**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 September 30, 2007





**OR**





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




For
      the transition period from _________ to __________





Commission
      file number: **001-32169**




**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.)**Westpointe
                Corporate Center****1550
                Coraopolis Heights Rd, 2****nd****FL**
              **Moon
                Township, PA**
            **15108**(Address
                of principal executive offices)
            (Zip
                code)





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





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





Indicate
      by check mark whether the registrant is 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 x
      Accelerated filer   o Non-accelerated filer o





Indicate
      by check mark whether the registrant is a shell company (as defined in Rule
      12b-2 of the Exchange Act).


Yes o No x





The
      number of outstanding shares of the registrant’s common stock on November 1,
      2007 was 26.9 million shares.










**ATLAS
      AMERICA, INC.**


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





**Page****PART
                I**
            **FINANCIAL
                INFORMATION**Item
                1.
            Financial
                StatementsConsolidated
                Balance Sheets - September 30, 2007 and December 31, 2006
            3Consolidated
                Statements of Income for the Three Months and Nine Months Ended September
                30, 2007 and 2006
            4Consolidated
                Statement of Changes in Stockholders’ Equity for the Nine Months Ended
                September 30, 2007
            5Consolidated
                Statements of Cash Flows for the Nine Months Ended September 30,
                2007 and
                2006
            6Notes
                to Consolidated Financial Statements
            7
                - 29Item
                2.
            Management’s
                Discussion and Analysis of Financial Condition and Results of
                Operations
            30-
                41Item
                3.
            Quantitative
                and Qualitative Disclosures about Market Risk
            42-
                46Item
                4.
            Controls
                and Procedures
            47**PART
                II**
            **OTHER
                INFORMATION**Item
                6.
            Exhibits
            48**SIGNATURES**
            49











**PART
      I. FINANCIAL INFORMATION**





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


**ATLAS
      AMERICA, INC.**


**CONSOLIDATED
      BALANCE SHEETS**


(in
      thousands, except share data)


**September
                30,**
            
            **December
                31,****2007**
            
            **2006**(Unaudited)
            
            (Audited)**ASSETS**Current
                assets:Cash
                and cash equivalents
            
            $
            113,812
            
            $
            185,401Accounts
                receivable
            
            
            169,841
            
            
            82,954Current
                portion of derivative asset
            
            
            40,385
            
            
            33,150Prepaid
                expenses
            
            
            15,067
            
            
            13,738Deferred
                tax asset
            
            
            10,434
            
            
            7,934Total
                current assets
            
            
            349,539
            
            
            323,177Property
                and equipment, net
            
            
            4,189,603
            
            
            884,812Other
                assets, net
            
            
            74,036
            
            
            42,501Intangible
                assets, net
            
            
            28,728
            
            
            30,741Goodwill,
                net
            
            
            98,607
            
            
            98,607$
            4,740,513
            
            $
            1,379,838**LIABILITIES
                AND STOCKHOLDERS’ EQUITY**Current
                liabilities:Current
                portion of long-term debt
            
            $
            77
            
            $
            109Accounts
                payable
            
            
            75,440
            
            
            56,438Liabilities
                associated with drilling contracts
            
            
            63,090
            
            
            86,765Accrued
                producer liabilities
            
            
            65,121
            
            
            32,766Accrued
                hedge liability
            
            
            55,162
            
            
            17,535Accrued
                liabilities
            
            
            66,715
            
            
            49,035Advances
                from affiliate
            
            
            112
            
            
            117Total
                current liabilities
            
            
            325,717
            
            
            242,765Long-term
                debt
            
            
            1,921,968
            
            
            324,042Deferred
                tax liability
            
            
            199,422
            
            
            82,307Long-term
                hedge liability
            
            
            50,692
            
            
            12,340Other
                liabilities
            
            
            51,197
            
            
            40,656Minority
                interest
            
            
            1,766,011
            
            
            406,387Stockholders’
                equity:Preferred
                stock, $0.01 par value: 1,000,000 authorized shares
            
            
            —
            
            
            —Common
                stock, $0.01 par value: 49,000,000 authorized shares
            
            
            290
            
            
            200Additional
                paid-in capital
            
            
            390,013
            
            
            186,696Treasury
                stock, at cost
            
            
            (109,137
            )
            
            (29,349
            )ESOP
                loan receivable
            
            
            (435
            )
            
            (490
            )Accumulated
                other comprehensive income (loss)
            
            
            4,028
            
            
            8,426Retained
                earnings
            
            
            140,747
            
            
            105,858Total
                stockholders’ equity
            
            
            425,506
            
            
            271,341$
            4,740,513
            
            $
            1,379,838




See
      accompanying notes to consolidated financial statements








3





**ATLAS
      AMERICA, INC.**


**CONSOLIDATED
      STATEMENTS OF INCOME**


(in
      thousands, except per share data)


(Unaudited)





**Three
                Months Ended**
            
            **Nine
                Months Ended****September
                30,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2007**
            
            **2006**(Restated)
            
            
            
            (Restated)**REVENUES**Well
                construction and completion
            
            $
            103,324
            
            $
            50,641
            
            $
            240,841
            
            $
            135,329Gas
                and oil production
            
            
            63,265
            
            
            21,888
            
            
            109,840
            
            
            66,696Transmission,
                gathering and processing
            
            
            246,195
            
            
            111,019
            
            
            480,594
            
            
            326,886Administration
                and oversight
            
            
            5,364
            
            
            2,990
            
            
            13,347
            
            
            8,487Well
                services
            
            
            4,845
            
            
            3,346
            
            
            12,721
            
            
            9,498Gain/
                (loss) on mark-to-market derivatives
            
            
            (11,467
            )
            
            733
            
            
            (16,036
            )
            
            990411,526
            
            
            190,617
            
            
            841,307
            
            
            547,886**COSTS
                AND EXPENSES**Well
                construction and completion
            
            
            89,847
            
            
            44,037
            
            
            209,427
            
            
            117,677Gas
                and oil production
            
            
            9,887
            
            
            2,315
            
            
            14,412
            
            
            6,437Transmission,
                gathering and processing
            
            
            187,416
            
            
            96,205
            
            
            377,740
            
            
            270,981Well
                services
            
            
            2,515
            
            
            1,752
            
            
            6,705
            
            
            5,540General
                and administrative
            
            
            48,923
            
            
            13,159
            
            
            85,229
            
            
            34,238Depreciation,
                depletion and amortization
            
            
            35,187
            
            
            12,442
            
            
            61,064
            
            
            33,158373,775
            
            
            169,910
            
            
            754,577
            
            
            468,031**OPERATING
                INCOME**
            
            
            37,751
            
            
            20,707
            
            
            86,730
            
            
            79,855**OTHER
                INCOME (EXPENSE**)Interest
                expense
            
            
            (37,480
            )
            
            (5,932
            )
            
            (53,681
            )
            
            (19,448
            )Minority
                interests
            
            
            6,402
            
            
            (2,021
            )
            
            14,992
            
            
            (12,987
            )Other,
                net
            
            
            3,526
            
            
            3,518
            
            
            6,425
            
            
            4,643(27,552
            )
            
            (4,435
            )
            
            (32,264
            )
            
            (27,792
            )Income
                before income taxes
            
            
            10,199
            
            
            16,272
            
            
            54,466
            
            
            52,063Provision
                for income taxes
            
            
            (3,096
            )
            
            (6,302
            )
            
            (17,249
            )
            
            (20,632
            )**Net
                income**
            
            $
            7,103
            
            $
            9,970
            
            $
            37,217
            
            $
            31,431**Net
                income per common share–basic**Net
                income per common share–basic
            
            
            .26
            
            
            .34
            
            
            1.36
            
            
            1.06Weighted
                average common shares outstanding-basic
            
            
            26,853
            
            
            29,396
            
            
            27,345
            
            
            29,759**Net
                income per common share–diluted**Net
                income per common share–diluted
            
            $
            .25
            
            $
            .33
            
            $
            1.31
            
            $
            1.03Weighted
                average common shares outstanding–diluted
            
            
            27,979
            
            
            30,000
            
            
            28,348
            
            
            30,409




See
      accompanying notes to consolidated financial statements








4





**ATLAS
      AMERICA, INC.**


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


**NINE
      MONTHS ENDED SEPTEMBER 30, 2007**


(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,
                January 1, 2007**–Restated
            
            
            20,008,419
            
            $
            200
            
            $
            186,696
            
            
            (659,135
            )
            $
            (29,349
            )
            $
            (490
            )
            $
            8,426
            
            $
            105,858
            
            $
            271,341Net
                income
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            37,217
            
            
            37,217Dividends–common
                shares
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            (2,238
            )
            
            (2,238
            )Other
                comprehensive income
              (loss)
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            (4,398
            )
            
            
            
            
            (4,398
            )Issuance
                of common stock
            
            
            56,736
            
            
            —
            
            
            1,113
            
            
            13,942
            
            
            661
            
            
            
            
            
            
            
            
            
            
            
            1,774Repurchase
                of common stock,
              at
                cost
            
            
            
            
            
            
            
            
            
            
            
            (1,486,605
            )
            
            (80,449
            )
            
            
            
            
            
            
            
            
            
            
            (80,449
            )Three-for-two
                stock split
            
            
            8,938,057
            
            
            90
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            (90
            )
            
            —Repayment
                of ESOP loan
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            55
            
            
            
            
            
            
            
            
            55Stock
                option compensation
            
            
            
            
            
            
            
            
            1,308
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            1,308Gain
                on sale of subsidiary units
            
            
            
            
            
            
            
            
            200,896
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            200,896**Balance,
                September 30, 2007**
            
            
            29,003,212
            
            $
            290
            
            $
            390,013
            
            
            (2,131,798
            )
            $
            (109,137
            )
            $
            (435
            )
            $
            4,028
            
            $
            140,747
            
            $
            425,506




See
      accompanying notes to consolidated financial statements








5





**ATLAS
      AMERICA, INC.**


**CONSOLIDATED
      STATEMENTS OF CASH FLOWS**


(in
      thousands)


(Unaudited)




**Nine
                Months Ended****September
                30,****2007**
            
            **2006****CASH
                FLOWS FROM OPERATING ACTIVITIES:**Net
                income
            
            $
            37,217
            
            $
            31,431Adjustments
                to reconcile net income to net cash used in operating
                activities:Depreciation,
                depletion and amortization
            
            
            61,064
            
            
            33,158Amortization
                of deferred finance costs
            
            
            7,626
            
            
            2,008Non-cash
                loss (gain) on derivative value
            
            
            19,501
            
            
            (990
            )Non-cash
                compensation on long-term incentive plans
            
            
            43,506
            
            
            6,312Minority
                interests
            
            
            (14,992
            )
            
            12,987Distributions
                paid to minority interests
            
            
            (32,853
            )
            
            (27,940
            )Gain
                (loss) on asset dispositions
            
            
            119
            
            
            (2,738
            )Deferred
                income taxes
            
            
            (4,145
            )
            
            (37,532
            )Changes
                in operating assets and liabilities (net of acquisition):(Increase)
                decrease in accounts receivable and prepaid expenses
            
            
            (53,273
            )
            
            1,455Increase
                in accounts payable and accrued liabilities
            
            
            30,974
            
            
            29,558(Decrease)
                increase in accounts payable/receivable from affiliates
            
            
            (4
            )
            
            265Changes
                in other operating assets and liabilities
            
            
            645
            
            
            (4,129
            )Net
                cash provided by operating activities
            
            
            95,385
            
            
            43,845**CASH
                FLOWS FROM INVESTING ACTIVITIES:**Investment
                in Lightfoot Capital Partners, L.P
            
            
            (10,379
            )
            
            —Business
                acquisitions, net of cash acquired
            
            
            (3,141,680
            )
            
            (30,000
            )Capital
                expenditures
            
            
            (219,088
            )
            
            (115,819
            )Proceeds
                from sale of assets
            
            
            1,071
            
            
            7,602Decrease
                (increase) in other assets
            
            
            (813
            )
            
            174Net
                cash used in investing activities
            
            
            (3,370,889
            )
            
            (138,043
            )**CASH
                FLOWS FROM FINANCING ACTIVITIES:**Borrowings
            
            
            1,931,509
            
            
            109,750Principal
                payments on debt
            
            
            (345,922
            )
            
            (144,805
            )Issuance
                of Atlas Pipeline Partners, L.P. common and preferred
                units
            
            
            946,555
            
            
            59,610Net
                proceeds from Atlas Energy equity offering
            
            
            597,500
            
            
            —Net
                proceeds from Atlas Pipeline Holdings equity offering
            
            
            167,033
            
            
            74,492Treasury
                shares purchased
            
            
            (80,449
            )
            
            (29,856
            )Issuance
                of Atlas Pipeline Senior notes
            
            
            —
            
            
            36,610Dividends
                paid
            
            
            (2,238
            )
            
            —(Increase)
                in deferred financing costs and other
            
            
            (10,073
            )
            
            (2,066
            )Net
                cash provided by financing activities
            
            
            3,203,915
            
            
            103,735(Decrease)
                increase in cash and cash equivalents
            
            
            (71,589
            )
            
            9,537Cash
                and cash equivalents at beginning of period
            
            
            185,401
            
            
            55,155Cash
                and cash equivalents at end of period
            
            $
            113,812
            
            $
            64,692





See
      accompanying notes to consolidated financial statements





6





**ATLAS
      AMERICA, INC.**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS**


**September
      30, 2007**


(Unaudited)





**NOTE
      1 - BASIS OF PRESENTATION**





**Company
      Overview**




The
      consolidated financial statements include the accounts of Atlas America, Inc.
      (the “Company” or “ATLS”) and its subsidiaries, all of which are wholly owned
      except for Atlas Pipeline Holdings, L.P. (“AHD”), Atlas Pipeline Partners, L.P.
      (“APL or Atlas Pipeline”) and Atlas Energy Resources, LLC (“Atlas
      Energy”).




In
      July
      2006, the Company contributed its ownership interests in Atlas Pipeline Partners
      GP, LLC, its then wholly-owned subsidiary, and the general partner of Atlas
      Pipeline, to AHD. Concurrent with this transaction, AHD issued 3,600,000 common
      units, representing a 17.1% ownership interest in it, in an initial public
      offering. In July 2007, AHD sold 6,250,000 common units through private
      placement and used the net proceeds from the sale to purchase 3,835,227 units
      of
      APL. As a result, AHD, through its ownership of Atlas Pipeline GP, owns a 2%
      general partner interest and 5,476,253 common units constituting a 13.6% limited
      partner interest for a total partnership interest of 15.6% in Atlas Pipeline.
      Because AHD controls the decisions and operations of APL, Atlas Pipeline is
      consolidated in the Company’s financial statements.




In
      December 2006, the Company contributed substantially all of its natural gas
      and
      oil assets and its investment partnership management business to Atlas Energy,
      a
      then wholly-owned subsidiary. Concurrent with this transaction, Atlas Energy
      issued 7,273,750 common units, representing a 19.4% ownership interest, in
      an
      initial public offering. Atlas Energy Management, Inc., a wholly owned
      subsidiary of the Company, is the managing member of Atlas Energy and owns
      1,238,986 Class A units, or a 2% interest which it manages and effectively
      controls Atlas Energy. On June 29, 2007, Atlas Energy completed a private
      placement of 7,298,181 Class B common units and 16,702,828 Class D units to
      a
      group of institutional investors to fund the acquisition of DTE Gas and Oil
      Company (See Note 4). After completion of the offering and private placement,
      the Company owns approximately 49.4% of Atlas Energy.





The
      consolidated financial statements and the information and tables contained
      in
      the notes to the consolidated financial statements as of September 30, 2007
      and
      for the three months and nine months ended September 30, 2007 and 2006 are
      unaudited except that the balance sheet at December 31, 2006 is derived from
      audited financial statements.  Certain information and footnote disclosures
      normally included in financial statements prepared in accordance with accounting
      principles generally accepted in the United States of America have been
      condensed or omitted in these statements pursuant to the rules and regulations
      of the Securities and Exchange Commission.  However, in the opinion of
      management, these interim financial statements include all the necessary
      adjustments to fairly present the results of the interim periods
      presented.  The results of operations for the three months and nine months
      ended September 30, 2007 may not necessarily be indicative of the results of
      operations for the full fiscal year ending December 31, 2007. Certain
      reclassifications have been made to the consolidated financial statements as
      of
      December 31, 2006 and for the three months and nine months ended September
      30,
      2006 to conform to the presentation as of and for the three months and nine
      months ended September 30, 2007.




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





Reference
      is hereby made to the Company's Annual Report on Form 10-K/A for the fiscal
      year
      ended December 31, 2006, 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
      consolidated financial statements as of September 30, 2007 and for the three
      months and nine months ended September 30, 2007 and 2006.





**Use
      of Estimates**




Preparation
      of the financial statements in conformity with accounting principles generally
      accepted in the United States of America requires management to make estimates
      and assumptions that affect the reported amounts of assets and liabilities
      and
      the disclosure of contingent assets and liabilities as of the date of the
      consolidated financial statements and the reported amounts of revenues and
      costs
      and expenses during the reporting period. Actual results could differ from
      these
      estimates.


7





**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited)





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





**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 customers. At September 30, 2007
      and
      December 31, 2006, the Company’s credit evaluation indicated that it has no need
      for an allowance for possible losses.





**Revenue
      Recognition**





Because
      there are timing differences between the delivery of natural gas, natural gas
      liquids (“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 September 30,
      2007
      and December 31, 2006 of $123.0 million and $40.2 million which are included
      in
      accounts receivable on its consolidated balance sheets.




**Restatement**
  The
        Company has restated its beginning balance sheet related to an amendment
        to its
        Form 10-K for the year ended December 31, 2006 for its accounting treatment
        of
        stock sales by its subsidiaries. This restatement decreased Minority Interest
        by
        $188.3 million, increased Deferred Taxes by $79.1 million and increased Paid-in
        Capital by $109.2 million at December 31, 2006 and March 31, 2007. The
        restatement resulted in the reversal of the $29.8 million income
        tax valuation allowance recorded in July 2006 related to the gain on
        sale of AHD’s common units.
  The
          following table reconciles net income and earnings per share as previously
          reported to restated amounts for the three months and nine months ended
          September 30, 2006 (in thousands, except per share data):
 Three
                      Months Ended September 30, 2006PreviouslyReported
                  
                  Adjustment
                  
                  RestatedNet
                      income (loss)
                  
                  $
                  (19,876
                  )
                  $
                  29,846
                  
                  $
                  9,970Net
                      income per common share - basic
                  
                  $
                  (0.68
                  )
                  $
                  1.02
                  
                  $
                  0.34Net
                      income per common share - diluted
                  
                  $
                  (0.66
                  )
                  $
                  0.99
                  
                  $
                  0.33
  Nine
                    Months Ended September 30, 2006PreviouslyReported
                
                Adjustment
                
                RestatedNet
                    income
                
                $
                1,585
                
                $
                29,846
                
                $
                31,431Net
                    income per common share - basic
                
                $
                0.05
                
                $
                1.01
                
                $
                1.06Net
                    income per common share - diluted
                
                $
                0.05
                
                $
                0.98
                
                $
                1.03


**Recently
      Issued Financial Accounting Standards**




In
      April 2007, the Financial Accounting Standards Board ( “FASB”)
      issued FASB interpretation No. 39-1, Amendment of FASB Interpretation No. 39, *Offsetting
      of Amounts Related to Certain Contracts* ,
      (“FIN
      39-1”). FIN 39-1 amends FIN 39, which allows an entity to offset fair value
      amounts for the right to reclaim cash collateral or the obligation to return
      cash collateral against fair value amounts recognized for derivative instruments
      executed with the same counterparty under the same master netting arrangement.
      FIN 39-1 is effective for fiscal years beginning after November 15, 2007. The
      Company does not expect the adoption of FIN 39-1 to have an impact on its
      financial position or results of operations.




In
      February 2007, the FASB issued Statement of Financial Accounting Standards
      No. 159, *The
      Fair Value Option for Financial Assets and Financial
      Liabilities,* (“SFAS
      159”). SFAS 159 permits entities to choose to measure eligible financial
      instruments and certain other items at fair value. The objective is to improve
      financial reporting by providing entities with the opportunity to mitigate
      volatility in reported earnings caused by measuring related assets and
      liabilities differently without having to apply complex hedge accounting
      provisions. The Statement will be effective as of the beginning of an entity’s
      first fiscal year beginning after November 15, 2007. The Statement offers
      various options in electing to apply the provisions of this Statement, and
      at
      this time the Company has not made any decisions on its application to its
      financial position or results of operations.




