**UNITED
      STATES**


**SECURITIES
      AND EXCHANGE COMMISSION**


**Washington,
      D.C. 20549**





**FORM
      10-Q**








(Mark
      One)


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








For
      the
      quarterly period ended December 31, 2005





**OR**





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








For
      the
      transition period from _________ to __________





Commission
      file number: **333-112653**








**ATLAS
      AMERICA, INC.**





(Exact
      name of registrant as specified in its charter)





**Delaware**
            **51-0404430**(State
                or other jurisdiction of
              incorporation
                or organization)
            (I.R.S.
                Employer
              Identification
                No.)**311
                Rouser
                Road****Moon
                Township, PA**
            **15108**(Address
                of principal executive offices)
            (Zip
                code)





Registrant's
      telephone number, including area code: **(412)
      262-2830**





Indicate
      by check mark whether the registrant (1) has filed all reports required to
      be
      filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
      the
      preceding 12 months (or for such shorter period that the registrant was required
      to file such reports), and (2) has been subject to such filing requirements
      for
      the past 90 days.  Yes [X]  No
      [ ]





Indicate
      by check mark whether the registrant is a large accelerated filer, an
      accelerated filer, or a non-accelerated filer. See definition of “accelerated
      filer” and “large accelerated filer” in Rule 12b-2 of the Exchange
      Act.  Large accelerated filer  [  ]  Accelerated filer  
      [X]  Non-accelerated filer  [  ]





Indicate
      by check mark whether the registrant is a shell company (as defined in Rule
      12b-2 of the Exchange Act).  Yes  [  ]  No  [X]





The
      number of outstanding shares of the registrant’s common stock on February 1,
      2006 was 13,355,065 shares.












**ATLAS
      AMERICA, INC.**


**INDEX
      TO QUARTERLY REPORT ON FORM 10-Q**





**Page****PART
                I**
            **FINANCIAL
                INFORMATION**Item
                1.
            Financial
                Statements (Unaudited)Consolidated
                Balance Sheets - December 31, 2005 and September 30, 2005
            3Consolidated
                Statements of Income Three Months Ended December 31, 2005and
                2004
            4Consolidated
                Statement of Changes in Stockholders’ Equity for the Three MonthsEnded
                December 31, 2005
            5Consolidated
                Statements of Cash Flows for the Three Months Ended December
                31, 2005 and 2004
            6Notes
                to Consolidated Financial Statements - December 31, 2005
            7
                -
                26Item
                2.
            Management’s
                Discussion and Analysis of Financial Condition and Resultsof
                Operations
            27
                - 36Item
                3.
            Quantitative
                and Qualitative Disclosures about Market Risk
            37
                - 40Item
                4.
            Controls
                and Procedures
            41**PART
                II**
            **OTHER
                INFORMATION**Item
                2.
            Unregistered
                Sales of Equity Securities and Use of Proceeds
            41Item
                5.
            Other
                Information
            42Item
                6.
            Exhibits
            42**SIGNATURES**
            43























2




**PART
      I.  FINANCIAL INFORMATION**




**Item
      1.**  **Financial
      Statements**


**ATLAS
      AMERICA, INC.**


**CONSOLIDATED
      BALANCE SHEETS**


(Unaudited)


(in
      thousands, except share data)


**December
                31,**
            
            **September
                30,****2005**
            
            **2005****ASSETS**Current
                assets:Cash
                and cash equivalents
            
            $
            55,155
            
            $
            18,281Accounts
                receivable
            
            
            89,830
            
            
            73,996Prepaid
                expenses
            
            
            5,772
            
            
            5,063Deferred
                tax asset
            
            
            6,249
            
            
            6,970Advances
                to affiliate
            
            
            492
            
            
            -Total
                current assets
            
            
            157,498
            
            
            104,310Property
                and equipment, net
            
            
            658,347
            
            
            505,967Intangible
                assets, net
            
            
            60,959
            
            
            18,708Other
                assets, net
            
            
            74,313
            
            
            15,360Goodwill
            
            
            105,063
            
            
            115,366$
            1,056,180
            
            $
            759,711**LIABILITIES
                AND STOCKHOLDERS’ EQUITY**Current
                liabilities:Current
                portion of long-term debt
            
            $
            1,351
            
            $
            122Accounts
                payable
            
            
            56,769
            
            
            31,477Liabilities
                associated with drilling contracts
            
            
            70,514
            
            
            60,971Accrued
                producer liabilities
            
            
            32,537
            
            
            32,543Accrued
                hedge liability
            
            
            24,107
            
            
            37,663Accrued
                liabilities
            
            
            33,091
            
            
            18,231Advances
                from affiliate
            
            
            -
            
            
            111Total
                current liabilities
            
            
            218,369
            
            
            181,118Long-term
                debt
            
            
            297,430
            
            
            191,605Deferred
                tax liability
            
            
            29,369
            
            
            28,903Other
                liabilities
            
            
            54,865
            
            
            47,612Minority
                interest
            
            
            323,297
            
            
            190,122Commitments
                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
            
            
            75,967
            
            
            75,637Treasury
                stock, at cost
            
            
            (73
            )
            
            -ESOP
                loan receivable
            
            
            (564
            )
            
            (583
            )Accumulated
                other comprehensive loss
            
            
            (5,116
            )
            
            (5,615
            )Retained
                earnings
            
            
            62,503
            
            
            50,779Total
                stockholders’ equity
            
            
            132,850
            
            
            120,351$
            1,056,180
            
            $
            759,711




See
      accompanying notes to consolidated financial statements





3





**ATLAS
      AMERICA, INC.**


**CONSOLIDATED
      STATEMENTS OF INCOME**


(in
      thousands, except per share data)


(Unaudited)


**Three
                Months Ended****December
                31,****2005**
            
            **2004****REVENUES**Well
                drilling
            
            $
            42,145
            
            $
            30,558Gas
                and oil production
            
            
            24,086
            
            
            14,659Transmission,
                gathering and processing
            
            
            129,460
            
            
            43,782Drilling
                management fee
            
            
            1,576
            
            
            -Well
                services
            
            
            2,561
            
            
            2,248199,828
            
            
            91,247**COSTS
                AND EXPENSES**Well
                drilling
            
            
            36,648
            
            
            26,573Gas
                and oil production and exploration
            
            
            2,458
            
            
            1,802Transmission,
                Gathering and processing
            
            
            109,889
            
            
            35,680Well
                services
            
            
            1,487
            
            
            1,191General
                and administrative
            
            
            8,048
            
            
            1,660Compensation
                reimbursement - affiliate
            
            
            163
            
            
            213Depreciation,
                depletion and amortization
            
            
            10,324
            
            
            5,872169,017
            
            
            72,991**OPERATING
                INCOME**
            
            
            30,811
            
            
            18,256**OTHER
                INCOME (EXPENSE**)Interest
                expense
            
            
            (6,147
            )
            
            (1,690
            )Minority
                interest in Atlas Pipeline Partners, L.P.
            
            
            (6,745
            )
            
            (7,220
            )Arbitration
                settlement, net
            
            
            -
            
            
            4,446Other,
                net
            
            
            691
            
            
            102(12,201
            )
            
            (4,362
            )Income
                from continuing operations before income taxes
            
            
            18,610
            
            
            13,894Provision
                for income taxes
            
            
            6,886
            
            
            5,002**Net
                income**
            
            $
            11,724
            
            $
            8,892**Net
                income per common share****-****basic**Net
                income per common share - basic
            
            $
            .88
            
            $
            .67Weighted
                average common shares outstanding
            
            
            13,335
            
            
            13,333**Net
                income per common share****-****diluted**Net
                income per common shares - diluted
            
            $
            .87
            
            $
            .67Weighted
                average common shares outstanding
            
            
            13,477
            
            
            13,338

















See
      accompanying notes to consolidated financial statements








4





**ATLAS
      AMERICA, INC.**


**CONSOLIDATED
      STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY**


**THREE
      MONTHS ENDED DECEMBER 31, 2005**


(in
      thousands, except share data)


(Unaudited)














**Accumulated****Additional**
              
              
              
              
              
              **ESOP**
              
              **Other**
              
              
              
              **Total****Common
                  Stock**
              
              **Paid-In**
              
              **Treasury
                  Stock**
              
              **Loan**
              
              **Comprehensive**
              
              **Retained**
              
              **Stockholders’****Shares**
              
              **Amount**
              
              **Capital**
              
              **Shares**
              
              **Amount**
              
              **Receivable**
              
              **Income
                  (Loss)**
              
              **Earnings**
              
              **Equity**Balance,
                  October 1, 2005
              
              
              13,334,703
              
              $
              133
              
              $
              75,637
              
              
              -
              
              $
              -
              
              $
              (583
              )
              $
              (5,615
              )
              $
              50,779
              
              $
              120,351Net
                  Income
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              11,724
              
              
              11,724Other
                  comprehensive income
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              499
              
              
              
              
              
              499Issuance
                  of common stock
              
              
              1,328
              
              
              -
              
              
              64
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              64Repurchase
                  of common stock, at cost
              
              
              
              
              
              
              
              
              
              
              
              (1,335
              )
              
              (73
              )
              
              
              
              
              
              
              
              
              
              
              (73
              )Repayment
                  of ESOP loan
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              19
              
              
              
              
              
              
              
              
              19Stock
                  option compensation
              
              
              -
              
              
              -
              
              
              266
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              -
              
              
              266Balance,
                  December 31, 2005
              
              
              13,336,031
              
              $
              133
              
              $
              75,967
              
              
              (1,335
              )
              $
              (73
              )
              $
              (564
              )
              $
              (5,116
              )
              $
              62,503
              
              $
              132,850


































See
      accompanying notes to consolidated financial statements























5








**ATLAS
      AMERICA, INC.**


**CONSOLIDATED
      STATEMENT OF CASH FLOWS**


**THREE
      MONTHS ENDED DECEMBER 31, 2005**


(in
      thousands)


(Unaudited)








**Three
                Months Ended****December
                31,****2005**
            
            **2004****CASH
                FLOWS FROM OPERATING ACTIVITIES:**Net
                income
            
            $
            11,724
            
            $
            8,892Adjustments
                to reconcile net income to net cash provided by operating
                activities:Depreciation,
                depletion and amortization
            
            
            10,324
            
            
            5,872Amortization
                of deferred financing costs
            
            
            544
            
            
            310Non-cash
                loss on derivative value
            
            
            138
            
            
            795Non-cash
                compensation on long-term incentive plans
            
            
            1,320
            
            
            416Minority
                interest in Atlas Pipeline Partners, L.P.
            
