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EX-31.2 - EXHIBIT 31.2 - ATLAS ENERGY, INC.c92258exv31w2.htm
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EX-31.1 - EXHIBIT 31.1 - ATLAS ENERGY, INC.c92258exv31w1.htm
EX-32.1 - EXHIBIT 32.1 - ATLAS ENERGY, INC.c92258exv32w1.htm
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2009
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission file number: 001-32169
ATLAS ENERGY, INC.
(Exact name of registrant as specified in its charter)
     
DELAWARE
(State or other jurisdiction of incorporation or
organization)
  51-0404430
(I.R.S. Employer Identification No.)
     
1550 Coraopolis Heights Road
Moon Township, Pennsylvania

(Address of principal executive office)
  15108
(Zip code)
Registrant’s telephone number, including area code:(412) 262-2830
ATLAS AMERICA, INC.
(Former name, Former address and former fiscal year, if changed since last report)
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 þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in rule 12b-2 of the Exchange Act.
             
Large accelerated filer þ   Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
        (Do not check if smaller reporting company)
   
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The number of outstanding shares of the registrant’s common stock on November 6, 2009 was 78,131,951 shares.
 
 

 

 


 

ATLAS ENERGY, INC. AND SUBSIDIARIES
INDEX TO QUARTERLY REPORT
ON FORM 10-Q
         
    PAGE  
       
 
       
       
 
       
    3  
 
       
    4  
 
       
    6  
 
       
    7  
 
       
    9  
 
       
    63  
 
       
    90  
 
       
    100  
 
       
       
 
       
    101  
 
       
    102  
 
       
    102  
 
       
    103  
 
       
    107  
 
       
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32.1
 Exhibit 32.2

 

 


Table of Contents

PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ATLAS ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)
(Unaudited)
                 
    September 30,     December 31,  
    2009     2008  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 35,693     $ 104,496  
Accounts receivable
    145,548       169,405  
Current portion of derivative receivable from Partnerships
    346       3,022  
Current portion of derivative asset
    88,960       152,726  
Prepaid expenses and other
    27,900       25,464  
Prepaid and deferred income taxes
    881       32,215  
Current assets of discontinued operations
          13,441  
 
           
Total current assets
    299,328       500,769  
 
               
Property, plant and equipment, net
    3,708,389       3,744,815  
Intangible assets, net
    177,539       197,485  
Goodwill, net
    35,166       35,166  
Long-term derivative receivable from Partnerships
    4,740       2,719  
Long term derivative asset
    42,405       69,451  
Investment in joint venture
    133,740        
Other assets, net
    70,419       53,311  
Long-term assets of discontinued operations
          242,165  
 
           
 
  $ 4,471,726     $ 4,845,881  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
 
               
Current liabilities:
               
Current portion of long-term debt
  $ 12,000     $  
Accounts payable
    105,929       140,725  
Liabilities associated with drilling contracts
    16,590       96,883  
Accrued producer liabilities
    45,539       66,846  
Current portion of derivative payable to Partnerships
    23,173       34,933  
Current portion of derivative liability
    46,570       73,776  
Accrued liabilities
    165,391       103,383  
Advances from affiliate
    219       108  
Current liabilities of discontinued operations
          10,572  
 
           
Total current liabilities
    415,411       527,226  
 
               
Long-term debt, less current portion
    2,115,505       2,413,082  
Deferred tax liability
    51,158       242,058  
Long-term derivative payable to Partnerships
    17,021       22,581  
Long-term derivative liability
    33,847       59,103  
Other long-term liabilities
    54,941       52,263  
Commitments and contingencies
               
 
               
Stockholders’ equity:
               
Preferred stock, $0.01 par value: 1,000,000 authorized shares
           
Common stock, $0.01 par value: 114,000,000 authorized shares
    814       426  
Additional paid-in capital
    1,137,546       412,869  
Treasury stock, at cost
    (143,362 )     (147,621 )
Accumulated other comprehensive income
    50,351       21,143  
Retained earnings
    136,027       124,698  
 
           
 
    1,181,376       411,515  
Non-controlling interests
    602,467       1,118,053  
 
           
Total stockholders’ equity
    1,783,843       1,529,568  
 
           
 
  $ 4,471,726     $ 4,845,881  
 
           
See accompanying notes to consolidated financial statements

 

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ATLAS ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
(Unaudited)
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Revenues:
                               
Well construction and completion
  $ 81,496     $ 116,987     $ 257,231     $ 343,466  
Gas and oil production
    65,986       81,235       207,908       236,417  
Transmission, gathering and processing
    205,603       410,942       555,373       1,218,359  
Administration and oversight
    3,149       5,216       9,644       15,370  
Well services
    5,012       5,299       14,911       15,363  
Gain on asset sales
    55             105,746        
Gain (loss) on mark-to-market derivatives
    1,032       147,505       (17,245 )     (257,344 )
Other, net
    4,851       3,818       11,696       11,842  
 
                       
Total revenues
    367,184       771,002       1,145,264       1,583,473  
 
                       
 
                               
Costs and expenses:
                               
Well construction and completion
    69,138       101,727       218,236       298,666  
Gas and oil production
    12,128       12,688       33,217       35,735  
Transmission, gathering and processing
    167,862       333,988       470,752       992,504  
Well services
    2,378       2,753       6,922       7,815  
General and administrative
    31,786       12,392       80,777       57,903  
Net expense reimbursement — affiliate
    280       255       842       689  
Depreciation, depletion and amortization
    46,460       44,325       147,427       129,539  
 
                       
Total costs and expenses
    330,032       508,128       958,173       1,522,851  
 
                       
 
                               
Operating income
    37,152       262,874       187,091       60,622  
 
                               
Interest Expense
    (47,754 )     (37,331 )     (124,322 )     (106,538 )
 
                       
 
                               
Income (loss) from continuing operations before income taxes (benefit)
    (10,602 )     225,543       62,769       (45,916 )
Provision (benefit) for income taxes
    (716 )     13,647       5,555       12,288  
 
                       
Net income (loss) from continuing operations
    (9,886 )     211,896       57,214       (58,204 )
 
                               
Discontinued operations:
                               
Gain on sale of discontinued operations (net of income taxes of $2,228 for the nine months ended September 30, 2009)
                48,851        
Income from discontinued operations (net of income taxes of $277 for the three months ended September 30, 2008 and $498 and $848 for the nine months ended September 30, 2009 and 2008, respectively)
          6,261       10,918       20,181  
 
                       
Net income (loss)
    (9,886 )     218,157       116,983       (38,023 )
(Income) loss attributable to non-controlling interests
    9,172       (194,054 )     (103,686 )     60,777  
 
                       
Net income (loss) attributable to common shareholders
  $ (714 )   $ 24,103     $ 13,297     $ 22,754  
 
                       

 

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    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Net income (loss) attributable to common shareholders per share — basic:
                               
Income (loss) from continuing operations attributable to common shareholders
  $ (0.02 )   $ 0.59     $ 0.23     $ 0.54  
Discontinued operations attributable to common shareholders
    0.00       0.01       0.11       0.03  
 
                       
Net income (loss) attributable to common shareholders
  $ (0.02 )   $ 0.60     $ 0.34     $ 0.57  
 
                       
 
                               
Net income (loss) attributable to common shareholders per share — diluted:
                               
Income (loss) from continuing operations attributable to common shareholders
  $ (0.02 )   $ 0.57     $ 0.22     $ 0.51  
Discontinued operations attributable to common shareholders
    0.00       0.01       0.11       0.03  
 
                       
Net income (loss) attributable to common shareholders
  $ (0.02 )   $ 0.58     $ 0.33     $ 0.54  
 
                       
 
                               
Weighted average common shares outstanding:
                               
Basic
    39,780       40,093       39,460       40,251  
 
                       
Diluted
    39,780       41,994       40,051       42,121  
 
                       
 
                               
Income (loss) attributable to common shareholders:
                               
Income (loss) from continuing operations (net of income taxes (benefit) of $(716) and $13,647 for the three months ended September 30, 2009 and 2008, respectively, and $5,555 and $12,288 for the nine months ended September 30, 2009 and 2008, respectively)
  $ (714 )   $ 23,670     $ 9,044     $ 21,431  
Discontinued operations (net of income taxes of $277 for the three months ended September 30, 2008, and $2,726 and $848 for the nine months ended September 30, 2009 and 2008, respectively)
          433       4,253       1,323  
 
                       
Net income (loss) attributable to common shareholders
  $ (714 )   $ 24,103     $ 13,297     $ 22,754  
 
                       
See accompanying notes to consolidated financial statements

 

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ATLAS ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2009
(in thousands, except share data)
(Unaudited)
                                                                         
                                            Accumulated                      
                    Additional                     Other             Non-     Total  
    Common Stock     Paid-In     Treasury Stock     Comprehensive     Retained     controlling     Stockholders’  
    Shares     Amount     Capital     Shares     Amount     Income     Earnings     Interests     Equity  
Balance at January 1, 2009
    42,503,119     $ 426     $ 412,869       (3,252,861 )   $ (147,621 )   $ 21,143     $ 124,698     $ 1,118,053     $ 1,529,568  
Common stock issuance
    24,425             (2,684 )     98,829       4,259                         1,575  
Other comprehensive income
                                  29,208             (14,230 )     14,978  
Stock option and unit compensation expense
    (40,600 )           2,550                                     2,550  
Merger with Atlas Energy Resources LLC
    38,776,768       388       724,811                               (556,384 )     168,815  
Dividends paid
                                        (1,968 )           (1,968 )
Distributions to non-controlling interests
                                              (43,799 )     (43,799 )
Non-controlling interests’ capital contributions
                                              (4,859 )     (4,859 )
Net income
                                        13,297       103,686       116,983  
 
                                                     
Balance at September 30, 2009
    81,263,712     $ 814     $ 1,137,546       (3,154,032 )   $ (143,362 )   $ 50,351     $ 136,027     $ 602,467     $ 1,783,843  
 
                                                     
See accompanying notes to consolidated financial statements

 

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ATLAS ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)
                 
    Nine Months Ended  
    September 30,  
    2009     2008  
CASH FLOWS FROM OPERATING ACTIVITIES:
               
Net income (loss)
  $ 116,983     $ (38,023 )
Income from discontinued operations
    59,769       20,181  
 
           
Income (loss) from continuing operations
    57,214       (58,204 )
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
               
Depreciation, depletion and amortization
    147,427       129,539  
Amortization of deferred finance costs
    9,439       5,925  
Non-cash loss (gain) on derivative value, net
    55,229       (45,872 )
Non-cash compensation expense (benefit)
    6,662       (4,132 )
Gain on asset sales and dispositions
    (105,442 )     (32 )
Distributions paid to non-controlling interests
    (43,799 )     (177,934 )
Equity loss in unconsolidated companies
    2,903       688  
Equity income in joint venture
    (2,140 )      
Distributions received from joint venture
    1,657        
Deferred income taxes
    1,185       15,621  
Changes in operating assets and liabilities, net of effects of acquisitions:
               
Accounts receivable and prepaid expenses and other
    22,816       (3,817 )
Accounts payable and accrued liabilities
    (43,322 )     (40,621 )
Accounts payable and accounts receivable — affiliate
    111       47  
Other operating assets/liabilities
    (161 )     29  
 
           
Net cash provided by (used in) continuing operations operating activities
    109,779       (178,763 )
Net cash provided by discontinued operations operating activities
    14,209       36,626  
 
           
Net cash provided by (used in) operating activities
    123,988       (142,137 )
 
           
 
               
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Capital expenditures
    (268,395 )     (448,738 )
Acquisition purchase price adjustment
          31,429  
Investment in Lightfoot Capital Partners, L.P.
    (26 )     (437 )
Proceeds from asset sales
    120,644       63  
Other
    (9,003 )     851  
 
           
Net cash used in continuing operations investing activities
    (156,780 )     (416,832 )
Net cash provided by (used in) discontinued operations investing activities
    290,594       (22,626 )
 
           
Net cash provided by (used in) investing activities
    133,814       (439,458 )
 
           
 
               
CASH FLOWS FROM FINANCING ACTIVITIES:
               
Borrowings under Atlas Energy Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P. credit facilities
    744,000       908,000  
Repayments under Atlas Energy Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P. credit facilities
    (1,235,675 )     (1,110,025 )
Issuance of Atlas Energy Resources, LLC long-term debt
    196,232       407,125  
Issuance of Atlas Pipeline Partners, L.P. long-term debt
          244,854  
Repayments on Atlas Pipeline Partners, L.P. long-term debt
          (122,847 )
Costs related to Atlas Energy, Inc. and Atlas Energy Resources, LLC Merger
    (10,571 )      
Net proceeds from Atlas Energy Resources equity offering
          82,514  
Net proceeds from Atlas Pipeline Partners, L.P. equity offering
    16,142       206,901  

 

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    Nine Months Ended  
    September 30,  
    2009     2008  
Dividends paid
    (1,968 )     (4,701 )
APL Class A preferred unit redemption
    (15,000 )      
Purchase of treasury stock
    (2,643 )     (34,861 )
Deferred financing costs and other
    (17,122 )     (16,030 )
 
           
Net cash provided by (used in) financing activities
    (326,605 )     560,930  
 
           
 
               
Net change in cash and cash equivalents
    (68,803 )     (20,665 )
Cash and cash equivalents, beginning of period
    104,496       145,896  
 
           
Cash and cash equivalents, end of period
  $ 35,693     $ 125,231  
 
           
See accompanying notes to consolidated financial statements

 

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ATLAS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2009
(Unaudited)
NOTE 1 — BASIS OF PRESENTATION
Atlas Energy, Inc. (the “Company”) is a publicly traded Delaware corporation (NASDAQ:ATLS) which is an independent developer and producer of natural gas and oil, with operations in the Appalachian Basin, the Michigan Basin, and the Illinois Basin. On September 29, 2009, the Company completed its merger with Atlas Energy Resources, LLC (“ATN”), the Company’s formerly publicly traded subsidiary and a Delaware limited liability company (NYSE: ATN), pursuant to the definitive merger agreement previously executed between the Company and ATN, with ATN surviving as the Company’s wholly-owned subsidiary (the “Merger”) (see Note 3). Additionally, Atlas America, Inc. changed its name to Atlas Energy, Inc. upon completion of the Merger.
In addition to its natural gas development and production operations, the Company also maintains ownership interests in the following entities:
   
Atlas Pipeline Partners, L.P. (“Atlas Pipeline Partners” or “APL”), a publicly traded Delaware limited partnership (NYSE: APL) and midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachia regions. At September 30, 2009, the Company had a 2.2% direct ownership interest in APL;
   
Atlas Pipeline Holdings, L.P. (“Atlas Pipeline Holdings” or “AHD”), a publicly traded Delaware limited partnership (NYSE: AHD) and owner of the general partner of APL. Through the Company’s ownership of AHD’s general partner, it manages AHD. AHD’s cash generating assets currently consist solely of its interests in APL. At September 30, 2009, the Company owned approximately 64.4% of the outstanding common units of AHD. AHD owned a 2% general partner interest, all of the incentive distribution rights, an approximate 11.2% common limited partner interest, and 15,000 $1,000 par value 12.0% Class B cumulative preferred limited partner units in APL; and
   
Lightfoot Capital Partners, LP (“Lightfoot LP”) and Lightfoot Capital Partners GP LLC, (“Lightfoot GP”), the general partner of Lightfoot (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. The Company has an approximate direct and indirect 18% ownership interest in Lightfoot GP and a commitment to invest a total of $20.0 million in Lightfoot LP. The Company also has direct and indirect ownership interest in Lightfoot LP. As of September 30, 2009, the Company has invested $10.7 million in Lightfoot LP.
The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2008 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. Management has evaluated subsequent events through November 9, 2009, the date the financial statements were issued. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008. Certain amounts in the prior year’s consolidated financial statements have also been reclassified to conform to the current year presentation, including $18.8 million of pre-development costs shown as component of “Property, plant, and equipment, net” which was previously combined with

 

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“Liabilities associated with drilling contracts” on the Company’s consolidated balance sheets at December 31, 2008. On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system (see Note 5). As such, the Company has adjusted its prior period consolidated financial statements and related footnote disclosures presented within this Form 10-Q to reflect the amounts related to the operations of the NOARK gas gathering and interstate pipeline system as discontinued operations. The Company’s consolidated financial statements and related footnotes as of and for the year ended December 31, 2008 contained within its Annual Report on Form 10-K have been restated to reflect the amounts related to the discontinued operations of the NOARK system (see Note 5) and Financial Accounting Standards Board issued Accounting Standard Concept 810-10-65-1, “Non-controlling Interests in Consolidated Financial Statements” (see Note 2).The results of operations for the three and nine month periods ended September 30, 2009 may not necessarily be indicative of the results of operations for the full year ending December 31, 2009.
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
In addition to matters discussed further within this note, a more thorough discussion of the Company’s significant accounting policies is included in its audited consolidated financial statements and notes thereto in its annual report on Form 10-K for the year ended December 31, 2008.
Principles of Consolidation and Non-controlling Interest
The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly-owned at September 30, 2009 except for AHD, which is controlled by the Company, and APL, which is controlled by AHD. The financial statements of AHD include its accounts and the accounts of its subsidiaries, all of which are wholly-owned except for APL. Prior to ATN’s merger with the Company’s wholly-owned subsidiary on September 29, 2009, ATN was a controlled subsidiary of the Company but was not wholly-owned (see Note 3). The non-controlling ownership interests in the net income (loss) of ATN prior to the Merger, AHD and APL are reflected within non-controlling interests on the Company’s consolidated statements of operations. The non-controlling interests in the assets and liabilities of AHD and APL are reflected as a component of stockholders’ equity on the Company’s consolidated balance sheets. The non-controlling interests in the assets and liabilities of ATN are reflected as a component of stockholders’ equity on the Company’s December 31, 2008 consolidated balance sheet. All material intercompany transactions have been eliminated.
In accordance with established practice in the oil and gas industry, the Company’s financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the energy partnerships in which the Company has an interest (“the Partnerships”). Such interests typically range from 15% to 35%. The Company’s financial statements do not include proportional consolidation of the depletion or impairment expenses of the Partnerships. Rather, the Company calculates these items specific to its own economics as further explained under the heading “Oil and Gas Properties” below.
The Company’s consolidated financial statements also include APL’s 95% ownership interest in joint ventures which individually own a 100% ownership interest in the Chaney Dell natural gas gathering system and processing plants and a 72.8% undivided interest in the Midkiff/Benedum natural gas gathering system and processing plants. APL consolidates 100% of these joint ventures. The Company reflects the non-controlling 5% ownership interest in the joint ventures as non-controlling interests on its statements of operations. The Company also reflects the 5% ownership interest in the net assets of the joint ventures as non-controlling interests as a component of stockholders’ equity on its consolidated balance sheets. The joint ventures have a $1.9 billion note receivable from the holder of the 5% ownership interest in the joint ventures, which is reflected within non-controlling interests on the Company’s consolidated balance sheets.

 

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The Midkiff/Benedum joint venture has a 72.8% undivided joint venture interest in the Midkiff/Benedum system, of which the remaining 27.2% interest is owned by Pioneer Natural Resources Company (NYSE: PXD) (“Pioneer”). Due to the Midkiff/Benedum system’s status as an undivided joint venture, the Midkiff/Benedum joint venture proportionally consolidates its 72.8% ownership interest in the assets and liabilities and operating results of the Midkiff/Benedum system. On November 2, 2009, APL’s agreement with Pioneer, whereby Pioneer had an option to purchase additional interest in the Midkiff/Benedum system, expired without Pioneer exercising its option (see Note 19.)
Use of Estimates
The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Company’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Company’s consolidated financial statements are based on a number of significant estimates, including the revenue and expense accruals, deferred tax assets and liabilities, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. Actual results could differ from those estimates.
The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three and nine months ended September 30, 2009 represent actual results in all material respects (see “- Revenue Recognition” accounting policy for further description).
Impairment of Long-Lived Assets
The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.
The review of the Company’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.
The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, the Company’s reserve estimates for its investment in the Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include the Company’s actual capital contributions, an additional carried interest (generally 7% to 10%), a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

 

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The Company’s lower operating and administrative costs result from the limited partners in the Partnerships paying to the Company their proportionate share of these expenses plus a profit margin. These assumptions could result in the Company’s calculation of depletion and impairment being different than its proportionate share of the Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Company cannot predict what reserve revisions may be required in future periods.
The Company’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Partnerships which the Company sponsors and owns an interest in but does not control. The Company’s reserve quantities include reserves in excess of its proportionate share of reserves in a partnership which the Company may be unable to recover due to the Partnership legal structure. The Company may have to pay additional consideration in the future as a well or Partnership becomes uneconomic under the terms of the Partnership agreement in order to recover these excess reserves and to acquire any additional residual interests in the wells held by other Partnership investors. The acquisition of any well interest from the Partnership by the Company is governed under the Partnership agreement and must be at fair market value supported by an appraisal of an independent expert selected by the Company.
Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. There were no impairments of oil and gas properties or unproved properties recorded by the Company for the three and nine months ended September 30, 2009 and 2008.
Capitalized Interest
The Company and its subsidiaries capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds by the Company in the aggregate was 8.4% and 5.6% for the three months ended September 30, 2009 and 2008, respectively, and 7.0% and 5.8% for the nine months ended September 30, 2009 and 2008, respectively. The aggregate amount of interest capitalized by the Company was $2.2 million and $2.6 million for the three months ended September 30, 2009 and 2008, respectively, and $7.9 million and $7.3 million for the nine months ended September 30, 2009 and 2008, respectively.
Intangible Assets
Customer contracts and relationships. APL amortizes intangible assets with finite lives in connection with natural gas gathering contracts and customer relationships assumed in certain consummated acquisitions, which APL amortizes over their estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset must be amortized over the best estimate of its useful life. At a minimum, APL will assess the useful lives of all intangible assets on an annual basis to determine if adjustments are required. The estimated useful life for APL’s customer contract intangible assets is based upon the approximate average length of customer contracts in existence and expected renewals at the date of acquisition. The estimated useful life for APL’s customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition, adjusted for APL’s management’s estimate of whether the individual relationships will continue in excess or less than the average length.