In
      December 2006, the FASB issued FASB Staff Position (FSP) EITF 00-19-2, *Accounting
      for Registration Payment Arrangements* .
      FSP
      EITF 00-19-2 requires an issuer of financial instruments, such as debt,
      convertible debt, equity shares or warrants, to account for a contingent
      obligation to transfer consideration under a registration payment arrangement
      in
      accordance with Statement 5, *Accounting
      for Contingencies* ,
      and
      FASB Interpretation 14, *Reasonable
      Estimation of the Amount of a Loss* .
      That
      accounting applies regardless of whether the registration payment arrangement
      is
      a provision in a financial instrument or a separate agreement. The FSP requires
      issuers to make certain disclosures for each registration payment arrangement
      or
      group of similar arrangements. The FSP is effective immediately for registration
      payment arrangements and financial instruments subject to those arrangements
      that are entered into or modified subsequent to December 21, 2006, the date
      FSP
      EITF 00-19-2 was issued. The Company applied the consensus in FSP EITF 00-19-2
      effective January 1, 2007. The Company reviewed the penalty terms in the
      registration rights agreement related to AHD's, Atlas Pipline's, and Atlas
      Energy’s respective private placements entered into during the nine months
      ended September 30, 2007, pursuant to the guidance in the FSP, and determined
      that the probability of payment is remote under Statement 5 based upon the
      Company’s status of current related filings. As a result, the application of FSP
      EITF 00-19-2 did not have an effect on the Company’s financial position or
      results of operations.




In
      September 2006, the FASB issued Statement of Financial Accounting Standards
      No. 157, *Fair
      Value Measurement* ,
      (“SFAS
      157”). SFAS 157 addresses the need for increased consistency in fair value
      measurements, defining fair value as the price that would be received to sell
      an
      asset or paid to transfer a liability in an orderly transaction between market
      participants at the measurement date. It also establishes a framework for
      measuring fair value and expands disclosure requirements. SFAS 157 is effective
      for the Company beginning January 1, 2008. The Company is currently
      evaluating the impact of the adoption of SFAS 157 on its financial position
      and
      results of operations.




8





**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited)





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





The
      Company adopted the provisions of FASB Interpretation No. 48, *Accounting
      for Uncertainty in Income Taxes,* (“FIN 48”), on January 1, 2007, and FASB Interpretation No. 48-1, *Definition
      of Settlement in FASB Interpretation No. 48* ,
      (“FIN 48-1”). Previously, the Company had accounted for tax contingencies in
      accordance with Statement of Financial Accounting Standards No. 5, *Accounting
      for Contingencies* . FIN
      48
      clarifies the accounting for income taxes, by prescribing a minimum recognition
      threshold a tax position is required to meet before being recognized in the
      financial statements. FIN 48 also provides guidance on derecognition,
      measurement, classification, interest and penalties, accounting in interim
      periods, disclosure and transition. FIN 48-1 amends FIN 48 to provide guidance
      on how an enterprise should determine whether a tax provision is effectively
      settled for the purpose of recognizing previously unrecognized tax benefits. As
      a result of the implementation of FIN 48 and FIN 48-1, the Company determined
      that it had no liability for unrecognized income tax benefits, upon adoption
      and
      through September 30, 2007.





The
      Company files numerous consolidated and separate income tax returns in the
      United States Federal jurisdiction and in many state jurisdictions. The Company
      is no longer subject to United States Federal income tax examinations for
      periods ending before September 30, 2003 and is no longer subject to state
      and
      local income tax examinations by tax authorities for periods ending before
      September 30, 2002.





The
      Company’s policy is to recognize potential accrued interest and penalties
      related to unrecognized tax benefits in income tax expense.





The
      Company does not anticipate that total unrecognized tax benefits will
      significantly change within the next twelve months.




**Earnings
      Per Share**





Basic
      earnings per share are 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. The following table
      sets
      forth the reconciliation of the Company’s weighted average number of common
      shares at the dates indicated (in thousands):





**Three
                Months Ended**
            
            **Nine
                Months Ended****September
                30,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2007**
            
            **2006**Weighted
                average common shares outstanding-basic(1)
            
            
            26,853
            
            
            29,396
            
            
            27,345
            
            
            29,759Dilutive
                effect of stock option and award plan(1)
            
            
            1,126
            
            
            604
            
            
            1,003
            
            
            650Weighted
                average common shares-diluted(1)
            
            
            27,979
            
            
            30,000
            
            
            28,348
            
            
            30,409





(1)
            The
                shares for the three months and nine months ended September 30, 2006
                have
                been restated to reflect the three-for-two-stock split on May 25,
                2007.








9


**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited)





**NOTE
      3 - COMPREHENSIVE INCOME (LOSS)**





Comprehensive
      income (loss) 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 changes in the
      fair values, net of taxes, of unrealized holding gains and losses on hedging
      contracts and post-retirement plan liabilities. The following table reconciles
      net income to comprehensive income (loss) (in thousands):





**Three
                Months Ended**
            
            **Nine
                Months Ended****September
                30,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2007**
            
            **2006**Net
                income
            
            $
            7,103
            
            $
            9,970
            
            $
            37,217
            
            $
            31,431Other
                comprehensive income:Unrealized
                holding gain (loss) on hedging contracts, net of tax of $(4,948),
                ($5,817), $2,377, and ($8,088)
            
            
            8,424
            
            
            9,873
            
            
            (3,184
            )
            
            13,515Less:
                reclassification adjustment for (gains) losses realized in net
                income, net of tax of $687, ($324), $786, and ($215)
            
            
            (1,170
            )
            
            553
            
            
            (1,339
            )
            
            251Plus:
                amortization of additional post-retirement liability recorded upon
                adoption of SFAS 158, net of taxes of ($27) and ($80)
            
            
            41
            
            
            —
            
            
            125
            
            
            —7,295
            
            
            10,426
            
            
            (4,398
            )
            
            13,766Comprehensive
                income
            
            $
            14,398
            
            $
            20,396
            
            $
            32,819
            
            $
            45,197





Components
      of Accumulated other comprehensive income (loss) at the dates indicated are
      as
      follows (in thousands):





**September
                30,**
              **2007**
            
            **December
                31, 2006**Unrealized
                holding gain on hedging contracts
            
            $
            4,319
            
            $
            8,842Additional
                post-retirement liability
            
            
            (291
            )
            
            (416
            )$
            4,028
            
            $
            8,426





**NOTE
      4 - ACQUISITIONS**




*Anadarko-Chaney
      Dell and Midkiff/Benedum*





On
      July
      27, 2007, APL acquired control of Anadarko’s 100% interest in the Chaney Dell
      natural gas gathering system and processing plants located in Oklahoma and
      its
      72.8% undivided joint venture interest in the Midkiff/Benedum natural gas
      gathering system and processing plants located in Texas (the “Assets”). The
      Chaney Dell System includes 3,470 miles of gathering pipeline and three
      processing plants, while the Midkiff/Benedum System includes 2,500 miles of
      gathering pipeline and two processing plants. The transaction was effected
      by
      the formation of two joint venture companies which own the respective systems,
      to which APL contributed $1.9 billion and Anadarko contributed the
      Assets.





In
      connection with this acquisition, APL has reached an agreement with Pioneer,
      which currently holds a 27.2% undivided joint venture interest in the
      Midkiff/Benedum system, whereby Pioneer will have an option to buy up to an
      additional 14.6% interest in the Midkiff/Benedum system on June 15, 2008, and
      up
      to an additional 7.4% interest on June 15, 2009. If the option is fully
      exercised, Pioneer would increase its interest in the system to approximately
      49.2%. Pioneer would pay approximately $230 million for the additional 22%
      interest if fully exercised. APL will manage and control the Midkiff/Benedum
      system regardless of whether Pioneer exercises the purchase
      options.





10


**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited)





**Note
      4 - ACQUISITIONS (Continued)**





APL
      funded the purchase price in part from the private placement of 25.6 million
      common limited partner units at a negotiated purchase price of $44.00 per unit,
      generating gross proceeds of $1.125 billion. AHD purchased 3.8 million of the
      25.6 million common limited partner units issued by Atlas Pipeline for $168.8
      million and funded this through the private **** placement
      of 6.25 million of its common units to investors at a negotiated price of $27.00
      per unit, yielding gross proceeds of $168.8 million (or net proceeds of $167.0
      million, after underwriting fees and other transaction costs). Atlas Pipeline
      also received a capital contribution from AHD of $23.1 million in order for
      AHD
      to maintain its 2.0% general partner interest in Atlas Pipeline. AHD funded
      this
      capital contribution and the underwriting fees and other transaction costs
      related to its private placement of common units through borrowings under its
      revolving credit facility of $25.0 million (see Note 8). AHD, which holds all
      of
      the incentive distribution rights as General Partner, has also agreed to
      allocate up to $5.0 million of its incentive distribution rights per quarter
      back to APL through the quarter ended June 30, 2009, and up to $3.75 million
      per
      quarter thereafter (see Note 14). APL funded the remaining purchase price from
      an $830.0 million senior secured term loan which matures in July 2014 and a
      new
      $300.0 million senior secured revolving credit facility that matures in July
      2013 (see Note 8). APL’s acquisition was accounted for using the purchase method
      of accounting under SFAS No. 141, “Business Combinations” (“SFAS No. 141”). The
      following table presents the preliminary purchase price allocation, including
      professional fees and other related acquisition costs, to the assets acquired
      and liabilities assumed in the acquisition, based on their fair values at the
      date of the acquisition (in thousands):





Prepaid
                expenses and other
            
            $
            1,254Property,
                plant and equipment
            
            
            1,879,581Total
                assets acquired
            
            
            1,880,835Accounts
                payable and accrued liabilities
            
            
            (2,209
            )Net
                cash paid for acquisition
            
            $
            1,878,626





Due
      to
      the recent date of the acquisition, the purchase price allocation for the
      acquisition is based upon preliminary data that remains subject to adjustment
      and could further change significantly as APL continues to evaluate this
      allocation. The results of Chaney Dell’s and Midkiff/Benedum’s operations are
      included within the Partnership’s consolidated financial statements from the
      date of acquisition.





*DTE
      Gas and Oil Company (DGO)*





On
      June
      29, 2007, Atlas Energy acquired all of the outstanding equity interests of
      DTE
      Gas & Oil Company (“DGO”) from DTE Energy Company (NYSE:DTE) and MCN Energy
      Enterprises for $1.268 billion, including adjustments for working capital of
      $10.4 million and current year capital expenditures of $19.0 million. Assets
      acquired include interests in approximately 2,150 natural gas wells with
      estimated proved reserves of approximately 613.7 billion cubic feet of natural
      gas equivalents, located in the northern lower peninsula of Michigan, 228,000
      developed acres and 66,000 undeveloped acres. Subsequent to the acquisition
      of
      DGO, Atlas Energy changed its name to Atlas Gas & Oil Company (“AGO”). With
      this acquisition, the Company increased its natural gas and production as well
      as entered into a new region that offers additional opportunities to expand
      its
      operations.




To
      fund the acquisition, Atlas Energy borrowed $713.9 million on its new credit
      facility (See Note 8) and completed a private placement of 7,298,181 Class
      B
      common units and 16,702,828 Class D units to a group of institutional investors
      at a weighted average price of $25.00 per unit for net proceeds of $597.5
      million. Proceeds of $52.5 million were used to pay the outstanding balance
      of
      Atlas Energy ’s
      credit
      facility with Wachovia Bank.





11


**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited)


**Note
      4 - ACQUISITIONS (Continued)**





The
      acquisition was accounted for using the purchase method of accounting under
      SFAS
      No. 141, *Business
      Combinations* (“SFAS
      No. 141”). The following table presents the preliminary purchase price
      allocation, including professional fees and other related acquisition costs,
      to
      the assets acquired and liabilities assumed based on their estimated fair market
      value at the date of acquisition (in thousands):





Accounts
                receivable
            
            $
            33,412Prepaid
                expenses
            
            
            515Leaseholds,
                wells and related equipment
            
            
            1,269,839Total
                assets acquired
            
            
            1,303,766Accounts
                payable and accrued liabilities
            
            
            (21,869
            )Asset
                retirement obligations
            
            
            (13,920
            )(35,789
            )Net
                assets acquired
            
            $
            1,267,977





Due
      to its recent date of acquisition, the purchase price allocation is based on
      preliminary data that is subject to adjustment and could change significantly
      as
      the Company continues to evaluate this allocation. DGO’s operations are included
      within the Company’s consolidated financial statements beginning June 29,
      2007.





The
      following data presents pro forma revenues, net income and basic and diluted
      net
      income per share for the Company as if the AGO and Anadarko acquisitions
      and related debt (see Note 8) and equity financing had occurred on January
      1, 2006. The Company has prepared these pro forma financial results for
      comparative purposes only which may not be indicative of the results that would
      have occurred if the Company had completed the acquisition at January 1, 2006,
      or the results that will be attained in the future (in thousands, except per
      share amounts):




**Nine
                Months Ended****September
                30, 2007****As**
            
            **Pro
                Forma**
            
            **Pro****Reported**
            
            **Adjustments**
            
            **Forma**Revenues
            
            $
            841,307
            
            $
            337,120
            
            $
            1,178,427Net
                income
            
            $
            37,217
            
            $
            (20,788
            )
            $
            16,429Net
                income per common unit outstanding–basic
            
            $
            1.36
            
            $
            (0.76
            )
            $
            .60Weighted
                average common units–outstanding basic
            
            
            27,345
            
            
            —
            
            
            27,345Net
                income per common share–diluted
            
            $
            1.31
            
            $
            (0.71
            )
            $
            .60Weighted
              average common shares–outstanding diluted
            
            
            28,348
            
            
            —
            
            
            28,348





**Three
                Months Ended**
            
            **Nine
                Months Ended****September
                30, 2006**
            
            **September
                30, 2006****As**
            
            **Pro
                Forma**
            
            **Pro**
            
            **As**
            
            **Pro
                Forma**
            
            **Pro****Reported**
            
            **Adjustments**
            
            **Forma**
            
            **Reported**
            
            **Adjustments**
            
            **Forma**Revenues
            
            $
            190,617
            
            $
            273,115
            
            $
            463,732
            
            $
            547,886
            
            $
            727,374
            
            $
            1,275,260Net
                income
            
            
            9,970
            
            
            18,066
            
            
            28,036
            
            
            31,431
            
            
            34,189
            
            
            65,620Net
                income per common unit outstanding–basic
            
            $
            .34
            
            $
            .61
            
            $
            .95
            
            $
            1.06
            
            $
            1.15
            
            $
            2.21Weighted
                average common units–outstanding basic
            
            
            29,396
            
            
            —
            
            
            29,396
            
            
            29,759
            
            
            —
            
            
            29,759Net
                income per common share–diluted
            
            $
            .33
            
            $
            .60
            
            $
            .93
            
            $
            1.03
            
            $
            1.12
            
            $
            2.16Weighted
                average common shares–outstanding diluted
            
            
            30,000
            
            
            —
            
            
            30,000
            
            
            30,409
            
            
            —
            
            
            30,409





Pro
      forma adjustments to revenues include substantial losses on derivatives realized
      by AGO. All such derivatives were canceled upon the acquisition of AGO by Atlas
      Energy and Atlas Energy entered into new derivative contracts covering future
      AGO production.





12





**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited)





**NOTE
      5 - PROPERTY AND EQUIPMENT**





Property
      and equipment is stated at cost. Depreciation, depletion and amortization are
      based on cost less estimated salvage value primarily using the
      unit-of-production or straight-line methods over the asset’s 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):





**September
                30,**
            
            **December
                31,****2007**
            
            **2006**Mineral
                interests:Proved
                properties
            
            $
            12,870
            
            $
            1,290Unproved
                properties
            
            
            1,002
            
            
            1,002Leaseholds,
                wells and related equipment
            
            
            1,729,282
            
            
            348,592Pipelines,
                processing and compression facilities
            
            
            2,289,411
            
            
            611,212Rights-of-way
            
            
            313,165
            
            
            30,401Land,
                building and improvements
            
            
            8,868
            
            
            8,451Support
                equipment
            
            
            9,210
            
            
            5,604Other
            
            
            14,178
            
            
            9,9024,377,986
            
            
            1,016,454Accumulated
                depreciation, depletion and amortization:Oil
                and gas properties and pipelines
            
            
            (181,540
            )
            
            (125,550
            )Other
            
            
            (6,843
            )
            
            (6,092
            )(188,383
            )
            
            (131,642
            )$
            4,189,603
            
            $
            884,812





On
      July 27, 2007, Atlas Pipeline acquired control of the Chaney Dell and
      Midkiff/Benedum systems for approximately $1.88 billion. On June 29, 2007,
      Atlas
      Energy acquired all of the outstanding equity interests in DTE Gas & Oil
      Company for approximately $1.268 billion, including acquisition costs of $11.0
      million (See Note 4). Due to the recent date of the acquisitions, the purchase
      price allocations are based upon estimated values and could change significantly
      as Atlas Pipeline and Atlas Energy continue to evaluate the preliminary
      allocations. At September 30, 2007, Atlas Pipeline recorded the portion of
      the
      purchase price of $1.88 billion allocable to pipelines, processing and
      compression facilities within the above table. Atlas Energy recorded the portion
      of the purchase price of $1.27 billion allocable to leaseholds, wells and
      related equipment within the above table.




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





**Other
      Assets**





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





**September
                30,**
            
            **December
                31,****2007**
            
            **2006**Deferred
                finance costs, net of accumulated amortization of $2,434 and
                $6,862
            
            $
            28,277
            
            $
            13,040Investments
            
            
            12,110
            
            
            1,553Security
                deposits
            
            
            2,046
            
            
            1,538Long-term
                hedge receivable from Partnerships
            
            
            6,731
            
            
            2,131Unrealized
                hedge gain–long term
            
            
            23,854
            
            
            24,148Other
            
            
            1,018
            
            
            91$
            74,036
            
            $
            42,501








13








**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited)





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





Deferred
      finance costs are recorded at cost and are amortized according to the terms
      of
      the related loan agreements which range from five to ten years. Investments
      include the Company’s $10.4 million investment in Lightfoot Capital Partners,
      L.P. (“Lightfoot”) (See Note 11). Long-term hedge receivable from Partnerships
      represents the portion of the long-term unrealized loss on contracts that has
      been allocated to affiliated energy partnerships.





**Intangible
      Assets**





*Customer
      contracts and relationships.* At
      September 30, 2007, Atlas Pipeline had $24.1 million of intangible assets,
      net
      of accumulated amortization of $5.9 million which was recorded in connection
      with natural gas gathering contracts and customer relations assumed in its
      acquisitions of Elk City and NOARK. 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.
      The customer contracts and relationship intangible assets, which have estimated
      lives of eight and twenty years, respectively, are being amortized on a
      straight-line basis. Amortization expense on intangible assets was $600,000
      and
      $(900,000) for the three months ended September 30, 2007 and 2006 respectively.
      Amortization expense was $1.8 million and $1.4 million for the nine months
      ended
      September 30, 2007 and 2006, respectively.





*Partnership
      management and operating contracts.* Included
      in intangible assets are partnership management and operating contracts acquired
      by Atlas Energy through acquisitions which are recorded at fair value on
      their acquisition dates.  Atlas Energy amortizes contracts acquired on the
      declining balance and straight-line methods, over their respective estimated
      lives, ranging from five to thirteen years.  Amortization expense for these
      contracts for the nine months ended September 30, 2007 and 2006 was $614,000
      and
      $659,000 respectively.





Aggregate
      estimated annual amortization expense for all of the contracts described above
      for the next five years ending September 30 is as follows: 2008 - $3.2 million;
      2009 - $3.2 million; 2010 - $3.1 million; 2011 - $3.1 million and 2012 - $2.7
      million.





