**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 ofincorporation
                  or organization)
              (I.R.S.
                  EmployerIdentification
                  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
              3Consolidated
                  Statements of Income Three Months and
                  Nine Months Ended June 30, 2005 and 2004
              4Consolidated
                  Statement of Changes in Stockholders’
                  Equity for the Nine Months Ended June 30, 2005
              5Consolidated
                  Statements of Cash Flows for the Nine
                  Months Ended June 30, 2005 and 2004
              6Notes
                  to Consolidated Financial Statements - June 30,
                  2005
              7
                  -
                  24Item
                  2.
              Management’s
                  Discussion and Analysis of Financial Condition
                  and Results of Operations
              25
                  - 34Item
                  3.
              Quantitative
                  and Qualitative Disclosures about Market Risk
              36
                  - 39Item
                  4.
              Controls
                  and Procedures
              39**PART
                  II**
              **OTHER
                  INFORMATION**Item
                  4.
              Submission
                  of Matters to a Vote of Security
                  Holders
              39
                  - 40Item
                  6.
              Exhibits
              40**SIGNATURES**
              41
 2
 *Index*
  **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
              
              $
              29,192Accounts
                  receivable
              
              
              44,503
              
              
              24,113Prepaid
                  expenses
              
              
              4,782
              
              
              2,433Deferred
                  tax asset
              
              
              2,103
              
              
              2,212Total
                  current assets
              
              
              70,265
              
              
              57,950Property
                  and equipment, net
              
              
              503,916
              
              
              313,091Intangible
                  assets, net
              
              
              6,543
              
              
              7,243Other
                  assets, net
              
              
              10,474
              
              
              7,955Goodwill
              
              
              97,470
              
              
              37,470$
              688,668
              
              $
              423,709**LIABILITIES
                  AND STOCKHOLDERS’ EQUITY**Current
                  liabilities:Current
                  portion of long-term debt
              
              $
              121
              
              $
              3,401Accounts
                  payable
              
              
              28,127
              
              
              20,869Liabilities
                  associated with drilling contracts
              
              
              55,627
              
              
              29,375Accrued
                  producer liabilities
              
              
              23,364
              
              
              8,815Accrued
                  hedge liability
              
              
              11,972
              
              
              3,972Accrued
                  liabilities
              
              
              23,417
              
              
              10,795Advances
                  from affiliate
              
              
              1,286
              
              
              -Total
                  current liabilities
              
              
              143,914
              
              
              77,227Long-term
                  debt
              
              
              180,140
              
              
              82,239Advances
                  from parent
              
              
              -
              
              
              10,413Deferred
                  tax liability
              
              
              25,658
              
              
              23,654Other
                  liabilities
              
              
              16,834
              
              
              6,949Minority
                  interest
              
              
              207,647
              
              
              132,224Commitments
                  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
              
              
              133Additional
                  paid-in capital
              
              
              75,584
              
              
              75,584ESOP
                  loan receivable
              
              
              (602
              )
              
              -Accumulated
                  other comprehensive loss
              
              
              (2,331
              )
              
              (2,553
              )Retained
                  earnings
              
              
              41,691
              
              
              17,839Total
                  stockholders’ equity
              
              
              114,475
              
              
              91,003$
              688,668
              
              $
              423,709
 
 See
        accompanying notes to consolidated financial statements
  3
 *Index*
  **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
              
