ARKHAN 10-Q 2005 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2005

OR

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

For the transition period from _________ to __________

Commission file number:  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 o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes o    No x

The number of outstanding shares of the registrant’s common stock on August 1, 2005 was 13,333,333 shares.

ATLAS AMERICA, INC.

INDEX TO QUARTERLY REPORT ON FORM 10-Q

		Page
PART I	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Consolidated Balance Sheets - June 30, 2005 and September 30, 2004	3
	Consolidated Statements of Income Three Months and Nine Months Ended June 30, 2005 and 2004	4
	Consolidated Statement of Changes in Stockholders’ Equity for the Nine Months Ended June 30, 2005	5
	Consolidated Statements of Cash Flows for the Nine Months Ended June 30, 2005 and 2004	6
	Notes to Consolidated Financial Statements - June 30, 2005	7 - 24
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25 - 34
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	36 - 39
Item 4.	Controls and Procedures	39
PART II	OTHER INFORMATION
Item 4.	Submission of Matters to a Vote of Security Holders	39 - 40
Item 6.	Exhibits	40
SIGNATURES		41

2

PART I.  FINANCIAL INFORMATION

Item 1. Financial Statements

ATLAS AMERICA, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)

	June 30, 2005			September 30, 2004
ASSETS
Current assets:
Cash and cash equivalents	$	18,877		$	29,192
Accounts receivable		44,503			24,113
Prepaid expenses		4,782			2,433
Deferred tax asset		2,103			2,212
Total current assets		70,265			57,950
Property and equipment, net		503,916			313,091
Intangible assets, net		6,543			7,243
Other assets, net		10,474			7,955
Goodwill		97,470			37,470
	$	688,668		$	423,709
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	121		$	3,401
Accounts payable		28,127			20,869
Liabilities associated with drilling contracts		55,627			29,375
Accrued producer liabilities		23,364			8,815
Accrued hedge liability		11,972			3,972
Accrued liabilities		23,417			10,795
Advances from affiliate		1,286			-
Total current liabilities		143,914			77,227
Long-term debt		180,140			82,239
Advances from parent		-			10,413
Deferred tax liability		25,658			23,654
Other liabilities		16,834			6,949
Minority interest		207,647			132,224
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		75,584			75,584
ESOP loan receivable		(602	)		-
Accumulated other comprehensive loss		(2,331	)		(2,553	)
Retained earnings		41,691			17,839
Total stockholders’ equity		114,475			91,003
	$	688,668		$	423,709

See accompanying notes to consolidated financial statements

3

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per share data)

(Unaudited)

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	(in thousands, except per share data)
REVENUES
Well drilling	$	26,749		$	16,370		$	98,758		$	64,577
Gas and oil production		16,051			12,977			44,669			34,972
Gathering, transmission and processing		81,322			1,344			168,845			4,522
Well services		2,422			2,146			7,020			6,206
		126,544			32,837			319,292			110,277
COSTS AND EXPENSES
Well drilling		23,259			14,235			85,876			56,154
Gas and oil production and exploration		2,452			2,369			6,667			7,377
Gathering, transmission and processing		70,485			551			143,627			1,767
Well services		1,293			1,009			3,800			3,071
General and administrative		4,709			2,254			7,863			3,713
Compensation reimbursement - affiliate		145			350			602			1,050
Depreciation, depletion and amortization		6,506			3,458			17,159			10,237
		108,849			24,226			265,594			83,369
OPERATING INCOME		17,695			8,611			53,698			26,908
OTHER INCOME (EXPENSE)
Interest expense		(4,580	)		(460	)		(7,893	)		(1,420	)
Minority interest in Atlas Pipeline Partners, L.P.		(1,247	)		(1,593	)		(10,967	)		(4,188	)
Arbitration settlement, net		(11	)		-			4,299			-
Other, net		156			110			77			609
		(5,682	)		(1,943	)		(14,484	)		(4,999	)
Income from continuing operations before income taxes		12,013			6,668			39,214			21,909
Provision for income taxes		5,569			2,486			15,362			7,668
Net income	$	6,444		$	4,182		$	23,852		$	14,241
Net income per common share - basic
Net income per common share - basic	$	.48		$	.35			1.79		$	1.28
Weighted average common shares outstanding		13,333			12,015			13,333			11,129
Net income per common share - diluted
Net income per common shares - diluted	$	.48		$	.35			1.79		$	1.28
Weighted average common shares outstanding		13,339			12,018			13,339			11,131

See accompanying notes to consolidated financial statements

4

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

NINE MONTHS ENDED JUNE 30, 2005

(in thousands, except share data)

(Unaudited)

	Common Stock				Additional Paid-In		ESOP Loan			Accumulated Other Comprehensive			Retained		Total Stockholders’
	Shares		Amount		Capital		Receivable			Income (Loss)			Earnings		Equity
Balance, October 1, 2004		13,333,333	$	133	$	75,584	$	-		$	(2,553	)	$	17,839	$	91,003
Net income		-		-		-		-			-			23,852		23,852
Other comprehensive income		-		-		-		-			222			-		222
Loan to ESOP		-		-		-		(602	)		-			-		(602	)
Balance, June 30, 2005		13,333,333	$	133	$	75,584	$	(602	)	$	(2,331	)	$	41,691	$	114,475

See accompanying notes to consolidated financial statements

5

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

NINE MONTHS ENDED JUNE 30, 2005

(in thousands)

(Unaudited)

	Nine Months Ended June 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	23,852		$	14,241
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		17,159			10,237
Amortization of deferred financing costs		2,045			435
Non-cash loss on derivative value		94			-
Non-cash compensation on long-term incentive plans		2,690			-
Minority interest in Atlas Pipeline Partners, L.P.		10,967			4,188
Gain on asset dispositions		(47	)		(41	)
Property impairments and abandonments		-			721
Deferred income taxes		1,749			9,001
Changes in operating assets and liabilities		49,605			3,211
Net cash provided by operating activities		108,114			41,993
CASH FLOWS FROM INVESTING ACTIVITIES:
Business acquisition		(194,941	)		−
Capital expenditures		(72,355	)		(22,669	)
Proceeds from sale of assets		262			242
Increase in other assets		(44	)		(3,546	)
Net cash used in investing activities		(267,078	)		(25,973	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings		349,250			61,500
Principal payments on debt		(254,630	)		(56,792	)
Payments to affiliate		(22,431	)		(9,730	)
Issuance of Atlas Pipeline Partners common units		91,661			25,188
Issuance of Atlas America, Inc. common stock		-			36,999
Dividends paid to Resource America, Inc.		-			(52,133	)
Distributions paid to minority interests of Atlas Pipeline Partners, L.P.		(12,017	)		(5,088	)
Increase in other assets		(3,184	)		(1,344	)
Net cash provided by (used in) financing activities		148,649			(1,400	)
(Decrease) increase in cash and cash equivalents		(10,315	)		14,620
Cash and cash equivalents at beginning of period		29,192			25,372
Cash and cash equivalents at end of period	$	18,877		$	39,992

See accompanying notes to consolidated financial statements

6

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2005

(Unaudited)

NOTE 1 - MANAGEMENT’S OPINION REGARDING INTERIM FINANCIAL STATEMENTS

Principles of Consolidation

The consolidated financial statements include the accounts of Atlas America, Inc. (“the Company”) 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 19% and 34% at June 30, 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 June 30, 2005 and for the three months and nine months ended June 30, 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 and nine months ended June 30, 2005 may not necessarily be indicative of the results of operations for the full fiscal year ending September 30, 2005. Certain reclassifications have been made to the consolidated financial statements as of September 30, 2004 and for the three months and nine months ended June 30, 2004 to conform to the presentation as of and for the three months and nine months ended June 30, 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. Any liability arising from this transaction will be reimbursed by us to RAI. The Company no longer consolidates with RAI as of June 30, 2005. In connection with the spin-off, RAI and the Company entered into a series of agreements, including a master separation and distribution agreement and a tax matters agreement, which will govern the future contractual obligations between the two companies.

NOTE 2 - SIGNIFICANT ACCOUNTING POLICIES

Reference is hereby made to the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 2004, which contains a summary of significant accounting policies followed by the Company in the preparation of its consolidated financial statements.  These policies were also followed in preparing the quarterly report included herein.  

Recently Issued Financial Accounting Standards    

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

7

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2005

(Unaudited)

NOTE 2 - SIGNIFICANT ACCOUNTING POLICIES - (Continued)

In April 2005, the FASB issued FASB Staff Position No. FAS 19-1 (“FSP FAS 19-1”), which addressed a discussion that was ongoing within the oil and gas industry regarding capitalization of costs of drilling exploratory wells. Paragraph 19 of FASB Statement No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies (“FASB No. 19”), requires costs of drilling exploratory wells to be capitalized pending determination of whether the well has found proved reserves. If the well has found proved reserves, the capitalized costs become part of the entity’s wells, equipment, and facilities; if, however, the well has not found proved reserves, the capitalized costs of drilling the well are expensed. Questions arose in practice about the application of this guidance due to changes in oil and gas exploration processes and lifecycles. The issue was whether there are circumstances that would permit the continued capitalization of exploratory well costs if reserves cannot be classified as proved within one year following the completion of drilling other than when additional exploration wells are necessary to justify major capital expenditures and those wells are underway or firmly planned for in the near future. FSP FAS 19-1 amends FASB No. 19 to allow for the continued capitalization of suspended well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the plan. This guidance requires management to exercise more judgment than was previously required and also requires additional disclosure. This new guidance is effective for the first reporting period beginning after April 4, 2005 and is to be applied prospectively to existing and newly capitalized exploratory well costs. Management does not believe this statement of position will have a significant effect on the Company’s financial statements.