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





**September
                30,**
            
            **December
                31,****2007**
            
            **2006****Accumulated**
            
            
            
            **Accumulated****Cost**
            
            **Amortization**
            
            **Cost**
            
            **Amortization**Customer
                contracts and relationships
            
            $
            30,070
            
            $
            (5,939
            )
            $
            29,650
            
            $
            (4,120
            )Partnership
                management and operating contracts
            
            
            14,343
            
            
            (9,746
            )
            
            14,343
            
            
            (9,132
            )Intangible
                assets, net
            
            $
            44,413
            
            $
            (15,685
            )
            $
            43,993
            
            $
            (13,252
            )





**Goodwill**




The
      Company applies the provisions of Statement of Financial Accounting Standards,
      (“SFAS”), No. 142, Goodwill and Other Intangible Assets”, which requires that
      goodwill no longer be amortized, but instead evaluated for impairment at least
      annually. The evaluation of impairment under SFAS 142 requires the use of
      projections, estimates and assumptions as to the future performance of the
      Company’s operations, including anticipated future revenues, expected future
      operating costs and the discount factor used. Actual results could differ from
      projections, resulting in revisions to the Company’s assumptions and, if
      required, recognition of an impairment loss. The Company’s evaluation of
      goodwill at December 31, 2006 (the most recent valuation date) indicated there
      was no impairment loss and no impairment indicators have arisen since that
      date.
      The Company will continue to evaluate its goodwill at least 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. At September 30, 2007 and December 31, 2006 the Company
      had goodwill of $98.6 million, net of accumulated amortization of $4.5
      million.








14





**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited)





**NOTE
      7 - ASSET RETIREMENT OBLIGATIONS**





The
      Company accounts for its estimated plugging and abandonment of its oil and
      gas
      properties in accordance with SFAS 143, *Accounting
      for Asset Retirement Obligations* and FASB Interpretation No. 47, *Accounting
      for Conditional Asset Retirement Obligations* ,
      (“FIN 47”). 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**
            
            **Nine
                Months Ended****September
                30**,
            
            **September
                30,****2007**
            
            **2006**
            
            **2007**
            
            **2006**Asset
                retirement obligations, beginning of period
            
            $
            41,792
            
            $
            19,760
            
            $
            26,726
            
            $
            18,499Liabilities
                acquired (See Note 4)
            
            
            505
            
            
            —
            
            
            13,920
            
            
            —Liabilities
                incurred
            
            
            997
            
            
            490
            
            
            2,024
            
            
            1,616Liabilities
                settled
            
            
            (9
            )
            
            (67
            )
            
            (30
            )
            
            (180
            )Accretion
                expense
            
            
            673
            
            
            124
            
            
            1,318
            
            
            372Asset
                retirement obligations, end of period
            
            $
            43,958
            
            $
            20,307
            
            $
            43,958
            
            $
            20,307





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):





**September
                30,**
            
            **December
                31,****2007**
            
            **2006**Senior
                notes–Atlas Pipeline
            
            $
            294,419
            
            $
            285,977Term
                credit facility–Atlas Pipeline
            
            
            830,000
            
            
            —Revolving
                credit facility–Atlas Pipeline
            
            
            33,500
            
            
            38,000Revolving
                credit facility–Atlas Energy
            
            
            739,000
            
            
            —Revolving
                credit facility–Atlas Pipeline Holdings
            
            
            25,000
            
            
            —Other
                debt
            
            
            126
            
            
            1741,922,045
            
            
            324,151Less
                current maturities
            
            
            77
            
            
            109$
            1,921,968
            
            $
            324,042







*Atlas
      Pipeline Credit Facility.* At
      September 30, 2007, Atlas Pipeline had a new credit facility, comprised of
      an
      $830.0 senior secured term loan (“term loan”) which matures in July 2014 and a
      $300.0 million senior secured revolving credit facility which matures in July
      2013. The Partnership borrowed $830.0 million under the term loan and $15.0
      million under the revolving credit facility to finance a portion of the Anadarko
      acquisition and to repay indebtedness under its prior revolving credit facility.
      The credit facility bears interest, at Atlas Pipeline’s option, at either
      (i) adjusted London Interbank Offered Rate (“LIBOR”) plus the applicable
      margin, as defined, or (ii) the higher of the federal funds rate plus 0.5%
      or the Wachovia Bank, National Association’s (“Wachovia”) prime rate (each plus
      the applicable margin). The weighted average interest rate on the outstanding
      credit facility borrowings at September 30, 2007 was 8.0%. Up to $50.0 million
      of the credit facility may be utilized for letters of credit, of which $7.1
      million was outstanding at September 30, 2007. These outstanding letter of
      credit amounts were not reflected as borrowings on the Company’s consolidated
      balance sheets. Borrowings under the credit facility are secured by a lien
      on
      and security interest in all of Atlas Pipeline’s property and that of its
      subsidiaries, and by the guaranty of each of its subsidiaries, other than joint
      venture companies. The credit facility contains customary covenants, including
      restrictions on Atlas Pipeline’s ability to incur additional indebtedness; make
      certain acquisitions, loans or investments; make distribution payments to its
      unitholders if an event of default exists; and enter into a merger or sale
      of
      assets, including the sale or transfer of interests in its subsidiaries. Atlas
      Pipeline is in compliance with these covenants as of September 30, 2007.







15





**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited)





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





*Atlas
      Pipeline Senior Notes.* At
      September 30, 2007, Atlas Pipeline has $293.5 million of 10-year, 8.125% senior
      unsecured notes (“Senior Notes”) outstanding, net of unamortized premium
      received of $900,000. Interest on the Senior Notes is payable semi-annually
      in
      arrears on June 15 and December 15. The Senior Notes are redeemable at any
      time
      on or after December 15, 2010 at certain 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 stated redemption prices,
      together with accrued and unpaid interest to the date of redemption. In
      addition, prior to December 15, 2008, Atlas Pipeline may redeem up to 35% of
      the
      aggregate principal amount of the Senior Notes with the proceeds of certain
      equity offerings at a stated redemption price. The Senior Notes are also subject
      to repurchase by Atlas Pipeline at a price equal to 101% of their principal
      amount, plus accrued and unpaid interest, upon a change of control or upon
      certain asset sales if Atlas Pipeline does not reinvest the net proceeds within
      360 days. The Senior Notes are junior in right of payment to Atlas Pipeline’s
      secured debt, including Atlas Pipeline’s obligations under its credit facility.





On
      April
      18, 2007, Atlas Pipeline issued to Sunlight Capital, $8.5 million of its 8.125%
      Senior Notes due April 18, 2015 (the “Notes”), in consideration of Sunlight
      Capital’s consent to the amendment of Atlas Pipeline’s preferred unit agreement.
      Atlas Pipeline filed, pursuant to the Registration Rights Agreement, an exchange
      offer registration statement to exchange the Notes for publicly tradable notes.
      The registration statement was declared effective by the SEC on July 17, 2007.
      Atlas Pipeline must complete the exchange offer by September 15, 2007. If Atlas
      Pipeline fails to meet this deadline, the Notes will accrue additional interest
      of 1% per annum for each 90-day period Atlas Pipeline is in default, up to
      a
      maximum amount of 3% per annum.




The
      indenture governing the Senior Notes contains covenants, including limitations
      of Atlas Pipeline ’s
      ability to: incur certain liens; engage in sale/leaseback transactions; incur
      additional indebtedness; declare or pay distributions if an event of default
      has
      occurred; redeem, repurchase or retire equity interests or subordinated
      indebtedness; make certain investments; or merge, consolidate or sell
      substantially all of its assets. Atlas Pipeline is in compliance with these
      covenants as of September 30, 2007.





*Atlas
      Pipeline Holdings Credit Facility.* On
      July 26, 2006, AHD, as borrower, and Atlas Pipeline GP, as guarantor,
      entered into a $50.0 million revolving credit facility ($25.0 million
      outstanding borrowings at September 30, 2007) with Wachovia as administrative
      agent and issuing bank, and a syndicate of banks. AHD’s credit facility matures
      in April 2010 and bears interest, at its option, at either (i) adjusted
      LIBOR (as defined in the credit facility) or (ii) the higher of the federal
      funds rate plus 0.5% or the Wachovia prime rate, except that no more than five
      LIBOR loans may be outstanding at any time. Borrowings under the credit facility
      are secured by a first-priority lien on a security interest in all of the AHD’s
      assets, including a pledge of Atlas Pipeline GP’s interests in Atlas Pipeline,
      and are guaranteed by Atlas Pipeline GP and AHD’s other subsidiaries (excluding
      Atlas Pipeline and its subsidiaries). The credit facility contains customary
      covenants, including restrictions on its ability to incur additional
      indebtedness; make certain acquisitions, loans or investments; make distribution
      payments to AHD’s unitholders if an event of default exists or would result from
      such distribution; or enter into a merger or sale of substantially all of AHD’s
      property or assets, including the sale or transfer of interests in its
      subsidiaries. AHD is in compliance with these covenants as of September 30,
      2007. AHD may borrow under its credit facility (i) for general business
      purposes, including for working capital, to purchase debt or limited partnership
      units of Atlas Pipeline, to fund general partner contributions from AHD to
      Atlas
      Pipeline and to make permitted acquisitions, (ii) to pay fees and expenses
      related to its credit facility and (iii) for letters of credit.





*Atlas
      Energy Resources Credit Facility.* Upon the
      closing of its acquisition of DTE Gas & Oil Company (See Note 4), Atlas
      Energy replaced its Wachovia Bank Credit facility with a new 5-year, $850.0
      million credit facility with JP Morgan Chase Bank, N.A. (“JP Morgan”) as
      administrative agent, Wachovia Bank, National Association as syndication agent,
      and other lenders. The revolving credit facility has a current borrowing base
      of
      $850.0 million which will be redetermined semi-annually on April 1 and October
      1
      subject to changes in Atlas Energy’s oil and gas reserves. The initial borrowing
      base is also scheduled to be reduced to $735.0 million less 25% of the amount
      of
      any issuance of equity or debt securities by Atlas Energy at the earlier of
      June
      29, 2008 or the issuance by Atlas Energy of equity or debt securities of at
      least $200.0 million. Up to $50.0 million of the facility may be in the form
      of
      standby letters of credit. The facility is secured by Atlas Energy’s assets and
      bears interest at either the base rate plus the applicable margin or at adjusted
      LIBOR plus the applicable margin, elected at Atlas Energy’s option. At September
      30, 2007, the weighted average interest rate on outstanding borrowings was
7.5 %.





16








**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited)





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





The
      base
      rate for any day equals the higher of the federal funds rate plus 0.50% or
      the
      JP Morgan prime rate. Adjusted LIBOR is LIBOR divided by 1.00 minus the
      percentage prescribed by the Federal Reserve Board for determining the reserve
      requirement for Eurocurrency liabilities. The applicable margin ranges from
      0.0%
      to 1.25% for base rate loans and 1.00% to 2.25% for LIBOR loans.




The
      JP Morgan credit facility requires Atlas Energy to maintain specified financial
      ratios of current assets to current liabilities and debt to earnings before
      interest, taxes, depreciation, depletion and amortization ( “EBITDA”).
      In addition, the facility limits sales, leases or transfers of assets and the
      incurrence of additional indebtedness. The facility limits the dividends payable
      by Atlas Energy if an event of default has occurred and is continuing or would
      occur as a result of such distribution. Atlas Energy is in compliance with
      these
      covenants as of September 30, 2007. The facility terminates in June 2012, when
      all outstanding borrowings must be repaid. At September 30, 2007 and
      December 31, 2006, $739 million and $0.0, respectively, were outstanding
      under this facility and the previous Wachovia Bank credit facility. In addition,
      letters of credit of $ 1.1 million and $495,000 were outstanding at each date
      which are not reflected as borrowings on the Company’s Consolidated Balance
      Sheets.





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





2008
            
            $
            772009
            
            
            262010
            
            
            25,0112011
            
            
            122012
                and thereafter
            
            
            1,896,919$
            1,922,045





**NOTE
      9 - DERIVATIVE INSTRUMENTS**




The
      Company, through its subsidiaries, enters into financial swap and option
      instruments to hedge its exposure to changes in commodity prices which are
      classified as cash flow hedges in accordance with SFAS No. 133 *,
      Accounting for Derivative Instruments and Hedging Activity* (“SFAS
      No. 133”). ** 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, the Company receives or pays a fixed price and
      receives or remits a floating price based on certain indices for the relevant
      contract period. 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 risk management objective and strategy for
      undertaking the hedging transactions. This includes matching the 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. Gains or losses on future contracts
      are determined as the difference between the contract price and a reference
      price, generally prices on New York Mercantile Exchange. Such gains and losses
      are charged or credited to accumulated other comprehensive income (loss) and
      recognized as a component of revenue 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.




17





**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited **)**





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





On
      May
      18, 2007, Atlas Energy signed a definitive agreement to acquire AGO (see Note
      4). In connection with the financing of this transaction, Atlas Energy agreed
      as
      a condition precedent to closing that it would hedge 80% of its projected
      natural gas volumes for no less than three years from the closing date of the
      transaction. During May 2007, Atlas Energy entered into derivative instruments
      to hedge 80% of the projected production of the assets to be acquired as
      required under the financing agreement. The production volume of the assets
      to
      be acquired was not considered to be “probable forecasted production” under SFAS
      No. 133 at the date these derivatives were entered into because the acquisition
      of the assets had not yet been completed. Accordingly, Atlas Energy recognized
      the instruments as non-qualifying for hedge accounting at inception with
      subsequent changes in the derivative value recorded within revenues in the
      Company’s consolidated statements of income. Atlas Energy recognized non-cash
      income of $26.3 million related to the change in value of these derivatives
      from
      May 22, 2007 to June 28, 2007, which is shown as “Gain on mark-to-market
      derivatives” in the Combined and Consolidated Statements of Income for the nine
      months ended September 30, 2007. Upon closing of the acquisition on June 29,
      2007, the production volume of the assets acquired was considered “probable
      forecasted production” under SFAS No. 133 and Atlas Energy evaluated these
      derivatives under the cash flow hedge criteria in accordance with SFAS No.
      133.




At
      September 30, 2007, Atlas Energy had 384 open natural futures contracts related
      to natural gas sales covering 147.5 million MMBtus of natural gas maturing
      through September 30, 2012 at a combined average settlement price of $8.04
      per
      MMBtu. At September 30, 2007 and December 31, 2006, Atlas Energy reflected
      net
      derivative assets of $50.4 million and $47.5 million, respectively. In addition,
      Atlas Energy recognized gains on settled contracts covering natural gas
      production of $4.9 million and $2.0 million for the three months ended September
      30, 2007 and 2006, and $9.6 million and $4.9 million for nine months ended
      September 30, 2007 and 2006, respectively. There were no gains or losses
      recognized during the three months and nine months ended September 30, 2006
      for
      hedge ineffectiveness or as a result of the discontinuance of any cash flow
      hedges.





On
      June
      3, 2007, Atlas Pipeline signed definitive agreements to acquire control of
      certain natural gas gathering systems and processing plants located in Oklahoma
      and Texas (see Note 4). In connection with the financing of this
      transaction, Atlas Pipeline agreed as a condition precedent to closing that
      it
      would hedge 80% of its projected natural gas, NGL and condensate production
      volume for no less than three years from the closing date of the transaction.
      During June 2007, Atlas Pipeline entered into derivative instruments to hedge
      80% of the projected production of the assets to be acquired as required under
      the financing agreements. The production volume of the assets to be acquired
      was
      not considered to be “probable forecasted production” under SFAS No. 133 at the
      date these derivatives were entered into because the acquisition of the assets
      had not yet been completed. Accordingly, Atlas Pipeline recognized the
      instruments as non-qualifying for hedge accounting at inception with subsequent
      changes in the derivative value recorded within revenues in the Company’s
      consolidated statements of income. APL recognized a non-cash loss of $19.8
      million related to the change in value of these derivatives for the three and
      nine months ended September 30, 2007. Upon closing of the acquisition in July
      2007, the production volume of the assets acquired was considered “probable
      forecasted production” under SFAS No. 133 and Atlas Pipeline evaluated these
      derivatives under the cash flow hedge criteria in accordance with SFAS No.
      133.





At
      September 30, 2007 and December 31, 2006, Atlas Pipeline reflected net
      derivative liabilities of $92.0 million and $20.1 million, respectively. Atlas
      Pipeline recognized losses of $12.9 million and $4.9 million for the three
      months ended September 30, 2007 and 2006, respectively, and losses of $23.5
      million and $10.5 million for the nine months ended September 30, 2007 and
      2006,
      respectively, within natural gas and liquids revenue in its consolidated
      statements of income related to the settlement of qualifying hedge instruments.
      Atlas Pipeline recognized a loss of $8.4 million and a gain of $3.7 million
      within “Other, net” on the Company’s consolidated statements of income related
      to the change in market value of non-qualifying derivatives and the ineffective
      portion of qualifying derivatives, respectively, for the three months ended
      September 30, 2007. Atlas Pipeline recognized a loss of $39.3 million and a
      gain
      of $4.6 million within “Other, net” in the Company’s consolidated statements of
      income related to the change in market value of non-qualifying derivatives
      and
      the ineffective portion of qualifying derivatives, respectively, for the nine
      months ended September 30, 2007. Atlas Pipeline recognized losses of $3.0
      million for the three and nine months ended September 30, 2007, within “Other,
      net” in its consolidated statements of income related to loss from cash
      settlement of non-qualifying derivatives. There were no gains or losses
      recognized for the three months or nine months ended September 30, 2006 related
      to cash settlements of non-qualifying derivatives..





18







**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited **)**





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





At
      September 30, 2007 and December 31, 2006, the Company reflected a net hedging
      liability and asset on its balance sheets of $41.6 million and $27.3 million,
      respectively, when combining the above hedges of Atlas Energy and Atlas
      Pipeline. Of the $4.0 million net gain in accumulated other comprehensive income
      at September 30, 2007, the Company will reclassify $2.8 million of gain to
      its
      consolidated statements of income over the next twelve month period as these
      contracts expire, and $1.2 million of gain 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.





