##### Table of Contents



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
 Washington, D.C. 20549
 FORM 10-Q
  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.
  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)
 (412) 262-2830
 ATLAS AMERICA, INC.
 (Former name, Former address and former fiscal year, if changed since last report)
 þ o
 o o
  Large accelerated filer þ
    
    Accelerated filer o
    
    Non-accelerated filer o
    
    Smaller reporting company o(Do not check if smaller reporting company)
 Yes o No þ




---



##### 



ATLAS ENERGY, INC. AND SUBSIDIARIES
INDEX TO QUARTERLY REPORT
ON FORM 10-Q
 PAGEPART I. FINANCIAL INFORMATIONItem 1. Financial Statements (Unaudited)Consolidated Balance Sheets as of September 30, 2009 and
December 31, 2008
    
    
    3Consolidated Statements of Operations for the Three and
Nine Months Ended September 30, 2009 and 2008
    
    
    4Consolidated Statement of Stockholders Equity for the Nine
Months Ended September 30, 2009
    
    
    6Consolidated Statements of Cash Flows for the Nine Months
Ended September 30, 2009 and 2008
    
    
    7Notes to Consolidated Financial Statements
    
    
    9Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
    
    
    63Item 3. Quantitative and Qualitative Disclosures About Market Risk
    
    
    90Item 4. Controls and Procedures
    
    
    100PART II. OTHER INFORMATIONItem 1. Legal Proceedings
    
    
    101Item 1A. Risk Factors
    
    
    102Item 4. Submission of Matters to a Vote of Security Holders
    
    
    102Item 6. Exhibits
    
    
    103SIGNATURES
    
    
    107Exhibit 31.1Exhibit 31.2Exhibit 32.1Exhibit 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
    
    
    2008ASSETSCurrent assets:Cash and cash equivalents
    
    $
    35,693
    
    
    $
    104,496Accounts receivable
    
    
    145,548
    
    
    
    169,405Current portion of derivative receivable from Partnerships
    
    
    346
    
    
    
    3,022Current portion of derivative asset
    
    
    88,960
    
    
    
    152,726Prepaid expenses and other
    
    
    27,900
    
    
    
    25,464Prepaid and deferred income taxes
    
    
    881
    
    
    
    32,215Current assets of discontinued operations
    
    
    
    
    
    
    13,441Total current assets
    
    
    299,328
    
    
    
    500,769Property, plant and equipment, net
    
    
    3,708,389
    
    
    
    3,744,815Intangible assets, net
    
    
    177,539
    
    
    
    197,485Goodwill, net
    
    
    35,166
    
    
    
    35,166Long-term derivative receivable from Partnerships
    
    
    4,740
    
    
    
    2,719Long term derivative asset
    
    
    42,405
    
    
    
    69,451Investment in joint venture
    
    
    133,740
    
    
    
    Other assets, net
    
    
    70,419
    
    
    
    53,311Long-term assets of discontinued operations
    
    
    
    
    
    
    242,165$
    4,471,726
    
    
    $
    4,845,881LIABILITIES AND STOCKHOLDERS EQUITYCurrent liabilities:Current portion of long-term debt
    
    $
    12,000
    
    
    $
    Accounts payable
    
    
    105,929
    
    
    
    140,725Liabilities associated with drilling contracts
    
    
    16,590
    
    
    
    96,883Accrued producer liabilities
    
    
    45,539
    
    
    
    66,846Current portion of derivative payable to Partnerships
    
    
    23,173
    
    
    
    34,933Current portion of derivative liability
    
    
    46,570
    
    
    
    73,776Accrued liabilities
    
    
    165,391
    
    
    
    103,383Advances from affiliate
    
    
    219
    
    
    
    108Current liabilities of discontinued operations
    
    
    
    
    
    
    10,572Total current liabilities
    
    
    415,411
    
    
    
    527,226Long-term debt, less current portion
    
    
    2,115,505
    
    
    
    2,413,082Deferred tax liability
    
    
    51,158
    
    
    
    242,058Long-term derivative payable to Partnerships
    
    
    17,021
    
    
    
    22,581Long-term derivative liability
    
    
    33,847
    
    
    
    59,103Other long-term liabilities
    
    
    54,941
    
    
    