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 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 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.

8

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2005

(Unaudited)

NOTE 2 - SIGNIFICANT ACCOUNTING POLICIES - (Continued)

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.

In December 2004, the FASB issued Statement No. 123 (R) (revised 2004) Share-Based Payment, which is a revision of SFAS No. 123, Accounting for Stock-Based Compensation.  Statement 123 (R) supersedes Accounting Principal Board Opinion (“APB”) No. 25, Accounting for Stock Issued to Employees, and amends SFAS No. 95, Statement of Cash Flows.  Generally, the approach to accounting in Statement 123 (R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.  Currently the Company accounts for these payments under the intrinsic value provisions of APB No. 25 with no expense recognition in the financial statements.  Statement 123 (R) is effective for the Company beginning October 1, 2005.  The Statement offers several alternatives for implementation.  At this time, the Company has not made a decision as to the alternative it may select.

Receivables

In evaluating its allowance for possible losses, the Company performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness, as determined by the Company’s review of its customers’ credit information. The Company extends credit on an unsecured basis to many of its energy customers. At June 30, 2005 and September 30, 2004, the Company’s credit evaluation indicated that it has no need for an allowance for possible losses.

Revenue Recognition

Because there are timing differences between the delivery of natural gas, natural gas liquids (“NGL’s”) and oil and the Company’s receipt of a delivery statement, the Company has unbilled revenues. These revenues are accrued based upon volumetric data from the Company’s records and the Company’s estimates of the related transportation and compression fees which are, in turn, based upon applicable product prices. The Company had unbilled trade receivables at June 30, 2005 and September 30, 2004 of $39.6 million and $22.1 million which are included in Accounts Receivable, on its Consolidated Balance Sheets.

Stock-Based Compensation

The Company accounts for its employees’ participation in the stock option plans of its former parent, RAI, in accordance with the provisions of APB No. 25 and related interpretations. Compensation expense is recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price.  The Company adopted the disclosure requirements of SFAS No. 123, as amended by the required disclosures of SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure.

9

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2005

(Unaudited)

NOTE 2 - SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Stock-Based Compensation - (Continued)

SFAS 123 requires the disclosure of pro forma net income and earnings per share as if the Company had adopted the fair value method for stock options granted after June 30, 1996. Under SFAS 123, the fair value of stock-based awards to employees is calculated through the use of option pricing models, even though such models were developed to estimate the fair value of freely tradable, fully transferable options without vesting restrictions, which significantly differ from the Company's stock option awards. These models also require subjective assumptions, including future stock price volatility and expected time to exercise, which greatly affect the calculated values. 

No stock-based employee compensation cost is reflected in net income of the Company, as all options granted under RAI’s plans in which the Company’s employees participated had an exercise price equal to the market value of the underlying RAI’s common stock on the date of grant.  The vesting of all unvested options was accelerated for all Company employees and all options were subsequently exercised prior to June 30, 2005 in anticipation of the spin-off from RAI. The following table illustrates the effect on net income if the Company had applied the fair value recognition provisions of SFAS 123 to stock-based employee compensation (in thousands, except per share data).

	Three Months Ended June 30,						Nine Months Ended June 30,
	2005			2004			2005			2004
Net income, as reported	$	6,444		$	4,182		$	23,852		$	14,241
Stock-based employee compensation expense reported in net income, net of tax		-			-			-			-
Less total stock-based employee compensation expense determined under the fair value-based method for all awards, net of income taxes		(242	)		(307	)		(456	)		(469	)
Pro forma net income	$	6,202		$	3,875		$	23,396		$	13,772
Net income per common share:
Basic - as reported	$	.48		$	.35		$	1.79		$	1.28
Basic - pro forma	$	.47		$	.32		$	1.75		$	1.24
Diluted - as reported	$	.48		$	.35		$	1.79		$	1.28
Diluted- pro forma	$	.46		$	.32		$	1.75		$	1.24

10

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2005

(Unaudited)

NOTE 2 - SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Supplemental Cash Flow Information

The Company considers temporary investments with a maturity at the date of acquisition of 90 days or less to be cash equivalents.  

Supplemental disclosure of cash flow information (in thousands) is listed below:

	Nine Months Ended June 30,
	2005		2004
Cash paid during the period for:
Interest	$	5,574	$	1,100
Income taxes	$	17	$	-

NOTE 3 - COMPREHENSIVE INCOME

Comprehensive income includes net income and other gains and losses affecting stockholders’ equity from non-owner sources that, under generally accepted accounting principles, 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 (in thousands). 

	Three Months Ended June 30,					Nine Months Ended June 30,
	2005			2004		2005			2004
Net income	$	6,444		$	4,182	$	23,852		$	14,241
Other comprehensive income (loss):
Unrealized loss on hedging contracts, net of taxes of $778 and $199		(1,383	)		-		(354	)		-
Add: reclassification adjustment for losses realized in net income, net of taxes of ($295) and ($324)		525			-		576			-
		(858	)		-		222			-
Comprehensive income	$	5,586		$	4,182	$	24,074		$	14,241

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.   

11

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2005

(Unaudited)

NOTE 4 - EARNINGS PER SHARE - (Continued)

The following table presents a reconciliation of the components used in the computation of net income per common share-basic and net income per common share-diluted (in thousands):

	Three Months Ended June 30,				Nine Months Ended June 30,
	2005		2004		2005		2004
Net income	$	6,444	$	4,182	$	23,852	$	14,241
Weighted average common shares outstanding-basic		13,333		12,015		13,333		11,129
Dilutive effect of stock incentive plan		6		3		6		2
Weighted average common shares-diluted		13,339		12,018		13,339		11,131

NOTE 5 - DERIVATIVE INSTRUMENTS

Atlas Pipeline, through its subsidiary, Atlas Pipeline Mid-Continent, LLC (“APLMC” or “Mid-Continent”), 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. Mid-Continent entered into these instruments to hedge forecasted natural gas, NGL’s 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, NGL’s and condensate is sold. Under these swap agreements, Mid-Continent receives a fixed price and pays a floating price based on certain indices for the relevant contract period. The options fix the price for Mid-Continent within the puts purchased and calls sold. 

Atlas Pipeline formally documents all relationships between hedging instruments and the items being hedged, including Atlas Pipeline’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. 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 forecast cash flow of hedged items. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of correlation between the 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.

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 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 June 30, 2005, Atlas Pipeline reflected a net hedge liability of $19.9 million on its balance sheet. Of the $2.3 million net unrealized loss in accumulated other comprehensive income at June 30, 2005, $1.2 million in losses will be reclassified to earnings over the next twelve month period as these contracts expire and $1.1 million will be reclassified in later periods if the fair values of the instruments remain constant. Actual amounts that will be reclassified will vary as a result of future changes in prices.  Ineffective gains or losses are recorded in income while the hedge contract is open and may increase or decrease until settlement of the contract. Atlas Pipeline recognized losses of $1.3 million and $1.9 million related to these hedging instruments for the three months and nine months ended June 30, 2005, respectively. Hedging gains of $307,000 and $523,000 resulting from ineffective hedges are included in gathering, transmission and processing revenues on the Company’s consolidated statements of income for the three months and nine months ended June 30, 2005, respectively.

