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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 of incorporation or organization)
(I.R.S. Employer Identification No.)
   
311 Rouser Road
  
Moon Township, PA
15108
(Address of principal executive offices)
(Zip code)

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

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
 Yes o    No x

The number of outstanding shares of the registrant’s common stock on May 2, 2005 was 13,333,333 shares.
 

ATLAS AMERICA, INC.
INDEX TO QUARTERLY REPORT ON FORM 10-Q

   
Page
     
PART I
  
     
Item 1.
  
     
 
3
     
 
4
     
 
5
     
 
6
     
 
7 - 25
     
Item 2.
26 - 36
     
Item 3.
36 - 39
     
Item 4.
39
     
PART II
  
     
Item 6.
40
     
41

2

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
  
$
29,192
  
Accounts receivable
    
29,545
    
24,113
  
Prepaid expenses
    
4,883
    
2,433
  
Total current assets
    
51,489
    
55,738
  
               
Property and equipment, net
    
345,515
    
313,091
  
Intangible assets, net
    
6,777
    
7,243
  
Other assets, net
    
9,521
    
7,955
  
Advances 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
  
$
3,401
  
Accounts payable
    
20,611
    
20,869
  
Liabilities associated with drilling contracts
    
23,060
    
29,375
  
Accrued producer liabilities
    
12,455
    
8,815
  
Accrued hedge liability
    
8,673
    
3,972
  
Accrued liabilities
    
13,397
    
10,795
  
Total current liabilities
    
80,557
    
77,227
  
               
Long-term debt
    
101,622
    
82,239
  
Advances from parent
    
-
    
10,413
  
Deferred tax liability
    
23,409
    
21,442
  
Other liabilities
    
9,867
    
6,949
  
               
Minority interest
   
126,488
    
132,224
  
               
Commitments and contingencies
    
-
    
-
  
               
Stockholders’ equity:
              
Preferred stock, $0.01 par value: 1,000,000 authorized shares
   
-
    
-
  
Common stock, $0.01 par value: 49,000,000 authorized shares
   
133
    
133
  
Additional paid-in capital
    
75,584
    
75,584
  
Accumulated other comprehensive loss
   
(1,473
)
  
(2,553
)
Retained earnings
   
35,247
    
17,839
  
Total stockholders’ equity
    
109,491
    
91,003
  
   
$
451,434
  
$
421,497
  


See accompanying notes to consolidated financial statements

3

ATLAS AMERICA, INC.
CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except per share data)
(Unaudited)
 
   
Three Months Ended
  
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
  
$
48,207
  
Gas and oil production
    
13,959
    
11,799
    
28,618
    
21,995
  
Gathering, transmission and processing
    
43,741
    
1,579
    
87,523
    
3,178
  
Well services
    
2,350
    
2,123
    
4,598
    
4,060
  
     
101,501
    
41,749
    
192,748
    
77,440
  
                           
COSTS AND EXPENSES
                          
Well drilling
    
36,044
    
22,824
    
62,617
    
41,919
  
Gas and oil production and exploration
    
2,413
    
3,323
    
4,215
    
5,008
  
Gathering, transmission and processing
    
37,462
    
620
    
73,142
    
1,216
  
Well services
    
1,316
    
1,021
    
2,507
    
2,062
  
General and administrative
    
1,494
    
785
    
3,154
    
1,094
  
Compensation reimbursement - affiliate
    
244
    
463
    
457
    
1,065
  
Depreciation, depletion and amortization
    
4,781
    
3,534
    
10,653
    
6,779
  
     
83,754
    
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
    
15,241
  
Provision 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
  
$
.94
  
Weighted 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
  
$
.94
  
Weighted average common shares outstanding
    
13,338
    
10,688
    
13,338
    
10,688
  
 

See accompanying notes to consolidated financial statements

4

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
  
$
91,003
  
Other comprehensive income
    
-
    
-
    
-
    
1,080
    
-
    
1,080
  
Net income
    
-
   
-
    
-
    
-
    
17,408
    
17,408
  
Balance, March 31, 2005
    
13,333,333
  
$
133
  
$
75,584
  
$
(1,473
 )
$
35,247
  
$
109,491
  
                                       


 
See accompanying notes to consolidated financial statements 

5

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
  
$
10,059
  
Adjustments to reconcile net income to net cash provided by operating activities:
              
Depreciation, depletion and amortization
   
10,653
    
6,779
  
Amortization of deferred financing costs
   
621
    
320
  
Non-cash loss on derivative value
   
720
        
Non-cash compensation on long-term incentive plans
   
922
        
Minority interest in Atlas Pipeline Partners, L.P.
   
