ARKHAN 10Q 2005 Q4 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 December 31, 2005

[ ]	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 February 1, 2006 was 13,355,065 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 - December 31, 2005 and September 30, 2005	3

	Consolidated Statements of Income Three Months Ended December 31, 2005 and 2004	4

	Consolidated Statement of Changes in Stockholders’ Equity for the Three Months Ended December 31, 2005	5

	Consolidated Statements of Cash Flows for the Three Months Ended December 31, 2005 and 2004	6

	Notes to Consolidated Financial Statements - December 31, 2005	7 - 26

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27 - 36

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	37 - 40

Item 4.	Controls and Procedures	41

PART II	OTHER INFORMATION

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

Item 5.	Other Information	42

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)

	December 31,			September 30,
	2005			2005
ASSETS
Current assets:
Cash and cash equivalents	$	55,155		$	18,281
Accounts receivable		89,830			73,996
Prepaid expenses		5,772			5,063
Deferred tax asset		6,249			6,970
Advances to affiliate		492			-
Total current assets		157,498			104,310

Property and equipment, net		658,347			505,967
Intangible assets, net		60,959			18,708
Other assets, net		74,313			15,360
Goodwill		105,063			115,366
	$	1,056,180		$	759,711
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	1,351		$	122
Accounts payable		56,769			31,477
Liabilities associated with drilling contracts		70,514			60,971
Accrued producer liabilities		32,537			32,543
Accrued hedge liability		24,107			37,663
Accrued liabilities		33,091			18,231
Advances from affiliate		-			111
Total current liabilities		218,369			181,118

Long-term debt		297,430			191,605
Deferred tax liability		29,369			28,903
Other liabilities		54,865			47,612

Minority interest		323,297			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		133			133
Additional paid-in capital		75,967			75,637
Treasury stock, at cost		(73	)		-
ESOP loan receivable		(564	)		(583	)
Accumulated other comprehensive loss		(5,116	)		(5,615	)
Retained earnings		62,503			50,779
Total stockholders’ equity		132,850			120,351
	$	1,056,180		$	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
	December 31,
	2005			2004

REVENUES
Well drilling	$	42,145		$	30,558
Gas and oil production		24,086			14,659
Transmission, gathering and processing		129,460			43,782
Drilling management fee		1,576			-
Well services		2,561			2,248
		199,828			91,247

COSTS AND EXPENSES
Well drilling		36,648			26,573
Gas and oil production and exploration		2,458			1,802
Transmission, Gathering and processing		109,889			35,680
Well services		1,487			1,191
General and administrative		8,048			1,660
Compensation reimbursement - affiliate		163			213
Depreciation, depletion and amortization		10,324			5,872
		169,017			72,991

OPERATING INCOME		30,811			18,256

OTHER INCOME (EXPENSE)
Interest expense		(6,147	)		(1,690	)
Minority interest in Atlas Pipeline Partners, L.P.		(6,745	)		(7,220	)
Arbitration settlement, net		-			4,446
Other, net		691			102
		(12,201	)		(4,362	)

Income from continuing operations before income taxes		18,610			13,894
Provision for income taxes		6,886			5,002
Net income	$	11,724		$	8,892

Net income per common share - basic
Net income per common share - basic	$	.88		$	.67
Weighted average common shares outstanding		13,335			13,333

Net income per common share - diluted
Net income per common shares - diluted	$	.87		$	.67
Weighted average common shares outstanding		13,477			13,338

See accompanying notes to consolidated financial statements

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

THREE MONTHS ENDED DECEMBER 31, 2005

(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																				11,724		11,724
Other comprehensive income																	499					499
Issuance of common stock		1,328		-		64																64
Repurchase of common stock, at cost								(1,335	)		(73	)										(73	)
Repayment of ESOP loan														19								19
Stock option compensation		-		-		266		-			-			-			-			-		266
Balance, December 31, 2005		13,336,031	$	133	$	75,967		(1,335	)	$	(73	)	$	(564	)	$	(5,116	)	$	62,503	$	132,850

See accompanying notes to consolidated financial statements

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

THREE MONTHS ENDED DECEMBER 31, 2005

(in thousands)

(Unaudited)

	Three Months Ended
	December 31,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	11,724		$	8,892
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		10,324			5,872
Amortization of deferred financing costs		544			310
Non-cash loss on derivative value		138			795
Non-cash compensation on long-term incentive plans		1,320			416
Minority interest in Atlas Pipeline Partners, L.P.		6,745			7,220
Gain on asset dispositions		(2	)		(24	)
Deferred income taxes		1,033			725
Changes in operating assets and liabilities		27,324			29,219
Net cash provided by operating activities		59,150			53,425

CASH FLOWS FROM INVESTING ACTIVITIES:
Business acquisition, net of cash acquired		(163,630	)		-
Capital expenditures		(31,809	)		(16,882	)
Proceeds from sale of assets		3			35
Decrease (increase) in other assets		495			(327	)
Net cash used in investing activities		(194,941	)		(17,174	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings		216,841			27,502
Principal payments on debt		(399,367	)		(50,556	)
Issuance of Atlas Pipeline Partners, L.P. common units		120,980			-
Payments to affiliate		-			(9,349	)
Issuance of Atlas Pipeline Partners, L.P. Senior Notes		243,102			-
Distributions paid to minority interests of Atlas Pipeline Partners, L.P.		(6,381	)		(3,839	)
Increase in other assets		(2,510	)		(42	)
Net cash provided by (used in) financing activities		172,665			(36,284	)

Increase (decrease) in cash and cash equivalents		36,874			(33	)
Cash and cash equivalents at beginning of period		18,281			29,192
Cash and cash equivalents at end of period	$	55,155		$	29,159

See accompanying notes to consolidated financial statements

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2005

(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 15% and 24% at December 31, 2005 and 2004, respectively. The limited partner units were subordinated until January 1, 2005, when the subordination term expired and they were converted to common units in accordance with the terms of the partnership agreement.

The consolidated financial statements and the information and tables contained in the notes to the consolidated financial statements as of December 31, 2005 and for the three months ended December 31, 2005 and 2004 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 three months ended December 31, 2005 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 three months ended December 31, 2004 to conform to the presentation as of and for the three months ended December 31, 2005.

Spin-off from Resource America, Inc.