As
      of September 30, 2007, the Company had the following financial hedges in
      place:





**ATLAS
      ENERGY RESOURCES HEDGES**


**Natural
      Gas Fixed Price Swaps**





**Twelve
                Month****Period
                Ending**
            
            
            
            
            
            **Average**
            
            **Fair
                Value****September
                30,**
            
            
            
            **Volumes**
            
            **Fixed
                Price**
            
            **Asset/(Liability)****(3)****(MMBtu)****(1)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands)**2008
            
            
            
            
            
            35,470,000
            
            $
            8.15
            
            $
            37,2892009
            
            
            
            
            
            33,530,000
            
            $
            8.32
            
            
            11,3102010
            
            
            
            
            
            25,430,000
            
            $
            8.02
            
            
            5172011
            
            
            
            
            
            18,950,000
            
            $
            7.75
            
            
            (
                790
            )2012
            
            
            
            
            
            11,150,000
            
            $
            7.62
            
            
            8212013
            
            
            
            
            
            2,250,000
            
            $
            7.67
            
            
            346$
            49,493





**Natural
      Gas Costless Collars**





**Twelve
                Month****Period
                Ending**
            
            
            
            
            
            **Average**
            
            **Fair
                Value****September
                30,**
            
            **Option
                Type**
            
            **Volumes**
            
            **Floor
                and Cap**
            
            **Asset/(Liability)****(3)****(MMBtu)****(1)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands)**2008
            
            
            Puts
                purchased
            
            
            450,000
            
            $
            7.50
            
            $
            3142008
            
            
            Calls
                sold
            
            
            450,000
            
            $
            8.60
            
            
            —2008
            
            
            Puts
                purchased
            
            
            1,170,000
            
            $
            7.50
            
            
            3252008
            
            
            Calls
                sold
            
            
            1,170,000
            
            $
            9.40
            
            
            —2009
            
            
            Puts
                purchased
            
            
            390,000
            
            $
            7.50
            
            
            —2009
            
            
            Calls
                sold
            
            
            390,000
            
            $
            9.40
            
            
            (32
            )2010
            
            
            Puts
                purchased
            
            
            2,160,000
            
            $
            7.75
            
            
            1442010
            
            
            Calls
                sold
            
            
            2,160,000
            
            $
            8.75
            
            
            —2011
            
            
            Puts
                purchased
            
            
            720,000
            
            $
            7.75
            
            
            (4
            )2011
            
            
            Calls
                sold
            
            
            720,000
            
            $
            8.75
            
            
            —2011
            
            
            Puts
                purchased
            
            
            5,400,000
            
            $
            7.50
            
            
            2402011
            
            
            Calls
                sold
            
            
            5,400,000
            
            $
            8.45
            
            
            —2012
            
            
            Puts
                purchased
            
            
            1,800,000
            
            $
            7.50
            
            
            —2012
            
            
            Calls
                sold
            
            
            1,800,000
            
            $
            8.45
            
            
            (25
            )2012
            
            
            Puts
                purchased
            
            
            6,480,000
            
            $
            7.50
            
            
            —2012
            
            
            Calls
                sold
            
            
            6,480,000
            
            $
            8.45
            
            
            (24
            )2013
            
            
            Puts
                purchased
            
            
            2,160,000
            
            $
            7.00
            
            
            —2013
            
            
            Calls
                sold
            
            
            2,160,000
            
            $
            8.37
            
            
            (19
            )$
            919Total
                Atlas Energy Resources net asset
            $
            50,412





19








**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited)





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





**ATLAS
      PIPELINE HEDGES**


**Natural
      Gas Fixed - Price Swaps (Liquids Sales)**





**Production****Period
                Ended**
            
            
            
            **Average**
            
            **Fair
                Value****December
                31,**
            
            **Volumes**
            
            **Fixed
                Price**
            
            **Asset/(Liability)****(2)****(gallons)**
            
            **(per
                gallon)**
            
            **(in
                thousands)**2007
            
            
            42,651,000
            
            $
            0.893
            
            $
            (10,739
            )2008
            
            
            61,362,000
            
            
            0.706
            
            
            (13,556
            )2009
            
            
            8,568,000
            
            
            0.746
            
            
            (1,752
            )$
            (26,047
            )





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





**Production****Period
                Ended**
            
            
            
            **Average**
            
            **Fair
                Value****December
                31,**
            
            **Volumes**
            
            **Fixed
                Price**
            
            **Asset/(Liability)****(3)****(MMBtu)****(1)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands)**2007
            
            
            1,449,000
            
            $
            8.197
            
            $
            1,7362008
            
            
            5,484,000
            
            $
            8.795
            
            
            4,6082009
            
            
            5,724,000
            
            $
            8.611
            
            
            1,9582010
            
            
            2,820,000
            
            $
            8.635
            
            
            1,132$
            9,434





**Natural
      Gas Basis Swaps (Sales)**





**Production****Period
                Ended**
            
            
            
            **Average**
            
            **Fair
                Value****December
                31,**
            
            **Volumes**
            
            **Fixed
                Price**
            
            **Asset/(Liability)****(3)****(MMBtu)****(1)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands)**2007
            
            
            1,449,000
            
            $
            (0.729
            )
            $
            1352008
            
            
            5,484,000
            
            $
            (0.727
            )
            
            3882009
            
            
            5,724,000
            
            $
            (0.513
            )
            
            5502010
            
            
            2,820,000
            
            $
            (0.572
            )
            
            435$
            1,508





**Natural
      Gas Fixed Price (Purchase)**





**Production****Period
                Ended**
            
            
            
            **Average**
            
            **Fair
                Value****December
                31,**
            
            **Volumes**
            
            **Fixed
                Price**
            
            **Liability****(3)****(MMBtu)****(1)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands)**2007
            
            
            3,909,000
            
            $
            8.633
            (4)
            $
            (6,819
            )2008
            
            
            16,260,000
            
            $
            8.923
            (5)
            
            (16,293
            )2009
            
            
            15,564,000
            
            $
            8.680
            
            
            (6,402
            )2010
            
            
            7,200,000
            
            $
            8.635
            
            
            (2,891
            )$
            (32,405
            )





20







**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited)





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





**Natural
      Gas Basis (Purchase)**





**Production****Period
                Ended**
            
            
            
            **Average**
            
            **Fair
                Value****December
                31,**
            
            **Volumes**
            
            **Fixed
                Price**
            
            **Liability****(3)****(MMBtu)****(1)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands)**2007
            
            
            3,909,000
            
            $
            (1.048
            )
            $
            1612008
            
            
            15,276,000
            
            $
            (1.186
            )
            
            (1,820
            )2009
            
            
            14,820,000
            
            $
            (0.686
            )
            
            (5,485
            )2010
            
            
            7,200,000
            
            $
            (0.560
            )
            
            (2,930
            )$
            (10,074
            )




**Crude
      Oil Fixed - Price Swaps (Sales)**




**Production****Period
                    Ended**
                
                
                
                **Average**
                
                **Fair
                    Value****December
                    31,**
                
                **Volumes**
                
                **Fixed
                    Price**
                
                **Liability****(3)****(barrels)**
                
                **(per
                    barrel)**
                
                **(in
                    thousands)**2007
                
                
                17,600
                
                $
                56.477
                
                $
                (427
                )2008
                
                
                65,400
                
                $
                59.424
                
                
                (1,133
                )2009
                
                
                33,000
                
                $
                62.700
                
                
                (362
                )$
                (1,922
                )





**Crude
      Oil Options (Sales)**





**Production****Period
                Ended**
            
            
            
            
            
            **Average**
            
            **Fair
                Value****December
                31,**
            
            **Option
                Type**
            
            **Volumes**
            
            **Strike
                Price**
            
            **Asset/(Liability)****(3)****(MMBtu)****(1)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands)**2007
            
            
            Puts
                purchased
            
            
            189,300
            
            $
            60.000
            
            $
            (39
            )2007
            
            
            Calls
                sold
            
            
            189,300
            
            $
            75.363
            
            
            (998
            )2008
            
            
            Puts
                purchased
            
            
            691,800
            
            $
            60.000
            
            
            6752008
            
            
            Calls
                sold
            
            
            691,800
            
            $
            78.004
            
            
            (3,266
            )2009
            
            
            Puts
                purchased
            
            
            738,000
            
            $
            60.000
            
            
            2,0602009
            
            
            Calls
                sold
            
            
            738,000
            
            $
            80.622
            
            
            (3,038
            )2010
            
            
            Puts
                purchased
            
            
            402,000
            
            $
            60.000
            
            
            1,3082010
            
            
            Calls
                sold
            
            
            402,000
            
            $
            79.341
            
            
            (1,804
            )2011
            
            
            Puts
                purchased
            
            
            30,000
            
            $
            60.000
            
            
            1242011
            
            
            Calls
                sold
            
            
            30,000
            
            $
            74.500
            
            
            (193
            )2012
            
            
            Puts
                purchased
            
            
            30,000
            
            $
            60.000
            
            
            1382012
            
            
            Calls
                sold
            
            
            30,000
            
            $
            73.900
            
            
            (211
            )$
            (5,244
            )





21


**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited)





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





**Crude
      Oil Sales Options (associated with NGL volumes)**





**Production****Period
                Ended**
            
            
            
            **Associated
                NGL**
            
            **Crude**
            
            **Average
                crude**
            
            **Fair
                Value****December
                31,**
            
            **Option
                Type**
            
            **Volumes**
            
            **Volumes**
            
            **Strike
                Price**
            
            **Asset/(Liability)****(3)****(gallons)**
            
            **(barrels)**
            
            **(per
                barrel)**
            
            **(in
                thousands)**2007
            
            
            Puts
                purchased
            
            
            25,789,680
            
            
            390,000
            
            $
            60.00
            
            $
            582007
            
            
            Calls
                sold
            
            
            25,789,680
            
            
            390,000
            
            $
            75.15
            
            
            (2,513
            )2008
            
            
            Puts
                purchased
            
            
            249,257,484
            
            
            3,744,600
            
            $
            60.00
            
            
            5,1192008
            
            
            Calls
                sold
            
            
            249,257,484
            
            
            3,744,600
            
            $
            79.38
            
            
            (15,961
            )2009
            
            
            Puts
                purchased
            
            
            324,233,280
            
            
            4,752,000
            
            $
            60.00
            
            
            13,2922009
            
            
            Calls
                sold
            
            
            324,233,280
            
            
            4,752,000
            
            $
            78.68
            
            
            (22,694
            )2010
            
            
            Puts
                purchased
            
            
            169,282,890
            
            
            2,413,500
            
            $
            60.00
            
            
            8,0642010
            
            
            Calls
                sold
            
            
            169,282,890
            
            
            2,413,500
            
            $
            77.28
            
            
            (12,643
            )$
            (27,278
            )Total
                Atlas Pipeline net liability
            $
            (92,028
            )Total
                Atlas America net liability
            $
            (41,616
            )







(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)
                      
                      Includes
                        Atlas Pipeline’s
                        premium received from its sale of an option for it to sell
                        1,200,000 MMBtu
                        of natural gas at an average price of $17.00 per MMBtu for
                        the year ended
                        December 31, 2007.
 (5)
                          
                          Includes Atlas Pipeline’s premium received
                            from its sale of an option for it to sell 936,000 MMBtu
                            of natural gas for
                            the year ended
                            December 31, 2008 at $15.50 per MMBtu.


22


**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited)





**NOTE
      10 - OPERATING SEGMENT INFORMATION**





The
      Company’s operations include three reportable operating segments.  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
      (in thousands):




**Three
                  Months Ended September 30,**
              
              **Nine
                  Months Ended September 30,****2007**
              
              **2006**
              
              **2007**
              
              **2006****Gas
                  and oil production**Revenues
                  (a)
              
              $
              63,265
              
              $
              21,888
              
              $
              136,097
              
              $
              66,696Costs
                  and expenses
              
              
              (9,887
              )
              
              (2,315
              )
              
              (14,412
              )
              
              (6,437
              )Segment
                  profit
              
              $
              53,378
              
              $
              19,573
              
              $
              121,685
              
              $
              60,259**Well
                  construction and completion**Revenues
                  (a)
              
              $
              103,324
              
              $
              50,641
              
              $
              240,841
              
              $
              135,329Costs
                  and expenses
              
              
              (89,847
              )
              
              (44,037
              )
              
              (209,427
              )
              
              (117,677
              )Segment
                  profit
              
              $
              13,477
              
              $
              6,604
              
              $
              31,414
              
              $
              17,652**Atlas
                  Pipeline**Revenues
              
              $
              231,257
              
              $
              108,434
              
              $
              427,792
              
              $
              319,983Revenues
                  - affiliates
              
              
              8,610
              
              
              6,974
              
              
              24,821
              
              
              22,719Costs
                  and expenses
              
              
              (187,389
              )
              
              (96,180
              )
              
              (377,668
              )
              
              (270,822
              )Segment
                  profit
              
              $
              52,478
              
              $
              19,228
              
              $
              74,945
              
              $
              71,880**Reconciliation
                  of segment profit to net income before taxes**Segment
                  profitGas
                  and oil production
              
              $
              53,378
              
              $
              19,573
              
              $
              121,685
              
              $
              60,259Well
                  construction and completion
              
              
              13,477
              
              
              6,604
              
              
              31,414
              
              
              17,652Atlas
                  Pipeline
              
              
              52,478
              
              
              19,228
              
              
              74,945
              
              
              71,880Total
                  segment profit
              
              
              119,333
              
              
              45,405
              
              
              228,044
              
              
              149,791General
                  and administrative expenses
              
              
              (48,923
              )
              
              (13,159
              )
              
              (85,229
              )
              
              (34,238
              )Depreciation,
                  depletion and amortization
              
              
              (35,187
              )
              
              (12,442
              )
              
              (61,064
              )
              
              (33,158
              )Other
                  income (expense) - net (b)
              
              
              (25,024
              )
              
              (3,532
              )
              
              (27,285
              )
              
              (30,332
              )Net
                  income before taxes
              
              $
              10,199
              
              $
              16,272
              
              $
              54,466
              
              $
              52,063**Capital
                  expenditures**Gas
                  and oil production
              
              
              
              
              
              
              
              $
              1,391,888
              
              $
              52,533Well
                  construction and completion
              
              
              
              
              
              
              
              
              -
              
              
              -Atlas
                  Pipeline
              
              
              
              
              
              
              
              
              1,973,241
              
              
              91,743Corporate
                  and other
              
              
              
              
              
              
              
              
              3,380
              
              
              1,543$
              3,368,509
              
              $
              145,819
  **September
                  30,**
                **2007**
              
              **December
                  31,**
                **2006****Balance
                  sheet**GoodwillGas
                  and oil production
              
              $
              21,527
              
              $
              21,527Well
                  construction and completion
              
              
              6,389
              
              
              6,389Atlas
                  Pipeline
              
              
              63,441
              
              
              63,441Corporate
                  and other
              
              
              7,250
              
              
              7,250$
              98,607
              
              $
              98,607Total
                  assetsGas
                  and oil production
              
              $
              1,782,990
              
              $
              377,807Well
                  construction and completion
              
              
              9,966
              
              
              8,335Atlas
                  Pipeline
              
              
              2,807,966
              
              
              787,128Corporate
                  and other
              
              
              139,591
              
              
              206,568$
              4,740,513
              
              $
              1,379,838


(a)
            Includes
                gain (loss) on mark-to-market
                derivatives.


(b)
            Includes
                revenue and expense from well services, transportation and administration
                and oversight of $2.5 million and $903,000 in the three months ended
                September 30, 2007 and 2006, respectively, and $5.0 million and ($2.5)
                million in the nine months ended September 30, 2007 and 2006,
                respectively, that do not meet the quantitative threshold for reporting
                segment information.





23








**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


**(Unaudited)**





**NOTE
      10 - OPERATING SEGMENT INFORMATION (Continued)**





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





**NOTE
      11 - COMMITMENTS AND CONTINGENCIES**





The
      Company is a party to various routine legal proceedings arising out of the
      ordinary course of its business. Management believes that none of these actions,
      individually or in the aggregate, will have a material adverse effect on its
      financial condition or results of operations.





One
      of
      the Company’s subsidiaries, Resource Energy, LLC, together with Resource
      America, Inc. (the Company’s former parent) was a defendant in a class action
      originally filed in February 2000 in the New York Supreme Court, Chautauqua
      County, by individuals, putatively on their own behalf and on behalf of
      similarly situated individuals, who leased property to the Company. The
      complaint alleged that the Company was not paying landowners the proper amount
      of royalty revenues with respect to natural gas produced from the leased
      properties. The complaint was seeking damages in an unspecified amount for
      the
      alleged difference between the amount of royalties actually paid and the amount
      of royalties that allegedly should have been paid. In April 2007, a settlement
      of this lawsuit was approved by the court. Pursuant to the settlement terms,
      the
      Company paid $300,000 in May 2007, upgraded certain gathering systems and
      capped certain transportation expenses chargeable to the land
      owners.





Atlas
      Gas
& Oil Company LLC, as successor to DTE Gas & Oil Company, is one of four
      defendants in a personal injury action filed in Antrim County Circuit Court
      in
      northern Michigan in August, 2006.  The complaint alleges that plaintiff
      suffered serious personal injuries as a result of the defendants’ negligence. A
      tentative settlement of this lawsuit was reached, the terms of which are subject
      to final approval by the court. Pursuant to the settlement terms, the Company
      paid $125,000 to the plaintiff in October 2007.





As
      of September 30, 2007, Atlas Pipeline is committed to expend approximately
      $91.3
      million on pipeline extensions, compressor station upgrades and processing
      facility upgrades.





The
      Company has begun construction of a new $2.9 million field operations building
      and yard in Fayette County, Pennsylvania of which $1.7 million remains committed
      at September 30, 2007.





The
      Company, through its subsidiary, Atlas Lightfoot, LLC, has committed to invest
      $20 million ($10.4 million invested at September 30, 2007) in Lightfoot Capital
      Partners, LP ("Lightfoot") and will own approximately 18% of Lightfoot Capital
      Partners GP, LLC. The Company uses the equity method to account for these
      investments and will also receive certain co-investment rights until such point
      as Lightfoot raises additional capital through a private offering to
      institutional investors or a public offering. Lightfoot has initial equity
      funding commitments of approximately $160.0 million and intends to focus its
      investments primarily on incubating new master limited partnerships, or MLPs,
      and providing capital to existing MLPs in need of additional equity or
      structured debt. Lightfoot will concentrate on assets that are MLP-qualified
      such as infrastructure, coal, and other asset categories and intends to form
      new
      MLPs in partnership with management teams in sectors that have been
      under-utilized by the MLP structure.





24





**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited)





**NOTE
      12 — BENEFIT PLANS**




The
      Company follows the provisions of SFAS No. 123(R), *Share-Based
      Payment* ,
      as
      revised (“SFAS No. 123(R)”), to account for stock incentive compensation plans.
      Generally, the approach to accounting in SFAS No. 123(R) requires all
      share-based payments to employees, including grants of employee stock options,
      to be recognized in the financial statements based on their fair values. Under
      various plans described below, employees and non-employee directors have
      received stock/unit options and stock/unit grants, and as a result, the Company
      charged to General and administrative expenses compensation cost of $34.6
      million and $4.5 for the three months ended September 30, 2007 and 2006,
      respectively, and $43.5 million and $6.3 million for the nine months ended
      September 30, 2007 and 2006, respectively. At September 30, 2007, the Company
      had unamortized compensation expense of $31.4 million that the Company expects
      to recognize over approximately four years. The Company issues new shares when
      options are exercised or units are converted to shares. Summarized information
      related to each of the Company’s stock incentive compensation plans is described
      in the following paragraphs.




*Atlas
      America Long Term Incentive Plan.* The
      Company adopted a Stock Incentive Plan (the “Plan”) in 2004 which authorized the
      granting of up to 3.0 million shares of the Company’s common stock. The Company
      awarded 20,000 options and 2,147 grants in the nine months ended September
      30,
      2007. During this period, the Company received $917,000 from the exercise of
      54,034 options. There were 1,810,254 options and 14,076 restricted and deferred
      shares outstanding as of September 30, 2007.





*Atlas
      Energy Resources Long-Term Incentive Plan.* In
      December 2006, Atlas Energy adopted a Long-Term Incentive Plan (“ATN LTIP”),
      which authorized the granting of 3,742,000 Atlas Energy Class B common
      units.




Pursuant
      to the plan, options that expire 10 years from the date of grant and vest over
      a
      four year service period have been awarded. ATN uses the Black-Scholes option
      pricing model to estimate the weighted average fair value per option granted
      with the following assumptions:




**Date**
                    **Granted**
              
              **Options****Granted**
              
              **Expected****Dividend
                  Yield**
              
              **Risk-Free****Interest
                  Rate**
              
              **Expected****Volatility**
              
              **Expected****Life**
              
              **Weighted
                    Average****Fair
                  Value**December
                  2006
              
              
              373,752
              
              
              8.0
              %
              
              4.4
              %
              
              25.0
              %
              
              6.25
                  years
              
              $
              2.14January
                  2007
              
              
              1,296,400
              
              
              8.0
              %
              
              4.7
              %
              
              25.0
              %
              
              6.25
                  years
              
              $
              2.41June
                  2007
              
              
              100,000
              
              
              5.1
              %
              
              4.7
              %
              
              25.0
              %
              
              6.25
                  years
              
              $
              5.93July
                  2007
              
              
              135,600
              
              
              5.1
              %
              
              4.7
              %
              
              25.0
              %
              
              6.25
                  years
              
              $
              6.07
  The
        following table summarizes the activity of options for the nine months ended
        September 30, 2007:


**Weighted****Average**
            
            **Aggregate****Weighted**
            
            **Remaining**
            
            **Intrinsic****Average**
            
            **Contractual**
            
            **Value****Units**
            
            **Exercise
                Price**
            
            **Term
                (in years)**
            
            **(in
                thousands)**Outstanding,
                December 31, 2006
            
            
            373,752
            
            $
            21.00
            
            
            8.50Granted
            
            
            1,532,000
            
            
            24.84
            
            
            9.33Forfeited
                or expired
            
            
            (10,100
            )
            
            23.06
            
            
            -Outstanding,
                September 30, 2007
            
            
            1,895,652
            
            $
            24.09
            
            
            9.16
            
            $
            19,119Options
                exercisable, September 30, 2007
            
            
            93,438Available
                for grant
            
            
            1,209,779






25


**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited)





**NOTE
      12 — BENEFIT PLANS** **(continued)**




In
      addition, Atlas Energy has granted restricted and phantom units that vest over
      a
      four year period. Each unit entitles the grantee to one common unit upon
      vesting, as well as distribution equivalent rights during the period the unit
      is
      outstanding. The following table sets forth the ATN LTIP restricted and phantom
      unit activity for the nine months ended September 30, 2007:




**Weighted****Average****Grant
                Date****Units**
            
            **Fair
                Value**Non-vested
                units outstanding,December
                31,
                2006
            
            
            47,619
            
            $
            21.00Granted
            
            
            590,950
            
            
            24.63Vested
            
            
            (11,904
            )
            
            21.00Forfeited
            
            
            (2,000
            )
            
            23.06Non-vested
                units outstanding, September 30, 2007
            
            
            624,665
            
            $
            24.42









*Atlas
      Pipeline Holdings, L.P. Long-Term Incentive Plan.* In
      November 2006, AHD adopted a Long-Term Incentive Plan (“AHD LTIP”), which
      authorized the grant of 2.1 million common units. At September 30, 2007, the
      Company had 1,435,000 phantom units and unit options outstanding under the
      AHD
      LTIP, with 665,000 phantom units and unit options available for grant.