 

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Partnership management, operating contracts and non-compete agreement. The Company has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through consummated acquisitions. In addition, the Company entered into a two-year non-compete agreement in connection with the acquisition of its Michigan operations. The Company amortizes contracts acquired on a declining balance and straight-line method over their respective estimated useful lives.
The following table reflects the components of intangible assets being amortized at September 30, 2009 and December 31, 2008 (in thousands):
                         
                    Estimated  
    September 30,     December 31,     Useful Lives  
    2009     2008     In Years  
Gross Carrying Amount:
                       
Customer contracts and relationships
  $ 235,382     $ 235,382       7 - 20  
Partnership management and operating contracts
    14,343       14,343       2 - 13  
Non-compete agreement
    890       890          
 
                   
 
  $ 250,615     $ 250,615          
 
                   
 
                       
Accumulated Amortization:
                       
Customer contracts and relationships
  $ (60,902 )   $ (41,735 )        
Partnership management and operating contracts
    (11,284 )     (10,728 )        
Non-compete agreement
    (890 )     (667 )        
 
                   
 
  $ (73,076 )   $ (53,130 )        
 
                   
 
                       
Net Carrying Amount:
                       
Customer contracts and relationships
  $ 174,480     $ 193,647          
Partnership management and operating contracts
    3,059       3,615          
Non-compete agreement
          223          
 
                   
 
  $ 177,539     $ 197,485          
 
                   
Amortization expense on intangible assets was $6.6 million and $6.7 million for the three months ended September 30, 2009 and 2008, respectively, and $19.9 million and $20.1 million for the nine months ended September 30, 2009 and 2008, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2010-$26.3 million; 2011-$26.2 million; 2012-$25.7 million; 2013-$24.6 million; and 2014-$20.6 million.
Goodwill
At September 30, 2009 and December 31, 2008, the Company had $35.2 million of goodwill recorded in connection with consummated acquisitions. The changes in the carrying amount of goodwill for the nine months ended September 30, 2009 and 2008 were as follows (in thousands):
                 
    Nine Months Ended  
    September 30,  
    2009     2008  
Balance, beginning of period
  $ 35,166     $ 744,449  
APL post-closing purchase price adjustment with seller and purchase price allocation adjustment — Chaney Dell and Midkiff/Benedum systems acquisition
          (2,217 )
APL recovery of state sales tax initially paid on transaction — Chaney Dell and Midkiff/Benedum systems acquisition
          (30,206 )
 
           
Balance, end of period
  $ 35,166     $ 712,026  
 
           

 

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As a result of its impairment evaluation at December 31, 2008, the Company recognized a $676.9 million non-cash impairment charge within its consolidated statements of operations for the year ended December 31, 2008. The goodwill impairment resulted from the reduction in APL’s estimated fair value of its reporting units in comparison to their carrying amounts at December 31, 2008. APL’s estimated fair value of its reporting units was impacted by many factors, including the significant deterioration of commodity prices and global economic conditions during the fourth quarter of 2008. These estimates were subjective and based upon numerous assumptions about future operations and market conditions. There were no goodwill impairments recognized by the Company related to ATN during the year ended December 31, 2008 and for the period ended September 30, 2009.
The Company tests its goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for its reporting units are not available, the Company’s management must apply judgment in determining the estimated fair value of these reporting units. The Company’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to the Company’s market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including the Company’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, the Company also considers a control premium to the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in the Company’s industry. The resultant fair values calculated for the reporting units are then compared to observable metrics on large mergers and acquisitions in the Company’s industry to determine whether those valuations appear reasonable in management’s judgment. The Company will continue to evaluate goodwill at least annually or when impairment indicators arise. During the nine months ended September 30, 2009, no impairment indicators arose.
In April 2008, APL received a $30.2 million cash reimbursement for sales tax initially paid on its transaction to acquire the Chaney Dell and Midkiff/Benedum systems in July 2007. The $30.2 million was initially capitalized as an acquisition cost and allocated to the assets acquired, including goodwill, based upon their estimated fair values at the date of acquisition. Based upon the reimbursement of the sales tax paid in April 2008, APL reduced goodwill recognized in connection with the acquisition at March 31, 2008.
Net Income (Loss) Per Share
Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of common stock outstanding during the period. Diluted net income (loss) per share is calculated by dividing net income (loss) by the sum of the weighted average number of common stock outstanding and the dilutive effect of potential shares issuable during the period, as calculated by the treasury stock method. Dilutive potential shares of common stock consist of the excess of shares issuable under the terms of the Company’s stock incentive plan over the number of such shares that could have been reacquired (at the weighted average market price of shares during the period) with the proceeds received from the exercise of the stock options (see Note 17). The following table sets forth the reconciliation of the Company’s weighted average number of common shares used to compute basic net income (loss) per share with those used to compute diluted net income (loss) per share (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008(1)     2009     2008(1)  
 
                               
Weighted average number of shares — basic
    39,780       40,093       39,460       40,251  
 
                               
Add: effect of dilutive incentive awards
          1,901       591       1,870  
 
                       
Weighted average number of common shares — diluted
    39,780       41,994       40,051       42,121  
 
                       
 
     
(1)  
For the three months ended September 30, 2009, approximately 926,000 shares were excluded from the computation of diluted earnings attributable to common shareholders because the inclusion of such shares would have been anti-dilutive.

 

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Revenue Recognition
Certain energy activities are conducted by the Company through, and a portion of its revenues are attributable to, sponsored investment Partnerships. The Company contracts with the Partnerships to drill partnership wells. The contracts require that the Partnerships must pay the Company the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed between 60 and 180 days. On an uncompleted contract, the Company classifies the difference between the contract payments it has received and the revenue earned as a current liability titled “Liabilities Associated with Drilling Contracts” on the Company’s consolidated balance sheets. The Company recognizes well services revenues at the time the services are performed. The Company is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned and includes them in administration and oversight revenues.
The Company generally sells natural gas and crude oil at prevailing market prices. Revenue is recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil in which the Company has an interest with other producers are recognized on the basis of the Company’s percentage ownership of working interest and/or overriding royalty. Generally, the Company’s sales contracts are based on pricing provisions that are tied to a market index, with certain adjustments based on proximity to gathering and transmission lines and the quality of its natural gas.
Atlas Pipeline. APL’s revenue primarily consists of the fees earned from its transmission, gathering and processing operations. Under certain agreements, APL purchases natural gas from producers and moves it into receipt points on its pipeline systems, and then sells the natural gas, or produced natural gas liquids (“NGLs”), if any, off of delivery points on its systems. Under other agreements, APL transports natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. In connection with its gathering and processing operations, APL enters into the following types of contractual relationships with its producers and shippers:
   
Fee-Based Contracts. These contracts provide for a set fee for gathering and processing raw natural gas. APL’s revenue is a function of the volume of natural gas that it gathers and processes and is not directly dependent on the value of the natural gas.
   
POP Contracts. These contracts provide for APL to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this situation, APL and the producer are directly dependent on the volume of the commodity and its value; APL owns a percentage of that commodity and is directly subject to its market value.
   
Keep-Whole Contracts. These contracts require APL, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, APL bears the economic risk (the “processing margin risk”) that the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that it paid for the unprocessed natural gas. However, because the natural gas purchases contracted under keep-whole agreements are generally low in liquids content and meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants and delivered directly into downstream pipelines during periods of margin risk. Therefore, the processing margin risk associated with a portion of APL’s keep-whole contracts is minimized.

 

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The Company accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, crude oil, and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s and APL’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “-Use of Estimates” accounting policy for further description). The Company had unbilled revenues at September 30, 2009 and December 31, 2008 of $66.3 million and $87.4 million, respectively, which are included in accounts receivable within the Company’s consolidated balance sheets.
Comprehensive Income (Loss)
Comprehensive income (loss) includes net income and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States, have not been recognized in the calculation of net income. These changes, other than net income, are referred to as “other comprehensive income (loss)” and for the Company includes changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges and post-retirement plan liabilities (which are presented net of income taxes). The following table sets forth the calculation of the Company’s comprehensive income (loss) (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
 
                               
Net income (loss)
  $ (9,886 )   $ 218,157     $ 116,983     $ (38,023 )
(Income) loss attributable to non-controlling interests
    9,172       (194,054 )     (103,686 )     60,777  
 
                       
Net income (loss) attributable to common shareholders
    (714 )     24,103       13,297       22,754  
Other comprehensive loss:
                               
Changes in fair value of derivative instruments accounted for as cash flow hedges, net of (tax) benefit of ($26,351) and ($53,885) for the three months ended September 30, 2009 and 2008, respectively, and ($39,354) and $9,431 for the six months ended September 30, 2009 and 2008, respectively
    (14,761 )     242,645       45,634       (111,397 )
Less: reclassification adjustment for realized losses (gains) in net income (loss), net of (tax) benefit of $13,027 and ($5,633) for the three months ended September 30, 2009 and 2008, respectively, and $20,722 and ($6,810) for the nine months ended September 30, 2009 and 2008, respectively
    (14,050 )     30,502       (30,722 )     63,398  
Changes in non-controlling interest related to items in other comprehensive income (loss)
    49,653       (180,054 )     14,231       44,256  
Plus: amortization of additional post-retirement liability recorded upon adoption of SFAS No. 158, net of (tax) benefit of $13 and $51 for the three months ended September 30, 2009 and 2008, respectively, and $39 and $153 for the nine months ended September 30, 2009 and 2008, respectively
    22       87       65       296  
 
                       
Total other comprehensive (loss) gain
    20,864       93,180       29,208       (3,447 )
 
                       
Comprehensive income (loss) attributable to common shareholders
  $ 20,150     $ 117,283     $ 42,505     $ 19,307  
 
                       

 

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Recently Adopted Accounting Standards
In August 2009, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2009-05, “Fair Value Measurements and Disclosures (Topic 820) — Measuring Liabilities at Fair Value” (“Update 2009-05”). Update 2009-05 amends Subtopic 820-10, “Fair Value Measurements and Disclosures — Overall” and provides clarification for the fair value measurement of liabilities in circumstances where quoted prices for an identical liability in an active market are not available. The amendments also provide clarification for not requiring the reporting entity to include separate inputs or adjustments to other inputs relating to the existence of a restriction that prevents the transfer of a liability when estimating the fair value of a liability. Additionally, these amendments clarify that both the quoted price in an active market for an identical liability at the measurement date and the quoted price for an identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are considered Level 1 fair value measurements. These requirements are effective for financial statements issued after the release of Update 2009-05. The Company adopted the requirements on September 30, 2009 and it did not have a material impact on its financial position, results of operations or related disclosures.
In August 2009, the FASB issued Accounting Standards Update 2009-04, “Accounting for Redeemable Equity Instruments — Amendment to Section 480-10-S99” (“Update 2009-04”). Update 2009-04 updates Section 480-10-S99, “Distinguishing Liabilities from Equity”, to reflect the SEC staff’s views regarding the application of Accounting Series Release No. 268, “Presentation in Financial Statements of ‘Redeemable Preferred Stocks’” (“ASR No. 268”). ASR No. 268 requires preferred securities that are redeemable for cash or other assets to be classified outside of permanent equity if they are redeemable (1) at a fixed or determinable price on a fixed or determinable date, (2) at the option of the holder, or (3) upon the occurrence of an event that is not solely within the control of the issuer. The Company adopted the requirements of FASB Update 2009-04 on August 1, 2009 and it did not have a material impact on its financial position, results of operations or related disclosures.
In June 2009, the FASB issued Accounting Standards Update 2009-01, “Topic 105 — Generally Acceptable Accounting Principles Amendments Based on Statement of Financial Accounting Standards No. 168 — The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“Update 2009-01”). Update 2009-01 establishes the FASB Accounting Standards Codification (“ASC”) as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The ASC supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following the ASC, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting Standards Updates, which will serve only to update the ASC. The ASC is effective for financial statements issued for interim and annual periods ending after September 15, 2009. All required references to non-SEC accounting standards have been modified by the Company. The Company adopted the requirements of Update 2009-01 to its financial statements on September 30, 2009 and it did not have a material impact to the Company’s financial statement disclosures.

 

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In May 2009, the FASB issued ASC 855-10, “Subsequent Events” (“ASC 855-10”). ASC 855-10 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The provisions require management of a reporting entity to evaluate events or transactions that may occur after the balance sheet date for potential recognition or disclosure in the financial statements and provides guidance for disclosures that an entity should make about those events. ASC 855-10 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. The Company adopted the requirements of this standard on June 30, 2009 and it did not have a material impact to its financial position or results of operations or related disclosures. The adoption of these provisions does not change the Company’s current practices with respect to evaluating, recording and disclosing subsequent events.
In April 2009, the FASB issued ASC 820-10-65-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“ASC 820-10-65-4”). ASC 820-10-65-4 applies to all fair value measurements and provides additional clarification on estimating fair value when the market activity for an asset has declined significantly. ASC 820-10-65-4 also require an entity to disclose a change in valuation technique and related inputs to the valuation calculation and to quantify its effects, if practicable. ASC 820-10-65-4 is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted the requirements of ASC 820-10-65-4 on April 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.
In April 2009, the FASB issued ASC 320-10-65-1, “Recognition and Presentation of Other-Than-Temporary Impairments” (“ASC 320-10-65-1”), which changes previously existing guidance for determining whether an impairment is other than temporary for debt securities. ASC 320-10-65-1 replaces the previously existing requirement that an entity’s management assess if it has both the intent and ability to hold an impaired security until recovery with a requirement that management assess that it does not have the intent to sell the security and that it is more likely than not that it will not have to sell the security before recovery of its cost basis. ASC 320-10-65-1 also requires that an entity recognize noncredit losses on held-to-maturity debt securities in other comprehensive income and amortize that amount over the remaining life of the security and for the entity to present the total other-than-temporary impairment in the statement of operations with an offset for the amount recognized in other comprehensive income. ASC 320-10-65-1 is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted these requirements on April 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.
In April 2009, the FASB issued ASC 825-10-65-1, “Interim Disclosures about Fair Value of Financial Instruments” (“ASC 825-10-65-1”), which requires an entity to provide disclosures about fair value of financial instruments in interim financial information. In addition, an entity shall disclose in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position. ASC 825-10-65-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted these requirements on April 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.
In April 2009, the FASB issued ASC 805-20-30-23, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“ASC 805-20-30-23”), which requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be recognized at fair value if fair value can be reasonably estimated. If fair value of such an asset or liability cannot be reasonably estimated, the asset or liability would generally be recognized in accordance with previous requirements. ASC 805-20-30-23 eliminates the requirement to disclose an estimate of the range of outcomes of recognized contingencies at the acquisition date. ASC 805-20-30-23 is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for the Company). The Company adopted the requirements on January 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

 

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In June 2008, the FASB issued ASC 260-10-45-61A, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“ASC 260-10-45-61A”). ASC 260-10-45-61A applies to the calculation of earnings per share (“EPS”) described in previous guidance, for share-based payment awards with rights to dividends or dividend equivalents. It states that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. ASC 260-10-45-61A is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption was prohibited. The Company adopted the requirements on January 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.
In April 2008, the FASB issued ASC 350-30-65-1, “Determination of Useful Life of Intangible Assets” (“ASC 350-30-65-1”). ASC 350-30-65-1 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under previous guidance. The intent of ASC 350-30-65-1 is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset. The Company adopted the requirements of ASC 350-30-65-1 on January 1, 2009 and its adoption did not have a material impact on its financial position and results of operations.
In March 2008, the FASB issued ASC 260-10-55-103 through 55-110, “Application of the Two-Class Method” (“ASC 260-10-55-103”), which considers whether the incentive distributions of a master limited partnership represent a participating security when considered in the calculation of earnings per unit under the two-class method. ASC 260-10-55-103 considers whether the partnership agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. The Company’s adoption of ASC 260-10-55-103 on January 1, 2009 impacted its presentation of net income (loss) per common limited partner unit as the Company previously presented net income (loss) per common limited partner unit as though all earnings were distributed each quarterly period (see “—Net Income (Loss) Per Common Unit”). The Company adopted the requirements of ASC 260-10-55-103 on January 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.
In March 2008, the FASB issued ASC 815-10-50-1, “Disclosures about Derivative Instruments and Hedging Activities” (“ASC 815-10-50-1”), to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The Company adopted the requirements of this section of ASC 815-10-50-1 on January 1, 2009 and it did not have a material impact on its financial position or results of operations (see Note 10).

 

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In December 2007, the FASB issued ASC 810-10-65-1, “Non-controlling Interests in Consolidated Financial Statements” (“ASC 810-10-65-1”). ASC 810-10-65-1 establishes accounting and reporting standards for the non-controlling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. It also requires consolidated net income to be reported and disclosed on the face of the consolidated statement of operations at amounts that include the amounts attributable to both the parent and the non-controlling interest. Additionally, ASC 810-10-65-1 establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated and adjust its remaining investment, if any, at fair value. The Company adopted the requirements of ASC 810-10-65-1on January 1, 2009 and adjusted its presentation of its financial position and results of operations. Prior period financial position and results of operations have been adjusted retrospectively to conform to these provisions.
In December 2007, the FASB issued ASC 805, “Business Combinations” (“ASC 805”). ASC 805 retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. ASC 805 requires an acquirer to recognize the assets acquired, liabilities assumed, and any non-controlling interest in the acquiree at the acquisition date, at their fair values as of that date, with specified limited exceptions. Additionally, it requires costs incurred in connection with an acquisition be expensed as incurred. Restructuring costs, if any, are to be recognized separately from the acquisition. The acquirer in a business combination achieved in stages must also recognize the identifiable assets and liabilities, as well as the non-controlling interests in the acquiree, at the full amounts of their fair values. The Company adopted these requirements on January 1, 2009 and it did not have a material impact on its financial position and results of operations.
Recently Issued Accounting Standards
In October 2009, the FASB issued Accounting Standards Update 2009-15, “Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing” (“Update 2009-15”). Update 2009-15 includes amendments to Topic 470, “Debt”, and Topic 260, “Earnings per Share”, to provide guidance on share-lending arrangements entered into on an entity’s own shares in contemplation of a convertible debt offering or other financing. These requirements are effective for existing arrangements for fiscal years beginning on or after December 15, 2009, and interim periods within those fiscal years for arrangements outstanding as of the beginning of those years, with retrospective application required for such arrangements that meet the criteria. These requirements are also effective for arrangements entered into on (not outstanding) or after the beginning of the first reporting period that begins on or after June 15, 2009. The Company will apply these requirements upon its adoption on January 1, 2010 and does not expect it to have a material impact to its financial position or results of operations or related disclosures.
In June 2009, the FASB issued ASC 810-10-25-20 through 25-59, “Consolidation of Variable Interest Entities” (“ASC 810-10-25-20”), which changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. ASC 820-10-25-20 requires a reporting entity to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. A reporting entity will be required to disclose how its involvement with a variable interest entity affects the reporting entity’s financial statements. These requirements are effective at the start of a reporting entity’s first fiscal year beginning after November 15, 2009 (January 1, 2010 for the Company). The Company is currently evaluating the impact of these requirements upon its adoption on January 1, 2010.
Modernization of Oil and Gas Reporting
In December 2008, the Securities and Exchange Commission (“SEC”) announced that it had approved revisions to its oil and gas reporting disclosures by adopting amendments to Rule 4-10 of Regulation S-X and Items 201, 801, and 802 of Regulation S-K. These new disclosure requirements are referred to as “Modernization of Oil and Gas Reporting” and include provisions that:
   
Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.

 

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Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end pricing. This should maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.
 
   
Permit companies to disclose their probable and possible reserves on a voluntary basis. Current rules limit disclosure to only proved reserves.
 
   
Update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include “by geographic area” and “reasonable certainty”.
 
   
Permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.
 
   
Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures are required related to internal controls over reserve estimation, as well as a report addressing the independence and qualifications of a company’s reserves preparer or auditor based on Society of Petroleum Engineers criteria.
The Company will begin complying with the disclosure requirements in its annual report on Form 10-K for the year ending December 31, 2009. The new rules may not be applied to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. The Company is currently in the process of evaluating the new requirements.
NOTE 3 — COMMON STOCK
Merger with Atlas Energy Resources, LLC
On September 29, 2009, the Company completed its merger with ATN pursuant to the definitive merger agreement previously executed between the Company and ATN, with ATN surviving as the Company’s wholly-owned subsidiary. In the Merger, the 33.4 million Class B common units of ATN not previously held by the Company were exchanged for 38.8 million shares of the Company’s common stock (a ratio of 1.16 shares of the Company’s common stock for each Class B common unit of ATN). The Company also changed its name from Atlas America, Inc. to Atlas Energy, Inc. Concurrent with the Merger, the Compensation Committee of the Board of Directors approved the Atlas Energy, Inc. 2009 Stock Incentive Plan, which creates a new stock incentive plan for the combined entity. The Company also has the legacy Atlas America stock incentive plan and the legacy ATN Long-Term Incentive Plan (see Note 17).
Due to the Merger, the Company recognized a reduction of $556.4 million in non-controlling interest and a decrease to deferred tax liability of $179.4 million, all of which was reflected as an increase to additional paid-in-capital on the Company’s consolidated balance sheets.
The Company also recognized the fair value of the interests exchanged in the Merger, excluding transaction costs incurred, of $724.8 million as a non-cash item in its consolidated statement of cash flows for the nine months ended September 30, 2009.
Authorized Shares
On July 13, 2009, the Company’s stockholders approved an increase to its authorized shares from 49,000,000 authorized shares to 114,000,000 authorized shares.