            
            6,745
            
            
            7,220Gain
                on asset dispositions
            
            
            (2
            )
            
            (24
            )Deferred
                income taxes
            
            
            1,033
            
            
            725Changes
                in operating assets and liabilities
            
            
            27,324
            
            
            29,219Net
                cash provided by operating activities
            
            
            59,150
            
            
            53,425**CASH
                FLOWS FROM INVESTING ACTIVITIES:**Business
                acquisition, net of cash acquired
            
            
            (163,630
            )
            
            -Capital
                expenditures
            
            
            (31,809
            )
            
            (16,882
            )Proceeds
                from sale of assets
            
            
            3
            
            
            35Decrease
                (increase) in other assets
            
            
            495
            
            
            (327
            )Net
                cash used in investing activities
            
            
            (194,941
            )
            
            (17,174
            )**CASH
                FLOWS FROM FINANCING ACTIVITIES:**Borrowings
            
            
            216,841
            
            
            27,502Principal
                payments on debt
            
            
            (399,367
            )
            
            (50,556
            )Issuance
                of Atlas Pipeline Partners, L.P. common units
            
            
            120,980
            
            
            -Payments
                to affiliate
            
            
            -
            
            
            (9,349
            )Issuance
                of Atlas Pipeline Partners, L.P. Senior Notes
            
            
            243,102
            
            
            -Distributions
                paid to minority interests of Atlas Pipeline Partners, L.P.
            
            
            (6,381
            )
            
            (3,839
            )Increase
                in other assets
            
            
            (2,510
            )
            
            (42
            )Net
                cash provided by (used in) financing activities
            
            
            172,665
            
            
            (36,284
            )Increase
                (decrease) in cash and cash equivalents
            
            
            36,874
            
            
            (33
            )Cash
                and cash equivalents at beginning of period
            
            
            18,281
            
            
            29,192Cash
                and cash equivalents at end of period
            
            $
            55,155
            
            $
            29,159











See
      accompanying notes to consolidated financial statements





6





**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS**


**December
      31, 2005**


(Unaudited)





**NOTE
      1 - BASIS OF PRESENTATION**





**Principles
      of Consolidation**





The
      consolidated financial statements include the accounts of Atlas America, Inc.
      (the “Company” or “ATLS”) and all of its subsidiaries, which are wholly owned
      except for Atlas Pipeline Partners, L.P. (“Atlas Pipeline”).  Atlas
      Pipeline is a master limited partnership in which the Company has a combined
      general and limited partnership interest of 15% and 24% at December 31, 2005
      and
      2004, respectively. The limited partner units were subordinated until January
      1,
      2005, when the subordination term expired and they were converted to common
      units in accordance with the terms of the partnership agreement.





The
      consolidated financial statements and the information and tables contained
      in
      the notes to the consolidated financial statements as of December 31, 2005
      and
      for the three months ended December 31, 2005 and 2004 are unaudited. 
Certain information and footnote disclosures normally included in financial
      statements prepared in accordance with accounting principles generally accepted
      in the United States of America have been condensed or omitted in these
      statements pursuant to the rules and regulations of the Securities and Exchange
      Commission.  However, in the opinion of management, these interim financial
      statements include all the necessary adjustments to fairly present the results
      of the interim periods presented.  The results of operations for the three
      months ended December 31, 2005 may not necessarily be indicative of the results
      of operations for the full fiscal year ending September 30, 2006. Certain
      reclassifications have been made to the consolidated financial statements as
      of
      September 30, 2005 and for the three months ended December 31, 2004 to conform
      to the presentation as of and for the three months ended December 31,
      2005.





**Spin-off
      from Resource America, Inc.**





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





**NOTE
      2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES**





Reference
      is hereby made to the Company's Annual Report on Form 10-K for the fiscal year
      ended September 30, 2005, which contains a summary of significant accounting
      policies followed by the Company in the preparation of its consolidated
      financial statements.  These policies were also followed in preparing the
      quarterly report included herein.





7





**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**


**December
      31, 2005**


(Unaudited)





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





**Recently
      Issued Financial Accounting Standards**





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





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





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





**Receivables**





In
      evaluating its allowance for possible losses, the Company performs ongoing
      credit evaluations of its customers and adjusts credit limits based upon payment
      history and the customers’ current creditworthiness, as determined by the
      Company’s review of its customers’ credit information. The Company extends
      credit on an unsecured basis to many of its energy customers. At December 31
      and
      September 30, 2005, the Company’s credit evaluation indicated that it has no
      need for an allowance for possible losses.










8





**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**


**December
      31, 2005**


(Unaudited)





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





**Revenue
      Recognition**





Because
      there are timing differences between the delivery of natural gas, NGLs and
      oil
      and the Company’s receipt of a delivery statement, the Company has unbilled
      revenues. These revenues are accrued based upon volumetric data from the
      Company’s records and the Company’s estimates of the related transportation and
      compression fees which are, in turn, based upon applicable product prices.
      The
      Company had unbilled trade receivables at December 31 and September 30, 2005
      of
      $71.6 million and $57.1 million which are included in Accounts Receivable on
      its
      Consolidated Balance Sheets.





**NOTE
      3 - COMPREHENSIVE INCOME**





Comprehensive
      income includes net income and other gains and losses affecting stockholders’
equity from non-owner sources that, under accounting principles generally
      accepted in the United States of America, have not been recognized in the
      calculation of net income. For the Company, this includes only changes in the
      fair value, net of taxes, of unrealized hedging gains and losses (shown in
      thousands).





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





**NOTE
      4 - EARNINGS PER SHARE**





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





**Three
                Months Ended****December
                31,****2005**
            
            **2004**Net
                Income
            
            $
            11,724
            
            $
            8,892Weighted
                average common shares outstanding-basic
            
            
            13,335
            
            
            13,333Dilutive
                effect of stock option and award plan
            
            
            142
            
            
            5Weighted
                average common shares-diluted
            
            
            13,477
            
            
            13,338





9





**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**


**December
      31, 2005**


(Unaudited)





**NOTE
      5 - PROPERTY AND EQUIPMENT**





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





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





**December
                31,**
            
            **September
                30,****2005**
            
            **2005**Mineral
                interests:Proved
                properties
            
            $
            2,308
            
            $
            2,852Unproved
                properties
            
            
            1,002
            
            
            1,002Wells
                and related equipment
            
            
            273,725
            
            
            255,879Pipelines,
                processing and compression facilities
            
            
            445,859
            
            
            304,523Rights-of-way
            
            
            15,769
            
            
            15,110Land,
                building and improvements
            
            
            7,799
            
            
            7,793Support
                equipment
            
            
            4,201
            
            
            3,675Other
            
            
            6,292
            
            
            5,251756,955
            
            
            596,085Accumulated
                depreciation, depletion and amortization:Oil
                and gas properties and pipelines
            
            
            (94,105
            )
            
            (85,824
            )Other
            
            
            (4,503
            )
            
            (4,294
            )(98,608
            )
            
            (90,118
            )$
            658,347
            
            $
            505,967




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





10








**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**


**December
      31, 2005**


(Unaudited)





**NOTE
      6 - OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL**





**Other
      Assets**





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





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





Deferred
      financing costs are recorded at cost and are amortized over the terms of the
      related loan agreements which range from three to ten years.





**Intangible
      Assets**





*Customer
      contracts and relations.*At December 31, 2005, Atlas Pipeline had $54.9 million of intangible
      assets, net of accumulated amortization of $2.1 million which was recorded
      in
      connection with natural gas gathering contracts and customer relations assumed
      in its acquisition of Elk City and NOARK (See Note 12). Statement of Financial
      Accounting Standard No. 142, *Goodwill and Other Intangible Assets*
      (“SFAS 142”), requires that intangible assets such as these gas gathering
      contracts and customer relations with finite useful lives be amortized over
      their respective estimated useful lives. If an intangible asset has a finite
      useful life, but the precise length of that life is not known, that intangible
      asset shall be amortized over the best estimate of its useful life. At a
      minimum, Atlas Pipeline will assess the useful lives and residual values of
      all
      intangible assets on an annual basis to determine if adjustments are required.
      Amortization expense on the customer contract and relations intangible assets,
      which have an estimated life of eight and 20 years, respectively, and are
      amortized on a straight-line basis, was $1.6 million and $0 for the three months
      ended December 31, 2005 and 2004, respectively.