*Atlas
      Pipeline Long-Term Incentive Plan.* Atlas
      Pipeline has a Long-Term Incentive Plan (“APL LTIP”), which authorized the grant
      of 435,000 common units. Only phantom units that vest over a four-year service
      period have been granted under the APL LTIP through September 30, 2007. Each
      unit entitles the grantee to one common unit upon vesting, as well as
      distribution equivalent rights during the period the unit is outstanding. The
      following table represents the APL LTIP phantom unit activity for the nine
      months ended September 30, 2007:





**Shares**
            
            **Weighted**
              **Average**
              **Grant
                Date**
              **Fair
                Value**Outstanding,
                beginning of period
            
            
            159,067
            
            $
            45.51Granted
            
            
            25,095
            
            $
            50.09Matured
            
            
            (38,401
            )
            $
            51.15Forfeited
            
            
            (1,000
            )
            $
            43.05Outstanding,
                end of period
            
            
            144,761
            
            $
            44.75








*Atlas
      Pipeline Incentive Compensation Agreements* .
      Atlas
      Pipeline has incentive compensation agreements which have granted awards to
      certain key employees retained from previously consummated acquisitions. These
      individuals are entitled to receive common units of Atlas Pipeline upon the
      vesting of the awards, which is dependent upon the achievement of certain
      predetermined performance targets through September 30, 2007. At September
      30,
      2007, the predetermined performance targets were achieved and all of the awards
      under the incentive compensation agreements vested. Of the total common units
      to
      be issued under the incentive compensation agreements, 58,824 common units
      will
      be issued prior to December 31, 2007. The remaining common units to be issued
      under the incentive compensation agreements will be determined based upon the
      financial performance of certain Atlas Pipeline assets for the year ended
      December 31, 2008.





Atlas
      Pipeline recognized compensation expense of $31.2 million and $1.2 million
      for
      the three months ended September 30, 2007 and 2006, respectively, and $33.6
      million and $2.8 million for the nine months ended September 30, 2007 and 2006,
      respectively, related to the vesting of awards under these incentive
      compensation agreements. The increase in non-cash compensation expense was
      due
      to an increase in common unit awards estimated by Atlas Pipeline’s management to
      be issued under incentive compensation agreements to certain key employees
      as a
      result of Atlas Pipeline’s acquisition of the Chaney Dell and




26




**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited)





**NOTE
      12 — BENEFIT PLANS** **(continued)**





Midkiff/Benedum
      systems. The ultimate number of common units estimated to be issued under the
      incentive compensation agreements will be determined by the financial
      performance of certain APL assets for the year ended December 31, 2008. The
      vesting period for such awards concluded on September 30, 2007 and all
      compensation expense related to the awards was recorded as of that date. Atlas
      Pipeline’s management anticipates that adjustments will be recorded in future
      periods with respect to the awards under the incentive compensation agreements
      based upon the actual financial performance of the assets in future periods
      in
      comparison to their estimated performance. Based upon Atlas Pipeline’s
      management estimate of the probable outcome of the performance targets at
      September 30, 2007, 877,543 common unit awards are ultimately expected to be
      issued under these agreements, which represents the amount of common units
      expected to be issued under the incentive compensation agreements. Atlas
      Pipeline follows SFAS No. 123(R) and recognized compensation expense related
      to
      these awards based upon the fair value method.




*Supplemental
      Employment Retirement Plan (“SERP”).* The
      Company has 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 is
      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
      September 30, 2007 and 2006 operations were charged $161,000 and $40,000
      respectively, and during the nine months ended September 30, 2007 and 2006
      operations were charged $484,000 and $121,000, respectively, with respect to
      this commitment.




**NOTE
      13** **-** **COMMON
      STOCK**





**Dutch
      Auction Tender Offer**




On
      January 30, 2007, the Company announced that the Board of Directors had
      authorized a “Dutch
      Auction” tender offer for up to 1,950,000 shares of the Company’s common stock
      at an anticipated offer range of between $52.00 and $54.00 per share. The tender
      offer commenced on February 8, 2007 and expired on March 9, 2007. In
      connection with this offering, the Company purchased 1,486,605 shares at a
      cost
      of $80.4 million, including expenses.




**Stock
      Split**




On
      April 27, 2007, the Company’s Board of Directors approved a 3-for-2 stock split
      of the Company’s common stock effected in the form of a 50% stock dividend. All
      shareholders of record as of May 15, 2007 received one additional share of
      common stock for every two shares of common stock held on that date. The
      additional shares of common stock were distributed on May 25, 2007. Information
      pertaining to shares and earnings per share has been restated in the
      accompanying financial statements and notes to the consolidated financial
      statements to reflect this split.


27








**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited **)**







**NOTE
      14 - CASH DISTRIBUTIONS**




The
      Company receives quarterly cash distributions from Atlas Pipeline Holdings
      and
      Atlas Energy Resources according to the policies described below.




*Atlas
      Pipeline Holdings Cash Distributions.* Upon
      completion of its initial public offering, AHD adopted a cash distribution
      policy under which it distributes, within 50 days after the end of each quarter,
      all of its available cash (as defined in its partnership agreement) for that
      quarter to its common unit holders. Distributions declared by AHD and paid
      to
      the Company from inception are as follows:




**Date
                Cash**
              **Distribution
                Paid or Payable**
            
            **For
                Quarter**
              **Ended**
            
            **Cash
                Distribution per**
              **Common
                Limited Partner Unit**
            
            **Total
                Cash Distribution to the Company (in thousands)**November
                19, 2006
            
            
            September
                30, 2006
            
            $
            0.17
            (1)
            $
            2,975February
                19, 2007
            
            
            December
                31, 2006
            
            $
            0.25
            
            $
            4,375May
                18, 2007
            
            
            March
                31, 2007
            
            $
            0.25
            
            $
            4,375August
                17, 2007
            
            
            June
                30, 2007
            
            $
            0.26
            
            $
            4,550November
                19,
                2007 (2)
            
            
            September
                30, 2007
            
            $
            0.32
            
            $
            5,600




__________________________




(1)
            Represents
                a pro-rated cash distribution of $0.24 per common unit for the period
                from
                July 26, 2006, the date of the AHD’s initial public offering, through
                September 30, 2006.





(2)
            Declared
                subsequent to September 30, 2007.




In
      connection with APL’s acquisition of control of the Chaney Dell and
      Midkiff/Benedum systems (see Note 4), the Partnership, which holds all of the
      incentive distribution rights in APL, agreed to allocate up to $5.0 million
      of
      its incentive distribution rights per quarter back to APL through the quarter
      ended June 30, 2009, and up to $3.75 million per quarter thereafter.




*Atlas
      Energy Resources Cash Distributions.* Upon
      completion of its initial public offering, Atlas Energy adopted a cash
      distribution policy under which it distributes, within 45 days after the end
      of
      each quarter, all of its available cash (as defined in its limited liability
      agreement) for that quarter. Distributions declared by Atlas Energy and paid
      to
      the Company from inception are as follows:




**Date
                Cash**
              **Distribution
                Paid or Payable**
            
            **For
                Quarter**
              **Ended**
            
            **Cash
                Distribution per**
              **Common
                Unit**
            
            **Total
                Cash Distribution to the Company (in thousands)**February
                14, 2007
            
            
            December
                31, 2006
            
            $
            0.06
            (1)
            $
            1,806May
                15, 2007
            
            
            March
                31, 2007
            
            $
            0.43
            
            $
            12,944August
                14, 2007
            
            
            June
                30, 2007
            
            $
            0.43
            
            $
            12,944November
                14,
                2007 (3)
            
            
            September
                30, 2007
            
            $
            0.55
            
            $
            16,825
            (2)




__________________________




(1)
            Represents
                a pro-rated cash distribution of $0.42 per unit for the period from
                December 18, 2006, the date of Atlas Energy’s initial public offering,
                through December 31, 2006.




(2)
            Does
                not include a $784,000 incentive distribution which will not be payable
                to
                the Company until 2010, provided the Atlas Energy meets certain minimum
                distribution levels.


(3)
              Declared
                  subsequent to September 30, 2007.
 28


**ATLAS
      AMERICA, INC.**


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


**September
      30, 2007**


(Unaudited)





**NOTE
      15 - ISSUANCE OF SUBSIDIARY UNITS**




In
        July
        2007, Atlas Pipeline Holdings issued 6.5 million common units (an approximate
        27% interest in it) for net proceeds of $167.2 million after offering costs
        in a
        private placement offering. In addition, in July 2007 Atlas Pipeline issued
        25.6
        million common units through a private placement to investors, of which 3.8
        million units were purchased by Atlas Pipeline Holdings. The Company has
        accounted for these offerings in accordance with Staff Accounting Bulletin
        No.
        51, *Accounting
        by the Parent in Consolidation for Sales of Stock by a
        Subsidiary,* (“SAB
        No. 51”). Accordingly, a gain of $53.0 million, net of an income tax provision
        of $34.3 million was recorded in consolidated equity as an increase to paid-in
        capital as well as a corresponding adjustment of $87.3 million to minority
        interest, in the three months ended September 30, 2007.  The Company has
        adopted a policy to recognize gains on such transactions as an increase directly
        to equity rather than as income.  This gain represents the Company’s
        portion of the excess net offering price per unit of each of its subsidiary’s
        units to the book carrying amount per unit.


In
      June
      2007, Atlas Energy issued 24.0 million Class B common and Class D units (an
      approximate 31% interest in it) for net proceeds of $597.5 million after
      offering costs in a private placement offering. The Company has accounted for
      this offering in accordance with Staff Accounting Bulletin No. 51, *Accounting
      by the Parent in Consolidation for Sales of Stock by a
      Subsidiary,* (“SAB
      No. 51”). Accordingly, a gain of $147.9 million, net of an income tax provision
      of $87.5 million was recorded in consolidated equity as an increase to paid-in
      capital as well as a corresponding adjustment of $235.4 million to minority
      interest, in the six months ended June 30, 2007. This gain represents the
      Company’s portion of the excess net offering price per unit of its subsidiary’s
      units to the book carrying amount per unit.




**NOTE
      16 - SUBSEQUENT EVENT**




*Stock
      Dividend.* On
      October 25, 2007, the Company announced that its Board of Directors had declared
      a cash dividend of $0.05 per share of common stock, payable on November 14,
      2007, to holders of record on November 7, 2007.





29





**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/A for fiscal 2006.  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, except as may be requested by applicable
      law.*




**General**





We
      are a
      publicly traded energy company engaged, through subsidiaries, in the
      development, production, gathering and processing of natural gas.




We
      conduct our development and production operations through Atlas Energy
      Resources, LLC (NYSE: ATN), which we refer to as Atlas Energy, or ATN, in which
      we own approximately 49.4%. Atlas Energy has focused its operations in the
      Appalachian Basin, and has expanded into Michigan after its acquisition of
      AGO
      on June 29, 2007.




We
      conduct our natural gas gathering and processing operations through Atlas
      Pipeline Partners, L.P. (NYSE: APL), which we refer to as Atlas Pipeline, or
      APL. The general partner of Atlas Pipeline is Atlas Pipeline Partners GP, LLC,
      which we refer to as Atlas Pipeline GP, a wholly-owned subsidiary of Atlas
      Pipeline Holdings, L.P. (NYSE: AHD), which we refer to as Atlas Pipeline
      Holdings, or AHD, in which we own a 64% interest. Atlas Pipeline GP has a 2%
      general partner interest, an 13.6% limited partner interest and all the
      incentive distribution rights in Atlas Pipeline.





**Recent
      Developments**





*Atlas
      Pipeline Acquisition* .
      On July
      27, 2007, Atlas Pipeline acquired control of Anadarko Petroleum Corporation’s
      (NYSE: APC) (“Anadarko”) 100% interest in the Chaney Dell natural gas gathering
      system and processing plants located in Oklahoma and its approximate 73%
      interest in the Midkiff/Benedum natural gas gathering system and processing
      plants located in Texas (the “Assets”). The
      Chaney Dell System includes 3,470 miles of gathering pipeline and three
      processing plants, while the Midkiff/Benedum System includes 2,500 miles of
      gathering pipeline and two processing plants. The transaction was effected
      by
      the formation of two joint venture companies which will own the respective
      systems, to which Atlas Pipeline has contributed $1.85 billion and Anadarko
      contributed the Assets.





In
      connection with this acquisition, APL has reached an agreement with Pioneer
      Natural Resources Company (NYSE: PXD - “Pioneer”), which currently holds an
      approximate 27.2% interest in the Midkiff/Benedum system, whereby Pioneer will
      have an option to buy up to an additional 14.6% interest in the Midkiff/Benedum
      system on June 15, 2008, and up to an additional 7.4% interest on June 15,
      2009.
      If the option is fully exercised, Pioneer would increase its interest in the
      system to approximately 49%. Pioneer would pay approximately $230 million for
      the additional 22% interest if fully exercised. APL will manage and control
      the
      Midkiff/Benedum system regardless of whether Pioneer exercises the purchase
      options.





APL funded
      the purchase price in part from the private placement of 25.6 million common
      limited partner units at a negotiated purchase price of $44.00 per unit,
      generating gross proceeds of $1.125 billion. AHD purchased 3.8 million of the
      25.6 million common limited partner units issued by APL for $168.8 million
      and
      funded this through the private placement of 6.25 million of its common units
      to
      investors at a negotiated price of $27.00 per unit, yielding gross proceeds
      of
      $168.8 million (or net proceeds of $167.0 million, after underwriting fees
      and
      other transaction costs). APL also received a capital contribution from AHD
      of
      $23.1 million in order for AHD to maintain its 2.0% general partner interest
      in
      APL. AHD funded this capital contribution and the underwriting fees and other
      transaction costs related to its private placement of common units through
      borrowings under its revolving credit facility of $25.0 million. AHD, which
      holds all of the incentive distribution rights as the General Partner of APL,
      has also agreed to allocate up to $5.0 million of its incentive distribution
      rights per quarter back to APL through the quarter ended June 30, 2009, and
      up
      to $3.75 million per quarter thereafter. APL
      funded the remaining purchase price from an $830.0 million senior secured term
      loan which matures in July 2014 and a new $300.0 million senior secured
      revolving credit facility that matures in July 2013.





30




*Atlas
      Energy Acquisition* .
      On June
      29, 2007, Atlas Energy acquired DTE Gas & Oil Company, or DGO, for a
      purchase price of $1.268 billion, including related expenses, adjustments for
      working capital of $10.4 million and current year capital expenditures of $19.0
      million. Assets acquired include interests in approximately 2,210 natural gas
      wells with estimated proved reserves of approximately 610.6 billion cubic feet
      of natural gas equivalents, located in the northern lower peninsula of Michigan,
      299,500 net developed acres and 65,600 net undeveloped acres. Subsequent to
      the
      acquisition, DGO changed its name to Atlas Gas & Oil Company, or
      AGO. With this acquisition, Atlas Energy increased its natural gas and oil
      production as well as entered into a new region that offers additional
      opportunities to expand its operations. In order to produce methane from the
      Antrim Shale, water must be drawn off first, a process that takes 3 to 12
      months. As a result, we don’t believe our Michigan business unit wells are
      compatible with our investment partnership and intend to drill those wells
      for
      our own account.




To
      fund the acquisition, Atlas Energy borrowed $713.9 million on its new credit
      facility and completed a private placement of 7,298,181 Class B common units
      and
      16,702,828 Class D units to a group of institutional investors at a weighted
      average price of $25.00 per unit for net proceeds of $597.5 million. Proceeds
      of
      $52.5 million were used to pay the outstanding balance of Atlas
      Energy ’s
      credit
      facility with Wachovia Bank.




*Investment
      by Atlas Lightfoot, LLC.* Through
      September 30, 2007, our subsidiary, Atlas Lightfoot, LLC, has invested $10.4
      million in Lightfoot Capital Partners LP, or Lightfoot, and will own
      approximately 18 % of Lightfoot Capital Partners GP, LLC, the general partner
      of
      Lightfoot. We have committed to invest a total of $20.0 million in Lightfoot.
      We
      will also receive certain co-investment rights until such point as Lightfoot
      raises additional capital through a private offering to institutional investors
      or a public offering. Lightfoot has initial equity funding commitments of
      approximately $160.0 million and intends to focus its investments primarily
      on
      incubating new master limited partnerships, or MLPs, and providing capital
      to
      existing MLPs in need of additional equity or structured debt. Lightfoot will
      concentrate on assets that are MLP-qualified such as infrastructure, coal,
      and
      other asset categories and intends to form new MLPs in partnership with
      management teams in sectors that are under-utilized by the MLP structure.





*Gains
      on sales of subsidiary units.* In July
      2007, Atlas Pipeline Holdings issued 6.5 million common units (an approximate
      27% interest in it) for net proceeds of $167.2 million after offering costs
      in a
      private placement offering. In addition, in July 2007 Atlas Pipeline issued
      25.6
      million common units through a private placement to investors, of which 3.8
      million units were purchased by Atlas Pipeline Holdings. The Company has
      accounted for these offerings in accordance with Staff Accounting Bulletin
      No.
      51, *Accounting
      by the Parent in Consolidation for Sales of Stock by a
      Subsidiary,* (“SAB
      No. 51”). Accordingly, a gain of $53.0 million, net of an income tax provision
      of $34.3 million was recorded in consolidated equity as an increase to paid-in
      capital as well as a corresponding adjustment of $87.3 million to minority
      interest, in the three months and nine months ended September 30, 2007. The
      Company has adopted a policy to recognize gains on such transactions as
      increases directly to equity rather than as income. This gain represents the
      Company’s portion of the excess net offering price per unit of AHD’s units to
      the book carrying amount per unit.





In
      June
      2007, Atlas Energy issued 24.0 million Class B common and Class D units (an
      approximate 31% interest in it) for net proceeds of $597.5 million after
      offering costs in a private placement offering. The Company has accounted for
      this offering in accordance with Staff Accounting Bulletin No. 51, *Accounting
      by the Parent in Consolidation for Sales of Stock by a
      Subsidiary,* (“SAB
      No. 51”). Accordingly, a gain of $147.9 million, net of an income tax provision
      of $87.5 million was recorded in consolidated equity as an increase to paid-in
      capital as well as a corresponding adjustment of $235.4 million to minority
      interest, in the six months ended June 30, 2007. This gain represents the
      Company’s portion of the excess net offering price per unit of Atlas Energy’s
      units to the book carrying amount per unit.




*Cash* *Dividend.* On
      October 25, 2007, our Board of Directors declared a cash dividend of $.05 per
      share, payable on November 14, 2007, to shareholders of record on November
      7,
      2007.




**Business
      Segments**





We
      operate two primary business segments:





·
            Our
                development and production segment which consists of our interest
                in Atlas
                Energy and includes well construction and completionand production from our interests in oil and gas
                properties.




·
            Our
                natural gas gathering and processing segment, which consistsof
                our interest in AHD, who owns the general partner ofAPL,
                a midstream energy service provider engaged in the transmission,
                gathering
                and processing of natural gas in the Mid-Continent and Appalachian
                regions.




31




**General
      Trends and Outlook**





*Atlas
      Pipeline.* The
      midstream natural gas industry links the exploration and production of natural
      gas and the delivery of its components to end-use markets and provides natural
      gas gathering, compression, dehydration, treating, conditioning, processing,
      and
      fractionation and transportation services. This industry group is generally
      characterized by regional competition based on the proximity of gathering
      systems and processing plants to natural gas producing wells.




Atlas
      Pipeline faces competition for natural gas transportation and in obtaining
      natural gas supplies for its processing and related services operations.
      Competition for natural gas supplies is based primarily on the location of
      gas-gathering facilities and gas-processing plants, operating efficiency and
      reliability, and the ability to obtain a satisfactory price for products
      recovered. Competition for customers is based primarily on price, delivery
      capabilities, and maintenance of high-quality customer relationships. Many
      of
      Atlas Pipeline’s competitors operate as master limited partnerships and enjoy a
      cost of capital comparable to and, in some cases lower than, theirs. Other
      competitors, such as major oil and gas and pipeline companies, have capital
      resources and control supplies of natural gas substantially greater than theirs.
      Smaller local distributors may enjoy a marketing advantage in their immediate
      service areas. Atlas Pipeline believes the primary difference between it and
      some of its competitors is that they provide an integrated and responsive
      package of midstream services, while some of their competitors provide only
      certain services. Atlas Pipeline believes that offering an integrated package
      of
      services, while remaining flexible in the types of contractual arrangements
      that
      it offers producers, allows it to compete more effectively for new natural
      gas
      supplies in their regions of operations.





