽³⁾		23,404			21,751			23,732			22,368

Average sales prices:
Gas (per mcf)^{(3) (4)}	$	10.91		$	7.07		$	10.99		$	6.93
Oil (per bbl)⁽³⁾	$	62.13		$	45.06		$	59.07		$	46.18

Production costs ⁽²⁾:
As a percent of production revenues		8	%		12	%		8	%		10	%
Per mcfe ⁽³⁾	$	.90		$	.86		$	.84		$	.71

Depletion per mcfe ⁽³⁾	$	1.98		$	1.41		$	2.00		$	1.34

(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 $9.37 and $10.24 for the three months and six months ended March 31, 2006. There were no financial hedges in the three months and six months ended March 31, 2005.

Our natural gas revenues were $20.5 million and $42.3 million in the three months and six months ended March 31, 2006, an increase of $8.2 million (66%) and $17.4 million (69%) from $12.3 million and $25.0 million in the three months and six months ended March 31, 2005. The increase in the three months and six months ended March 31, 2006 was attributable to an increase in the average sales price of natural gas of 54% and 59% and an increase of 8% and 7% in the volume of natural gas produced in the three months and six months ended March 31, 2006. The $8.2 million increase in gas revenues in the three months ended March 31, 2006 as compared to the prior period consisted of $6.7 million attributable to increases in natural gas sales prices, and $1.5 attributable to increased production volumes. The $17.4 million increase in natural gas revenues in the six months ended March 31, 2006 as compared to the prior year period consisted of $14.6 million attributable to increases in natural gas sales prices and $2.7 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 fiscal 2006 as ongoing projects to extend and enhance our gathering systems in the Appalachian Basin are completed and wells drilled are connected in these areas of expansion.

Our oil revenues were $2.4 million and $4.6 million in the three months and six months ended March 31, 2006, an increase of $718,000 (44%) and $1.0 million (28%) from $1.6 million and $3.6 million in the three months and six months ended March 31, 2005, primarily due to an increase in the average sales price of oil of 38% and 28% for the three months and six months ended March 31, 2006 as compared to the prior year similar periods. The $718,000 increase in oil revenues in three months ended March 31, 2006 as compared to the prior period consisted of $624,000 attributable to increases in sales prices and an increase of $94,000 attributable to increased production volumes. The $1.0 million increase in oil revenues for the six months ended March 31, 2006 as compared to the prior year period consisted of $998,000 attributable to increases in sales prices and $2,000 attributable to increased production volumes.

Our production costs were $1.9 million and $3.6 million in the three months and six months ended March 31, 2006, an increase of $226,000 (13%) and $750,000 (26%) from $1.7 million and $2.9 million in the three months and six months ended March 31, 2005. These 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. The decrease in production costs as a percent of production revenues in the three months and six months ended March 31, 2006 as compared to March 31, 2005 was due to an increase in our average sales price which more than offset the slight increase in production costs per mcfe.

Transmission, Gathering and Processing

Our transmission, gathering and processing revenues and related expenses for the three months ended March 31, 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 $69.4 million (161%) and $154.9 million (179%) to $112.6 million and $241.4 million for the three months and six months ended March 31, 2006 from $43.2 million and $86.5 million for the three months and six months ended March 31, 2005, primarily due to contributions from Elk City and NOARK and an increase in commodity prices.

Our expenses increased $53.9 million (144%) and $128.2 million (175%) to $91.4 million and $201.3 million for the three months and six months ended March 31, 2006 from $37.5 million and $73.1 million for the three months and six months ended March 31, 2005, primarily due to acquisitions and an increase in commodity prices.

Drilling Management Fee

Our drilling management fee represents supervision and administrative fees earned for drilling wells for our investment partnerships. Due to a change in our drilling agreement; 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 agreement.

Well Services

Our well services revenues were $2.8 million and $5.3 million in the three months and six months ended March 31, 2006, an increase of $416,000 (18%) and $728,000 (16%) from $2.3 million and $4.6 million in the three months and six months ended March 31, 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 March 31, 2006.