              $
              64,577Gas
                  and oil production
              
              
              16,051
              
              
              12,977
              
              
              44,669
              
              
              34,972Gathering,
                  transmission and processing
              
              
              81,322
              
              
              1,344
              
              
              168,845
              
              
              4,522Well
                  services
              
              
              2,422
              
              
              2,146
              
              
              7,020
              
              
              6,206126,544
              
              
              32,837
              
              
              319,292
              
              
              110,277**COSTS
                  AND EXPENSES**Well
                  drilling
              
              
              23,259
              
              
              14,235
              
              
              85,876
              
              
              56,154Gas
                  and oil production and exploration
              
              
              2,452
              
              
              2,369
              
              
              6,667
              
              
              7,377Gathering,
                  transmission and processing
              
              
              70,485
              
              
              551
              
              
              143,627
              
              
              1,767Well
                  services
              
              
              1,293
              
              
              1,009
              
              
              3,800
              
              
              3,071General
                  and administrative
              
              
              4,709
              
              
              2,254
              
              
              7,863
              
              
              3,713Compensation
                  reimbursement - affiliate
              
              
              145
              
              
              350
              
              
              602
              
              
              1,050Depreciation,
                  depletion and amortization
              
              
              6,506
              
              
              3,458
              
              
              17,159
              
              
              10,237108,849
              
              
              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
              
              
              21,909Provision
                  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
              
              $
              1.28Weighted
                  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
              
              $
              1.28Weighted
                  average common shares outstanding
              
              
              13,339
              
              
              12,018
              
              
              13,339
              
              
              11,131
 
 See
        accompanying notes to consolidated financial statements
  4
 *Index*
  **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
              
              $
              91,003Net
                  income
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              23,852
              
              
              23,852Other
                  comprehensive income
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              222
              
              
              -
              
              
              222Loan
                  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
 *Index*
  **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
              
              $
              14,241Adjustments
                  to reconcile net income to net cash provided by operating
                  activities:Depreciation,
                  depletion and amortization
              
              
              17,159
              
              
              10,237Amortization
                  of deferred financing costs
              
              
              2,045
              
              
              435Non-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
              
              
              4,188Gain
                  on asset dispositions
              
              
              (47
              )
              
              (41
              )Property
                  impairments and abandonments
              
              
              -
              
              
              721Deferred
                  income taxes
              
              
              1,749
              
              
              9,001Changes
                  in operating assets and liabilities
              
              
              49,605
              
              
              3,211Net
                  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
              
              
              242Increase
                  in other assets
              
              
              (44
              )
              
              (3,546
              )Net
                  cash used in investing activities
              
              
              (267,078
              )
              
              (25,973
              )**CASH
                  FLOWS FROM FINANCING ACTIVITIES:**Borrowings
              
              
              349,250
              
              
              61,500Principal
                  payments on debt
              
              
              (254,630
              )
              
              (56,792
              )Payments
                  to affiliate
              
              
              (22,431
              )
              
              (9,730
              )Issuance
                  of Atlas Pipeline Partners common units
              
              
              91,661
              
              
              25,188Issuance
                  of Atlas America, Inc. common stock
              
              
              -
              
              
              36,999Dividends
                  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
              )
              
              14,620Cash
                  and cash equivalents at beginning of period
              
              
              29,192
              
              
              25,372Cash
                  and cash equivalents at end of period
              
              $
              18,877
              
              $
              39,992
 
 See
        accompanying notes to consolidated financial statements
  6
 *Index*
  **ATLASAMERICA,
        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
 *Index*
  **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
 *Index*
  **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
 *Index*
  **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
              
              $
              14,241Stock-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
              
              $
              13,772Net
                  income per common share:Basic-as
                  reported
              
              $
              .48
              
              $
              .35
              
              $
              1.79
              
              $
              1.28Basic-pro forma
              
              $
              .47
              
              $
              .32
              
              $
              1.75
              
              $
              1.24Diluted-as
                  reported
              
              $
              .48
              
              $
              .35
              
              $
              1.79
              
              $
              1.28Diluted-pro forma
              
              $
              .46
              
              $
              .32
              
              $
              1.75
              
              $
              1.24
 10
 *Index*
  **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
              
              $
              1,100Income
                  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
              
              $
              14,241Other
                  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
 *Index*
  **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
              
              $
              14,241Weighted
                  average common shares outstanding-basic
              