*Partnership
      and operating contracts.* Included
      in intangible assets are partnership management and operating contracts acquired
      through acquisitions which are recorded at fair value on their acquisition
      dates.  The Company amortizes contracts acquired on the declining balance
      and straight-line methods, over their respective estimated lives, ranging from
      five to 13 years.  Amortization expense for these contracts for the three
      months ended December 31, 2005 and 2004 was $220,000 and $233,000,
      respectively.





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





11





**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**


**December
      31, 2005**


(Unaudited)





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





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





**December
                31,**
            
            **September
                30,****2005**
            
            **2005****Accumulated**
            
            
            
            **Accumulated****Cost**
            
            **Amortization**
            
            **Cost**
            
            **Amortization**Customer
                contracts and relations
            
            $
            56,950
            
            $
            (2,081
            )
            $
            12,891
            
            $
            (492
            )Partnership
                management and operating contracts
            
            
            14,343
            
            
            (8,253
            )
            
            14,343
            
            
            (8,034
            )Intangible
                assets
            
            $
            71,293
            
            $
            (10,334
            )
            $
            27,234
            
            $
            (8,526
            )





**Goodwill**





The
      Company applies the provisions of SFAS No. 142, which require that goodwill
      no
      longer be amortized, but instead evaluated for impairment at least annually.
      The
      Company performs such evaluations annually or when impairment indicators arise,
      and will reflect the impairment of goodwill, if any, within the consolidated
      statements of income in the period in which the impairment is indicated. A
      reconciliation of the Company’s goodwill for the periods indicated is as follows
      (in thousands).





**December
                31,**
            
            **September
                30,****2005**
            
            **2005**Goodwill
                at beginning of period, net of accumulated amortization of
                $4,532
            
            $
            115,366
            
            $
            37,470Adjustment
                to goodwill related to Atlas Pipeline acquisitions(see
                Note 12)
            
            
            (10,303
            )
            
            77,896Goodwill
                at end of period, net of accumulated amortization of $4,532
            
            $
            105,063
            
            $
            115,366








**NOTE
      7 - ASSET RETIREMENT OBLIGATIONS**





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





A
      reconciliation of the Company’s liability for well plugging and abandonment
      costs for the periods indicated is as follows (in thousands):





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








12





**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**


**December
      31, 2005**


(Unaudited)





**NOTE
      7 - ASSET RETIREMENT OBLIGATIONS - (Continued)**





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





**NOTE
      8 - DEBT**





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





**December
                31,**
            
            **September
                30,****2005******
            
            **2005**Senior
                notes - Atlas Pipeline
            
            $
            250,000
            
            $
            -Revolving
                credit facility - Atlas Pipeline
            
            
            9,500
            
            
            183,500Revolving
                credit facility
            
            
            -
            
            
            8,000Installment
                notes - NOARK
            
            
            39,000
            
            
            -Other
                debt
            
            
            281
            
            
            227298,781
            
            
            191,727Less
                current maturities
            
            
            1,351
            
            
            122$
            297,430
            
            $
            191,605





*Atlas
      Pipeline Senior Notes.*  In
      December 2005, Atlas Pipeline and its subsidiary, Atlas Pipeline Finance
      Corporation, issued $250.0 million of 10-year, 8.125% senior unsecured notes
      (“Senior Notes”) in a private placement transaction pursuant to Rule 144A and
      Regulation S under the Securities Act of 1933 for net proceeds of approximately
      $243.1 million, after underwriting commissions and other transaction costs.
      The
      Senior Notes are guaranteed by all of Atlas Pipeline’s existing subsidiaries,
      other than NOARK. Interest on the Senior Notes is payable semi-annually in
      arrears on June 15 and December 15, commencing on June 15, 2006. The Senior
      Notes are redeemable at any time on or after December 15, 2010 at specified
      redemption prices, together with accrued and unpaid interest to the date of
      redemption. The Senior Notes are also redeemable at any time prior to December
      15, 2010 at a make-whole redemption price. In addition, prior to December 15,
      2008, Atlas Pipeline may redeem up to 35% of the aggregate principal amount
      of
      the Senior Notes with the proceeds of certain equity offerings at a stated
      redemption price. The Senior Notes are also subject to repurchase by Atlas
      Pipeline at a price equal to 101% of their principal amount, plus accrued and
      unpaid interest, upon a change of control of Atlas Pipeline, upon certain asset
      sales if the net proceeds are not reinvested into Atlas Pipeline within
      specified time periods. The Senior Notes are junior in right of payment to
      the
      Atlas Pipeline secured debt, including Atlas Pipeline’s obligations under is
      credit facility.





The
      indenture governing the Senior Notes contains covenants, including limitations
      of Atlas Pipeline’s ability to: incur liens; engage in sale/leaseback
      transactions; incur additional indebtedness; declare or pay distributions;
      redeem, repurchase or retire equity interests or subordinated indebtedness;
      make
      investments; or merge, consolidate or sell substantially all of its assets.
      Atlas Pipeline is in compliance with these covenants as of December 31,
      2005.





13





**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**


**December
      31, 2005**


(Unaudited)





**NOTE
      8 - DEBT - (Continued)**





In
      connection with a registration rights agreement entered into by Atlas Pipeline
      upon issuance of the Senior Notes, Atlas Pipeline agreed to (a) file an exchange
      offer registration statement with the Securities and Exchange Commission within
      120 days of issuance of the Senior Notes, (b) cause the exchange offer
      registration statement to be declared effective by the Securities and Exchange
      Commission within 210 days of issuance, and (c) cause the exchange offer to
      be
      consummated within 240 days of issuance. If Atlas Pipeline does not meet the
      aforementioned deadlines, the Senior Notes will be subject to additional
      interest, up to 1% per annum; until such time that the deadlines have been
      met.





*Installment
      notes - NOARK.* Upon
      Atlas Pipeline’s acquisition of a 75% interest in NOARK at October 31, 2005,
      NOARK’s subsidiary, NOARK Pipeline Finance, L.L.C., had $66.0 million in
      principal amount outstanding of 7.15% notes due in 2018. The notes are governed
      by an indenture dated June 1, 1998 for which UMB Bank, N.A. serves as trustee.
      Interest on the notes is payable semi-annually, in cash, in arrears on June
      1
      and December 1 of each year. Liability under the notes was originally allocated
      severally 40% to Enogex and 60% to Southwestern, and the parties were several
      guarantors for their respective allocations. The notes are subject to a
      semi-annual redemption in installments of $600,000each
      at a redemption price of 100% of the principal, plus accrued and unpaid
      interest. Additionally, at the option of either Enogex or Southwestern, notes
      in
      an aggregate principal amount guaranteed by either company as of a particular
      payment date may be redeemed at such notes’ redemption price plus a make-whole
      premium and unpaid interest accrued to that date by giving the trustee at least
      60 days notice. As part of the NOARK acquisition, Enogex agreed to redeem its
      portion of the notes as promptly as practicable after the closing. The
      redemption of $26.4 million of the notes occurred on December 5, 2005. At
      December 31, 2005, $39.0 million of notes remain outstanding and are presented
      on the Company’s consolidated balance sheet, for which Southwestern remains
      liable. Under the NOARK partnership agreement, payments on the notes will be
      made from amounts otherwise distributable to Southwestern and, if that amount
      is
      insufficient, Southwestern is required to make a capital contribution to NOARK.
      NOARK distributes cash available for distribution to the partners, after amounts
      payable on their respective allocations of the notes, in accordance with their
      percentage interests.





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




2006
            
            $
            1,3512007
            
            
            1,3002008
            
            
            1,2302009
            
            
            1,2002010
                and thereafter
            
            
            293,700$
            298,781










14





**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**


**December
      31, 2005**


(Unaudited)





**NOTE
      9 - DERIVATIVE INSTRUMENTS**





*Atlas
      America.* The
      Company from time to time enters into natural gas futures and option contracts
      to hedge its exposure to changes in natural gas prices. At any point in time,
      such contracts may include regulated New York Mercantile Exchange (“NYMEX”)
      futures and options contracts and non-regulated over-the-counter futures
      contracts with qualified counterparties. NYMEX contracts are generally settled
      with offsetting positions, but may be settled by the delivery of natural
      gas.





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





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





*Atlas
      Pipeline.* Atlas
      Pipeline also enters into certain financial swap and option instruments that
      are
      classified as cash flow hedges in accordance with SFAS No. 133, *Accounting for Derivative Instruments and Hedging Activity* .
      Atlas
      Pipeline enters into these instruments to hedge its forecasted natural gas,
      NGLs
      and condensate sales against the variability in expected future cash flows
      attributable to changes in market prices. The swap instruments are contractual
      agreements between counterparties to exchange obligations of money as the
      underlying natural gas, NGLs and condensate is sold. Under these swap
      agreements, Atlas Pipeline receives a fixed price and pays a floating price
      based on certain indices for the relevant contract period.





Atlas
      Pipeline formally documents all relationships between hedging instruments and
      the items being hedged, including the risk management objective and strategy
      for
      undertaking the hedging transactions. This includes matching the natural gas
      futures and options contracts to the forecasted transactions. Atlas Pipeline
      assesses both at the inception of the hedge and on an ongoing basis, whether
      the
      derivatives are effective in offsetting changes in the forecasted cash flow
      of
      hedged items. If Atlas Pipeline determines that a derivative is not effective
      as
      a hedge or that it has ceased to be an effective hedge due to the loss of
      correlation between the hedging instrument and the underlying commodity, Atlas
      Pipeline will discontinue hedge accounting for the derivative and subsequent
      changes in fair value for the derivative will be recognized immediately into
      earnings.