On June 30, 2005, Resource America, Inc. (“RAI”) (NASDAQ: REXI) distributed its remaining 10.7 million shares of the Company to its stockholders in the form of a tax-free dividend. Each stockholder of RAI received 0.59367 shares of the Company 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. The Company anticipates that it may reimburse to RAI all or a portion of any liability arising from this transaction. 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.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2005

(Unaudited)

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

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.

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 December 31 and September 30, 2005, the Company’s credit evaluation indicated that it has no need for an allowance for possible losses.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2005

(Unaudited)

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

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 December 31 and September 30, 2005 of $71.6 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).

	Three Months Ended
	December 31,
	2005			2004
Net income	$	11,724		$	8,892
Other comprehensive income (loss):
Unrealized holding gain (loss) on hedging contracts, net of tax of $653 and $(1,351)		(1,112	)		2,402
Less: reclassification adjustment for (gain) loss realized in net income, net of tax of $(946) and $29		1,611			(51	)
		499			2,351
Comprehensive income	$	12,223		$	11,243

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
	December 31,
	2005		2004
Net Income	$	11,724	$	8,892

Weighted average common shares outstanding-basic		13,335		13,333
Dilutive effect of stock option and award plan		142		5
Weighted average common shares-diluted		13,477		13,338

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2005

(Unaudited)

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.

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

	December 31,			September 30,
	2005			2005
Mineral interests:
Proved properties	$	2,308		$	2,852
Unproved properties		1,002			1,002
Wells and related equipment		273,725			255,879
Pipelines, processing and compression facilities		445,859			304,523
Rights-of-way		15,769			15,110
Land, building and improvements		7,799			7,793
Support equipment		4,201			3,675
Other		6,292			5,251
		756,955			596,085
Accumulated depreciation, depletion and amortization:
Oil and gas properties and pipelines		(94,105	)		(85,824	)
Other		(4,503	)		(4,294	)
		(98,608	)		(90,118	)
	$	658,347		$	505,967

In April 2005, Atlas Pipeline completed the acquisition of ETC Oklahoma Pipeline, Ltd. (“Elk City”) and, in October 2005, the acquisition of a 75% interest in NOARK Pipeline System, Limited Partnership (“NOARK”) for an aggregate of approximately $375.8 million (see Note 12). The purchase price allocations for these acquisitions are based on estimated values determined by Atlas Pipeline, which are subject to adjustment and could change significantly as they are futher evaluated. At December 31, 2005, the portion of the purchase price allocated to property, plant and equipment for these acquisitions are included in the pipelines, processing and compression facilities category within the above table.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2005

(Unaudited)

NOTE 6 - OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL

Other Assets

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

	December 31,		September 30,
	2005		2005
Deferred financing costs, net of accumulated amortization of $3,063 and $2,519	$	15,654	$	5,524
Investments		1,647		1,647
Security deposits		1,725		1,779
Minority interest in NOARK		41,481		-
Hedge receivable - long term		13,727		5,970
Other		79		440
	$	74,313	$	15,360

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 December 31, 2005, Atlas Pipeline had $54.9 million of intangible assets, net of accumulated amortization of $2.1 million which was recorded in connection with natural gas gathering contracts and customer relations assumed in its acquisition 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 an estimated life of eight and 20 years, respectively, and are amortized on a straight-line basis, was $1.6 million and $0 for the three months ended December 31, 2005 and 2004, respectively.

Partnership 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 13 years. Amortization expense for these contracts for the three months ended December 31, 2005 and 2004 was $220,000 and $233,000, respectively.

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

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2005

(Unaudited)

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

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

	December 31,					September 30,
	2005					2005
			Accumulated					Accumulated
	Cost		Amortization			Cost		Amortization
Customer contracts and relations	$	56,950	$	(2,081	)	$	12,891	$	(492	)
Partnership management and operating contracts		14,343		(8,253	)		14,343		(8,034	)
Intangible assets	$	71,293	$	(10,334	)	$	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).

	December 31,			September 30,
	2005			2005

Goodwill at beginning of period, net of accumulated amortization of $4,532	$	115,366		$	37,470
Adjustment to goodwill related to Atlas Pipeline acquisitions (see Note 12)		(10,303	)		77,896
Goodwill at end of period, net of accumulated amortization of $4,532	$	105,063		$	115,366

NOTE 7 - ASSET RETIREMENT OBLIGATIONS

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

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
	December 31,
	2005		2004
Asset retirement obligations, beginning of year	$	17,651	$	4,888
Liabilities incurred		725		650
Liabilities settled		-		(4	)
Accretion expense		123		84
Asset retirement obligations, end of year	$	18,499	$	5,618

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2005

(Unaudited)

NOTE 7 - ASSET RETIREMENT OBLIGATIONS - (Continued)

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):

	December 31,		September 30,
	2005		2005
Senior notes - Atlas Pipeline	$	250,000	$	-
Revolving credit facility - Atlas Pipeline		9,500		183,500
Revolving credit facility		-		8,000
Installment notes - NOARK		39,000		-
Other debt		281		227
		298,781		191,727
Less current maturities		1,351		122
	$	297,430	$	191,605

Atlas Pipeline Senior Notes. In December 2005, Atlas Pipeline and its subsidiary, Atlas Pipeline Finance Corporation, 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. 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 is 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 December 31, 2005.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2005

(Unaudited)

NOTE 8 - DEBT - (Continued)

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 within 120 days of issuance of the Senior Notes, (b) cause the exchange offer registration statement to be declared effective by the Securities and Exchange Commission within 210 days of issuance, and (c) cause the exchange offer to be consummated within 240 days of issuance. 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.

Installment notes - NOARK. Upon Atlas Pipeline’s acquisition of a 75% interest in NOARK at October 31, 2005, NOARK’s subsidiary, NOARK Pipeline Finance, L.L.C., had $66.0 million in principal amount outstanding of 7.15% notes due in 2018. 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. Liability under the notes was originally allocated severally 40% to Enogex and 60% to Southwestern, and the parties were several guarantors for their respective allocations. The notes are subject to a semi-annual redemption in installments of $600,000 each at a redemption price of 100% of the principal, plus accrued and unpaid interest. Additionally, at the option of either Enogex or Southwestern, notes in an aggregate principal amount guaranteed by either company as of a particular payment date may be redeemed at such notes’ redemption price plus a make-whole premium and unpaid interest accrued to that date by giving the trustee at least 60 days notice. As part of the NOARK acquisition, Enogex agreed to redeem its portion of the notes as promptly as practicable after the closing. The redemption of $26.4 million of the notes occurred on December 5, 2005. At December 31, 2005, $39.0 million of notes remain outstanding and are presented on the Company’s consolidated balance sheet, for which Southwestern remains liable. Under the NOARK partnership agreement, payments on the notes will be made from amounts otherwise distributable to Southwestern and, if that amount is insufficient, Southwestern is required to make a capital contribution to NOARK. NOARK distributes cash available for distribution to the partners, after amounts payable on their respective allocations of the notes, in accordance with their percentage interests.