12

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2005

(Unaudited)

NOTE 5 - DERIVATIVE INSTRUMENTS - (Continued)

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

As of June 30, 2005, Atlas Pipeline had the following derivative instruments in place:

Natural Gas Basis Swaps

Production Period Ended June 30,	Volumes (MMBTU)(1)		Average Fixed Price (per MMBTU)		Fair Value Liability(3) (in thousands)
2006		1,260,000	$	-0.537	$	(83	)
2007		1,140,000		-0.530		(67	)
2008		780,000		-0.541		(55	)
					$	(205	)

Plant Volume Reduction Basis Swaps

Production Period Ended June 30,	Volumes (MMBTU)(1)		Average Fixed Price (per MMBTU)		Fair Value Receivable(3) (in thousands)
2006		1,800,000	$	-0.478	$	12
2007		900,000		-0.495		21
					$	33

Natural Gas Liquids Fixed - Price Swaps

Production Period Ended June 30,	Volumes (gallons)		Average Fixed Price (per gallon)		Fair Value Liability(2) (in thousands)
2006		37,104,000	$	0.662	$	(9,235	)
2007		24,570,000		0.686		(5,821	)
2008		9,954,000		0.698		(2,079	)
					$	(17,135	)

Natural Gas Fixed - Price Swaps

Production Period Ended June 30,	Volumes (MMBTU)(1)		Average Fixed Price (per MMBTU)		Fair Value Liability(3) (in thousands)
2006		1,200,000	$	6.594	$	(1,419	)
2007		1,140,000		7.131		(889	)
2008		780,000		7.260		(235	)
					$	(2,543	)

13

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2005

(Unaudited)

NOTE 5 - DERIVATIVE INSTRUMENTS - (Continued)

Crude Oil Fixed - Price Swaps

Production Period Ended June 30,	Volumes (barrels)		Average Fixed Price (per barrel)		Fair Value Liability(3) (in thousands)
2006		54,450	$	51.558	$	(403	)
2007		74,400		53.638		(358	)
2008		55,200		55.875		(91	)
					$	(852	)

Plant Volume Reduction Fixed - Price Swaps

Production Period Ended June 30,	Volumes (MMBTU)(1)		Average Fixed Price (per MMBTU)		Fair Value Receivable(3) (in thousands)
2006		1,650,000	$	7.205	$	995
2007		900,000		7.255		548
					$	1,543

Crude Oil Options

Production Ended June 30,	Option Type	Volumes (barrels)		Average Strike Price (per barrel)		Fair Value Liability(3) (in thousands)
2006	Puts purchased		30,000	$	30.00	$	-
2006	Calls sold		30,000		34.25		(721	)
						$	(721	)
					Total net liability	$	(19,880	)

____________________

⁽¹⁾ MMBTU means million British Thermal Units.

⁽²⁾ Fair value based on Atlas Pipeline’s internal model which forecasts forward NGL prices as a function of forward New York Mercantile Exchange (“NYMEX”) natural gas and light crude prices.

⁽³⁾ Fair value based on forward NYMEX natural gas and light crude prices, as applicable

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

	June 30, 2005						September 30, 2004
	Book Value			Fair Value			Book Value			Fair Value
Assets
Derivative instruments	$	1,776		$	1,776		$	−		$	−
	$	1,776		$	1,776		$	−		$	−
Liabilities
Derivative instruments	$	(21,656	)	$	(21,656	)	$	(6,032	)	$	(6,032	)
	$	(21,656	)	$	(21,656	)	$	(6,032	)	$	(6,032	)
	$	(19,880	)	$	(19,880	)	$	(6,032	)	$	(6,032	)

14

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2005

(Unaudited)

NOTE 6 - 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.

The Company uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a pool-by-pool basis with certain exploratory expenditures and exploratory dry holes expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method for each pool based on estimated proved oil and gas reserves.

The estimated service lives of other property and equipment are as follows:

Pipelines, processing and compression facilities	15-20 years
Rights-of-way - Mid-Continent	40 years
Rights-of-way - Appalachia	20 years
Land, buildings and improvements	10-40 years
Furniture and equipment	3-7 years
Other	3-10 years

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

	June 30, 2005			September 30, 2004
Mineral interests:
Proved properties	$	3,068		$	2,544
Unproved properties		1,002			1,002
Wells and related equipment		227,358			184,046
Pipelines, processing and compression facilities		323,350			163,302
Rights-of-way		16,121			14,702
Land, buildings and improvements		7,768			7,213
Support equipment		3,398			2,902
Other		5,001			4,227
		587,066			379,938
Accumulated depreciation, depletion and amortization:
Oil and gas properties		(79,062	)		(63,551	)
Other		(4,088	)		(3,296	)
		(83,150	)		(66,847	)
	$	503,916		$	313,091

In April 2005, Atlas Pipeline completed the acquisition of ETC Oklahoma Pipeline, Ltd. (“Elk City”) for approximately $194.9 million (see Note 11). Due to its recent date of acquisition, the purchase price allocation is based upon estimated values determined by Atlas Pipeline, which are subject to adjustment and could change significantly as Atlas Pipeline continues to evaluate this allocation. At June 30, 2005, the purchase price allocated to property, plant and equipment for this acquisition by Atlas Pipeline was included within the pipelines, processing and compression facilities category.

15

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2005

(Unaudited)

NOTE 7 - ASSET RETIREMENT OBLIGATIONS

The Company accounts for its estimated plugging and abandonment of its oil and gas properties in accordance with SFAS 143, Accounting for Asset Retirement Obligations. A reconciliation of the Company’s liability for well plugging and abandonment costs is as follows at the dates indicated (in thousands):

	Three Months Ended June 30,						Nine Months Ended June 30,
	2005			2004			2005			2004
Asset retirement obligations, beginning of period	$	6,707		$	3,180		$	4,889		$	3,131
Liabilities incurred		400			71			2,058			101
Liabilities settled		(52	)		(15	)		(84	)		(43	)
Accretion expense		96			52			288			99
Revisions of previous estimates		-			83			-			83
Asset retirement obligations, end of period	$	7,151		$	3,371		$	7,151		$	3,371

The above accretion expense is included in depreciation, depletion and amortization expense 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 - INCOME TAXES

The Company accounts for income taxes under SFAS No. 109, Accounting for Income Taxes. In accordance with the tax matters agreement with RAI, the Company’s earnings will be included in the consolidated federal income tax return of RAI from October 1, 2004 to June 30, 2005 and it is responsible for the payment to RAI of federal income taxes to the date of the spin-off. The Company is also responsible for all state income taxes and files these on a separate company basis. In addition, the Company will be required to reimburse RAI for an income tax payment associated with the spin-off estimated to be $1.2 million. The expense associated with this payment is included in the provision for income taxes in the Company’s consolidated statement of income for the nine months ended June 30, 2005.

The Company records deferred tax assets and liabilities, as appropriate, to account for the estimated future tax effects attributable to temporary differences between the financial statement and tax bases of assets and liabilities and operating loss carry forwards, using currently enacted tax rates.  The deferred tax provision or benefit each year represents the net change during that year in the deferred tax asset and liability balances. 

NOTE 9 - OTHER ASSETS AND INTANGIBLE ASSETS

Other Assets

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

16

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2005

(Unaudited)

NOTE 9 - OTHER ASSETS AND INTANGIBLE ASSETS - (Continued)

Other Assets - (Continued)

	June 30, 2005		September 30, 2004
Deferred financing costs, net of accumulated amortization of $2,116 and $1,080	$	5,865	$	4,704
Investments		2,134		2,166
Security deposits		1,838		1,085
Hedge receivable - long term		637		-
	$	10,474	$	7,955

Deferred financing costs are recorded at cost and are amortized over the terms of the related loan agreements which range from three to five years. In June 2005, Atlas Pipeline recognized accelerated amortization of $1.0 million related to deferred financing costs associated with the retirement of the term portion of its $270 million credit facility and incurred additional financing costs of $3.2 million associated with this new larger credit facility (see note 10).

Intangible Assets

Intangible assets consist of partnership management and operating contracts acquired through acquisitions and recorded at fair value on their acquisition dates.  The Company amortizes contracts acquired on a declining balance or straight-line method over their respective estimated lives, ranging from five to thirteen years.  Amortization expense for the nine months ended June 30, 2005 and 2004 was $700,000 and $779,000, respectively.  The aggregate estimated annual amortization expense is approximately $804,000 for each of the succeeding five-year periods.   

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

	June 30, 2005			September 30, 2004
Partnership management and operating contracts	$	14,343		$	14,343
Accumulated amortization		(7,800	)		(7,100	)
Intangible assets, net	$	6,543		$	7,243

Goodwill

The Company follows SFAS No. 142 Goodwill and Other Intangible Assets in accounting for its goodwill, which requires that goodwill no longer be amortized, but instead evaluated for impairment at least annually. The Company performs such annual evaluation and will reflect the impairment of goodwill, if any, in operating income in the statements of income in the period in which the impairment is indicated.

Changes in the carrying amount of goodwill for the periods indicated are as follows (in thousands):

17

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2005

(Unaudited)

NOTE 9 - OTHER ASSETS AND INTANGIBLE ASSETS - (Continued))

	Three Months Ended June 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
Goodwill at beginning of period, (less accumulated amortization of $4,209)	$	37,470	$	37,470	$	37,470	$	37,470
Preliminary addition to goodwill related to Elk City acquisition (see note 11)		60,000		-		60,000		-
Goodwill at end of period (net of accumulated amortization of $4,209)	$	97,470	$	37,470	$	97,470	$	37,470

NOTE 10 - DEBT

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

	June 30, 2005		September 30, 2004
Revolving credit facility-Atlas Pipeline	$	168,000	$	-
Revolving credit facility		12,000		25,000
Term loan -Atlas Pipeline		-		60,000
Other debt		261		640
		180,261		85,640
Less current maturities		121		3,401
	$	180,140	$	82,239

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

2006	$	121
2007		12,100
2008		40
2009		-
2010		168,000

On April 14, 2005, Atlas Pipeline entered into a new $270.0 million credit facility (“Credit Facility”) with a syndicate of banks, which replaced its existing $135.0 million facility. The facility was comprised of a five-year $225.0 million revolving line of credit and a five-year $45.0 million term loan. The term loan portion of the Credit Facility was repaid and retired through a portion of the net proceeds from its June 2005 equity offering. The revolving portion of the Credit Facility bears interest, at Atlas Pipeline’s option, at either (i) Adjusted LIBOR plus an applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding credit facility borrowings at June 30, 2005 was 6.07%. Up to $10.0 million of the revolving Credit Facility may be utilized for letters of credit, of which $8.2 million is outstanding at June 30, 2005 and are not reflected as borrowings on the Company’s consolidated balance sheets. Borrowings under the facility are secured by a lien on and security interest in all of Atlas Pipeline’s property and that of its subsidiaries, and by the guaranty of each of Atlas Pipeline’s subsidiaries.

