**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 March 31, 2005
 
 **OR**
 
 **o**
    **TRANSITION
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
      1934**
 
 For the
transition period from _________ to __________
 
 Commission
file number: **333-112653**
 
 
 **ATLAS
AMERICA, INC.**
 (Exact
name of registrant as specified in its charter)
 
 **Delaware**
    **51-0404430**(State
      or other jurisdiction ofincorporation
      or organization)
    (I.R.S.
      EmployerIdentification
      No.)**311
      Rouser Road****Moon
      Township, PA**
    **15108**(Address
      of principal executive offices)
    (Zip
      code)
 
 Registrant's
telephone number, including area code: **(412)
262-2830**
 
 Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days.  Yes x   
No o
 
 Indicate
by check mark whether the registrant is an accelerated filer (as defined in Rule
12b-2 of the Exchange Act).
 Yes o    No x
 
 The
number of outstanding shares of the registrant’s common stock on May 2, 2005 was
13,333,333 shares.
 
 
 
  **ATLAS AMERICA, INC.**
 **INDEX
TO QUARTERLY REPORT ON FORM 10-Q**
 
 **Page****PART
      I**
    **FINANCIAL INFORMATION**Item
      1.
    Financial Statements (Unaudited)Consolidated Balance Sheets - March 31, 2005 and
      September 30, 2004
    3Consolidated Statements of Income Three Months and
      Six Months Ended March 31, 2005
    4Consolidated Statement of Changes in Stockholders’ Equity
      for the Six Months Ended March 31, 2005
    5Consolidated Statements of Cash Flows for the Six Months
      Ended March 31, 2005 and 2004
    6Notes to Consolidated Financial Statements - March 31,
      2005
    7 -
      25Item
      2.
    Management’s
      Discussion and Analysis of Financial Condition and Resultsof
      Operations
    26
      - 36Item
      3.
    Quantitative and Qualitative Disclosures about Market Risk
    36
      - 39Item
      4.
    Controls and Procedures
    39**PART
      II**
    **OTHER INFORMATION**Item
      6.
    Exhibits
    40**SIGNATURES**
    41
  2
 *Index*
  **PART I. FINANCIAL INFORMATION**
 **Item 1.    Financial
Statements**
 
 **ATLAS
AMERICA, INC.**
 **CONSOLIDATED
BALANCE SHEETS**
 (in
thousands, except share data)
 
 **March
      31,**
    
    **September
      30,****2005**
    
    **2004**(Unaudited)
    
    (Audited)**ASSETS**Current
      assets:Cash
      and cash equivalents
    
    $
    17,061
    
    $
    29,192Accounts
      receivable
    
    
    29,545
    
    
    24,113Prepaid
      expenses
    
    
    4,883
    
    
    2,433Total
      current assets
    
    
    51,489
    
    
    55,738Property
      and equipment, net
    
    
    345,515
    
    
    313,091Intangible
      assets, net
    
    
    6,777
    
    
    7,243Other
      assets, net
    
    
    9,521
    
    
    7,955Advances
      to parent
    
    
    662
    
    
    -Goodwill
    
    
    37,470
    
    
    37,470$
    451,434
    
    $
    421,497**LIABILITIES
      AND STOCKHOLDERS’ EQUITY**Current
      liabilities:Current
      portion of long-term debt
    
    $
    2,361
    
    $
    3,401Accounts
      payable
    
    
    20,611
    
    
    20,869Liabilities
      associated with drilling contracts
    
    
    23,060
    
    
    29,375Accrued
      producer liabilities
    
    
    12,455
    
    
    8,815Accrued
      hedge liability
    
    
    8,673
    
    
    3,972Accrued
      liabilities
    
    
    13,397
    
    
    10,795Total
      current liabilities
    
    
    80,557
    
    
    77,227Long-term
      debt
    
    
    101,622
    
    
    82,239Advances
      from parent
    
    
    -
    
    
    10,413Deferred
      tax liability
    
    
    23,409
    
    
    21,442Other
      liabilities
    
    
    9,867
    
    
    6,949Minority
      interest
    
    
    126,488
    
    
    132,224Commitments
      and contingencies
    
    
    -
    
    
    -Stockholders’
      equity:Preferred
      stock, $0.01 par value: 1,000,000 authorized shares
    
    
    -
    
    
    -Common
      stock, $0.01 par value: 49,000,000 authorized shares
    
    
    133
    
    
    133Additional
      paid-in capital
    
    
    75,584
    
    
    75,584Accumulated
      other comprehensive loss
    
    
    (1,473
    )
    
    (2,553
    )Retained
      earnings
    
    
    35,247
    
    
    17,839Total
      stockholders’ equity
    
    
    109,491
    
    
    91,003$
    451,434
    
    $
    421,497
 
 
 See
accompanying notes to consolidated financial statements
  3
 *Index*
  **ATLAS
AMERICA, INC.**
 **CONSOLIDATED STATEMENTS OF INCOME**
 (in
thousands, except per share data)
 (Unaudited)
 
 **Three
      Months Ended**
    
    **Six
      Months Ended****March
      31,**
    
    **March
      31,****2005**
    
    **2004**
    
    **2005**
    
    **2004**(in
      thousands, except per share data)**REVENUES**Well
      drilling
    
    $
    41,451
    
    $
    26,248
    
    $
    72,009
    
    $
    48,207Gas
      and oil production
    
    
    13,959
    
    
    11,799
    
    
    28,618
    
    
    21,995Gathering,
      transmission and processing
    
    
    43,741
    
    
    1,579
    
    
    87,523
    
    
    3,178Well
      services
    
    
    2,350
    
    
    2,123
    
    
    4,598
    
    
    4,060101,501
    
    
    41,749
    
    
    192,748
    
    
    77,440**COSTS
      AND EXPENSES**Well
      drilling
    
    
    36,044
    
    
    22,824
    
    
    62,617
    
    
    41,919Gas
      and oil production and exploration
    
    
    2,413
    
    
    3,323
    
    
    4,215
    
    
    5,008Gathering,
      transmission and processing
    
    
    37,462
    
    
    620
    
    
    73,142
    
    
    1,216Well
      services
    
    
    1,316
    
    
    1,021
    
    
    2,507
    
    
    2,062General
      and administrative
    
    
    1,494
    
    
    785
    
    
    3,154
    
    
    1,094Compensation
      reimbursement - affiliate
    
    
    244
    
    
    463
    
    
    457
    
    
    1,065Depreciation,
      depletion and amortization
    
    
    4,781
    
    
    3,534
    
    
    10,653
    
    
    6,77983,754
    
    
    32,570
    
    
    156,745
    
    
    59,143**OPERATING
      INCOME**
    
    
    17,747
    
    
    9,179
    
    
    36,003
    
    
    18,297**OTHER
      INCOME (EXPENSE**)Interest
      expense
    
    
    (1,623
    )
    
    (473
    )
    
    (3,313
    )
    
    (960
    )Minority
      interest in Atlas Pipeline Partners, L.P.
    
    
    (2,500
    )
    
    (1,324
    )
    
    (9,720
    )
    
    (2,595
    )Arbitration
      settlement, net
    
    
    (136
    )
    
    -
    
    
    4,310
    
    
    -Other,
      net
    
    
    (181
    )
    
    331
    
    
    (79
    )
    
    499(4,440
    )
    
    (1,466
    )
    
    (8,802
    )
    
    (3,056
    )Income
      from continuing operations before income taxes
    
    
    13,307
    
    
    7,713
    
    
    27,201
    
    
    15,241Provision
      for income taxes
    
    
    4,791
    
    
    2,547
    
    
    9,793
    
    
    5,182**Net
      income**
    
    $
    8,516
    
    $
    5,166
    
    $
    17,408
    
    $
    10,059**Net
      income per common share****-****basic**Net
      income per common share - basic
    
    $
    .64
    
    $
    .48
    
    
    1.31
    
    $
    .94Weighted
      average common shares outstanding
    
    
    13,333
    
    
    10,688
    
    
    13,333
    
    
    10,688**Net
      income per common share****-****diluted**Net
      income per common shares - diluted
    
    $
    .64
    
    $
    .48
    
    
    1.31
    
    $
    .94Weighted
      average common shares outstanding
    
    
    13,338
    
    
    10,688
    
    
    13,338
    
    
    10,688
 
 
 See
accompanying notes to consolidated financial statements
  4
 *Index*
  **ATLAS
AMERICA, INC.**
 **CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’
EQUITY**
 **SIX
MONTHS ENDED MARCH 31, 2005**
 (in
thousands, except share data)
 (Unaudited)
 
 **Additional**
    
    **Accumulated**
      **Other**
    
    
    
    **Total****Common
      Stock**
    
    **Paid-In**
    
    **Comprehensive**
    
    **Retained**
    
    **Stockholders’****Shares**
    
    **Amount**
    
    **Capital**
    
    **Income
      (Loss)**
    
    **Earnings**
    
    **Equity**Balance,
      October 1, 2004
    
    
    13,333,333
    
    $
    133
    
    $
    75,584
    
    $
    (2,553
    )
    $
    17,839
    
    $
    91,003Other
      comprehensive income
    
    
    -
    
    
    -
    
    
    -
    
    
    1,080
    
    
    -
    
    
    1,080Net
      income
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    17,408
    
    
    17,408Balance,
      March 31, 2005
    
    
    13,333,333
    
    $
    133
    
    $
    75,584
    
    $
    (1,473
    )
    $
    35,247
    
    $
    109,491
 
 
 See
accompanying notes to consolidated financial statements ****
  5
 *Index*
  **ATLAS
AMERICA, INC.**
 **CONSOLIDATED STATEMENT OF CASH FLOWS**
 **SIX
MONTHS ENDED MARCH 31, 2005**
 (in
thousands)
 (Unaudited)
  **Sixth
      Months Ended**
      **March
      31,**
    
    **Sixth
      Months Ended**
      **March
      31,****2005**
    
    **2004****CASH
      FLOWS FROM OPERATING ACTIVITIES:**Net
      income
    
    $
    17,408
    
    $
    10,059Adjustments
      to reconcile net income to net cash provided by operating
      activities:Depreciation,
      depletion and amortization
    
    
    10,653
    
    
    6,779Amortization
      of deferred financing costs
    
    
    621
    
    
    320Non-cash
      loss on derivative value
    
    
    720Non-cash
      compensation on long-term incentive plans
    
    
    922Minority
      interest in Atlas Pipeline Partners, L.P.
    
    
    9,720
    
    
    2,595Gain
      on asset dispositions
    
    
    (36
    )
    
    (49
    )Property
      impairments and abandonments
    
    
    -
    
    
    599Deferred
      income taxes
    
    
    1,420
    
    
    5,182Changes
      in operating assets and liabilities
    
    
    (1,621
    )
    
    (2,972
    )Net
      cash provided by operating activities
    
    
    39,807
    
    
    22,513**CASH
      FLOWS FROM INVESTING ACTIVITIES:**Capital
      expenditures
    
    
    (40,867
    )
    
    (17,546
    )Proceeds
      from sale of assets
    
    
    66
    
    
    159Increase
      in other assets
    
    
    (789
    )
    
    (826
    )Net
      cash used in investing activities
    
    
    (41,590
    )
    
    (18,213
    )**CASH
      FLOWS FROM FINANCING ACTIVITIES:**Borrowings
    
    
    86,252
    
    
    48,000Principal
      payments on debt
    
    
    (67,910
    )
    
    (38,528
    )Payments
      to parent
    
    
    (19,448
    )
    
    (7,866
    )Dividends
      paid to parent
    
    
    -
    
    
    (15,134
    )Distributions
      paid to minority interests of Atlas Pipeline Partners,
L.P.
    
    
    (7,845
    )
    
    (3,379
    )Increase
      in other assets
    
    
    (1,397
    )
    
    (857
    )Net
      cash used in financing activities
    
    
    (10,348
    )
    
    (17,764
    )Decrease
      in cash and cash equivalents
    
    
    (12,131
    )
    
    (13,464
    )Cash
      and cash equivalents at beginning of period
    
    
    29,192
    
    
    25,372Cash
      and cash equivalents at end of period
    
    $
    17,061
    
    $
    11,908
 
 
 See
accompanying notes to consolidated financial statements
  6
 *Index*
  **ATLAS
AMERICA, INC.**
 **NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**
 **March
31, 2005**
 (Unaudited)
 
 **NOTE
1 - MANAGEMENT’S OPINION REGARDING INTERIM FINANCIAL
STATEMENTS**
 
 The
consolidated financial statements include the accounts of Atlas America, Inc.
(the “Company”) which is an 80.2% owned subsidiary of Resource America, Inc.
(“Resource America”).  The Company’s subsidiaries are all wholly owned
except for Atlas Pipeline Partners, L.P. (“Atlas Pipeline”).  Atlas
Pipeline is a master limited partnership in which the Company has a combined
general and limited partnership interest of 24% and 59% March 31, 2005 and 2004,
receptively. The limited partner units were subordinated until January 1, 2005,
when the subordination term expired and they were converted to common units in
accordance with the terms of the partnership agreement.
 