Our well services expenses were $1.8 and $3.3 million in the three months and six months ended March 31, 2006, an increase of $450,000 (34%) and $746,000 (30%) from $1.3 million and $2.5 million in the three months and six months ended March 31, 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 $10.2 million and $18.2 million in the three months and six months ended March 31, 2006, an increase of $8.7 million and $15.1 million from $1.5 million and $3.1 million in the three months and six months ended March 31, 2005. 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 $8.7 million in the three months ended March 31, 2006 is principally attributable the following:

•

general and administrative expenses related to Atlas Pipeline’s operations increased $3.1 million primarily as a result of Atlas Pipeline’s acquisitions of Elk City on April 14, 2005 and NOARK on October 31, 2005, therefore, we had no such expenses in the quarter ended March 31, 2005. In addition, general and administrative expense reimbursements from our investment partnerships decreased by $5.4 million as prior year amounts were reduced by reimbursements and credits from our drilling partnerships. The reimbursements are now included in revenue as drilling management fees in accordance with a change in our drilling agreements.

The increase of $15.1 million in the six months ended March 31, 2006 is principally attributed to the following:

•		general and administrative expenses related to Atlas Pipeline’s Mid-Continent operations were $5.9 million, an increase of $4.6 million primarily attributable to costs associated with operations of Atlas Pipeline’s acquisitions of Elk City and NOARK,

•		general and administrative expense reimbursements from our investment partnerships decreased by $6.5 million as prior year amounts were reduced by reimbursements and credits from our drilling partnerships. The reimbursements are now included in revenue as drilling management fees in accordance with a change in our drilling agreements,

•		salaries and wages increased $1.1 million due to an increase in executive salaries and in the number of employees as a result of our spin-off from RAI,

•		professional and legal fees increased $2.0 million primarily due to higher audit fees and implementation of Sarbanes-Oxley Section 404 compliance,

•		expense recognized in connection with our non-cash stock compensation was $532,000; there were no such expenses in the prior year similar period; and

•		directors’ fees increased $443,000 as a result of our spin-off from RAI.

Our depletion of oil and gas properties as a percentage of oil and gas revenues was 18% in the three months and six months ended March 31, 2006, compared to 19% in the three months and six months ended March 31, 2005. Depletion expense per mcfe was $1.98 and $2.00 in the three months and six months ended March 31, 2006, an increase of $.57 (40%) and $.66 (49%) per mcfe from $1.41 and $1.34 in the three months and six months ended March 31, 2005. Increases in our depletable basis and production volumes caused depletion expense to increase $1.4 million (52%) and $3.1 million (58%) to $4.2 million and $8.6 million in the three months and six months ended Mach 31, 2006 compared to $2.8 million and $5.5 million in the three months and six months ended March 31, 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 $3.9 million (192%) and $6.6 million (127%), to $5.9 million and $11.8 million in the three months and six months ended March 31, 2006 compared to $2.0 million and $5.2 million in the three months and six months ended March 31, 2005. This was primarily due to the increased asset base associated with Atlas Pipeline’s acquisitions.

Our interest expense was $6.7 million and $12.9 million in the three months and six months ended March 31, 2006, an increase of $5.1 million and $9.6 million from $1.6 million and $3.3 million in the three months and six months ended March 31, 2005. This increase resulted primarily from an increase in outstanding borrowings by Atlas Pipeline to fund the acquisitions of Elk City and NOARK. Atlas Pipeline also incurred interest expense of $5.3 million and $5.9 million in the three months and six months ended March 31, 2006 related to its December 2005 issuance of $250 million Senior Notes. We had no such expense in the three months or six months ended March 31, 2005.

At March 31, 2006, we own 14% of the partnership interest in Atlas Pipeline through our general partner interest and limited partner units. Our ownership interest decreased 10% from 24% at March 31, 2005 as a result of the completion by Atlas Pipeline of common unit offerings in June and November 2005. Our interest also decreased on March 13, 2006 due to Atlas Pipeline’s issuance of $30 million 6.5% cumulative preferred units.

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 $6.3 million and $13.0 million for the three months and six months ended March 31, 2006, as compared to $2.5 million and $9.7 million for the three months and six months ended March 31, 2005, an increase of $3.8 million and $3.3 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 increased to 37% for the three months and six months ended March 31, 2006 as compared to 36% for the three months and six months ended March 31, 2005 as a result of a reduction in statutory depletion benefits relative to increased net income.