 

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Stock Repurchase Plan
In September 2008, the Company’s Board of Directors approved a stock repurchase program of up to $50.0 million at a price not to exceed $36.00 per share. The daily repurchase amount was limited to 50,000 shares. The Company purchased 595,292 of its shares during September and October 2008 for a total price of $20.0 million under this program. In addition, the Company utilized the remaining $20.0 million of availability under a stock repurchase program approved in September 2005 to purchase 560,291 shares in August and September 2008. The average price for the shares purchased during 2008 was $34.76 per share.
Stock Splits
On April 22, 2008, the Company’s Board of Directors approved a three-for-two stock split of the Company’s common stock effected in the form of a 50% stock dividend. All shareholders of record as of May 21, 2008 received one additional share of common stock for every two shares of common stock held on that date. The additional shares of common stock were distributed on May 30, 2008. Information pertaining to shares and earnings per share has been restated for the three and nine months ended September 30, 2008 in the accompanying consolidated financial statements and notes to the consolidated financial statements to reflect this split.
The following data presents pro forma revenue, net income, net income per share and basic and diluted weighted average shares outstanding for the Company for the three and nine months ended September 30, 2009 and 2008, respectively, as if the Merger discussed above had occurred on January 1, 2008. The Company has prepared these unaudited pro forma financial results for comparative purposes only. The pro forma adjustments reflect an adjustment to income previously allocated to non-controlling interest offset by the restated tax impact. These pro forma financial results may not be indicative of the results that would have occurred if the Merger had been completed at the beginning of the periods shown below or the results that will be attained in the future (in thousands, except per share data; unaudited):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Revenue
  $ 367,184     $ 771,002     $ 1,145,264     $ 1,583,473  
Income attributable to common shareholders:
                               
Income from continuing operations
  $ 562     $ 36,495     $ 18,591     $ 59,568  
Discontinued operations
          433       4,253       1,323  
 
                       
Net income attributable to common shareholders
  $ 562     $ 36,928     $ 22,844     $ 60,891  
 
                       
 
                               
Net income attributable to common shareholders per share — basic:
                               
Income from continuing operations attributable to common shareholders
  $ 0.01     $ 0.46     $ 0.24     $ 0.75  
Discontinued operations attributable to common shareholders
    0.00       0.01       0.05       0.02  
 
                       
Net income attributable to common shareholders
  $ 0.01     $ 0.47     $ 0.29     $ 0.77  
 
                       
 
                               
Net income attributable to common shareholders per share — diluted:
                               
Income from continuing operations attributable to common shareholders
  $ 0.01     $ 0.44     $ 0.24     $ 0.73  
Discontinued operations attributable to common shareholders
    0.00       0.01       0.05       0.02  
 
                       
Net income attributable to common shareholders
  $ 0.01     $ 0.45     $ 0.29     $ 0.75  
 
                       
 
                               
Weighted average common shares outstanding:
                               
Basic
    78,136       78,869       78,095       79,027  
 
                       
Diluted
    79,144       81,307       78,714       81,451  
 
                       

 

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NOTE 4 — APL INVESTMENT IN JOINT VENTURE
On May 31, 2009, APL and subsidiaries of The Williams Companies, Inc. (NYSE: WMB) (“Williams”) completed the formation of Laurel Mountain Midstream, LLC (“Laurel Mountain”), a joint venture which owns and operates APL’s Appalachia Basin natural gas gathering system, excluding APL’s Northern Tennessee operations. Williams contributed cash of $100.0 million to the joint venture (of which APL received approximately $87.8 million, net of working capital adjustments) and a note receivable of $25.5 million. In addition, ATN sold certain assets to the joint venture for $12.0 million. APL contributed its Appalachia Basin natural gas gathering system and retained a 49% ownership interest. APL is also entitled to preferred distribution rights relating to all payments on the note receivable. Williams retained the remaining 51% ownership interest in Laurel Mountain. Upon completion of the transaction, APL recognized its 49% ownership interest in Laurel Mountain as an investment in joint venture on the Company’s consolidated balance sheet at fair value and recognized a gain on sale of $108.9 million, including $54.2 million associated with the re-measurement of APL’s investment in Laurel Mountain to fair value. APL used the net proceeds from the transaction to reduce borrowings under its senior secured credit facility (see Note 9). In addition, the Company sold two natural gas processing plants and associated pipelines located in Southwestern Pennsylvania to Laurel Mountain for $10.0 million, resulting in a $5.7 million loss which is included in gain on asset sale on the Company’s consolidated statement of operations. Upon the completion of the contribution of APL’s Appalachia gathering systems to Laurel Mountain, Laurel Mountain entered into new gas gathering agreements with the Company which superseded the existing natural gas gathering agreements and omnibus agreement between APL and the Company. Under the new gas gathering agreement, the Company is obligated to pay the joint venture all of the gathering fees it collects from its investment drilling partnerships plus any excess amount over the amount of the competitive gathering fee (which is currently defined as 13% of the gross sales price received for the Company’s investment drilling partnerships’ gas). APL has accounted for its ownership interest in Laurel Mountain under the equity method of accounting, with recognition of its ownership interest in the income of Laurel Mountain other income (loss) on the Company’s consolidated statements of operations.
The following table provides summarized statement of operations and balance sheet data on a 100% basis for Laurel Mountain for the three and nine months ended September 30, 2009 and as of September 30, 2009 (in thousands):
                 
    Three Months     Nine Months  
    Ended     Ended  
    September 30, 2009     September 30, 2009(1)  
Statement of Operations data:
               
Total revenue
  $ 9,622     $ 12,690  
Net income
    2,386       3,664  
         
    September 30, 2009  
Balance Sheet data:
       
Current assets
  $ 9,871  
Long-term assets
    245,577  
Current liabilities
    19,303  
Long-term liabilities
    8,500  
Net equity
    227,645  
 
     
(1)  
Represents the period from May 31, 2009, the date of initial formation, through September 30, 2009.

 

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NOTE 5 — DISCONTINUED OPERATIONS
On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system to Spectra Energy Partners OLP, LP (NYSE:SEP) (“Spectra”) for net proceeds of $292.0 million in cash, net of working capital adjustments. APL received an additional $2.5 million in cash in July 2009 upon the delivery of audited financial statements for the NOARK system assets to Spectra. APL used the net proceeds from the transaction to reduce borrowings under its senior secured term loan and revolving credit facility (see Note 9). The Company accounted for the sale of the NOARK system assets as discontinued operations within its consolidated financial statements and recorded a gain of $48.8 million (net of income taxes of $2.2 million) on the sale of APL’s NOARK assets within income from discontinued operations on its consolidated financial statement of operations for the three and nine months ended September 30, 2009. The following table summarizes the components included within income from discontinued operations on the Company’s consolidated statements of operations (amounts in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Total revenues
  $     $ 13,468     $ 21,274     $ 45,827  
Total costs and expenses
          (6,930 )     (9,858 )     (24,798 )
 
                       
Income before income tax expense
          6,538       11,416       21,029  
Income tax expense
          (277 )     (498 )     (848 )
 
                       
Income from discontinued operations
  $     $ 6,261     $ 10,918     $ 20,181  
 
                       
The following table summarizes the components included within total assets and liabilities of discontinued operations within the Company’s consolidated balance sheet for the period indicated (amounts in thousands):
         
    December 31,  
    2008  
Cash and cash equivalents
  $ 75  
Accounts receivable
    12,365  
Prepaid expenses and other
    1,001  
 
     
Total current assets of discontinued operations
    13,441  
Property, plant and equipment, net
    241,926  
Other assets, net
    239  
 
     
Total assets of discontinued operations
  $ 255,606  
 
     
 
       
Accounts payable
  $ 4,120  
Accrued liabilities
    5,892  
Accrued producer liabilities
    560  
 
     
Total current liabilities of discontinued operations
  $ 10,572  
 
     

 

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NOTE 6 — PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment are stated at cost. Depreciation, depletion and amortization are based on cost less estimated salvage value primarily using the unit-of-production or straight-line methods over the asset’s estimated useful life. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.
The following is a summary of property, plant and equipment (in thousands):
                         
                    Estimated  
    September 30,     December 31,     Useful Lives  
    2009     2008(1)     in Years  
Natural gas and oil properties:
                       
Proved properties:
                       
Leasehold interests
  $ 1,237,331     $ 1,214,991          
Pre-development costs
    14,750       18,772          
Wells and related equipment
    970,063       872,128          
 
                   
Total proved properties
    2,222,144       2,105,891          
Unproved properties
    43,279       43,749          
Support equipment
    8,605       9,527          
 
                   
Total natural gas and oil properties
    2,274,028       2,159,167          
Pipelines, processing and compression facilities
    1,671,863       1,728,472       15 - 40  
Rights of way
    166,874       168,206       20 - 40  
Land, buildings and improvements
    24,593       24,385       10 - 40  
Other
    21,867       22,108       3 - 10  
 
                   
 
    4,159,225       4,102,338          
 
                       
Less — accumulated depreciation, depletion and amortization
    (450,836 )     (357,523 )        
 
                   
 
  $ 3,708,389     $ 3,744,815          
 
                   
 
     
(1)  
Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 5)
The Company follows the successful efforts method of accounting for oil and gas producing activities. Acquisition costs of leases and development activities are capitalized. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs and delay rentals are expensed. Oil is converted to gas equivalent basis (“Mcfe”) at the rate one barrel equals 6 thousand cubic feet (“Mcf”). Depletion is provided on the units-of-production method.
Depletion, depreciation and amortization expense is determined on a field-by-field basis using the units-of-production method. Depletion, depreciation and amortization rates for leasehold acquisition costs based on estimated proved reserves and depletion, depreciation and amortization rates for well and related equipment costs based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include the Company’s costs of property interests in uncontrolled, but proportionately consolidated from investment partnerships, wells drilled solely by the Company for its interest, properties purchased and working interests with other outside operators.
Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to income. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the statements of income. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

 

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On July 13, 2009, APL sold a natural gas processing facility and a one-third undivided interest in other associated assets located in its Mid-Continent operating segment for approximately $22.6 million in cash. The facility was sold to Penn Virginia Resource Partners, L.P. (NYSE: PVR), who will provide natural gas volumes to the facility and reimburse APL for its proportionate share of the operating expenses. APL will continue to operate the facility. APL used the proceeds from this transaction to reduce outstanding borrowings under its senior secured credit facility. APL recognized a gain on sale of $2.5 million, which is recorded within gain on asset sales on the Company’s consolidated statements of operations.
NOTE 7 — OTHER ASSETS
The following is a summary of other assets at the dates indicated (in thousands):
                 
    September 30,     December 31,  
    2009     2008(1)  
Deferred finance costs, net of accumulated amortization of $32,544 and $23,105 at September 30, 2009 and December 31, 2008, respectively
  $ 49,446     $ 38,871  
Investment in Lightfoot LP, Lightfoot GP and Magnetar LP
    8,442       10,779  
Other investments
    5,988       1,994  
Long-term pipeline lease prepayment
    2,606        
Security deposits
    3,937       1,667  
 
           
 
  $ 70,419     $ 53,311  
 
           
 
     
(1)  
Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 5)
Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (see Note 9). During the nine months ended September 30, 2009 and 2008, APL recorded $2.5 million and $1.2 million, respectively, of accelerated amortization of deferred financing costs associated with the retirement of a portion of its term loan, which is recorded within interest expense on the Company’s consolidated statement of operations.
The Company owns, directly and indirectly, approximately 13% of Lightfoot LP, an entity of which Jonathan Cohen, Vice Chairman of the Company’s Board of Directors, is the Chairman of the Board. In addition, the Company owns, directly and indirectly, approximately 18% of Lightfoot GP, the general partner of Lightfoot LP. The Company committed to invest a total of $20.0 million in Lightfoot LP. The Company has certain co-investment rights until such point as Lightfoot LP raises additional capital through a private offering to institutional investors or a public offering. Lightfoot LP has initial equity funding commitments of approximately $160.0 million and focuses its investments primarily on incubating new master limited partnerships and providing capital to existing MLPs in need of additional equity or structured debt. Lightfoot LP concentrates on assets that are MLP-qualified such as infrastructure, coal and other asset categories. The Company accounts for its investment in Lightfoot under the equity method of accounting. For the nine months ended September 30, 2009 and 2008, the Company recorded losses of $1.9 million and $0.7 million, respectively.
NOTE 8 — ASSET RETIREMENT OBLIGATIONS
The Company recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Company also considers the estimated salvage value in the calculation of depreciation, depletion and amortization.

 

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The estimated liability is based on the Company’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The Company has no assets legally restricted for purposes of settling asset retirement obligations. Except for its oil and gas properties, the Company has determined that there are no other material retirement obligations associated with tangible long-lived assets.
A reconciliation of the Company’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Asset retirement obligations, beginning of period
  $ 50,142     $ 45,334     $ 48,136     $ 42,358  
Liabilities incurred
    125       975       721       2,615  
Liabilities settled
    (113 )     (36 )     (198 )     (38 )
Accretion expense
    753       687       2,248       2,025  
 
                       
Asset retirement obligations, end of period
  $ 50,907     $ 46,960     $ 50,907     $ 46,960  
 
                       
The accretion expense is included in depreciation, depletion and amortization in the Company’s consolidated statements of operations.
NOTE 9 — DEBT
As of September 30, 2009, the Company’s debt consists entirely of instruments entered into by ATN, AHD and APL. The Company has not guaranteed any of its subsidiaries’ debt obligations, with the exception of the AHD credit facility. Total debt consists of the following (in thousands):
                 
    September 30,     December 31,  
    2009     2008  
ATN revolving credit facility
  $ 270,000     $ 467,000  
ATN 10.75% senior notes — due 2018
    406,105       406,655  
ATN 12.125% senior notes — due 2017
    196,350        
AHD credit facility
    12,000       46,000  
APL revolving credit facility
    315,000       302,000  
APL term loan
    433,505       707,180  
APL 8.125% senior notes — due 2015
    271,495       261,197  
APL 8.75% senior notes — due 2018
    223,050       223,050  
 
           
Total debt
    2,127,505       2,413,082  
Less current maturities
    (12,000 )      
 
           
Total long-term debt
  $ 2,115,505     $ 2,413,082  
 
           

 

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ATN Revolving Credit Facility
At September 30, 2009, ATN had a credit facility with a syndicate of banks with a borrowing base of $600.0 million that matures in June 2012. The borrowing base is redetermined semiannually on April 1 and October 1 subject to changes in oil and gas reserves or is automatically reduced by 25% of the stated principal of any senior unsecured notes issued by ATN. On July 13, 2009, ATN issued $200.0 million of senior unsecured notes, and the borrowing base was reduced by $50.0 million to $600.0 million. Up to $50.0 million of the credit facility may be in the form of standby letters of credit, of which $1.2 million was outstanding at September 30, 2009, which was not reflected as borrowings on the Company’s consolidated balance sheets. The facility is secured by substantially all of ATN’s assets and is guaranteed by each of its subsidiaries and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at ATN’s option. On April 9, 2009, the credit agreement was amended to, among other things, increase the applicable margin on Eurodollar Loans from a range of 100 to 175 basis points to a range of 200 to 300 basis points and the applicable margin for base rate loans from a range of 0 to 75 basis points to a range of 112.5 to 212.5 basis points. At September 30, 2009 and December 31, 2008, the weighted average interest rate on outstanding borrowings was 2.7% and 2.8%, respectively. The base rate for any day equals the higher of the federal funds rate plus 0.50%, the J.P. Morgan prime rate or the adjusted LIBOR for a month interest period plus 1.0%. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for Eurocurrency liabilities.
On July 10, 2009, ATN’s credit agreement was amended to, among other things, permit the Merger to allow ATN to distribute (a) amounts equal to the Company’s income tax liability attributable to ATN’s net income at the highest marginal rate and (b) up to $40.0 million per year and, to the extent that it distributes less than that amount in any year, it may carry over up to $20.0 million for use in the next year.
The events which constitute an event of default for ATN’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against ATN in excess of a specified amount and a change of control. In addition, the agreement limits sales, leases or transfers of assets and the incurrence of additional indebtedness. ATN is in compliance with these covenants as of September 30, 2009. The credit facility also requires ATN to maintain a ratio of current assets (as defined in the credit facility) to current liabilities (as defined in the credit facility) of not less than 1.0 to 1.0, and a ratio of total debt (as defined in the credit facility) to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”, as defined in the credit facility) of 3.75 to 1.0 commencing January 1, 2009, decreasing to 3.5 to 1.0 commencing January 1, 2010 and thereafter. According to the definitions contained in ATN’s credit facility, ATN’s ratio of current assets to current liabilities was 2.1 to 1.0 and its ratio of total debt to EBITDA was 3.0 to 1.0 at September 30, 2009.
ATN Senior Notes
At September 30, 2009, ATN had $400.0 million principal amount outstanding of 10.75% senior unsecured notes (“ATN 10.75% Senior Notes”) due on February 1, 2018 and $200.0 million principal amount outstanding of 12.125% senior unsecured notes due August 1, 2017 (“ATN 12.125% Senior Notes”; collectively, the “ATN Senior Notes”). The ATN 12.125% Senior Notes were issued on July 13, 2009 in a public offering at a price of 98.116% to par value for a yield 12.5% at maturity. Net proceeds from the offering were used to reduce outstanding borrowings under ATN’s revolving credit facility. Interest on the ATN Senior Notes in the aggregate is payable semi-annually in arrears on February 1 and August 1 of each year. The ATN 10.75% Senior Notes are redeemable at any time on or after February 1, 2013, and the ATN 12.125% Senior Notes are redeemable at any time on or after August 1, 2013, at specified redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, before February 1, 2011 for the ATN 10.75% Notes and before August 1, 2012 for the ATN 12.125% Senior Notes, ATN may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of equity offerings at a stated redemption price. The ATN Senior Notes are also subject to repurchase by ATN at a price equal to 101% for the ATN 10.75% Senior Notes and ATN 12.125% Senior Notes of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if ATN does not reinvest the net proceeds within 360 days. The ATN Senior Notes are junior in right of payment to ATN’s secured debt, including its obligations under its credit facility. The indentures governing the ATN Senior Notes contain covenants, including limitations of ATN’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. ATN is in compliance with these covenants as of September 30, 2009.

 

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AHD Credit Facility
At September 30, 2009, AHD had $12.0 million outstanding under a revolving credit facility with a syndicate of banks. On June 1, 2009, AHD entered into an amendment to its credit facility agreement which, among other changes:
   
required AHD to immediately repay $30.0 million of then-outstanding $46.0 million of borrowings under the credit facility, $15.0 million of which was borrowed from the Company through a subordinate loan;
 
   
required AHD to repay $4.0 million of the then-remaining $16.0 million outstanding under the credit facility on each of July 13, 2009, October 13, 2009 and January 13, 2010, with the balance of the indebtedness being due on the original maturity date of the credit facility of April 13, 2010. AHD repaid $4.0 million of its outstanding credit facility borrowings on July 13, 2009 and October 13, 2009 in accordance with the amendment through a subordinate loan with the Company. AHD may not borrow additional amounts under the credit facility or issue letters of credit;
 
   
requires AHD to use any of its “excess cash flow”, which the amendment generally defines as cash in excess of $1.5 million as of the last business day of each month, to repay outstanding borrowings under the credit facility. In addition, the amendment requires AHD to repay borrowings under the credit facility with the net proceeds of any sales of its common units in APL;
 
   
eliminated all financial covenants in the credit agreement, including the leverage ratio, the combined leverage ratio with APL and the interest coverage ratio (all as defined within the credit facility agreement);
 
   
prohibits AHD from paying any cash distributions on or redeeming any of its equity while the credit facility is in effect and permits AHD to pay operating expenses only to the extent incurred or paid in the ordinary course of business; and
 
   
reduced the applicable margin above LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank, National Association prime rate to be 0.75% for LIBOR loans and 0.0% for federal funds rate or prime rate loans. The weighted average interest rate on the outstanding credit facility borrowings at September 30, 2009 was 3.25%.
Borrowings under AHD’s credit facility are secured by a first-priority lien on a security interest in all of AHD’s assets, including the pledge of Atlas Pipeline GP’s interests in APL, and are guaranteed by Atlas Pipeline GP and AHD’s other subsidiaries (excluding APL and its subsidiaries). AHD’s credit facility contains customary covenants, including restrictions on its ability to incur additional indebtedness; make certain acquisitions, loans or investments; or enter into a merger or sale of substantially all of AHD’s property or assets, including the sale or transfer of interest in its subsidiaries. AHD is in compliance with these covenants as of September 30, 2009. The events which constitute an event of default under AHD’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreements, adverse judgments against AHD in excess of a specified amount, a change of control of the Company, AHD’s general partner or any other obligor, and termination of a material agreement and occurrence of a material adverse effect.

 

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AHD’s $30 million repayment was funded from the proceeds of (i) a loan from the Company in the amount of $15 million (obtained on June 1, 2009) and (ii) the purchase by APL of $15 million of preferred equity in a newly-formed subsidiary of AHD. Under the subordinate loan, interest accrues quarterly on the outstanding principal amount at the rate of 12% per annum, but before the maturity date, interest is payable entirely by increasing the principal amount of the note, and the maturity date is generally the day following the day that AHD pays all indebtedness under the credit facility (“Termination Date”). The material terms of the preferred units purchased by APL in a newly-formed subsidiary of AHD are as follows: distributions are payable quarterly at the rate of 12% per annum, but before the Termination Date, distributions will be paid by increasing APL’s investment in the preferred units; upon the Termination Date, all preferred distributions will be paid in cash to APL; and AHD has the option, after the Termination Date, of redeeming all of the preferred units APL owns for an amount equal to the preferred unit capital.
On June 1, 2009, in connection with AHD’s amendment of the credit facility, the Company guaranteed the then remaining balance outstanding under the credit facility under a guarantee agreement with the administrative agent of the credit facility. In consideration for this guarantee, AHD issued to the Company a promissory note which requires it to pay interest to the Company in an amount based upon the principal amount outstanding under the credit facility. The maturity date of the promissory note is the day following the date that AHD repays all outstanding borrowings under its credit facility. Interest on the promissory note, which is calculated on the outstanding balance under the credit facility, accrues quarterly at the rate of 3.75% per annum. However, prior to the maturity date of the promissory note, interest under the promissory note will not be payable in cash, but instead the principal amount upon which interest is calculated will be increased by the interest amount payable.
APL Term Loan and Revolving Credit Facility
At September 30, 2009, APL had a senior secured credit facility with a syndicate of banks which consisted of a term loan which matures in July 2014 and a $380.0 million revolving credit facility which matures in July 2013. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding APL revolving credit facility borrowings at September 30, 2009 was 6.8%, and the weighted average interest rate on the outstanding APL term loan borrowings at September 30, 2009 was 6.8%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $9.1 million was outstanding at September 30, 2009. These outstanding letter of credit amounts were not reflected as borrowings on the Company’s consolidated balance sheet.
On May 29, 2009, APL entered into an amendment to its credit facility agreement which, among other changes:
   
increased the applicable margin above adjusted LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank prime rate upon which borrowings under the credit facility bear interest;
 
   
for borrowings under the credit facility that bear interest at LIBOR plus the applicable margin, set a floor for the adjusted LIBOR interest rate of 2.0% per annum;
 
   
increased the maximum ratio of total funded debt (as defined in the credit agreement) to consolidated EBITDA (as defined in the credit agreement; the “leverage ratio”) and decreased the ratio of interest coverage (as defined in the credit agreement) that the credit facility requires APL to maintain;

 

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instituted a maximum ratio of senior secured funded debt (as defined in the credit agreement) to consolidated EBITDA (the “senior secured leverage ratio”) that the credit facility requires APL to maintain;
 
   
required that APL pay no cash distributions during the remainder of the year ended December 31, 2009 and allows it to pay cash distributions beginning January 1, 2010 if its senior secured leverage ratio is less than 2.75x and it has minimum liquidity (as defined in the credit agreement) of at least $50.0 million;
 
   
generally limits APL’s annual capital expenditures to $95.0 million for the remainder of fiscal 2009 and $70.0 million each year thereafter;
 
   
permitted APL to retain (i) up to $135.0 million of net cash proceeds from dispositions completed in fiscal 2009 for reinvestment in similar replacement assets within 360 days, and (ii) up to $50.0 million of net cash proceeds from dispositions completed in any subsequent fiscal year subject to certain limitations as defined within the credit agreement; and
 
   
instituted a mandatory repayment requirement of the outstanding senior secured term loan from excess cash flow (as defined in the credit agreement) based upon APL’s leverage ratio.
In June 2008, APL entered into an amendment to the credit facility agreement to revise the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to its early termination of certain derivative contracts (see Note 10) in calculating Consolidated EBITDA. Pursuant to this amendment, in June 2008, APL repaid $122.8 million of its outstanding term loan and repaid $120.0 million of outstanding borrowings under the revolving credit facility with proceeds from its issuance of $250.0 million of 10-year 8.75% senior unsecured notes. Additionally, pursuant to this amendment, in June 2008 APL’s lenders increased their commitments for the revolving credit facility by $80.0 million to $380.0 million.
Borrowings under APL’s credit facility are secured by a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by Chaney Dell and Midkiff/Benedum joint ventures and the Laurel Mountain joint venture, and by the guaranty of each of APL’s consolidated subsidiaries other than the joint venture companies. The credit facility contains customary covenants, including restrictions on APL’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement. APL is in compliance with these covenants as of September 30, 2009.