As
      a
      result of Atlas Pipeline’s POP and keep-whole contracts, its results of
      operations and financial condition substantially depend upon the price of
      natural gas and NGLs. Atlas Pipeline believes that future natural gas prices
      will be influenced by supply deliverability, the severity of winter and summer
      weather and the level of United States economic growth. Based on historical
      trends, Atlas Pipeline generally expects NGL prices to follow changes in crude
      oil prices over the long term, which it believes will in large part be
      determined by the level of production from major crude oil exporting countries
      and the demand generated by growth in the world economy. The number of active
      oil and gas rigs has increased in recent years, mainly due to recent significant
      increases in natural gas prices, which could result in sustained increases
      in
      drilling activity during the current and future periods. However, energy market
      uncertainty could negatively impact North American drilling activity in the
      short term. Lower drilling levels over a sustained period would have a negative
      effect on natural gas volumes gathered and processed.





*Atlas
      Energy.* As a
      driller for and producer of natural gas, Atlas Energy’s results of operations
      and financial condition, like those of Atlas Pipeline, substantially depend
      on
      the price of natural gas and are affected by the same factors. Because of the
      current high levels of natural gas prices Atlas Energy expects that not
      withstanding short-term market uncertainty that may cause short-term declines
      in
      drilling activity, there will continue to be relatively high levels of natural
      gas-related drilling in the United States as producers seek to increase their
      level of natural gas production.





However,
      fluctuations in energy prices can greatly affect production rates and
      investments by third parties in the development of new natural gas reserves,
      including investments in our drilling investment partnerships. Significant
      factors that may impact future commodity prices include developments in the
      issues currently impacting Iraq and Iran and the Middle East in general; the
      extent to which members of the Organization of Petroleum Exporting Countries
      and
      other oil exporting nations are able to continue to manage oil supply through
      export quotas; and overall North American gas supply and demand fundamentals,
      including the impact of increasing liquefied natural gas deliveries to the
      United States. Although Atlas Energy cannot predict the occurrence of events
      that will affect future commodity prices or the degree to which these prices
      will be affected, the prices for commodities that it produces will generally
      approximate market prices in the geographic region of the
      production.




In
      order
      to address, in part, volatility in commodity prices, Atlas Energy has
      implemented a hedging program that is intended to reduce the volatility in
      its
      gas production revenues. Under that program, Atlas Energy has financial hedges
      in place for approximately 84% of its expected production for the twelve months
      ended September 30, 2008. This policy mitigates, but does not eliminate, its
      sensitivity to short-term changes in commodity prices. Please read
“— Quantitative and Qualitative Disclosures About Market
      Risk.”





32







Atlas
      Energy believes that current natural gas prices will continue to cause
      relatively high levels of natural gas-related drilling in the United States
      as
      producers seek to increase their level of natural gas production. Although
      the
      number of natural gas wells drilled in the United States has increased overall
      in recent years, a corresponding increase in production has not been realized,
      primarily as a result of smaller discoveries and the decline in production
      from
      existing wells. Atlas Energy believes that an increase in United States drilling
      activity, additional sources of supply such as liquefied natural gas, and
      imports of natural gas will be required for the natural gas industry to meet
      the
      expected increased demand for, and to compensate for the slowing production
      of,
      natural gas in the United States. The areas in which it operates are
      experiencing significant drilling activity as a result of recent high natural
      gas prices, new increased drilling for deeper natural gas formations and the
      implementation of new exploration and production techniques.




While
      Atlas Energy anticipates continued high levels of exploration and production
      activities in the areas in which it operates, fluctuations in energy prices
      can
      greatly affect production rates and investments by third parties in the
      development of new natural gas reserves. Drilling activity generally decreases
      as natural gas prices decrease.





Inflation
      in the United States did not have a material impact on our results of operations
      for the nine month periods ended September 30, 2007 and 2006. It may in the
      future, however, increase the cost to acquire or replace property, plant and
      equipment, and may increase the costs of labor and supplies. To the extent
      permitted by competition and our existing agreements, we have and will continue
      to pass along increased costs to our investors and customers in the form of
      higher fees.




**Results
      of Operations**


***Well
      Construction and Completion***





Our
      well construction and completion 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**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,****2007**
              
              **2006**
              
              **2007**
              
              **2006**Average
                  construction and completion revenue per well
              
              $
              361
              
              $
              301
              
              $
              322
              
              $
              295Average
                  construction and completion cost per well
              
              
              314
              
              
              262
              
              
              280
              
              
              256Average
                  construction and completion gross profit per well
              
              $
              47
              
              $
              39
              
              $
              42
              
              $
              39Gross
                  profit margin
              
              $
              13,477
              
              $
              6,604
              
              $
              31,414
              
              $
              17,652Gross
                  profit percent
              
              
              13
              %
              
              13
              %
              
              13
              %
              
              13
              %Net
                  wells drilled
              
              
              286
              
              
              168
              
              
              748
              
              
              459


Our
      well construction and completion segment margin was $13.5 million and $31.4
      million in the three months and nine months ended September 30, 2007
      respectively, an increase of $6.9 million (104%) and $13.7 million (78%) from
      $6.6 million and $17.7 million in the three months and nine months ended
      September 30, 2006, respectively. During the three months ended September 30,
      2007, the increase of $6.9 million in segment margin was attributable to an
      increase in the number of wells drilled ($5.6 million) and an increase in the
      gross profit per well ($1.3 million). During
      the nine months ended September 30, 2007, the increase of $13.7 million in
      segment margin was attributable to an increase in the number of wells drilled
      ($12.1 million) and an increase in the gross profit per well ($1.6 million). The
      increase in the number of wells drilled of 289 in the nine months ended
      September 30, 2007 as compared to September 30, 2006 is the result of an
      increase in our fundraising in 2007. It should be noted that “Liabilities
      associated with drilling contracts” on our balance sheet includes $37.7 million
      of funds raised in the first nine months of calendar 2007 that have not been
      applied to the completion of wells as of September 30, 2007 due to the timing
      of
      drilling operations, and thus had not been recognized as well construction
      and
      completion revenue.  We expect to recognize this amount as revenue in the
      fourth quarter of fiscal 2007. During fiscal 2006 we raised $218.5 million
      and
      plan to raise approximately $340.0 million in fiscal 2007. We anticipate
      favorable oil and gas prices will continue to favorably impact our fundraising
      and therefore our drilling revenues in the remainder of fiscal
      2007.





33


***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**
            
            **Nine
                Months Ended****September
                30,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2007**
            
            **2006**Production
                revenues (in thousands):Gas(1)
                (6)
            
            $
            60,302
            
            $
            19,402
            
            $
            102,439
            
            $
            59,332Oil
            
            $
            2,938
            
            $
            2,489
            
            $
            7,357
            
            $
            7,323Production
                volume:(2)AppalachiaGas
                (Mcf/day)(1)
            
            
            29,324
            
            
            25,955
            
            
            26,220
            
            
            24,064Oil
                (Bbls/day)
            
            
            443
            
            
            416
            
            
            422
            
            
            415Michigan(5)Gas
                (Mcf/day)
            
            
            59,304
            
            
            —
            
            
            59,325
            
            
            —Oil
                (Bbls/day)
            
            
            3
            
            
            —
            
            
            3
            
            
            —Total
                (Mcfe/day)(5)
            
            
            91,304
            
            
            28,451
            
            
            88,095
            
            
            26,554Average
                sales prices:Gas
                (per Mcf)(3) (7)
            
            $
            8.19
            
            $
            8.13
            
            $
            8.55
            
            $
            9.03Oil
                (per Bbl)
            
            $
            71.63
            
            $
            65.01
            
            $
            63.75
            
            $
            64.59Production
                costs:(4)As
                a percent of production revenues
            
            
            13
            %
            
            11
            %
            
            12
            %
            
            10
            %Per
                Mcfe
            
            $
            .99
            
            $
            .93
            
            $
            .95
            
            $
            .92Depletion
                per Mcfe
            
            $
            2.19
            
            $
            2.14
            
            $
            2.24
            
            $
            2.04


(1)
              Excludes
                  sales of residual gas and sales to landowners.(2)
              Production
                  quantities consist of the sum of (i) our proportionate share of
                  production from wells in which we have a direct interest, based
                  on our
                  proportionate net revenue interest in such wells, and (ii) our
                  proportionate share of production from wells owned by the investment
                  partnerships in which we have an interest, based on our equity
                  interest in
                  each such partnership and based on each partnership’s proportionate net
                  revenue interest in these wells.(3)
              Our
                  average sales price before the effects of financial hedging were
                  $6.55 and
                  $7.32 per Mcf for the three months ended September 30, 2007 and
                  2006, and
                  $7.18 and $8.10 per Mcf for the nine months ended September 30,
                  2007 and
                  2006, respectively.(4)
              Production
                  costs include labor to operate the wells and related equipment,
                  repairs
                  and maintenance, materials and supplies, property taxes, severance
                  taxes,
                  insurance and production overhead.(5)
              Amounts
                  represent production volumes related to DGO from the acquisition
                  date
                  (June 29, 2007) to September 30, 2007.(6)
              Excludes
                  non-qualifying hedge gains of $26.3 million associated with the
                  AGO
                  acquisition in the nine months ended September 30,
                  2007.(7)
              Includes
                  $6.5 million in derivative proceeds which were not included as
                  revenue in
                  the three and nine months ended September 30,
                  2007.





Our
      natural gas revenues were $60.3 million and $102.4 million in the three months
      and nine months ended September 30, 2007, respectively, an increase of $40.9
      million (211%) and $43.1million (73%) from $19.4 million and $59.3 million
      in
      the three and nine months ended September 30, 2006, respectively. The increases
      were attributable to volumes
      associated with our Michigan operations acquired on June 29, 2007 and a 13
      %
      increase and 9% increases in production volumes in our Appalachian operating
      area in the three months and nine months ended September 30, 2007, respectively.
      The $40.9 million increase in natural gas revenues in the three months ended
      September 30, 2007 consisted of $42.6 million attributable to increases in
      production volumes and $1.7 million attributable to decreases in natural gas
      sales prices. The $43.1 million increase in natural gas revenues in the nine
      months ended September 30, 2007 consisted of $49.6 million attributable to
      increases in production volumes and $6.5 million attributable to decreases
      in
      natural gas sales prices.





34








The
      increase in our gas production volumes of 62,673 Mcf/d and 61,481 Mcf/d in
      the
      three months and nine months ended September 30, 2007 as compared to September
      30, 2006, resulted from the acquisition of DTE Gas & Oil Company on June 29,
      2007 and production associated with new wells drilled for our investment
      partnerships. We believe that gas volumes will continue to be favorably impacted
      in the remainder of 2007 with our acquisition of AGO and as ongoing projects
      to
      extend and enhance the gathering systems of Atlas Pipeline are completed and
      wells drilled are connected in these areas of expansion.





Our
      oil
      revenues were $2.9 million and $7.4 million in the three months and nine months
      ended September 30, 2007, respectively, an increase of $449,000 (18%) and an
      increase of $34,000 (0.5%) from $2.5 million and $7.3 million during the three
      months and nine months ended September 30, 2006, respectively. The increase
      in
      the three months ended September 30, 2007 resulted from a 7% increase in
      production volumes and a 10 % increase in the average sales price of oil. The
      increase in the nine months ended September 30, 2007 resulted from a 1% decrease
      in the average sales price of oil and a 2% increase in production volumes.
      The
      $449,000 increase in the three months ended September 30, 2007 consisted of
      $254,000 attributable to increases in sales prices and $195,000 attributable
      to
      volume increases due to an increase in the number of new wells placed into
      production during the three months ended September 30, 2007. The $34,000
      increase in the nine months ended September 30, 2007 consisted of $95,000
      attributable to decreases in sales prices and $129,000 attributable to volume
      increases.





Our
      production costs were $12.0 million and $20.3 million in the three and nine
      months ended September 30, 2007, respectively, an increase of $8.3 million
      (222%) and $9.8 million (93%) from $3.7 million and $10.5 million in the three
      and nine months ended September 30, 2006, respectively. These increases include
      $7.4 million of production costs including, $2.0 million related to production
      taxes associated with our acquisition of AGO on June 29, 2007 as well as
      increases in transportation charges, labor and maintenance costs associated
      with
      an increase in the number of wells we own from the prior year period. The
      transportation fees charged to our wells connected to Atlas Pipeline’s gathering
      system were generally increased as a percent of gas revenues beginning in
      January 2007.





***Transmission,
      Gathering and Processing***





The
      following table presents selected volumetric information related to Atlas
      Pipeline for the periods indicated (in Mcf/day):





**Three
                Months Ended**
            
            **Nine
                Months Ended****September
                30,**
            
            **September
                30,****2007**
            
            **2006**
            
            **2007**
            
            **2006**Appalachia
                system throughput volume
            
            
            71,876
            
            
            63,909
            
            
            66,888
            
            
            61,473Velma
                system gathered gas volume
            
            
            63,757
            
            
            62,113
            
            
            62,531
            
            
            61,641Chaney
                Dell system gathered gas volume
            
            
            255,649
            
            
            —
            
            
            255,649
            
            
            —Midkiff
                / Benedum System gathered gas volume
            
            
            150,061
            
            
            —
            
            
            150,061
            
            
            —NOARK
                Ozark Gas Transmission throughput volume
            
            
            325,652
            
            
            226,962
            
            
            311,562
            
            
            236,331Elk
                City/Sweetwater system gathered gas volume
            
            
            299,450
            
            
            284,461
            
            
            298,724
            
            
            270,957Combined
                throughput volume
            
            
            1,166,445
            
            
            637,445
            
            
            1,145,415
            
            
            630,402




The
      average throughput volume on Atlas Pipeline's gathering systems  for the
      three months and nine months ended September 30, 2007
      respectively increased by 529,000 Mcf/day (82%) and 515,000 Mcf/day (83%)
      primarily due to gathered volumes on the Cheney Dell and Midkiff/ Benedum
      systems, which were acquired in July 2007. Average throughput volume also
      increased due to higher volumes for the NOARK and Elk City systems. The average
      Ozark Gas /Transmission volume was 325.7 MMcfd for the three months and nine
      months ended September 30, 2007, respectively, an increase of 43% and 32% from
      the prior year comparable periods. The Elk City system, which includes the
      newly
      constructed Sweetwater plant averaged 299.5 MMcfd and 298.7 MMcfd for the three
      months and nine months ended September 30, 2007, respectively, an increase
      of 5%
      and 10% from the comparable prior year periods.




35








Atlas
      Pipeline’s transmission, gathering and processing revenues were $239.9 million
      and $452.6 million for the three months and nine months ended September 30,
      2007
      respectively, an increase of $124.5 million and $109.9 million from $115.4
      million and $342.7 million for the three months and nine months ended September
      30, 2006 respectively. The increase was primarily attributable to revenue
      contributions from the newly acquired Chaney Dell and Midkiff/Benedum systems
      of
      $131.3 million, and to an increase of $1.6 million and $27.6 million for the
      three months and nine months ended September 30, 2007, respectively, from the
      Elk City Sweetwater System due primarily to an increase in volumes, including
      processing volumes from the newly constructed Sweetwater gas plant. This was
      partially offset by a decrease of $20.8 million for the nine months ended
      September 30, 2007 from Atlas Pipeline’s NOARK system due to lower natural gas
      sales volumes on its gathering systems. Transportation and compression revenue
      increased by $7.7 million and $14.5 million for the three months and nine months
      ended September 30, 2007, respectively, primarily due to an increase of $3.6
      million and $8.6 million from the transportation revenues associated with the
      NOARK system.





Transmission,
      gathering, and processing revenues above include revenues earned by Atlas
      Pipeline’s Appalachian segment under its master gas gathering agreement with us
      or Atlas Energy which is eliminated upon consolidation in our financial
      statements. Revenues eliminated under this agreement were approximately $8.6
      million and $7.0 million for the three months ended September 30, 2007 and
      2006
      respectively, and $24.8 million and $22.7 million for the nine months ended
      September 30, 2007 and 2006, respectively. In addition, we receive
      transportation revenues from our investment partnerships for gathering services
      of $3.5 million, $3.0 million, $10.5 million and $6.9 million for the same
      periods.




Our
      transmission, gathering and processing costs and expenses were $187.4 million
      and $377.7 million for the three months and nine months ended September 30,
      2007
      respectively, an increase of $91.2 million (95%) and $106.7 million (39%)
      from $96.2 million and $271.0 million for the three months and nine months
      ended
      September 30, 2006 respectively. The increase was primarily related to
      expenses from Atlas Pipelines’ Anadarko acquisition on July 27, 2007 and higher
      NOARK and Appalachia system operating and maintenance costs as a result of
      additional capacity and additional well connections.





***Administration
      and Oversight***





Our
      administrative and oversight fee represents supervision and administrative
      fees
      earned for drilling wells and ongoing monthly management fees from our
      investment partnerships. These fees were $5.4 million and $13.3 million in
      the
      three months and nine months ended September 30, 2007 respectively, an increase
      of $2.4 million (79%) and $4.8 million (57%) from $3.0 million and $8.5 million
      in the three months and nine months ended September 30, 2006 respectively.
      These
      increases are attributable to an increase in the number of wells drilled and
      managed for our investment partnerships in the three months and nine months
      ended September 30, 2007 as compared to 2006.





***Well
      Services***





Our
      well services revenues were $4.8 million and $12.7 million in the three months
      and nine months ended September 30, 2007 respectively, an increase of $1.5
      million (45%) and $3.2 million (34%) from $3.3 million and $9.5 million in
      the
      three months and nine months ended September 30, 2006 respectively. These
      increases resulted from an increase in the number of wells operated for our
      investment partnerships due to additional wells drilled in the twelve months
      ended September 30, 2007.





Our
      well services expenses were $2.5 million and $6.7 million in the three months
      and nine months ended September 30, 2007 respectively, an increase of $763,000
      (44%) and $1.2 million (21%) from $1.8 million and $5.5 million in the three
      months and nine months ended September 30, 2006 respectively.  These
      increases were attributable to an increase in wages, benefits, and field office
      expenses associated with an increase in employees due to the increase in the
      number of wells we operate for our investment partnerships.





***Gain
      (Loss) on Mark-to-Market Derivatives***





Our
      gain (loss) on mark-to-market derivatives represents non-cash gains and losses
      recognized on Atlas Energy’s and APL’s derivatives. Atlas Energy recognized a
      $26.3 million non-cash gain related to the change in value of derivative
      contracts associated with the acquisition of AGO in the nine months ended
      September 30, 2007 (see Note 9). Atlas Pipeline recognized an $18.8 million
      non-cash loss related to the change in value of derivative contracts associated
      with the acquisition of Anadarko in the nine months ended September 30, 2007
      (See Note 9). The contracts entered into by Atlas Energy and Atlas Pipeline
      were
      derivative contracts to hedge the projected production volume of their
      anticipated acquisitions (see Note 4). The production volumes of the assets
      to
      be acquired were not considered to be “probable forecasted production” under
      SFAS No. 133 at the date these derivatives were entered into because the
      acquisition of the assets had not yet been completed. Accordingly, we recorded
      the instruments as non-qualifying for hedge accounting at inception with
      subsequent changes in the derivative values recorded within our consolidated
      statements of income. Upon closing of the acquisitions, the production volumes
      of the assets acquired were considered “probable forecasted production” under
      SFAS No. 133 and we evaluated these derivatives under the cash flow hedge
      criteria in accordance with SFAS No. 133




36




***General
      and Administrative***





Our
      general and administrative expenses were $48.9 million and $85.2million in
      the
      three months and nine months ended September 30, 2007 respectively, an increase
      of $35.8 million and $51.0 million from $13.1 million and $34.2 million in
      the
      three months and nine months ended September 30, 2006 respectively. These
      expenses include, among other things, salaries and benefits not allocated to
      a
      specific segment, costs of running our corporate office, partnership syndication
      activities and outside services. The increase of $35.8 million in the three
      months ended September 30, 2007 is principally attributable to $37.2 million
      related to employee costs including benefits and stock compensation awards.
      The
      increase of $51.0 million in the nine months ended September 30, 2007 is
      principally attributable to $45.9 million related to employee costs including
      benefits and stock compensation awards plus a $4.9 million increase in audit,
      tax and professional fees, including $3.9 million in fees related to hedges
      entered into associated with the AGO acquisition.