              
              13,333
              
              
              12,015
              
              
              13,333
              
              
              11,129Dilutive
                  effect of stock incentive plan
              
              
              6
              
              
              3
              
              
              6
              
              
              2Weighted
                  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
 *Index*
  **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
              
              $
              122007
              
              
              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
 *Index*
  **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
              
              $
              9952007
              
              
              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”)
                  naturalgas
                  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**AssetsDerivative
                  instruments
              
              $
              1,776
              
              $
              1,776
              
              $
              −
              
              $
              −$
              1,776
              
              $
              1,776
              
              $
              −
              
              $
              −LiabilitiesDerivative
                  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
 *Index*
  **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
                  yearsRights-of-way
                  - Mid-Continent
              40
                  yearsRights-of-way
                  - Appalachia
              20
                  yearsLand,
                  buildings and improvements
              10-40
                  yearsFurniture
                  and equipment
              3-7
                  yearsOther
              3-10
                  years
 
 Property
        and equipment consists of the following (in thousands):
 
 **June
                  30,**
                **2005**
              
              **September
                  30,**
                **2004**Mineral
                  interests:Proved
                  properties
              
              $
              3,068
              
              $
              2,544Unproved
                  properties
              
              
              1,002
              
              
              1,002Wells
                  and related equipment
              
              
              227,358
              
              
              184,046Pipelines,
                  processing and compression facilities
              
              
              323,350
              
              
              163,302Rights-of-way
              
              
              16,121
              
              
              14,702Land,
                  buildings and improvements
              
              
              7,768
              
              
              7,213Support
                  equipment
              
              
              3,398
              
              
              2,902Other
              
              
              5,001
              
              
              4,227587,066
              
              
              379,938Accumulated
                  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
 *Index*
  **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
              
              $
              3,131Liabilities
                  incurred
              
              
              400
              
              
              71
              
              
              2,058
              
              
              101Liabilities
                  settled
              
              
              (52
              )
              
              (15
              )
              
              (84
              )
              
              (43
              )Accretion
                  expense
              
              
              96
              
              
              52
              
              
              288
              
              
              99Revisions
                  of previous estimates
              
              
              -
              
              
              83
              
              
              -
              
              
              83Asset
                  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
 *Index*
  **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
              
              $
              4,704Investments
              
              
              2,134
              
              
              2,166Security
                  deposits
              
              
              1,838
              
              
              1,085Hedge
                  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
              
              $
              14,343Accumulated
                  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
 *Index*
  **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
              
              $
              37,470Preliminary
                  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
              
              
              25,000Term
                  loan -Atlas Pipeline
              
              
              -
              
              
              60,000Other
                  debt
              
              
              261
              
              
              640180,261
              
              
              85,640Less
                  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
              
              $
              1212007
              
              
              12,1002008
              
              
              402009
              
              
              -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
 *Index*
  **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
              
              $
              803Accounts
                  receivable
              
              
              18,505Prepaid
                  expenses
              
              
              649Property,
                  plant and equipment
              
              
              140,936Other
                  long-term assets
              
              
              1,054Total
                  assets acquired
              
              
              161,947Accounts
                  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
 *Index*
  **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
              
              $
              4,577Other
                  assets
              
              
              497Property,
                  plant and equipment
              
              
              133,637Goodwill
              
              
              60,000Total
                  assets acquired
              
              
              198,711Accounts
                  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
                  FormaAdjustment
              
              Pro
                FormaRevenues
              
              $
              126,544
              
              $
              5,083
              
              $
              131,627Net
                  income
              
              $
              6,444
              
              $
              (61
              )
              $
              6,383Net
                  income per common share − basic
              
              $
              .48
              
              $
              -
              
              $
              .48Weighted
                  average common shares − outstanding
              
              
              13,333
              
              
              -
              
              
              13,333Net
                  income per common share − diluted
              
              $
              .48
              
              $
              -
              
              $
              .48Weighted
                  average common shares
              
              
              13,339
              
              
              -
              
              
              13,339
 20
 *Index*
  **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
                  FormaAdjustment
              