 

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The events which constitute an event of default for the credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against APL in excess of a specified amount and a change of control of APL’s General Partner. The credit facility requires APL to maintain the following ratios:
                         
            Maximum     Minimum  
    Maximum     Senior Secured     Interest  
    Leverage     Leverage     Coverage  
Fiscal quarter ending:   Ratio     Ratio     Ratio  
September 30, 2009
    6.50x       3.75x       2.50x  
December 31, 2009
    8.50x       5.25x       1.70x  
March 31, 2010
    9.25x       5.75x       1.40x  
June 30, 2010
    8.00x       5.00x       1.65x  
September 30, 2010
    7.00x       4.25x       1.90x  
December 31, 2010
    6.00x       3.75x       2.20x  
Thereafter
    5.00x       3.00x       2.75x  
As of September 30, 2009, APL’s leverage ratio was 4.2 to 1.0, its senior secured leverage ratio was 2.5 to 1.0 and its interest coverage ratio was 3.3 to 1.0.
APL Senior Notes
At September 30, 2009, APL had $223.1 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“APL 8.75% Senior Notes”) and $275.5 million principal amount outstanding of 8.125% senior unsecured notes due on December 15, 2015 (“APL 8.125% Senior Notes”; collectively, the “APL Senior Notes”). The APL 8.125% Senior Notes are presented combined with a net $4.0 million of unamortized discount as of September 30, 2009. Interest on the APL Senior Notes in the aggregate is payable semi-annually in arrears on June 15 and December 15. The APL 8.75% Senior Notes are redeemable at any time after June 15, 2013, and the APL 8.125% Senior Notes are redeemable at any time after December 15, 2010 at certain redemption prices, together with accrued and unpaid interest to the date of redemption. Prior to June 15, 2011, APL may redeem up to 35% of the aggregate principal amount of the APL 8.75% Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The APL 8.75% Senior Notes in the aggregate are also subject to repurchase by APL at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if APL does not reinvest the net proceeds within 360 days. The APL 8.75% Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its credit facility.
In January 2009, APL issued Sunlight Capital $15.0 million of its 8.125% Senior Notes to redeem 10,000 APL Class A Preferred Units. Management of APL estimated that the fair value of the $15.0 million 8.125% Senior Notes issued was approximately $10.0 million at the date of issuance based upon the market price of the publicly-traded Senior Notes. As such, APL recognized a $5.0 million discount on the issuance of the Senior Notes, which is presented as a reduction of long-term debt on the Company’s consolidated balance sheets. The discount recognized upon issuance of the Senior Notes will be amortized to interest expense within the Company’s consolidated statements of operations over the term of the 8.125% Senior Notes based upon the effective interest rate method.
Indentures governing the APL Senior Notes in the aggregate contain covenants, including limitations of APL’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. APL is in compliance with these covenants as of September 30, 2009.

 

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NOTE 10 — DERIVATIVE INSTRUMENTS
The Company, AHD and APL use a number of different derivative instruments, principally swaps, collars and options, in connection with its commodity price and interest rate risk management activities. The Company and its subsidiaries enter into financial instruments to hedge its forecasted natural gas, NGLs, crude oil and condensate sales against the variability in expected future cash flows attributable to changes in market prices. Its subsidiaries also enter into financial swap instruments to hedge certain portions of its floating interest rate debt against the variability in market interest rates. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs, crude oil and condensate is sold or interest payments on the underlying debt instrument is due. Under swap agreements, the Company and its subsidiaries receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas, NGLs, crude oil and condensate at a fixed price for the relevant contract period.
The Company and its subsidiaries formally document all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity and interest derivative contracts to the forecasted transactions. The Company and its subsidiaries assess, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Company and its subsidiaries will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by the Company and its subsidiaries through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s consolidated statements of operations. For derivatives qualifying as hedges, the Company and its subsidiaries recognize the effective portion of changes in fair value in stockholders’ equity as accumulated other comprehensive income and reclassifies the portion relating to commodity derivatives to gas and oil production revenues for the Company’s derivatives and gathering, transmission and processing revenues for APL derivatives, and the portion relating to interest rate derivatives to interest expense within the Company’s consolidated statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Company and its subsidiaries recognize changes in fair value within gain (loss) on mark-to-market derivatives in its consolidated statements of operations as they occur.
Derivatives are recorded on the Company’s consolidated balance sheet as assets or liabilities at fair value. The Company reflected net derivative assets on its consolidated balance sheets of $50.9 million and $89.3 million at September 30, 2009 and December 31, 2008, respectively. Of the $50.4 million of net gain in accumulated other comprehensive income within stockholders’ equity on the Company’s consolidated balance sheet at September 30, 2009, if the fair values of the instruments remain at current market values, the Company will reclassify $32.9 million of gains to the Company’s consolidated statements of operations over the next twelve month period as these contracts expire, consisting of $37.1 million of gains to gas and oil production revenues, $2.2 million of losses to gathering, transmission and processing revenues and $2.1 million of losses to interest expense. Aggregate gains of $17.6 million will be reclassified to the Company’s consolidated statements of operations in later periods as these remaining contracts expire, consisting of $20.3 million of gains to gas and oil production revenues, $1.5 million of losses to gathering, transmission and processing revenues and $1.1 million of losses to interest expense. Actual amounts that will be reclassified will vary as a result of future price changes.
The following table summarizes the fair value of the Company’s derivative instruments as of September 30, 2009 and December 31, 2008, as well as the gain or loss recognized in income for effective derivative instruments for the nine months ended September 30, 2009 and 2008. There were no gains or losses recognized in income for ineffective derivative instruments for the nine months ended September 30, 2009 and 2008.

 

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Fair Value of Derivative Instruments:
                                         
    Asset Derivatives     Liability Derivatives  
Derivatives in       Fair Value         Fair Value  
Cash Flow   Balance Sheet   September 30,     December 31,     Balance Sheet   September 30,     December 31,  
Hedging Relationships   Location   2009     2008     Location   2009     2008  
        (in thousands)         (in thousands)  
 
                                       
Commodity contracts:
  Current assets   $ 84,446     $ 107,766     Current liabilities   $ (1,273 )   $ (9,348 )
 
  Long-term assets     40,425       69,451     Long-term liabilities     (23,725 )     (8,410 )
 
                               
 
        124,871       177,217           (24,998 )     (17,758 )
 
                                       
Interest rate contracts:
  Current assets               Current liabilities     (3,832 )     (3,481 )
 
  Long-term assets               Long-term liabilities     (866 )     (2,361 )
 
                               
 
                        (4,698 )     (5,842 )
 
                               
 
                                       
Total derivatives
      $ 124,871     $ 177,217         $ (29,696 )   $ (23,600 )
 
                               
Effects of Derivative Instruments on Consolidated Statements of Operations for the three months and nine months ended September 30, 2009 and 2008 is as follows:
                                     
    Gain/(Loss)     Location of   Gain/(Loss)  
    Recognized in OCI on Derivative     Gain/(Loss)   Reclassified from OCI into Income  
    (Effective Portion)     Reclassified from   (Effective Portion)  
Derivatives in   For the Three Months Ended     Accumulated   For the Three Months Ended  
Cash Flow   September 30,     September 30,     OCI into Income   September 30,     September 30,  
Hedging Relationships   2009     2008     (Effective Portion)   2009     2008  
    (in thousands)         (in thousands)  
 
                                   
Commodity contracts
  $ 5,983     $ 284,075     Gas and oil production   $ 35,134     $ (27,613 )
Interest rate contracts
    (966 )     (1,169 )   Interest expense     (1,083 )     (312 )
 
                           
 
                                   
 
  $ 5,017     $ 282,906         $ 34,051     $ (27,925 )
 
                           
                                     
    Gain/(Loss)     Location of   Gain/(Loss)  
    Recognized in OCI on Derivative     Gain/(Loss)   Reclassified from OCI into Income  
    (Effective Portion)     Reclassified from   (Effective Portion)  
Derivatives in   For the Nine Months Ended     Accumulated   For the Nine Months Ended  
Cash Flow   September 30,     September 30,     OCI into Income   September 30,     September 30,  
Hedging Relationships   2009     2008     (Effective Portion)   2009     2008  
    (in thousands)         (in thousands)  
 
                                   
Commodity contracts
  $ 70,269     $ (26,447 )   Gas and oil production   $ 82,216     $ (25,969 )
Interest rate contracts
    (1,971 )     626     Interest expense     (3,115 )     (335 )
 
                           
 
                                   
 
  $ 68,298     $ (25,821 )       $ 79,101     $ (26,304 )
 
                           
From time to time, the Company enters into natural gas and crude oil future option contracts and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in natural gas prices and oil prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.
In May 2009, the Company received approximately $28.5 million in proceeds from the early termination of natural gas and oil derivative positions for production periods from 2011 through 2013. In conjunction with the early termination of these derivatives, the Company entered into new derivative positions at prevailing prices at the time of the transaction. The net proceeds from the early termination of these derivatives were used to reduce indebtedness under ATN’s credit facility (see Note 9). The gain recognized upon the early termination of these derivative positions will continue to be reported in accumulated other comprehensive income and will be reclassified into the Company’s consolidated statements of operations in the same periods in which the hedged production revenues would have been recognized in earnings.

 

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The Company has a $94.2 million net unrealized gain related to financial derivatives on its gas and oil production which is shown as a component of accumulated other comprehensive income at September 30, 2009, compared to a net unrealized gain of $106.1 million at December 31, 2008. If the fair values of the instruments remain at current market values, the Company will reclassify $60.1 million of unrealized gains to its consolidated statements of operations over the next twelve-month period as these contracts settle and $34.1 million of unrealized gains will be reclassified in later periods.
The Company’s commodity price risk management includes estimated future natural gas and crude oil production of the Partnerships. Therefore, a portion of any unrealized derivative gain or loss is allocable to the limited partners of the Partnerships based on their share of estimated gas and oil production related to the derivatives not yet settled. At September 30, 2009 and December 31, 2008, net unrealized derivative liabilities of $35.1 million and $51.8 million, respectively, are payable to the limited partners in the Partnerships and are included in the consolidated balance sheets.
At September 30, 2009, ATN had $270.0 million of borrowings under its revolving credit facility (see Note 9). At September 30, 2009, the Company had interest rate derivative contracts having an aggregate notional principal amount of $150.0 million through January 2011, which were designated as cash flow hedges. Under the terms of the contract, the Company will pay an interest rate of 3.11%, plus the applicable margin as defined under the terms of its revolving credit facility, and will receive LIBOR, plus the applicable margin, on the notional principal amounts. This derivative effectively converts $150.0 million of ATN’s floating rate debt under the revolving credit facility to fixed-rate debt. The Company has accounted for the interest rate derivative contracts as effective hedge instruments under prevailing accounting standards.
As of September 30, 2009, the Company had the following interest rate and commodity derivatives:
Interest Fixed Rate Swap
                                 
                    Contract        
    Notional             Period Ended     Fair Value  
Term   Amount     Option Type     December 31,     Liability  
                            (in thousands)  
January 2008 - January 2011
  $ 150,000,000     Pay 3.11% - Receive LIBOR       2009     $ (1,009 )
 
                    2010       (3,495 )
 
                    2011       (194 )
 
                             
 
                          $ (4,698 )
 
                             
Natural Gas Fixed Price Swaps
                         
Production                    
Period Ending           Average     Fair Value  
December 31,   Volumes     Fixed Price     Asset (2)  
    (MMBtu) (1)     (per MMBtu) (1)     (in thousands)  
2009
    10,340,000     $ 8.242     $ 36,116  
2010
    31,880,000     $ 7.708       47,682  
2011
    20,720,000     $ 7.040       3,403  
2012
    19,680,000     $ 7.223       4,119  
2013
    13,260,000     $ 7.082       235  
 
                     
 
                  $ 91,555  
 
                     

 

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Natural Gas Costless Collars
                             
Production                        
Period Ending               Average     Fair Value  
December 31,   Option Type   Volumes     Floor and Cap     Asset/(Liability) (1)  
        (MMBtu) (1)     (per MMBtu) (1)     (in thousands)  
2009
  Puts purchased     60,000     $ 11.000     $ 370  
2009
  Calls sold     60,000     $ 15.350        
2010
  Puts purchased     3,360,000     $ 7.839       6,021  
2010
  Calls sold     3,360,000     $ 9.007        
2011
  Puts purchased     9,540,000     $ 6.523       808  
2011
  Calls sold     9,540,000     $ 7.666        
2012
  Puts purchased     4,020,000     $ 6.514        
2012
  Calls sold     4,020,000     $ 7.718       (249 )
2013
  Puts purchased     5,340,000     $ 6.516        
2013
  Calls sold     5,340,000     $ 7.811       (579 )
 
                         
 
                      $ 6,371  
 
                         
Crude Oil Fixed Price Swaps
                         
Production                    
Period Ending           Average     Fair Value  
December 31,   Volumes     Fixed Price     Asset/(Liability) (3)  
    (Bbl) (1)     (per Bbl) (1)     (in thousands)  
2009
    14,600     $ 99.319     $ 424  
2010
    48,900     $ 97.400       1,134  
2011
    42,600     $ 77.460       11  
2012
    33,500     $ 76.855       (74 )
2013
    10,000     $ 77.360       (29 )
 
                     
 
                  $ 1,466  
 
                     
Crude Oil Costless Collars
                             
Production                        
Period Ending               Average     Fair Value  
December 31,   Option Type   Volumes     Floor and Cap     Asset/(Liability) (3)  
        (Bbl) (1)     (per Bbl) (1)     (in thousands)  
2009
  Puts purchased     9,000     $ 85.000     $ 134  
2009
  Calls sold     9,000     $ 116.561        
2010
  Puts purchased     31,000     $ 85.000       468  
2010
  Calls sold     31,000     $ 112.918        
2011
  Puts purchased     27,000     $ 67.223        
2011
  Calls sold     27,000     $ 89.436       (27 )
2012
  Puts purchased     21,500     $ 65.506        
2012
  Calls sold     21,500     $ 91.448       (70 )
2013
  Puts purchased     6,000     $ 65.358        
2013
  Calls sold     6,000     $ 93.442       (24 )
 
                         
 
                      $ 481  
 
                         
 
              Total ATN asset     $ 95,175  
 
                         
 
     
(1)  
“Mmbtu” represents million British Thermal Units; “Bbl” represents barrels.
 
(2)  
Fair value based on forward NYMEX natural gas prices, as applicable.
 
(3)  
Fair value based on forward WTI crude oil prices, as applicable.

 

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Atlas Pipeline Holdings and Atlas Pipeline Partners
Beginning July 1, 2008, APL discontinued hedge accounting for its existing commodity derivatives which were qualified as hedges under prevailing accounting literature. As such, subsequent changes in fair value of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s consolidated statements of operations. The fair value of these commodity derivative instruments at June 30, 2008, which was recognized in accumulated other comprehensive income within stockholders’ equity on the Company’s consolidated balance sheet, will be reclassified to the Company’s consolidated statements of operations in the future at the time the originally hedged physical transactions affect earnings.
During the nine months ended September 30, 2009 and year ended December 31, 2008, APL made net payments of $5.0 million and $274.0 million, respectively, related to the early termination of derivative contracts. Substantially all of these derivative contracts were put into place simultaneously with the APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 and related to production periods ranging from the end of the second quarter of 2008 through the fourth quarter of 2009. During the three and nine months ended September 30, 2009 and 2008, the Company recognized the following derivative activity related to the termination of these derivative instruments within its consolidated statements of operations (amounts in thousands):
                                 
    Early Termination of Derivative Contracts  
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Net cash derivative expense included within gain (loss) on mark-to-market derivatives
  $     $ (70,258 )   $ (5,000 )   $ (186,068 )
Net cash derivative expense included within transmission, gathering and processing revenue
          (1,258 )           (1,573 )
Net non-cash derivative income (expense) included within gain (loss) on mark-to-market derivatives
    15,488       6,488       34,708       (39,857 )
Net non-cash derivative expense included within transmission, gathering and processing revenue
    (19,976 )     (19,514 )     (54,043 )     (19,514 )
At September 30, 2009, AHD had an interest rate derivative contract having an aggregate notional principal amount of $25.0 million. Under the terms of the agreement, AHD will pay an interest rate of 3.01%, plus the applicable margin as defined under the terms of its revolving credit facility (see Note 9), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. The interest rate swap agreement is effective at September 30, 2009 and expires on May 28, 2010. In June 2009, AHD repaid a portion of its borrowings under the credit facility, with a resulting balance of $12.0 million outstanding under the credit facility at September 30, 2009. In addition, in accordance with the June 2009 amendment to its credit facility (see Note 9), AHD is prohibited from borrowing additional amounts under its credit facility once the amounts have been repaid. In accordance with prevailing accounting literature, the portion of any gain or loss in other comprehensive income related to forecasted hedge transactions that are no longer expected to occur are to be removed from other comprehensive income and recognized within the Company’s statements of operations. As a result of this reduction in borrowings under the credit facility below the notional amount of the interest rate derivative contract, the Company recognized an expense of $0.1 million and $0.3 million within gain (loss) on mark-to-market derivatives in its consolidated statements of operations for the three and nine months ended September 30, 2009, respectively.

 

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At September 30, 2009, APL had interest rate derivative contracts having aggregate notional principal amounts of $450.0 million. Under the terms of these agreements, APL will pay weighted average interest rates of 3.02%, plus the applicable margin as defined under the terms of its credit facility (see Note 9), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. The APL interest rate swap agreements were in effect as of September 30, 2009 and expire during periods ranging from January 30, 2010 through April 30, 2010. Beginning May 29, 2009, APL discontinued hedge accounting for its interest rate derivatives which were qualified as hedges under prevailing accounting literature. As such, subsequent changes in fair value of these derivatives will be recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s consolidated statements of operations. The fair value of these derivative instruments at May 29, 2009, which was recognized within accumulated other comprehensive income within stockholders’ equity on the Company’s consolidated balance sheet, will be reclassified to the Company’s consolidated statements of operations in the future at the time the originally hedged physical transactions affect earnings.
The following table summarizes AHD and APL’s derivative activity, including the early termination of derivative contracts disclosed above, for the periods indicated (amounts in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
 
                               
Loss from cash settlement and non-cash recognition of qualifying hedge instruments(1)
  $ (9,779 )   $ (27,419 )   $ (37,281 )   $ (78,214 )
Gain (loss) from change in market value of non- qualifying derivatives(2)
    12,021       190,013       (30,460 )     (17,919 )
Gain (loss) from change in market value of ineffective portion of qualifying derivatives(2)
          44,997       10,813       41,271  
Gain (loss) from cash settlement and non-cash recognition of non-qualifying derivatives(2)
    (10,321 )     (84,207 )     3,500       (280,696 )
Loss from cash settlement of interest rate derivatives(3)
    (3,164 )     (708 )     (9,343 )     (915 )
Loss from change in market value of non-qualifying interest rate derivatives(2)
    (861 )           (891 )      
Loss from reclassification of loss from Other Comprehensive Income to Other Loss(2)
    (60 )           (256 )      
 
     
(1)  
Included within transmission, gathering and processing revenue on the Company’s consolidated statements of operations.
 
(2)  
Included within gain (loss) on mark-to-market derivatives on the Company’s consolidated statements of operations.
 
(3)  
Included within interest expense on the Company’s consolidated statements of operations.
The following table summarizes AHD’s and APL’s gross fair values of cumulative derivative instruments for the period indicated (amounts in thousands):
                         
    September 30, 2009  
    Asset Derivatives     Liability Derivatives  
    Balance Sheet           Balance Sheet      
    Location   Fair Value     Location   Fair Value  
Derivatives not designated as hedging instruments:
                       
Interest rate contracts
  N/A   $     Current portion of derivative liability   $ (6,352 )
Commodity contracts
  Current portion of derivative asset     4,514              
Commodity contracts
  Long-term derivative asset     1,980              
Commodity contracts
  Current portion of derivative liability     10,050     Current portion of derivative liability     (45,162 )
Commodity contracts
  Long-term derivative liability     3,341     Long-term derivative liability     (12,597 )
 
                   
 
      $ 19,885         $ (64,111 )
 
                   

 

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The following table summarizes the gross effect of AHD’s and APL’s derivative instruments on the Company’s consolidated statement of operations for the period indicated (amounts in thousands):
                                 
    Derivatives not designated as hedging instruments
    Three months ended September 30, 2009
    Gain (Loss)     Gain (Loss) Reclassified from   Gain (Loss) Recognized in Income
    Recognized in     Accumulated OCI into Income   (Ineffective Portion and Amount
    Accumulated     (Effective Portion)   Excluded from Effectiveness Testing)
    OCI     Amount     Location   Amount     Location
Interest rate contracts(1)
  $ 30     $ (3,419 )   Interest expense   $ (951 )   Gain (loss) on mark-to-market derivatives
Commodity contracts(1)
          (10,294 )   Transmission, gathering and processing revenue     (13,671 )   Gain (loss) on mark-to-market derivatives
Commodity contracts(2)
              N/A     16,036     Gain (loss) on mark-to-market derivatives
 
                         
 
  $ 30     $ (13,713 )       $ 1,414      
 
                         
 
     
(1)  
Hedges previously designated as cash flow hedges.
 
(2)  
Dedesignated cash flow hedges and non-designated hedges.
                                 
    Derivatives not designated as hedging instruments
    Nine months ended September 30, 2009
    Gain (Loss)     Gain (Loss) Reclassified from   Gain (Loss) Recognized in Income
    Recognized in     Accumulated OCI into Income   (Ineffective Portion and Amount
    Accumulated     (Effective Portion)   Excluded from Effectiveness Testing)
    OCI     Amount     Location   Amount     Location
Interest rate contracts(1)
  $ (2,411 )   $ (9,599 )   Interest expense   $ (1,147 )   Gain (loss) on mark-to-market derivatives
Commodity contracts(1)
          (37,158 )   Transmission, gathering and processing revenue     (36,579 )   Gain (loss) on mark-to-market derivatives
Commodity contracts(2)
              N/A     20,155     Gain (loss) on mark-to-market derivatives
 
                         
 
  $ (2,411 )   $ (46,757 )       $ (17,571 )    
 
                         

 

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(1)  
Hedges previously designated as cash flow hedges.
 