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

2006	$	1,351
2007		1,300
2008		1,230
2009		1,200
2010 and thereafter		293,700
	$	298,781

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2005

(Unaudited)

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.

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 December 31, 2005, the Company had 60 open natural gas futures contracts related to natural gas sales covering 5,845,000 dekatherms (“Dth”) (net to the Company) of natural gas, maturing through December 31, 2009 at a combined average settlement price of $9.24 per Dth. The Company has not recognized any income or loss on settled contracts covering natural gas production for the three months ended December 31, 2005 or 2004, respectively. The Company recognized no gains or losses during the three months ended December 31, 2005 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 AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2005

(Unaudited)

NOTE 9 - DERIVATIVE INSTRUMENTS - (Continued)

Derivatives are recorded in the same manner as the company. At December 31 and September 30, 2005, the Company reflected net hedging liabilities on its balance sheets of $41.5 million and $46.7 million, respectively. Of the $5.1 million net loss in accumulated other comprehensive income (loss) at December 31, 2005, the Company will reclassify $538,000 of losses to its consolidated statements of income over the next twelve month period as these contracts expire, and $4.6 million 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. Atlas Pipeline recognized losses of $5.6 million and a gain of $24,000 related to the settlement of qualifying hedge instruments which are included in the Company’s consolidated statement of income for the three months ended December 31, 2005 and 2004, respectively. Atlas Pipeline also recognized a loss of $320,000 and a gain of $440,000 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 December 31, 2005 and 2004, respectively.

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

As of December 31, 2005, the Company (including Atlas Pipeline) had the following NGLs, natural gas, and crude oil volumes hedged:

Natural Gas Liquids Fixed - Price Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽²⁾
Ended December 31,	(gallons)		(per gallon)		(in thousands)
2006		40,068,000	$	0.683	$	(12,119	)
2007		36,036,000		0.717		(9,157	)
2008		33,012,000		0.697		(7,365	)
					$	(28,641	)

Natural Gas Fixed - Price Swaps⁽⁴⁾

Production			Average		Fair Value
Period	Volumes		Fixed Price		Asset⁽³⁾
Ended December 31,	(MMBTU)⁽¹⁾		(per MMBTU)		(in thousands)
2006⁽⁴⁾		1,115,000	$	11.62	$	3,190
					$	3,190

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2005

(Unaudited)

NOTE 9 - DERIVATIVE INSTRUMENTS - (Continued)

Natural Gas Fixed - Price Swaps⁽⁴⁾

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽³⁾
Ended December 31,	(MMBTU)⁽¹⁾		(per MMBTU)		(in thousands)
2006		1,100,000	$	6.985	$	(4,093	)
2006⁽⁴⁾		225,000		10.76		(312	)
2007		1,080,000		7.255		(3,242	)
2007 ⁽⁴⁾		2,124,000		8.770		(7,714	)
2008		240,000		7.270		(606	)
2008⁽⁴⁾		2,381,000		8.400		(6,242	)
					$	(22,209	)

Natural Gas Basis Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Asset⁽³⁾
Ended December 31,	(MMBTU)⁽¹⁾		(per MMBTU)		(in thousands)
2006		1,200,000	$	-0.551	$	3,916
2007		1,080,000		-0.535		3,581
2008		240,000		-0.555		808
					$	8,305

Fixed Purchase Price - Price Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽³⁾
Ended December 31,	(MMBTU)⁽¹⁾		(per MMBTU)		(in thousands)
2006		442,500	$	7.429	$	(1,711	)
					$	(1,711	)

Fixed Price Purchase Basis Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Asset⁽³⁾
Ended December 31,	(MMBTU)⁽¹⁾		(per MMBTU)		(in thousands)
2006		527,500	$	-0.544	$	1,776
					$	1,776

Plant Volume Reduction Fixed - Price Swaps

Production				Average		Fair Value
Period	Volumes			Fixed Price		Asset⁽³⁾
Ended December 31,	(MMBTU)⁽¹⁾			(per MMBTU)		(in thousands)
2006		(1,650,000	)	$	7.255	$	5,694
						$	5,694

Plant Volume Reduction Basis Swaps

Production				Average		Fair Value
Period	Volumes			Fixed Price		Liability⁽²⁾
Ended December 31,	(MMBTU)⁽¹⁾			(per MMBTU)		(in thousands)
2006		(1,800,000	)	$	-0.495	$	(6,165	)
						$	(6,165	)

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2005

(Unaudited)

NOTE 9 - DERIVATIVE INSTRUMENTS - (Continued)

Crude Oil Fixed - Price Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽³⁾
Ended December 31,	(barrels)		(per barrel)		(in thousands)
2006		77,600	$	51.545	$	(881	)
2007		80,400		56.069		(643	)
2008		62,400		59.267		(223	)
					$	(1,747	)
				Total liability	$	(41,508	)

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

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

	December 31, 2005						September 30, 2005
	Book Value			Fair Value			Book Value			Fair Value
Assets
Derivative instruments	$	18,965		$	18,965		$	20,963		$	20,963
	$	18,965		$	18,965		$	20,963		$	20,963
Liabilities
Derivative instruments	$	(60,473	)	$	(60,473	)	$	(67,625	)	$	(67,625	)
	$	(60,473	)	$	(60,473	)	$	(67,625	)	$	(67,625	)
	$	(41,508	)	$	(41,508	)	$	(46,662	)	$	(46,662	)

NOTE 10 - OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS

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:

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2005

(Unaudited)

NOTE 10 - OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS - (Continued)