 The
consolidated financial statements and the information and tables contained in
the notes to the consolidated financial statements as of March 31, 2005 and for
the three months and six months ended March 31, 2005 and 2004 are
unaudited.  Certain information and footnote disclosures normally included
in financial statements prepared in accordance with accounting principles
generally accepted in the United States of America have been condensed or
omitted in these statements pursuant to the rules and regulations of the
Securities and Exchange Commission.  However, in the opinion of management,
these interim financial statements include all the necessary adjustments to
fairly present the results of the interim periods presented.  The results
of operations for the three months and six months ended March 31, 2005 may not
necessarily be indicative of the results of operations for the full fiscal year
ending September 30, 2005.
 
 Certain
reclassifications have been made to the consolidated financial statements as of September
30, 2004 and for the three months and six months ended March 31, 2004 to conform
to the presentation as of and for the three months and six months ended March
31, 2005.
 
 **NOTE
2 - SIGNIFICANT ACCOUNTING POLICIES**
 
 Reference
is hereby made to the Company's Annual Report on Form 10-K for the fiscal year
ended September 30, 2004, which contains a summary of significant accounting
policies followed by the Company in the preparation of its consolidated
financial statements.  These policies were also followed in preparing the
quarterly report included herein.
 
 **Recently
Issued Financial Accounting Standards**
 
 In April
2005, the Financial Accounting Standards Board (“FASB”) issued FASB
Interpretation No. 47, Accounting for Conditional Assets Retirement Obligations
(“FIN 47”), which will result in (a) more consistent recognition of liabilities
relating to asset retirement obligations, (b) more information about expected
future cash outflows associated with those obligations, and (c) more information
about investments in long-lived assets because additional asset retirement cost
will be recognized as part of the carrying amounts of the assets. FIN 47
clarifies that the term conditional asset retirement obligation as used in
Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for
Asset Retirement Obligations, refers to a legal obligation to perform an asset
retirement activity in which the timing and (or) method of settlement are
conditional on a future event that may or may not be within the control of the
entity. The obligation to perform the asset retirement activity is unconditional
even though uncertainty exists about the timing and (or) method of settlement.
Uncertainty about the timing and (or) method of settlement of a conditional
asset retirement obligation should be factored into the measurement of the
liability when sufficient information exists.
  7
 *Index*
  **ATLAS
AMERICA, INC.**
 **NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**
 **March
31, 2005**
 (Unaudited)
 
 **NOTE
2 - SIGNIFICANT ACCOUNTING POLICIES - (Continued)**
 
 **Recently
Issued Financial Accounting Standards - (Continued)**
 
 FIN 47
also clarifies when an entity would have sufficient information to reasonably
estimate the fair value of an asset retirement obligation. FIN 47 is effective
no later than the end of fiscal years ending after December 15, 2005.
Retrospective application of interim financial information is permitted but is
not required. Early adoption of this interpretation is encouraged. As FIN 47 was
recently issued, the Company has not determined whether the interpretation will
have a significant adverse effect on its financial position or results of
operations.
 
 In April
2005, the FASB issued FASB Staff Position No. FAS 19-1 (“FSP FAS 19-1”), which
addressed a discussion that was ongoing within the oil and gas industry
regarding capitalization of costs of drilling exploratory wells. Paragraph 19 of
FASB Statement No. 19, Financial Accounting and Reporting by Oil and Gas
Producing Companies (“FASB No. 19”), requires costs of drilling exploratory
wells to be capitalized pending determination of whether the well has found
proved reserves. If the well has found proved reserves, the capitalized costs
become part of the entity’s wells, equipment, and facilities; if, however, the
well has not found proved reserves, the capitalized costs of drilling the well
are expensed. Questions arose in practice about the application of this guidance
due to changes in oil and gas exploration processes and lifecycles. The issue
was whether there are circumstances that would permit the continued
capitalization of exploratory well costs if reserves cannot be classified as
proved within one year following the completion of drilling other than when
additional exploration wells are necessary to justify major capital expenditures
and those wells are underway or firmly planned for in the near future. FSP FAS
19-1 amends FASB No. 19 to allow for the continued capitalization of suspended
well costs when the well has found a sufficient quantity of reserves to justify
its completion as a producing well and the enterprise is making sufficient
progress assessing the reserves and the economic and operating viability of the
plan. This guidance requires management to exercise more judgment than was
previously required and also requires additional disclosure. This new guidance
is effective for the first reporting period beginning after April 4, 2005 and is
to be applied prospectively to existing and newly capitalized exploratory well
costs. Management does not believe this statement of position will have a
significant effect on its financial statements .
 
 In
December 2004, the FASB issued Statement No. 123 (R) (revised 2004) Share-Based
Payment, which is a revision of SFAS No. 123, Accounting for Stock-Based
Compensation.  Statement 123 (R) supersedes Accounting Principal Board
Opinion (“APB”) No. 25, Accounting for Stock Issued to Employees, and amends
SFAS No. 95, Statement of Cash Flows.  Generally, the approach to
accounting in Statement 123 (R) requires all share-based payments to employees,
including grants of employee stock options, to be recognized in the financial
statements based on their fair values.  Currently the Company accounts for
these payments under the intrinsic value provisions of APB No. 25 with no
expense recognition in the financial statements.  Statement 123 (R) is
effective for the Company beginning October
1, 2005.  The Statement offers several alternatives for
implementation.  At this time, the company has not made a decision as to
the alternative it may select.
  8
 *Index*
  **ATLAS
AMERICA, INC.**
 **NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**
 **March
31, 2005**
 (Unaudited)
 
 **NOTE
2 - SIGNIFICANT ACCOUNTING POLICIES - (Continued)**
 
 **Concentration
of Credit Risk**
 
 Financial
instruments, which potentially subject the Company to concentrations of credit
risk, consist principally of periodic temporary investments of cash and cash
equivalents. The Company places its temporary cash investments in high-quality
short-term money market instruments and deposits with high-quality financial
institutions and brokerage firms. At March 31, 2005, the Company had $25.0
million in deposits at various banks, of which $24.0 million was over the
insurance limit of the Federal Deposit Insurance Corporation. No losses have
been experienced on such investments.
 
 **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 customer’s current creditworthiness, as determined by the
Company’s review of its customers’ credit information. The Company extends
credit on an unsecured basis to many of its energy customers. At March 31, 2005
and September 30, 2004, the Company’s credit evaluation indicated that it has no
need for an allowance for possible losses.
 
 **Revenue
Recognition**
 
 Because
there are timing differences between the delivery of natural gas, NGL’s and oil
and the Company’s receipt of a delivery statement, the Company has unbilled
revenues. These revenues are accrued based upon volumetric data from the
Company’s records and the Company’s estimates of the related transportation and
compression fees which are, in turn, based upon applicable product prices. The
Company had unbilled trade receivables at March 31, 2005 and September 30, 2004
of $26.7 million and $22.1 million which are included in Accounts Receivable, on
its Consolidated Balance Sheets.
 ****
 **Stock-Based
Compensation**
 
 The
Company accounts for its employees’ participation in the stock option plans of
its ultimate parent, Resource America, in accordance with the provisions of APB
No. 25 and related interpretations. Compensation expense is recorded on the date
of grant only if the current market price of the underlying stock exceeded the
exercise price.  The Company adopted the disclosure requirements of SFAS
No. 123, as amended by the required disclosures of SFAS No. 148, Accounting for
Stock-Based Compensation-Transition and Disclosure.
 
 SFAS 123
requires the disclosure of pro forma net income and earnings per share as if the
Company had adopted the fair value method for stock options granted after June
30, 1996. Under SFAS 123, the fair value of stock-based awards to employees is
calculated through the use of option pricing models, even though such models
were developed to estimate the fair value of freely tradable, fully transferable
options without vesting restrictions, which significantly differ from the
Company's stock option awards. These models also require subjective assumptions,
including future stock price volatility and expected time to exercise, which
greatly affect the calculated values.
 
 9
 *Index*
  **ATLAS
AMERICA, INC.**
 **NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**
 **March
31, 2005**
 (Unaudited)
 
 **NOTE
2 - SIGNIFICANT ACCOUNTING POLICIES - (Continued)**
 
 **Stock-Based
Compensation - (Continued)**
 
 No
stock-based employee compensation cost is reflected in net income of the
Company, as all options granted under Resource America’s plans in which the
Company’s employees participate had an exercise price equal to the market value
of the underlying Resource America common stock on the date of grant.  The
following table illustrates the effect on net income if the Company had applied
the fair value recognition provisions of SFAS 123 to stock-based employee
compensation (in thousands, except per share data).
 
  **Three
      Months Ended**
    
    **Six
      Months Ended****March
      31,**
    
    **March
      31,****2005**
    
    **2004**
    
    **2005**
    
    **2004**Net
      income, as reported
    
    $
    8,516
    
    $
    5,166
    
    $
    17,408
    
    $
    10,059Stock-based
      employee compensation expense reported in net income, net of
      tax
    
    
    -
    
    
    -
    
    
    -
    
    
    -Less
      total stock-based employee compensation expense determined under the fair
      value-based method for all awards, net of income taxes
    
    
    (78
    )
    
    (82
    )
    
    (214
    )
    
    (162
    )Pro
      forma net income
    
    $
    8,438
    
    $
    5,084
    
    $
    17,194
    
    $
    9,897Net
      income per common share:Basic-as
      reported
    
    $
    .64
    
    $
    .48
    
    $
    1.31
    
    $
    .94Basic-pro forma
    
    $
    .63
    
    $
    .48
    
    $
    1.29
    
    $
    .93Diluted-as
      reported
    
    $
    .64
    
    $
    .48
    
    $
    1.31
    
    $
    .94Diluted-pro forma
    
    $
    .63
    
    $
    .48
    
    $
    1.29
    
    $
    .93
  10
 *Index*
  **ATLAS
AMERICA, INC.**
 **NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**
 **March
31, 2005**
 (Unaudited)
 
 **NOTE
2 - SIGNIFICANT ACCOUNTING POLICIES - (Continued)**
 
 **Supplemental
Cash Flow Information**
 
 The
Company considers temporary investments with a maturity at the date of
acquisition of 90 days or less to be cash equivalents.
 
 Supplemental
disclosure of cash flow information (in thousands) is listed below:
 
 **Six
      Months Ended****March
      31,****2005**
    
    **2004**Cash
      paid during the period for:Interest
    
    $
    2,187
    
    $
    579Income
      taxes
    
    $
    17
    
    $
    -
 
 **NOTE
3 - COMPREHENSIVE INCOME**
 
 Comprehensive
income includes net income and other gains and losses affecting stockholders’
equity from non-owner sources that under generally accepted accounting
principles, have not been recognized in the calculation of net income. For the
Company, these include only changes in the fair value, net of taxes, of
unrealized hedging gains and losses (in thousands).
  **Three
      Months Ended**
    
    **Six
      Months Ended****March
      31,**
    
    **March
      31,****2005**
    
    **2004**
    
    **2005**
    
    **2004**Net
      income
    
    $
    8,516
    
    $
    5,166
    
    $
    17,408
    
    $
    10,059Other
      comprehensive income (loss):Unrealized
      gain (loss) on hedging contracts, net of taxes of $772 and
      ($579)
    
    
    (1,373
    )
    
    -
    
    
    1,029
    
    
    -Add:
      reclassification adjustment for losses realized in net income, net of
      taxes of ($58) and ($29)
    
    
    102
    
    
    -
    
    
    51
    
    
    -(1,271
    )
    
    -
    
    
    1,080
    
    
    -Comprehensive
      income
    
    $
    7,245
    
    $
    5,166
    
    $
    18,488
    
    $
    10,059
 **NOTE
4 - EARNINGS PER SHARE**
 
 Basic
earnings per share is determined by dividing net income by the weighted average
number of shares of common stock outstanding during the period.  Earnings
per share - diluted is computed by dividing net income by the sum of the
weighted average number of shares of common stock outstanding and dilutive
potential shares issuable during the period.  Dilutive potential shares of
common stock consist of the excess of shares issuable under the terms of the
Company’s stock option plan over the number of such shares that could have been
reacquired (at the weighted average price of shares during the period) with the
proceeds received from the exercise of the options.
  11
 *Index*
  **ATLAS
AMERICA, INC.**
 **NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**
 **March
31, 2005**
 (Unaudited)
 
 **NOTE
4 - EARNINGS PER SHARE - (Continued)**
 
 The
following table presents a reconciliation of the components used in the
computation of net income per common share-basic and net income per common
share-diluted (in thousands):
 
 **Three
      Months Ended**
    
    **Six
      Months Ended****March
      31,**
    
    **March
      31,****2005**
    
    **2004**
    
    **2005**
    
    **2004**Net
      income
    
    $
    8,516
    
    $
    5,166
    
    $
    17,408
    
    $
    10,059Weighted
      average common shares outstanding-basic
    
    
    13,333
    
    
    10,688
    
    
    13,333
    
    
    10,688Dilutive
      effect of stock option and award plan
    
    
    5
    
    
    -
    
    
    5
    
    
    -Weighted
      average common shares-diluted
    
    
    13,338
    
    
    10,688
    
    
    13,338
    
    
    10,688
 
 **NOTE
5 - DERIVATIVE INSTRUMENTS**
 
 Atlas
Pipeline, through its subsidiary, Atlas Pipeline Mid-Continent, LLC (“APLMC” or “Mid-Continent-Velma”),
enters into certain financial swap and option instruments that are classified as
cash flow hedges in accordance with SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activity. Mid-Continent-Velma entered into these
instruments to hedge the forecasted natural gas, natural gas liquids and
condensate sales against the variability in expected future cash flows
attributable to changes in market prices. The swap instruments are contractual
agreements between counterparties to exchange obligations of money as the
underlying natural gas, natural gas liquids and condensate is sold. Under these
swap agreements, Mid-Continent-Velma receives a fixed price and pays a floating
price based on certain indices for the relevant contract period. The options fix
the price for Mid-Continent-Velma within the puts purchased and calls
sold.
 