    52,263Commitments and contingenciesStockholders equity:Preferred stock, $0.01 par value: 1,000,000 authorized shares
    
    
    
    
    
    
    Common stock, $0.01 par value: 114,000,000 authorized shares
    
    
    814
    
    
    
    426Additional paid-in capital
    
    
    1,137,546
    
    
    
    412,869Treasury stock, at cost
    
    
    (143,362
    )
    
    
    (147,621
    )Accumulated other comprehensive income
    
    
    50,351
    
    
    
    21,143Retained earnings
    
    
    136,027
    
    
    
    124,6981,181,376
    
    
    
    411,515Non-controlling interests
    
    
    602,467
    
    
    
    1,118,053Total stockholders equity
    
    
    1,783,843
    
    
    
    1,529,568$
    4,471,726
    
    
    $
    4,845,881
   3




---



##### Table of Contents



ATLAS ENERGY, INC. AND SUBSIDIARIES
 
 CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
 (Unaudited)
 Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Revenues:Well construction and completion
    
    $
    81,496
    
    
    $
    116,987
    
    
    $
    257,231
    
    
    $
    343,466Gas and oil production
    
    
    65,986
    
    
    
    81,235
    
    
    
    207,908
    
    
    
    236,417Transmission, gathering and processing
    
    
    205,603
    
    
    
    410,942
    
    
    
    555,373
    
    
    
    1,218,359Administration and oversight
    
    
    3,149
    
    
    
    5,216
    
    
    
    9,644
    
    
    
    15,370Well services
    
    
    5,012
    
    
    
    5,299
    
    
    
    14,911
    
    
    
    15,363Gain 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
    
    
    
    11,842Total revenues
    
    
    367,184
    
    
    
    771,002
    
    
    
    1,145,264
    
    
    
    1,583,473Costs and expenses:Well construction and completion
    
    
    69,138
    
    
    
    101,727
    
    
    
    218,236
    
    
    
    298,666Gas and oil production
    
    
    12,128
    
    
    
    12,688
    
    
    
    33,217
    
    
    
    35,735Transmission, gathering and processing
    
    
    167,862
    
    
    
    333,988
    
    
    
    470,752
    
    
    
    992,504Well services
    
    
    2,378
    
    
    
    2,753
    
    
    
    6,922
    
    
    
    7,815General and administrative
    
    
    31,786
    
    
    
    12,392
    
    
    
    80,777
    
    
    
    57,903Net expense reimbursement  affiliate
    
    
    280
    
    
    
    255
    
    
    
    842
    
    
    
    689Depreciation, depletion and amortization
    
    
    46,460
    
    
    
    44,325
    
    
    
    147,427
    
    
    
    129,539Total costs and expenses
    
    
    330,032
    
    
    
    508,128
    
    
    
    958,173
    
    
    
    1,522,851Operating income
    
    
    37,152
    
    
    
    262,874
    
    
    
    187,091
    
    
    
    60,622Interest 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
    
    
    
    12,288Net 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
    
    
    
    20,181Net income (loss)
    
    
    (9,886
    )
    
    
    218,157
    
    
    
    116,983
    
    
    
    (38,023
    )(Income) loss attributable to non-controlling
interests
    
    
    9,172
    
    
    
    (194,054
    )
    
    
    (103,686
    )
    
    
    60,777Net income (loss) attributable to common
shareholders
    
    $
    (714
    )
    
    $
    24,103
    
    
    $
    13,297
    
    
    $
    22,754
  4




---



##### Table of Contents



Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Net income (loss) attributable to common
shareholders per share  basic:Income (loss) from continuing
operations attributable to common
shareholders
    
    $
    (0.02
    )
    
    $
    0.59
    
    
    $
    0.23
    
    
    $
    0.54Discontinued operations attributable
to common shareholders
    
    
    0.00
    
    
    
    0.01
    
    
    
    0.11
    
    
    
    0.03Net income (loss) attributable to
common shareholders
    
    $
    (0.02
    )
    
    $
    0.60
    
    
    $
    0.34
    
    
    $
    0.57Net income (loss) attributable to common
shareholders per share  diluted:Income (loss) from continuing
operations attributable to common
shareholders
    
    $
    (0.02
    )
    