(2)  
Dedesignated cash flow hedges and non-designated hedges.
As of September 30, 2009, AHD had the following interest rate derivatives, including derivatives that do not qualify for hedge accounting:
Interest Fixed-Rate Swap
                                 
    Notional             Contract Period     Fair Value  
Term   Amount     Type     Ended December 31,     Liability(1)  
                            (in thousands)  
May 2008 - May 2010
  $ 25,000,000     Pay 3.01% — Receive LIBOR       2009     $ (174 )
 
                    2010       (271 )
 
                             
 
                  Total AHD net liability   $ (445 )
 
                             
 
     
(1)  
Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace.
As of September 30, 2009, APL had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:
Interest Fixed-Rate Swap
                                 
    Notional             Contract Period     Fair Value  
Term   Amount     Type     Ended December 31,     Liability(1)  
                            (in thousands)  
January 2008 - January 2010
  $ 200,000,000     Pay 2.88% — Receive LIBOR       2009     $ (1,335 )
 
                    2010       (426 )
 
                             
 
                          $ (1,761 )
 
                             
 
                               
April 2008 - April 2010
  $ 250,000,000     Pay 3.14% — Receive LIBOR       2009     $ (1,832 )
 
                    2010       (2,314 )
 
                             
 
                          $ (4,146 )
 
                             
Natural Gas Sales — Fixed Price Swaps
                         
Production Period           Average     Fair Value  
Ended December 31,   Volumes     Fixed Price     Asset (3)  
    (mmbtu)(6)     (per mmbtu)(6)     (in thousands)  
2009
    120,000     $ 8.000     $ 390  
 
                     
Natural Gas Basis Sales
                         
Production Period           Average     Fair Value  
Ended December 31,   Volumes     Fixed Price     Liability(3)  
    (mmbtu)(6)     (per mmbtu)(6)     (in thousands)  
2009
    1,230,000     $ (0.558 )   $ (386 )
2010
    2,220,000     $ (0.607 )     (401 )
 
                     
 
                  $ (787 )
 
                     

 

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Natural Gas Purchases — Fixed Price Swaps
                         
Production Period           Average     Fair Value  
Ended December 31,   Volumes     Fixed Price     Liability (3)  
    (mmbtu)(6)     (per mmbtu)(6)     (in thousands)  
2009
    2,580,000     $ 8.687   $ (10,162 )
2010
    4,380,000     $ 8.635     (11,718 )
 
                     
 
                  $ (21,880 )
 
                     
Natural Gas Basis Purchases
                         
Production Period           Average     Fair Value  
Ended December 31,   Volumes     Fixed Price     Asset(3)  
    (mmbtu)(6)     (per mmbtu)(6)     (in thousands)  
2009
    3,690,000     $ (0.659 )   $ 1,508  
2010
    6,600,000     $ (0.590 )     1,193  
 
                     
 
                  $ 2,701  
 
                     
Natural Gas Liquids — Fixed Price Swap
                         
Production Period           Average     Fair Value  
Ended December 31,   Volumes     Fixed Price     Liability(2)  
    (gallons)     (per gallon)     (in thousands)  
2009
    5,544,000     $ 0.754     $ (762 )
 
                     
Ethane Put Options
                                 
    Associated                    
Production Period   NGL     Average     Fair Value        
Ended December 31,   Volume     Price(4)     Liability(1)     Option Type  
    (gallons)     (per gallon)     (in thousands)          
 
2009
    630,000     $ 0.340     $ (57 )   Puts purchased
 
                             
Propane Put Options
                                 
    Associated                    
Production Period   NGL     Average     Fair Value        
Ended December 31,   Volume     Price(4)     Asset(1)     Option Type  
    (gallons)     (per gallon)     (in thousands)          
 
2009
    15,246,000     $ 0.820     $ 579     Puts purchased
 
                             
Isobutane Put Options
                                 
    Associated                    
Production Period   NGL     Average     Fair Value        
Ended December 31,   Volume     Price(4)     Liability(1)     Option Type  
    (gallons)     (per gallon)     (in thousands)          
 
2009
    126,000     $ 0.589     $ (20 )   Puts purchased
 
                             
Normal Butane Put Options
                                 
    Associated                    
Production Period   NGL     Average     Fair Value        
Ended December 31,   Volume     Price(4)     Asset(1)     Option Type  
    (gallons)     (per gallon)     (in thousands)          
 
2009
    3,654,000     $ 0.943     $ 98     Puts purchased
2010
    3,654,000     $ 1.038     $ 544     Puts purchased
 
                             
 
                  $ 642          
 
                             

 

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Natural Gasoline Put Options
                                 
    Associated                    
Production Period   NGL     Average     Fair Value        
Ended December 31,   Volume     Price(4)     Asset(1)     Option Type  
    (gallons)     (per gallon)     (in thousands)          
 
2009
    3,906,000     $ 1.341     $ 549     Puts purchased
2010
    3,906,000     $ 1.345     $ 902     Puts purchased
 
                             
 
                  $ 1,451          
 
                             
Crude Oil Sales Options (associated with NGL volume)
                                     
            Associated     Average            
Production Period   Crude     NGL     Crude     Fair Value      
Ended December 31,   Volume     Volume     Price (4)     Asset/(Liability)(3)     Option Type
    (barrels)     (gallons)     (per barrel)     (in thousands)      
 
2009
    165,000       9,321,900     $ 63.53     $ 856     Puts purchased
2009
    527,700       29,874,978     $ 84.80       (647 )   Calls sold
2010
    486,000       27,356,700     $ 61.24       4,111     Puts purchased
2010
    3,127,500       213,088,050     $ 86.20       (20,462 )   Calls sold
2010
    714,000       45,415,440     $ 132.17       705     Calls purchased(5)
2011
    606,000       33,145,560     $ 100.70       (4,517 )   Calls sold
2011
    252,000       13,547,520     $ 133.16       920     Calls purchased(5)
2012
    450,000       25,893,000     $ 102.71       (4,038 )   Calls sold
2012
    180,000       9,676,800     $ 134.27       919     Calls purchased(5)
 
                                 
 
                          $ (22,153 )    
 
                                 
Crude Oil Sales
                         
Production Period           Average     Fair Value  
Ended December 31,   Volumes     Fixed Price     Liability(3)  
    (barrels)     (per barrel)     (in thousands)  
2009
    6,000     $ 62.700     $ (48 )
 
                     
Crude Oil Sales Options
                                 
Production Period           Average     Fair Value        
Ended December 31,   Volumes     Crude Price(4)     Asset/(Liability)(3)     Option Type  
    (barrels)     (per barrel)     (in thousands)        
2009
    117,000     $ 64.151     $ 604     Puts purchased
2009
    76,500     $ 84.956       (116 )   Calls sold
2010
    411,000     $ 64.732       4,450     Puts purchased
2010
    234,000     $ 88.088       (1,475 )   Calls sold
2011
    72,000     $ 93.109       (746 )   Calls sold
2012
    48,000     $ 90.314       (648 )   Calls sold
 
                             
 
                  $ 2,069          
 
                             
 
                               
 
          Total net APL liability     $ (43,782 )        
 
          Total net AHD liability       (445 )        
 
          Total net Company asset       95,175          
 
                             
 
          Total consolidated net asset     $ 50,948          
 
                             

 

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(1)  
Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace.
 
(2)  
Fair value based upon management estimates, including forecasted forward NGL prices.
 
(3)  
Fair value based on forward NYMEX natural gas and light crude prices, as applicable.
 
(4)  
Average price of options based upon average strike price adjusted by average premium paid or received.
 
(5)  
Calls purchased for 2010 through 2012 represent offsetting positions for calls sold. These offsetting positions were entered into by APL to limit the loss which could be incurred if crude oil prices continued to rise.
 
(6)  
Mmbtu represents million British Thermal Units.
The fair value of the derivatives included in the Company’s consolidated balance sheets is as follows (in thousands):
                 
    September 30,     December 31,  
    2009     2008  
Current portion of derivative asset
  $ 88,960     $ 152,727  
Long-term derivative asset
    42,405       69,451  
Current portion of derivative liability
    (46,570 )     (73,776 )
Long-term derivative liability
    (33,847 )     (59,103 )
 
           
Total Company net asset
  $ 50,948     $ 89,299  
 
           
NOTE 11 — FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:
  Level 1 —  
Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.
  Level 2 —  
Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.
  Level 3 —  
Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Company uses a fair value methodology to value the assets and liabilities for its, AHD’s and APL’s outstanding derivative contracts (see Note 10) and the Company’s Supplemental Employment Retirement Plan (“SERP” — see Note 17). The Company’s and APL’s commodity hedges, with the exception of APL’s NGL fixed price swaps and NGL options, are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. The Company’s, AHD’s and APL’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model and are therefore defined as Level 2 fair value measurements. The Company’s SERP is calculated based on observable actuarial inputs developed by a third-party actuary and therefore is defined as a Level 2 fair value measurement, while the asset related to the funding of the SERP is based on third-party financial statements and is therefore also defined as a Level 2 fair value measurement. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGL’s for similar locations, and therefore are defined as Level 3 fair value measurements. Valuations for APL’s NGL options are based on forward price curves developed by the related financial institution, and therefore are defined as Level 3 fair value measurements.

 

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On June 30, 2009, APL changed the basis for its valuation of crude oil options. Previously, APL utilized forward price curves developed by its derivative counterparties. Effective June 30, 2009, APL utilized crude oil option prices quoted from a public commodity exchange. With this change in valuation basis, APL reclassified the inputs for the valuation of its crude oil options from a Level 3 input to a Level 2 input. The change in valuation basis did not materially impact the fair value of its derivative instruments on its consolidated statements of operations.
The following table represents the Company’s assets and liabilities recorded at fair value as of September 30, 2009 (in thousands):
                                 
    Level 1     Level 2     Level 3     Total  
SERP liability
  $     $ (3,587 )   $     $ (3,587 )
SERP asset funded in rabbi trust
          3,655             3,655  
ATN commodity-based derivatives
          99,873             99,873  
APL commodity-based derivatives
          (39,708 )     1,834       (37,874 )
Interest rate derivatives
          (11,051 )           (11,051 )
 
                       
Total
  $     $ 49,182     $ 1,834     $ 51,016  
 
                       
APL’s Level 3 fair value amount relates to its derivative contracts on NGL fixed price swaps and crude oil options. The following table provides a summary of changes in fair value of APL’s Level 3 derivative instruments as of September 30, 2009 (in thousands):
                                 
    NGL                    
    Fixed                    
    Price     NGL Sales     Crude Oil        
    Swaps     Options     Options     Total  
Balance — December 31, 2008
  $ 1,509     $ 12,316     $ (23,436 )   $ (9,611 )
New options contracts
          (2,896 )           (2,896 )
Cash settlements from unrealized gain (loss)(1)
    (5,459 )     (9,866 )     (37,671 )     (52,996 )
Cash settlements from other comprehensive income(1)
    5,453             11,618       17,071  
Net change in unrealized gain (loss)(2)
    (2,265 )     (1,084 )     14,886       11,537  
Deferred option premium recognition
          4,126       2,239       6,365  
Net change in other comprehensive loss
                       
Transfer to Level 2
                32,364       32,364  
 
                       
Balance — September 30, 2009
  $ (762 )   $ 2,596     $     $ 1,834  
 
                       
 
     
(1)  
Included within transmission, gathering and processing revenue on the Company’s consolidated statements of operations.
 
(2)  
Included within loss on mark-to-market derivatives on the Company’s consolidated statements of operations.
Other Financial Instruments
The estimated fair value of the Company’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Company could realize upon the sale or refinancing of such financial instruments.

 

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The Company’s other current assets and liabilities on its consolidated balance sheets are financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature. The estimated fair values of the Company’s debt at September 30, 2009 and December 31, 2008, which consists principally of APL’s term loan, ATN and APL’s Senior Notes and borrowings under the ATN’s, AHD’s and APL’s credit facilities, were $2,047.9 million and $1,911.4 million, respectively, compared with the carrying amounts of $2,127.5 million and $2,413.1 million, respectively. The Senior Notes were valued based upon recent trading activity. The carrying value of outstanding borrowings under the credit facilities, which bear interest at a variable interest rate, approximates their estimated fair value.
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
The Company estimates the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements; the credit-adjusted risk-free rate of the Company; and estimated inflation rates (see Note 8).
Information for assets that are measured at fair value on a nonrecurring basis for the three and nine months ended September 30, 2009 is as follows (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30, 2009     September 30, 2009  
    Level 3     Total     Level 3     Total  
Asset retirement obligations
  $ 125     $ 125     $ 721     $ 721  
 
                       
Total
  $ 125     $ 125     $ 721     $ 721  
 
                       
NOTE 12 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
In the ordinary course of its business operations, the Company has ongoing relationships with several related entities:
Relationship with the Company’s Sponsored Investment Partnerships. The Company conducts certain activities through, and a substantial portion of its revenues are attributable to, the Partnerships. The Company serves as general partner of the Partnerships and assumes customary rights and obligations for the Partnerships. As the general partner, the Company is liable for the Partnerships’ liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Partnerships. The Company is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Partnerships’ revenue, and costs and expenses according to the respective Partnership agreements.
Relationship with Resource America, Inc. The Company has two agreements that govern its ongoing relationship with Resource America, Inc. (“RAI”), its former parent, that are still in effect at September 30, 2009. These agreements are the tax matters agreement and the transition services agreement. The tax matters agreement governs the respective rights, responsibilities and obligations of the Company and RAI with respect to tax liabilities and benefits, tax attributes, tax contests and other matters regarding income taxes, non-income taxes and related tax matters. The transition services agreement governs the provision of support services by the Company to RAI and by RAI to the Company, such general and administrative functions. The Company reimburses RAI for various costs and expenses it incurs for these services on behalf of the Company, primarily payroll and rent. For the three months ended September 30, 2009 and 2008, the Company’s reimbursements to RAI totaled $0.3 million and $0.3 million, respectively, and $0.8 million and $0.7 million for the nine months ended September 30, 2009 and 2008, respectively. At September 30, 2009 and December 31, 2008, reimbursements to RAI totaling $0.2 million and $0.1 million, respectively, which remain to be settled between the parties, were reflected in the Company’s consolidated balance sheets as advances to/from affiliate.

 

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Relationship with Laurel Mountain. Upon completion of the transaction with Laurel Mountain, the Company entered into new gas gathering agreements with Laurel Mountain which superseded the existing master natural gas gathering agreement and omnibus agreement between the Company and APL. Under the new gas gathering agreements, the Company is obligated to pay Laurel Mountain all of the gathering fees it collects from the Partnerships, which generally ranges from $0.35 per Mcf to the amount of the competitive gathering fee (which is currently defined as 13% of the gross sales price received for the partnerships gas) plus any excess amount of the gathering fees collected up to an amount equal to approximately 16% of the natural gas sales price. The new gathering agreements contain additional provisions which define certain obligations and options of each party to build and connect newly drilled wells to any Laurel Mountain gathering system.
NOTE 13 — COMMITMENTS AND CONTINGENCIES
General Commitments
The Company is the managing general partner of the Partnerships, and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Partnership assets. Subject to certain conditions, investor partners in certain Partnerships have the right to present their interests for purchase by the Company, as managing general partner. The Company is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on past experience, the management of the Company believes that any liability incurred would not be material. The Company may be required to subordinate a part of its net partnership revenues from the Partnerships to the benefit of the investor partners for an amount equal to at least 10% of their subscriptions, determined on a cumulative basis, in accordance with the terms of the partnership agreements. For the three and nine months ended September 30, 2009, $1.4 million and $2.3 million, respectively, of the Company’s net revenues were subordinated, which reduced its cash distributions received from the investment partnerships for the respective periods. No subordination of the Company’s net revenues was required for the three and nine months ended September 30, 2008 with regard to the Partnerships.
The Company is party to employment agreements with certain executives that provide compensation and certain other benefits. The agreements also provide for severance payments under certain circumstances.
As of September 30, 2009, the Company and its subsidiaries are committed to expend approximately $17.8 million on pipeline extensions, compressor station upgrades, and processing facility upgrades.
Legal Proceedings
The Company is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Company’s financial condition or results of operations.
Following the announcement of the merger agreement on April 27, 2009 between the Company and Atlas Energy Resources, the following actions were filed in Delaware Chancery Court purporting to challenge the Merger:
   
Alonzo v. Atlas Energy Resources, LLC, et al., C.A. No. 4553-VCN (Del. Ch. filed 4/30/09);
 
   
Operating Engineers Constructions Industry and Miscellaneous Pension Fund v. Atlas America, Inc., et al., C.A. No. 4589-VCN (Del. Ch. filed 5/13/09);

 

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Vanderpool v. Atlas Energy Resources, LLC, et al., C.A. No. 4604-VCN (Del. Ch. filed 5/15/09);
 
   
Farrell v. Cohen, et al., C.A. No. 4607-VCN (Del. Ch. filed 5/19/09); and
 
   
Montgomery County Employees’ Retirement Fund v. Atlas Energy Resources, L.L.C., et al., C.A. No. 4613-VCN (Del. Ch. filed 5/21/09).
On June 15, 2009, Vice Chancellor Noble issued an order consolidating all five lawsuits, renaming the action In re Atlas Energy Resources, LLC Unitholder Litigation, C.A. No. 4589-VCN, and appointing as co-lead plaintiffs Operating Engineers Construction Industry and Miscellaneous Pension Fund and Montgomery County Employees Retirement Fund. Plaintiffs filed a Verified Consolidated Class Action Complaint on July 1, 2009, which has superseded all prior complaints. On July 27, 2009, the Chancery Court granted the parties’ scheduling stipulation, setting a preliminary injunction hearing for September 4, 2009. The complaint advances claims of breach of fiduciary duty in connection with the Merger agreement, including allegations of inadequate disclosures in connection with the unitholder vote on the Merger, and seeks monetary damages or injunctive relief, or both. On August 7, 2009, plaintiffs advised the court by letter that they are not pursuing their motion for preliminary injunction and requested that the preliminary injunction hearing date be removed from the court’s calendar. Around that time, plaintiffs advised counsel for the defendants that they intended to continue to pursue the case after the Merger as a claim for monetary damages. The Chancery Court approved the briefing schedule in mid-September and the defendants filed a brief in support of their motion to dismiss on October 16, 2009. Predicting the outcome of this lawsuit is difficult. An adverse judgment for monetary damages could have a material adverse effect on the operations of the combined company. Based on the facts known to date, the defendants believe that the claims asserted against them in this lawsuit are without merit, and intend to defend themselves vigorously against the claims.
In June 2008, the Company’s wholly-owned subsidiary, Atlas America, LLC, was named as a co-defendant in the matter captioned CNX Gas Company, LLC (“CNX”) v. Miller Petroleum, Inc. (“Miller”), et al. (Chancery Court, Campbell County, Tennessee). In its complaint, CNX alleges that Miller breached a contract to assign to CNX certain leasehold rights (“Leases”) representing approximately 30,000 acres in Campbell County, Tennessee and that Atlas America, LLC and another defendant, Wind City Oil & Gas, LLC, interfered with the closing of this assignment on June 6, 2008. ATN purchased the Leases from Miller for approximately $19.1 million. On December 15, 2008, the Chancery Court dismissed the matter in its entirety, holding that there had been no breach of the contract by Miller and, therefore, that Atlas America, LLC could not have tortuously interfered with the contract. The Chancery Court dismissed all claims against Atlas America, LLC; however, CNX has appealed this decision.
NOTE 14 — INCOME TAXES
The Company accounts for income taxes under the asset and liability method pursuant to prevailing accounting literature. Under such literature, deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value. As of September 30, 2009 and December 31, 2008, the Company determined that no valuation allowance was necessary. In conjunction with the Merger, the Company recognized a reduction of its deferred tax liability of $179.4 million, related to book and tax basis differences in the Company’s investment in ATN.

 

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The Company recognizes the financial statement benefit of a tax position after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting a more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. The Company had applied this methodology to all tax positions for which the statute of limitation remains open, and there were no additions, reductions or settlements in unrecognized tax benefits during the three and nine months ended September 30, 2009 and 2008. The Company has no material uncertain tax positions at September 30, 2009.
The Company is subject to income taxes in the U.S. federal jurisdiction and various states. Tax regulations within each jurisdiction are subject to the interpretations of the related tax laws and regulations and require significant judgment to apply. With few exceptions, the Company is no longer subject to U.S. federal, state, and local, or non-U.S. income tax examinations by tax authorities for the years before 2005. The Company’s policy is to reflect interest and penalties related to uncertain tax positions as part of the income tax expense, when and if they become applicable.
NOTE 15 — ISSUANCES OF SUBSIDIARY UNITS
The Company recognizes gains on its subsidiaries’ equity transactions as a credit to equity rather than as income. These gains represent the Company’s portion of the excess net offering price per unit of each of its subsidiary’s units to the book carrying amount per unit.
In August 2009, APL sold 2,689,765 common units in a private placement at an offering price of $6.35 per unit, yielding net proceeds of approximately $16.1 million. APL also received a capital contribution from AHD of $0.4 million for AHD to maintain its 2.0% general partner interest in the APL. In addition, APL issued warrants granting investors in its private placement the right to purchase an additional 2,689,765 common units at a price of $6.35 per unit for a period of two years following the issuance of the original common units. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan (see Note 9), and will make similar repayments with net proceeds from future exercises of the warrants.
The common units and warrants sold by APL in the August 2009 private placement are subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement required APL to (a) file a registration statement with the Securities and Exchange Commission for the privately placed common units and those underlying the warrants by September 21, 2009 and (b) cause the registration statement to be declared effective by the Securities and Exchange Commission by November 18, 2009. APL filed a registration statement with the Securities and Exchange Commission in satisfaction of the registration requirements of the registration rights agreement on September 3, 2009, and the registration statement was declared effective on October 14, 2009.
In June 2008, APL sold 5,750,000 common limited partner units in a public offering at a price of $37.52 per unit, yielding net proceeds of approximately $206.6 million. Also in June 2008, the Company purchased 308,109 AHD common units and 1,112,000 APL common limited partner units through a private placement transaction at a price of $32.50 and $36.02 per unit, respectively, for net proceeds of approximately $10.0 million and $40.1 million, respectively. AHD utilized the net proceeds from the sale to purchase 278,000 common units of APL, which in turn utilized the proceeds to partially fund the early termination of certain derivative agreements (see Note 10).
In May 2008, ATN sold 2,070,000 of its Class B common units in a public offering yielding net proceeds of approximately $82.5 million. The net proceeds were used to repay a portion of ATN’s outstanding balance under its revolving credit facility. A gain of $17.7 million, net of an income tax provision of $8.7 million, in accordance with prevailing accounting literature was recorded in consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $26.4 million to non-controlling interest, during the year ended December 31, 2008.

 

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NOTE 16 — CASH DISTRIBUTIONS
Prior to the Merger, ATN was required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its limited liability company agreement) for that quarter to its Class A and Class B common unitholders in accordance with their respective percentage interests. Effective April 1, 2009, ATN suspended further distributions due to the announcement of its intent to merge with the Company (see Note 3).
Atlas Pipeline Partners Cash Distributions. APL is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders and AHD, as general partner. If APL’s common unit distributions in any quarter exceed specified target levels, AHD will receive between 15% and 50% of such distributions in excess of the specified target levels. Common unit and General Partner distributions declared by APL for the period from January 1, 2008 through September 30, 2009 were as follows (in thousands, except per unit amounts):
                             
        APL Cash     Total APL Cash     Total APL Cash  
        Distribution     Distribution     Distribution  
Date Cash       per Common     to Common     to the  
Distribution   For Quarter   Limited     Limited     General  
Paid   Ended   Partner Unit     Partners     Partner  
February 14, 2008
  December 31, 2007   $ 0.93     $ 36,051     $ 5,092  
 
                           
May 15, 2008
  March 31, 2008   $ 0.94     $ 36,450     $ 7,891  
August 14, 2008
  June 30, 2008   $ 0.96     $ 44,096     $ 9,308  
November 14, 2008
  September 30, 2008   $ 0.96     $ 44,105     $ 9,312  
February 13, 2009
  December 31, 2008   $ 0.38     $ 17,463     $ 2,545  
 
                           
May 13, 2009
  March 31, 2009   $ 0.15     $ 7,147     $ 1,010  
APL did not declare a cash distribution for the quarters ended September 30, 2009 and June 30, 2009. On May 29, 2009, APL entered into an amendment to its senior secured credit facility (see Note 9), which, among other things, requires that it pay no cash distributions during the remainder of the year ended December 31, 2009 and allows it to pay cash distributions beginning January 1, 2010 if its senior secured leverage ratio is above certain thresholds and it has minimum liquidity (both as defined in the credit agreement) of at least $50.0 million.
In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems, AHD, which holds all of the incentive distribution rights in APL, agreed to allocate up to $3.75 million of its incentive distribution rights per quarter back to APL. AHD also agreed that the resulting allocation of incentive distribution rights back to APL would be after AHD receives the initial $7.0 million per quarter of incentive distribution rights.