 Atlas
Pipeline formally documents all relationships between hedging instruments and
the items being hedged, including Atlas Pipeline’s risk management objective and
strategy for undertaking the hedging transactions. This includes matching the
natural gas futures and options contracts to the forecasted transactions. Atlas
Pipeline assesses, both at the inceptions of the hedge and on an ongoing basis,
whether the derivatives are effective in offsetting changes in the forecast cash
flow of hedged items. If it is determined that a derivative is not effective as
a hedge or it has ceased to be an effective hedge due to the loss of correlation
between the hedging instrument and the underlying commodity, Atlas Pipeline will
discontinue hedge accounting for the derivative and subsequent changes in fair
value for the derivative will be recognized immediately into
earnings.
  12
 *Index*
  **ATLAS
AMERICA, INC.**
 **NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**
 **March
31, 2005**
 (Unaudited)
 
 **NOTE
5 - DERIVATIVE INSTRUMENTS - (Continued)**
 
 Derivatives
are recorded on the balance sheet as assets or liabilities at fair value. For
derivatives qualifying as hedges, the effective portion of changes in fair value
are recognized in stockholders’ equity as Accumulated Other Comprehensive Income
and reclassified to earnings as such transactions are settled. For
non-qualifying derivatives and for the ineffective portion of qualifying
derivatives, changes in fair value are recognized in earnings as they occur. At
March 31, 2005, Atlas Pipeline reflected a net hedge liability of $10.8
million on its Balance Sheet. Of the $1.5 million net unrealized loss in
Accumulated Other Comprehensive Income at March 31, 2005, $1.1 million in losses
will be reclassified to earnings over the next twelve month period as these
contracts expire and $400,000 will be reclassified in later periods if the fair
values of the instruments remain constant. Actual amounts that will be
reclassified will vary as a result of future changes in prices. 
Ineffective gains or losses are recorded in income while the hedge contract is
open and may increase or decrease until settlement of the contract. Atlas
Pipeline recognized losses of $669,000 and $645,000 related to these hedging
instruments for the three months and six months ended March 31, 2005,
respectively. A hedging loss of $224,000 and a hedging gain of $216,000
resulting from ineffective hedges are included in gathering, transmission and
processing revenues on the Consolidated Statements of Income for the three
months and six months ended March 31, 2005, respectively.
 
 A portion
of the Company’s future natural gas sales is periodically hedged through the use
of swap and collar contracts.  Realized gains and losses on these
instruments are reflected in the contract month being hedged as an adjustment to
gas revenue.
 
 As of
March 31, 2005, Atlas Pipeline had the following natural gas liquids, natural
gas, and crude oil volumes hedged.
 
 **Natural
Gas Basis Swaps - Price Swaps**
 Production
    
    
    
    Average
    
    Fair
      ValueVolumes
    
    Fixed
      Price
    
    Asset(3)(MMBTU)(1)
    
    (perMMBTU)
    
    (in
      thousands)2006
    
    
    990,000
    
    $
    (0.500
    )
    $
    156$
    156
 
 **Natural
Gas Liquids Fixed - Price Swaps**
 Production
    
    
    
    Average
    
    Fair
      ValueVolumes
    
    Fixed
      Price
    
    Liability(2)(gallons)
    
    (per
      gallon)
    
    (in
      thousands)2006
    
    
    15,966,000
    
    $
    0.585
    
    $
    (5,453
    )2007
    
    
    4,536,000
    
    
    0.574
    
    
    (1,581
    )$
    (7,034
    )
  13
 *Index*
  **ATLAS
AMERICA, INC.**
 **NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**
 **March
31, 2005**
 (Unaudited)
 
 **NOTE
5 - DERIVATIVE INSTRUMENTS - (Continued)**
 
 **Natural
Gas Fixed - Price Swaps**
 Production
    
    
    
    Average
    
    Fair
      ValueVolumes
    
    Fixed
      Price
    
    Liability(3)(MMBTU)(1)
    
    (per
      MMBTU)
    
    (in
      thousands)2006
    
    
    1,110,000
    
    $
    6.203
    
    $
    (2,077
    )2007
    
    
    300,000
    
    
    5.905
    
    
    (426
    )$
    (2,503
    )
 
 **Crude
Oil Fixed - Price Swaps**
 Production
    
    
    
    Average
    
    Fair
      ValueVolumes
    
    Fixed
      Price
    
    Liability(3)(barrels)
    
    (per
      barrel)
    
    (in
      thousands)2006
    
    
    9,000
    
    $
    40.958
    
    $
    (136
    )2007
    
    
    21,000
    
    
    40.818
    
    
    (295
    )$
    (431
    )
 
 **Crude
Oil Options**
 Production
    
    
    
    
    
    Average
    
    Fair
      ValueOption
      Type
    
    Volumes
    
    Strike
      Price
    
    Liability(3)(barrels)
    
    (per
      barrel)
    
    (in
      thousands)2006
    
    
    Puts
      Purchased
    
    
    45,000
    
    $
    30.00
    
    
    -2006
    
    
    Calls
      sold
    
    
    45,000
    
    
    34.25
    
    $
    (1,007
    )$
    (
      1,007
    )Total
      liability
    
    $
    (
      10,819
    )
 _________________________________
 MMBTU
means Million British Thermal Units.
  (1)
    Fair
      value based on APLMC internal model which forecasts forward natural gas
      liquid prices as a function of forward NYMEX natural gas and light crude
      prices.
 (2)
    Fair
      value based on forward NYMEX natural gas and light crude prices, as
      applicable.
  14
 *Index*
  **ATLAS
AMERICA, INC.**
 **NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**
 **March
31, 2005**
 (Unaudited)
 
 **NOTE
6 - PROPERTY AND EQUIPMENT**
 
 Property
and equipment is stated at cost. Depreciation, depletion and amortization is
based on cost less estimated salvage value primarily using the
unit-of-production or straight-line method over the assets estimated useful
lives. Maintenance and repairs are expensed as incurred. Major renewals and
improvements that extend the useful lives of property are
capitalized.
 
 The
Company uses the “successful efforts” method to account for its exploration and
production activities. Under this method, costs are accumulated on a
pool-by-pool basis with certain exploratory expenditures and exploratory dry
holes expensed as incurred. Costs of productive wells and development dry holes
are capitalized and amortized on the unit-of-production method for each pool
based on estimated proved oil and gas reserves.
 
 The
estimated service lives of other property and equipment are as
follows:
 
 Pipelines,
      processing and compression facilities
    15-20
      yearsRights-of-way
      - Appalachia
    20
      yearsRights-of-way
      - Mid-Continent-Velma
    40
      yearsLand,
      buildings and improvements
    10-40
      yearsFurniture
      and equipment
    3-7
      yearsOther
    3-10
      years
 
 Property
and equipment consists of the following (in thousands):
 
 **March
      31,**
    
    **September
      30,****2005**
    
    **2004**Mineral
      interests:Proved
      properties
    
    $
    2,936
    
    $
    2,544Unproved
      properties
    
    
    1,002
    
    
    1,002Wells
      and related equipment
    
    
    213,781
    
    
    184,046Pipelines,
      processing and compression facilities
    
    
    174,251
    
    
    163,302Rights-of-way
    
    
    15,107
    
    
    14,702Land,
      buildings and improvements
    
    
    7,632
    
    
    7,213Support
      equipment
    
    
    3,193
    
    
    2,902Other
    
    
    4,512
    
    
    4,227422,414
    
    
    379,938Accumulated
      depreciation, depletion and amortization:Oil
      and gas properties
    
    
    (73,060
    )
    
    (63,551
    )Other
    
    
    (3,839
    )
    
    (3,296
    )(76,899
    )
    
    (66,847
    )$
    345,515
    
    $
    313,091
  15
 *Index*
  **ATLAS
AMERICA, INC.**
 **NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**
 **March
31, 2005**
 (Unaudited)
 
 **NOTE
7 - ASSET RETIREMENT OBLIGATIONS**
 
 The
Company accounts for its estimated plugging and abandonment of its oil and gas
properties in accordance with SFAS 143, Accounting for Asset Retirement
Obligations. A reconciliation of the Company’s liability for well plugging and
abandonment costs is as follows at the dates indicated (in thousands):
  **Three
      Months Ended**
    
    **Six
      Months Ended****March
      31,**
    
    **March
      31,****2005**
    
    **2004**
    
    **2005**
    
    **2004**Asset
      retirement obligations, beginning of period
    
    $
    5,618
    
    $
    3,180
    
    $
    4,888
    
    $
    3,131Liabilities
      incurred
    
    
    1,008
    
    
    71
    
    
    1,658
    
    
    101Liabilities
      settled
    
    
    (28
    )
    
    (15
    )
    
    (32
    )
    
    (43
    )Accretion
      expense
    
    
    109
    
    
    52
    
    
    193
    
    
    99Revisions
      of previous estimates
    
    
    -
    
    
    83
    
    
    -
    
    
    83Asset
      retirement obligations, end of period
    
    $
    6,707
    
    $
    3,371
    
    $
    6,707
    
    $
    3,371
 The above
accretion expense is included in depreciation, depletion and amortization
expense in the Company’s consolidated statements of income and the asset
retirement obligation liabilities are included in other liabilities in the
Company’s consolidated balance sheets.
 
 **NOTE
8 - INCOME TAXES**
 
 The
Company is included in the consolidated federal income tax return of Resource
America.  Income taxes are calculated as if the Company had filed a return
on a separate company basis.  The Company records deferred tax assets and
liabilities, as appropriate, to account for the estimated future tax effects
attributable to temporary differences between the financial statement and tax
bases of assets and liabilities and operating loss carry forwards, using
currently enacted tax rates.  The deferred tax provision or benefit each
year represents the net change during that year in the deferred tax asset and
liability balances.  Separate company state tax returns are filed in those
states in which the Company is registered to do business.
  16
 *Index*
  **ATLAS
AMERICA, INC.**
 **NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**
 **March
31, 2005**
 (Unaudited)
 
 **NOTE
9 - OTHER ASSETS AND INTANGIBLE ASSETS**
 
 **Other
Assets**
 
 The
following table provides information about other assets at the dates indicated
(in thousands):
 
 **March
       31,**
    
    **September
      30,****2005**
    
    **2004**Deferred
      financing costs, net of accumulated amortization of $1,701 and $1,080
    
    $
    5,479
    
    $
    4,704Investments
    
    
    2,134
    
    
    2,166Security
      deposits
    
    
    1,376
    
    
    1,085Acquisition
      costs - Elk City (see note 15)
    
    
    532
    
    
    -$
    9,521
    
    $
    7,955
 
 Deferred
financing costs are recorded at cost and are amortized over the terms of the
related loan agreements which range from three to five years. Additional
financing costs of $1,389,000 were incurred during the six months ended March
31, 2005 related to Atlas Pipeline’s new credit facility (see note
15).
 
 **Intangible
Assets**
 
 Intangible
assets consist of partnership management and operating contracts acquired
through acquisitions and recorded at fair value on their acquisition
dates.  The Company amortizes contracts acquired on a declining balance or
straight-line method over their respective estimated lives, ranging from five to
thirteen years.  Amortization expense for the six months ended March 31,
2005 and 2004 was $466,000 and $519,000, respectively.  The aggregate
estimated annual amortization expense is approximately $815,000 for each of the
succeeding five-year periods.
 