Three Months Ended December 31, 2005 (in thousands):
			Production		Atlas Pipeline		Atlas
	Well		and		Mid-		Pipeline
	Drilling		Exploration		Continent		Appalachia		Other^(a)			Total
Revenues from external customers	$	42,145	$	24,086	$	127,501	$	1,959	$	4,137		$	199,828
Interest income		-		-		345		83		21			449
Interest expense		-		-		767		-		5,380			6,147
Depreciation, depletion and amortization		-		4,477		4,660		750		437			10,324
Segment profit (loss)		5,012		17,089		8,885		220		(12,596	)		18,610
Goodwill		6,389		21,527		67,593		2,305		7,249			105,063
Segment assets		8,428		256,210		645,801		91,176		54,565			1,056,180

Three Months Ended December 31, 2004 (in thousands):
				Production		Atlas Pipeline		Atlas
		Well		and		Mid-		Pipeline
		Drilling		Exploration		Continent		Appalachia		Other^(a)			Total
Revenues from external customers	$	30,558	$	14,659	$	42,061	$	1,721	$	2,248		$	91,247
Interest income		-		-		-		-		113			113
Interest expense		-		-		8		-		1,682			1,690
Depreciation, depletion and amortization		-		2,804		2,162		545		361			5,872
Segment profit (loss)		3,678		10,113		3,648		70		(3,615	)		13,894
Goodwill		6,389		21,527		-		2,305		7,249			37,470
Segment assets		9,006		185,347		157,308		39,351		47,822			438,834

(a)	Includes revenues and expenses from well services which do not meet the quantitative threshold for reporting segment information and general corporate expenses not allocable to any particular segment.

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.

The Company’s NGL’s and natural gas are sold under contract to various purchasers. For the three months ended December 31, 2005, NGL sales to ONEOK Hydrocarbon, L.P. and Oilco Gas Co., accounted for 12% and 10% of total revenues, respectively. No other operating segments had revenues from a single purchaser which exceeded 10% of total revenues.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2005

(Unaudited)

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. For the three months ended December 31, 2005, the Company recorded compensation expense of $168,000, net of taxes of $98,000. At December 31, 2005, the Company had unamortized compensation expense of $3.7 million. There were no options granted or exercised in either of the three month periods ended December 31, 2005 and 2004.

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 ended December 31, 2004 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 ended December 31, 2004 would have been reduced to the pro forma amounts indicated below (in thousands, except per share data):


	Three Months Ended
	December 31, 2004
Net income, as reported	$	8,892
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 tax of ($77)		(136	)
Pro forma net income	$	8,756

Net income per common share:
Basic - as reported	$	.67
Basic - pro forma	$	.66
Diluted - as reported	$	.67
Diluted - pro forma	$	.66

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2005

(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 1,333,333 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 777,500 shares were issued under this Plan. Options under the Plan become exercisable as to 25% of the optioned shares each year after the date of grant, except options totaling 500,000 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.

The following table summarizes certain information about the Plan’s stock options as of December 31, 2005.

	(a)	(b)	(c)
Plan category	Number of securities to be issued upon exercise of outstanding options	Weighted-average exercise price of outstanding options	Number of securities remaining available for future issuance under equity compensation plans excluding securities reflected in column (a)
Equity compensation plan approved by security holders	777,500	$38.21	548,513

The fair value of each option grant is estimated on the date of grant using the binomial (lattice) model with the following weighted average assumptions:

	Three Months Ended
	December 31,
	2005		2004
Expected life (in years)		10.0		10.0
Risk-free interest rate		4.1%		4.1%
Expected volatility		46%		23%
Expected dividend yield		0%		0%

Additionally, under the Plan, on an annual basis, non-employee directors of the Company are awarded deferred units having a fair market value at the date of grant of $15,000. Each unit represents the right to receive one share of the Company’s common stock upon vesting. The shares vest one-third on the second anniversary of the grant, one-third on the third anniversary of the grant and one-third on the fourth anniversary of the grant. In May 2005 and 2004, 2,485 and 4,835 deferred units, respectively, representing a right to receive a share of common stock over a 4-year vesting period (at an average price of $30.19 and $15.50, respectively, per unit) were awarded to non-employee directors of the Company under this Plan. 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 ($75,000) in total each year is being charged to operations over the vesting periods. Upon termination of service by a grantee, all unvested units are forfeited. Non-cash compensation expense recognized during the three months ended December 31, 2005 and 2004 with respect to these units was $6,300 and $3,100, respectively.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2005

(Unaudited)

NOTE 11 - BENEFIT PLANS - (Continued)

The following information applies to stock options and deferred units outstanding as of December 31, 2005:

Outstanding							Exercisable
			Weighted		Weighted				Weighted
Range of			Average		Average				Average
Exercise			Contractual		Exercise				Exercise
Prices	Shares		Life (Years)		Price		Shares		Price
$-0-		7,320		8.71	$	-0-		-0-	$	-0-
$38.21		777,500		9.50	$	38.21		500,000	$	38.21
		784,820						500,000

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 December 31, 2005, 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 for the three months ended December 31, 2005. The fair value of unearned ESOP shares was $2.0 million at December 31, 2005.

Supplemental Employment 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 December 31, 2005 and 2004, operations were charged $40,300 and $39,000, respectively, with respect to this commitment.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2005

(Unaudited)

NOTE 11 - BENEFIT PLANS - (Continued)

Atlas Pipeline Plan. Atlas Pipeline has a Long-Term Incentive Plan (“LTIP”) for officers and non-employee managing board members of its general partner and employees of the general partner, consultants and joint venture partners who perform services for Atlas Pipeline. Atlas Pipeline recognized $939,000 and $359,000 in compensation expense related to these grants and their associated distributions for the three months ended December 31, 2005 and 2004, respectively.

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

	Three Months Ended
	December 31,
	2005		2004
Outstanding, beginning of period		192,853		58,752
Granted		422		-
Performance factor adjusted⁽¹⁾		36,653		-
Matured		-		-
Forfeited		-		-
Outstanding, end of period⁽²⁾		229,928		58,752

(1)	Consists of performance-based awards.
(2)	Of the units outstanding under the LTIP at December 31, 2005, 31,320 units will vest within the following twelve months.