18

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2005

(Unaudited)

NOTE 10 - DEBT - (Continued)

The Credit Facility contains customary covenants, including limitation of Atlas Pipeline’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in Atlas Pipeline’s subsidiaries. The credit facility also requires Atlas Pipeline to maintain a specified interest coverage ratio, a specified ratio of funded debt to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”), adjusted as provided in the credit facility and a specified ratio of senior secured debt to such adjusted EBITDA.

NOTE 11 - ACQUISITIONS BY ATLAS PIPELINE

Spectrum Field Services, Inc.

On July 16, 2004, Atlas Pipeline acquired Spectrum Field Services, Inc. (now known as “Atlas Pipeline Mid-Continent, LLC”), for approximately $143.1 million, including transaction costs and the payment of taxes due as a result of the transaction. Spectrum’s principal assets include 1,900 miles of natural gas pipelines and a natural gas processing facility in Velma, Oklahoma.

The acquisition was accounted for using the purchase method of accounting under SFAS No. 141, Business Combinations. The following table presents the allocation of the purchase price, 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	$	803
Accounts receivable		18,505
Prepaid expenses		649
Property, plant and equipment		140,936
Other long-term assets		1,054
Total assets acquired		161,947
Accounts payable and accrued liabilities		(17,153	)
Hedging liabilities		(1,519	)
Long-term debt		(164	)
Total liabilities assumed		(18,836	)
Net assets acquired	$	143,111

Atlas Pipeline continues to evaluate certain estimates made in the purchase price allocation, which is subject to adjustment.

Elk City

On April 14, 2005, Atlas Pipeline acquired all of the outstanding equity interests in Elk City, a Texas limited partnership, for $194.9 million, including related transaction costs. Elk City’s principal assets include 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 acquisition expands Atlas Pipeline activities in the Mid-Continent area and provides the potential for further growth in Atlas Pipeline’s operations based in Tulsa, Oklahoma.

19

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2005

(Unaudited)

NOTE 11 - ACQUISITIONS BY ATLAS PIPELINE - (Continued)

Elk City - (Continued)

The acquisition was accounted for using the purchase method of accounting under SFAS No. 141 Business Combinations. The following table presents the preliminary allocation of the purchase price, 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	$	4,577
Other assets		497
Property, plant and equipment		133,637
Goodwill		60,000
Total assets acquired		198,711
Accounts payable and accrued liabilities		(3,770	)
Total liabilities assumed		(3,770	)
Net assets acquired	$	194,941

Due to its recent acquisition, the purchase price allocation for Elk City is based upon estimated values determined by Atlas Pipeline. These estimates are subject to adjustment and could change significantly as Atlas Pipeline continues to evaluate this allocation. Atlas Pipeline recorded goodwill in connection with this acquisition as a result of Elk City’s significant cash flow and its strategic industry position. The results of the acquisition were included within the Partnership’s consolidated financial statements from its date of acquisition.

The following data presents pro forma revenues, net income and basic and diluted net income per common share for the Company as if the acquisitions discussed above 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 the beginning of the periods shown below or the results that will be attained in the future (in thousands except per share amounts):

	Three Months Ended June 30, 2005
	As Reported		Pro Forma Adjustment			Pro Forma
Revenues	$	126,544	$	5,083		$	131,627
Net income	$	6,444	$	(61	)	$	6,383
Net income per common share − basic	$	.48	$	-		$	.48
Weighted average common shares − outstanding		13,333		-			13,333
Net income per common share − diluted	$	.48	$	-		$	.48
Weighted average common shares		13,339		-			13,339

20

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2005

(Unaudited)

NOTE 11 - ACQUISITIONS BY ATLAS PIPELINE - (Continued)

	Nine Months Ended June 30, 2005
	As Reported		Pro Forma Adjustment			Pro Forma
Revenues	$	319,292	$	89,279		$	408,571
Net income	$	23,852	$	(111	)	$	23,741
Net income per common share − basic	$	1.79	$	(.01	)	$	1.78
Weighted average common shares − outstanding		13,333		-			13,333
Net income per common share − diluted	$	1.79	$	(.01	)	$	1.78
Weighted average common shares		13,339		-			13,339

	Three Months Ended June 30, 2004
	As Reported		Pro Forma Adjustment			Pro Forma
Revenues	$	32,837	$	63,764		$	96,601
Net income	$	4,182	$	(37	)	$	4,145
Net income per common share − basic	$	.35	$	(.01	)	$	.34
Weighted average common shares − outstanding		12,015		-			12,015
Net income per common share − diluted	$	.35	$	(.01	)	$	.34
Weighted average common shares		12,018		-			12,018

	Nine Months Ended June 30, 2004
	As Reported		Pro Forma Adjustment			Pro Forma
Revenues	$	110,277	$	172,862		$	283,139
Net income	$	14,241	$	(852	)	$	13,389
Net income per common share − basic	$	1.28	$	(.08	)	$	1.20
Weighted average common shares − outstanding		11,129		-			11,129
Net income per common share − diluted	$	1.28	$	(.08	)	$	1.20
Weighted average common shares		11,131		-			11,131

Significant pro forma adjustments include revenues and costs and expenses for the period prior to Atlas Pipeline’s acquisitions, interest and depreciation expenses and the elimination of income taxes.

NOTE 12 - OPERATING SEGMENT INFORMATION

The Company’s operations include four reportable operating segments.  In addition to the reportable operating segments, certain other activities are reported in the “Other energy” 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:

21

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2005

(Unaudited)

NOTE 12 - OPERATING SEGMENT INFORMATION - (Continued)

Three Months Ended June 30, 2005 (in thousands):
	Revenues from external customers		Interest income		Interest expense		Depreciation, depletion and amortization		Segment profit (loss)(b)			Other significant items: Segment assets
Well drilling	$	26,749	$	-	$	-	$	-	$	2,807		$	9,522
Production and exploration		16,051		-		-		3,145		10,210			185,542
Natural gas and liquids		79,700		14		5		2,502		3,523			395,319
Transportation and compression		1,622		73		-		626		401			49,003
Other(a)		2,422		11		4,575		233		(4,928	)		49,282
Total	$	126,544	$	98	$	4,580	$	6,506	$	12,013		$	688,668

Three Months Ended June 30, 2004 (in thousands):
	Revenues from external customers		Interest income		Interest expense		Depreciation, depletion and amortization		Segment profit (loss)(b)			Other significant items: Segment assets
Well drilling	$	16,370	$	-	$	-	$	-	$	1,753		$	7,951
Production and exploration		12,977		-		-		2,468		8,024			156,895
Natural gas and liquids		-		-		-		-		-			-
Transportation and compression		1,344		67		-		592		(293	)		75,970
Other(a)		2,146		-		460		398		(2,816	)		25,844
Total	$	32,837	$	67	$	460	$	3,458	$	6,668		$	266,660

Nine Months Ended June 30, 2005 (in thousands):
	Revenues from external customers		Interest income		Interest expense		Depreciation, depletion and amortization		Segment profit (loss)(b)			Other significant items: Segment assets
Well drilling	$	98,758	$	-	$	-	$	-	$	11,377		$	9,522
Production and exploration		44,669		-		-		9,063		28,716			185,542
Natural gas and liquids		164,095		45		17		5,653		10,023			395,319
Transportation and compression		4,750		181		-		1,743		306			49,003
Other(a)		7,020		67		7,876		700		(11,208	)		49,282
Total	$	319,292	$	293	$	7,893	$	17,159	$	39,214		$	688,668

Nine Months Ended June 30, 2004 (in thousands):
	Revenues from external customers		Interest income		Interest expense		Depreciation, depletion and amortization		Segment profit (loss)(b)			Other significant items: Segment assets
Well drilling	$	64,577	$	-	$	-	$	-	$	7,258		$	7,951
Production and exploration		34,972		-		-		7,190		20,055			156,895
Natural gas and liquids		-		-		-		-		-			-
Transportation and compression		4,522		109		-		1,615		(383	)		75,970
Other(a)		6,206		17		1,420		1,432		(5,021	)		25,844
Total	$	110,277	$	126	$	1,420	$	10,237	$	21,909		$	266,660

22

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2005

(Unaudited)

NOTE 12 - OPERATING SEGMENT INFORMATION - (Continued)

_____________ 

^(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.

^(b) Segment operating profit (loss) represents total revenues less costs and expenses attributable thereto, including interest and depreciation, depletion and amortization, excluding general corporate expenses.