 The
following table provides information about intangible assets at the dates
indicated (in thousands):
 
 **March
      31,**
    
    **September
      30,****2005**
    
    **2004**Partnership
      management and operating contracts
    
    $
    14,343
    
    $
    14,343Accumulated
      amortization
    
    
    (7,566
    )
    
    (7,100
    )Intangible
      assets, net
    
    $
    6,777
    
    $
    7,243
  17
 *Index*
  **ATLAS
AMERICA, INC.**
 **NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**
 **March
31, 2005**
 (Unaudited)
 
 **NOTE
10 - DEBT**
 
 Total
debt consists of the following at the dates indicated (in
thousands):
 **March
      31,**
    
    **September
      30,****2005**
    
    **2004**Revolving
      credit facilities
    
    $
    60,000
    
    $
    25,000Term
      loan
    
    
    43,690
    
    
    60,000Other
      debt
    
    
    293
    
    
    640103,983
    
    
    85,640Less
      current maturities
    
    
    2,361
    
    
    3,401$
    101,622
    
    $
    82,239
 Annual
debt principal payments over the next five years ending March 31 are as follows (in
thousands):
 
 2006
    
    $
    2,3612007
    
    
    52,3552008
    
    
    2,3002009
    
    
    12,2412010
    
    
    34,726
 
 **NOTE
11 - ACQUISITION OF SPECTRUM BY ATLAS PIPELINE**
 
 On July
16, 2004, Atlas Pipeline acquired Spectrum Field Services, Inc. (“Spectrum or
Mid-Continent-Velma”), for approximately $143.0 million, including transaction
costs and the payment of taxes due as a result of the transaction. Spectrum’s
principal assets include 1,900 miles of natural gas pipelines and a natural gas
processing facility in Velma, Oklahoma.
 
 The
acquisition was accounted for using the purchase method of accounting under SFAS
No. 141, Business Combinations. The following table presents the allocation of
the purchase price, including professional fees and other related acquisition
costs, to the assets acquired and liabilities assumed, based on their fair
values at the date of acquisition (in thousands):
 
 Cash
      and cash equivalents
    
    $
    803Accounts
      receivable
    
    
    18,505Prepaid
      expenses
    
    
    649Property,
      plant and equipment
    
    
    140,780Other
      long-term assets
    
    
    1,054Total
      assets acquired
    
    
    161,791Accounts
      payable and accrued liabilities
    
    
    (17,153
    )Hedging
      liabilities
    
    
    (1,519
    )Long-term
      debt
    
    
    (164
    )Total
      liabilities assumed
    
    
    (18,836
    )Net
      assets acquired
    
    $
    142,955
 
  Atlas
Pipeline is in the process of evaluating certain estimates made in the purchase
price and related allocations; thus, the purchase price and allocation are both
subject to adjustment.
   18
 *Index*
  **ATLAS
AMERICA, INC.**
 **NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**
 **March
31, 2005**
 (Unaudited)
 
 **NOTE
11 - ACQUISITION OF SPECTRUM BY ATLAS PIPELINE -
(Continued)**
 
 The
following summarized unaudited pro forma consolidated income statement
information for the three months and six months ended March 31, 2004 assumes
that the acquisition occurred as of October 1, 2003.  The Company has
prepared these pro forma financial results for comparative purposes only. 
These pro forma financial results may not be indicative of the results that
would have occurred for the three months and six months ended March 31, 2004 had
the acquisition been completed on October 1, 2003 or the results that will be
attained in the future.  The amounts presented below are in thousands,
except per share amounts:
 
 **Three
      Months Ended**
      **March 
      31, 2004**As
      Reported
    
    Pro
      Forma
      Adjustment
    
    Pro
      FormaRevenues
    
    $
    41,749
    
    $
    27,202
    
    $
    68,951Net
      income
    
    $
    5,166
    
    $
    (287
    )
    $
    4,879Net
      income per common share − basic
    
    $
    .48
    
    $
    (.02
    )
    $
    .46Weighted
      average common shares − outstanding
    
    
    10,688
    
    
    -
    
    
    10,688Net
      income per common share − diluted
    
    $
    .48
    
    $
    (.02
    )
    $
    .46Weighted
      average common shares
    
    
    10,688
    
    
    -
    
    
    10,688
 
 **Six
      Months Ended**
      **March 
      31, 2004**As
      Reported
    
    Pro
      Forma
      Adjustment
    
    Pro
      FormaRevenues
    
    $
    77,440
    
    $
    49,736
    
    $
    127,176Net
      income
    
    $
    10,059
    
    $
    (752
    )
    $
    9,307Net
      income per common share − basic
    
    $
    .94
    
    $
    (.07
    )
    $
    .87Weighted
      average common shares − outstanding
    
    
    10,688
    
    
    -
    
    
    10,688Net
      income per common share − diluted
    
    $
    .94
    
    $
    (.07
    )
    $
    .87Weighted
      average common shares
    
    
    10,688
    
    
    -
    
    
    10,688
 
 Significant
pro forma adjustments include revenues and costs and expenses for the period
prior to Atlas Pipeline’s acquisition, interest and depreciation expenses and
the elimination of income taxes.
  19
 *Index*
  **ATLAS
AMERICA, INC.**
 **NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**
 **March
31, 2005**
 (Unaudited)
 
 **NOTE
12 - OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS**
 
 The
Company’s operations include four reportable operating segments.  In
addition to the reportable operating segments, certain other activities are
reported in the “Other energy” category.  These operating segments reflect
the way the Company manages its operations and makes business decisions. The
Company does not allocate income taxes to its operating segments. 
Operating segment data for the periods indicated are as follows:
 
 **Three
      Months Ended March 31, 2005**(in thousands):Revenues
      from
      external
      customers
    
    Interest
      income
    
    Interest
      expense
    
    Depreciation,
      depletion
      and
      amortization
    
    Segment
      profit
      (loss)
    
    Other
      significant
      items:
      Segment
      assetsWell
      drilling
    
    $
    41,451
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    4,892
    
    $
    9,263Production
      and exploration
    
    
    13,959
    
    
    -
    
    
    -
    
    
    3,114
    
    
    8,393
    
    
    194,287Natural
      gas and liquids
    
    
    42,334
    
    
    11
    
    
    5
    
    
    988
    
    
    2,852
    
    
    163,160Transportation
      and compression
    
    
    1,407
    
    
    65
    
    
    -
    
    
    573
    
    
    (165
    )
    
    37,710Other(a)
    
    
    2,350
    
    
    6
    
    
    1,618
    
    
    106
    
    
    (2,665
    )
    
    47,014Total
    
    $
    101,501
    
    $
    82
    
    $
    1,623
    
    $
    4,781
    
    $
    13,307
    
    $
    451,434
 
 
 **Three
      Months Ended March 31, 2004**(in thousands):Revenues
      from
      external
      customers
    
    Interest
      income
    
    Interest
      expense
    
    Depreciation,
      depletion
      and
      amortization
    
    Segment
      profit
      (loss)
    
    Other
      significant
      items:
      Segment
      assetsWell
      drilling
    
    $
    26,248
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    3,007
    
    $
    7,725Production
      and exploration
    
    
    11,799
    
    
    -
    
    
    -
    
    
    2,513
    
    
    5,847
    
    
    150,683Natural
      gas and liquids
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Transportation
      and compression
    
    
    1,579
    
    
    17
    
    
    -
    
    
    518
    
    
    200
    
    
    32,605Other(a)
    
    
    2,123
    
    
    3
    
    
    473
    
    
    503
    
    
    (1,341
    )
    
    36,518Total
    
    $
    41,749
    
    $
    20
    
    $
    473
    
    $
    3,534
    
    $
    7,713
    
    $
    227,531
  20
 *Index*
  **ATLAS
AMERICA, INC.**
 **NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**
 **March
31, 2005**
 (Unaudited)
 
 **NOTE
12 - OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS -
(Continued)**
 
 **Six
      Months Ended March  31, 2005**(in thousands):Revenues
      from
      external
      customers
    
    Interest
      income
    
    Interest
      expense
    
    Depreciation,
      depletion
      and
      amortization
    
    Segment
      profit
      (loss)
    
    Other
      significant
      items:
      Segment
      assetsWell
      drilling
    
    $
    72,009
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    8,570
    
    $
    9,263Production
      and exploration
    
    
    28,618
    
    
    -
    
    
    -
    
    
    5,918
    
    
    18,506
    
    
    194,287Natural
      gas and liquids
    
    
    84,395
    
    
    31
    
    
    13
    
    
    3,150
    
    
    6,500
    
    
    163,160Transportation
      and compression
    
    
    3,128
    
    
    108
    
    
    -
    
    
    1,118
    
    
    (95
    )
    
    37,710Other(a)
    
    
    4,598
    
    
    56
    
    
    3,300
    
    
    467
    
    
    (6,280
    )
    
    47,014Total
    
    $
    192,748
    
    $
    195
    
    $
    3,313
    
    $
    10,653
    
    $
    27,201
    
    $
    451,434
 
 **Six
      Months Ended March  31, 2004**(in thousands):Revenues
      from
      external
      customers
    
    Interest
      income
    
    Interest
      expense
    
    Depreciation,
      depletion
      and
      amortization
    
    Segment
      profit
      (loss)
    
    Other
      significant
      items:
      Segment
      assetsWell
      drilling
    
    $
    48,207
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    5,505
    
    $
    7,725Production
      and exploration
    
    
    21,995
    
    
    -
    
    
    -
    
    
    4,722
    
    
    12,031
    
    
    150,683Natural
      gas and liquids
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Transportation
      and compression
    
    
    3,178
    
    
    37
    
    
    -
    
    
    1,023
    
    
    (90
    )
    
    32,605Other(a)
    
    
    4,060
    
    
    22
    
    
    960
    
    
    1,033
    
    
    (2,205
    )
    
    36,518Total
    
    $
    77,440
    
    $
    59
    
    $
    960
    
    $
    6,779
    
    $
    15,241
    
    $
    227,531
 
 (a)
    Includes
      revenues and expenses from well services which do not meet the
      quantitative threshold for reporting segment information and general
      corporate expenses not allocable to any particular segment.  Segment
      operating profit (loss) represents total revenues less costs and expenses
      attributable thereto, including interest and depreciation, depletion and
      amortization, excluding general corporate
expenses.
 
 
 The
Company’s natural gas and natural gas liquids are sold under contract to various
purchasers.  For the six months ended March 31, 2005, sales to one of Mid-Continent-Velma’s purchasers accounted for 17% of the Company’s revenues.  No other operating
segments had revenues from a single customer which exceeded 10% of total
revenues.
  21
 *Index*
  **ATLAS
AMERICA, INC.**
 **NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**
 **March
31, 2005**
 (Unaudited)
 **NOTE
13 - BENEFIT PLANS**
 
 *Stock
Incentive Plan.* The
Company has a Stock Incentive Plan (the “Plan”) for employees, consultants and
directors of the Company and its affiliates, in which a maximum of 1,333,333
shares are reserved for issuance.  In May 2004, 4,835 deferred units
representing a right to receive a share of common stock over a 4-year vesting
period (at an average price at the date of grant of $15.50 per unit) were
awarded to non-employee directors of the Company under this plan.  The fair
value of the grants awarded ($75,000 in total) will be charged to operations
over the vesting period.  Units will vest sooner upon a change of control
of the Company or death or disability of a grantee, except that no units can
vest before the date of the Company’s spin-off from Resource America is
completed or abandoned.  Upon termination of service by a grantee, all
unvested units are forfeited.
 
 Under the
Plan, on an annual basis, non-employee directors of the Company are awarded
deferred units having a fair market value of $15,000. Each unit represents the
right to receive one share of the Company’s common stock upon vesting. The
shares vest one-third on the second anniversary of the grant, one-third on the
third anniversary of the grant and one-third on the fourth anniversary of the
grant, except that no units can vest before the date the spin-off from Resource
America is completed or abandoned.
 
 *Supplement
Employment Retirement Plan (“SERP”).* In May
2004, the Company entered into an employment agreement with its Chairman and
Chief Executive Officer pursuant to which the Company has agreed to provide him
with a SERP and with certain financial benefits upon termination of his
employment.  During the three months and six months ended March 31, 2005,
operations were charged $39,000 and $79,000, respectively, with respect to this
commitment.
  22
 *Index*
  **ATLAS
AMERICA, INC.**
 **NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**
 **March
31, 2005**
 (Unaudited)
 
 **NOTE
13 - BENEFIT PLANS - (Continued)**
 
 *Atlas
Pipeline Plan.* Atlas
Pipeline has a Long-Term Incentive Plan for officers and non-employee managing
board members of its general partner and employees of the general partner,
consultants and joint venture partners who perform services for Atlas
Pipeline.  Atlas Pipeline recognized $548,000 and $949,000 in compensation
expense under the plan related to grants of phantom units and their associated
distributions in the three months and six months ended March 31, 2005,
respectively.  The fair market value associated with these grants is $5.6
million which will be amortized into expense over the vesting period of the
units.
 