15





**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**


**December
      31, 2005**


(Unaudited)





**NOTE
      9 - DERIVATIVE INSTRUMENTS - (Continued)**





Derivatives
      are recorded in the same manner as the company.   At December 31 and
      September 30, 2005, the Company reflected net hedging liabilities on its balance
      sheets of $41.5 million and $46.7 million, respectively. Of the $5.1 million
      net
      loss in accumulated other comprehensive income (loss) at December 31, 2005,
      the
      Company will reclassify $538,000 of losses to its consolidated statements of
      income over the next twelve month period as these contracts expire, and $4.6
      million will be reclassified in later periods if the fair values of the
      instruments remain at current market values. Actual amounts that will be
      reclassified will vary as a result of future price changes. Ineffective hedging
      gains or losses are recorded within its consolidated statements of income while
      the hedge contract is open and may increase or decrease until settlement of
      the
      contract. Atlas Pipeline recognized losses of $5.6  million and a gain of
      $24,000 related to the settlement of qualifying hedge instruments which are
      included in the Company’s consolidated statement of income for the three months
      ended December 31, 2005 and 2004, respectively. Atlas Pipeline also recognized
      a
      loss of $320,000 and a gain of $440,000 related to the change in market value
      of
      non-qualifying or ineffective hedges which are included in the Company’s
      consolidated statement of income for the three months ended December 31, 2005
      and 2004, respectively.





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





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





**Natural
      Gas Liquids Fixed - Price Swaps**


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


**Natural
      Gas Fixed - Price Swaps** **(4)**


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





16





**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**


**December
      31, 2005**


(Unaudited)





**NOTE
      9 - DERIVATIVE INSTRUMENTS - (Continued)**





**Natural
      Gas Fixed - Price Swaps**(4)


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


**Natural
      Gas Basis Swaps**


Production
            
            
            
            Average
            
            Fair
                ValuePeriod
            
            Volumes
            
            Fixed
                Price
            
            Asset(3)Ended
                December 31,
            
            (MMBTU)(1)
            
            (per
                MMBTU)
            
            (in
                thousands)2006
            
            
            1,200,000
            
            $
            -0.551
            
            $
            3,9162007
            
            
            1,080,000
            
            
            -0.535
            
            
            3,5812008
            
            
            240,000
            
            
            -0.555
            
            
            808$
            8,305


**Fixed
      Purchase Price - Price Swaps**


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


**Fixed
      Price Purchase Basis Swaps**


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


**Plant
      Volume Reduction Fixed - Price Swaps**


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


**Plant
      Volume Reduction Basis Swaps**


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





17





**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**


**December
      31, 2005**


(Unaudited)





**NOTE
      9 - DERIVATIVE INSTRUMENTS - (Continued)**





**Crude
      Oil Fixed - Price Swaps**


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





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





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





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





**NOTE
      10 - OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS**





The
      Company’s operations include four reportable operating segments.  In
      addition to the reportable operating segments, certain other activities are
      reported in the “Other” category.  These operating segments reflect the way
      the Company manages its operations and makes business decisions. The Company
      does not allocate income taxes to its operating segments.  Operating
      segment data for the periods indicated are as follows:











18





**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**


**December
      31, 2005**


(Unaudited)





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





**Three
                Months Ended December 31, 2005**(in
                thousands):Production
            
            Atlas
                Pipeline
            
            AtlasWell
            
            and
            
            Mid-
            
            PipelineDrilling
            
            Exploration
            
            Continent
            
            Appalachia
            
            Other(a)
            
            TotalRevenues
                from external customers
            
            $
            42,145
            
            $
            24,086
            
            $
            127,501
            
            $
            1,959
            
            $
            4,137
            
            $
            199,828Interest
                income
            
            
            -
            
            
            -
            
            
            345
            
            
            83
            
            
            21
            
            
            449Interest
                expense
            
            
            -
            
            
            -
            
            
            767
            
            
            -
            
            
            5,380
            
            
            6,147Depreciation,
                depletion and amortization
            
            
            -
            
            
            4,477
            
            
            4,660
            
            
            750
            
            
            437
            
            
            10,324Segment
                profit (loss)
            
            
            5,012
            
            
            17,089
            
            
            8,885
            
            
            220
            
            
            (12,596
            )
            
            18,610Goodwill
            
            
            6,389
            
            
            21,527
            
            
            67,593
            
            
            2,305
            
            
            7,249
            
            
            105,063Segment
                assets
            
            
            8,428
            
            
            256,210
            
            
            645,801
            
            
            91,176
            
            
            54,565
            
            
            1,056,180**Three
                Months Ended December 31, 2004**(in
                thousands):Production
            
            
            Atlas
                Pipeline
            
            
            AtlasWell
            
            
            and
            
            
            Mid-
            
            
            PipelineDrilling
            
            
            Exploration
            
            
            Continent
            
            
            Appalachia
            
            
            Other(a)
            
            
            TotalRevenues
                from external customers
            
            $
            30,558
            
            $
            14,659
            
            $
            42,061
            
            $
            1,721
            
            $
            2,248
            
            $
            91,247Interest
                income
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            113
            
            
            113Interest
                expense
            
            
            -
            
            
            -
            
            
            8
            
            
            -
            
            
            1,682
            
            
            1,690Depreciation,
                depletion and amortization
            
            
            -
            
            
            2,804
            
            
            2,162
            
            
            545
            
            
            361
            
            
            5,872Segment
                profit (loss)
            
            
            3,678
            
            
            10,113
            
            
            3,648
            
            
            70
            
            
            (3,615
            )
            
            13,894Goodwill
            
            
            6,389
            
            
            21,527
            
            
            -
            
            
            2,305
            
            
            7,249
            
            
            37,470Segment
                assets
            
            
            9,006
            
            
            185,347
            
            
            157,308
            
            
            39,351
            
            
            47,822
            
            
            438,834










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





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





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








19





**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**


**December
      31, 2005**


(Unaudited)





**NOTE
      11 - BENEFIT PLANS**





In
      December 2004, the FASB issued SFAS No. 123R, *Share-Based
      Payment* (“SFAS
      No. 123R”). SFAS No. 123R is a revision of SFAS No. 123, *Accounting
      for Stock-Based Compensation* (“SFAS
      No. 123”), and supersedes Accounting Principles Board Opinion No. 25, *Accounting
      for Stock Issued to Employees* (“APB
      No. 25”), and its related implementation guidance. On October 1, 2005,
      the Company adopted the provisions of SFAS No. 123R using the modified
      prospective method. SFAS No. 123R focuses primarily on accounting for
      transactions in which an entity obtains employee services in share-based payment
      transactions. The Statement requires entities to recognize compensation expense
      for awards of equity instruments to employees based on the grant-date fair
      value
      of those awards (with limited exceptions). SFAS No. 123R also requires the
      benefits of tax deductions in excess of recognized compensation expense to
      be
      reported as a financing cash flow, rather than as an operating cash flow as
      prescribed under the prior accounting rules. This requirement reduces net
      operating cash flows and increases net financing cash flows in periods after
      adoption. Total cash flow remains unchanged from what would have been reported
      under prior accounting rules. For the three months ended December 31, 2005,
      the
      Company recorded compensation expense of $168,000, net of taxes of $98,000.
      At
      December 31, 2005, the Company had unamortized compensation expense of $3.7
      million. There were no options granted or exercised in either of the three
      month
      periods ended December 31, 2005 and 2004.





Prior
      to the adoption of SFAS
      No. 123R, the Company followed the intrinsic value method in accordance
      with APB No. 25 to account for its employee stock options. Accordingly, no
      compensation expense was recognized upon the issuance of stock options under
      the
      Company’s stock incentive plan; however, compensation expense was recognized in
      connection with the issuance of deferred units granted under the incentive
      plan.
      The adoption of SFAS No. 123R primarily resulted in a change in the
      Company’s method of recognizing the fair value of share-based compensation.
      Specifically, the adoption of SFAS No. 123R resulted in the recording of
      compensation expense for employee stock options. Results
      for the three months ended December 31, 2004 have not been restated. Had
      compensation expense for employee stock options granted under the Company’s
      Stock Incentive Plan been determined based on fair value at the grant date
      consistent with SFAS No. 123, the  Company’s
      net income for the three months ended December 31, 2004 would have been
      reduced to the pro forma amounts indicated below (in thousands, except per
      share
      data):


**Three
                Months Ended****December
                31, 2004**Net
                income, as reported
            
            $
            8,892Stock-based
                employee compensation expense reported innet
                income
            
            
            -Stock-based
                employee compensation expense determined underthe
                fair value-based method for all awards, net of tax of
                ($77)
            
            
            (136
            )Pro
                forma net income
            
            $
            8,756Net
                income per common share:Basic-as
                reported
            
            $
            .67Basic-pro forma
            
            $
            .66Diluted-as
                reported
            
            $
            .67Diluted-pro forma
            
            $
            .66










20




**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**


**December
      31, 2005**


(Unaudited)





**NOTE
      11 - BENEFIT PLANS - (Continued)**





*Stock
      Incentive Plan.* The
      Company adopted a Stock Incentive Plan (the “Plan”) in fiscal 2004 which
      authorized the granting of up to 1,333,333 shares of the Company’s common stock
      to employees, affiliates, consultants and directors of the Company in the form
      of incentive stock options (“ISOs”), non-qualified stock options, stock
      appreciation rights (“SARs”), restricted stock and deferred units. In July 2005,
      options for 777,500 shares were issued under this Plan. Options under the Plan
      become exercisable as to 25% of the optioned shares each year after the date
      of
      grant, except options totaling 500,000 shares awarded to Messrs. Edward Cohen
      and Jonathan Cohen which are immediately exercisable, and expire not later
      than
      ten years after the date of grant.