              Pro
                FormaRevenues
              
              $
              319,292
              
              $
              89,279
              
              $
              408,571Net
                  income
              
              $
              23,852
              
              $
              (111
              )
              $
              23,741Net
                  income per common share − basic
              
              $
              1.79
              
              $
              (.01
              )
              $
              1.78Weighted
                  average common shares − outstanding
              
              
              13,333
              
              
              -
              
              
              13,333Net
                  income per common share − diluted
              
              $
              1.79
              
              $
              (.01
              )
              $
              1.78Weighted
                  average common shares
              
              
              13,339
              
              
              -
              
              
              13,339
 
 **Three
                    Months Ended**
                  **June
                    30, 2004**As
                    Reported
                
                Pro
                    FormaAdjustment
                
                Pro
                  FormaRevenues
                
                $
                32,837
                
                $
                63,764
                
                $
                96,601Net
                    income
                
                $
                4,182
                
                $
                (37
                )
                $
                4,145Net
                    income per common share − basic
                
                $
                .35
                
                $
                (.01
                )
                $
                .34Weighted
                    average common shares − outstanding
                
                
                12,015
                
                
                -
                
                
                12,015Net
                    income per common share − diluted
                
                $
                .35
                
                $
                (.01
                )
                $
                .34Weighted
                    average common shares
                
                
                12,018
                
                
                -
                
                
                12,018
  **Nine
                    Months Ended**
                  **June
                    30, 2004**As
                    Reported
                
                Pro
                    Forma Adjustment
                
                Pro
                  FormaRevenues
                
                $
                110,277
                
                $
                172,862
                
                $
                283,139Net
                    income
                
                $
                14,241
                
                $
                (852
                )
                $
                13,389Net
                    income per common share − basic
                
                $
                1.28
                
                $
                (.08
                )
                $
                1.20Weighted
                    average common shares − outstanding
                
                
                11,129
                
                
                -
                
                
                11,129Net
                    income per common share − diluted
                
                $
                1.28
                
                $
                (.08
                )
                $
                1.20Weighted
                    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
 *Index*
  **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 externalcustomers
              
              Interestincome
              
              Interestexpense
              
              Depreciation,
                  depletion andamortization
              
              Segmentprofit
                  (loss)(b)
              
              Other
                  significant items:
                Segment
                  assetsWell
                  drilling
              
              $
              26,749
              
              $
              -
              
              $
              -
              
              $
              -
              
              $
              2,807
              
              $
              9,522Production
                  and exploration
              
              
              16,051
              
              
              -
              
              
              -
              
              
              3,145
              
              
              10,210
              
              
              185,542Natural
                  gas and liquids
              
              
              79,700
              
              
              14
              
              
              5
              
              
              2,502
              
              
              3,523
              
              
              395,319Transportation
                  and compression
              
              
              1,622
              
              
              73
              
              
              -
              
              
              626
              
              
              401
              
              
              49,003Other(a)
              
              
              2,422
              
              
              11
              
              
              4,575
              
              
              233
              
              
              (4,928
              )
              
              49,282Total
              
              $
              126,544
              
              $
              98
              
              $
              4,580
              
              $
              6,506
              
              $
              12,013
              
              $
              688,668
 
 **Three
                  Months Ended June 30, 2004**(in thousands):Revenues
                  from externalcustomers
              
              Interestincome
              
              Interestexpense
              
              Depreciation,
                  depletion andamortization
              
              Segmentprofit
                  (loss)(b)
              
              Other
                  significant items:
                Segment
                  assetsWell
                  drilling
              
              $
              16,370
              
              $
              -
              
              $
              -
              
              $
              -
              
              $
              1,753
              
              $
              7,951Production
                  and exploration
              
              
              12,977
              
              
              -
              
              
              -
              
              
              2,468
              
              
              8,024
              
              
              156,895Natural
                  gas and liquids
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Transportation
                  and compression
              