 A summary
of the phantom units for the periods indicated, is listed below (in thousands,
except per unit data):
 
 **Three
      Months Ended**
      **March
      31,**
    
    **Sixth
      Months Ended**
      **March
      31,****2005**
    
    **2004**
    
    **2005**
    
    **2004****(in
      thousands, except unit data)**Balance,
      beginning of period
    
    
    58,752
    
    
    -
    
    
    58,752
    
    
    -Granted
    
    
    67,338
    
    
    1,692
    
    
    67,338
    
    
    1,692Vested
    
    
    (210
    )
    
    -
    
    
    (210
    )
    
    -Forfeited
    
    
    (679
    )
    
    -
    
    
    (679
    )
    
    -Balance,
      end of period
    
    
    125,201
    
    
    1,692
    
    
    125,201
    
    
    1,692Fair
      value, end of period
    
    $
    5,620
    
    $
    68
    
    $
    5,620
    
    $
    68Vesting
      expense
    
    $
    548
    
    $
    -
    
    $
    949
    
    $
    -
  Units
granted under Atlas Pipeline’s **** Long-Term
Incentive Plan vest over a period of four years from the date of grant. Of the
125,201 units outstanding at March 31, 2005, 31,326 units vest within the next
twelve months.
 
 **NOTE
14 - SETTLEMENT OF ALASKA PIPELINE COMPANY ARBITRATION**
 
 In
September 2003, Atlas Pipeline entered into an agreement with SEMCO Energy, Inc.
to purchase all of the stock of Alaska Pipeline Company (“APC”). In order to
complete the acquisition, Atlas Pipeline needed the approval of the Regulatory
Commission of Alaska. The Regulatory Commission initially approved the
transaction, but on June 4, 2004, it vacated its order of approval based upon a
motion for clarification or reconsideration filed by SEMCO. On July 1, 2004,
SEMCO sent Atlas Pipeline a notice purporting to terminate the transaction.
Atlas Pipeline pursued its remedies under the acquisition agreement. In
connection with the acquisition, subsequent termination, and settlement of the
legal action, Atlas Pipeline incurred costs of approximately $1.2 million in the
six months ended March 31, 2005 which were included in arbitration settlement,
net on the Company’s Statements of Income. Atlas Pipeline also incurred $3.0
million of costs in the year ended September 30, 2004. On December 30, 2004,
Atlas Pipeline entered into an agreement with SEMCO settling all issues and
matters related to SEMCO’s termination of the sale of APC to
  23
 *Index*
  **ATLAS
AMERICA, INC.**
 **NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**
 **March
31, 2005**
 (Unaudited)
 
 **NOTE
14 - SETTLEMENT OF ALASKA PIPELINE COMPANY ARBITRATION -
(Continued)**
 
 Atlas
Pipeline and SEMCO paid Atlas Pipeline $5.5 million which was also included in
arbitration settlement, net.
  **NOTE
15 - SUBSEQUENT EVENTS**
 
 **Elk
City Acquisition**
 
 On April
14, 2005, Atlas Pipeline acquired all of the outstanding equity interests in ETC
Oklahoma Pipeline, Ltd. (“Elk City”), a Texas limited partnership, for $194.4
million including related transaction costs. Elk
City’s principal assets include 318 miles of natural gas pipelines located in
the Anadarko Basin in western Oklahoma, a natural gas processing facility in Elk
City, Oklahoma, with total capacity of 130 million cubic feet of gas per day
("mmcf/d") and a gas treatment facility in Prentiss, Oklahoma, with a total
capacity of 100 mmcf/d. Total gas throughput is currently approximately 262
mmcf/d. Total compression horsepower (hp) consists of 21,000 hp at six field
stations and 12,000 hp within the Elk City and Prentiss facilities. The system
gathers and processes gas from more than 300 receipt points representing more
than fifty producers and delivers that gas into multiple interstate pipeline
systems. T he
acquisition expands Atlas Pipeline’s activities in the Mid-Continent area and
provides the potential for further growth in Atlas Pipeline’s operations based
in Tulsa, Oklahoma.
 
 The
acquisition was accounted for using the purchase method of accounting under SFAS
No. 141 Business Combinations. The following table presents the allocation of
the purchase price, including professional fees and other related acquisition
costs, to the assets acquired and liabilities assumed, based on their fair
values at the date of acquisition (in thousands):
 
 Accounts
      receivable
    
    $
    3,837Other
      current assets
    
    
    1,237Property,
      plant and equipment
    
    
    193,121Total
      assets acquired
    
    
    198,195Accounts
      payable and accrued liabilities
    
    
    (3,770
    )Total
      liabilities assumed
    
    
    (3,770
    )Net
      assets acquired
    
    $
    194,425
 
  24
 *Index*
  **ATLAS
AMERICA, INC.**
 **NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS** **-** **(Continued)**
 **March
31, 2005**
 (Unaudited)
 
 **NOTE
15 - SUBSEQUENT EVENTS - (Continued)**
 
 **Elk
City Acquisition - (Continued)**
 
 The
purchase price is subject to post-closing adjustment based, among other things,
on gas imbalances, certain prepaid expenses, capital expenditures, and title
defects, if any. In addition, Atlas Pipeline is in the process of evaluating
certain estimates made in the purchase price and related allocations; thus, the
purchase price and allocation are both subject to adjustment.
 
 **Credit
Facility**
 
 To
finance the Elk City acquisition, Atlas Pipeline entered
into a new $270 million credit facility which replaced its existing $135 million
facility. Wachovia Capital Markets, LLC and Bank of America Securities LLC, are
Co-Lead Arrangers for this facility. The bank group consists of the twelve banks
that participated in the prior credit facility plus five new
participants.
 
 The five
year facility is comprised of a $225 million revolving line of credit and a $45
million five year term loan. Atlas Pipeline immediately drew down $249.5 million
which was used to refinance the existing $53.8 million outstanding on the prior
$135 million facility and to finance the acquisition of Elk City.
 
 The
credit facility requires Atlas
Pipeline to
maintain a specified interest coverage ratio, a specified ratio of funded debt
to earnings before interest, taxes, depreciation, depletion and amortization
(“EBITDA”), adjusted as provided in the credit facility and a specified ratio of
senior secured debt to such adjusted EBITDA.
 
 **Spin
off from Resource America, Inc.**
 
 In May
2005, Resource America, Inc. (“RAI”) received the rulings it requested from the
Internal Revenue Service in connection with the distribution of its remaining
10.7 million shares of the Company to the stockholders of RAI. The effect of the
rulings is that, among other things, the distribution will be tax-free for U.S.
federal income tax purposes to RAI and its stockholders. However, the consequent
deconsolidation of RAI and the Company may result in some tax liability to
the Company arising from prior unrelated corporate transactions among the
Company and some of its subsidiaries.  According to the terms of the spin
off, each stockholder of RAI will receive approximately 0.6 shares of the
Company's common stock for each share of RAI common stock owned in the form
of a tax-free dividend. RAI intends to complete the distribution by the close of
its present fiscal quarter, which ends on June 30, 2005.
  25
 *Index*
  **Item 2.Management’s Discussion and Analysis of Financial
Condition and Results of Operations (unaudited)**
 
 **When
used in this Form 10-Q, the words “believes” “anticipates,” “expects” and
similar expressions are intended to identify forward-looking statements. 
Such statements are subject to certain risks and uncertainties more particularly
described in Item 1, under the caption “Risk Factors”, in our annual report on
Form 10-K for fiscal 2004.  These risks and uncertainties could cause
actual results to differ materially.  Readers are cautioned not to place
undue reliance on these forward-looking statements, which speak only as of the
date hereof.  We undertake no obligation to publicly release the results of
any revisions to forward-looking statements which we may make to reflect events
or circumstances after the date of this Form 10-Q or to reflect the occurrence
of unanticipated events.**
 
 ***General***
 
 During
the six months ended March 31, 2005, our operations continued to grow as we
increased our total assets, revenues, number of wells drilled and number of
wells operated.
 
 Our gross
revenues depend, to a significant extent, on the price of natural gas and oil
which can fluctuate significantly.  We seek to balance this volatility with
the more stable net income from our well drilling and well servicing operations
which are principally fee-based.  Our business strategy for increasing our
reserve base includes acquisitions of undeveloped properties or companies with
significant amounts of undeveloped property.  However, as a result of our
agreements with Resource America, Inc., our ultimate parent, relating to its
proposed tax-free distribution to its stockholders of the stock it owns in
us, we will
be limited in our ability to issue voting securities, non-voting securities or
convertible debt and in making acquisitions or entering into mergers or other
business combinations that would jeopardize the tax-free status of the
distribution until such time that Resource America completes the spin-off. At March
31, 2005, we had $23.6 million available under our credit facility, which could
be employed to finance such acquisitions.
 
 Our
financial condition and results of operations have been affected by initiatives
taken by Atlas Pipeline Partners, L.P.  In fiscal 2004, Atlas Pipeline
completed two public offerings of its common units, realizing $92.7 million of
offering proceeds, net of expenses.  The principal financial effect of
these offerings was an increase to the minority interest in our financial
statements.
 
 In July
2004, Atlas Pipeline acquired Spectrum Field Services, Inc. (which changed its
name to Atlas Pipeline Mid-Continent, LLC (“APLMC” or “Mid-Continent-Velma”) for
approximately $143.0 million, including transaction costs and the payment of
anticipated taxes due as a result of the transaction.  This acquisition
significantly increased Atlas Pipeline's size and diversifies the natural gas
supply basins in which it operates and the natural gas midstream services it
provides to its customers.  Spectrum was a privately owned natural gas
gathering and processing company headquartered in Tulsa, Oklahoma.
 
 ***Spin-off
by Resource America***
 
 In May
2005, Resource America, received the rulings it requested from the Internal
Revenue Service in connection with the distribution of its remaining 10.7
million shares of our stock to the stockholders of Resource America. The effect
of the rulings is that, among other things, the distribution will be tax-free
for U.S. federal income tax purposes to Resource America and its
stockholders.  However, as a result of the deconsolidation there may be
some tax liability arising from prior unrelated corporate transactions among the
Company and some of its subsidiaries.  According to the terms of the spin
off, each stockholder of Resource America will receive approximately 0.6 shares
of our common stock for each share of Resource America common stock owned
in the form of a tax-free dividend. Resource America intends to complete the
distribution by the close of its present fiscal quarter, which ends on June 30,
2005.
  26
 *Index*
  ***Recent
Developments***
 
 On April
14, 2005, Atlas Pipeline acquired all of the outstanding equity interests in ETC
Oklahoma Pipeline, Ltd., a Texas limited partnership, for $194.4 million
including related transaction costs. ETC Oklahoma Pipeline’s principal assets
include approximately 318 miles of natural gas pipelines located in the Anadarko
Basin in western Oklahoma, a natural gas processing facility in Elk City,
Oklahoma with total capacity of 130 million cubic feet of gas per day or mmcf/d
and a gas treatment facility in Prentiss, Oklahoma, with a total capacity of 100
mmcf/d. Total gas throughput is currently approximately 262 mmcf/d. Total
compression horsepower consists of 21,000 hp at six field stations and 12,000
horsepower within the Elk City and Prentiss facilities. The system gathers and
processes gas from more than 300 receipt points representing more than fifty
producers and delivers that gas into multiple interstate pipeline systems. The
acquisition expands Atlas Pipeline’s activities in the mid-continent area and
provides the potential for further growth in Atlas Pipeline’s operation based in
Tulsa, Oklahoma.
 
 To
finance the acquisition, Atlas Pipeline entered into a new $270 million credit
facility which replaces its existing $135 million facility. Wachovia Capital
Markets, LLC and Bank of America Securities LLC, are Co-Lead Arrangers. The bank
group consists of the twelve banks that participated in the prior credit
facility, plus five new participants.
 
 The five
year facility is comprised of a $225 million revolving line of credit and a $45
million five-year term loan. Atlas Pipeline immediately borrowed $249.5 million
which was used to refinance the existing $53.8 million outstanding on the prior
$135 million facility and to finance the acquisition of ETC Oklahoma Pipeline,
Ltd.
 