    $
    0.57
    
    
    $
    0.22
    
    
    $
    0.51Discontinued operations attributable
to common shareholders
    
    
    0.00
    
    
    
    0.01
    
    
    
    0.11
    
    
    
    0.03Net income (loss) attributable to
common shareholders
    
    $
    (0.02
    )
    
    $
    0.58
    
    
    $
    0.33
    
    
    $
    0.54Weighted average common shares outstanding:Basic
    
    
    39,780
    
    
    
    40,093
    
    
    
    39,460
    
    
    
    40,251Diluted
    
    
    39,780
    
    
    
    41,994
    
    
    
    40,051
    
    
    
    42,121Income (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
    
    
    $
    21,431Discontinued 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
    
    
    
    1,323Net income (loss) attributable to common
shareholders
    
    $
    (714
    )
    
    $
    24,103
    
    
    $
    13,297
    
    
    $
    22,754
   5




---



##### Table of Contents



ATLAS ENERGY, INC. AND SUBSIDIARIES
 
 CONSOLIDATED STATEMENT OF STOCKHOLDERS EQUITY
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2009
 (in thousands, except share data)
(Unaudited)
 AccumulatedAdditional
    
    
    
    
    
    
    
    
    
    
    Other
    
    
    
    
    
    
    Non-
    
    
    TotalCommon Stock
    
    
    Paid-In
    
    
    Treasury Stock
    
    
    Comprehensive
    
    
    Retained
    
    
    controlling
    
    
    StockholdersShares
    
    
    Amount
    
    
    Capital
    
    
    Shares
    
    
    Amount
    
    
    Income
    
    
    Earnings
    
    
    Interests
    
    
    EquityBalance at January 1, 2009
    
    
    42,503,119
    
    
    $
    426
    
    
    $
    412,869
    
    
    
    (3,252,861
    )
    
    $
    (147,621
    )
    
    $
    21,143
    
    
    $
    124,698
    
    
    $
    1,118,053
    
    
    $
    1,529,568Common stock issuance
    
    
    24,425
    
    
    
    
    
    
    
    (2,684
    )
    
    
    98,829
    
    
    
    4,259
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,575Other comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    29,208
    
    
    
    
    
    
    
    (14,230
    )
    
    
    14,978Stock option and unit
compensation expense
    
    
    (40,600
    )
    
    
    
    
    
    
    2,550
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,550Merger with Atlas Energy
Resources LLC
    
    
    38,776,768
    
    
    
    388
    
    
    
    724,811
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (556,384
    )
    
    
    168,815Dividends 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
    
    
    
    116,983Balance 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
   6




---



##### Table of Contents



ATLAS ENERGY, INC. AND SUBSIDIARIES
 
 CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
 (Unaudited)
 Nine Months EndedSeptember 30,2009
    
    
    2008CASH FLOWS FROM OPERATING ACTIVITIES:Net income (loss)
    
    $
    116,983
    
    
    $
    (38,023
    )Income from discontinued operations
    
    
    59,769
    
    
    
    20,181Income (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
    
    
    
    129,539Amortization of deferred finance costs
    
    
    9,439
    
    
    
    5,925Non-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
    
    
    
    688Equity income in joint venture
    
    
    (2,140
    )
    
    
    Distributions received from joint venture
    
    
    1,657
    
    
    
    Deferred income taxes
    
    
    1,185
    
    
    
    15,621Changes 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
    
    
    
    47Other operating assets/liabilities
    
    
    (161
    )
    
    
    29Net cash provided by (used in) continuing operations operating
activities
    
    
    109,779
    
    
    
    (178,763
    )Net cash provided by discontinued operations operating activities
    
    
    14,209
    
    
    
    36,626Net 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
    
    
    
    
    
    
    31,429Investment in Lightfoot Capital Partners, L.P.
    