NOTE 12 − ACQUISITIONS BY ATLAS PIPELINE

NOARK

On October 31, 2005, Atlas Pipeline acquired from Enogex, Inc., a wholly-owned subsidiary of OGE Energy Corp. (NYSE: OGE), of all of the outstanding equity of Atlas Arkansas Pipeline, L.P., which owns a 75% interest in NOARK, for $179.8 million, including $16.8 million for working capital adjustments and other related transaction costs. The remaining 25% interest in NOARK is owned by Southwestern Energy Pipeline Company (“Southwestern”), a wholly-owned subsidiary of Southwestern Energy Company (NYSE: SWN). Before the closing of the acquisition, Atlas Arkansas converted from an Oklahoma corporation into an Oklahoma limited liability company and changed its name from Enogex Arkansas Pipeline Company. The NOARK acquisition further expands Atlas Pipeline’s activities in the Mid-Continent region and provides an additional source of fee-based cash flows from a FERC-regulated interstate pipeline system and an intrastate gas gathering system. NOARK’s geographic position relative to Atlas Pipeline’s other businesses and interconnections with major interstate pipelines also provides it with organic growth opportunities. NOARK’s principal assets include:

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2005

(Unaudited)

NOTE 12 − ACQUISITIONS BY ATLAS PIPELINE - (Continued)

•		The Ozark Gas Transmission system, a 565-mile FERC-regulated interstate pipeline system which extends from southeast Oklahoma through Arkansas and into southeast Missouri and has a throughput capacity of approximately 322 MMcf/d. The system includes approximately 30 supply and delivery interconnections and two compressor stations.

•		The Ozark Gas Gathering system, a 365-mile intrastate natural gas gathering system, located in eastern Oklahoma and western Arkansas, and 11 associated compressor stations.

Atlas Pipeline financed the acquisition by borrowing under its revolving credit facility and has since reduced those borrowings with proceeds from its November 2005 equity offering and December 2005 Senior Notes offering (see Notes 8 and 13).

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	$	16,214
Accounts receivable		12,272
Prepaid expenses		497
Property, plant and equipment		126,306
Minority interest in NOARK		42,564
Other assets		1,515
Intangible assets		27,300
Goodwill		6,456
Total assets acquired		233,125

Accounts payable and accrued liabilities		(13,694	)
Long-term debt		(39,600	)
Total liabilities assumed		(53,294	)
Net assets acquired	$	179,830

Elk City

On April 14, 2005, Atlas Pipeline acquired all of the outstanding equity interests in Elk City, for $196.0 million, including related transaction costs. Elk City’s principal assets included 318 miles of natural gas pipelines located in the Anadarko Basin in western Oklahoma, a natural gas processing facility in Elk City, Oklahoma, with total capacity of 130 million cubic feet of gas per day ("mmcf/d") and a gas treatment facility in Prentiss, Oklahoma, with a total capacity of 100 mmcf/d. The purchase price was subject to post-closing adjustments based upon, among other things, gas imbalances, certain prepaid expenses and capital expenditures, and title defects, if any. The acquisition was accounted for using the purchase method of accounting under SFAS No. 141.

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2005

(Unaudited)

NOTE 12 − ACQUISITIONS BY ATLAS PIPELINE - (Continued)

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		29,650
Goodwill		61,136
Total assets acquired		200,976
Accounts payable and accrued liabilities		(4,970	)
Total liabilities assumed		(4,970	)
Net assets acquired	$	196,006

The purchase price allocation for Elk City and NOARK are based upon preliminary data that is subject to adjustment and could change significantly as Atlas Pipeline continues to evaluate these allocations. Atlas Pipeline recognized goodwill in connection with these acquisitions as a result of Elk City’s and NOARK’s significant cash flow and its strategic industry position. All of the intangible assets, which consist of customer contracts and relations, are subject to amortization and have a weighted-average useful life of 8 to 20 years. The goodwill is assigned to the natural gas and liquids segment and is expected to be deductible for tax purposes. The results of these acquisitions are included within the consolidated financial statements from their 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 in June and November 2005, the net proceeds of which were utilized to repay debt borrowed to finance the acquisitions (see Note 13) and the debt offering in December 2005, 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. The pro-forma financial information for the three months ended December 31, 2005, is immaterial and therefore has not been presented (shown in thousands except per share amounts):

	Three Months Ended
	December 31, 2004
	As		Pro Forma			Pro
	Reported		Adjustments			Forma
Revenues	$	91,247	$	76,747		$	167,994
Net income	$	8,892	$	(218	)	$	8,674
Net income per common share outstanding - basic	$	.67	$	(.02	)	$	.65
Weighted average common shares - outstanding basic		13,333		-			13,333
Net income per common share - diluted	$	.67	$	(.02	)	$	.65
Weighted average common shares		13,338		-			13,338

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2005

(Unaudited)

NOTE 13 - ATLAS PIPELINE EQUITY OFFERING

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 Company’s interest in Atlas Pipeline decreased to 14.8% as a result of this offering.

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. The Company repurchased 1,335 shares at a cost of $73,000 through December 31, 2005.

NOTE 15 - SUBSEQUENT EVENTS

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 12.8% limited partner interest in Atlas Pipeline. This public offering is expected to generate proceeds of as much as $103.0 million.

On February 6, 2006, the Company’s Board of Directors authorized a three-for-two split of the Company’s common stock to be effected in the form of a 50% stock dividend. All shareholders of record as of February 28, 2006 will receive one additional share of common stock for every two shares held on that date. The additional shares of common stock will be distributed on or about March, 2006, in the form of a stock dividend. Information pertaining to shares and earnings per share has not been restated in the accompanying financial statements and notes to the consolidated financial statements to reflect this split. This information will be presented effective after the stock dividend is distributed (i.e. with the Company’s March 31, 2006 interim financial statements).

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 ended December 31, 2005, 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 December 31, 2005, we had $58.5 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 to be effected in the form of a stock dividend. Shareholders of record as of February 28, 2006, will receive one additional share of common stock for each two shares of common stock they own on that date. The shares will be distributed on or about March 10, 2006. As of February 6, 2006, there were approximately 13.3 million shares of our common stock issued and outstanding. After the split, there will be approximately 20.0 million shares of our common stock outstanding. We expect the adjusted number of shares outstanding and adjusted per-share stock price to be reported by the Nasdaq Stock Market, effective March 10, 2006.

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 and its subsidiary, Atlas Pipeline Finance Corp., 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 25 and December 25, commencing on June 15, 2006. The Senior Notes are redeemable at any time on or after December 25, 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 25, 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.