              
              1,344
              
              
              67
              
              
              -
              
              
              592
              
              
              (293
              )
              
              75,970Other(a)
              
              
              2,146
              
              
              -
              
              
              460
              
              
              398
              
              
              (2,816
              )
              
              25,844Total
              
              $
              32,837
              
              $
              67
              
              $
              460
              
              $
              3,458
              
              $
              6,668
              
              $
              266,660
 
 **Nine
                  Months Ended June 30, 2005**(in thousands):Revenues
                  from externalcustomers
              
              Interestincome
              
              Interestexpense
              
              Depreciation,
                  depletion andamortization
              
              Segmentprofit
                  (loss)(b)
              
              Other
                  significant items:
                Segment
                  assetsWell
                  drilling
              
              $
              98,758
              
              $
              -
              
              $
              -
              
              $
              -
              
              $
              11,377
              
              $
              9,522Production
                  and exploration
              
              
              44,669
              
              
              -
              
              
              -
              
              
              9,063
              
              
              28,716
              
              
              185,542Natural
                  gas and liquids
              
              
              164,095
              
              
              45
              
              
              17
              
              
              5,653
              
              
              10,023
              
              
              395,319Transportation
                  and compression
              
              
              4,750
              
              
              181
              
              
              -
              
              
              1,743
              
              
              306
              
              
              49,003Other(a)
              
              
              7,020
              
              
              67
              
              
              7,876
              
              
              700
              
              
              (11,208
              )
              
              49,282Total
              
              $
              319,292
              
              $
              293
              
              $
              7,893
              
              $
              17,159
              
              $
              39,214
              
              $
              688,668
 
 **Nine
                  Months Ended June 30, 2004**(in thousands):Revenues
                  from externalcustomers
              
              Interestincome
              
              Interestexpense
              
              Depreciation,
                  depletion andamortization
              
              Segmentprofit
                  (loss)(b)
              
              Other
                  significant items:
                Segment
                  assetsWell
                  drilling
              
              $
              64,577
              
              $
              -
              
              $
              -
              
              $
              -
              
              $
              7,258
              
              $
              7,951Production
                  and exploration
              
              
              34,972
              
              
              -
              
              
              -
              
              
              7,190
              
              
              20,055
              
              
              156,895Natural
                  gas and liquids
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Transportation
                  and compression
              
              
              4,522
              
              
              109
              
              
              -
              
              
              1,615
              
              
              (383
              )
              
              75,970Other(a)
              
              
              6,206
              
              
              17
              
              
              1,420
              
              
              1,432
              
              
              (5,021
              )
              
              25,844Total
              
              $
              110,277
              
              $
              126
              
              $
              1,420
              
              $
              10,237
              
              $
              21,909
              
              $
              266,660
 22
 *Index*
  **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
 *Index*
  **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
              
              
              58,598Performance
                  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
              
              
              57,752Non-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.
  24
 *Index*
  **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.
  25
 *Index*
  ***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):
  26
 *Index*
  
 **Three
                  Months Ended**
                **June
                  30,**
              
              **Nine
                  Months Ended**
                **June
                  30,****2005**
              
              **2004**
              
              **2005**
              
              **2004**Average
                  drilling revenue per well
              
              $
              243
              
              $
              241
              
              $
              218
              
              $
              192Average
                  drilling cost per well
              
              
              211
              
              
              209
              
              
              190
              
              
              167Average
                  drilling gross profit per well
              
              $
              32
              
              $
              32
              
              $
              28
              
              $
              25Gross
                  profit margin
              
              $
              3,490
              
              $
              2,135
              
              $
              12,882
              
              $
              8,423Gross
                  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:
  27
 *Index*
  **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
              