    
    (26
    )
    
    
    (437
    )Proceeds from asset sales
    
    
    120,644
    
    
    
    63Other
    
    
    (9,003
    )
    
    
    851Net 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
    
    
    
    908,000Repayments 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
    
    
    
    407,125Issuance of Atlas Pipeline Partners, L.P. long-term debt
    
    
    
    
    
    
    244,854Repayments 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
    
    
    
    
    
    
    82,514Net proceeds from Atlas Pipeline Partners, L.P. equity offering
    
    
    16,142
    
    
    
    206,901
  7




---



##### Table of Contents



Nine Months EndedSeptember 30,2009
    
    
    2008Dividends 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
    )
    
    
    560,930Net change in cash and cash equivalents
    
    
    (68,803
    )
    
    
    (20,665
    )Cash and cash equivalents, beginning of period
    
    
    104,496
    
    
    
    145,896Cash and cash equivalents, end of period
    
    $
    35,693
    
    
    $
    125,231
   8




---



##### Table of Contents



ATLAS ENERGY, INC. AND SUBSIDIARIES
 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2009
 (Unaudited)
 NOTE 1  BASIS OF PRESENTATION
   
    
    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.
   9




---



##### Table of Contents



NOTE 2  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
  Principles of Consolidation and Non-controlling Interest
     10




---



##### Table of Contents



Use of Estimates
   Impairment of Long-Lived Assets
     11




---



##### Table of Contents











Capitalized Interest




Intangible Assets


Customer contracts and relationships.  12




---



##### Table of Contents



Partnership management, operating contracts and non-compete agreement.
  EstimatedSeptember 30,
    
    
    December 31,
    
    
    Useful Lives2009
    
    
    2008
    
    
    In YearsGross Carrying Amount:Customer contracts and relationships
    
    $
    235,382
    
    
    $
    235,382
    
    
    
    7 - 20Partnership management and operating contracts
    
    
    14,343
    
    
    
    14,343
    
    
    
    2 - 13Non-compete agreement
    
    
    890
    
    
    
    890$
    250,615
    
    
    $
    250,615Accumulated 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
    
    
    $
    193,647Partnership management and operating contracts
    
    
    3,059
    
    
    
    3,615Non-compete agreement
    
    
    
    
    
    
    223$
    177,539
    
    
    $
    197,485
  Goodwill
  Nine Months EndedSeptember 30,2009
    
    
    2008Balance, beginning of period
    
    $
    35,166
    
    
    $
    744,449APL 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
  13




---



##### Table of Contents



Net Income (Loss) Per Share
  Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008(1)
    
    
    2009
    
    
    2008(1)Weighted average number of shares  basic
    
    
    39,780
    
    
    
    40,093
    
    
    
    39,460
    
    
    
    40,251Add: effect of dilutive incentive awards
    
    
    
    
    
    
    1,901
    
    
    
    591
    
    
    
    1,870Weighted 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.  14




---



##### Table of Contents



Revenue Recognition
   Atlas Pipeline.
 
    
    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.
  15




---



##### Table of Contents



Comprehensive Income (Loss)
  Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Net income (loss)
    
    $
    (9,886
    )
    
    $
    218,157
    
    
    $
    116,983
    
    
    $
    (38,023
    )(Income) loss attributable to
non-controlling interests
    
    
    9,172
    
    
    
    (194,054
    )
    
    
    (103,686
    )
    
    
    60,777Net income (loss) attributable to
common shareholders
    
    
    (714
    )
    
    
    24,103
    
    
    
    13,297
    
    
    
    22,754Other 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
    )
    
    
    63,398Changes in non-controlling interest
related to items in other
comprehensive income (loss)
    
    
    49,653
    
    
    
    (180,054
    )
    
    
    14,231
    
    
    
    44,256Plus: 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
    
    
    
    296Total 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
  16




---



##### Table of Contents



Recently Adopted Accounting Standards
     17




---



##### Table of Contents



18
    Table of Contents        19




---



##### Table of Contents



Recently Issued Accounting Standards
   Modernization of Oil and Gas Reporting
  
    
    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.
  20




---



##### Table of Contents




    
    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.
  NOTE 3  COMMON STOCK
 Merger with Atlas Energy Resources, LLC
    Authorized Shares
   21




---



##### Table of Contents



Stock Repurchase Plan
  Stock Splits
   Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Revenue
    
    $
    367,184
    
    
    $
    771,002
    
    
    $
    1,145,264
    
    
    $
    1,583,473Income attributable to common shareholders:Income from continuing operations
    
    $
    562
    
    
    $
    36,495
    
    
    $
    18,591
    
    
    $
    59,568Discontinued operations
    
    
    
    
    
    
    433
    
    
    
    4,253
    
    
    