 **Results
of Operations for the Three Months and Six Months Ended March 31, 2005 and
2004**
 
 ***Well
Drilling***
 
 Our well
drilling revenues and costs and expenses incurred represent the billings and
costs associated with the completion of wells for drilling investment
partnerships we sponsor.  The following table sets forth information
relating to these revenues and the related costs, gross profit margins and
number of net wells drilled
during the periods indicated (dollars in thousands):
  **Three
      Months Ended**
    
    **Six
      Months Ended****March
       31,**
    
    **March
      31,****2005**
    
    **2004**
    
    **2005**
    
    **2004**Average
      drilling revenue per well
    
    $
    200
    
    $
    167
    
    $
    210
    
    $
    180Average
      drilling cost per well
    
    
    174
    
    
    145
    
    
    183
    
    
    156Average
      drilling gross profit per well
    
    $
    26
    
    $
    22
    
    $
    27
    
    $
    23Gross
      profit margin
    
    $
    5,407
    
    $
    3,424
    
    $
    9,392
    
    $
    6,288Gross
      margin percent
    
    
    13%
    
    
    13%
    
    
    13%
    
    
    13%Net
      wells drilled
    
    
    207
    
    
    157
    
    
    343
    
    
    268
 Our well
drilling gross margin was $5.4 million and $9.4 million in the three months and
six months ended March 31, 2005, an increase of $2.0 million (58%) and $3.1
million (49%) from $3.4 million and $6.3 million in the three months and six
months ended March 31, 2004, respectively.  In the three months ended March
31, 2005, the increase of $2.0 million in gross margin was attributable to an
increase in the number of wells drilled ($1.3 million) and an increase in the
gross profit per well ($677,000). In the six months ended March 31, 2005, the
increase of $3.1 million was attributable to an increase in the number of wells
drilled ($2.1
million) and an increase in the gross profit per well ($1.0 million). 
Since our drilling contracts are on a “cost plus” basis (typically cost plus
15%), an increase in our average cost per well also results in an increase in
our average revenue per well.  The increase in our average cost per well in
the three months and six months ended March 31, 2005 resulted from an increase
in the cost of tangible equipment used in the wells.  In addition, it
should be noted that “Liabilities associated with drilling contracts” on our
balance sheet includes $17.1 million of funds raised in our drilling investment
programs in late fiscal 2004 and the three months ended December 31, 2004 that
had not been applied to drill wells as of March 31, 2005 due to the timing of
drilling operations, and thus had not been recognized as well drilling
revenue.  We expect to recognize this amount as revenue in the remainder of
fiscal 2005. Because we raised $62.3 million in the first six months of fiscal
2005 as compared to $40.2 million in the six months of fiscal 2004, we
anticipate drilling revenues and related costs to be substantially higher in
fiscal 2005 than in fiscal 2004.
  27
 *Index*
  ***Gas
and Oil Production***
 
 The
following table sets forth information relating to our production revenues,
production volumes, sales prices, production costs and depletion:
 
 **Three
      Months Ended**
    
    **Six
      Months Ended****March
      31,**
    
    **March
      31,********2005**
    
    **2004**
    
    **2005******
    
    **2004**Production
      revenues (in thousands):Gas(1)
    
    $
    12,285
    
    $
    10,116
    
    $
    24,982
    
    $
    19,182Oil
    
    $
    1,647
    
    $
    1,666
    
    $
    3,589
    
    $
    2,789Production
      volume:Gas
      (mcf/day)(1)
      (3)
    
    
    19,315
    
    
    18,265
    
    
    19,806
    
    
    18,875Oil
      (bbls/day)
    
    
    406
    
    
    576
    
    
    427
    
    
    514Total
      (mcfe/day)(3)
    
    
    21,751
    
    
    21,721
    
    
    22,368
    
    
    21,959Average
      sales prices:Gas
      (per mcf)(3)
    
    $
    7.07
    
    $
    6.09
    
    $
    6.93
    
    $
    5.55Oil
      (per bbl)(3)
    
    $
    45.06
    
    $
    31.81
    
    $
    46.18
    
    $
    29.65Production
      costs(2):As
      a percent of production revenues
    
    
    16%
    
    
    15%
    
    
    14%
    
    
    16%Per
      mcfe(3)
    
    $
    1.11
    
    $
    .91
    
    $
    .96
    
    $
    .85Depletion
      per mcfe(3)
    
    $
    1.36
    
    $
    1.24
    
    $
    1.29
    
    $
    1.15
 
 (1)
    Excludes
      sales of residual gas and sales to
landowners.
 (2)
    Production
      costs include labor to operate the wells and related equipment, repairs
      and maintenance, materials and supplies, property taxes, severance taxes,
      insurance, gathering charges and production overhead.
 (3)
    “Mcf”
      and “mmcf” means thousand cubic feet and million cubic feet; “mcfe” and
      “mmcfe” means thousand cubic feet equivalent and million cubic feet
      equivalent, and “bbls” means barrels.  Bbls are converted to mcfe
      using the ratio of six mcfs to one
bbl.
 
 Our
natural gas revenues were $12.3 million and $25.0 million in the three months
and six months ended March 31, 2005, an increase of $2.2 million (21%) and $5.8
million (30%) from $10.1 million and $19.2 million in the three months and six
months ended March 31, 2004 respectively.  The increases were due to
an increase in the average sales price of natural gas of 16% and 25% for the
three months and six months ended March 31, 2005 and an increase of 5% in the
volume of natural gas produced in the three months and six months ended March
31, 2005. The $2.2 million increase in gas revenues in the three months ended
March 31, 2005 as compared to the prior period consisted of $1.6 million
attributable to increases in natural gas sales prices, and $539,000 attributable
to increased production volumes. The $5.8 million increase in natural gas
revenue in the six months ended March 31, 2005 as compared to the prior year
period consisted of $4.7 million attributable to increases in natural gas sales
prices, and $1.1 million attributable to increased production volumes.
  28
 *Index*
  Our oil
revenues were $1.6 million and $3.6 million in the three months and six months
ended March 31, 2005, a decrease of $19,000 (1%) and an increase of
$800,000 (29%), respectively, from $1.7 million and $2.8 million in the three
months and six months ended March 31, 2004. The average sales price of oil
increased 42% and 56% for the three months and six months ended March 31, 2005
as compared to the prior year similar periods. The $19,000 decrease in oil
revenues in three months ended March 31, 2005 as compared to the prior year
period consisted of $694,000 attributable to increases in sales prices, offset
by a $713,000 decrease in production volumes. The $800,000 increase in oil
revenues for the six months ended March 31, 2005 as compared to the prior year
period consisted of $1.6 million attributable to increases in sales prices
offset by $755,000 attributable to decreased production volumes.
 
 Our
production costs were $2.2 million and $3.9 million in the three months and six
months ended March 31, 2005, an increase of $382,000 (21%) and $495,000 (14%)
from $1.8 million and $3.4 million in the three months and six months ended
March 31, 2004.  These increases include an increase in insurance expense,
material costs related to well workovers and an increase in transportation
expenses associated with increased production volumes and natural gas sales
prices, as a portion of our wells are charged transportation based on the sales
price of the gas transported.
 
 Our
exploration costs were $236,000 and $288,000 in the three months and six months
ended March 31,
2005, a decrease of $1.3 million, from $1.5 million and $1.6 million in the
three months and six months ended March 31, 2004. We attribute these decreases
to the following: an increase in the benefit we receive for our contribution of
well sites to our drilling investment partnerships as a result of more wells
drilled; a decrease in dry hole costs which were expensed in the prior period,
no such costs were incurred in the six months ended March 31, 2005; partially
offset by increase in the cost of running our land department as we manage the
increase in our drilling activities.
 
 ***Gathering,
Transmission and Processing***
 
 Our
gathering, transmission and processing revenues and related expenses for the
three and six months ended March 31, 2005 increased significantly from the prior
year periods due to the acquisition of Spectrum on July 16, 2004.
 
 Revenues
increased $42.1 million and $84.3 million to $43.7 million and $87.5 million for
the three and six months ended March 31, 2005 from $1.6 million and $3.2 million
for the three and six months ended March 31, 2004.
 
 Expenses
increased $36.8 million and $71.9 million to $37.5 million and $73.1 million for
the three and six months ended March 31, 2005 from $620,000 and $1.2 million for
the three and six months ended March 31, 2004.
 
 ***Well
Services***
 
 Our well
services revenues were $2.3 million and $4.6 million in the three months and six
months ended March 31, 2005, an increase of $227,000 (11%) and $538,000 (13%)
from $2.1 million and $4.1 million in the three months and six months ended
March 31, 2004.  The increase resulted from an increase in the number of
wells operated for our investment partnerships due to additional wells drilled
in the twelve months ended March 31, 2005.
 
 Our well
services expenses were $1.3 million and $2.5 million in the three months and six
months ended March 31, 2005, an increase of $295,000 (29%) and $445,000 (22%)
from $1.0 million and $2.1 million in the three months and six months ended
March 31, 2004 respectively.  The increases were attributable to an
increase in wages benefits, and field office expenses associated with an
increase in employees due to the increase in the number of wells we operate for
our investment partnerships.
  29
 *Index*
  ***Other
Income, Costs and Expenses***
 
 Our
general and administrative expenses were $1.5 million and $3.2 million in the
three months
and six months ended March 31, 2005, an increase of $709,000 and $2.1 million
from $785,000 and $1.1 million in the three months and six months ended March 31,
2004.  These expenses include, among other things, salaries and benefits
not allocated to a specific
energy activity, costs of running our energy corporate office, partnership
syndication activities and outside services.  These expenses are partially
offset by reimbursements we receive from our drilling investment
partnerships.
 
 The increase of $709,000 in the three months ended
March 31, 2005 is principally attributable to $752,000 in general and
administrative expenses related to our Mid-Continent-Velma operations; we
acquired Spectrum on July 16, 2004 and therefore, we had no such expenses in the
quarter ended March 31, 2004.
 
 The
increase of $2.1 million in the six months ended March 31,
2005 as compared to the six months ended March 31, 2004 is attributable
principally to the following:
 
 ·
    general
      and administrative expenses related to our Mid-Continent-Velma operations
      were $1.3 million in the six months ended March  31, 2005; we
      acquired Spectrum on July 16, 2004;
 ·
    costs
      associated with Atlas Pipeline’s long-term incentive plan were $1.1
      million in the six months ended March 31, 2005; there were no such
      expenses in the prior year similar
period;
 ·
    an
      increase of $263,000 in legal and professional fees which includes the
      implementation of Sarbanes-Oxley Section 404
compliance
  These
increases were partially offset by a decrease in net syndication expenses of
$547,000 due to increased credits we received for costs incurred in organizing
and offering our partnership investments.
 
 Our
compensation reimbursements-affiliates decreased to $244,000 and $463,000 for
the three months and six months ended March 31, 2005, a decrease of $219,000
(47%) and $608,000 (57%) from $463,000 and $1.1 million in the three months and
six months ended March 31, 2004. These decreases resulted primarily from a
decrease in allocations from our parent for executive management and
administrative services as we now directly employee many of these individuals
and include their compensation in our general and administrative
expenses.
 
 Our
depletion of oil and gas properties as a percentage of oil and gas revenues was
20 % and 19% in the three months and six months ended March 31, 2005 compared to
21% in the three months and six months ended March 31, 2004.  Depletion
expense per mcfe was $1.36 and $1.29 in the three months and six months ended
March 31, 2005, an increase of $.12 (10%) per mcfe and $.14 (12%) per mcfe from
$1.24 and $1.15 in the three months and six months ended March 31, 2004. 
Increases in our depletable basis and production volumes caused depletion
expense to increase $240,000 (10%) and $730,000 (15%) to $2.8 million and $5.5
million in the three months and six months ended March 31, 2005 compared to $2.5
million and $4.7 million in the three months and six months ended March 31,
2004.  The variances from period to period are directly attributable to
changes in our oil and gas reserve quantities, production levels, product prices
and changes in the depletable cost basis of our oil and gas
properties.
 
 Our
interest expense was $1.6 million and $3.3 million in the three months and six
months ended March 31, 2005, an increase of $1.2 million and $2.4 million from
$473,000 and $960,000 in the three months and six months ended March 31,
2004.  These increases resulted primarily from an increase in outstanding
borrowings due to funds borrowed by Atlas Pipeline for the acquisition of
Spectrum.
 