Results of Operations for the Three Months Ended December 31, 2005 and 2004

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
	December 31,
	2005			2004
Average drilling revenue per well	$	225		$	224
Average drilling cost per well		196			195
Average drilling gross profit per well	$	29		$	29

Gross profit margin	$	5,497		$	3,985

Gross margin percent		13	%		13	%

Net wells drilled		187			136

Our well drilling gross margin was $5.5 million in the three months ended December 31, 2005, an increase of $1.5 million from $4.0 million in the three months ended December 31, 2004. During the three months ended December 31, 2005, the increase in gross margin was attributable to an increase in the number of wells drilled ($1.5 million) and an increase in the gross profit per well ($13,000). 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 ended December 31, 2005 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 $59.0 million of funds raised in our drilling investment programs in calendar 2005 that have not been applied to drill wells as of December 31, 2005 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 $52.1 million raised bringing the total for the calendar year to $113.7 million. We anticipate higher 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
	December 31,
	2005			2004
Production revenues (in thousands):
Gas ⁽¹⁾	$	21,851		$	12,697
Oil	$	2,227		$	1,942

Production volume:
Gas (mcf/day) ^{(1) (3)}		21,468			20,286
Oil (bbls/day)		431			447
Total (mcfe/day)⁽³⁾		24,054			22,968

Average sales prices:
Gas (per mcf)⁽³⁾	$	11.06		$	6.80
Oil (per bbl)⁽³⁾	$	56.13		$	47.17

Production costs ⁽²⁾:
As a percent of production revenues		10	%		12	%
Per mcfe ⁽³⁾	$	1.10		$	.83

Depletion per mcfe ⁽³⁾	$	2.01		$	1.28

(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, gathering charges 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.

Our natural gas revenues were $21.9 million in the three months ended December 31, 2005, an increase of $9.2 million (72%) from $12.7 million in the three months ended December 31, 2004. The increase in the three months ended December 31, 2005 was attributable to an increase in the average sales price of natural gas of 63% for the three months ended December 31, 2005 and an increase of 6% in the volume of natural gas produced in the three months ended December 31, 2005. The $9.2 million increase in gas revenues in the three months ended December 31, 2005 as compared to the prior period consisted of $8.0 million attributable to increases in natural gas sales prices, and $1.2 attributable to increased production volumes.

The increase in our gas production volumes resulted from 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 $2.2 million in the three months ended December 31, 2005, an increase of $285,000 (15%), from $1.9 million in the three months ended December 31, 2004, primarily due to an increase in the average sales price of oil of 19% for the three months ended December 31, 2005. The $285,000 increase in oil revenues in three months ended December 31, 2005 as compared to the prior period consisted of $369,000 attributable to increases in sales prices, partially offset by a decrease of $84,000 attributable to decreased production volumes.

Our production costs were $2.4 million in the three months ended December 31, 2005, an increase of $691,000 (40%) from $1.7 million in the three months ended December 31, 2004. These increases include an increase in pumping labor and an increase in transportation expenses associated with increased production volumes and natural gas sales prices, as a portion of our wells are charged transportation based on the sales price of the gas transported. The decrease in production costs as a percent of production revenues in the three months ended December 31, 2005 as compared to December 31, 2004 was 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 December 31, 2005 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 $85.7 million (196%) to $129.5 million for the three months ended December 31, 2005 from $43.8 million for the three months ended December 31, 2004, primarily due to contributions from Elk City & NOARK and an increase in commodity prices.

Our expenses increased $74.2 million to $109.9 million for the three months ended December 31, 2005 from $35.7 for the three months ended December 31, 2004, primarily due to aquisitions and an increase in commodity prices.

Well Services

Our well services revenues were $2.6 million in the three months ended December 31, 2005, an increase of $312,000 (14%) from $2.2 million in the three months ended December 31, 2004. The 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 December 31, 2005.

Our well services expenses were $1.5 million in the three months ended December 31, 2005, an increase of $295,000 (25%) from $1.2 million in the three months ended December 31, 2004. The 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 $8.0 million in the three months ended December 31, 2005, an increase of $6.3 million from $1.7 million in the three months ended December 31, 2004. 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. These expenses are partially offset by reimbursements we receive from our drilling investment partnerships.

The increase in the three months ended December 31, 2005 is principally attributed to the following:

•		general and administrative expenses related to Atlas Pipeline’s Mid-Continent operations were $1.7 million, an increase of $1.1 million primarily attributable to costs associated with operations of Elk City acquired in April 2005 and NOARK acquired in October 2005,

•		net syndication costs increased $1.1 million as we continue to expand our syndication activities and the drilling funds we raise in our public and private partnerships,

•		general and administrative expense reimbursements from our investment partnerships decreased by $1.1 million as prior year amounts were reduced by reimbursements from our drilling partnerships which are now included in revenue in accordance with a change in our drilling agreements,

•		salaries and wages increased $969,000 due to an increase in executive salaries and the in the number of employees as a result of our spin-off from RAI,

•		professional and legal fees increased $905,000 primarily due to higher audit fees and implementation of Sarbanes-Oxley Section 404 compliance,

•		costs associated with Atlas Pipeline’s long term incentive plan were $939,000, an increase of $580,000 over the three months ended December 2004,

•		expense recognized in connection with our non-cash stock compensation was $266,000; there were no such expenses in the prior year similar period; and

•		directors’ fees increased $263,000 as a result of our spin-off from RAI.

Our compensation reimbursements-affiliate was $163,000 for the three months ended December 31, 2005, a decrease of $50,000 from $213,000 in the three months ended December 31, 2004, respectively. This decrease resulted from a decrease in allocations from our former parent for executive management and administrative services as we now directly employ many of the individuals previously being allocated to us and therefore include their compensation in our general and administrative expenses.

Our depletion of oil and gas properties as a percentage of oil and gas revenues was 18% in the three months ended December 31, 2005 and December 31, 2004. Depletion expense per mcfe was $2.01 in the three months ended December 31, 2005, an increase of $.73 (57%) per mcfe from $1.28 in the three months ended December 31, 2004. Increases in our depletable basis and production volumes caused depletion expense to increase $1.7 million (65%) to $4.4 million in the three months ended December 31, 2005 compared to $2.7 million in the three months ended December 31, 2004. The variances from period to period are directly attributable to changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties.

Depreciation and amortization increased $2.7 million (85%), to $5.9 million in the three months ended December 31, 2005 compared to $3.2 million in the three months ended December 31, 2004. This was primarily due to the increased asset base associated with Atlas Pipeline Mid-Continent acquisitions.