 

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Atlas Pipeline Holdings Cash Distributions. AHD has a cash distribution policy under which it distributes, within 50 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders. Distributions declared by AHD for the period from January 1, 2008 through September 30, 2009 were as follows (in thousands except per unit amounts):
                     
                Total Cash  
Date Cash       Cash Distribution per     Distribution to the  
Distribution Paid or   For Quarter   Common Limited     Company  
Payable   Ended   Partner Unit     (in thousands)  
February 19, 2008
  December 31, 2007   $ 0.34     $ 5,950  
 
                   
May 20, 2008
  March 31, 2008   $ 0.43     $ 7,525  
August 19, 2008
  June 30, 2008   $ 0.51     $ 9,082  
November 19, 2008
  September 30, 2008   $ 0.51     $ 9,082  
February 19, 2009
  December 31, 2008   $ 0.06     $ 1,068  
There was no distribution declared by AHD for the quarters ended September 30, 2009, June 30, 2009 and March 31, 2009. On June 1, 2009, AHD entered into an amendment to its credit facility agreement, which, among other changes, prohibited it from paying any cash distributions on its equity while the credit facility is in effect (see Note 9).
NOTE 17 — BENEFIT PLANS
Incentive Bonus Plan
The Company’s shareholders approved an Incentive Bonus Plan (“Bonus Plan”) for the benefit of its senior executive officers. The total amount of cash bonus awards to be made under the Bonus Plan for any plan year will be based on performance goals related to objective business criteria for such year. For any plan year, the Company’s performance must achieve levels targeted by the Company’s compensation committee, as established at the beginning of each year, for any bonus awards to be made. Aggregate bonus awards to all participants under the Bonus Plan may not exceed a limit as set by the compensation committee. The compensation committee has the authority to reduce the total amount of bonus awards, if any, to be made to the eligible employees for any plan year based on its assessment of personal performance or other factors as the Board may determine to be relevant or appropriate. The compensation committee may permit participants to elect to defer awards. For the three month periods ended September 30, 2009 and 2008, the Company recognized $1.7 million and $0.9 million, respectively, of estimated expenses under the plan and $5.2 million and $3.7 million for the nine month periods ended September 30, 2009 and 2008, respectively.
Stock Incentive Plans
The Company has a Stock Incentive Plan (the “2004 Plan”) which authorizes the granting of up to 4,499,999 shares of the Company’s common stock to employees, affiliates, consultants and directors of the Company in the form of incentive stock options (“ISOs”), non-qualified stock options, stock appreciation rights (“SARs”), restricted stock and deferred units. The Company also has a 2009 Stock Incentive Plan (the “2009 Plan” and together with the 2004 Plan, the “Plans”) which authorizes the granting of up to 4,800,000 shares of the Company’s common stock to employees, affiliates, consultants and directors of the Company in the form of ISOs, non-qualified stock options, SARs, restricted stock, restricted stock units and deferred units. No awards have been issued under the 2009 Plan. Generally, the approach to accounting in 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.
Stock Options. Options under the 2004 Plan become exercisable as to 25% of the optioned shares each year after the date of grant, except options totaling 1,687,500 shares awarded in fiscal 2005 to Messrs. Edward Cohen and Jonathan Cohen, which are immediately exercisable, and expire not later than ten years after the date of grant. Compensation cost is recorded on a straight-line basis. The Company issues new shares when stock options are exercised or units are converted to shares. Under the 2004 Plan, there were 6,411 and 19,067 options exercised during the three and nine months ended September 30, 2009, respectively. Under the 2004 Plan, 28,155 options were exercised during the three and nine months ended September 30, 2008, respectively.

 

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The following tables set forth the 2004 Plan activity for the three and nine months ended September 30, 2009 and 2008:
                                 
    Three Months Ended  
    September 30,  
    2009     2008  
            Weighted             Weighted  
    Number     Average     Number     Average  
    of Unit     Exercise     of Unit     Exercise  
    Options     Price     Options     Price  
Outstanding, beginning of period
    3,537,132     $ 16.96       3,540,380     $ 16.89  
Granted
    7,500     $ 19.75              
Exercised
    (6,411 )   $ 11.32       (28,155 )   $ 11.32  
Forfeited
    (30,000 )   $ 35.82              
 
                       
Outstanding, end of period(1)(2)
    3,508,221     $ 16.81       3,512,225     $ 16.94  
 
                       
 
                               
Non-cash compensation expense recognized
(in thousands)
  $ 494             $ 983          
 
                           
                                 
    Nine Months Ended  
    September 30,  
    2009     2008  
            Weighted             Weighted  
    Number     Average     Number     Average  
    of Unit     Exercise     of Unit     Exercise  
    Options     Price     Options     Price  
Outstanding, beginning of period
    3,495,351     $ 16.97       2,715,380     $ 12.10  
Granted
    107,500     $ 13.80       825,000     $ 32.68  
Exercised(3)
    (19,067 )   $ 11.32       (28,155 )   $ 11.32  
Cancelled
    (15,187 )   $ 11.32              
Forfeited
    (60,376 )   $ 23.49              
 
                       
Outstanding, end of period(1)(2)
    3,508,221     $ 16.81       3,512,225     $ 16.94  
 
                       
 
                               
Options exercisable, end of period(4)
    2,745,408     $ 13.30       2,350,298     $ 11.61  
 
                       
 
                               
Non-cash compensation expense recognized
(in thousands)
  $ 2,388             $ 2,941          
 
                           
 
                               
Available for grant at September 30, 2009
    761,562                          
 
                             
     
(1)  
The weighted average remaining contractual life for outstanding options at September 30, 2009 was 6.7 years.
 
(2)  
The aggregate intrinsic value of options outstanding at September 30, 2009 was approximately $40.6 million.
 
(3)  
The aggregate intrinsic values of options exercised were approximately $0.1 million during the nine months ended September 30, 2009, and $0.8 million during the three and nine months ended September 30, 2008.
 
(4)  
The weighted average outstanding contractual life of exercisable options at September 30, 2009 is 6.0 years.

 

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The Company used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the periods indicated:
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
 
                               
Expected dividend yield
                0.6 %     0.4 %
Expected stock price volatility
    44 %           37 %     33 %
Risk-free interest rate
    3.1 %           2.3 %     2.6 %
Expected term (in years)
    6.88             6.29       6.25  
Fair value of stock options granted
  $ 9.80           $ 5.23     $ 11.75  
Deferred Units and Restricted Shares
Under the 2004 Plan, non-employee directors of the Company are awarded deferred units that vest over a four-year period. Each unit represents the right to receive one share of the Company’s common stock upon vesting. Units will vest sooner upon a change in control of the Company or death or disability of a grantee. The fair value of the grants is based on the closing stock price on the grant date, and is being charged to operations over the requisite service periods using a straight-line attribution method. Upon termination of service by a grantee, all unvested units are forfeited.
Restricted shares are granted from time to time to employees of the Company. Each unit represents the right to receive one share of the Company’s common stock upon vesting. The shares are issued to the participant, held in escrow, and paid to the participant upon vesting. The units vest one-fourth at each anniversary date over a four-year service period. The fair value of the grant is based on the closing price on the grant date, and is being expensed over the requisite service period using a straight-line attribution method.
The following table summarizes the activity of deferred and restricted units for the three and nine months ended September 30, 2009 and 2008:
                                 
            Three Months Ended          
    September 30,  
    2009     2008  
            Weighted             Weighted  
            Average             Average  
    Number     Grant Date     Number     Grant Date  
    of Units     Fair Value     of Units     Fair Value  
Non-vested shares outstanding, beginning of period
    12,534     $ 23.80       12,364     $ 23.53  
Granted
    24,663     $ 22.10       396     $ 37.69  
Matured(1)
    (5,123 )   $ 22.43       (248 )   $ 20.14  
Forfeited
                       
 
                       
Non-vested shares outstanding, end of period(2)
    32,074     $ 22.71       12,512     $ 24.05  
 
                       
 
                               
Non-cash compensation expense recognized
(in thousands)
  $ 93             $ 25          
 
                           

 

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            Nine Months Ended          
    September 30,  
    2009     2008  
            Weighted             Weighted  
            Average             Average  
    Number     Grant Date     Number     Grant Date  
    of Units     Fair Value     of Units     Fair Value  
Non-vested shares outstanding, beginning of period
    12,512     $ 24.05       21,114     $ 14.61  
Granted
    29,468     $ 21.04       1,920     $ 46.87  
Matured(1)
    (9,906 )   $ 19.43       (10,522 )   $ 9.27  
Forfeited
                       
 
                       
Non-vested shares outstanding, end of period(2)
    32,074     $ 22.71       12,512     $ 24.05  
 
                       
 
                               
Non-cash compensation expense recognized
(in thousands)
  $ 144             $ 74          
 
                           
 
     
(1)  
The intrinsic values for phantom unit awards vested during the three months ended at September 30, 2009 were $0.1 million and $0.2 million and $0.5 million during the nine months ended September 30, 2009 and 2008, respectively.
 
(2)  
The aggregate intrinsic value for phantom unit awards outstanding at September 30, 2009 was $0.9 million.
At September 30, 2009, the Company had unamortized compensation expense related to its unvested portion of the options and units of $6.8 million that the Company expects to recognize over the next four years.
Employee Stock Ownership Plan
The Company has an Employee Stock Ownership Plan (“ESOP”), which is a qualified non-contributory retirement plan, that was established to acquire shares of the Company’s common stock for the benefit of all employees who are 21 years of age or older and have completed 1,000 hours of service. Contributions to the ESOP are made at the discretion of the Company’s Board of Directors. Any dividends which may be paid on allocated shares will reduce retained earnings; dividends on unearned ESOP shares will be used to service the related debt.
The common stock purchased by the ESOP is held by the ESOP trustee in a suspense account. On an annual basis, a portion of the common stock will be released from the suspense account and allocated to participating employees. As of September 30, 2009, there were 767,378 shares allocated to participants and 49,861 shares which are unallocated. All unallocated shares were allocated to participating employees at the end of the ESOP’s fiscal year on September 30, 2009. Participants will receive shares upon vesting, which occurs over a five year period, beginning after the participant’s second year of service. The fair value of unearned ESOP shares was $1.3 million at September 30, 2009.

 

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Supplemental Employment Retirement Plan (“SERP”)
The Company entered into an employment agreement with its Chairman of the Board, Chief Executive Officer and President, Edward E. Cohen, pursuant to which the Company has agreed to provide him with a SERP and with certain financial benefits upon termination of his employment. Under the SERP, Mr. Cohen will be paid an annual benefit equal to the product of (a) 6.5% multiplied by, (b) his base salary at the time of his retirement, death or other termination of employment with the Company, multiplied by, (c) the amount of years he shall be employed by the Company commencing upon the effective date of the SERP agreement, limited to an annual maximum benefit of 65% of his final base salary and a minimum of 26% of his final base salary. During the three months ended September 30, 2009 and 2008, expense recognized with respect to this commitment was $0.2 million and $0.4 million, respectively, and $0.5 million and $1.1 million during the nine months ended September 30, 2009 and 2008, respectively.
During the nine months ended September 30, 2009, the Company funded $3.2 million of the outstanding liability with a financial institution in a rabbi trust, which is included in other assets on the Company’s consolidated balance sheet. As of September 30, 2009, the actuarial present value of the expected postretirement obligation due under this the SERP was $3.6 million, which is included in other long-term liabilities on the Company’s consolidated balance sheets.
The following table provides information about amounts recognized in the Company’s consolidated balance sheets at the dates indicated (in thousands):
                 
    September 30,     December 31,  
    2009     2008  
Other liabilities
  $ (3,587 )   $ (3,209 )
Accumulated other comprehensive income
    187       255  
Deferred income tax asset
    110       150  
 
           
Net amount recognized
  $ (3,290 )   $ (2,804 )
 
           
The estimated amount that will be amortized from accumulated other comprehensive income into expense for the year ended December 31, 2009 is $0.1 million.
Amended and Restated Atlas Energy, Inc. Assumed Long-Term Incentive Plan
In connection with the Merger, the Company agreed to assume ATN’s Long-Term Incentive Plan (the “Assumed LTIP”), which applies to all of ATN’s awards that were outstanding at the time of the Merger. Under the Assumed LTIP, each outstanding unit option, phantom unit and restricted unit granted under the ATN’s previous plan was converted to an equivalent stock option, phantom share or restricted share of the Company’s at a ratio of 1.0 unit to 1.16 common shares.
Following the consummation of the Merger, no new grant awards will be issued pursuant to the Assumed LTIP. All of the terms related to the previous LTIP remain unchanged and no new grant awards will be issued pursuant to the Assumed LTIP. Awards granted after 2006 vest 25% after three years and 100% upon the four-year anniversary of grant, except for awards to ATN’s former board members which vest 25% per year over four years. Awards granted in 2006 vest 25% per year over four years. Upon termination of service by a grantee, all unvested awards are forfeited. A restricted stock grant or phantom stock grant entitles a grantee to receive a share of the Company’s common stock upon vesting of the grant or, at the discretion of the Company’s compensation committee, cash equivalent to the then fair market value of its common share.
Restricted Stock and Phantom Units. Under the Assumed LTIP, 28,523 restricted and phantom units were awarded during the period from January 1, 2009 to September 29, 2009. During the nine months ended September 30, 2008, 35,793 restricted units were awarded under the Assumed LTIP. The fair value of the grants is based on the closing unit price on the grant date, and is being charged to operations over the requisite service periods using a straight-line attribution method.

 

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The following table summarizes the activity of restricted stock and phantom units for the period from January 1, 2009 to September 30, 2009 and lists the number and average grant date fair value of the Company’s common shares underlying the converted phantom and restricted stock:
                 
            Weighted  
            Average  
            Grant Date  
    Units     Fair Value  
Non-vested units outstanding at December 31, 2008
    768,829     $ 23.86  
Granted
    28,523       16.48  
Vested
    (13,073 )     21.70  
Forfeited
    (46,000 )     31.12  
 
           
Non-vested units outstanding at September 29, 2009
    738,279       23.16  
Units converted on September 29, 2009(1)
    118,125       N/A  
 
           
Non-vested units outstanding at September 30, 2009
    856,404     $ 19.97  
 
           
 
     
(1)  
Converted at a ratio of 1.0 ATN common unit to 1.16 common shares of the Company.
Unit Options. There were 5,000 unit options granted during the period from January 1, 2009 to September 30, 2009. During the nine months ended September 30, 2008, 14,000 unit options were awarded under the predecessor ATN LTIP. Option awards expire 10 years from the date of grant and were generally granted with an exercise price equal to the market price of ATN’s common units at the date of grant. The Company uses the Black-Scholes option pricing model to estimate the weighted average fair value per option granted.
The following table sets forth option activity for the period from January 1, 2009 to September 30, 2009 and lists the number of the ATN class B units prior to September 29, 2009, the number of the Company’s common shares subsequent to the Merger and the weighted average exercise price underlying the converted stock options:
                                 
                    Weighted        
                    Average        
            Weighted     Remaining     Aggregate  
            Average     Contractual     Intrinsic  
            Exercise     Term     Value  
    Units     Price     (in years)     (in thousands)  
 
                               
Outstanding at December 31, 2008
    1,902,902     $ 24.17                  
Granted
    5,000       25.78                  
Exercised
                           
Forfeited or expired
    (123,600 )     31.96                  
 
                         
Outstanding at September 29, 2009
    1,784,302     $ 23.64       7.34          
Stock options converted on September 29, 2009
    285,488       N/A       N/A          
 
                       
Non-vested stock options outstanding at September 30, 2009
    2,069,790     $ 20.36       7.34     $ 14,402  
 
                       

 

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The following tables summarize information about unit options outstanding and exercisable at September 30, 2009 and list the number of the Company’s common shares subsequent to the Merger and the weighted average exercise price underlying the converted stock options:
                                         
    Options Outstanding     Options Exercisable  
            Weighted                      
            Average     Weighted             Weighted  
    Number of     Remaining     Average     Number of     Average  
Range of   Shares     Contractual     Exercise     Shares     Exercise  
Exercise Prices   Outstanding     Life in Years     Price     Exercisable     Price  
$21.00 - 25.18
    1,635,002       7.1     $ 22.60       280,314     $ 21.00  
$30.24 - 35.00
    141,800       7.8     $ 34.78              
$37.79 and above
    7,500       8.3     $ 39.79              
 
                             
 
    1,784,302       7.34     $ 23.64       280,314     $ 21.00  
 
                                       
Stock options converted on September 29, 2009(1)
    285,488       N/A       N/A       44,850       N/A  
 
                             
Converted stock options at September 30, 2009
    2,069,790       7.34     $ 20.38       325,164     $ 18.10  
 
                             
 
     
(1)  
Converted at a ratio of 1.0 ATN common unit to 1.16 common shares of the Company.
The Company recognized $0.4 million and $1.4 million in compensation expense related to the Assumed LTIP restricted stock units, phantom units and unit options for the three months ended September 30, 2009 and 2008, respectively. The Company recognized $3.4 million and $4.0 million of compensation expense related to the Assumed LTIP for the nine months ended September 30, 2009 and 2008, respectively. ATN paid $0.4 million with respect to distribution equivalent rights (“DER”) for the three months ended September 30, 2008, and $0.4 million and $1.0 million for the nine months ended September 30, 2009 and 2008, respectively. These amounts were recorded as a reduction of members’ equity on the Company’s consolidated balance sheet during the respective period. At September 30, 2009, the Company had approximately $8.8 million of unrecognized compensation expense related to the unvested portion of the restricted shares, phantom shares and stock options.
AHD Long-Term Incentive Plan
The Board of Directors of AHD approved and adopted AHD’s Long-Term Incentive Plan (“AHD LTIP”), which provides performance incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for AHD. The AHD LTIP is administered by a committee (the “AHD LTIP Committee”), appointed by AHD’s board. Under the AHD LTIP, phantom units and/or unit options may be granted, at the discretion of the AHD LTIP Committee, to all or designated Participants, at the discretion of the AHD LTIP Committee. The AHD LTIP Committee may grant such awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units. At September 30, 2009, AHD had 1,136,800 phantom units and unit options outstanding under the AHD LTIP, with 962,650 phantom units and unit options available for grant.
AHD Phantom Units. A phantom unit entitles a Participant to receive a common unit of AHD, without payment of an exercise price, upon vesting of the phantom unit or, at the discretion of the AHD LTIP Committee, cash equivalent to the then fair market value of a common limited partner unit of AHD. In tandem with phantom unit grants, the AHD LTIP Committee may grant a Participant a distribution equivalent right (“DER”), which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions AHD makes on a common unit during the period such phantom unit is outstanding. The AHD LTIP Committee will determine the vesting period for phantom units. Through September 30, 2009, phantom units granted under the AHD LTIP generally will vest 25% three years from the date of grant and 100% four years from the date of grant. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the AHD LTIP Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control of AHD, as defined in the AHD LTIP. Of the phantom units outstanding under the AHD LTIP at September 30, 2009, 44,550 units will vest within the following twelve months. All phantom units outstanding under the AHD LTIP at September 30, 2009 include DERs granted to the Participants by the AHD LTIP Committee. The amount paid with respect to AHD’s LTIP DERs was $0.1 million for the three months ended September 30, 2008, and $14,000 and $0.3 million for the nine months ended September 30, 2009 and 2008, respectively. No DER payments were made during the three months ended September 30, 2009. These amounts were recorded as an adjustment of non-controlling interests on the Company’s consolidated balance sheet.

 

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The following table sets forth the AHD LTIP phantom unit activity for the periods indicated:
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
 
                               
Outstanding, beginning of period
    181,300       225,475       226,300       220,825  
Granted(1)
    500             500       4,650  
Matured
                       
Forfeited
                (45,000 )      
 
                       
Outstanding, end of period(2)
    181,800       225,475       181,800       225,475  
 
                       
 
                               
Non-cash compensation expense recognized
(in thousands)
  $ 295     $ 354     $ 277     $ 1,092  
 
                       
     
(1)  
The weighted average prices for phantom unit awards on the date of grant, which are utilized in the calculation of compensation expense and do not represent exercise prices to be paid by the recipient, were $3.40 for the three and nine months ended September 30, 2009, and $32.28 for the nine months ended September 30, 2008. There were no grants awarded for the three months ended September 30, 2008.
 
(2)  
The aggregate intrinsic value for phantom unit awards outstanding at September 30, 2009 was $0.7 million.
At September 30, 2009, AHD had approximately $1.0 million of unrecognized compensation expense related to unvested phantom units outstanding under AHD’s LTIP based upon the fair value of the awards.
AHD Unit Options. A unit option entitles a Participant to receive a common unit of AHD upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of AHD’s common unit as determined by the AHD LTIP Committee on the date of grant of the option. The AHD LTIP Committee also shall determine how the exercise price may be paid by the Participant. The AHD LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through September 30, 2009, unit options granted under the AHD LTIP generally will vest 25% three years from the date of grant and 100% four years from the date of grant. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by AHD’s LTIP Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control of AHD, as defined in the AHD LTIP. There are 213,750 unit options outstanding under the AHD LTIP at September 30, 2009 that will vest within the following twelve months. The following table sets forth the AHD LTIP unit option activity for the periods indicated:
                                 
    Three Months Ended September 30,  
    2009     2008  
            Weighted             Weighted  
    Number     Average     Number     Average  
    of Unit     Exercise     of Unit     Exercise  
    Options     Price     Options     Price  
 
                               
Outstanding, beginning of period
    955,000     $ 20.54       1,215,000     $ 22.56  
Granted
                       
Matured
                       
Forfeited
                       
 
                       
Outstanding, end of period(1)(2)
    955,000     $ 20.54       1,215,000     $ 22.56  
 
                       
 
                               
Options exercisable, end of period
                       
 
                       
 
                               
Non-cash compensation expense recognized
(in thousands)
  $ 222             $ 309          
 
                           

 

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    Nine Months Ended September 30,  
    2009     2008  
            Weighted             Weighted  
    Number     Average     Number     Average  
    of Unit     Exercise     of Unit     Exercise  
    Options     Price     Options     Price  
Outstanding, beginning of period
    1,215,000     $ 22.56       1,215,000     $ 22.56  
Granted
    100,000     $ 3.24              
Matured
                       
Forfeited
    (360,000 )   $ 22.56              
 
                       
Outstanding, end of period(1)(2)
    955,000     $ 20.54       1,215,000     $ 22.56  
 
                       
 
                               
Options exercisable, end of period
                       
 
                       
 
                               
Non-cash compensation expense (income) recognized (in thousands)
  $ (129 )           $ 928          
 
                           
     
(1)  
The weighted average remaining contractual lives for outstanding options at September 30, 2009 were 7.3 years.
 