9,720
    
2,595
  
Gain on asset dispositions
   
(36
)
  
(49
)
Property impairments and abandonments
   
-
    
599
  
Deferred income taxes
   
1,420
    
5,182
  
Changes 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
    
159
  
Increase in other assets
   
(789
)
  
(826
)
Net cash used in investing activities
   
(41,590
)
  
(18,213
)
               
CASH FLOWS FROM FINANCING ACTIVITIES:
              
Borrowings
   
86,252
    
48,000
  
Principal 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
   
25,372
  
Cash and cash equivalents at end of period
 
$
17,061
  
$
11,908
  


See accompanying notes to consolidated financial statements

6

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

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

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

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
  
$
10,059
  
Stock-based employee compensation expense reported in net income, net of tax
    
-
    
-
    
-
    
-
  
                           
Less total stock-based employee compensation expense determined under the fair value-based method for all awards, net of income taxes
    
(78
)
  
(82
)
  
(214
)
  
(162
)
Pro forma net income
  
$
8,438
  
$
5,084
  
$
17,194
  
$
9,897
  
                           
Net income per common share:
                          
Basic - as reported
  
$
.64
  
$
.48
  
$
1.31
  
$
.94
  
Basic - pro forma
  
$
.63
  
$
.48
  
$
1.29
  
$
.93
  
Diluted - as reported
  
$
.64
  
$
.48
  
$
1.31
  
$
.94
  
Diluted - pro forma
  
$
.63
  
$
.48
  
$
1.29
  
$
.93
  
 
10

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
  
$
579
  
Income taxes
  
$
17
  
$
-
  

NOTE 3 - COMPREHENSIVE INCOME

Comprehensive income includes net income and other gains and losses affecting stockholders’ equity from non-owner sources that under generally accepted accounting principles, have not been recognized in the calculation of net income. For the Company, 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
  
$
10,059
  
Other 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

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
  
$
10,059
  
Weighted average common shares outstanding-basic
   
13,333
    
10,688
    
13,333
    
10,688
  
Dilutive 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

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 Value
  
   
Volumes
  
Fixed Price
  
Asset (3)
  
   
(MMBTU) (1)
  
(per MMBTU)
  
(in thousands)
  
2006
    
990,000
  
$
(0.500
)
$
156
  
               
$
156
  

Natural Gas Liquids Fixed - Price Swaps
Production
      
Average
  
Fair Value
  
   
Volumes
  
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
 
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 Value
  
   
Volumes
  
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 Value
  
   
Volumes
  
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 Value
 
 
 
Option 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

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 years
Rights-of-way - Appalachia
20 years
Rights-of-way - Mid-Continent-Velma
40 years
Land, buildings and improvements
10-40 years
Furniture and equipment
3-7 years
Other
3-10 years

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

   
March 31,
  
September 30,
  
   
2005
  
2004
  
Mineral interests:
          
Proved properties
 
$
2,936
  
$
2,544
  
Unproved properties
    
1,002
    
1,002
  
Wells and related equipment
   
213,781
    
184,046
  
Pipelines, processing and compression facilities
    
174,251
    
163,302
  
Rights-of-way
   
15,107
    
14,702
  
Land, buildings and improvements
   
7,632
    
7,213
  
Support equipment
   
3,193
    
2,902
  
Other
   
4,512
   
4,227
  
     
422,414
    
379,938
  
Accumulated 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
 
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
  
$
3,131
  
Liabilities incurred
   
1,008
    
71
    
1,658
    
101
  
Liabilities settled
   
(28
)
  