    1,323Net income attributable to common shareholders
    
    $
    562
    
    
    $
    36,928
    
    
    $
    22,844
    
    
    $
    60,891Net income attributable to common
shareholders per share  basic:Income from continuing operations
attributable to common shareholders
    
    $
    0.01
    
    
    $
    0.46
    
    
    $
    0.24
    
    
    $
    0.75Discontinued operations attributable to
common shareholders
    
    
    0.00
    
    
    
    0.01
    
    
    
    0.05
    
    
    
    0.02Net income attributable to common shareholders
    
    $
    0.01
    
    
    $
    0.47
    
    
    $
    0.29
    
    
    $
    0.77Net income attributable to common
shareholders per share  diluted:Income from continuing operations
attributable to common shareholders
    
    $
    0.01
    
    
    $
    0.44
    
    
    $
    0.24
    
    
    $
    0.73Discontinued operations attributable to
common shareholders
    
    
    0.00
    
    
    
    0.01
    
    
    
    0.05
    
    
    
    0.02Net income attributable to common shareholders
    
    $
    0.01
    
    
    $
    0.45
    
    
    $
    0.29
    
    
    $
    0.75Weighted average common shares outstanding:Basic
    
    
    78,136
    
    
    
    78,869
    
    
    
    78,095
    
    
    
    79,027Diluted
    
    
    79,144
    
    
    
    81,307
    
    
    
    78,714
    
    
    
    81,451
  22




---



##### Table of Contents



NOTE 4  APL INVESTMENT IN JOINT VENTURE
   Three Months
    
    
    Nine MonthsEnded
    
    
    EndedSeptember 30, 2009
    
    
    September 30, 2009(1)Statement of Operations data:Total revenue
    
    $
    9,622
    
    
    $
    12,690Net income
    
    
    2,386
    
    
    
    3,664
 September 30, 2009Balance Sheet data:Current assets
    
    $
    9,871Long-term assets
    
    
    245,577Current liabilities
    
    
    19,303Long-term liabilities
    
    
    8,500Net equity
    
    
    227,645
 
 (1)
    
    Represents the period from May 31, 2009, the date of initial formation,
through September 30, 2009.  23




---



##### Table of Contents



NOTE 5  DISCONTINUED OPERATIONS
  Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Total revenues
    
    $
    
    
    
    $
    13,468
    
    
    $
    21,274
    
    
    $
    45,827Total costs and expenses
    
    
    
    
    
    
    (6,930
    )
    
    
    (9,858
    )
    
    
    (24,798
    )Income before income tax expense
    
    
    
    
    
    
    6,538
    
    
    
    11,416
    
    
    
    21,029Income tax expense
    
    
    
    
    
    
    (277
    )
    
    
    (498
    )
    
    
    (848
    )Income from discontinued operations
    
    $
    
    
    
    $
    6,261
    
    
    $
    10,918
    
    
    $
    20,181
  December 31,2008Cash and cash equivalents
    
    $
    75Accounts receivable
    
    
    12,365Prepaid expenses and other
    
    
    1,001Total current assets of discontinued operations
    
    
    13,441Property, plant and equipment, net
    
    
    241,926Other assets, net
    
    
    239Total assets of discontinued operations
    
    $
    255,606Accounts payable
    
    $
    4,120Accrued liabilities
    
    
    5,892Accrued producer liabilities
    
    
    560Total current liabilities of discontinued
operations
    
    $
    10,572
  24




---



##### Table of Contents



NOTE 6  PROPERTY, PLANT AND EQUIPMENT
   EstimatedSeptember 30,
    
    
    December 31,
    
    
    Useful Lives2009
    
    
    2008(1)
    
    
    in YearsNatural gas and oil properties:Proved properties:Leasehold interests
    
    $
    1,237,331
    
    
    $
    1,214,991Pre-development costs
    
    
    14,750
    
    
    
    18,772Wells and related equipment
    
    
    970,063
    
    
    
    872,128Total proved properties
    
    
    2,222,144
    
    
    
    2,105,891Unproved properties
    
    
    43,279
    
    
    
    43,749Support equipment
    
    
    8,605
    
    
    
    9,527Total natural gas and oil properties
    
    
    2,274,028
    
    
    
    2,159,167Pipelines, processing and compression facilities
    
    
    1,671,863
    
    
    