(2)  
The intrinsic value of options outstanding at September 30, 2009 was $0.1 million.
At September 30, 2009, AHD had approximately $0.7 million of unrecognized compensation expense related to unvested unit options outstanding under AHD’s LTIP based upon the fair value of the awards.
AHD used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the period indicated:
         
    Nine Months Ended  
    September 30, 2009  
Expected dividend yield
    7.0 %
Expected stock price volatility
    40 %
Risk-free interest rate
    2.3 %
Expected term (in years)
    6.9  
APL Long-Term Incentive Plan
APL has a Long-Term Incentive Plan (“APL LTIP”), in which officers, employees and non-employee managing board members of the General Partner and employees of the General Partner’s affiliates and consultants are eligible to participate. The APL LTIP is administered by a committee (the “APL LTIP Committee”) appointed by AHD’s managing board. The APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 435,000 common units.

 

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APL Phantom Units. A phantom unit entitles a grantee to receive a common unit, without payment of an exercise price, upon vesting of the phantom unit or, at the discretion of the APL LTIP Committee, cash equivalent to the fair market value of an APL common unit. In addition, the APL LTIP Committee may grant a participant a DER, which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions APL makes on a common unit during the period the phantom unit is outstanding. A unit option entitles the grantee to purchase APL’s common limited partner units at an exercise price determined by the APL LTIP Committee at its discretion. The APL LTIP Committee also has discretion to determine how the exercise price may be paid by the participant. Except for phantom units awarded to non-employee managing board members of AHD, the APL LTIP Committee will determine the vesting period for phantom units and the exercise period for options. Through September 30, 2009, phantom units granted under the APL LTIP generally had vesting periods of four years. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the APL LTIP Committee, although no awards currently outstanding contain any such provision. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards will automatically vest upon a change of control, as defined in the APL LTIP. Of the units outstanding under the APL LTIP at September 30, 2009, 28,960 units will vest within the following twelve months. All phantom units outstanding under the APL LTIP at September 30, 2009 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL LTIP DERs were $0.1 million for the three months ended September 30, 2008, and $0.1 million and $0.4 million for the nine months ended September 30, 2009 and 2008, respectively. No LTIP DER payments were made for the three months ended September 30, 2009. These amounts were recorded as reductions of non-controlling interest on the Company’s consolidated balance sheet.
The following table sets forth the APL LTIP phantom unit activity for the periods indicated:
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Outstanding, beginning of period
    76,721       149,923       126,565       129,746  
Granted(1)
                2,000       54,296  
Matured(2)
    (11,038 )     (10,860 )     (46,132 )     (44,229 )
Forfeited
    (75 )     (1,000 )     (16,825 )     (1,750 )
 
                       
Outstanding, end of period(3)
    65,608       138,063       65,608       138,063  
 
                       
 
                               
Non-cash compensation expense recognized
(in thousands)
  $ 235     $ 600     $ 491     $ 1,783  
 
                       
 
     
(1)  
The weighted average prices for phantom unit awards on the date of grant, which are utilized in the calculation of compensation expense and do not represent an exercise price to be paid by the recipient, were $4.75 and $44.43 for awards granted for the nine months ended September 30, 2009 and 2008, respectively. There were no awards granted for the three months ended September 30, 2009 and 2008.
 
(2)  
The intrinsic values for phantom unit awards exercised during the three months ended September 30, 2009 and 2008 were $0.1 million and $0.4 million, respectively, and $0.2 million and $1.8 million during the nine months ended September 30, 2009 and 2008, respectively.
 
(3)  
The aggregate intrinsic value for phantom unit awards outstanding at September 30, 2009 was $0.5 million.
At September 30, 2009, APL had approximately $0.8 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIP based upon the fair value of the awards.

 

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APL Unit Options. A unit option entitles a participant to receive a common unit of APL upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of APL’s common unit as determined by the APL LTIP Committee on the date of grant of the option. The APL LTIP Committee also shall determine how the exercise price may be paid by the Participant. The APL LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through September 30, 2009, unit options granted under APL’s LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the APL LTIP Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control of APL, as defined in the APL’s LTIP. There were 25,000 unit options outstanding under APL’s LTIP at September 30, 2009 that will vest within the following twelve months. The following table sets forth the APL LTIP unit option activity for the periods indicated:
                                 
    Three Months Ended September 30,  
    2009     2008  
            Weighted             Weighted  
    Number     Average     Number     Average  
    of Unit     Exercise     of Unit     Exercise  
    Options     Price     Options     Price  
Outstanding, beginning of period
    100,000     $ 6.24              
Granted
                       
Matured
                       
Forfeited
                       
 
                       
Outstanding, end of period(1)(2)
    100,000     $ 6.24              
 
                       
Options exercisable, end of period
                       
 
                       
 
                               
Weighted average fair value of unit options per unit granted during the period
                       
 
                       
 
                               
Non-cash compensation expense recognized
(in thousands)
  $ 2                        
 
                           
                                 
    Nine Months Ended September 30,  
    2009     2008  
            Weighted             Weighted  
    Number     Average     Number     Average  
    of Unit     Exercise     of Unit     Exercise  
    Options     Price     Options     Price  
Outstanding, beginning of period
        $              
Granted
    100,000       6.24              
Matured
                       
Forfeited
                       
 
                       
Outstanding, end of period(1)(2)
    100,000     $ 6.24              
 
                       
 
                               
Options exercisable, end of period
                       
 
                       
 
                               
Weighted average fair value of unit options per unit granted during the period
    100,000     $ 0.14              
 
                       
 
                               
Non-cash compensation expense recognized
(in thousands)
  $ 5                        
 
                           
 
     
(1)  
The weighted average remaining contractual life for outstanding options at September 30, 2009 was 9.3 years.
 
(2)  
There was $0.1 million aggregate intrinsic value of options outstanding at September 30, 2009.

 

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APL used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the period indicated:
         
    Nine Months Ended  
    September 30, 2009  
Expected dividend yield
    11.0 %
Expected stock price volatility
    20 %
Risk-free interest rate
    2.2 %
Expected term (in years)
    6.3  
APL Employee Incentive Compensation Plan and Agreement
In June 2009, a wholly-owned subsidiary of APL adopted an incentive plan (the “APL Plan”) which allows for equity-indexed cash incentive awards to employees of APL (the “Participants”), but expressly excludes as an eligible Participant any “Named Executive Officer” of APL (as such term is defined under the rules of the Securities and Exchange Commission). The APL Plan is administered by a committee appointed by the chief executive officer of APL. Under the APL Plan, cash bonus units may be awarded Participants at the discretion of the committee and bonus units totaling 325,000 were awarded under the APL Plan in June 2009. In September 2009, the APL subsidiary entered into an agreement with an APL executive officer that granted an award of 50,000 bonus units on substantially the same terms as the bonus units available under the APL Plan (the bonus units issued under the APL Plan and under the separate agreement are, for purposes hereof, referred to as “APL Bonus Units”). An APL Bonus Unit entitles the employee to receive the cash equivalent of the then-fair market value of an APL common limited partner unit, without payment of an exercise price, upon vesting of the APL Bonus Unit. APL Bonus Units vest ratably over a three year period from the date of grant and will automatically vest upon a change of control, death, or termination without cause, each as defined in the governing document. Vesting will terminate upon termination of employment with cause. During the three and nine months ended September 30, 2009, APL granted 50,000 and 375,000 APL Bonus Units, respectively. Of the APL Bonus Units outstanding at September 30, 2009, 123,750 APL Bonus Units will vest within the following twelve months. APL recognized compensation expense related to these awards based upon the fair value. APL recognized $0.4 million and $0.5 million of compensation expense within general and administrative expense on the Company’s consolidated statements of operations with respect to the vesting of these awards for the three and nine months ended September 30, 2009, respectively. At September 30, 2009, the Company has recognized $0.5 million within accrued liabilities on its consolidated balance sheet with regard to the awards, which represents their fair value at September 30, 2009.
NOTE 18 — OPERATING SEGMENT INFORMATION
The Company’s operations include three reportable operating segments. These operating segments reflect the way the Company manages its operations and makes business decisions. The Company does not allocate income taxes to its operating segments. Operating segment data for the periods indicated are as follows (in thousands):
                                 
    Three Months Ended September 30,     Nine Months Ended September 30,  
    2009     2008 (c)     2009 (c)     2008 (c)  
Gas and oil production
                               
Revenues (a)
  $ 65,986     $ 81,235     $ 207,908     $ 236,417  
Costs and expenses
    (12,128 )     (12,688 )     (33,217 )     (35,735 )
 
                       
Segment profit
  $ 53,858     $ 68,547     $ 174,691     $ 200,682  
 
                       
 
                               
Well construction and completion
                               
Revenues
  $ 81,496     $ 116,987     $ 257,231     $ 343,466  
Costs and expenses
    (69,138 )     (101,727 )     (218,236 )     (298,666 )
 
                       
Segment profit
  $ 12,358     $ 15,260     $ 38,995     $ 44,800  
 
                       
 
Other (a)
                               
Revenues
  $ 14,259     $ 3,380     $ 23,999     $ 13,116  
Costs and expenses
    (10,350 )     (2,890 )     (19,290 )     (8,206 )
 
                       
Segment profit
  $ 3,909     $ 490     $ 4,709     $ 4,910  
 
                       
 
                               
Atlas Pipeline (b)
                               
Revenues (c)
  $ 200,537     $ 553,561     $ 521,918     $ 945,864  
Revenues — affiliates
          12,021       16,766       32,768  
Equity income in joint venture
    1,430             2,140        
Costs and expenses
    (159,890 )     (333,851 )     (458,384 )     (992,113 )
 
                       
Segment profit (loss)
  $ 42,077     $ 231,731     $ 82,440     $ (13,481 )
 
                       
 
                               

 

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    Three Months Ended September 30,     Nine Months Ended September 30,  
    2009     2008 (c)     2009 (c)     2008 (c)  
 
Reconciliation of segment profit (loss) to net income (loss) before income tax provision (benefit)
                               
Segment profit (loss)
                               
Gas and oil production
  $ 53,858     $ 68,547     $ 174,691     $ 200,682  
Well construction and completion
    12,358       15,260       38,995       44,800  
Other
    3,909       490       4,709       4,910  
Atlas Pipeline
    42,077       231,731       82,440       (13,481 )
 
                       
Total segment profit (loss)
    112,202       316,028       300,835       236,911  
Gain on sale of APL’s Appalachia system assets
    55             105,746        
General and administrative expenses
    (31,786 )     (12,392 )     (80,777 )     (57,903 )
Net expense reimbursement — affiliate
    (280 )     (255 )     (842 )     (689 )
Depreciation, depletion and amortization
    (46,460 )     (44,325 )     (147,427 )     (129,539 )
Interest expense (d)
    (47,754 )     (37,331 )     (124,322 )     (106,538 )
Other income (loss) — net
    3,421       3,818       9,556       11,842  
 
                       
Income (loss) from continuing operations before income tax provision (benefit)
  $ (10,602 )   $ 225,543     $ 62,769     $ (45,916 )
 
                       
 
                               
Capital expenditures
                               
Gas and oil production
  $ 33,824     $ 89,165     $ 129,818     $ 224,179  
Well construction and completion
                       
Atlas Pipeline
    7,116       81,714       137,610       223,768  
Corporate and other
    548       135       967       791  
 
                       
Total capital expenditures
  $ 41,488     $ 171,014     $ 268,395     $ 448,738  
 
                       
                 
    September 30,     December 31,  
    2009     2008 (c)  
Balance sheet
               
Goodwill
               
Gas and oil production
  $ 21,527     $ 21,527  
Well construction and completion
    13,639       13,639  
Atlas Pipeline
           
 
           
 
  $ 35,166     $ 35,166  
 
           
Total assets
               
Gas and oil production
  $ 2,201,175     $ 2,210,563  
Well construction and completion
    12,760       16,399  
Atlas Pipeline (c)
    2,139,561       2,157,590  
Discontinued operations
          255,606  
Corporate and other
    118,230       205,723  
 
           
 
  $ 4,471,726     $ 4,845,881  
 
           
 
     
(a)  
Includes revenues and expenses from well services, transportation and administration and oversight that do not meet the quantitative threshold for reporting segment information.
 
(b)  
Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 5).
 
(c)  
Includes gains of $1.0 million and $147.5 million on mark-to-market derivatives for three months ended September 30, 2009 and 2008, respectively, and losses of $17.2 million and $257.3 million on mark-to-market derivatives for nine months ended September 30, 2009 and 2008, respectively.
 
(d)  
The Company notes that interest expense has not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.
Operating profit (loss) represents total revenues less costs and expenses attributable thereto. Amounts for interest, provision for possible losses and depreciation, depletion and amortization and general corporate expenses are shown in the aggregate because these measures are not significant drivers in deciding how to allocate resources and assessing performance of each defined segment.

 

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NOTE 19 — SUBSEQUENT EVENTS
On November 2, 2009, APL’s agreement with Pioneer, whereby Pioneer had an option to purchase up to an additional 22.0% interest in the Midkiff/Benedum system, expired without Pioneer exercising its option (see Note 2).
On October 22, 2009, the Company entered into the following natural gas derivative contracts:
Natural Gas Fixed Price Swaps
                 
Production              
Period Ending           Average  
December 31,   Volumes     Fixed Price  
    (MMBtu)     (per MMBtu)  
2010
    2,520,000     $ 6.250  
2011
    1,260,000     $ 6.863  
Natural Gas Costless Collars
                     
Production                  
Period Ending               Average  
December 31,   Option Type   Volumes     Floor and Cap  
        (MMBtu)     (per MMBtu)  
2012
  Puts purchased     3,480,000     $ 6.550  
2012
  Calls sold     3,480,000     $ 7.750  
2013
  Puts purchased     3,480,000     $ 6.700  
2013
  Calls sold     3,480,000     $ 7.800  
On October 14, 2009, in conjunction with a regularly scheduled borrowing based redetermination, the Company’s borrowing base under its revolving credit facility of $575.0 million was approved.
On October 13, 2009 AHD repaid $4.0 million of its outstanding credit facility borrowings in accordance with the amendment through a subordinate loan with the Company.
ITEM 2.  
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements
When used in this Form 10-Q, the words “believes,” “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties more particularly described in Item 1A, “Risk Factors”, in our annual report on Form 10-K for the year ended December 31, 2008. These risks and uncertainties could cause actual results to differ materially from the results stated or implied in this document. 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
The following discussion provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this report.

 

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We are a publicly traded Delaware corporation whose common units are listed on the NASDAQ Stock Market under the symbol “ATLS”. On September 29, 2009, we completed our merger with Atlas Energy Resources, LLC (“ATN”), our formerly publicly traded subsidiary and a Delaware limited liability company (NYSE: ATN), pursuant to the definitive merger agreement previously executed between us and ATN, with ATN surviving as our wholly-owned subsidiary (the “Merger”).
We are an independent developer and producer of natural gas and oil, with operations in the Appalachian Basin, the Michigan Basin, and the Illinois Basin. Within these Basins, we focus our drilling and production in four established shale plays: namely, the Marcellus Shale of western Pennsylvania, the Antrim Shale of northern Michigan, the Chattanooga Shale of northeastern Tennessee, and the New Albany Shale of west central Indiana. Our Appalachian Basin major operations are located in eastern Ohio, western Pennsylvania, and north central Tennessee. We have additional operations in New York, West Virginia and Kentucky. We specialize in development of these natural gas basins because they provide it with repeatable, low-risk drilling opportunities. We are also a leading sponsor and manager of tax-advantaged direct investment natural gas and oil partnerships in the United States. We fund the drilling of natural gas and oil wells on its acreage by sponsoring and managing tax advantaged investment partnerships. We generally structure our investment partnerships so that, upon formation of a partnership, we co-invest in and contribute leasehold acreage to it, enter into drilling and well operating agreements with it and becomes its managing general partner.
KEY PERFORMANCE INDICATORS
In our Appalachia gas and oil operations:
   
we own direct and indirect working interests in approximately 8,658 gross productive gas and oil wells;
   
we own overriding royalty interests in approximately 624 gross productive gas and oil wells;
   
our net daily production was 41.3 million cubic feet equivalents per day (“Mmcfed”) and 42.4 Mmcfed for the three and nine months ended September 30, 2009, respectively;
   
we lease approximately 919,200 gross (873,600 net) acres, of which approximately 606,800 gross (599,800 net) acres are undeveloped;
 
   
included in our undeveloped acreage are approximately 215,600 Marcellus acres in Pennsylvania, New York and West Virginia, of which approximately 160,400 acres are located in our core Marcellus Shale position in southwestern Pennsylvania;
   
we drilled 153 gross wells (including 73 Marcellus Shale wells), during the nine months ended September 30, 2009, on our own behalf and that of our investment partnerships;
   
we have drilled 184 vertical and 15 horizontal gross Marcellus Shale wells to date, of which 159 vertical and 7 horizontal Marcellus Shale wells have been successfully completed and have been turned on-line and are producing;
   
of the 159 vertical completed Marcellus Shale wells we drilled to date, we have utilized the multi-frac technique on 68 wells, with successful results;

 

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we turned on-line 274 gross wells during the nine months ended September 30, 2009; and
   
we drilled and participated in 25 horizontal wells in the Chattanooga Shale of eastern Tennessee to date. We have leased approximately 130,700 gross acres (128,200 net undeveloped) in this shale area.
In our Michigan gas and oil operations:
   
we own direct and indirect working interests in approximately 2,498 gross producing gas and oil wells;
   
we own overriding royalty interests in approximately 93 gross producing gas and oil wells;
   
our net daily production was 57.8 Mmcfed and 58.3 Mmcfed for the three and nine months ended September 30, 2009, respectively;
   
we have leased approximately 345,000 gross (271,900 net) acres, of which approximately 34,900 gross (26,400 net) acres are undeveloped; and
   
we drilled 32 gross wells (27 net wells) during the nine months ended September 30, 2009.
In our Indiana gas and oil operations:
   
we own direct and indirect working interests in approximately 20 gross producing gas and oil wells;
   
our net daily production was 0.8 Mmcfed and 0.4 Mmcfed for the three and nine months ended September 30, 2009, respectively;
   
we have leased approximately 249,600 gross (122,800 net) acres, of which approximately 242,600 gross (117,200 net) acres are undeveloped; and
   
we drilled 19 gross wells (17 net wells) during the nine months ended September 30, 2009.
In our partnership management business:
   
our investment partnership business includes equity interests in 96 investment partnerships and a registered broker-dealer which acts as the dealer manager of our investment partnership offerings; and
   
during 2009, we have raised $122.8 million in investor funds for Atlas Resources Public #18B-2009(B) L.P., and have begun raising funds for our most recent investment partnership, Atlas Resources Public #18-2009(C) L.P. in which we have registered subscriptions of up to $275.7 million (A written prospectus meeting the requirements of Section 10 of the Securities Act may be obtained from Anthem Securities, Inc. (a subsidiary of Atlas Energy), 1550 Coraopolis Heights Rd. — 3rd Floor, Moon Township, PA 15108).

 

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OTHER OWNERSHIP INTERESTS
In addition to our production operations, we also maintain ownership interests in the following entities at September 30, 2009:
   
1,112,000 common units, representing a 2.2% ownership interest, in Atlas Pipeline Partners, L.P. (“Atlas Pipeline Partners” or “APL”), a publicly traded Delaware limited partnership (NYSE: APL) and midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachia regions;
   
17,808,109 common units, representing a 64.4% ownership interest, in Atlas Pipeline Holdings, L.P. (“Atlas Pipeline Holdings” or “AHD”), a publicly traded Delaware limited partnership (NYSE: AHD) and owner of the general partner of APL. We manage AHD through our ownership of its general partner; and
   
Lightfoot Capital Partners LP (“Lightfoot LP”) and Lightfoot Capital Partners GP LLC (“Lightfoot GP”), the general partner of Lightfoot (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. We have an approximate direct and indirect 18% ownership interest in Lightfoot GP and a commitment to invest a total of $20.0 million in Lightfoot LP. We also have a direct and indirect ownership interests in Lightfoot LP.
AHD, which owns the general partner and manages APL, had the following ownership interests in APL at September 30, 2009:
   
a 2.0% general partner interest, which entitles it to receive 2% of the cash distributed by APL;
   
all of the incentive distribution rights, which entitle it to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per APL common unit in any quarter. AHD, the holder of all of the incentive distribution rights in APL, agreed to allocate up to $3.75 million of its incentive distribution rights per quarter back to APL (“the IDR Adjustment Agreement”) after AHD receives the initial $7.0 million per quarter of incentive distribution rights;
   
5,754,253 common units, representing approximately 11.4% of the outstanding common units at September 30, 2009, or a 11.2% ownership interest in APL; and
   
15,000 $1,000 par value 12.0% cumulative preferred limited partner units at September 30, 2009.
FINANCIAL PRESENTATION
Our consolidated financial statements contain our accounts and those of our subsidiaries, all of which are wholly-owned at September 30, 2009 except for AHD, which we control, and APL, which is controlled by AHD. Prior to the Merger on September 29, 2009, ATN was a controlled subsidiary of ours but was not wholly-owned. The non-controlling interests in ATN prior to the Merger and AHD and APL are reflected as income (loss) attributable to non-controlling interests in our consolidated statements of operations and as a component of stockholders’ equity on our consolidated balance sheets. Throughout this section, when we refer to “our” consolidated financial statements, we are referring to the consolidated results for us and our wholly-owned subsidiaries and the consolidated results of AHD, including APL’s financial results, adjusted for non-controlling interests in ATN’s net income (loss) prior to the Merger on September 29, 2009 and AHD’s and APL’s net income (loss).