NOTE 13 - BENEFIT PLANS

Stock Incentive Plan. The Company has a Stock Incentive Plan (the “Plan”) for employees, consultants and directors of the Company and its affiliates, in which a maximum of 1,333,333 shares are reserved for issuance.  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 at the date of grant of $30.19 and $15.50, respectively, per unit) were awarded to non-employee directors of the Company under this Plan.  The fair value of the grants awarded ($75,000 in total each year) is being charged to operations over the vesting periods.  Units will vest sooner upon a change of control of the Company or death or disability of a grantee.  Upon termination of service by a grantee, all unvested units are forfeited. On an annual basis, each non-employee director of the Company is awarded deferred units having a fair market value of $15,000.

Supplement Employment Retirement Plan (“SERP”). In May 2004, the Company entered into an employment agreement with its Chairman and Chief Executive Officer pursuant to which the Company has agreed to provide him with a SERP and with certain financial benefits upon termination of his employment.  During the three months and nine months ended June 30, 2005, operations were charged $39,500 and $118,500, respectively, with respect to this commitment.

Employee Stock Ownership Plan. On June 30, 2005 and in connection with the spin-off from RAI, the Company established an Employee Stock Ownership Plan (“ESOP”), whereby the ESOP purchased 40,375 shares of RAI common stock with the proceeds of a $602,588 loan from the Company. The ESOP is a qualified non-contributory retirement plan 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. Contributions to the ESOP are made at the discretion of the Board of Directors. The ESOP loan receivable (a reduction in stockholders’ equity) bears interest at 7.5% and is reduced by the amount of any loan principal reduction resulting from contributions by the Company to the ESOP.

The common stock owned by the ESOP is held by the ESOP trustee in a suspense account. On an annual basis, a portion of the common stock is released from the suspense account.

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. 

23

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

June 30, 2005

(Unaudited)

NOTE 13 - BENEFIT PLANS - (Continued)

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

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	(in thousands, except unit data)
Outstanding, beginning of period		125,201			1,692			58,752			-
Granted(1)					56,906			67,338			58,598
Performance factor adjusted(2)		140,211			-			140,211			-
Matured		(226	)		-			(436	)		-
Forfeited		(340	)		(846	)		(1,019	)		(846	)
Outstanding, end of period(3)		264,846			57,752			264,846			57,752
Non-cash compensation expense recognized (in thousands)	$	1,610		$	70		$	2,559		$	72

⁽¹⁾ The weighted average price for phantom unit awards on the date of grant was $0 and $37.19 for awards granted for the three months ended June 30, 2005 and 2004, respectively, and $48.58 and $37.15 for awards granted for the nine months ended June 30, 2005 and 2004, respectively.

⁽²⁾ Consists of adjustments to performance-based awards to reflect actual performance.

⁽³⁾ Of the units outstanding under the LTIP at June 30, 2005, 31,214 units will vest within the following twelve months.

NOTE 14 - SETTLEMENT OF ALASKA PIPELINE COMPANY ARBITRATION

In September 2003, Atlas Pipeline entered into an agreement with SEMCO Energy, Inc. to purchase all of the stock of Alaska Pipeline Company (“APC”). In order to complete the acquisition, Atlas Pipeline needed the approval of the Regulatory Commission of Alaska. The Regulatory Commission initially approved the transaction, but on June 4, 2004, it vacated its order of approval based upon a motion for clarification or reconsideration filed by SEMCO. On July 1, 2004, SEMCO sent Atlas Pipeline a notice purporting to terminate the transaction. Atlas Pipeline pursued its remedies under the acquisition agreement. In connection with the acquisition, subsequent termination, and settlement of the legal action, Atlas Pipeline incurred costs of approximately $1.2 million in the nine months ended June 30, 2005 which were included in arbitration settlement, net on the Company’s Consolidated Statements of Income. Atlas Pipeline also incurred $3.0 million of costs in the year ended September 30, 2004. On December 30, 2004, Atlas Pipeline entered into an agreement with SEMCO settling all issues and matters related to SEMCO’s termination of the sale of APC to Atlas Pipeline and SEMCO paid Atlas Pipeline $5.5 million which was also included in arbitration settlement, net.

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

When used in this Form 10-Q, the words “believes” “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements.  Such statements are subject to certain risks and uncertainties more particularly described in Item 1, under the caption “Risk Factors”, in our annual report on Form 10-K for fiscal 2004.  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 nine months ended June 30, 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 June 30, 2005, we had $61.6 million available under our credit facility, which could be employed to finance such acquisitions.

Our financial condition and results of operations have been affected by initiatives taken by Atlas Pipeline Partners, L.P.  or Atlas Pipeline. In June 2005 and in fiscal 2004, Atlas Pipeline completed public offerings of its common units, realizing $91.7 million and $92.7 million, respectively, of offering proceeds, net of expenses.  The principal financial effect of these offerings was an increase in the minority interest in our financial statements. 

In July 2004, Atlas Pipeline acquired Spectrum Field Services, Inc. (which changed its name to Atlas Pipeline Mid-Continent, LLC or APLMC or Mid-Continent) for approximately $143.1 million, including transaction costs and the payment of anticipated taxes due as a result of the transaction.  This acquisition significantly increased Atlas Pipeline's size and diversified the natural gas supply basins in which it operates and the natural gas midstream services it provides to its customers.  Spectrum was a privately owned natural gas gathering and processing company headquartered in Tulsa, Oklahoma. 

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 will be required to make a non-recurring income tax payment, payable to Resource America, of $1.2 million associated with the spin-off.

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Recent Developments

Atlas Pipeline’s Acquisition of Elk City

On April 14, 2005, Atlas Pipeline acquired all of the outstanding equity interests in Elk City, a Texas limited partnership, for $194.9 million including related transaction costs. ETC Oklahoma Pipeline’s principal assets include approximately 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 or mmcf/d and a gas treatment facility in Prentiss, Oklahoma, with a total capacity of 100 mmcf/d. Total compression horsepower consists of 21,000 hp at six field stations and 12,000 horsepower within the Elk City and Prentiss facilities. The system gathers and processes gas from more than 300 receipt points representing more than fifty producers and delivers that gas into multiple interstate pipeline systems. The acquisition expanded Atlas Pipeline’s activities in the mid-continent area and provides the potential for further growth in Atlas Pipeline’s operation based in Tulsa, Oklahoma.

Atlas Pipeline New Credit Facility

To finance the Elk City acquisition, Atlas Pipeline entered into a new $270 million credit facility which replaced its existing $135 million facility. Wachovia Capital Markets, LLC and Bank of America Securities LLC, are Co-Lead Arrangers. The facility was comprised of a five-year $225.0 million revolving line of credit and a five-year $45.0 million term loan. The term loan portion of the Credit Facility was repaid and retired through a portion of the net proceeds from Atlas Pipeline’s June 2005 equity offering. The revolving portion of the Credit Facility bears interest, at Atlas Pipeline’s option, at either (i) Adjusted LIBOR plus an applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding credit facility borrowings at June 30, 2005 was 6.07%. The bank group consists of the twelve banks that participated in the prior credit facility, plus five new participants. Up to $10.0 million of the facility may be used for standby letters of credit, of which $8.2 million was being used at June 30, 2005. Borrowings under the facility are secured by a lien on and security interest in all of Atlas Pipeline’s property and that of Atlas Pipeline’s subsidiaries and by the guaranty of each of Atlas Pipeline’s subsidiaries.

Atlas Pipeline Public Offering

On June 2, 2005, Atlas Pipeline completed a public offering of 2.3 million common units for total proceeds of $96.5 million, less underwriting commissions and transaction costs of $4.8 million. The net proceeds of $91.7 million were primarily used to pay Atlas Pipeline’s $45 million term loan and $43 million on its new revolving credit facility.

Results of Operations for the Three Months and Nine Months Ended June 30, 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):

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	Three Months Ended June 30,						Nine Months Ended June 30,
	2005			2004			2005			2004
Average drilling revenue per well	$	243		$	241		$	218		$	192
Average drilling cost per well		211			209			190			167
Average drilling gross profit per well	$	32		$	32		$	28		$	25
Gross profit margin	$	3,490		$	2,135		$	12,882		$	8,423
Gross margin percent		13	%		13	%		13	%		13	%
Net wells drilled		110			68			453			336

Our well drilling gross margin was $3.5 million and $12.9 million in the three months and nine months ended June 30, 2005, an increase of $1.4 million and $4.5 million from $2.1 million and $8.4 million in the three months and nine months ended June 30, 2004, respectively.  In the three months ended June 30, 2005, the increase of $1.4 million in gross margin was attributable to an increase in the number of wells drilled ($1.3 million) and an increase in the gross profit per well ($100,000). In the nine months ended June 30, 2005, the increase of $4.5 million was attributable to an increase in the number of wells drilled ($3.4 million) and an increase in the gross profit per well ($1.1 million). Since our drilling contracts are on a “cost plus” basis (typically cost plus 15%), an increase in our average cost per well also results in an increase in our average revenue per well.  The increase in our average cost per well in the three months and nine months ended June 30, 2005 resulted from an increase in the cost of tangible equipment, leases and reclamation expenses. In addition, it should be noted that “Liabilities associated with drilling contracts” on our balance sheet includes $50.4 million of funds raised in our drilling investment programs in the third quarter ended June 30, 2005 that had not been applied to drill wells as of June 30, 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 2005. Because we raised $113.8 million in the first nine months of fiscal 2005 as compared to $68 million in the first nine months of fiscal 2004, we anticipate drilling revenues and related costs to be substantially higher in fiscal 2005 than in fiscal 2004.