    1,728,472
    
    
    
    15 - 40Rights of way
    
    
    166,874
    
    
    
    168,206
    
    
    
    20 - 40Land, buildings and improvements
    
    
    24,593
    
    
    
    24,385
    
    
    
    10 - 40Other
    
    
    21,867
    
    
    
    22,108
    
    
    
    3 - 104,159,225
    
    
    
    4,102,338Less  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)     25




---



##### Table of Contents







NOTE 7  OTHER ASSETS




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
    
    
    $
    38,871Investment in Lightfoot LP, Lightfoot GP and Magnetar LP
    
    
    8,442
    
    
    
    10,779Other investments
    
    
    5,988
    
    
    
    1,994Long-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)





NOTE 8  ASSET RETIREMENT OBLIGATIONS


26




---



##### Table of Contents



Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Asset retirement obligations, beginning of period
    
    $
    50,142
    
    
    $
    45,334
    
    
    $
    48,136
    
    
    $
    42,358Liabilities incurred
    
    
    125
    
    
    
    975
    
    
    
    721
    
    
    
    2,615Liabilities settled
    
    
    (113
    )
    
    
    (36
    )
    
    
    (198
    )
    
    
    (38
    )Accretion expense
    
    
    753
    
    
    
    687
    
    
    
    2,248
    
    
    
    2,025Asset retirement obligations, end of period
    
    $
    50,907
    
    
    $
    46,960
    
    
    $
    50,907
    
    
    $
    46,960
  NOTE 9  DEBT
  September 30,
    
    
    December 31,2009
    
    
    2008ATN revolving credit facility
    
    $
    270,000
    
    
    $
    467,000ATN 10.75% senior notes  due 2018
    
    
    406,105
    
    
    
    406,655ATN 12.125% senior notes  due 2017
    
    
    196,350
    
    
    
    AHD credit facility
    
    
    12,000
    
    
    
    46,000APL revolving credit facility
    
    
    315,000
    
    
    
    302,000APL term loan
    
    
    433,505
    
    
    
    707,180APL 8.125% senior notes  due 2015
    
    
    271,495
    
    
    
    261,197APL 8.75% senior notes  due 2018
    
    
    223,050
    
    
    
    223,050Total debt
    
    
    2,127,505
    
    
    
    2,413,082Less current maturities
    
    
    (12,000
    )
    
    
    Total long-term debt
    
    $
    2,115,505
    
    
    $
    2,413,082
  27




---



##### Table of Contents



ATN Revolving Credit Facility
    ATN Senior Notes
   28




---



##### Table of Contents



AHD Credit Facility
  
    
    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%.
   29




---



##### Table of Contents



APL Term Loan and Revolving Credit Facility
   
    
    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;
  30




---



##### Table of Contents




    
    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.
    31




---



##### Table of Contents



Maximum
    
    
    MinimumMaximum
    
    
    Senior Secured
    
    
    InterestLeverage
    
    
    Leverage
    
    
    CoverageFiscal quarter ending:
    
    Ratio
    
    
    Ratio
    
    
    RatioSeptember 30, 2009
    
    
    6.50x
    
    
    
    3.75x
    
    
    
    2.50xDecember 31, 2009
    
    
    8.50x
    
    
    
    5.25x
    
    
    
    1.70xMarch 31, 2010
    
    
    9.25x
    
    
    
    5.75x
    
    
    
    1.40xJune 30, 2010
    
    
    8.00x
    
    
    
    5.00x
    
    
    
    1.65xSeptember 30, 2010
    
    
    7.00x
    
    
    
    4.25x
    
    
    
    1.90xDecember 31, 2010
    
    
    6.00x
    
    
    
    3.75x
    
    
    
    2.20xThereafter
    
    
    5.00x
    
    
    
    3.00x
    
    
    
    2.75x
  APL Senior Notes
     32




---



##### Table of Contents



NOTE 10  DERIVATIVE INSTRUMENTS
      33




---



##### Table of Contents



Fair Value of Derivative Instruments:
 Asset Derivatives
    
    
    Liability DerivativesDerivatives in
    
    
    
    Fair Value
    
    
    
    
    Fair ValueCash 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 EndedCash 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 EndedCash 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
    )
    34