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






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






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







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


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





21








**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**


**December
      31, 2005**


(Unaudited)




**NOTE
      11 - BENEFIT PLANS - (Continued)**







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





**Outstanding**
            
            **Exercisable****Weighted**
            
            **Weighted**
            
            
            
            **Weighted****Range
                of**
            
            
            
            **Average**
            
            **Average**
            
            
            
            **Average****Exercise**
            
            
            
            **Contractual**
            
            **Exercise**
            
            
            
            **Exercise****Prices**
            
            **Shares**
            
            **Life
                (Years)**
            
            **Price**
            
            **Shares**
            
            **Price**$-0-
            
            
            7,320
            
            
            8.71
            
            $
            -0-
            
            
            -0-
            
            $
            -0-$38.21
            
            
            777,500
            
            
            9.50
            
            $
            38.21
            
            
            500,000
            
            $
            38.21784,820
            
            
            
            
            
            
            
            
            500,000




*Employee
      Stock Ownership
      Plan.* In June
      2005, in connection with the spin-off from RAI, the Company established an
      Employee Stock Ownership Plan ("ESOP"). The ESOP, which is a qualified
      non-contributory retirement plan, was established to acquire shares of the
      Company's common stock for the benefit of all employees who are 21 years of
      age
      or older and have completed 1,000 hours of service for the Company. In addition,
      as a result of the spin-off, the ESOP holds 167,000 shares of RAI stock, of
      which 127,000 are allocated to participants. **** The
      Company loaned $602,000 (payable in quarterly installments of $18,508 plus
      interest at 7.5%) to the ESOP, which was used by the ESOP to acquire the
      remaining unallocated 40,375 shares of RAI common stock. Contributions to the
      ESOP are made at the discretion of the Company's Board of Directors. The cost
      of
      shares purchased by the ESOP but not yet allocated to participants is shown
      as a
      reduction of stockholders’ equity. The unearned benefits expense (a reduction in
      stockholders' equity) will be reduced by the amount of any loan principal
      payments made by the ESOP to the Company. Any dividends which may be paid on
      allocated shares will reduce retained earnings; dividends on unearned ESOP
      shares will be used to service the related debt.






The
      common stock purchased by the ESOP with the money borrowed is held by the ESOP
      trustee in a suspense account. On an annual basis, as the ESOP loan is paid
      down, a portion of the common stock will be released from the suspense account
      and allocated to participating employees. As of December 31, 2005, there were
      76,500 shares allocated to participants and 22,500 shares which are unallocated.
      Compensation expense related to the plan amounted to $29,000 for the three
      months ended December 31, 2005. The fair value of unearned ESOP shares was
      $2.0
      million at December 31, 2005.





*Supplemental
      Employment Supplemental Employment Retirement Plan (“SERP”).* In May
      2004, the Company entered into an employment agreement with its Chairman of
      the
      Board, Chief Executive Officer and President, Edward E. Cohen, pursuant to
      which
      the Company has agreed to provide him with a SERP and with certain financial
      benefits upon termination of his employment. Under the SERP, Mr. Cohen will
      be
      paid an annual benefit equal to the product of (a) 6.5% multiplied by, (b)
      his
      base salary at the time of his retirement, death or other termination of
      employment with the Company, multiplied by, (c) the amount of years he shall
      be
      employed by the Company commencing upon the effective date of the SERP
      agreement, limited to an annual maximum benefit of 65% of his final base salary
      and a minimum of 26% of his final base salary. During the three months ended
      December 31, 2005 and 2004, operations were charged $40,300 and $39,000,
      respectively, with respect to this commitment.










22








**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**


**December
      31, 2005**


(Unaudited)


**NOTE
      11 - BENEFIT PLANS - (Continued)**





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





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


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





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







**NOTE
      12 − ACQUISITIONS BY ATLAS PIPELINE**




**NOARK**





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











23





**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**


**December
      31, 2005**


(Unaudited)





**NOTE
      12 − ACQUISITIONS BY ATLAS PIPELINE - (Continued)**





•
            
            The
                Ozark Gas Transmission system, a 565-mile FERC-regulated interstate
                pipeline system which extends from southeast Oklahoma through Arkansas
                and
                into southeast Missouri and has a throughput capacity of approximately
                322
                MMcf/d. The system includes approximately 30 supply and delivery
                interconnections and two compressor stations.•
            
            The
                Ozark Gas Gathering system, a 365-mile intrastate natural gas gathering
                system, located in eastern Oklahoma and western Arkansas, and 11
                associated compressor stations.





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




The
      following table presents the preliminary purchase price allocation, including
      professional fees and other related acquisition costs, to the assets acquired
      and liabilities assumed, based on their fair values at the date of acquisition
      (in thousands):





Cash
                and cash equivalents
            
            $
            16,214Accounts
                receivable
            
            
            12,272Prepaid
                expenses
            
            
            497Property,
                plant and equipment
            
            
            126,306Minority
                interest in NOARK
            
            
            42,564Other
                assets
            
            
            1,515Intangible
                assets
            
            
            27,300Goodwill
            
            
            6,456Total
                assets acquired
            
            
            233,125Accounts
                payable and accrued liabilities
            
            
            (13,694
            )Long-term
                debt
            
            
            (39,600
            )Total
                liabilities assumed
            
            
            (53,294
            )Net
                assets acquired
            
            $
            179,830








**Elk
      City**





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





24





**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**


**December
      31, 2005**


(Unaudited)





**NOTE
      12 − ACQUISITIONS BY ATLAS PIPELINE - (Continued)**





The
      following table presents the purchase price allocation, including professional
      fees and other related acquisition costs, to the assets acquired and liabilities
      assumed, based on their fair values at the date of acquisition (in
      thousands):





Accounts
                receivable
            
            $
            5,587Other
                assets
            
            
            497Property,
                plant and equipment
            
            
            104,106Intangible
                assets
            
            
            29,650Goodwill
            
            
            61,136Total
                assets acquired
            
            
            200,976Accounts
                payable and accrued liabilities
            
            
            (4,970
            )Total
                liabilities assumed
            
            
            (4,970
            )Net
                assets acquired
            
            $
            196,006





The
      purchase price allocation for Elk City and NOARK are based upon preliminary
      data
      that is subject to adjustment and could change significantly as Atlas Pipeline
      continues to evaluate these allocations. Atlas Pipeline recognized goodwill
      in
      connection with these acquisitions as a result of Elk City’s and NOARK’s
      significant cash flow and its strategic industry position. All of the intangible
      assets, which consist of customer contracts and relations, are subject to
      amortization and have a weighted-average useful life of 8 to 20 years. The
      goodwill is assigned to the natural gas and liquids segment and is expected
      to
      be deductible for tax purposes. The results of these acquisitions are included
      within the consolidated financial statements from their date of
      acquisition.





The
      following data presents unaudited pro forma revenues, net income and basic
      and
      diluted net income per share of common stock for the Company as if the
      acquisitions discussed above, Atlas Pipeline's equity offerings in June and
      November 2005, the net proceeds of which were utilized to repay debt borrowed
      to
      finance the acquisitions (see Note 13) and the debt offering in December 2005,
      had occurred on October 1, 2004. The Company has prepared these pro forma
      financial results for comparative purposes only. These pro forma financial
      results may not be indicative of the results that would have occurred if Atlas
      Pipeline had completed these acquisitions at October 1, 2004 or the results
      that
      will be attained in the future. The pro-forma financial information for the
      three months ended December 31, 2005, is immaterial and therefore has not been
      presented (shown in thousands except per share amounts):





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





25





**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**


**December
      31, 2005**


(Unaudited)








**NOTE
      13** **- ATLAS PIPELINE EQUITY OFFERING**





In
      November 2005, Atlas Pipeline sold 2.7 million common units, plus 330,000 common
      units in December 2005 pursuant to an option exercised by the underwriters.
      The
      sale of the units resulted in net proceeds of $123.7 million, including a $2.7
      million contribution from the Company as general partner and after deducting
      underwriting discounts, commissions and estimated offering expenses of $6.4
      million. Atlas Pipeline used the net proceeds of the offering to repay a portion
      of the amounts outstanding under its credit facility. The Company’s interest in
      Atlas Pipeline decreased to 14.8% as a result of this offering.





**NOTE
      1** **4
      - REPURCHASE OF COMMON SHARES**





In
      November 2005, the Company announced that its Board of Directors authorized
      a
      repurchase program through which the Company may repurchase up to $50.0 million
      of its common stock. Repurchases may be made from time to time through open
      market purchases or privately negotiated transactions at the discretion of
      the
      Company and in accordance with the rules of the Securities and Exchange
      Commission, as applicable. The amount and timing of any repurchases will depend
      on market and other relevant conditions. The Company repurchased 1,335 shares
      at
      a cost of $73,000 through December 31, 2005.




**NOTE
      1** **5
      - SUBSEQUENT EVENTS**




In
      January 2006, the Company's wholly-owned subsidiary, Atlas Pipeline
      Holdings, L.P. ("AP Holdings"), filed a registration statement with the
      Securities and Exchange Commission for an initial public offering of 3,600,000
      common units, representing an approximate 17.1% limited partner interest in
      it.
      Upon completion of this offering, AP Holdings will own the general partner
      interest, all of the incentive distribution rights and an approximate 12.8%
      limited partner interest in Atlas Pipeline. This public offering is expected
      to
      generate proceeds of as much as $103.0 million.