 On
December 30, 2004, Atlas Pipeline entered into a settlement agreement with SEMCO
Energy, Inc. settling all issues and matters related to SEMCO’s termination of
the sale of Alaska Pipeline Company to Atlas Pipeline and SEMCO paid Atlas
Pipeline $5.5 million which is included in arbitration settlement-net on our
statements of income. In connection with the acquisition, subsequent
termination, and settlement of the legal action, Atlas Pipeline incurred costs
of approximately $136,000 and $1.2 million in the three months and six months
ended March 31, 2005, which are included in arbitration settlement-net on our
statements of income.  Atlas Pipeline also incurred $3.0 million of costs
in our year ended September 30, 2004.
  30
 *Index*
  At March
31, 2005, we own 24% of the partnership interests in Atlas Pipeline through our
general partner interest and limited partner units. The limited partner units
were subordinated until January 1, 2005, when the subordination term expired and
they were converted to common units in accordance with the terms of the
partnership agreement. Since March 31, 2003, our ownership interest has
decreased 35% from 59% as a result of the completion by Atlas Pipeline of common
unit offerings in May 2003 and April and July 2004.
 
 Because
we control the operations of Atlas Pipeline, we include it in our consolidated
financial statements and show the ownership by the public as a minority
interest.  The minority interest in Atlas Pipeline’s earnings was $2.5
million and $9.7 million for the three months and six months ended March 31,
2005, as compared to $1.3 million and $2.6 million for the three months and six
months ended March 31, 2004, an increase of $1.2 million and $7.1 million for
the three months and six months ended March 31, 2005, respectively. These
increases were a result of an increase in the percentage interest of public unit
holders and an increase in Atlas Pipeline’s net income, as discussed above.
 
 Our
effective tax rate increased to 36% for the three months and six months ended
March 31, 2005 as compared to 33% and 34% for the three months and six
months ended March 31, 2004 as a result of a reduction in statutory depletion
benefits relative to increased net income.
 
 **Liquidity
and Capital Resources**
 
 *General.* We
fund our exploration and production operations from a combination of cash
generated by operations, capital raised through drilling investment partnerships
and, if required, use of our credit facility.  We fund our gathering,
transmission and processing operations, which are conducted through Atlas
Pipeline, through a combination of cash generated by operations, Atlas
Pipeline’s credit facility and the sale of Atlas Pipeline’s common units. 
The following table sets forth our sources and uses of cash (in
thousands):
 
 **Six
      Months Ended****March
       31,****2005**
    
    **2004**Provided
      by operations
    
    $
    39,807
    
    $
    22,513Used
      in investing activities
    
    
    (41,590
    )
    
    (18,213
    )Used
      in financing activities
    
    
    (10,348
    )
    
    (17,764
    )Decrease
      in cash and cash equivalents
    
    $
    (12,131
    )
    $
    (13,464
    )
 
 We had
$17.1 million in cash and cash equivalents at March 31, 2005, as compared to
$29.2 million at September 30, 2004.  Our ratio of earnings from continuing
operations before income taxes, minority interest and interest expense to fixed
charges was 12.1 to 1.0 in the six months ended March 31, 2005 as compared to
19.6 to 1.0 in the six months ended March 31, 2004.  We had working capital
deficits of $29.1 million and $21.5 million at March 31, 2005 and September 30,
2004, respectively.  The increase in our working capital deficit is a
result of an increase in accrued hedge liabilities associated with our Mid-Continent-Velma
operations and cash used for payments to our Parent.
  31
 *Index*
  Our
long-term debt (including current maturities) was 95% and 94% of our total
equity at March 31,
2005 and September 30, 2004, respectively.  Since September 30, 2004, total
stockholders’ equity has increased by $18.5 million with a corresponding
increase in our total debt of $18.3 million. Stockholders’ equity increased
principally due to net earnings of $17.4 million for the six months ended March
31, 2005. The increase in long-term debt relates to increased borrowings to fund
our drilling operations.
 
 In
September 2004, the borrowing base under our credit facility was increased to
$75.0 million.  In December 2004, the borrowing base under Atlas Pipeline’s
revolving credit facility was increased to $90.0 million from $75.0
million.  At March 31, 2005, we had $23.6 million available on our credit
facility. See note 15 to our Consolidated Financial Statements for information
on Atlas Pipeline’s new credit facility which closed April 14, 2005. After
borrowing on Atlas Pipeline’s new $270 million credit facility on April 14,
2005, it has approximately $249.5 million outstanding at 5.70% and $18.9 million
available under its credit facility.
 
 *Cash
flows from operating activities* . **** Cash
provided by operations is an important source of short-term liquidity for
us.  It is directly affected by changes in the price of natural gas and
oil, interest rates and our ability to raise funds for our drilling investment
partnerships.  Net ** cash
provided by operating activities increased $17.3 million in the six months ended
March 31, 2005 to $39.8 million from $22.5 million in the six months ended March
31, 2004, substantially as a result of the following:
  ·
    Changes
      in operating assets and liabilities increased operating cash flow by $1.3
      million in the six months ended March 31, 2005, compared to the six months
      ended March 31, 2004, primarily due to increases during the six months
      ended March 31, 2005 in accounts payable and accrued liabilities as
      compared to March 31, 2004.  Our level of liabilities is dependent
      upon the remaining amount of our drilling obligations at any balance sheet
      date, which is dependent upon the timing of funds raised through our
      investment partnerships;
  ·
    An
      increase in net income before depreciation and amortization of $11.5
      million in the six months ended March 31, 2005 as compared to the prior
      year period, principally as a result of higher natural gas and oil prices
      and drilling profits;
  ·
    Changes
      in our deferred tax liability decreased cash flow by $3.8 million as
      compared to the six months ended March 31, 2004 which reflects the impact
      of timing differences between accounting and tax
  records;
  ·
    An
      increase in minority interest of $7.1 million due to an increase in Atlas
      Pipeline’s earnings and our decreased ownership percentage in Atlas
      Pipeline; and
  ·
    An
      increase in non-cash items of $1.6 million related losses on derivative
      value and compensation expensed on our long-term incentive
      plans.
 
 *Cash
flows from investing activities.* **** Cash used
in our investing activities increased $23.4 million in the six months ended
March 31, 2005 to $41.6 million from $18.2 million in the six months ended March
31, 2004 as a result of an increase in capital expenditures of $23.3 million
principally due to an increase in the number of wells we drilled and
expenditures related to Atlas Pipeline’s gathering system extensions and
compressor upgrades.
 
 *Cash
flows from financing activities.* Cash used
in our financing activities decreased $7.4 million in the six months ended March 31,
2005 to $10.3 million from cash used of $17.8 million in the six months ended
March 31, 2004, as a result of the following:
 
 ·
    Payments
      to our parent in the form of either repayments of advances or dividends
      decreased by $3.6 million in the six months ended March 31, 2005 to $19.4
      million from $23.0 million in the six months ended March 31, 2004;
  ·
    Net
      borrowings and principal payments increased cash flows by $8.9 million in
      the six months ended March 31, 2005, as compared to the prior year similar
      period;
  32
 *Index*
  ·
    Dividends
      paid to minority interests increased $4.5 million as a result of higher
      earnings and more common units outstanding for Atlas Pipeline as a result
      of its fiscal 2004 offerings of common units; and
  ·
    An
      increase in other assets of $540,000 related to financing costs incurred
      on Atlas Pipeline’s new credit facility.
 
 *Capital
Requirement:* During
the six months ended March 31, 2005 and 2004, our capital expenditures related
primarily to investments in our drilling partnerships and pipeline expansions,
in which we invested $20.2 million and $17.3 million, respectively.  For
the six months ended March 31, 2005 and the remaining quarters of fiscal 2005,
we funded and expect to continue to fund these capital expenditures through cash
on hand, borrowings under our credit facilities, and from operations.  We
have established two credit facilities to facilitate the funding of our capital
expenditures.
 
 The level
of capital expenditures we must devote to our exploration and production
operations depends upon the level of funds raised through our drilling
investment partnerships.  We have budgeted to raise up to $138.0 million in
fiscal 2005 through drilling partnerships.  Through the six months ended
March 31, 2005 we had raised $62.3 million.  We believe cash flows from
operations and amounts available under our credit facility will be adequate to
fund our contributions to these partnerships.  However, the amount of funds
we raise and the level of our capital expenditures will vary in the future
depending on market conditions for natural gas and other factors.
 
 We
continuously evaluate acquisitions of gas and oil and pipeline assets.  In
order to make any acquisition, we believe we will be required to access outside
capital either through debt or equity placements or through joint venture
operations with other energy companies.  There can be no assurance that we
will be successful in our efforts to obtain outside capital.  For a
discussion of limitations on our ability to issue equity or make certain
acquisitions or business combinations, see “General.”
  33
 *Index*
  **Contractual
Obligations and Commercial Commitments**
 
 The
following table summarizes our contractual obligations at March 31, 2005.
 
 Payments
      Due By Period
      (in
      thousands)Contractual
      cash obligations:
    
    Total
    
    Less
      than
      1
      Year
    
    2 -
      3
      Years
    
    4 -
      5
      Years
    
    After
      5
      YearsLong-term
      debt(1)
    
    $
    103,983
    
    $
    2,361
    
    $
    54,655
    
    $
    46,967
    
    $
    -Secured
      revolving credit facilities
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Operating
      lease obligations
    
    
    1,296
    
    
    1,005
    
    
    188
    
    
    101
    
    
    2Capital
      lease obligations
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Unconditional
      purchase obligations
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Other
      long-term obligation
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Total
      contractual cash obligations
    
    $
    105,279
    
    $
    3,366
    
    $
    54,843
    
    $
    47,068
    
    $
    2
 
 (1)
    Not
      included in the table above are estimated interest payments calculated at
      the rates in effect at March 31, 2005: 2006 - $5.6 million; 2007 - $5.4
      million; 2008 - $2.7 million; 2009 - $2.2 million and 2010 -
      $493,400.
 
 Payments
      Due By Period
      (in
      thousands)Other
      commercial commitments:
    
    Total
    
    Less
      than
      1
      Year
    
    2 -
      3
      Years
    
    4 -
      5
      Years
    
    After
      5
      YearsStandby
      letters of credit
    
    $
    3,012
    
    $
    3,012
    
    $
    -
    
    $
    -
    
    $
    -Guarantees
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Standby
      replacement commitments
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Other
      commercial commitments
    
    
    8,321
    
    
    8,321
    
    
    -
    
    
    -
    
    
    -Total
      commercial commitments
    
    $
    11,333
    
    $
    11,333
    
    $
    -
    
    $
    -
    
    $
    -
  34
 *Index*
  **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 and cost and expenses, and related disclosure of
contingent assets and liabilities.  On an on-going basis, we evaluate our
estimates, including those related to the provision for possible losses,
deferred tax assets and liabilities, goodwill and identifiable intangible
assets, and certain accrued liabilities.  We base our estimates on
historical experience and on various other assumptions that we believe
reasonable under the circumstances, the results of which form the basis for
making judgments about the carrying values of assets and liabilities that are
not readily apparent from other sources.  Actual results may differ from
these estimates under different assumptions or conditions.
 
 For a
detailed discussion on the application of policies critical to our business
operations and other accounting policies, see our Annual Report on Form 10-K for
the year ended September 30, 2004 Form 10K, 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
2005, the Financial Accounting Standards Board (“FASB”) issued FASB
Interpretation No. 47, Accounting for Conditional Assets Retirement Obligations
(“FIN 47”), which will result in (a) more consistent recognition of liabilities
relating to asset retirement obligations, (b) more information about expected
future cash outflows associated with those obligations, and (c) more information
about investments in long-lived assets because additional asset retirement cost
will be recognized as part of the carrying amounts of the assets. FIN 47
clarifies that the term conditional asset retirement obligation as used in
Statement FAS No. 143, Accounting for Asset Retirement Obligations, refers to a
legal obligation to perform an asset retirement activity in which the timing and
(or) method of settlement are conditional on a future event that may or may not
be within the control of the entity. The obligation to perform the asset
retirement activity is unconditional even though uncertainty exists about the
timing and (or) method of settlement. Uncertainty about the timing and (or)
method of settlement of a conditional asset retirement obligation should be
factored into the measurement of the liability when sufficient information
exists.
  FIN 47
also clarifies when an entity would have sufficient information to reasonably
estimate the fair value of an asset retirement obligation. FIN 47 is effective
no later than the end of fiscal years ending after
December 15, 2005. Retrospective application of interim financial information is
permitted but is not
required. Early adoption of this interpretation is encouraged. As FIN 47 was
recently issued, we have not
determined whether the interpretation will have a significant adverse effect on
its financial position
or results of operations.
 