***Depletion***





Our
      depletion of oil and gas properties as a percentage of oil and gas revenues
      was
      29% and 27% in the three months and nine months ended September 30, 2007
      respectively, compared to 26% and 22% in the three months and nine months ended
      September 30, 2006 respectively. Depletion expense per Mcfe was $2.19 and $2.24
      in the three and nine months ended September 30, 2007, an increase of $0.05
      (2%)
      and $0.20 (9%) per Mcfe from $2.14 and $2.04 in the three and nine months ended
      September 30, 2006, respectively. Increases in our depletable basis and
      production volumes caused depletion expense to increase $12.8 million (228%)
      and
      $15.2 million (103%) to $18.4 million and $30.0 million in the three months
      and
      nine months ended September 30, 2007, respectively, compared to $5.6
      million and $14.8 million in the three and nine months ended September 30,
      2006.
      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***




Depreciation
      and amortization increased $10.0 million (146%) and $12.7 million (69%) to
      $16.8
      million and $31.0 million in the three months and nine months ended September
      30, 2007 respectively compared to $6.8 million and $18.3 million in the three
      months and nine months ended September 30, 2006 respectively. This was primarily
      due to the increased asset base associated with Atlas Energy’s acquisition of
      AGO on June 29, 2007 and Atlas Pipeline’s acquisition of the Anadarko assets on
      July 27, 2007 and expansion capital expenditures, particularly the construction
      of the Atlas Pipeline’s Sweetwater processing facility.





***Interest
      Expense***





Our
      interest expense was $37.5 million and $53.7 million in the three months and
      nine months ended September 30, 2007 respectively, an increase of $31.6 million
      and $34.3 million from $5.9 million and $19.4 million in the three and nine
      months ended September 30, 2006 respectively. These increases resulted primarily
      from an increase in outstanding borrowings by Atlas Energy of $739.0 million
      under its credit facility, borrowings by Atlas Pipeline of its term loan of
      $830.0 million, and AHD’s credit facility of $25.0 million. These borrowings
      were used to fund Atlas Energy’s and Atlas Pipeline’s acquisitions and capital
      expenditures during the nine months ended September 30, 2007





***Minority
      Interests***




At
      September 30, 2007, we owned 10% of
      the partnership interest in Atlas Pipeline through our ownership in AHD. Because
      we control the operations of APL, we include it in our consolidated financial
      statements and show the ownership by the public as minority interests. The
      minority interest income in AHD’s loss was $22.5 and $43.9 million for the three
      and nine months ended September 30, 2007 respectively and an expense of
      $2.0 million and $13.0 million for the three and nine months ended September
      30,
      2006 respectively, a decrease of $24.5 million and $56.9 million in the three
      and nine months ended September 30, 2007 respectively. This decrease is a result
      of a decrease in Atlas Pipeline’s net income.




After
      the
      initial public offering of Atlas Energy on December 18, 2006 and the issuance
      of
      private placement Class B common and Class D units on June 29, 2007,
      approximately 51.0% is owned by the general public. We include Atlas Energy
      in
      our consolidated financial statements and show the ownership by the pubic as
      a
      minority interest. The minority interest expense in Atlas Energy was $16.1
      million and $28.9 million for the three and nine months ended September 30,
      2007, respectively.





***Provision
      for Income Taxes***





Our
      effective tax rate was 28% and 31% for the three months and nine months ended
      September 30, 2007 as compared to 39% and 40% for the three months and nine
      months ended September 30, 2006 respectively. For the three months and nine
      months ended September 30, 2007, our effective income tax rates decreased
      compared to prior year similar periods substantially due to revisions of our
      previous estimates as a result of anticipated state and local taxes in
      connection with the acquisition of AGO.  Currently, it is our expectation
      that our effective income tax rate will approximate 32% for the year ended
      December 31, 2007.




37




**Liquidity
      and Capital Resources**




*General.* We
      fund operations through our subsidiaries by a combination of sources, including
      cash generated by operations, capital raised through drilling investment
      partnerships, the issuance of units and use of our credit facilities. Atlas
      Pipeline funds its operations through a combination of cash generated by
      operations, its credit facility and sales of its common units.




The
      following table sets forth our sources and uses of cash (in
      thousands):





**Nine
                Months Ended****September
                30,****2007**
            
            **2006**Provided
                by operations
            
            $
            95,385
            
            $
            43,845Used
                in investing activities
            
            
            (3,370,889
            )
            
            (138,043
            )Provided
                by financing activities
            
            
            3,203,915
            
            
            103,735Increase
                in cash and cash equivalents
            
            $
            (71,589
            )
            $
            9,537




We
      had $113.8 million in cash and cash equivalents on hand at September 30, 2007,
      as compared to $185.4 million at December 31, 2006. We had a working
      capital of $2 3.8
      million, a decrease of $56.6 million from working capital of $80.4 million
      at
      December 31, 2006. The decrease in our working capital relates primarily to
      a net increase in our cash and accounts receivable of $15.3 million and a
      corresponding increase in our current liabilities of $83.0 million. These
      increases are due primarily to the AGO and Anadarko acquisitions. Our working
      capital also fluctuates in relation to the level of drilling activities at
      any
      given date, which is related to the timing of funds raised and the subsequent
      use of those funds, and also as a result of commodity prices.




At
      September 30, 2007, the borrowing base under Atlas Energy’s credit facility is
      $850.0 million, and it has $109.9 million available. At September 30, 2007,
      Atlas Pipeline has a borrowing base of $300.0 million under its credit facility,
      of which $266.5 million is available. At September 30, 2007, AHD has a borrowing
      base of $50.0 million, of which $25.0 million is available. See Note 8 to our
      Consolidated Financial Statements for information on Atlas Energy’s, Atlas
      Pipeline’s and AHD’s credit facilities at September 30, 2007.





*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, competition for natural gas transportation and in obtaining gas supplies
      for our processing operations, interest rates and our ability to raise funds
      from our drilling investment partnerships.  Net ** cash
      provided by operating activities increased $51.5 million in the nine months
      ended September 30, 2007 to $95.4 million from $43.9 million in the nine months
      ended September 30, 2006, substantially as a result of the following:





•
            an
                increase in net income before depreciation and amortization of $39.3
                million in the nine months ended September 30, 2007 as compared to
                the
                prior year period, principally as a result of income included in
                our
                financial statements from our acquisitions, higher gross margins
                related
                to administrative and oversight and well services, and drilling profits;•
            an
                increase in non-cash items of $57.7 million related to losses on
                our hedge
                values and compensation expense resulting from grants under long-term
                incentive plans;•
            changes
                in minority interests and distributions paid to minority interests
                decreased by $32.9 million due to a decrease in Atlas Pipeline’s earnings
                and higher distributions paid to minority interests;•
            changes
                in our deferred tax liability increased by $33.4 million as compared
                to
                the nine months ended September 30, 2006 which reflects the impact
                of
                timing differences between accounting and tax records.  The $33.4
                million increase is primarily related to the reversal of a $29.8
                million
                income tax valuation allowance recorded in July 2006 related to the
                gain
                on sale of subsidiary units issued by AHD.•
            changes
                in operating assets and liabilities decreased operating cash flow
                by $48.8
                million in the nine months ended September 30, 2007, compared to
                the nine
                months ended September 30, 2006.





This
      change in operating assets and liabilities is primarily a result of the
      following:





•
            an
                increase of $1.1 million in accounts payable and accrued liabilities,
                including liabilities associated with our drilling contracts. Our
                level of
                liabilities associated with drilling contracts is dependent upon
                the
                remaining amount of our drilling obligations at any balance sheet
                date,
                which is dependent upon the timing of funds raised through our investment
                partnerships;




38




•
            a
                decrease of $54.7 million in accounts receivable and prepaid expenses,
                primarily due to a decrease in Atlas Pipeline’s accounts receivable
                resulting from a decrease in commodity prices; and•
            an
                increase of $4.8 million in changes in other assets and liabilities.





*Cash
      flows from investing activities.* **** Cash
      used in our investing activities increased $3.233 billion in the nine months
      ended September 30, 2007, to $3.371 billion from $138.0 million in the nine
      months ended September 30, 2006, primarily as a result of our AGO and Anadarko
      acquisitions for a total of $3.118 billion and a $71.4 million increase in
      capital expenditures related to an increase in the number of wells we drilled,
      and a $31.9 million increase in capital expenditures related to pipeline
      expansions.





*Cash
      flows from financing activities.* Cash
      provided by in our financing activities increased $3.100 billion in the nine
      months ended September 30, 2007, to $3.204 billion from $103.7 million in the
      nine months ended September 30, 2006, as a result of the following:





•
            we
                repurchased $80.4 million of common stock in a Dutch tender offer
                in the
                nine months ended September 30, 2007; repurchases were $29.9 million
                in
                the nine months ended September 30, 2006;•
            net
                borrowings on debt increased by $1.621 billion in the nine months
                ended
                September 30, 2007 as compared to the prior year similar period
                principally as a result of the borrowings under Atlas Energy’s and Atlas
                Pipeline’s credit facilities, to fund the AGO and Anadarko
                acquisitions:•
            we
                received proceeds of $597.5 million from Atlas Energy’s issuance of Class
                B common and Class D units;•
            we
                received proceeds of $1.114 billion from AHD’s and Atlas Pipeline’s
                issuance of common and preferred units in the nine months ended September
                30, 2007 compared to $134.1 million received, for an increase of
                $979.5
                million in 2006; and,•
            our
                deferred financing costs paid increased $8.0
                million.





*Capital
      Requirements:* During the nine months ended September 30, 2007, our capital expenditures
      related primarily to our acquisitions. Atlas Energy acquired AGO on June 29,
      2007 which included $1.268 billion in oil and gas properties. Atlas Pipeline
      completed its Anadarko acquisition on July 27, 2007 which included $1.878
      billion in gas gathering and processing plants. We also continue to invest
      in
      our drilling partnerships and expand our pipelines, in which we invested $72.5
      million and $93.7 million, respectively.  For the nine months ended
      September 30, 2007 and the remaining quarter of fiscal 2007, 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 three 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 believe cash flows from operations and amounts
      available under our credit facilities will be adequate to fund our contributions
      to these partnerships.  However, the amount of funds we raise and the level
      of our capital expenditures will vary in the future depending on market
      conditions for natural gas and other factors.





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





**New
      Credit Facility**





Upon
      the
      closing of the acquisition of DTE Gas & Oil Company, Atlas Energy replaced
      its Wachovia Bank Credit facility with a new 5-year, $850.0 million credit
      facility, which is led by J.P. Morgan Chase Bank, N.A. (“J.P. Morgan”), as
      administrative agent, Wachovia Bank, National Association, as syndication agent,
      and other lenders. The J.P. Morgan revolving credit facility has a current
      borrowing base of $850.0 million which will be redetermined semi-annually on
      April 1 and October 1 subject to changes in our oil and gas reserves. The
      initial borrowing base is also scheduled to be reduced to $735.0 million less
      25% of the amount of any issuance of equity or debt securities by Atlas Energy
      at the earlier of June 29, 2008 or the issuance by Atlas Energy of equity or
      debt securities of at least $200.0 million. Up to $50.0 million of the facility
      may be in the form of standby letters of credit. The facility is secured by
      our
      assets and bears interest at either the base rate plus the applicable margin
      or
      at adjusted LIBOR plus the applicable margin, elected at our option. At
      September 30, 2007, the weighted average interest rate on outstanding borrowings
      was 7.5%.





39




Atlas
      Energy is required to maintain specified ratios of current assets to current
      liabilities and debt (as defined in the agreement) to earnings before interest,
      taxes, depreciation, depletion and amortization, or EBITDA. In addition, the
      facility limits sales, leases or transfers of assets and the incurrence of
      additional indebtedness. The facility limits the dividends payable by us if
      an
      event of default has occurred and is continuing or would occur as a result
      of
      such distribution. Atlas Energy was in compliance with these covenants as of
      September 30, 2007. At September 30, 2007, $740.1 million was outstanding under
      this facility including letters of credit of $1.1 million, which are not
      reflected as borrowings on our Consolidated Balance Sheets.





**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/A
      for the year ended December 31, 2006 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
      April 2007, the Financial Accounting Standards Board ( “FASB”)
      issued FASB interpretation No. 39-1, Amendment of FASB Interpretation No. 39, *Offsetting
      of Amounts Related to Certain Contracts* ,
      (“FIN
      39-1”). FIN 39-1 amends FIN 39, which allows an entity to offset fair value
      amounts for the right to reclaim cash collateral or the obligation to return
      cash collateral against fair value amounts recognized for derivative instruments
      executed with the same counterparty under the same master netting arrangement.
      FIN 39-1 is effective for fiscal years beginning after November 15, 2007. We
      do
      not expect the adoption of FIN 39-1 to have an impact on our financial position
      or results of operations.




In
      February 2007, the FASB issued Statement of Financial Accounting Standards
      No. 159, *The
      Fair Value Option for Financial Assets and Financial
      Liabilities,* (“SFAS
      159”). SFAS 159 permits entities to choose to measure eligible financial
      instruments and certain other items at fair value. The objective is to improve
      financial reporting by providing entities with the opportunity to mitigate
      volatility in reported earnings caused by measuring related assets and
      liabilities differently without having to apply complex hedge accounting
      provisions. The Statement will be effective as of the beginning of an entity’s
      first fiscal year beginning after November 15, 2007. The Statement offers
      various options in electing to apply the provisions of this Statement, and
      at
      this time we have not made any decisions on its application to our financial
      position or results of operations.




In
      December 2006, the FASB issued FASB Staff Position (FSP) EITF 00-19-2, *Accounting
      for Registration Payment Arrangements* .
      FSP
      EITF 00-19-2 requires an issuer of financial instruments, such as debt,
      convertible debt, equity shares or warrants, to account for a contingent
      obligation to transfer consideration under a registration payment arrangement
      in
      accordance with Statement 5, *Accounting
      for Contingencies* ,
      and
      FASB Interpretation 14, *Reasonable
      Estimation of the Amount of a Loss* .
      That
      accounting applies regardless of whether the registration payment arrangement
      is
      a provision in a financial instrument or a separate agreement. The FSP requires
      issuers to make certain disclosures for each registration payment arrangement
      or
      group of similar arrangements. The FSP is effective immediately for registration
      payment arrangements and financial instruments subject to those arrangements
      that are entered into or modified subsequent to December 21, 2006, the date
      FSP
      EITF 00-19-2 was issued.




We
      applied the consensus in FSP EITF 00-19-2 effective January 1, 2007. We reviewed
      the penalty terms in the registration rights agreement related to AHD's, Atlas
      Pipeline's, and Atlas Energy’s respective private placement entered into during
      the nine months ended September 30, 2007, pursuant to the guidance in the FSP,
      and determined that the probability of payment is remote under Statement 5
      based
      upon our status of current related filings. As a result, the application of
      FSP
      EITF 00-19-2 did not have an effect on our financial position or results of
      operations.




In
      September 2006, the FASB issued Statement of Financial Accounting Standards
      No. 157, *Fair
      Value Measurement* ,
      (“SFAS
      157”). SFAS 157 addresses the need for increased consistency in fair value
      measurements, defining fair value as the price that would be received to sell
      an
      asset or paid to transfer a liability in an orderly transaction between market
      participants at the measurement date. It also establishes a framework for
      measuring fair value and expands disclosure requirements. SFAS 157 is effective
      for the Company beginning January 1, 2008. We are currently evaluating the
      impact of the adoption of SFAS 157 on our financial position and results of
      operations.




40





We
      adopted the provisions of FASB Interpretation No. 48, *Accounting
      for Uncertainty in Income Taxes,* (“FIN 48”), on January 1, 2007, and FASB Interpretation No. 48-1, *Definition
      of Settlement in FASB Interpretation No. 48* ,
      (“FIN 48-1”). Previously, we had accounted for tax contingencies in accordance
      with Statement of Financial Accounting Standards No. 5, *Accounting
      for Contingencies* . FIN
      48
      clarifies the accounting for income taxes, by prescribing a minimum recognition
      threshold a tax position is required to meet before being recognized in the
      financial statements. FIN 48 also provides guidance on derecognition,
      measurement, classification, interest and penalties, accounting in interim
      periods, disclosure and transition. FIN 48-1 amends FIN 48 to provide guidance
      on how an enterprise should determine whether a tax provision is effectively
      settled for the purpose of recognizing previously unrecognized tax benefits. As
      a result of the implementation of FIN 48 and FIN 48-1, we determined that we
      had
      no liability for unrecognized income tax benefits, upon adoption and through
      September 30, 2007.





We
      file numerous consolidated and separate income tax returns in the United States
      Federal jurisdiction and in many state jurisdictions. We are no longer subject
      to United States Federal income tax examinations for periods ending before
      September 30, 2003 and we are no longer subject to state and local income tax
      examinations by tax authorities for periods ending before September 30, 2002.
      Our policy is to recognize potential accrued interest and penalties related
      to
      unrecognized tax benefits in income tax expense. We do not anticipate that
      total
      unrecognized tax benefits will significantly change within the next twelve
      months.





41





**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 gains or 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
      September 30, 2007.  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
      September 30, 2007, Atlas Energy had an $850.0 million revolving credit facility
      ($739.0 million outstanding at September 30, 2007).  The weighted average
      interest rate for this facility was 7.5% at September 30, 2007.





At
      September 30, 2007, Atlas Pipeline has a new comprised of a senior secured
      term
      loan of $830.0 million and a $300.0 million senior secured revolving credit
      facility ($33.5 million outstanding at September 30, 2007). The weighted average
      interest rate for this facility was 8.0% at September 30, 2007.





Atlas
      Pipeline Holdings has a $50.0 million revolving credit facility ($25.0 million
      outstanding at September 30, 2007). The weighted average interest rate for
      this
      facility was 7.4% at September 30, 2007.





Holding
      all other variables constant, if interest rates hypothetically increased or
      decreased by 10%, our net annual income would change by approximately $2.2
      million.





*Commodity
      Price Risk* . 
      Our major market risk exposure to 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 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..  Through our hedges, we seek to provide a
      measure of stability in the volatile environment of natural gas
      prices.   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 September 30, 2008, we estimate approximately 84% of
      Atlas Energy’s produced natural gas volumes will be sold in this manner, leaving
      its remaining production to be sold at contract prices in the month produced
      or
      at spot market prices.  Atlas Energy’s risk management objective is to lock
      in a range of pricing for expected production volumes. Considering those volumes
      for which we have entered into financial hedge agreements for the twelve months
      ending September 30, 2008, and current indices, a theoretical 10% upward or
      downward change in the price of natural gas would change net income by
      approximately $3.8 million.





Atlas
      Energy formally documents all relationships between hedging instruments and
      the
      items being hedged, including its 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.




42




At
      September 30, 2007, Atlas Energy had 384 open
      natural gas futures contracts related to natural gas sales covering 147.5
      million MMBtus of natural gas (which includes 76.9 million MMBtu covering
      natural gas produced by assets acquired from AGO), maturing through June 30,
      2013 at a combined average settlement price of $8.04 per MMBtu. At September
      30,
      2007 and December 31, 2006, Atlas Energy reflected net derivative assets of
      $50.4 million and $47.5 million, respectively.





On
      May
      18, 2007, Atlas Energy signed a definitive agreement to acquire AGO (see Note
      4). In connection with the financing of this transaction, Atlas Energy agreed
      as
      a condition precedent to closing that it would hedge 80% of its projected
      natural gas volumes for no less than three years from the closing date of the
      transaction. During May 2007, Atlas Energy entered into derivative instruments
      to hedge 80% of the projected production of the assets to be acquired as
      required under the financing agreement. The production volume of the assets
      to
      be acquired was not considered to be “probable forecasted production” under SFAS
      No. 133 at the date these derivatives were entered into because the acquisition
      of the assets had not yet been completed. Accordingly, Atlas Energy recognized
      the instruments as non-qualifying for hedge accounting at inception with
      subsequent changes in the derivative value recorded within revenues in the
      Company’s consolidated statements of income. Atlas Energy recognized non-cash
      income of $26.3 million related to the change in value of these derivatives
      from
      May 22, 2007 to June 28, 2007, which is shown as “Gain on mark-to-market
      derivatives” in the Combined and Consolidated Statements of Income for the nine
      months ended September 30, 2007. Upon closing of the acquisition on June 29,
      2007, the production volume of the assets acquired was considered “probable
      forecasted production” under SFAS No. 133 and Atlas Energy evaluated these
      derivatives under the cash flow hedge criteria in accordance with SFAS No.
      133.