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





26








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




**When
      used in this Form 10-Q, the words “believes” “anticipates,” “expects” and
      similar expressions are intended to identify forward-looking statements. 
Such statements are subject to certain risks and uncertainties more particularly
      described in Item 1A, under the caption “Risk Factors”, in our annual report on
      Form 10-K for fiscal 2005.  These risks and uncertainties could cause
      actual results to differ materially.  Readers are cautioned not to place
      undue reliance on these forward-looking statements, which speak only as of
      the
      date hereof.  We undertake no obligation to publicly release the results of
      any revisions to forward-looking statements which we may make to reflect events
      or circumstances after the date of this Form 10-Q or to reflect the occurrence
      of unanticipated events.**




***General***





During
      the three months ended December 31,  2005,
      we
      continued to grow our operations, increasing our total assets, revenues, number
      of wells drilled and number of wells operated.





Our
      gross
      revenues depend, to a significant extent, on the price of natural gas and oil,
      which can fluctuate significantly.  We seek to balance this volatility with
      the more stable net income from our well drilling and well servicing operations
      which are principally fee-based.  Our business strategy for increasing our
      reserve base includes acquisitions of undeveloped properties or companies with
      significant amounts of undeveloped property.  At December 31,  2005,
      we
      had $58.5 million available under our credit facility, which could be employed
      to finance such acquisitions.





***Spin-off
      by Resource America***





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





***Recent
      Developments***




The Company





On January
        12, 2006, our subsidiary, Atlas Pipeline Holdings, L.P. (“Atlas Holdings”),
        filed a registration statement with the Securities and Exchange Commission
        for
        an initial public offering of 3.6 million common units, representing an
        approximate 17% limited partner interest in it. Upon completion of this
        offering, Atlas Holdings will own the general partner interest, all of the
        incentive distribution rights and an approximate 12.8% limited partner interest
        in Atlas Pipeline.
  On
        February 6, 2006, our Board of Directors approved a three-for-two stock split
        to
        be effected in the form of a stock dividend. Shareholders of record as of
        February 28, 2006, will receive one additional share of common stock for
        each
        two shares of common stock they own on that date. The shares will be distributed
        on or about March 10, 2006. As of February 6, 2006, there were approximately
        13.3 million shares of our common stock issued and outstanding. After the
        split,
        there will be approximately 20.0 million shares of our common stock outstanding.
        We expect the adjusted number of shares outstanding and adjusted per-share
        stock
        price to be reported by the Nasdaq Stock Market, effective March 10,
        2006.


Atlas
      Pipeline





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





27










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




In December 2005, the Atlas Pipeline and its subsidiary, Atlas Pipeline Finance
      Corp., issued $250.0 million of 10-year, 8.125% senior unsecured notes, or
      Senior Notes in a private placement transaction pursuant to Rule 144A and
      Regulation S under the Securities Act of 1933 for net proceeds of approximately
      $243.1 million, after underwriting commissions and other transaction costs.
      Interest on the Senior Notes is payable semi-annually in arrears on June 25
      and
      December 25, commencing on June 15, 2006. The Senior Notes are redeemable at
      any
      time on or after December 25, 2010 at certain redemption prices, together with
      accrued an unpaid interest to the date of redemption. The Senior Notes are
      also
      redeemable at any time prior to December 15, 2010 at a make-whole redemption
      price. In addition, prior to December 25, 2008, Atlas Pipeline may redeem up
      to
      35% of the aggregate principal amount of the Senior Notes with the proceeds
      of
      certain equity offerings at a stated redemption price. The Senior Notes are
      also
      subject to repurchase by Atlas Pipeline at a price equal to 101% of their
      principal amount, plus accrued and unpaid interest upon a change of control
      or
      upon certain asset sales with which the net proceeds are not reinvested into
      Atlas Pipeline. The Senior Notes are junior in right of payment to the Atlas
      Pipeline secured debt, including Atlas Pipeline’s obligations under is credit
      facility. Atlas Pipeline utilized the net proceeds principally to repay
      indebtedness under its credit facility.




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





***Well
      Drilling***





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





**Three
                Months Ended****December
                31,****2005**
            
            **2004**Average
                drilling revenue per well
            
            $
            225
            
            $
            224Average
                drilling cost per well
            
            
            196
            
            
            195Average
                drilling gross profit per well
            
            $
            29
            
            $
            29Gross
                profit margin
            
            $
            5,497
            
            $
            3,985Gross
                margin percent
            
            
            13
            %
            
            13
            %Net
                wells drilled
            
            
            187
            
            
            136








28








Our
      well
      drilling gross margin was $5.5 million in the three months ended December 31,  2005,
      an
      increase of $1.5 million from $4.0 million in the three months ended December
      31, 2004.  During the three months ended December 31,  2005,
      the
      increase in gross margin was attributable to an increase in the number of wells
      drilled ($1.5 million) and an increase in the gross profit per well ($13,000).
      Since our drilling contracts are on a “cost plus” basis (typically cost plus
      15%), an increase in our average cost per well also results in an increase
      in
      our average revenue per well.  The increase in our average cost per well in
      the three months ended December 31,  2005
      resulted from an increase in the cost of tangible equipment, leases, site
      preparation and reclamation expenses, as well as increased costs due to drilling
      into deeper formations. In addition, it should be noted that “Liabilities
      associated with drilling contracts” on our balance sheet includes $59.0 million
      of funds raised in our drilling investment programs in calendar 2005 that have
      not been applied to drill wells as of December 31,  2005
      due
      to the timing of drilling operations, and thus had not been recognized as well
      drilling revenue.  We expect to recognize this amount as revenue in the
      remainder of fiscal 2006. We completed our fundraising for calendar 2005 in
      November 2005 with a total of $52.1 million raised bringing the total for the
      calendar year to $113.7 million. We anticipate higher oil and gas prices will
      continue to favorably impact our fundraising and therefore our drilling revenues
      in fiscal 2006.





***Gas
      and Oil
      Production***


******


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





**Three
                Months Ended****December
                31,****2005**
            
            **2004**Production
                revenues (in thousands):Gas(1)
            
            $
            21,851
            
            $
            12,697Oil
            
            $
            2,227
            
            $
            1,942Production
                volume:Gas (mcf/day)(1)
                (3)
            
            
            21,468
            
            
            20,286Oil (bbls/day)
            
            
            431
            
            
            447Total (mcfe/day)(3)
            
            
            24,054
            
            
            22,968Average
                sales prices:Gas (per mcf)(3)
            
            $
            11.06
            
            $
            6.80Oil (per bbl)(3)
            
            $
            56.13
            
            $
            47.17Production
                costs(2):As a percent of production revenues
            
            
            10
            %
            
            12
            %Per
                mcfe(3)
            
            $
            1.10
            
            $
            .83Depletion
                per mcfe(3)
            
            $
            2.01
            
            $
            1.28





(1)
            
            Excludes
                sales to landowners.(2)
            
            Production
                costs include labor to operate the wells and related equipment, repairs
                and maintenance, materials and supplies, property taxes, severance
                taxes,
                insurance, gathering charges and production overhead.(3)
            
            “Mcf”
                and “mmcf” means thousand cubic feet and million cubic feet; “mcfe” and
                “mmcfe” means thousand cubic feet equivalent and million cubic feet
                equivalent, and “bbls” means barrels.  Bbls are converted to mcfe
                using the ratio of six mcfs to one
                bbl.








29











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




The
        increase in our gas production volumes resulted from new wells drilled for
        our
        investment partnerships. We believe that gas volumes will be favorably impacted
        in the remainder of fiscal 2006 as ongoing projects to extend and enhance
        our
        gathering systems in the Appalachian Basin are completed and wells drilled
        are
        connected in these areas of expansion.


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





Our
      production costs were $2.4 million in the three months ended December
      31,  2005,
      an
      increase of $691,000 (40%) from $1.7 million in the three months ended December
      31,  2004. 
      These increases include an increase in pumping labor and an increase in
      transportation expenses associated with increased production volumes and natural
      gas sales prices, as a portion of our wells are charged transportation based
      on
      the sales price of the gas transported. The decrease in production costs as
      a
      percent of production revenues in the three months ended December 31, 2005
      as
      compared to December 31, 2004 was an increase in our average sales price which
      more than offset the slight increase in production costs per mcfe.





***Transmission,
      Gathering and Processing***





Our
      transmission, gathering and processing revenues and related expenses for the
      three months ended December 31,  2005
      increased significantly from the prior year periods due to Atlas Pipeline’s
      acquisitions of Elk City on April 15, 2005 and NOARK on October 31,
      2005.





Our
      revenues increased $85.7 million (196%) to $129.5 million for the three months
      ended December 31, 2005 from $43.8 million for the three months ended December
      31,  2004,
      primarily
      due to contributions from Elk City & NOARK and an increase in commodity
      prices.




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





***Well
      Services***





Our
      well
      services revenues were $2.6 million in the three months ended December 31,
      2005,
      an increase of $312,000 (14%) from $2.2 million in the three months ended
      December 31, 2004. The increases resulted from an increase in the number of
      wells operated for our investment partnerships due to additional wells drilled
      in the twelve months ended December 31, 2005.