              $
              30,789Oil
              
              $
              2,106
              
              $
              1,395
              
              $
              5,695
              
              $
              4,183Production
                  volume:Gas
                  (mcf/day)(1)
                  (3)
              
              
              21,214
              
              
              20,710
              
              
              20,275
              
              
              19,485Oil
                  (bbls/day)
              
              
              461
              
              
              452
              
              
              438
              
              
              494Total
                  (mcfe/day)(3)
              
              
              23,980
              
              
              23,422
              
              
              22,903
              
              
              22,449Average
                  sales prices:Gas
                  (per mcf)(3)
              
              $
              7.22
              
              $
              6.16
              
              $
              7.03
              
              $
              5.77Oil
                  (per bbl)(3)
              
              $
              50.15
              
              $
              33.87
              
              $
              47.57
              
              $
              30.93Production
                  costs(2):As
                  a percent of production revenues
              
              
              12
              %
              
              14
              %
              
              13
              %
              
              15
              %Per
                  mcfe(3)
              
              $
              .91
              
              $
              .84
              
              $
              .94
              
              $
              .84Depletion
                  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.
  28
 *Index*
  ***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
  29
 *Index*
  ·
              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.
  30
 *Index*
  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
              
              $
              41,993Used
                  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.
  31
 *Index*
  *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.  Net ** cash
        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
  32
 *Index*
  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
                YearsLong-term
                  debt(1)
              
              $
              180,261
              
              $
              121
              
              $
              12,140
              
              $
              168,000
              
              $
              -Secured
                  revolving credit facilities
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Operating
                  lease obligations
              
              
              1,263
              
              
              539
              
              
              471
              
              
              251
              
              
              2Capital
                  lease obligations
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Unconditional
                  purchase obligations
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Other
                  long-term obligation
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -Total
                  contractual cash obligations
              
              $
              181,524
              
              $
              660
              
              $
              12,611
              
              $
              168,251
              
              $
              2
 33
 *Index*
  (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
                YearsStandby
                  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.
  34
 *Index*
  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 .
  35
 *Index*
  **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.
  36
 *Index*
  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
              
              $
              122007
              
              
              900,000
              
              
              -0.495
              
              
              21$
              33
 37
 *Index*
  **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
              
              $
              9952007
              
              
              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 naturalgas
                  and light crude prices.
 (3)
              Fair
                  value based on forward NYMEX natural gas and light crude prices,
                  as
                  applicable
 
 38
 *Index*
  **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:
                11,988,415AGAINST:
                557,408ABSTAIN:
                78,052BROKER
                    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:
                11,984,545AGAINST:
                561,194ABSTAIN:
                78,236BROKER
                    NON-VOTES:
                709,315
 39
 *Index*
  ●
                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:
                11,984,781AGAINST:
                561,442ABSTAIN:
                77,752BROKER
                    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. BagnellFOR:
                13,327,538WITHHELD:
                4,892Nicholas
                    A. DiNubileFOR:
                13,321,294WITHHELD:
                11,136Carlton
                    M. ArrendellFOR:
                13,327,538WITHHELD:
                4,892Jonathan
                    Z. CohenFOR:
                13,329,338WITHHELD:
                3,092Donald
                    W. DelsonFOR:
                13,320,434WITHHELD:
                11,996Edward
                    E. CohenFOR:
                13,328,178WITHHELD:
                4,252Dennis
                    A. HoltzFOR:
                13,321,884WITHHELD:
                10,546
 
 There
        were no broker non-votes on this matter.
 
 **Item
                  6.**
              **Exhibits**
  Exhibit
                  No.
              
              Description3.2
              
              
              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.
  40
 *Index*
  **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. JonesExecutive
                  Vice President and Chief Financial OfficerDate: 
                  August 15, 2005
              By:
              */s/
                  Nancy J. McGurk*Nancy
                  J. McGurkSenior
                  Vice President and Chief Accounting Officer
 41