 

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RECENT DEVELOPMENTS
On September 29, 2009, we completed our merger with ATN pursuant to the definitive merger agreement previously executed between us and ATN, with ATN surviving as our wholly-owned subsidiary. In the Merger, the 33.4 million Class B common units of ATN not previously held by us were exchanged for 38.8 million shares of our common stock (a ratio of 1.16 shares of our common stock for each Class B common unit of ATN). We also changed our name from Atlas America, Inc. to Atlas Energy, Inc. Concurrent with the Merger, the Compensation Committee of the Board of Directors approved the Atlas Energy, Inc. 2009 Stock Incentive Plan, which creates a new stock incentive plan for the combined entity. We also have the legacy Atlas America stock incentive plan and assumed the legacy ATN Long-Term Incentive Plan. Due to the Merger, we recognized a reduction of $556.4 million in non-controlling interest and a decrease to deferred tax liability of $179.4 million, all of which was reflected as an increase to additional paid-in-capital on our consolidated balance sheets.
On September 7, 2009, we began fundraising for Atlas Resources Public #18-2008 Drilling Program, in which we have the capacity to raise approximately $275.7 million, representing the third partnership (Atlas Resources Public #18-2009(C) L.P.) in the program. During the first six months of 2009, we raised $122.8 million for our second partnership (Atlas Resources Public #18-2009 (B) L.P.). Atlas Resources, LLC, our wholly-owned subsidiary, serves as the managing general partner for each partnership. A written prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended, may be obtained from Anthem Securities, Inc. (a subsidiary of Atlas Energy), 1550 Coraopolis Heights Rd. — 3rd Floor, Moon Township, PA 15108.
On July 13, 2009, ATN issued $200.0 million of 12.125% senior unsecured notes (“ATN 12.125% Senior Notes”) due 2017 at 98.116% of par value to yield 12.5% at maturity. We used the net proceeds of $191.7 million, net underwriting fees of $4.5 million, to repay outstanding borrowings under ATN’s revolving credit facility (see “ATN Credit Facility”). Under the terms of the credit facility, the borrowing base is automatically reduced by 25% of the stated principal amount of any senior unsecured notes offering by ATN. As such, the borrowing base of the credit facility was reduced by $50.0 million to $600.0 million upon the issuance of the ATN 12.125% Senior Notes. Interest on the ATN 12.125% Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year. The ATN 12.125% Senior Notes are redeemable on or after August 1, 2013 at certain redemption prices, together with accrued interest at the date of redemption. In addition, before August 1, 2012, we may redeem up to 35% of the aggregate principal amount of the ATN 12.125% Senior Notes with the proceeds of certain equity offerings at a stated redemption price of 112.125% of the principal, plus accrued interest. The ATN 12.125% Senior Notes are junior in right of payment to ATN’s secured debt, including its obligations under the revolving credit facility. The indenture governing the ATN 12.125% Senior Notes contains covenants, including limitations of ATN’s ability to incur certain liens, engage in sale/leaseback transactions, incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of ATN’s assets. We are not guarantors of ATN’s or APL’s senior notes, including the ATN 12.125% Senior Notes, ATN’s or APL’s credit facilities, or APL’s term loan.
On July 10, 2009, ATN’s credit agreement was amended to, among other things, permit the Merger and to allow ATN to distribute (a) amounts equal to our income tax liability attributable to ATN’s net income at the highest marginal rate and (b) up to $40.0 million per year and, to the extent that it distributes less than that amount in any year, may carry an amount up to $20.0 million for use in the next year.
SUBSEQUENT EVENTS
On November 2, 2009, APL’s agreement with Pioneer Natural Resources Company (“Pioneer”), whereby Pioneer had an option to purchase up to an additional 22.0% interest in the Midkiff/Benedum system, expired without Pioneer exercising its option (see Note 2 under Item 1, “Financial Statements”).

 

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Natural Gas Derivative Contracts
On October 22, 2009, we entered into the following natural gas derivative contracts:
Natural Gas Fixed Price Swaps
                 
Production              
Period Ending           Average  
December 31,   Volumes     Fixed Price  
    (MMBtu)     (per MMBtu)  
2010
    2,520,000     $ 6.250  
2011
    1,260,000     $ 6.863  
Natural Gas Costless Collars
                         
Production                      
Period Ending                   Average  
December 31,   Option Type     Volumes     Floor and Cap  
            (MMBtu)     (per MMBtu)  
2012
  Puts purchased     3,480,000     $ 6.550  
2012
  Calls sold     3,480,000     $ 7.750  
2013
  Puts purchased     3,480,000     $ 6.700  
2013
  Calls sold     3,480,000     $ 7.800  
Credit Agreement Amendment
Effective October 14, 2009, in conjunction with a regularly scheduled borrowing base redetermination, ATN’s borrowing base under its revolving credit facility of $575.0 million was approved.
On October 13, 2009 AHD repaid $4.0 million of its outstanding credit facility borrowings in accordance with the amendment through a subordinate loan with us.
CONTRACTUAL REVENUE ARRANGEMENTS
Appalachia Natural Gas. We market our natural gas, which is principally located in the Fayette County, PA area, primarily to Hess Corporation, Colonial Energy, Inc., South Jersey Resources Group and others. We expect that natural gas produced from our wells drilled in areas of the Appalachian Basin other than those described above will be primarily tied to the spot market price and supplied to:
   
gas marketers;
   
local distribution companies;
   
industrial or other end-users; and/or
   
companies generating electricity.
Michigan Natural Gas. In Michigan, we have natural gas sales agreements with DTE Energy Company, which are valid through December 31, 2012. DTE has the obligation to purchase all of the natural gas produced and delivered by us and our affiliates from specific projects at certain delivery points. Based on recent production data available to us, we anticipate that we and our affiliates will sell approximately 49% of our Michigan natural gas production during the year ending December 31, 2009 under the DTE agreements, in most cases at NYMEX pricing.

 

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Crude Oil. Crude oil produced from our wells flow directly into storage tanks where it is picked up by an oil company, a common carrier or pipeline companies acting for an oil company, which is purchasing the crude oil. We sell any oil produced by our Appalachian wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil. In Michigan, the property operator typically markets the oil produced.
Investment Partnerships. We generally fund our drilling activities through sponsorship of tax-advantaged investment partnerships. In addition to providing capital for our drilling activities, our investment partnerships are a source of fee-based revenues, which are not directly dependent on natural gas and oil prices. As managing general partner of the investment partnerships, we receive the following fees:
   
Well construction and completion. For each well that is drilled by an investment partnership, we receive an 18% mark-up on those costs incurred to drill and complete the well.
   
Administration and oversight. For each well drilled by an investment partnership, we receive a fixed fee that currently ranges from $15,700 to $248,964. The fixed fee is based on factors such as well type (vertical or horizontal), depth, formation, and area. Additionally, the partnership pays us a monthly per well administrative fee of $75 for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by its proportionate interest in the well.
   
Well services. Each partnership pays us a monthly per well operating fee, currently $100 to $1,500, for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.
GENERAL TRENDS AND OUTLOOK
We expect our business to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.
Natural Gas Supply and Outlook
While commodity prices for natural gas were at lower levels during the three months ended September 30, 2009 when compared with the prior year, we believe that the current development of the Marcellus Shale and the New Albany Shale, and new horizontal drilling techniques will likely cause relatively high levels of natural gas-related drilling in these geological areas as producers seek to increase their level of natural gas production. Although the number of natural gas wells drilled in the United States has increased overall in recent years, a corresponding increase in production has not been realized, primarily as a result of smaller discoveries and the decline in production from existing wells. We believe that an increase in United States drilling activity, additional sources of supply such as liquefied natural gas and imports of natural gas will be required for the natural gas industry to meet the expected increased demand for, and to compensate for the slowing production of, natural gas in the United States. However, the areas in which we operate are experiencing a decline in the development of shallow wells, but a significant increase in drilling activity related to new and increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques, including horizontal and multiple fracturing techniques.
While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas reserves. Drilling activity generally decreases as natural gas prices decrease. We have no control over the level of drilling activity in the areas of our operations.

 

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Reserve Outlook
Our future oil and gas reserves, production, cash flow and our ability to make payments on ATN’s debt depend on our success in producing our current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. We face the challenge of natural production declines and volatile natural gas and oil prices. As initial reservoir pressures are depleted, natural gas production from particular wells decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. In order to sustain and grow our cash flow, we may need to make acquisitions.
RESULTS OF OPERATIONS
GAS AND OIL PRODUCTION
Production Profile. Currently, we have focused our natural gas production operations in various shale plays in the northeastern and midwestern United States. Notably, we are one of the leading producers in the Marcellus Shale, a rich, organic shale located in the Appalachia basin. The portion of the Marcellus Shale in southwestern Pennsylvania in which we focus our drilling is high-pressured and generally contains dry, pipeline-quality natural gas. In addition, we also are a leading natural gas producer in Michigan through our activity in the Antrim Shale, a biogenic shale play with a long-lived and shallow decline profile. We have also established a position in the New Albany Shale in southwestern Indiana, where we produce out of the biogenic region of the shale similar to the Antrim. We also produce from the Chattanooga Shale in northeastern Tennessee, which enables us to access other formations in that region such as the Monteagle and Ft. Payne Limestone.
Production Volumes. The following table shows our total net gas and oil production volumes and production per day during the three and nine months ended September 30, 2009 and 2008, respectively (in thousands, except for production per day):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Production:(1)(2)
                               
Appalachia:(3)
                               
Natural gas (MMcf)
    3,549       3,057       10,851       8,748  
Oil (000’s Bbls)
    42       39       120       112  
Total (MMcfe)
    3,801       3,291       11,571       9,420  
Michigan/Indiana:
                               
Natural gas (MMcf)
    5,384       5,561       15,910       16,373  
Oil (000’s Bbls)
    1       1       3       3  
Total (MMcfe)
    5,390       5,567       15,928       16,391  
Total:
                               
Natural gas (MMcf)
    8,933       8,618       26,761       25,121  
Oil (000’s Bbls)
    43       40       123       115  
Total (MMcfe)
    9,191       8,858       27,499       25,811  

 

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    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Production per day:(1)(2)
                               
Appalachia:(3)
                               
Natural gas (Mcfd)
    38,579       33,228       39,749       31,929  
Oil (Bpd)
    460       413       442       410  
Total (Mcfed)
    41,339       35,706       42,401       34,389  
Michigan/Indiana:
                               
Natural gas (Mcfd)
    58,519       60,436       58,277       59,755  
Oil (Bpd)
    9       11       9       11  
Total (Mcfed)
    58,573       60,502       58,331       59,821  
Total:
                               
Natural gas (Mcfd)
    97,098       93,664       98,026       91,684  
Oil (bpd)
    469       424       451       421  
Total (Mcfed)
    99,912       96,208       100,732       94,210  
 
     
(1)  
Production quantities consist of the sum of (i) our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells, and (ii) our proportionate share of production from wells owned by the investment partnerships in which we have an interest, based on our equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells.
 
(2)  
“MMcf” represents million cubic feet; “MMcfe” represent million cubic feet equivalents; “Mcfd” represents thousand cubic feet per day; “Mcfed” represents thousand cubic feet equivalents per day; and “Bbls” and “Bpd” represent barrels and barrels per day.
 
(3)  
Appalachia includes our production located in Pennsylvania, Ohio, New York, West Virginia, and Tennessee.
Production Revenues, Prices and Costs. Production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised 99% of our proved reserves on an energy equivalent basis at December 31, 2008. The following table shows our production revenues and average sales prices for our oil and gas production during the three and nine months ended September 30, 2009 and 2008, along with our average production costs, taxes, and transmission and compression costs in each of the reported periods:
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Production Revenues (in thousands):
                               
Appalachia:
                               
Natural gas
  $ 22,802     $ 30,430     $ 79,873     $ 85,440  
Oil
    3,185       3,868       8,265       11,753  
 
                       
Total
  $ 25,987     $ 34,298     $ 88,138     $ 97,193  
 
                       
Michigan/Indiana:
                               
Natural gas
  $ 39,946     $ 46,823     $ 119,646     $ 138,905  
Oil
    53       114       124       319  
 
                       
Total
  $ 39,999     $ 46,937     $ 119,770     $ 139,224  
 
                       
Total:
                               
Natural gas
  $ 62,748     $ 77,253     $ 199,519     $ 224,345  
Oil
    3,238       3,982       8,389       12,072  
 
                       
Total
  $ 65,986     $ 81,235     $ 207,908     $ 236,417  
 
                       
 
                               
Average Sales Price:
                               
Natural Gas:
                               
Appalachia:
                               
Total realized price, after hedge(2)
  $ 7.00     $ 9.95     $ 7.67     $ 9.76  
Total realized price, before hedge(2)
  $ 2.92     $ 11.13     $ 4.06     $ 10.62  
Michigan/Indiana:
                               
Total realized price, after hedge(1)
  $ 7.49     $ 8.88     $ 7.67     $ 9.13  

 

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    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Total realized price, before hedge
  $ 3.38     $ 10.15     $ 3.98     $ 9.71  
Total:
                               
Total realized price, after hedge(1)(2)
  $ 7.29     $ 9.26     $ 7.67     $ 9.35  
Total realized price, before hedge(2)
  $ 3.20     $ 10.49     $ 4.01     $ 10.03  
 
                               
Oil:
                               
Appalachia:
                               
Total realized price, after hedge
  $ 75.26     $ 101.07     $ 68.49     $ 104.04  
Total realized price, before hedge
  $ 62.81     $ 106.81     $ 52.33     $ 108.09  
Michigan/Indiana:
                               
Total realized price, after hedge
  $ 63.00     $ 111.72     $ 50.72     $ 108.36  
Total realized price, before hedge
  $ 63.00     $ 111.72     $ 50.72     $ 108.36  
Total:
                               
Total realized price, after hedge
  $ 75.03     $ 101.34     $ 68.13     $ 104.15  
Total realized price, before hedge
  $ 62.81     $ 106.94     $ 52.30     $ 108.09  
 
     
(1)  
Includes cash proceeds of $0.3 million and $2.6 million for the three months ended September 30, 2009 and 2008, respectively and $2.4 million and $10.5 million for the nine months ended September 30, 2009 and 2008, respectively, received from the settlement of ineffective derivative gains associated with the acquisition of our Michigan operations, but not reflected in the consolidated statements of operations for the respective periods.
 
(2)  
Excludes the impact of certain allocation of production revenue to investor partners within our investment partnerships. Including the effect of these allocations, average realized gas sales prices for the three and nine months ended September 30, 2009 for Appalachia were $6.42 per Mcf ($2.34 per Mcf before the effects of financial hedging) and $7.36 per Mcf ($3.75 before the effects of financial hedging), respectively, and in total were $7.06 per Mcf ($2.97 per Mcf before the effects of financial hedging) and $7.55 per Mcf ($3.89 per Mcf before the effects of financial hedging), respectively.
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Production Costs (per Mcfe):
                               
Appalachia:
                               
Lease operating expenses(1)
  $ 0.97     $ 1.08     $ 1.03     $ 0.98  
Production taxes
    0.01       0.04       0.03       0.04  
Transportation and compression
    0.77       1.18       0.79       0.94  
 
                       
 
  $ 1.75     $ 2.30     $ 1.85     $ 1.96  
 
                       
Michigan/Indiana:
                               
Lease operating expenses
  $ 0.69     $ 0.67     $ 0.70     $ 0.73  
Production taxes
    0.22       0.63       0.25       0.59  
Transportation and compression
    0.23       0.28       0.24       0.27  
 
                       
 
  $ 1.14     $ 1.58     $ 1.19     $ 1.59  
 
                       
Total:
                               
Lease operating expenses(1)
  $ 0.81     $ 0.82     $ 0.84     $ 0.82  
Production taxes
    0.14       0.41       0.16       0.39  
Transportation and compression
    0.45       0.61       0.47       0.52  
 
                       
 
  $ 1.40     $ 1.84     $ 1.47     $ 1.73  
 
                       
 
     
(1)  
Excludes the effects of the Company’s proportionate share of lease operating expenses associated with certain allocations of production revenue to investor partners within its investment partnerships. Including the effects of these costs, lease operating expenses per Mcfe for the three and nine months ended September 30, 2009 for Appalachia were $0.80 per Mcfe (total production costs per Mcfe were $1.58) and $0.94 per Mcfe (total production costs per Mcfe were $1.76), respectively, and in total they were $0.73 per Mcfe (total production costs per Mcfe were $1.32) and $0.80 per Mcfe (total production costs per Mcfe were $1.43), respectively.

 

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Total natural gas revenues were $62.8 million for the three months ended September 30, 2009, a decrease of $14.5 million from $77.3 million for the three months ended September 30, 2008. The $14.6 million decrease consisted of a $14.7 million decrease resulting from lower realized natural gas prices, $2.0 million of subordinated gas revenues during the current period to the investor partners within our investment partnerships, and a $2.2 million increase attributable to increases in natural gas production volumes. In accordance with the terms of our investment partnerships, we may be required to net revenues subordinated from the investment partnerships to the benefit of the investor partners in order to provide them with an amount equal to at least 10% of their subscriptions determined on a cumulative basis for the initial 5-year period after commencement of distributions from the investment partnerships, subject to certain limitations. Appalachian production volumes increased 5.4 MMcfd to 38.6 MMcfd for the three months ended September 30, 2009 when compared with the prior year comparable period, which was principally attributable to the increase in production we received from our Marcellus Shale wells and an increase in wells drilled in the most recent nine-month period as they were connected to gas gathering facilities and transportation pipelines. Total oil revenues were $3.2 million for the three months ended September 30, 2009, a decrease of $0.7 million from $3.9 million for the three months ended September 30, 2008. The decrease resulted primarily from a $1.0 million decrease from lower average realized oil prices, partially offset by a $0.3 million increase from the increase in production volumes.
Appalachia production costs were $6.0 million for the three months ended September 30, 2009, a decrease of $1.5 million from $7.5 million, before the elimination of the excess gathering fees prior to the Laurel Mountain joint venture (see “Transmission, gathering and processing”). This decrease principally consists of a $1.0 million decrease due to the Company’s proportionate share of lease operating expenses associated with its revenue that was subordinated to the investor partners within its investment partnerships and a $1.0 million decrease in transportation expense, partially offset by a $0.8 million increase in water hauling and disposal costs associated with an increase in the number of Marcellus Shale wells we drilled. The decrease in Appalachia transportation expense was related to the decline in natural gas prices, for which our wells are generally charged a percentage of the sales price received for the natural gas transported. Michigan/Indiana production costs were $6.1 million for the three months ended September 30, 2009, a decrease of $2.7 million from $8.8 million for the three months ended September 30, 2008. This decrease was primarily attributable to a $2.3 million decrease in production taxes due to a state reduction in the production tax rate on January 1, 2009.
Total natural gas revenues were $199.5 million for the nine months ended September 30, 2009, a decrease of $24.8 million from $224.4 million for the nine months ended September 30, 2008. This decrease consisted of $33.7 million decrease attributable to lower realized natural gas prices and $3.3 million of gas revenues subordinated to the investor partners within our investment partnerships, partially offset by a $12.2 million increase attributable to a higher natural gas production volumes. Appalachian production volumes increased 7.8 MMcfd to 39.7 MMcfd for the nine months ended September 30, 2009 when compared to the prior year comparable period, which was principally attributable to the increase in production we received from our Marcellus Shale wells and wells drilled in the most recent nine-month period as they were connected to gas gathering facilities and transportation pipelines. Total oil revenues were $8.4 million for the nine months ended September 30, 2009, a decrease of $3.6 million from $12.0 million for the nine months ended September 30, 2008. This decrease resulted primarily from a $4.2 million decrease associated with lower average realized oil prices, partially offset by a $0.5 million increase associated with higher production volumes.

 

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Appalachia production costs were $14.1 million for the nine months ended September 30, 2009, an increase of $4.6 million from $9.5 million for the nine months ended September 30, 2008. This increase was principally due to a $2.5 million increase in water hauling and disposal costs and a $0.8 million increase associated with an increase in the number of Marcellus Shale wells we drilled from the prior year comparable period, partially offset by a decrease of $1.4 million associated with the Company’s proportionate share of lease operating expenses associated with its revenue that was subordinated to the investor partners within its investment partnerships. Michigan/Indiana production costs were $19.1 million for the nine months ended September 30, 2009, a decrease of $7.1 million from $26.2 million for the nine months ended September 30, 2008. This decrease was primarily attributable to a $5.7 million decrease in production taxes due to a state reduction in the production tax rate on January 1, 2009 and other production cost decreases when compared with the prior year comparable period.
PARTNERSHIP MANAGEMENT
Well Construction and Completion
Drilling Program Results. The number of wells we drill will vary depending on the amount of money we raise through our investment partnerships, the cost of each well, the depth or type of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. The following table presents the number of gross and net development wells we drilled exclusively for us and for our investment partnerships during the three and nine months ended September 30, 2009 and 2008. We did not drill any exploratory wells during the three and nine months ended September 30, 2009 and 2008.
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Gross:
                               
Appalachia
    27       242       153       733  
Michigan/Indiana
    11       49       51       135  
 
                       
 
    38       291       204       868  
 
                       
Net:
                               
Appalachia
    26       242       126       672  
Michigan/Indiana
    11       49       44       135  
 
                       
 
    37       291       170       807  
 
                       
Well construction and completion revenues and costs and expenses incurred represent the billings and costs associated with the completion of wells for investment partnerships we sponsor. The following table sets forth information relating to these revenues and the related costs and number of net wells drilled and completed during the periods indicated (dollars in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Average construction and completion:
                               
Revenue per well
  $ 2,328     $ 483     $ 1,487     $ 511  
Cost per well
    1,975       420       1,261       444  
 
                       
Gross profit per well
  $ 353     $ 63     $ 226     $ 67  
 
                       
 
Gross profit margin
  $ 12,358     $ 15,260     $ 38,995     $ 44,800  
 
                       
 
                               
Net wells drilled and completed:
                               
Marcellus Shale
    22       26       64       68  
Chattanooga Shale
    4       30       9       75  
Michigan/Indiana
    11             44        
Other — shallow
          186       53       529  
 
                       
 
    37       242       170       672  
 
                       

 

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Well construction and completion segment margin was $12.4 million for the three months ended September 30, 2009, a decrease of $2.9 million from $15.3 million for the three months ended September 30, 2008. This decrease was due to a $73.0 million decrease associated with a decrease in the number of wells drilled, partially offset by a $70.1 million increase associated with the an increase in the gross profit per well. Since our drilling contracts are on a “cost-plus” basis (typically cost-plus 18%), an increase in our average cost per well also results in a proportionate increase in our average revenue per well, which directly affects the number of wells we drill. Average cost and revenue per well have increased due to a shift from drilling less expensive shallow wells to more expensive deep or horizontal shale wells in Appalachia and in Michigan/Indiana during the three and nine months ended September 30, 2009 in comparison to the prior year comparable periods.
Well construction and completion segment margin was $39.0 million for the nine months ended September 30, 2009, a decrease of $5.8 million from $44.8 million for the nine months ended September 30, 2008. The decrease in segment margin was due to a $112.5 million decrease associated with a decrease in the number of wells drilled, partially offset by a $106.7 million increase associated with an increase in the gross profit per well.
Our consolidated balance sheet at September 30, 2009 includes $16.6 million of “liabilities associated with drilling contracts” for funds raised by our investment partnerships that have not been applied to the completion of wells due to the timing of drilling operations, and thus had not been recognized as well construction and completion revenue on our consolidated statements of operations. We expect to recognize this amount as revenue during the fourth quarter of 2009.
Administration and Oversight
Administration and oversight represents supervision and administrative fees earned for the drilling and subsequent ongoing management of wells for our investment partnerships. Administration and oversight fees were $3.1 million for the three months ended September 30, 2009, a decrease of $2.1 million from $5.2 million for the three months ended September 30, 2008. This decrease was due to a decrease in the number of wells drilled during the period in comparison to the prior year. Administration and oversight fees were $9.6 million for the nine months ended September 30, 2009, a decrease of $5.8 million from $15.4 million for the nine months ended September 30, 2008. This decrease was primarily a result of a decrease associated with fewer wells drilled during the period in comparison to the prior year.
Well Services
Well service revenue and expenses represent the monthly operating fees we charge and the work our service company performs for our investment partnership wells during the drilling and completing phase as well as ongoing maintenance of these wells and other wells in which we serve as operator.
Well services revenues were $5.0 million for the three months ended September 30, 2009, a decrease of $0.3 million from $5.3 million for the three months ended September 30, 2008. This decrease was principally attributable to the slowdown in drilling for shallow wells for our investment partnerships. Well services expenses were $2.4 million for the three months ended September 30, 2009, a decrease of $0.4 million from $2.8 million for the three months ended September 30, 2008. This decrease was primarily attributable to a decrease in labor costs associated with drilling a large number of shallow wells in prior periods to fewer, but more productive, wells for our investment partnerships during the current period.

 

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Well services revenues were $14.9 million for the nine months ended September 30, 2009, a decrease of $0