30








Our
      well
      services expenses were $1.5 million in the three months ended December
      31,  2005,
      an
      increase of $295,000 (25%) from $1.2 million in the three months ended December
      31,  2004. 
      The increases were attributable to an increase in wages, benefits, and field
      office expenses associated with an increase in employees due to the increase
      in
      the number of wells we operate for our investment partnerships.





***Other
      Income, Costs and Expenses***





Our
      general and administrative expenses were $8.0 million in the three months ended
      December 31, 2005, an increase of $6.3 million from $1.7 million in the three
      months ended December 31, 2004. These expenses include, among other things,
      salaries and benefits not allocated to a specific energy activity, costs of
      running our energy corporate office, partnership syndication activities and
      outside services. These expenses are partially offset by reimbursements we
      receive from our drilling investment partnerships.





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





•
            
            general
                and administrative expenses related to Atlas Pipeline’s Mid-Continent
                operations were $1.7 million, an increase of $1.1 million primarily
                attributable to costs associated with operations of Elk City acquired
                in
                April 2005 and NOARK acquired in October 2005,•
            
            net
                syndication costs increased $1.1 million as we continue to expand
                our
                syndication activities and the drilling funds we raise in our public
                and
                private partnerships,•
            
            general
                and administrative expense reimbursements from our investment partnerships
                decreased by $1.1 million as prior year amounts were reduced by
                reimbursements from our drilling partnerships which are now included
                in
                revenue in accordance with a change in our drilling
                agreements,•
            
            salaries
                and wages increased $969,000 due to an increase in executive salaries
                and
                the in the number of employees as a result of our spin-off from
                RAI,•
            
            professional
                and legal fees increased $905,000 primarily due to higher audit fees
                and
                implementation of Sarbanes-Oxley Section 404
                compliance,•
            
            costs
                associated with Atlas Pipeline’s long term incentive plan were $939,000,
                an increase of $580,000 over the three months ended December
                2004,•
            
            expense
                recognized in connection with our non-cash stock compensation was
                $266,000; there were no such expenses in the prior year similar period;
                and•
            
            directors’
                fees increased $263,000 as a result of our spin-off from
                RAI.







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





31










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




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




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





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





Because
      we control the operations of Atlas Pipeline, we include it in our consolidated
      financial statements and show the ownership by the public as a minority
      interest.  The minority interest in Atlas Pipeline’s earnings was $6.7
      million for the three months ended December 31,  2005,
      as
      compared to $7.2 million for the three months ended December 31,  2004,
      a
      decrease of $500,000. The decrease in 2005 is due to Atlas Pipeline’s
      arbitration settlement with SEMCO Energy, Inc., resulting in net income of
      $4.4
      million in 2004 partially offset by an increase in the percentage interest
      of
      public unit holders and an increase in Atlas Pipeline’s net income, as discussed
      above.





Our
      effective tax rate increased to 37% for the three months ended December
      31,  2005
      as
      compared to 36% for the three months ended December 31,  2004
      as a
      result of a reduction in statutory depletion benefits relative to increased
      net
      income.





**Liquidity
      and Capital Resources**





*General.* We
      fund our exploration and production operations with a combination of cash
      generated by operations, capital raised through drilling investment partnerships
      and, if required, use of our credit facility.  We fund
      our transmission, gathering and processing operations, which are conducted
      through Atlas Pipeline, through a combination of cash generated by operations,
      Atlas Pipeline’s credit facility and the sale of Atlas Pipeline’s common
      units.  The following table sets forth our sources and uses of cash (in
      thousands):





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








32








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





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





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





*Cash
      flows from operating activities* . **** Cash
      provided by operations is an important source of short-term liquidity for
      us.  It is directly affected by changes in the price of natural gas and
      oil, interest rates and our ability to raise funds from our drilling investment
      partnerships.  Net ** cash
      provided by operating activities increased $5.8 million in the three months
      ended December 31, 2005 to $59.2 million from $53.4 million in the three months
      ended December 31, 2004, substantially as a result of the following:




•
              
              An
                  increase in net income before depreciation and amortization of
                  $7.5
                  million in the three months ended December 31, 2005 as compared
                  to the
                  prior year period, principally as a result of income included in
                  our
                  financial statements from our acquisitions, higher natural gas
                  and oil
                  prices and drilling profits;•
              
              An
                  increase in non-cash items of $250,000 related to losses on Atlas
                  Pipeline’s hedge value and compensation expense resulting from grants
                  under long-term incentive plans.•
              
              Changes
                  in operating assets and liabilities decreased operating cash flow
                  by $1.9
                  million in the three months ended December 31, 2005, compared to
                  the three
                  months ended December 31, 2004, primarily due to increases during
                  the
                  three months ended December 31, 2005 in accounts receivable related
                  to our
                  Mid-Continent operations partially offset by an increase in accounts
                  payable and accrued liabilities as compared to December 31, 2004.
                  Our
                  level of liabilities associated with drilling contracts is dependent
                  upon
                  the remaining amount of our drilling obligations at any balance
                  sheet
                  date, which is dependent upon the timing of funds raised through
                  our
                  investment partnerships.



















33








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





•
            
            Cash
                used in Atlas Pipeline’s acquisition of NOARK was $163.6 million; and•
            
            Capital
                expenditures increased $14.9 million due to an increase in the number
                of
                wells we drilled and expenditures related to Atlas Pipeline’s gathering
                system extensions.


******


*Cash
      flows from financing activities.* Cash
      provided by our financing activities increased $209.0 million in the three
      months ended December 31, 2005 to $172.7 million from cash used of $36.3 million
      in the three months ended December 31, 2004, as a result of the following:





•
            
            Payments
                to RAI primarily related to our share of income taxes included in
                RAI’s
                income tax return decreased by $9.3 million in the three months ended
                December 31, 2005, there was no such payment made in the three months
                ended December 2005, as a result of our spin-off from
                RAI;•
            
            Net
                borrowings on debt increased by $83.6 million in the three months
                ended
                December 31, 2005 as compared to the prior year similar period principally
                as a result of the issuance of Atlas Pipeline’s Senior Notes partially
                offset by payments on borrowings associated with the acquisition
                of NOARK;
                and•
            
            We
                received proceeds of $121.0 million from Atlas Pipeline’s November 2005
                public offering. There was no such offering in the first quarter
                of fiscal
                2005.





These
      increases were partially offset by the following:





•
            
            Distributions
                paid to minority interests increased $2.5 million as a result of
                higher
                earnings and more common units outstanding for Atlas Pipeline as
                a result
                of its fiscal 2004 and 2005 offerings of common units; and•
            
            An
                increase in other assets of $2.5 million related to financing costs
                associated with Atlas Pipeline’s new senior
                notes.





*Capital
      Requirements:* During
      the three months ended December 31, 2005, our capital expenditures related
      primarily to investments in our drilling partnerships and pipeline expansions,
      in which we invested $15.2 million and $16.6 million, respectively.  For
      the three months ended December 31, 2005 and the remaining quarters of fiscal
      2006, we funded and expect to continue to fund these capital expenditures
      through cash on hand, borrowings under our credit facilities, and from
      operations.  We have established two credit facilities to fund our capital
      expenditures.





The
      level
      of capital expenditures we must devote to our exploration and production
      operations depends upon the level of funds raised through our drilling
      investment partnerships.  We have budgeted to raise up to $200.0 million in
      fiscal 2006 through drilling partnerships.  Through the three months ended
      December 31, 2005 we had raised $52.1 million.  We believe cash flows from
      operations and amounts available under our credit facility will be adequate
      to
      fund our contributions to these partnerships.  However, the amount of funds
      we raise and the level of our capital expenditures will vary in the future
      depending on market conditions for natural gas and other factors.





34








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





**Contractual
      Obligations and Commercial Commitments**





The
      following table summarizes our contractual obligations at December 31, 2005.





Payments
                Due By Period(in
                thousands)Less
                than
            
            2
                -
                3
            
            4
                -
                5
            
            After
                5Contractual
                cash obligations:
            
            Total
            
            1
                Year
            
            Years
            
            Years
            
            YearsLong-term
                debt(1)
            
            $
            298,781
            
            $
            1,351
            
            $
            2,530
            
            $
            11,900
            
            $
            283,000Secured
                revolving creditfacilities
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Operating
                lease obligations
            
            
            4,761
            
            
            1,978
            
            
            2,149
            
            
            632
            
            
            2Capital
                lease obligations
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Unconditional
                purchaseobligations
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Other
              long-term obligation
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Total
                contractual cashobligations
            
            $
            302,542
            
            $
            3,329
            
            $
            4,679
            
            $
            12,532
            
            $
            283,002





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





Payments
                Due By Period(in
                thousands)Less
                than
            
            1
                -
                3
            
            4
                -
                5
            
            After
                5Other
                commercial commitments:
            
            Total
            
            1
                Year
            
            Years
            
            Years
            
            YearsStandby
                letters of credit
            
            $
            27,525
            
            $
            27,500
            
            $
            25
            
            $
            -
            
            $
            -Guarantees
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Standby
                replacement commitments
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Other
                commercial commitments
            
            
            18,955
            
            
            18,955
            
            
            -
            
            
            -
            
            
            -Total
                commercial commitments
            
            $
            46,480
            
            $
            46,455
            
            $
            25
            
            $
            -
            
            $
            -








35




**Critical
      Accounting Policies**





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





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





**Recently
      Issued Financial Accounting Standards**




In
      December 2004, the FASB issued SFAS
      No. 123R, *Share-Based
      Payment*(“SFAS
      No. 123R”). SFAS No. 123R is a revision of SFAS No. 123,*Accounting
      for Stock-Based Compensation*(“SFAS
      No. 123”), and supersedes Accounting Principles Board Opinion No. 25,*Accounting
      for Stock Issued to Employees*(“APB
      No. 25”), and its related implementation guidance. On October 1, 2005,
      the Company adopted the provisions of SFAS No. 123R using the modified
      prospective method. SFAS No. 123R focuses primarily on accounting for
      transactions in which an entity obtains employee services in share-based payment
      transactions. The Statement requires entities to recognize compensation expense
      for awards of equity instruments to employees based on the grant-date fair
      value
      of those awards (with limited exceptions). SFAS No. 123R also requires the
      benefits of tax deductions in excess of recognized compensation expense to
      be
      reported as a financing cash flow, rather than as an operating cash flow as
      prescribed under the prior accounting rules. This requirement reduces net
      operating cash flows and increases net financing cash flows in periods after
      adoption. Total cash flow remains unchanged from what would have been reported
      under prior accounting rules. For the three months ended December 31, 2005,
      the
      Company recorded compensation expense of $168,000, net of taxes of $98,000.
      At
      December 31, 2005, the Company had unamortized compensation expense of $3.7
      million. There were no options granted or exercised in either of the three
      month
      periods ended December 31, 2005 and 2004.