Gas and Oil Production          

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

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	Three Months Ended June 30,						Nine Months Ended June 30,
	2005			2004			2005			2004
Production revenues (in thousands):
Gas (1)	$	13,934		$	11,607		$	38,916		$	30,789
Oil	$	2,106		$	1,395		$	5,695		$	4,183
Production volume:
Gas (mcf/day) (1) (3)		21,214			20,710			20,275			19,485
Oil (bbls/day)		461			452			438			494
Total (mcfe/day) (3)		23,980			23,422			22,903			22,449
Average sales prices:
Gas (per mcf) (3)	$	7.22		$	6.16		$	7.03		$	5.77
Oil (per bbl) (3)	$	50.15		$	33.87		$	47.57		$	30.93
Production costs (2):
As a percent of production revenues		12	%		14	%		13	%		15	%
Per mcfe (3)	$	.91		$	.84		$	.94		$	.84
Depletion per mcfe (3)	$	1.29		$	1.13		$	1.29		$	1.17

⁽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 $13.9 million and $38.9 million in the three months and nine months ended June 30, 2005, an increase of $2.3 million (20%) and $8.1 million (26%) from $11.6 million and $30.8 million in the three months and nine months ended June 30, 2004, respectively.  The increases were due to an increase in the average sales price of natural gas of 17% and 22% for the three months and nine months ended June 30, 2005 and an increase of 2% and 4% in the volume of natural gas produced in the three months and nine months ended June 30, 2005, respectively. The $2.3 million increase in gas revenues in the three months ended June 30, 2005 as compared to the prior period consisted of $2.0 million attributable to increases in natural gas sales prices, and $330,000 attributable to increased production volumes. The $8.1 million increase in natural gas revenue in the nine months ended June 30, 2005 as compared to the prior year period consisted of $6.7 million attributable to increases in natural gas sales prices, and $1.4 million attributable to increased production volumes.

Our oil revenues were $2.1 million and $5.7 million in the three months and nine months ended June 30, 2005, an increase of $711,000 (51%) and $1.5 million (36%), respectively, from $1.4 million and $4.2 million in the three months and nine months ended June 30, 2004. The average sales price of oil increased 48% and 54% for the three months and nine months ended June 30, 2005 as compared to the prior year similar periods. The $711,000 increase in oil revenues in three months ended June 30, 2005 as compared to the prior year period consisted of $670,000 attributable to increases in sales prices, and $41,000 attributable to increases in production volumes. The $1.5 million increase in oil revenues for the nine months ended June 30, 2005 as compared to the prior year period consisted of $2.3 million attributable to increases in sales prices offset by $739,000 attributable to decreased production volumes.

Our production costs were $2.0 million and $5.9 million in the three months and nine months ended June 30, 2005, an increase of $196,000 (11%) and $691,000 (13%) from $1.8 million and $5.2 million in the three months and nine months ended June 30, 2004.  These increases include an increase in insurance expense, costs related to well workovers 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.

Our exploration and land costs were $472,000 and $760,000 in the three months and nine months ended June 30, 2005, a decrease of $113,000 (19%) and $1.4 million (65%) from $585,000 million and $2.2 million in the three months and nine months ended June 30, 2004. We attribute these decreases to the following: an increase in the benefit we receive for our contribution of well sites to our drilling investment partnerships as a result of more wells drilled and dry hole costs expensed in fiscal 2004, no dry hole costs have been incurred in fiscal 2005, partially offset by increases in the cost of running our land department as we manage the increases in our drilling activities.

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Gathering, Transmission and Processing

Our gathering, transmission and processing revenues and related expenses for the three and nine months ended June 30, 2005 increased significantly from the prior year periods due to the acquisition of Spectrum on July 16, 2004 and Elk City on April 15, 2005.

Our revenues increased $80.0 million and $164.3 million to $81.3 million and $168.8 million for the three and nine months ended June 30, 2005 from $1.3 million and $4.5 million for the three and nine months ended June 30, 2004, respectively.

Our expenses increased $70.0 million and $141.9 million to $70.5 million and $143.7 million for the three and nine months ended June 30, 2005 from $551,000 and $1.8 million for the three and nine months ended June 30, 2004, respectively.

Well Services

Our well services revenues were $2.4 million and $7.0 million in the three months and nine months ended June 30, 2005, an increase of $276,000 (13%) and $814,000 (13%) from $2.1 million and $6.2 million in the three months and nine months ended June 30, 2004, respectively. 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 June 30, 2005.

Our well services expenses were $1.3 million and $3.8 million in the three months and nine months ended June 30, 2005, an increase of $284,000 (28%) and $729,000 (24%) from $1.1 million and $3.1 million in the three months and nine months ended June 30, 2004, respectively.  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 $4.7 million and $7.9 million in the three months and nine months ended June 30, 2005, an increase of $2.4 million and $4.2 million from $2.3 million and $3.7 million in the three months and nine months ended June 30, 2004, respectively. These expenses include, among other things, salaries and benefits not allocated to a specific energy activity, costs of running our energy corporate office, partnership syndication activities and outside services.  These expenses are partially offset by reimbursements we receive from our drilling investment partnerships. 

The increase of $2.4 million in the three months ended June 30, 2005 is principally attributable to $2.4 million in general and administrative expenses related to Atlas Pipeline’s Mid-Continent and Elk City operations; we acquired Spectrum on July 16, 2004 and Elk City on April 14, 2005 and therefore, we had no such expenses in the quarter ended June 30, 2004.

The increase of $4.2 million in the nine months ended June 30, 2005 as compared to the nine months ended June 30, 2004 is attributable principally to the following:

· general and administrative expenses related to Atlas Pipeline’s Mid-Continent operations were $3.7 million in the nine months ended June 30, 2005; we acquired Spectrum on July 16, 2004 and Elk City on April 15, 2005;  

· costs associated with Atlas Pipeline’s long-term incentive plan were $2.6 million in the nine months ended June 30, 2005; there were no such expenses in the prior year similar period; and

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· an increase of $967,000 in legal and professional fees which includes the implementation of Sarbanes-Oxley section 404 compliance.

These increases were partially offset by decreases in net syndication expenses of $394,000 and $1.8 million in increased credits we received for costs incurred in organizing and offering our partnership investments.

Our compensation reimbursements-affiliates decreased to $145,000 and $602,000 for the three months and nine months ended June 30, 2005, a decrease of $205,000 and $448,000 from $350,000 and $1.1 million in the three months and nine months ended June 30, 2004, respectively. These decreases resulted from a decrease in allocations from our former parent for executive management and administrative services as we now directly employee 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 % and 19% in the three months and nine months ended June 30, 2005 compared to 19% and 21% in the three months and nine months ended June 30, 2004, respectively.  Depletion expense per mcfe was $1.29 in the three months and nine months ended June 30, 2005, an increase of $.16 (14%) per mcfe and $.12 (10%) per mcfe from $1.13 and $1.17 in the three months and nine months ended June 30, 2004, respectively.  Increases in our depletable basis and production volumes caused depletion expense to increase $460,000 (19%) and $1.2 million (17%) to $2.9 million and $8.4 million in the three months and nine months ended June 30, 2005 compared to $2.5 million and $7.2 million in the three months and nine months ended June 30, 2004, respectively.  The variances from period to period are directly attributable to changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties.

Our interest expense was $4.6 million and $7.9 million in the three months and nine months ended June 30, 2005, an increase of $4.1 million and $6.5 million from $460,000 and $1.4 million in the three months and nine months ended June 30, 2004, respectively.  These increases resulted primarily from an increase in outstanding borrowings by Atlas Pipeline to fund the acquisitions of Spectrum and Elk City.

On December 30, 2004, Atlas Pipeline entered into a settlement agreement with SEMCO Energy, Inc. settling all issues and matters related to SEMCO’s termination of the sale of Alaska Pipeline Company to Atlas Pipeline and SEMCO paid Atlas Pipeline $5.5 million which is included in arbitration settlement-net on our statements of income. In connection with the acquisition, subsequent termination, and settlement of the legal action, Atlas Pipeline incurred costs of approximately $11,000 and $1.2 million in the three months and nine months ended June 30, 2005, which are also included in arbitration settlement-net on our statements of income.  Atlas Pipeline also incurred $3.0 million of costs in our year ended September 30, 2004. 

At June 30, 2005, we own 19% of the partnership interest in Atlas Pipeline through our general partner interest and limited partner units. The limited partner units were subordinated until January 1, 2005, when the subordination term expired and they converted to common units in accordance with the terms of the partnership agreement. Our ownership interest has decreased 32% from 51% as a result of the completion by Atlas Pipeline of common unit offerings in May 2003, April and July 2004, and June 2005.