 In
December 2004, the FASB issued Statement No. 123 (R) (revised 2004) Share-Based
Payment, which is a revision of Statement of Financial Accounting Standards
(“SFAS”) No. 123, Accounting for
Stock-Based Compensation.  Statement 123 (R) supersedes Accounting
Principal Board Opinion (APB) No. 25,
Accounting for Stock Issued to Employees, and amends Statement of Financial Accounting
Standards (SFAS) No. 95, Statement of Cash Flows.  Generally, the approach
to accounting
in Statement 123 (R) requires all share-based payments to employees, including
grants of employee stock options, to be recognized in the financial statements
based on their fair values.  Currently we
account for these payments under the intrinsic value provisions of APB No. 25
with no expense
recognition in the financial statements.  Statement 123 (R) is effective
for us beginning October
1, 2005.  The Statement offers several alternatives for
implementation.  At this time, we have not made a decision as to the
alternative we may select.
  35
 *Index*
  In April
2005, the FASB issued
FASB Staff Position No. FAS 19-1 (“FSP FAS 19-1”), which addressed a discussion
that was ongoing within the oil and gas industry regarding capitalization of
costs of drilling exploratory wells. Paragraph 19 of FASB Statement No. 19,
Financial Accounting and Reporting by Oil and Gas Producing Companies (“FASB No.
19”), requires costs of drilling exploratory wells to be capitalized pending
determination of whether the well has found proved reserves. If the well has
found proved reserves, the capitalized costs become part of the entity’s wells,
equipment, and facilities; if, however, the well has not found proved reserves,
the capitalized costs of drilling the well are expensed. Questions arose in
practice about the application of this guidance due to changes in oil and gas
exploration processes and lifecycles. The issue was whether there are
circumstances that would permit the continued capitalization of exploratory well
costs if reserves cannot be classified as proved within one year following the
completion of drilling other than when additional exploration wells are
necessary to justify major capital expenditures and those wells are underway or
firmly planned for the near future. FSP FAS 19-1 amends FASB No. 19 to allow for
the continued capitalization of suspended well costs when the well has found a
sufficient quantity of reserves to justify its completion as a producing well
and the enterprise is making sufficient progress assessing the reserves and the
economic and operating viability of the plan. This guidance requires management
to exercise more judgment than was previously required and also requires
additional disclosure. This new guidance is effective for the first reporting
period beginning after April 4, 2005 and is to be applied prospectively to
existing and newly capitalized exploratory well costs. We do not believe this
statement of position will have a significant effect on our financial
statements .
 
 **Item 3.**
    **Quantitative
      and Qualitative Disclosures about Market
Risk**
 
 The
primary objective of the following information is to provide forward-looking
quantitative and qualitative information about our potential exposure to market
risks.  The following discussion is not meant to be a precise indicator of
expected future losses, but rather an indicator of reasonable possible
losses.  This forward-looking information provides indicators of how we
view and manage our ongoing market risk exposures.  All of our market risk
sensitive instruments were entered into for purposes other than
trading.
 
 **General**
 
 We are
exposed to various market risks, principally fluctuating interest rates and
changes in commodity prices.  These risks can impact our results of
operations, cash flows and financial position.  We manage these risks
through regular operating and financing activities and periodically use
derivative financial instruments.
 
 The
following analysis presents the effect on our earnings, cash flows and financial
position as if the hypothetical changes in market risk factors occurred on March
31, 2005.  Only the potential impacts of hypothetical assumptions are
analyzed.  The analysis does not consider other possible effects that could
impact our business.
 
 *Interest
Rate Risk.* At March
31, 2005, the amount outstanding under our credit facility had increased to
$50.0 million from $25.0 million at September 30, 2004.  The weighted
average interest rate for this facility increased from 4.1% at September 30,
2004 to 5.4% at March 31, 2005 due to a larger portion of our borrowings being
at the bank’s prime rate.
 
 At March
31, 2005, Atlas Pipeline had a $90.0 million revolving credit facility ($10
million outstanding) and a $45.0 million term loan ($43.7 million outstanding)
to fund the expansion of its existing gathering systems and the acquisitions of
other gas gathering systems. The weighted average interest rate for these
borrowings decreased from 5.7% at September 30, 2004 to 5.5% at March 31, 2005
due to a larger portion of our borrowings being at the bank’s LIBOR rate.
  36
 *Index*
  Holding
all other variables constant, if interest rates hypothetically increased or
decreased by 10%, our net annual income would change by approximately
$219,000.
 
 *Commodity
Price Risk* . 
Our major market risk exposure in commodities is fluctuations in the pricing of
our gas and oil production.  Realized pricing is primarily driven by the
prevailing worldwide prices for crude oil and spot market prices applicable to
United States natural gas production.  Pricing for gas and oil production
has been volatile and unpredictable for many years.  To limit our exposure
to changing natural gas prices, we use hedges.  Through our hedges, we seek
to provide a measure of stability in the volatile environment of natural gas
prices.  Our risk management objective is to lock in a range of pricing for
expected production volumes.
 
 We also
are exposed to commodity prices as a result of Atlas Pipeline being paid for
certain services in the form of commodities rather than cash. For gathering
services, we receive fees or commodities from the producers to bring the raw
natural gas from the wellhead to the processing plant.
 
 For
processing services, we either receive fees or commodities as payment for these
services, based on the type of contractual agreement. Based on Atlas Pipeline’s
current contract mix, we have long condensate, NGL and natural gas
positions.  Based upon Atlas Pipeline’s portfolio of supply contracts, a
change in the average price of 10% of NGLs, natural gas and crude oil sold and
processed by APLMC would result in a decrease to our annual income of
approximately $30,000.
 
 Atlas
Pipeline through its subsidiary, APLMC, acquired and/or entered into certain
financial swap and option instruments that are classified as cash flow hedges in
accordance with SFAS 133. APLMC entered into these instruments to hedge the
forecasted natural gas, natural gas liquids and condensate sales against the
variability in expected future cash flows attributable to changes in market
prices. The swap instruments are contractual agreements between counterparties
to exchange obligations of money as the underlying natural gas, natural gas
liquids and condensate is sold. Under these swap agreements, APLMC receives a
fixed price and pays a floating price based on certain indices for the relevant
contract period. The options fix the price for APLMC within the puts purchased
and calls sold.
 
 Derivatives
are recorded on our balance sheet as assets or liabilities at fair value. For
derivatives qualifying as hedges, the effective portion of changes in fair value
are recognized in stockholders’ equity as Other Comprehensive Income and
reclassified to earnings as such transactions are settled. For non-qualifying
derivatives and for the ineffective portion of qualifying derivatives, changes
in fair value are recognized in earnings as they occur. At March 31, 2005,
Atlas Pipeline reflected an unrealized net pre-tax commodity hedging loss of
$10.8 million on its Balance Sheet.  Of the $1.5 million unrealized
loss in Accumulated Other Comprehensive Income at March 31, 2005,
$1.1 million of losses will be reclassified to earnings over the next
twelve month period and $400,000 in later periods, if future prices remained
constant. Actual amounts that will be reclassified will vary as a result of
future changes in prices.   APLMC recognized losses of $669,000 and
$645,000 related to these hedging instruments in the three months and six months
ended March 31, 2005, respectively.  Ineffective gains or losses are
recorded in income while the hedge contract is open and may increase or decrease
until settlement of the contract. A hedging loss of $224,000 and a hedging gain
of $216,000 resulting from ineffective hedges is included in income for the
three months and six months ended March 31, 2005, respectively.
 
 A portion
of our future natural gas sales is periodically hedged through the use of swap
and collar contracts.  Realized gains and losses on these instruments are
reflected in the contract month being hedged as an adjustment to gas revenue.
  37
 *Index*
  As of
March 31, 2005, Atlas Pipeline had the following natural gas liquids, natural
gas, and crude oil volumes hedged.
 
 **Natural
Gas Basis Swaps - Price Swaps**
 Production
    
    
    
    Average
    
    Fair
      ValueVolumes
    
    Fixed
      Price
    
    Asset(3)(MMBTU)(1)
    
    (perMMBTU)
    
    (in
      thousands)2006
    
    
    990,000
    
    $
    (0.500
    )
    $
    156$
    156
 
 **Natural
Gas Liquids Fixed - Price Swaps**
 Production
    
    
    
    Average
    
    Fair
      ValueVolumes
    
    Fixed
      Price
    
    Liability(2)(gallons)
    
    (per
      gallon)
    
    (in
      thousands)2006
    
    
    15,966,000
    
    $
    0.585
    
    $
    (5,453
    )2007
    
    
    4,536,000
    
    
    0.574
    
    
    (1,581
    )$
    (7,034
    )
 
 **Natural
Gas Fixed - Price Swaps**
 Production
    
    
    
    Average
    
    Fair
      ValueVolumes
    
    Fixed
      Price
    
    Liability(3)(MMBTU)(1)
    
    (per
      MMBTU)
    
    (in
      thousands)2006
    
    
    1,110,000
    
    $
    6.203
    
    $
    (2,077
    )2007
    
    
    300,000
    
    
    5.905
    
    
    (426
    )$
    (2,503
    )
 
 **Crude
Oil Fixed - Price Swaps**
 Production
    
    
    
    Average
    
    Fair
      ValueVolumes
    
    Fixed
      Price
    
    Liability(3)(barrels)
    
    (per
      barrel)
    
    (in
      thousands)2006
    
    
    9,000
    
    $
    40.958
    
    $
    (136
    )2007
    
    
    21,000
    
    
    40.818
    
    
    (295
    )$
    (431
    )
 
 **Crude
Oil Options**
 Production
    
    
    
    
    
    Average
    
    Fair
      ValueOption
      Type
    
    Volumes
    
    Strike
      Price
    
    Liability(3)(barrels)
    
    (per
      barrel)
    
    (in
      thousands)2006
    
    
    Puts
      Purchased
    
    
    45,000
    
    $
    30.00
    
    
    -2006
    
    
    Calls
      sold
    
    
    45,000
    
    
    34.25
    
    $
    (1,007
    )$
    (1,007
    )Total liability
    
    $
    (10,819
    )
 
 (1)
    MMBTU
      means Million British Thermal Units.
 (2)
    Fair
      value based on APLMC internal model which forecasts forward natural gas
      liquid 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.
  38
 *Index*
  FirstEnergy
Solutions and other third party marketers to which we sell gas also use
financial hedges to hedge their pricing exposure and make price hedging
opportunities available to us.  These transactions are similar to
NYMEX-based futures contracts, swaps and options, but also require firm delivery
of the hedged quantity.  Thus, we limit these arrangements to much smaller
quantities than those projected to be available at any delivery point.  For
the fiscal year ending September 30, 2006, we estimate approximately 71% of our
produced natural gas volumes will be sold in this manner, leaving our remaining
production to be sold at contract prices in the month produced or at spot market
prices.  We also negotiate with certain purchasers for delivery of a
portion of natural gas we will produce for the upcoming twelve months.  The
prices under most of our gas sales contracts are negotiated on an annual basis
and are index-based.  Considering those volumes already designated for the
fiscal year ending September 30, 2006, and current indices, a theoretical 10%
upward or downward change in the price of natural gas would result in
approximately a 3.0% change in our projected natural gas revenues, for the
volumes we can hedge in this manner.
 
 **Item 4.**
    **Controls
      and Procedures**
 
 We
maintain disclosure controls and procedures that are designed to ensure that
information required to be disclosed in our periodic reports required under the
Securities Exchange Act of 1934 is recorded, processed, summarized and reported
within the time periods specified in the SEC’s rules and forms, and that such
information is accumulated and communicated to our management, including our
Chief Executive Officer and our Chief Financial Officer, as appropriate, to
allow timely decisions regarding required disclosure.  In designing and
evaluating the disclosure controls and procedures, our management recognized
that any controls and procedures, no matter how well designed and operated, can
provide only reasonable assurance of achieving the desired control objectives,
and our management necessarily was required to apply its judgment in evaluating
the cost-benefit relationship of possible controls and procedures.
 
 Under the
supervision of our Chief Executive Officer and Chief Financial Officer and with
the participation of the disclosure committee of our parent, we have carried out
an evaluation of the effectiveness of our disclosure controls and procedures as
of the end of the period covered by this report.  Based upon that
evaluation, our Chief Executive Officer and Chief Financial Officer concluded
that our disclosure controls and procedures are effective.
 
 There
have been no significant changes in our internal controls over financial
reporting that has partially affected, or is reasonably likely to materially
affect, our internal control over financial reporting during our most recent
fiscal quarter.
  39
 *Index*
  **PART II. OTHER INFORMATION**
 
 **Item 6.**
    **Exhibits**
 
 Exhibit
      No.
    
    Description31.1
    
    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.
  40
 *Index*
  **SIGNATURES**
 
 Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
 
 **ATLAS
      AMERICA, INC.****(Registrant)**Date: 
      May 12, 2005
    By:
    */s/
      Matthew A. Jones*Matthew
      A. JonesExecutive
      Vice President and Chief Financial OfficerDate: 
      May 12, 2005
    By:
    */s/
      Nancy J. McGurk*Nancy
      J. McGurkSenior
      Vice President and Chief Accounting Officer
 41