Our interest expense was $6.1 million in the three months ended December 31, 2005, an increase of $4.4 million from $1.7 in the three months ended December 31, 2004. This increase resulted primarily from an increase in outstanding borrowings by Atlas Pipeline to fund the acquisitions of Elk City and NOARK.

At December 31, 2005, we own 15% of the partnership interest in Atlas Pipeline through our general partner interest and limited partner units. Our ownership interest decreased 9% from 24% at December 31, 2004 as a result of the completion by Atlas Pipeline of common unit offerings in June and November 2005.

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 $6.7 million for the three months ended December 31, 2005, as compared to $7.2 million for the three months ended December 31, 2004, a decrease of $500,000. The decrease in 2005 is due to Atlas Pipeline’s arbitration settlement with SEMCO Energy, Inc., resulting in net income of $4.4 million in 2004 partially offset by 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 ended December 31, 2005 as compared to 36% for the three months ended December 31, 2004 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 common units. The following table sets forth our sources and uses of cash (in thousands):

	Three Months Ended
	December 31,
	2005			2004
Provided by operations	$	59,150		$	53,425
Used in investing activities		(194,941	)		(17,174	)
Provided by (used in) financing activities		172,665			(36,284	)
Increase (decrease) in cash and cash equivalents	$	36,874		$	(33	)

We had $55.2 million in cash and cash equivalents at December 31, 2005, as compared to $29.2 million at December 31, 2004. Our ratio of earnings from continuing operations before income taxes, minority interest and interest expense to fixed charges was 5 to 1 in the three months ended December 31, 2005 as compared to 13 to 1 in the three months ended December 31, 2004. We had a working capital deficit of $60.9 million at December 31, 2005, a decrease of $15.9 million from September 30, 2005. The decrease in our working capital deficit 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. This was partially offset by an increase in accounts payable and liabilities associated with our drilling partnerships.

Our long-term debt (including current maturities) was 225% and 159% of our total equity at December 31, 2005 and September 30, 2005, respectively. Since September 30, 2005, total stockholders’ equity has increased by $12.5 million and total debt has increased by $107.1 million. Stockholders’ equity increased principally due to net earnings of $11.7 million for the three months ended December 31, 2005. The increase in long-term debt relates to increased borrowings to fund Atlas Pipeline’s acquisitions.

We have a borrowing base under our credit facility of $75.0 million. At December 31, 2005, we had $58.5 million available on this credit facility. Atlas Pipeline had $9.5 million borrowed against its $225.0 million credit facility at an average rate of 7.1% and $204.5 million available at December 31, 2005.

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 increased $5.8 million in the three months ended December 31, 2005 to $59.2 million from $53.4 million in the three months ended December 31, 2004, substantially as a result of the following:

•		An increase in net income before depreciation and amortization of $7.5 million in the three months ended December 31, 2005 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 $250,000 related to losses on Atlas Pipeline’s hedge value and compensation expense resulting from grants under long-term incentive plans.

•		Changes in operating assets and liabilities decreased operating cash flow by $1.9 million in the three months ended December 31, 2005, compared to the three months ended December 31, 2004, primarily due to increases during the three months ended December 31, 2005 in accounts receivable related to our Mid-Continent operations partially offset by an increase in accounts payable and accrued liabilities as compared to December 31, 2004. 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.

Cash flows from investing activities. Cash used in our investing activities increased $177.7 million in the three months ended December 31, 2005 to $194.9 million from $17.2 million in the three months ended December 31, 2004 as a result of the following:

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

•		Capital expenditures increased $14.9 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 $209.0 million in the three months ended December 31, 2005 to $172.7 million from cash used of $36.3 million in the three months ended December 31, 2004, as a result of the following:

•		Payments to RAI primarily related to our share of income taxes included in RAI’s income tax return decreased by $9.3 million in the three months ended December 31, 2005, there was no such payment made in the three months ended December 2005, as a result of our spin-off from RAI;

•		Net borrowings on debt increased by $83.6 million in the three months ended December 31, 2005 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; and

•		We received proceeds of $121.0 million from Atlas Pipeline’s November 2005 public offering. There was no such offering in the first quarter of fiscal 2005.

These increases were partially offset by the following:


•		Distributions paid to minority interests increased $2.5 million as a result of higher earnings and more common units outstanding for Atlas Pipeline as a result of its fiscal 2004 and 2005 offerings of common units; and

•		An increase in other assets of $2.5 million related to financing costs associated with Atlas Pipeline’s new senior notes.

Capital Requirements: During the three months ended December 31, 2005, our capital expenditures related primarily to investments in our drilling partnerships and pipeline expansions, in which we invested $15.2 million and $16.6 million, respectively. For the three months ended December 31, 2005 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 three months ended December 31, 2005 we had raised $52.1 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 December 31, 2005.

			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⁾	$	298,781	$	1,351	$	2,530	$	11,900	$	283,000
Secured revolving credit facilities		-		-		-		-		-
Operating lease obligations		4,761		1,978		2,149		632		2
Capital lease obligations		-		-		-		-		-
Unconditional purchase obligations		-		-		-		-		-
Other long-term obligation		-		-		-		-		-
Total contractual cash obligations	$	302,542	$	3,329	$	4,679	$	12,532	$	283,002

(1)	Not included in the table above are estimated interest payments calculated at the rates in effect at December 31, 2005 of: 2006 - $23.7 million; 2007 - $23.6 million; 2008 - $23.5 million; 2009 - $23.4 million and 2010 - $22.9 million.

			Payments Due By Period
			(in thousands)
			Less than		1 - 3		4 - 5		After 5
Other commercial commitments:	Total		1 Year		Years		Years		Years
Standby letters of credit	$	27,525	$	27,500	$	25	$	-	$	-
Guarantees		-		-		-		-		-
Standby replacement commitments		-		-		-		-		-
Other commercial commitments		18,955		18,955		-		-		-
Total commercial commitments	$	46,480	$	46,455	$	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 December 31, 2005. 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 December 31, 2005, the amount outstanding under our credit facility was $0 from $8.0 million at September 30, 2005. The weighted average interest rate for this facility was 6.1% at September 30, 2005.

At December 31, 2005, Atlas Pipeline had a $225.0 million revolving credit facility ($9.5 million outstanding). The weighted average interest rate for these borrowings increased from 6.6% at September 30, 2005 to 7.1% at December 31, 2005. Holding all other variables constant, if interest rates hypothetically increased or decreased by 10%, our net annual income would change by approximately $6,000.