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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 $1.2 million and $11.0 million for the three months and nine months ended June 30, 2005, as compared to $1.6 million and $4.2 million for the three months and nine months ended June 30, 2004, a decrease of $346,000 and an increase of $6.8 million for the three months and nine months ended June 30, 2005, respectively. These decreases and increases are a result of an increase in the percentage interest of public unit holders and an increase in Atlas Pipeline’s net income, as discussed above.

Our effective tax rate increased to 46% and 39% for the three months and nine months ended June 30, 2005 as compared to 37% and 35% for the three months and nine months ended June 30, 2004 as a result of a reduction in statutory depletion benefits relative to increased net income. For the nine months ended June 30, 2005, we also incurred a $1.2 million income tax charge related to our spin-off from Resource America.

Liquidity and Capital Resources

General.  We fund our exploration and production operations from a combination of cash generated by operations, capital raised through drilling investment partnerships and, if required, use of our credit facility.  We fund our gathering, transmission 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):

	Nine Months Ended June 30,
	2005			2004
Provided by operations	$	108,114		$	41,993
Used in investing activities		(267,078	)		(25,973	)
Used in financing activities		148,649			(1,400	)
(Decrease) increase in cash and cash equivalents	$	(10,315	)	$	14,620

We had $18.9 million in cash and cash equivalents at June 30, 2005, as compared to $29.2 million at September 30, 2004.  Our ratio of earnings from continuing operations before income taxes, minority interest and interest expense to fixed charges was 7.4 to 1.0 in the nine months ended June 30, 2005 as compared to 19.4 in the nine months ended June 30, 2004.  We had working capital deficits of $73.6 million and $19.3 million at June 30, 2005 and September 30, 2004, respectively.  The increase in our working capital deficit is a result of an increase in accrued hedge liabilities associated with our Mid-Continent operations, an increase in our liabilities associated with our drilling partnerships and cash used for payments to Resource America.

Our long-term debt (including current maturities) was 157% and 94% of our total equity at June 30, 2005 and September 30, 2004, respectively.  Since September 30, 2004, total stockholders’ equity has increased by $23.5 million and total debt has increased by $94.6 million. Stockholders’ equity increased principally due to net earnings of $23.9 million for the nine months ended June 30, 2005. The increase in long-term debt relates to increased borrowings to fund Atlas Pipeline’s acquisitions.

In September 2004, the borrowing base under our credit facility was increased to $75.0 million.  At June 30, 2005, we had $61.6 million available on our credit facility. See note 10 to our Consolidated Financial Statements for information on Atlas Pipeline’s new credit facility which closed April 14, 2005. After borrowing on Atlas Pipeline’s new $270 million credit facility on April 14, 2005, it has approximately $168.0 million outstanding at 6.1% and $48.8 million available under its credit facility.

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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 for our drilling investment partnerships.  Netcash provided by operating activities increased $66.1 million in the nine months ended June 30, 2005 to $108.1 million from $42.0 million in the nine months ended June 30, 2004, substantially as a result of the following:

· Changes in operating assets and liabilities increased operating cash flow by $46.4 million in the nine months ended June 30, 2005, compared to the nine months ended June 30, 2004, primarily due to increases during the nine months ended June 30, 2005 in accounts payable and accrued liabilities as compared to June 30, 2004.  Our level of liabilities is dependent upon the remaining amount of our drilling obligations at any balance sheet date, which is dependent upon the timing of funds raised through our investment partnerships;

· An increase in net income before depreciation and amortization of $18.1 million in the nine months ended June 30, 2005 as compared to the prior year period, principally as a result of higher natural gas and oil prices and drilling profits;

· Changes in our deferred tax liability decreased cash flow by $7.3 million as compared to the nine months ended June 30, 2004 which reflects the impact of timing differences between accounting and tax deductions;

· An increase in minority interest of $6.8 million due to an increase in Atlas Pipeline’s earnings and our decreased ownership percentage in Atlas Pipeline; and

· An increase in non-cash items of $2.8 million related to losses on Atlas Pipeline’s hedge value and compensation expense resulting from grants under our long-term incentive plans.

Cash flows from investing activities.Cash used in our investing activities increased $241.1 million in the nine months ended June 30, 2005 to $267.1 million from $26.0 million in the nine months ended June 30, 2004 as a result of the following:

· Cash used in Atlas Pipeline’s acquisition of Elk City was $194.9 million; and

· Capital expenditures increased $49.7 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 $150.0 million in the nine months ended June 30, 2005 to $148.6 million from cash used of $1.4 million in the nine months ended June 30, 2004, as a result of the following: 

· Payments to Resource America in the form of repayments of advances and dividends decreased by $39.4 million in the nine months ended June 30, 2005 to $22.4 million from $61.8 million in the nine months ended June 30, 2004 principally as a result of a one-time special dividend paid in the third fiscal quarter of 2004 as part of the transactions leading to our spin-off from Resource America; 

· Net borrowings and principal payments increased cash flows by $89.9 million in the nine months ended June 30, 2005, as compared to the prior year similar period principally as a result of borrowings associated with the acquisition of Elk City.

· Atlas Pipeline received $91.7 million from its public offering in June 2005, as compared to $25.2 million received the prior fiscal period; and

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These increases were partially offset by the following:

· Proceeds of $37.0 million as a result of the public offering of Atlas America, Inc. common stock in fiscal 2004, no offering has been made in fiscal 2005;

· Distributions paid to minority interests increased $6.9 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 $1.8 million related to financing costs incurred on Atlas Pipeline’s new credit facility.

Capital Requirements: During the nine months ended June 30, 2005 and 2004, our capital expenditures related primarily to investments in our drilling partnerships and pipeline expansions, in which we invested $66.8 million and $22.2 million, respectively.  For the nine months ended June 30, 2005 and the remaining quarter of fiscal 2005, 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 $138.0 million in fiscal 2005 through drilling partnerships.  Through the nine months ended June 30, 2005 we had raised $113.8 million.  We believe cash flows from operations and amounts available under our credit facility will be adequate to fund our contributions to these partnerships.  However, the amount of funds we raise and the level of our capital expenditures will vary in the future depending on market conditions for natural gas and other factors.  

We continuously evaluate acquisitions of gas and oil and pipeline assets.  In order to make any acquisition, we believe we will be required to access outside capital either through debt or equity placements or through joint venture operations with other energy companies.  There can be no assurance that we will be successful in our efforts to obtain outside capital. 

Contractual Obligations and Commercial Commitments

The following table summarizes our contractual obligations at June 30, 2005.

			Payments Due By Period (in thousands)
Contractual cash obligations:	Total		Less than 1 Year		2 - 3 Years		4 - 5 Years		After 5 Years
Long-term debt(1)	$	180,261	$	121	$	12,140	$	168,000	$	-
Secured revolving credit facilities		-		-		-		-		-
Operating lease obligations		1,263		539		471		251		2
Capital lease obligations		-		-		-		-		-
Unconditional purchase obligations		-		-		-		-		-
Other long-term obligation		-		-		-		-		-
Total contractual cash obligations	$	181,524	$	660	$	12,611	$	168,251	$	2

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⁽¹⁾ Not included in the table above are estimated interest payments calculated at the rates in effect at June 30, 2005: 2006 - $10.9 million; 2007 - $10.7 million; 2008 - $10.4 million; 2009 - $10.3 million and 2010 - $8.1 million.

			Payments Due By Period (in thousands)
Other commercial commitments:	Total		Less than 1 Year		2 - 3 Years		4 - 5 Years		After 5 Years
Standby letters of credit	$	9,612	$	9,612	$	-	$	-	$	-
Guarantees		-		-		-		-		-
Standby replacement commitments		-		-		-		-		-
Other commercial commitments		7,866		7,866		-		-		-
Total commercial commitments	$	17,478	$	17,478	$	-	$	-	$	-

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, 2004 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.

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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.

In December 2004, the FASB issued SFAS No. 123 (R) (revised 2004) “Share-Based Payment”, which is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation”.  Statement 123 (R) supersedes Accounting Principal Board, or APB Opinion No. 25, “Accounting for Stock Issued to Employees”, and amends SFAS No. 95, “Statement of Cash Flows”.  Generally, the approach to accounting in SFAS 123 (R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.  Currently we account for these payments under the intrinsic value provisions of APB No. 25 with no expense recognition in the financial statements.  SFAS 123 (R) is effective for us beginning October 1, 2005.  The Statement offers several alternatives for implementation.  At this time, we have not made a decision as to the alternative we may select.