Liquidity and Capital Resources

General. We fund our exploration 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
	March 31,
		2006			2005
Provided by operations	$	6,564		$	31,962
Used in investing activities		(227,036	)		(41,590	)
Provided by (used in) financing activities		244,989			(2,503	)
Increase (decrease) in cash and cash equivalents	$	24,517		$	(12,131	)

We had $42.8 million in cash and cash equivalents at March 31, 2006, as compared to $18.3 million at September 30, 2005. Our ratio of earnings from continuing operations before income taxes, minority interest and interest expense to fixed charges was 5 to 1 in the six months ended March 31, 2006 as compared to 12 to 1 in the six months ended March 31, 2005. We had working capital of $1.8 million at March 31, 2006, an increase of $78.6 million from September 30, 2005. The increase in our working capital is due to an increase in cash and accounts receivable as a result of our Mid-Continent operations, including the NOARK acquisition, and a decrease in our accrued hedge liabilities and liabilities associated with our drilling partnerships. This was partially offset by an increase in accounts payable and accrued liabilities.

Our long-term debt (including current maturities) was 229% and 159% of our total equity at March 31, 2006 and September 30, 2005, respectively. Since September 30, 2005, total stockholders’ equity has increased by $26.1 million and total debt has increased by $143.6 million. Stockholders’ equity increased principally due to net earnings of $23.1 million for the six months ended March 31, 2006. The increase in long-term debt relates to increased borrowings to fund Atlas Pipeline’s acquisitions and our drilling operations.

On April 27, 2006 we increased the borrowing base under our credit facility to $130.0 million. At March 31, 2006, we had $77.5 million available on this credit facility. Atlas Pipeline had no outstanding balance on its $225.0 million credit facility and $214.0 million available at March 31, 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 $25.4 million in the six months ended March 31, 2006 to $6.6 million from $32.0 million in the six months ended March 31, 2006, substantially as a result of the following:

•		an increase in net income before depreciation and amortization of $16.1 million in the six months ended March 31, 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 and compensation expense resulting from grants under long-term incentive plans; and

•		changes in minority interests and distributions paid to minority interests decreased cash flow by $4.3 million due to an increase in Atlas Pipeline's earnings and our decreased ownership percentage, offset by higher distributions paid to minority interests, and

•		changes in our deferred tax liability increased cash flow by $614,000 as compared to the six months ended March 31, 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 $41.0 million in the six months ended March 31, 2006, compared to the six months ended March 31, 2005.

This decrease is primarily a result of the following:

•		a decrease of $3.6 million in accounts payable and accrued liabilities

•		a decrease of $29.8 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.

•		an increase of $1.6 million in accounts receivable and prepaid expenses

Cash flows from investing activities. Cash used in our investing activities increased $185.4 million in the six months ended March 31, 2006 to $227.0 million from $41.6 million in the six months ended March 31, 2005 primarily as a result of the following:

•		cash used in Atlas Pipeline’s acquisition of NOARK was $163.6 million; and

•		capital expenditures increased $23.3 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 increased $247.5 million in the six months ended March 31, 2006 to $245.0 million from cash used of $2.5 million in the six months ended March 31, 2005, as a result of the following:

•		payments to affiliate primarily related to our share of income taxes included in RAI’s income tax return decreased by $19.4 million in the six months ended March 31, 2006, there was no such payment made in the six months ended March 31, 2006, as a result of our spin-off from RAI;

•		net borrowings on debt increased by $78.7 million in the six months ended March 31, 2006 as compared to the prior year similar period principally as a result of the issuance of Atlas Pipeline’s Senior Notes partially offset by payments on borrowings associated with the acquisition of NOARK;

•		we received aggregate proceeds of $151.0 million from Atlas Pipeline’s November 2005 and March 2006 common and preferred unit offerings; there were no such offerings in the first half of 2005;

•		an increase in other assets of $1.7 million related to financing costs associated with Atlas Pipeline’s Senior Notes.

Capital Requirements: During the six months ended March 31, 2006, our capital expenditures related primarily to investments in our drilling partnerships and pipeline expansions, in which we invested $32.1 million and $30.4 million, respectively. For the three months and six months ended March 31, 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 fiscal 2006 through drilling partnerships. Through the six months ended March 31, 2006 we had raised $52.5 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 March 31, 2006.

			Payments Due By Period
			(in thousands)
			Less than		2 - 3		4 - 5		After 5
Contractual cash obligations:		Total		1 Year		Years		Years		Years
Long-term debt⁽¹⁾	$	335,310	$	1,365	$	2,545	$	2,400	$	329,000
Secured revolving credit facilities		-		-		-		-		-
Operating lease obligations		4,719		1,851		2,341		525		2
Capital lease obligations		-		-		-		-		-
Unconditional purchase obligations		-		-		-		-		-
Other long-term obligation		-		-		-		-		-
Total contractual cash obligations	$	340,029	$	3,216	$	4,886	$	2,925	$	329,002

(1)

Not included in the table above are estimated interest payments calculated at the rates in effect at March 31, 2006 of: 2007 - $26.1 million; 2008 - $26.0 million; 2009 - $26.0 million; 2010 - $26.0 million and 2011 - $23.6 million.