(15
)
  
(32
)
  
(43
)
Accretion expense
   
109
    
52
    
193
   
99
  
Revisions of previous estimates
    
-
    
83
    
-
    
83
  
Asset 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

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
  
$
4,704
  
Investments
   
2,134
   
2,166
  
Security deposits
    
1,376
    
1,085
  
Acquisition 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
  
$
14,343
  
Accumulated amortization
   
(7,566
)
  
(7,100
)
Intangible assets, net
 
$
6,777
  
$
7,243
  
 
17

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
  
$
25,000
  
Term loan
   
43,690
    
60,000
  
Other debt
   
293
    
640
  
     
103,983
    
85,640
  
               
Less 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
  
$
2,361
  
2007
    
52,355
  
2008
    
2,300
  
2009
    
12,241
  
2010
    
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
  
$
803
  
Accounts receivable
    
18,505
  
Prepaid expenses
    
649
  
Property, plant and equipment
    
140,780
  
Other long-term assets
    
1,054
  
Total assets acquired
    
161,791
  
Accounts 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
 
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
Forma
  
Revenues
 
$
41,749
  
$
27,202
  
$
68,951
  
Net income
 
$
5,166
  
$
(287
)
$
4,879
  
Net income per common share − basic
 
$
.48
  
$
(.02
)
$
.46
  
Weighted average common shares − outstanding
   
10,688
    
-
    
10,688
  
Net income per common share − diluted
 
$
.48
  
$
(.02
)
$
.46
  
Weighted average common shares
   
10,688
   
-
    
10,688
  

       
Six Months Ended
March  31, 2004 
      
   
As Reported
  
Pro Forma
Adjustment
  
Pro
Forma
  
Revenues 
 
$
77,440
  
$
49,736
  
$
127,176
  
Net income
 
$
10,059
  
$
(752
)
$
9,307
  
Net income per common share − basic
 
$
.94
  
$
(.07
)
$
.87
  
Weighted average common shares − outstanding
   
10,688
    
-
    
10,688
  
Net income per common share − diluted
 
$
.94
  
$
(.07
)
$
.87
  
Weighted 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

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 assets
  
Well drilling
  
$
41,451
  
$
-
  
$
-
  
$
-
  
$
4,892
  
$
9,263
  
Production and exploration
    
13,959
    
-
    
-
    
3,114
    
8,393
    
194,287
  
Natural gas and liquids
    
42,334
    
11
    
5
    
988
    
2,852
    
163,160
  
Transportation and compression
    
1,407
    
65
    
-
    
573
    
(165
)
  
37,710
  
Other(a)
    
2,350
    
6
    
1,618
    
106
    
(2,665
)
  
47,014
  
Total
  
$
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 assets
  
Well drilling
  
$
26,248
  
$
-
  
$
-
  
$
-
  
$
3,007
  
$
7,725
  
Production and exploration
    
11,799
    
-
    
-
    
2,513
    
5,847
    
150,683
  
Natural gas and liquids
    
-
    
-
    
-
    
-
    
-
    
-
  
Transportation and compression
    
1,579
    
17
    
-
    
518
    
200
    
32,605
  
Other(a)
    
2,123
    
3
    
473
    
503
   
(1,341
)
  
36,518
  
Total
  
$
41,749
  
$
20
  
$
473
  
$
3,534
  
$
7,713
  
$
227,531
  
 
20

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 assets
  
Well drilling
  
$
72,009
  
$
-
  
$
-
  
$
-
  
$
8,570
  
$
9,263
  
Production and exploration
    
28,618
    
-
    
-
    
5,918
    
18,506
    
194,287
  
Natural gas and liquids
    
84,395
    
31
    
13
    
3,150
    
6,500
    
163,160
  
Transportation and compression
    
3,128
    
108
    
-
    
1,118
    
(95
)
  
37,710
  
Other(a)
    
4,598
    
56
    
3,300
    
467
    
(6,280
)
  