In April 2005, the FASB issued FASB Staff Position No. FAS 19-1 or FSP FAS 19-1, which addressed a discussion that was ongoing within the oil and gas industry regarding capitalization of costs of drilling exploratory wells. Paragraph 19 of FASB SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies”, requires costs of drilling exploratory wells to be capitalized pending determination of whether the well has found proved reserves. If the well has found proved reserves, the capitalized costs become part of the entity’s wells, equipment, and facilities; if, however, the well has not found proved reserves, the capitalized costs of drilling the well are expensed. Questions arose in practice about the application of this guidance due to changes in oil and gas exploration processes and lifecycles. The issue was whether there are circumstances that would permit the continued capitalization of exploratory well costs if reserves cannot be classified as proved within one year following the completion of drilling other than when additional exploration wells are necessary to justify major capital expenditures and those wells are underway or firmly planned for the near future. FSP FAS 19-1 amends SFAS No. 19 to allow for the continued capitalization of suspended well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the plan. This guidance requires management to exercise more judgment than was previously required and also requires additional disclosure. This new guidance is effective for the first reporting period beginning after April 4, 2005 and is to be applied prospectively to existing and newly capitalized exploratory well costs. We do not believe this statement of position will have a significant effect on our financial statements.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks.  The following discussion is not meant to be a precise indicator of expected future 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 June 30, 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 June 30, 2005, the amount outstanding under our credit facility had decreased to $12.0 million from $25.0 million at September 30, 2004.  The weighted average interest rate for this facility increased from 4.1% at September 30, 2004 to 5.2% at June 30, 2005 due to an increase in market index rates on these borrowings. 

At June 30, 2005, Atlas Pipeline had a $225.0 million revolving credit facility ($168.0 million outstanding). The weighted average interest rate for these borrowings increased from 5.7% at September 30, 2004 to 6.1% at June 30, 2005.

Holding all other variables constant, if interest rates hypothetically increased or decreased by 10%, our net annual income would change by approximately $163,000.

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 June 30, 2006, we estimate approximately 55% 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 are exposed to commodity prices as a result of Atlas Pipeline being paid for certain services in the form of commodities rather than cash. For gathering services, we receive fees or commodities from the producers to bring the raw natural gas from the wellhead to the processing plant. For processing services, we either receive fees or commodities as payment for these services, based on the type of contractual agreement. Based on Atlas Pipeline’s current contract mix, we have long condensate, NGL and natural gas positions.  A 10% increase in the average price of NGL’s, natural gas and crude oil prices would result in an increase to our income for the next twelve months ending June 30, 2006 of approximately $4,662,000.  A 10% decrease in the average price of NGL’s, natural gas and crude oil would result in a decrease to our income for the next twelve months ending June 30, 2006 of approximately $4,638,000.

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Atlas Pipeline through its subsidiary, APLMC, acquired and/or entered into certain financial swap and option instruments that are classified as cash flow hedges in accordance with SFAS 133. APLMC entered into these instruments to hedge the forecasted natural gas, natural gas liquids 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, natural gas liquids and condensate is sold. Under these swap agreements, APLMC receives a fixed price and pays a floating price based on certain indices for the relevant contract period. The options fix the price for APLMC within the puts purchased and calls sold. 

Derivatives are recorded on our 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 other comprehensive income 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 June 30, 2005, Atlas Pipeline reflected an unrealized net pre-tax commodity hedging loss of $19.9 million on its balance sheet.  Of the $2.3 million unrealized loss in accumulated other comprehensive income at June 30, 2005, $1.2 million of losses will be reclassified to earnings over the next twelve month period as these contracts expire, and $1.1 million 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 changes in prices. Ineffective gains or losses are recorded in income while the hedge contract is open and may increase or decrease until settlement of the contract. Atlas Pipeline recognized losses of $1.3 million and $1.9 million related to these hedging instruments in the three months and nine months ended June 30, 2005, respectively.  Hedging gains of $307,000 and $523,000 resulting from ineffective hedges is included in gathering, transmission and processing revenues on the consolidated statements of income for the three months and nine months ended June 30, 2005, respectively.

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

As of June 30, 2005, Atlas Pipeline had the following derivative instruments in place:

Natural Gas Basis Swaps

Production Period Ended June 30,	Volumes (MMBTU)(1)		Average Fixed Price (per MMBTU)		Fair Value Liability(3) (in thousands)
2006		1,260,000	$	-0.537	$	(83	)
2007		1,140,000		-0.530		(67	)
2008		780,000		-0.541		(55	)
					$	(205	)

Plant Volume Reduction Basis Swaps

Production Period Ended June 30,	Volumes (MMBTU)(1)		Average Fixed Price (per MMBTU)		Fair Value Receivable(3) (in thousands)
2006		1,800,000	$	-0.478	$	12
2007		900,000		-0.495		21
					$	33

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Natural Gas Liquids Fixed - Price Swaps

Production Period Ended June 30,	Volumes (gallons)		Average Fixed Price (per gallon)		Fair Value Liability(2) (in thousands)
2006		37,104,000	$	0.662	$	(9,235	)
2007		24,570,000		0.686		(5,821	)
2008		9,954,000		0.698		(2,079	)
					$	(17,135	)

Natural Gas Fixed - Price Swaps

Production Period Ended June 30,	Volumes (MMBTU)(1)		Average Fixed Price (per MMBTU)		Fair Value Liability(3) (in thousands)
2006		1,200,000	$	6.594	$	(1,419	)
2007		1,140,000		7.131		(889	)
2008		780,000		7.260		(235	)
					$	(2,543	)

Crude Oil Fixed - Price Swaps

Production Period Ended June 30,	Volumes (barrels)		Average Fixed Price (per barrel)		Fair Value Liability(3) (in thousands)
2006		54,450	$	51.558	$	(403	)
2007		74,400		53.638		(358	)
2008		55,200		55.875		(91	)
					$	(852	)

Plant Volume Reduction Fixed - Price Swaps

Production Period Ended June 30,	Volumes (MMBTU)(1)		Average Fixed Price (per MMBTU)		Fair Value Receivable(3) (in thousands)
2006		1,650,000	$	7.205	$	995
2007		900,000		7.255		548
					$	1,543

Crude Oil Options

Production	Option Type	Volumes (barrels)			Average Strike Price (per barrel)		Fair Value Liability(3) (in thousands)
2006	Puts purchased		30,000		$	30.00	$	-
2006	Calls sold		30,000			34.25		(721	)
							$	(721	)
				Total net liability			$	(19,880	)

____________________

⁽¹⁾ MMBTU means million British Thermal Units.

⁽²⁾ Fair value based on our internal model which forecasts forward natural gas liquid prices as a function of forward New York Mercantile Exchange or NYMEX natural gas and light crude prices.

⁽³⁾ Fair value based on forward NYMEX natural gas and light crude prices, as applicable

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Item 4. Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our periodic reports required under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.  In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our Chief Executive Officer and Chief Financial Officer, and with the participation of the disclosure control committee, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report.  Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective at the reasonable assurance level.

There have been no significant changes in our internal controls over financial reporting that have materially affected, or is reasonably likely to materially affect, our internal control over financial reporting during our most recent fiscal quarter.

PART II.  OTHER INFORMATION

Item 4. Submission of Matters to a Vote of Security Holders

On June 13, 2005, the registrant held a special meeting of stockholders at which the following matters were voted on:

●	Amendment of the Company’s certificate of incorporation to provide for three classes of directors:
	FOR:	11,988,415
	AGAINST:	557,408
	ABSTAIN:	78,052
	BROKER NON-VOTES:	709,315
●	Amendment of the Company’s certificate of incorporation to provide that any vacancy on the Board of Directors shall be filled by the affirmative vote of a majority of the remaining directors:
	FOR:	11,984,545
	AGAINST:	561,194
	ABSTAIN:	78,236
	BROKER NON-VOTES:	709,315

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●	Amendment of the Company’s certificate of incorporation to remove provisions permitting removal of members of the Board of Directors without cause and to increase the vote required:
	FOR:	11,984,781
	AGAINST:	561,442
	ABSTAIN:	77,752
	BROKER NON-VOTES:	709,315
●	Election of seven directors, two to serve in Class I until 2006, three to serve in Class II until 2007 and two to serve in Class III until 2008:
	William R. Bagnell
	FOR:	13,327,538
	WITHHELD:	4,892
	Nicholas A. DiNubile
	FOR:	13,321,294
	WITHHELD:	11,136
	Carlton M. Arrendell
	FOR:	13,327,538
	WITHHELD:	4,892
	Jonathan Z. Cohen
	FOR:	13,329,338
	WITHHELD:	3,092
	Donald W. Delson
	FOR:	13,320,434
	WITHHELD:	11,996
	Edward E. Cohen
	FOR:	13,328,178
	WITHHELD:	4,252
	Dennis A. Holtz
	FOR:	13,321,884
	WITHHELD:	10,546

There were no broker non-votes on this matter.

Item 6. Exhibits

Exhibit No.	Description
3.2	Amended and Restated Bylaws (1)
31.1	Rule 13(a)-14(a)/15d-14(a) Certification.
31.2	Rule 13(a)-14(a)/15d-14(a) Certification.
32.1	Section 1350 Certification.
32.2	Section 1350 Certification.

____________________

⁽¹⁾ Previously filed as an exhibit to our Form 8-K dated May 16, 2005.

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SIGNATURES

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

	ATLAS AMERICA, INC.
	(Registrant)
Date:  August 15, 2005	By:	/s/ Matthew A. Jones
		Matthew A. Jones
		Executive Vice President and Chief Financial Officer
Date:  August 15, 2005	By:	/s/ Nancy J. McGurk
		Nancy J. McGurk
		Senior Vice President and Chief Accounting Officer

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