---



##### Table of Contents



Interest Fixed Rate Swap
 ContractNotional
    
    
    
    
    
    
    Period Ended
    
    
    Fair ValueTerm
    
    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
 ProductionPeriod Ending
    
    
    
    
    
    Average
    
    
    Fair ValueDecember 31,
    
    Volumes
    
    
    Fixed Price
    
    
    Asset(2)(MMBtu) (1)
    
    
    (per MMBtu)(1)
    
    
    (in thousands)2009
    
    
    10,340,000
    
    
    $
    8.242
    
    
    $
    36,1162010
    
    
    31,880,000
    
    
    $
    7.708
    
    
    
    47,6822011
    
    
    20,720,000
    
    
    $
    7.040
    
    
    
    3,4032012
    
    
    19,680,000
    
    
    $
    7.223
    
    
    
    4,1192013
    
    
    13,260,000
    
    
    $
    7.082
    
    
    
    235$
    91,555
  35




---



##### Table of Contents



Natural Gas Costless Collars
 ProductionPeriod Ending
    
    
    
    
    
    
    
    Average
    
    
    Fair ValueDecember 31,
    
    Option Type
    
    Volumes
    
    
    Floor and Cap
    
    
    Asset/(Liability) (1)(MMBtu)(1)
    
    
    (per MMBtu)(1)
    
    
    (in thousands)2009
    
    Puts purchased
    
    
    60,000
    
    
    $
    11.000
    
    
    $
    3702009
    
    Calls sold
    
    
    60,000
    
    
    $
    15.350
    
    
    
    2010
    
    Puts purchased
    
    
    3,360,000
    
    
    $
    7.839
    
    
    
    6,0212010
    
    Calls sold
    
    
    3,360,000
    
    
    $
    9.007
    
    
    
    2011
    
    Puts purchased
    
    
    9,540,000
    
    
    $
    6.523
    
    
    
    8082011
    
    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
 ProductionPeriod Ending
    
    
    
    
    
    Average
    
    
    Fair ValueDecember 31,
    
    Volumes
    
    
    Fixed Price
    
    
    Asset/(Liability) (3)(Bbl)(1)
    
    
    (per Bbl)(1)
    
    
    (in thousands)2009
    
    
    14,600
    
    
    $
    99.319
    
    
    $
    4242010
    
    
    48,900
    
    
    $
    97.400
    
    
    
    1,1342011
    
    
    42,600
    
    
    $
    77.460
    
    
    
    112012
    
    
    33,500
    
    
    $
    76.855
    
    
    
    (74
    )2013
    
    
    10,000
    
    
    $
    77.360
    
    
    
    (29
    )$
    1,466
 Crude Oil Costless Collars
 ProductionPeriod Ending
    
    
    
    
    
    
    
    Average
    
    
    Fair ValueDecember 31,
    
    Option Type
    
    Volumes
    
    
    Floor and Cap
    
    
    Asset/(Liability) (3)(Bbl)(1)
    
    
    (per Bbl)(1)
    
    
    (in thousands)2009
    
    Puts purchased
    
    
    9,000
    
    
    $
    85.000
    
    
    $
    1342009
    
    Calls sold
    
    
    9,000
    
    
    $
    116.561
    
    
    
    2010
    
    Puts purchased
    
    
    31,000
    
    
    $
    85.000
    
    
    
    4682010
    
    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
    )$
    481Total 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.  36




---



##### Table of Contents



Atlas Pipeline Holdings and Atlas Pipeline Partners
   Early Termination of Derivative ContractsThree Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Net 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
    )
   37




---



##### Table of Contents



Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Loss 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
    
    
    
    41,271Gain (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.  September 30, 2009Asset Derivatives
    
    
    Liability DerivativesBalance Sheet
    
    
    
    
    
    Balance SheetLocation
    
    Fair Value
    
    
    Location
    
    Fair ValueDerivatives not
designated as hedging
instruments:Interest rate contracts
    
    N/A
    
    $
    
    
    
    Current portion of derivative liability
    
    $
    (6,352
    )Commodity contracts
    
    Current portion of derivative asset
    
    
    4,514Commodity contracts
    
    Long-term derivative asset
    
    
    1,980Commodity 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
    )
  38




---



##### Table of Contents



Derivatives not designated as hedging instrumentsThree months ended September 30, 2009Gain (Loss)
    