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 December 31, 2006, we estimate approximately 63% 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 December 31, 2005, we had 60 open natural gas futures contracts related to natural gas sales covering 5,845,000 dekatherms (“Dth”) (net to us) of natural gas, maturing through December 31, 2009 at a combined average settlement price of $9.24 per Dth. We have not recognized any income or loss on settled contracts covering natural gas production for the three months ended December 31, 2005 or 2004, respectively. We recognized no gains or losses during the three months ended December 31, 2005 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges.

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.

Derivatives are recorded on the balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, the effective portion of changes in fair value are recognized in stockholders’ equity as Accumulated Other Comprehensive Income (Loss) and reclassified to earnings as such transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, changes in fair value are recognized in earnings as they occur. At December 31 and September 30, 2005, the Company reflected net hedging liabilities on its balance sheets of $41.5 million and $46.7 million, respectively. Of the $5.1 million net loss in accumulated other comprehensive income (loss) at December 31, 2005, the Company will reclassify $538,000 of losses to its consolidated statements of income over the next twelve month period as these contracts expire, and $4.6 million 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. Atlas Pipeline recognized losses of $5.6 million and a gain of $24,000 related to the settlement of qualifying hedge instruments which are included in the Company’s consolidated statement of income for the three months ended December 31, 2005 and 2004, respectively. Atlas Pipeline also recognized a loss of $320,000 and a gain of $440,000 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 December 31, 2005 and 2004, respectively.

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

As of December 31, 2005, we had the following NGLs, natural gas, and crude oil volumes hedged:

Natural Gas Liquids Fixed - Price Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽²⁾
Ended December 31,	(gallons)		(per gallon)		(in thousands)
2006		40,068,000	$	0.683	$	(12,119	)
2007		36,036,000		0.717		(9,157	)
2008		33,012,000		0.697		(7,365	)
					$	(28,641	)

Natural Gas Fixed - Price Swaps⁽⁴⁾

Production			Average		Fair Value
Period	Volumes		Fixed Price		Asset⁽³⁾
Ended December 31,	(MMBTU)⁽¹⁾		(per MMBTU)		(in thousands)
2006⁽⁴⁾		1,115,000	$	11.62	$	3,190
					$	3,190

Natural Gas Fixed - Price Swaps⁽⁴⁾

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽³⁾
Ended December 31,	(MMBTU)⁽¹⁾		(per MMBTU)		(in thousands)
2006		1,100,000	$	6.985	$	(4,093	)
2006⁽⁴⁾		225,000		10.76		(312	)
2007		1,080,000		7.255		(3,242	)
2007⁽⁴⁾		2,124,000		8.770		(7,714	)
2008		240,000		7.270		(606	)
2008⁽⁴⁾		2,381,000		8.400		(6,242	)
					$	(22,209	)

Natural Gas Basis Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Asset⁽³⁾
Ended December 31,	(MMBTU)⁽¹⁾		(per MMBTU)		(in thousands)
2006		1,200,000	$	-0.551	$	3,916
2007		1,080,000		-0.535		3,581
2008		240,000		-0.555		808
					$	8,305

Fixed Price Purchase - Price Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽³⁾
Ended December 31,	(MMBTU)⁽¹⁾		(per MMBTU)		(in thousands)
2006		442,500	$	7.429	$	(1,711	)
					$	(1,711	)

Fixed Price Purchase Basis Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Asset⁽³⁾
Ended December 31,	(MMBTU)⁽¹⁾		(per MMBTU)		(in thousands)
2006		527,500	$	-0.544	$	1,776
					$	1,776

Plant Volume Reduction Fixed - Price Swaps

Production				Average		Fair Value
Period	Volumes			Fixed Price		Asset⁽³⁾
Ended December 31,	(MMBTU)⁽¹⁾			(per MMBTU)		(in thousands)
2006		(1,650,000	)	$	7.255	$	5,694
						$	5,694

Plant Volume Reduction Basis Swaps

Production				Average		Fair Value
Period	Volumes			Fixed Price		Liability⁽²⁾
Ended December 31,	(MMBTU)⁽¹⁾			(per MMBTU)		(in thousands)
2006		(1,800,000	)	$	-0.495	$	(6,165	)
						$	(6,165	)

Crude Oil Fixed - Price Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability⁽³⁾
Ended December 31,	(barrels)		(per barrel)		(in thousands)
2006		77,600	$	51.545	$	(881	)
2007		80,400		56.069		(643	)
2008		62,400		59.267		(223	)
					$	(1,747	)
				Total liability	$	(41,508	)

(1)	MMBTU represents million British Thermal Units.
(2)	Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas and light crude prices.
(3)	Fair value based on forward NYMEX natural gas and light crude prices, as applicable.
(4)	Represents ATLS’s 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 December 31, 2005. 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

October 1-31, 2005		-		-		-
November 1-30, 2005		-		-		-
December 1-31, 2005		1,335	$	54.67		1,335
Total		1,335	$	54.67		1,335		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 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 5. Other Information

In January 2006, the Company issued restricted stock to certain employees pursuant to the Company’s stock incentive plan. The form of the stock award agreement and is attached hereto as Exhibit 10.14 and is filed pursuant to Item 1.01 of Form 8-K.

Item 6. Exhibits

Exhibit No. Description

3.2	Amendments to Bylaws ⁽¹⁾
10.3	Revolving Credit and Term Loan Agreement dated as of April 14, 2005 among Atlas Pipeline Partners, L.P., Wachovia Bank, National Association, and the other parties named therein
10.3(a)	First Amendment to Revolving Credit and Term Loan Agreement dated as of October 31, 2005
10.4	Amendment dated October 25, 2005 among Atlas America, Inc., Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership;, L.P., Resource Energy, Inc., Viking Resources Corporation, Atlas Noble Corp. and Atlas Resources, Inc.
10.5	Atlas Pipeline Partners, L.P. Indenture dated December 20, 2005
10.6	Atlas Pipeline Partners, L.P. Registration Rights Agreement dated December 20, 2005
10.14	Form of Stock Award Agreement
10.15	Stock Purchase Agreement dated September 21, 2005
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 10Q for the quarter ended March 31, 2004.

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: February 9, 2006	By: /s/ Matthew A. Jones
	Matthew A. Jones
	Executive Vice President and Chief Financial Officer



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

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

ARKHAN Inactive 10-Q2005 Q4 Quarterly report

Content analysis