47,014
  
Total
  
$
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 assets
  
Well drilling
  
$
48,207
  
$
-
  
$
-
  
$
-
  
$
5,505
  
$
7,725
  
Production and exploration
    
21,995
    
-
    
-
    
4,722
    
12,031
    
150,683
  
Natural gas and liquids
    
-
    
-
    
-
    
-
   
-
    
-
  
Transportation and compression
    
3,178
    
37
    
-
    
1,023
    
(90
)
  
32,605
  
Other(a)
    
4,060
    
22
    
960
   
1,033
   
(2,205
)
  
36,518
 
Total
  
$
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

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

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
    
1,692
  
Vested
    
(210
)
  
-
    
(210
)
  
-
  
Forfeited
    
(679
)
  
-
    
(679
)
  
-
  
Balance, end of period
    
125,201
    
1,692
    
125,201
    
1,692
  
                           
Fair value, end of period
  
$
5,620
  
$
68
  
$
5,620
  
$
68
  
                           
Vesting 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

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. The 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
  
$
3,837
  
Other current assets
    
1,237
  
Property, plant and equipment
    
193,121
  
Total assets acquired
    
198,195
  
Accounts payable and accrued liabilities
    
(3,770
)
Total liabilities assumed
    
(3,770
)
Net assets acquired
  
$
194,425
  


24

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

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

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
  
$
180
  
Average drilling cost per well
   
174
    
145
    
183
    
156
  
Average drilling gross profit per well
 
$
26
  
$
22
  
$
27
  
$
23
  
Gross profit margin
 
$
5,407
  
$
3,424
  
$
9,392
  
$
6,288
  
Gross 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

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
  
$
19,182
  
Oil
  
$
1,647
  
$
1,666
  
$
3,589
  
$
2,789
  
                           
Production volume:
                          
Gas (mcf/day) (1) (3)
   
19,315
    
18,265
    
19,806
    
18,875
  
Oil (bbls/day)
    
406
    
576
    
427
    
514
  
Total (mcfe/day) (3) 
    
21,751
    
21,721
    
22,368
    
21,959
  
                           
Average sales prices:
                          
Gas (per mcf) (3) 
  
$
7.07
  
$
6.09
  
$
6.93
  
$
5.55
  
Oil (per bbl) (3)
 
$
45.06
  
$
31.81
  
$
46.18
  
$
29.65
  
                           
Production costs (2):
                          
As a percent of production revenues
    
16%
 
  
15%
 
  
14%
 
  
16%
 
Per mcfe (3)
 
$
1.11
  
$
.91
  
$
.96
  
$
.85
  
                           
Depletion 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

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

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

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
  
$
22,513
  
Used 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

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

 
·
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

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
Years
  
Long-term debt(1) 
  
$
103,983
  
$
2,361
  
$
54,655
  
$
46,967
  
$
-
  
Secured revolving credit facilities
   
-
    
-
    
-
    
-
    
-
  
Operating lease obligations
   
1,296
    
1,005
    
188
    
101
    
2
  
Capital 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
Years
  
Standby 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

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
 
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.

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

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

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 Value
  
   
Volumes
  
Fixed Price
  
Asset (3)
  
   
(MMBTU) (1)
  
(per MMBTU)
  
(in thousands)
  
2006
    
990,000
  
$
(0.500
)
$
156
  
               
$
156
  

Natural Gas Liquids Fixed - Price Swaps
Production
      
Average
  
Fair Value
  
   
Volumes
  
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 Value
  
   
Volumes
  
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 Value
  
   
Volumes
  
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 Value
  
   
Option 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

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.

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

PART II.  OTHER INFORMATION

Exhibits

Exhibit No.
  
Description
     
 
Rule 13(a)-14(a)/15d-14(a) Certification.
 
Rule 13(a)-14(a)/15d-14(a) Certification.
 
Section 1350 Certification.
 
Section 1350 Certification.
 
40

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. Jones
   
Executive Vice President and Chief Financial Officer
     
     
     
Date:  May 12, 2005
By:
/s/ Nancy J. McGurk
   
Nancy J. McGurk
   
Senior Vice President and Chief Accounting Officer
     
 
41