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





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





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





36





**Item
      3.**  **Quantitative
      and Qualitative Disclosures about Market Risk**





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





**General**





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





The
      following analysis presents the effect on our earnings, cash flows and financial
      position as if the hypothetical changes in market risk factors occurred on
      December 31, 2005.  Only the potential impacts of hypothetical assumptions
      are analyzed.  The analysis does not consider other possible effects that
      could impact our business.





*Interest
      Rate Risk.* At
      December 31, 2005, the amount outstanding under our credit facility was $0
      from
      $8.0 million at September 30, 2005.  The weighted average interest rate for
      this facility was 6.1% at September 30, 2005.





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





*Commodity
      Price Risk*.  Our major market risk exposure in commodities is
      fluctuations in the pricing of our gas and oil production.  Realized
      pricing is primarily driven by the prevailing worldwide prices for crude oil
      and
      spot market prices applicable to United States natural gas production. 
Pricing for gas and oil production has been volatile and unpredictable for
      many
      years.  To limit our exposure to changing natural gas prices, we use
      hedges.  Through our hedges, we seek to provide a measure of stability in
      the volatile environment of natural gas prices.  These transactions are
      similar to NYMEX-based futures contracts, swaps and options, but also require
      firm delivery of the hedged quantity.  Thus, we limit these arrangements to
      much smaller quantities than those projected to be available at any delivery
      point.  For the twelve month period ending December 31, 2006, we
      estimate approximately 63% of our produced natural gas volumes will be sold
      in
      this manner, leaving our remaining production to be sold at contract prices
      in
      the month produced or at spot market prices.  We also negotiate with
      certain purchasers for delivery of a portion of natural gas we will produce
      for
      the upcoming twelve months.  The prices under most of our gas sales
      contracts are negotiated on an annual basis and are index-based. Our risk
      management objective is to lock in a range of pricing for expected production
      volumes.





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





37








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





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





Atlas
      Pipeline also enters into certain financial swap and option instruments that
      are
      classified as cash flow hedges in accordance with SFAS No. 133, *Accounting for Derivative Instruments and Hedging Activity* .
      Atlas
      Pipeline enters into these instruments to hedge its forecasted natural gas,
      NGLs
      and condensate sales against the variability in expected future cash flows
      attributable to changes in market prices. The swap instruments are contractual
      agreements between counterparties to exchange obligations of money as the
      underlying natural gas, NGLs and condensate is sold. Under these swap
      agreements, Atlas Pipeline receives a fixed price and pays a floating price
      based on certain indices for the relevant contract period.





Atlas
      Pipeline formally documents all relationships between hedging instruments and
      the items being hedged, including the risk management objective and strategy
      for
      undertaking the hedging transactions. This includes matching the natural gas
      futures and options contracts to the forecasted transactions. Atlas Pipeline
      assesses both at the inception of the hedge and on an ongoing basis, whether
      the
      derivatives are effective in offsetting changes in the forecasted cash flow
      of
      hedged items. If Atlas Pipeline determines that a derivative is not effective
      as
      a hedge or that it has ceased to be an effective hedge due to the loss of
      correlation between the hedging instrument and the underlying commodity, Atlas
      Pipeline will discontinue hedge accounting for the derivative and subsequent
      changes in fair value for the derivative will be recognized immediately into
      earnings.





38





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




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





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





**Natural
      Gas Liquids Fixed - Price Swaps**


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


**Natural
      Gas Fixed - Price Swaps** **(4)**


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


**Natural
      Gas Fixed - Price Swaps**(4**)**


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








39





**Natural
      Gas Basis Swaps**


Production
            
            
            
            Average
            
            Fair
                ValuePeriod
            
            Volumes
            
            Fixed
                Price
            
            Asset(3)Ended
                December 31,
            
            (MMBTU)(1)
            
            (per
                MMBTU)
            
            (in
                thousands)2006
            
            
            1,200,000
            
            $
            -0.551
            
            $
            3,9162007
            
            
            1,080,000
            
            
            -0.535
            
            
            3,5812008
            
            
            240,000
            
            
            -0.555
            
            
            808$
            8,305


**Fixed
      Price Purchase - Price Swaps**


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


**Fixed
      Price Purchase Basis Swaps**


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


**Plant
      Volume Reduction Fixed - Price Swaps**


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


**Plant
      Volume Reduction Basis Swaps**


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


**Crude
      Oil Fixed - Price Swaps**


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





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








40








**Item
      4.**  **Controls
      and Procedures**





As
      indicated in the certifications in Exhibit 31 of this report, the Company’s
      principal executive officer and principal financial officer have evaluated
      the
      Company’s disclosure controls and procedures as of December 31, 2005. Based on
      that evaluation, these officers have concluded that the Company’s disclosure
      controls and procedures are effective in ensuring that material information
      required to be in this quarterly report is made known to them on a timely basis.
      There were no changes during the Company’s last fiscal quarter that materially
      affected, or are reasonably likely to materially affect, the Company’s internal
      control over financial reporting.





**PART
      II.  OTHER INFORMATION**





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





**Shares
                Purchased As**
            
            **Maximum
                Number of****Part
                of Publicly**
            
            **Shares
                that May Yet****Total
                Number of**
            
            **Average
                Price paid**
            
            **Announced
                Plans or**
            
            **Be
                Purchased Under****Shares
                Purchased**
            
            **per
                Share**
            
            **Programs**
            
            **the
                Plans or Programs**October
                1-31, 2005
            
            
            **-**
            
            
            **-**
            
            
            **-**November
                1-30, 2005
            
            
            **-**
            
            
            **-**
            
            
            **-**December
                1-31, 2005
            
            
            1,335
            
            $
            54.67
            
            
            1,335Total
            
            
            1,335
            
            $
            54.67
            
            
            1,335
            
            
            See
                Note 1





Note
      1:
      In November 2005, the Company announced that its Board of Directors authorized
      a
      repurchase program through which the Company may repurchase up to $50.0 million
      of its common stock. Repurchases may be made from time to time through open
      market purchases or privately negotiated transactions at the discretion of
      the
      Company and in accordance with the rules of the Securities and Exchange
      Commission, as applicable. The amount and timing of any repurchases will depend
      on market and other relevant conditions. Purchases may be increased, decreased,
      or discontinued at any time without prior notice. Shares of stock repurchased
      under the plan are held as treasury shares.





41





**Item
      5.**  **Other
      Information**





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





**Item
      6.**  **Exhibits**




Exhibit
      No.  Description


3.2
              Amendments
                  to Bylaws(1)10.3
              Revolving
                  Credit and Term Loan Agreement dated as of April 14, 2005 among
                  Atlas
                  Pipeline Partners, L.P.,  Wachovia Bank, National Association, and
                  the other parties named therein10.3(a)
              First
                  Amendment to Revolving Credit and Term Loan Agreement dated as
                  of October
                  31, 200510.4
              Amendment
                  dated October 25, 2005 among Atlas America, Inc., Atlas Pipeline
                  Partners,
                  L.P., Atlas Pipeline Operating Partnership;, L.P., Resource Energy,
                  Inc., Viking Resources Corporation, Atlas Noble Corp. and Atlas
                  Resources,
                  Inc.10.5
              Atlas
                  Pipeline Partners, L.P. Indenture dated December 20,
                  200510.6
              Atlas
                  Pipeline Partners, L.P. Registration Rights Agreement dated December
                  20,
                  200510.14
              Form
                  of Stock Award Agreement10.15
              Stock
                  Purchase Agreement dated September 21, 200531.1
              Rule
                  13(a)-14(a)/15d-14(a) Certification.31.2
              Rule
                  13(a)-14(a)/15d-14(a) Certification.32.1
              Section
                  1350 Certification.32.2
              Section
                  1350 Certification.






(1)
            Previously
                filed as an exhibit to our Form 10Q for the quarter ended March
                31, 2004.





42










**SIGNATURES**





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





**ATLAS
                AMERICA, INC.****(Registrant)**Date: 
                February 9, 2006
            By:*/s/
                Matthew A. Jones*Matthew
                A. JonesExecutive
                Vice President and Chief Financial OfficerDate: February
                9, 2006
            By:     
              /s/*Nancy J. McGurk*Nancy
                J. McGurkSenior
                Vice President and Chief Accounting Officer










43