In
      addition, Atlas Energy recognized gains on settled contracts covering natural
      gas production of $4.9 million and $2.0 million for the three months ended
      September 30, 2007 and 2006, and $9.6 million and $4.9 million for nine months
      ended September 30, 2007 and 2006, respectively. As the underlying prices in
      the
      Atlas Energy hedge contracts were consistent with the indices used to sell
      its
      natural gas, there were no gains or losses recognized during the three months
      and nine months ended September 30, 2007 and 2006, respectively and for hedge
      ineffectiveness or as a result of the discontinuance of any cash flow
      hedges.




*Atlas
      Pipeline.* Atlas
      Pipeline also enters into certain financial swaps and option instruments which
      qualify as cash flow hedges in accordance with SFAS No. 133 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 remits
      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 its 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 it is determined that a derivative is not effective as
      a
      hedge or that it has ceased to be an effective hedge due to the loss of
      correlation between the reference prices underlying a hedging instrument and
      the
      underlying commodity, Atlas Pipeline will discontinue hedge accounting for
      the
      derivative and subsequent changes in the derivative fair value, which is
      determined through the utilization of market data, will be recognized
      immediately into earnings. 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.





On
      June
      3, 2007, Atlas Pipeline signed definitive agreements to acquire control of
      certain natural gas gathering systems and processing plants located in Oklahoma
      and Texas (see Note 16). In connection with the financing of this
      transaction, Atlas Pipeline agreed as a condition precedent to closing that
      it
      would hedge 80% of its projected natural gas, NGL and condensate production
      volume for no less than three years from the closing date of the transaction.
      During June 2007, Atlas Pipeline entered into derivative instruments to hedge
      80% of the projected production of the assets to be acquired as required under
      the financing agreements. The production volume of the assets to be acquired
      was
      not considered to be “probable forecasted production” under SFAS No. 133 at the
      date these derivatives were entered into because the acquisition of the assets
      had not yet been completed. Accordingly, Atlas Pipeline recognized the
      instruments as non-qualifying for hedge accounting at inception with subsequent
      changes in the derivative value recorded within revenues in the Company’s
      consolidated statements of income. Atlas Pipeline recognized a non-cash loss
      of
      $19.8 million related to the change in value of these derivatives for the three
      and nine months ended September 30, 2007. Upon closing of the acquisition in
      July 2007, the production volume of the assets acquired was considered “probable
      forecasted production” under SFAS No. 133 and Atlas Pipeline evaluated these
      derivatives under the cash flow hedge criteria in accordance with SFAS No.
      133.




At
      September 30, 2007 and December 31, 2006, Atlas Pipeline reflected net
      derivative liabilities of $92.0 million and $20.1 million, respectively. Atlas
      Pipeline recognized losses of $12.9 million and $4.9 million for the three
      months ended September 30, 2007 and 2006, respectively, and losses of $23.5
      million and $10.5 million for the nine months ended September 30, 2007 and
      2006,
      respectively, within natural gas and liquids revenue in its consolidated
      statements of income related to the settlement of qualifying hedge instruments.
      Atlas Pipeline recognized a loss of $8.4 million and a gain of $3.7 million
      within “Other, net” on the Company’s consolidated statements of income related
      to the change in market value of non-qualifying derivatives and the ineffective
      portion of qualifying derivatives, respectively, for the three months ended
      September 30, 2007. Atlas Pipeline recognized a loss of $39.3 million and a
      gain
      of $4.6 million within “Other, net” in the Company’s consolidated statements of
      income related to the change in market value of non-qualifying derivatives
      and
      the ineffective portion of qualifying derivatives, respectively, for the nine
      months ended September 30, 2007. Atlas Pipeline recognized losses of $3.0
      million for the three and nine months ended September 30, 2007, within “Other,
      net” in its consolidated statements of income related to loss from cash
      settlement of non-qualifying derivatives. There were no gains or losses
      recognized for the three months or nine months ended September 30, 2006 related
      to cash settlements of non-qualifying derivatives.




43




Derivatives
      are recorded on our balance sheets as assets or liabilities at fair value.
      At
      September 30, 2007 and
      December 31, 2006, we reflected a net hedging asset and liability on our balance
      sheets of $27.3 million and $41.6 million, respectively, when combining the
      above hedges of Atlas Energy and Atlas Pipeline. Of the $4.0 million net loss
      in
      accumulated other comprehensive income at September 30, 2007, we will reclassify
      $2.8 of gains to our consolidated statements of income over the next
      twelve-month period as these contracts expire, and $1.2 million of losses will
      be reclassified in later periods if the fair values of the instruments remain
      at
      current market values. Actual amounts that will be reclassified will vary as
      a
      result of future price changes.





As
      of September 30, 2007, we had the following financial hedges in
      place:





**ATLAS
      ENERGY RESOURCES HEDGES**


**Natural
      Gas Fixed Price Swaps**





**Twelve
                Month****Period
                Ending**
            
            
            
            **Average**
            
            **Fair
                Value****September
                30,**
            
            **Volumes**
            
            **Fixed
                Price**
            
            **Asset/(Liability)****(3)****(MMBtu)****(1)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands)**2008
            
            
            35,470,000
            
            $
            8.15
            
            $
            37,2892009
            
            
            33,530,000
            
            $
            8.32
            
            
            11,3102010
            
            
            25,430,000
            
            $
            8.02
            
            
            5172011
            
            
            18,950,000
            
            $
            7.75
            
            
            (790
            )2012
            
            
            11,150,000
            
            $
            7.62
            
            
            8212013
            
            
            2,250,000
            
            $
            7.67
            
            
            346$
            49,493





**Natural
      Gas Costless Collars**





**Twelve
                Month****Period
                Ending**
            
            
            
            
            
            **Average**
            
            **Fair
                Value****September
                30,**
            
            **Option
                Type**
            
            **Volumes**
            
            **Floor
                and Cap**
            
            **Asset/(Liability)****(3)****(MMBtu)****(1)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands)**2008
            
            
            Puts
                purchased
            
            
            450,000
            
            $
            7.50
            
            $
            3142008
            
            
            Calls
                sold
            
            
            450,000
            
            $
            8.60
            
            
            —2008
            
            
            Puts
                purchased
            
            
            1,170,000
            
            $
            7.50
            
            
            3252008
            
            
            Calls
                sold
            
            
            1,170,000
            
            $
            9.40
            
            
            —2009
            
            
            Puts
                purchased
            
            
            390,000
            
            $
            7.50
            
            
            —2009
            
            
            Calls
                sold
            
            
            390,000
            
            $
            9.40
            
            
            (32
            )2010
            
            
            Puts
                purchased
            
            
            2,160,000
            
            $
            7.75
            
            
            1442010
            
            
            Calls
                sold
            
            
            2,160,000
            
            $
            8.75
            
            
            —2011
            
            
            Puts
                purchased
            
            
            720,000
            
            $
            7.75
            
            
            (4
            )2011
            
            
            Calls
                sold
            
            
            720,000
            
            $
            8.75
            
            
            —2011
            
            
            Puts
                purchased
            
            
            5,400,000
            
            $
            7.50
            
            
            2402011
            
            
            Calls
                sold
            
            
            5,400,000
            
            $
            8.45
            
            
            —2012
            
            
            Puts
                purchased
            
            
            1,800,000
            
            $
            7.50
            
            
            —2012
            
            
            Calls
                sold
            
            
            1,800,000
            
            $
            8.45
            
            
            (25
            )2012
            
            
            Puts
                purchased
            
            
            6,480,000
            
            $
            7.50
            
            
            —2012
            
            
            Calls
                sold
            
            
            6,480,000
            
            $
            8.45
            
            
            (24
            )2013
            
            
            Puts
                purchased
            
            
            2,160,000
            
            $
            7.00
            
            
            —2013
            
            
            Calls
                sold
            
            
            2,160,000
            
            $
            8.37
            
            
            (19
            )$
            919Total
                Atlas Energy Resources net asset
            $
            50,412





44




**ATLAS
      PIPELINE HEDGES**


**Natural
      Gas Fixed - Price Swaps (Liquids Sales)**





**Production****Period
                Ended**
            
            
            
            **Average**
            
            **Fair
                Value****December
                31,**
            
            **Volumes**
            
            **Fixed
                Price**
            
            **Asset/(Liability)****(2)****(gallons)**
            
            **(per
                gallon)**
            
            **(in
                thousands)**2007
            
            
            42,651,000
            
            $
            0.893
            
            $
            (10,739
            )2008
            
            
            61,362,000
            
            
            0.706
            
            
            (13,556
            )2009
            
            
            8,568,000
            
            
            0.746
            
            
            (1,752
            )$
            (26,047
            )





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





**Production****Period
                Ended**
            
            
            
            **Average**
            
            **Fair
                Value****December
                31,**
            
            **Volumes**
            
            **Fixed
                Price**
            
            **Asset/(Liability)****(3)****(MMBtu)****(1)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands)**2007
            
            
            1,449,000
            
            $
            8.20
            
            $
            1,7362008
            
            
            5,484,000
            
            $
            8.80
            
            
            4,6082009
            
            
            5,724,000
            
            $
            8,61
            
            
            1,9582010
            
            
            2,820,000
            
            $
            8.64
            
            
            1,132$
            9,434





**Natural
      Gas Basis Swaps (Sales)**





**Production****Period
                Ended**
            
            
            
            **Average**
            
            **Fair
                Value****December
                31,**
            
            **Volumes**
            
            **Fixed
                Price**
            
            **Asset/(Liability)****(3)****(MMBtu)****(1)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands)**2007
            
            
            1,449,000
            
            $
            (0.73
            )
            $
            1352008
            
            
            5,484,000
            
            $
            (0.73
            )
            
            3882009
            
            
            5,724,000
            
            $
            (0.51
            )
            
            5502010
            
            
            2,820,000
            
            $
            (0.57
            )
            
            435$
            1,508





**Natural
      Gas Fixed Price (Purchase)**





**Production****Period
                Ended**
            
            
            
            **Average**
            
            **Fair
                Value****December
                31,**
            
            **Volumes**
            
            **Fixed
                Price**
            
            **Liability****(3)****(MMBtu)****(1)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands)**2007
            
            
            3,909,000
            
            $
            8.63
            (4)
            $
            (6,819
            )2008
            
            
            16,260,000
            
            $
            8.92
            (5)
            
            (16,293
            )2009
            
            
            15,564,000
            
            $
            8.68
            
            
            (6,402
            )2010
            
            
            7,200,000
            
            $
            8.64
            
            
            (2,891
            )$
            (32,405
            )





**Natural
      Gas Basis (Purchase)**





**Production****Period
                Ended**
            
            
            
            **Average**
            
            **Fair
                Value****December
                31,**
            
            **Volumes**
            
            **Fixed
                Price**
            
            **Liability****(3)****(MMBtu)****(1)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands)**2007
            
            
            3,909,000
            
            $
            (1.05
            )
            $
            1612008
            
            
            15,276,000
            
            $
            (1.19
            )
            
            (1,820
            )2009
            
            
            14,820,000
            
            $
            (0.69
            )
            
            (5,485
            )2010
            
            
            7,200,000
            
            $
            (0.56
            )
            
            (2,930
            )$
            (10,074
            )





45











**Crude
      Oil Fixed - Price Swaps (Sales)**





**Production****Period
                Ended**
            
            
            
            **Average**
            
            **Fair
                Value****December
                31,**
            
            **Volumes**
            
            **Fixed
                Price**
            
            **Liability****(3)****(barrels)**
            
            **(per
                barrel)**
            
            **(in
                thousands)**2007
            
            
            17,600
            
            $
            56.48
            
            $
            (427
            )2008
            
            
            65,400
            
            $
            59.42
            
            
            (1,133
            )2009
            
            
            33,000
            
            $
            62.70
            
            
            (362
            )$
            (1,922
            )


**Crude
      Oil Options (Sales)**





**Production****Period
                  Ended****December
                31,**
            
            **Option
                Type**
            
            **Volumes**
            
            **Average****Strike
                Price**
            
            **Fair
                Value**
              **Asset/****(Liability)(3)****(MMBtu)****(1)**
            
            **(per
                MMBtu)**
            
            **(in
                thousands)**2007
            
            
            Puts
                purchased
            
            
            189,300
            
            $
            60.00
            
            $
            (39
            )2007
            
            
            Calls
                sold
            
            
            189,300
            
            $
            75.36
            
            
            (998
            )2008
            
            
            Puts
                purchased
            
            
            691,800
            
            $
            60.00
            
            
            6752008
            
            
            Calls
                sold
            
            
            691,800
            
            $
            78.00
            
            
            (3,266
            )2009
            
            
            Puts
                purchased
            
            
            738,000
            
            $
            60.00
            
            
            2,0602009
            
            
            Calls
                sold
            
            
            738,000
            
            $
            80.62
            
            
            (3,038
            )2010
            
            
            Puts
                purchased
            
            
            402,000
            
            $
            60.00
            
            
            1,3082010
            
            
            Calls
                sold
            
            
            402,000
            
            $
            79.34
            
            
            (1,804
            )2011
            
            
            Puts
                purchased
            
            
            30,000
            
            $
            60.00
            
            
            1242011
            
            
            Calls
                sold
            
            
            30,000
            
            $
            74.50
            
            
            (193
            )2012
            
            
            Puts
                purchased
            
            
            30,000
            
            $
            60.00
            
            
            1382012
            
            
            Calls
                sold
            
            
            30,000
            
            $
            73.90
            
            
            (211
            )$
            (5,244
            )





**Crude
      Oil Sales Options (associated with NGL volumes)**





**Production****Period
                  Ended****December
                31,**
            
            **Option
                Type**
            
            **Associated
                  NGL****Volumes**
            
            **Crude****Volumes**
            
            **Average
                  Crude****Strike
                Price**
            
            **Fair
                  Value****Asset/(Liability)
(3)****(gallons)**
            
            **(barrels)**
            
            **(per
                barrel)**
            
            **(in
                thousands)**2007
            
            
            Puts
                purchased
            
            
            25,789,680
            
            
            390,000
            
            $
            60.00
            
            $
            582007
            
            
            Calls
                sold
            
            
            25,789,680
            
            
            390,000
            
            $
            75.18
            
            
            (2,513
            )2008
            
            
            Puts
                purchased
            
            
            249,257,484
            
            
            3,744,600
            
            $
            60.00
            
            
            5,1192008
            
            
            Calls
                sold
            
            
            249,257,484
            
            
            3,744,600
            
            $
            79.38
            
            
            (15,961
            )2009
            
            
            Puts
                purchased
            
            
            324,233,280
            
            
            4,752,000
            
            $
            60.00
            
            
            13,2922009
            
            
            Calls
                sold
            
            
            324,233,280
            
            
            4,752,000
            
            $
            78.68
            
            
            (22,694
            )2010
            
            
            Puts
                purchased
            
            
            169,282,890
            
            
            2,413,500
            
            $
            60.00
            
            
            8,0642010
            
            
            Calls
                sold
            
            
            169,282,890
            
            
            2,413,500
            
            $
            77.28
            
            
            (12,643
            )$
            (27,278
            )Total
                Atlas Pipeline net liability
            $
            (92,028
            )Total
                Atlas America net liability
            $
            (40,616
            )


(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)
              Includes
                  Atlas Pipeline’s premium received from its sale of an option for it to
                  sell 1,200,000 MMBtu of natural gas at an average price of $17.00
                  per
                  MMBtu for the year ended December 31, 2007.(5)
              Includes
                  Atlas Pipeline’s premium received from its sale of an option for it to
                  sell 936,000 MMBtu of natural gas for the year ended December 31,
                  2008 at
                  $15.50 per MMBtu.





46


**ITEM
      4.**  **CONTROLS
      AND PROCEDURES**





**Disclosure
      Controls and Procedures**





In
      connection with the preparation of this Form 10-Q, our management, with the
      participation of our principal executive officer and principal financial
      officer, carried out an evaluation of the effectiveness of the design and
      operation of our disclosure controls and procedures (as defined in Rules
      13a-15(e) and 15d-15(e)) under the Securities Exchange Act of 1934, as amended
      (the “Exchange Act”). Based upon that evaluation, our principal executive
      officer and principal financial officer concluded that, because of the material
      weakness in internal controls over financial reporting discussed below, as
      of
      September 30, 2007, our disclosure controls and procedures were not
      effective.





**Changes
      in Internal Control over Financial Reporting**





There
      were no changes in our internal control over financial reporting during the
      three months ended June 30, 2007 that materially affected or are reasonably
      likely to materially affect, our internal control over financial reporting,
      except for the following material weakness that was identified as a result
      of
      management’s evaluation of such changes and as a result of the evaluation
      described above.





During
      the preparation of our Quarterly Report on Form 10-Q for the quarterly period
      ended June 30, 2007, we determined that our accounting treatment for the sales
      of our subsidiaries stock were subject to the provisions of Staff Accounting
      Bulletin No. 51, *Accounting
      by the Parent in Consolidation for Sales of Stock by a
      Subsidiary* ,
      (“SAB No. 51”). SAB No. 51 requires the calculation of a gain or loss on the
      sale of subsidiary stock based on the change in the Parent’s share of the
      carrying value of equity before and after the transaction. The resulting gain
      or
      loss may be recognized through income or alternatively as an increase in paid-in
      capital (in the case of a gain), net of tax. The Company must establish a policy
      as to its treatment and must consistently apply this treatment to all such
      sales
      of subsidiary stock. The Company has elected to recognize gains for its three
      subsidiaries which have issued stock in order to record the effects in the
      December 31, 2006 and March 31, 2007 financial statements. The correction of
      the
      accounting treatment affected our December 31, 2006 balance sheet by increasing
      minority interest by $188.3 million, increasing deferred taxes by $79.1 million
      and increasing paid-in capital by $109.2 million from what was reported in
      previous filings.





Based
      upon the results of our evaluation described above which was performed in
      connection with the restatement of our financial statements for the year ended
      December 31, 2006 and quarterly period ended March 31, 2007, our principal
      executive officer and principal financial officer determined that the incorrect
      treatment of our subsidiary stock sales referenced above was not detected in
      our
      financial reporting process for the year ended December 31, 2006 and quarterly
      period ended March 31, 2007 as a result of a material weakness in internal
      control over financial reporting related to review procedures performed in
      the
      preparation of the financial statements for these periods. The material weakness
      that existed was that the controls to review and validate the proper accounting
      treatment did not operate effectively.





A
      material weakness in internal control is a significant deficiency, or
      combination of significant deficiencies, that results in more than a remote
      likelihood that a material misstatement of the financial statements would not
      be
      prevented or detected on a timely basis by the Company.





To
      remediate this material weakness, the Company added additional review procedures
      including increasing the knowledge of our employees responsible for reviewing
      accounting principles, including enhanced background research and documentation
      related to the accounting principles and increasing the involvement of
      third-party advisors in the determination of the appropriate accounting
      treatment. The Company believes that the changes remediated the material
      weakness described above subsequent to June 30, 2007.








47


**PART
      II.  OTHER INFORMATION**




**ITEM
              6.**
            **EXHIBITS**Exhibit
                No.
            Description3.1
            
            Amended
                and Restated Certificate of Incorporation(1)3.2
            
            Amended
                and Restated Bylaws(1)31.1
            
            Rule
                13(a)-14(a)/15d-14(a) Certification.31.2
            
            Rule
                13(a)-14(a)/15d-14(a) Certification.32.1
            
            Section
                1350 Certification.32.2
            
            Section
                1350 Certification.




(1)
            
            Previously
                filed as an exhibit to our Form 8-K for the quarter ended June 14,
                2005.








48






**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: 
                November 8, 2007
            By:
            */s/ Matthew A. Jones*Matthew
              A. JonesChief
                Financial Officer  Date: 
                  November 8, 2007
              By:
              /s/*Nancy
                J. McGurk*Nancy
                J. McGurkSenior
                  Vice President and Chief Accounting
                  Officer


49