			Payments Due By Period
			(in thousands)
			Less than		1 - 3		4 - 5		After 5
Other commercial commitments:		Total		1 Year		Years		Years		Years
Standby letters of credit	$	17,525	$	17,500	$	25	$	-	$	-
Guarantees		-		-		-		-		-
Standby replacement commitments		-		-		-		-		-
Other commercial commitments		28,333		28,333		-		-		-
Total commercial commitments	$	45,858	$	45,833	$	25	$	-	$	-

Critical Accounting Policies

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

For a detailed discussion on the application of policies critical to our business operations and other accounting policies, see our Annual Report on Form 10-K for the year ended September 30, 2005 Note 2 of the "Notes to Consolidated Financial Statements" and Note 2 to the “Notes to Consolidated Financial Statements” included in this report.

Recently Issued Financial Accounting Standards

In May 2005, the Financial Accounting Standards Board, or FASB, issued SFAS No. 154, “Accounting Changes and Error Corrections”, or SFAS 154. SFAS 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle. It also requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than being reported in an income statement. The statement will be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but management does not currently expect SFAS 154 to have a material impact on the Company’s financial position or results of operations.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” or FIN 47, which will result in (a) more consistent recognition of liabilities relating to asset retirement obligations, (b) more information about expected future cash outflows associated with those obligations, and (c) more information about investments in long-lived assets because additional asset retirement cost will be recognized as part of the carrying amounts of the assets. FIN 47 clarifies that the term conditional asset retirement obligation as used in Statement No. 143, “Accounting for Asset Retirement Obligations”, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists.

FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. Retrospective application of interim financial information is permitted but is not required. Early adoption of this interpretation is encouraged. We do not believe the interpretation will have a significant impact on our financial position or results of operations.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

General

We are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We manage these risks through regular operating and financing activities and periodically use derivative financial instruments.

The following analysis presents the effect on our earnings, cash flows and financial position as if the hypothetical changes in market risk factors occurred on March 31, 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 March 31, 2006, the amount outstanding under our credit facility increased to $46 million from $8.0 million at September 30, 2005. The weighted average interest rate for this facility increased from 6.1% at September 30, 2005 to 7.7% at March 31, 2006 due to an increase in market index rates on these borrowings.

At March 31, 2006, Atlas Pipeline had a $225.0 million revolving credit facility ($0 outstanding at March 31, 2006). The weighted average interest rate for these borrowings was 6.6% at September 30, 2005. Holding all other variables constant, if interest rates hypothetically increased or decreased by 10%, our net annual income would change by approximately $223,000.

Commodity Price Risk. Our major market risk exposure in commodities is fluctuations in the pricing of our gas and oil production. Realized pricing is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas production. Pricing for gas and oil production has been volatile and unpredictable for many years. To limit our exposure to changing natural gas prices, we use hedges. Through our hedges, we seek to provide a measure of stability in the volatile environment of natural gas prices. These transactions are similar to NYMEX-based futures contracts, swaps and options, but also require firm delivery of the hedged quantity. Thus, we limit these arrangements to much smaller quantities than those projected to be available at any delivery point. For the twelve month period ending March 31, 2007, we estimate approximately 62% of our produced natural gas volumes will be sold in this manner, leaving our remaining production to be sold at contract prices in the month produced or at spot market prices. 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.

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

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

At March 31, 2006, we had 108 open natural gas futures contracts related to natural gas sales covering 11,452,000 dekatherms (“Dth”) (net to us) of natural gas, maturing through December 31, 2009 at a combined average settlement price of $8.94 per Dth. We recognized a gain of $1.4 million on settled contracts covering natural gas production for the three months and six months ended March 31, 2006. We recognized no gains or losses during the three months and six months ended March 31, 2006 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges.

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 $2.4 million and $669,000 related to the settlement of qualifying hedge instruments which are included in our consolidated statements of income for the three months ended March 31, 2006 and 2005, respectively. Atlas Pipeline also recognized a gain of $1.2 million and a loss of $224,000 related to the change in market value of non-qualifying or ineffective hedges which are included in our consolidated statements of income for the three months ended March 31, 2006 and 2005, respectively. Atlas Pipeline recognized losses of $8.0 million and $645,000 related to the settlement of qualifying hedge instruments which are included in our consolidated statements of income for the six months ended March 31, 2006 and 2005, respectively. Atlas Pipeline also recognized gains of $860,000 and $216,000 related to the change in market value of non-qualifying or ineffective hedges which are included in our consolidated statements of income for the six months ended March 31, 2006 and 2005, respectively.

At March 31, 2006 and September 30, 2005, we reflected net hedging liabilities on our balance sheets of $30.3 million and $46.7 million, respectively. Of the $2.9 million net loss in accumulated other comprehensive income (loss) at March 31, 2006, we will reclassify $800,000 of gains to our consolidated statements of income over the next twelve month period as these contracts expire, and $3.7 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.

As of March 31, 2006, we (including Atlas Pipeline) had the following financial hedges in place:

Natural Gas Liquids Fixed - Price Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽¹⁾
Ended March 31,		(gallons)		(per gallon)		(in thousands)
2007		49,077,000	$	0.733	$	(9,269	)
2008		36,099,000		0.712		(7,343	)
2009		26,082,000		0.701		(5,208	)
2010		6,426,000		0.746		(1,113	)
					$	(22,933	)

Natural Gas Fixed - Price Swaps - Atlas⁽⁴⁾

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽³⁾
Ended March 31,		(MMBTU)⁽²⁾		(per MMBTU)		(in thousands)
2007		1,349,700	$	10.760	$	8,299
2008		4,842,900		8.760		(11,153	)
2009		4,039,100		8.710		(495	)
2010		1,220,700		8.350		1,244
					$	(2,105	)

Natural Gas Fixed - Price Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽³⁾
Ended March 31,		(MMBTU)⁽²⁾		(per MMBTU)		(in thousands)
2007		3,530,000	$	7.530	$	(466	)
2008		930,000		7.257		(2,021	)
2009		120,000		7.270		(132	)
					$	(2,619	)

Natural Gas Basis Swaps

Production			Average			Fair Value
Period	Volumes		Fixed Price			Asset⁽³⁾
Ended March 31,	(MMBTU)⁽²⁾		(per MMBTU)			(in thousands)
2007		3,870,000	$	(0.673	)	$	(409	)
2008		930,000		(0.538	)		541
2009		120,000		(0.555	)		45
						$	177

Crude Oil Fixed - Price Swaps

Production			Average		Fair Value
Period	Volumes		Strike Price		Liability⁽³⁾
Ended March 31,	(barrels)		(per barrel)		(in thousands)
2007		76,100	$	53.149	$	(1,198	)
2008		80,400		56.759		(1,029	)
2009		51,300		60.019		(437	)
2010		27,000		62.700		(130	)
					$	(2,794	)

Crude Oil Options

Production			Average		Fair Value
Period	Volumes		Strike Price		Liability⁽³⁾
Ended March 31,		(barrels)		(per barrel)		(in thousands)		Option Type
2007		9,900	$	60.000	$	-		Puts purchased
2007		9,900		73.380		-		Calls sold
2008		13,200		60.000		-		Puts purchased
2008		13,200		73.380		-		Calls sold
2009		21,600		60.000		-		Puts purchased
2009		21,600		72.178		-		Calls sold
2010		22,500		60.000		-		Puts purchased
2010		22,500		71.250		-		Calls sold
					$	-
	Total net liability				$	(30,274	)

(1)		Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas and light crude prices.
(2)		MMBTU represents million British Thermal Units.
(3)		Fair value based on forward NYMEX natural gas and light crude prices, as applicable.
(4)		Represents our hedged volumes. All others are related to Atlas Pipeline.

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

PART II. OTHER INFORMATION

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

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

January 1 - 31, 2006		-		-		-
February 1 - 28, 2006		7,500		63.26		7,500
March 1 - 31, 2006		-	$	-		-
Total		7,500	$	63.26		7,500		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 ($49.4 million remaining at March 31, 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.
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 10-Q for the quarter ended March 31, 2004.
(2)		Previously filed as an exhibit to our Form 8-K filed on May 16, 2005.

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: May 9, 2006	By: /s/ Matthew A. Jones
	Matthew A. Jones
	Chief Financial Officer



Date: May 9, 2006	By: /s/Nancy J. McGurk
	Nancy J. McGurk Senior Vice President and Chief Accounting Officer

Positive
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Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

ARKHAN Inactive 10-Q2006 Q1 Quarterly report

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