    
    Gain (Loss) Reclassified from
    
    Gain (Loss) Recognized in IncomeRecognized in
    
    
    Accumulated OCI into Income
    
    (Ineffective Portion and AmountAccumulated
    
    
    (Effective Portion)
    
    Excluded from Effectiveness Testing)OCI
    
    
    Amount
    
    
    Location
    
    Amount
    
    
    LocationInterest rate contracts(1)
    
    $
    30
    
    
    $
    (3,419
    )
    
    Interest expense
    
    $
    (951
    )
    
    Gain (loss) on mark-to-market derivativesCommodity contracts(1)
    
    
    
    
    
    
    (10,294
    )
    
    Transmission, gathering and processing revenue
    
    
    (13,671
    )
    
    Gain (loss) on mark-to-market derivativesCommodity 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 instrumentsNine months ended September 30, 2009Gain (Loss)
    
    
    Gain (Loss) Reclassified from
    
    Gain (Loss) Recognized in IncomeRecognized in
    
    
    Accumulated OCI into Income
    
    (Ineffective Portion and AmountAccumulated
    
    
    (Effective Portion)
    
    Excluded from Effectiveness Testing)OCI
    
    
    Amount
    
    
    Location
    
    Amount
    
    
    LocationInterest rate contracts(1)
    
    $
    (2,411
    )
    
    $
    (9,599
    )
    
    Interest expense
    
    $
    (1,147
    )
    
    Gain (loss) on mark-to-market derivativesCommodity contracts(1)
    
    
    
    
    
    
    (37,158
    )
    
    Transmission, gathering and processing revenue
    
    
    (36,579
    )
    
    Gain (loss) on mark-to-market derivativesCommodity contracts(2)
    
    
    
    
    
    
    
    
    
    N/A
    
    
    20,155
    
    
    Gain (loss) on mark-to-market derivatives$
    (2,411
    )
    
    $
    (46,757
    )
    
    
    
    $
    (17,571
    )
  39




---



##### Table of Contents



(1)
    
    Hedges previously designated as cash flow hedges.(2)
    
    Dedesignated cash flow hedges and non-designated hedges.  Interest Fixed-Rate Swap
 Notional
    
    
    
    
    
    
    Contract Period
    
    
    Fair ValueTerm
    
    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.  Interest Fixed-Rate Swap
 Notional
    
    
    
    
    
    
    Contract Period
    
    
    Fair ValueTerm
    
    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 ValueEnded 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 ValueEnded 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
    )
  40




---



##### Table of Contents



Natural Gas Purchases  Fixed Price Swaps
 Production Period
    
    
    
    
    
    Average
    
    
    Fair ValueEnded 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 ValueEnded December 31,
    
    Volumes
    
    
    Fixed Price
    
    
    Asset(3)(mmbtu)(6)
    
    
    (per mmbtu)(6)
    
    
    (in thousands)2009
    
    
    3,690,000
    
    
    $
    (0.659
    )
    
    $
    1,5082010
    
    
    6,600,000
    
    
    $
    (0.590
    )
    
    
    1,193$
    2,701
 Natural Gas Liquids  Fixed Price Swap
 Production Period
    
    
    
    
    
    Average
    
    
    Fair ValueEnded December 31,
    
    Volumes
    
    
    Fixed Price
    
    
    Liability(2)(gallons)
    
    
    (per gallon)
    
    
    (in thousands)2009
    
    
    5,544,000
    
    
    $
    0.754
    
    
    $
    (762
    )
 Ethane Put Options
 AssociatedProduction Period
    
    NGL
    
    
    Average
    
    
    Fair ValueEnded 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
 AssociatedProduction Period
    
    NGL
    
    
    Average
    
    
    Fair ValueEnded 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
 AssociatedProduction Period
    
    NGL
    
    
    Average
    
    
    Fair ValueEnded 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
 AssociatedProduction Period
    
    NGL
    
    
    Average
    
    
    Fair ValueEnded December 31,
    
    Volume
    
    
    Price(4)
    
    
    Asset(1)
    
    
    Option Type(gallons)
    
    
    (per gallon)
    
    
    (in thousands)2009
    
    
    3,654,000
    
    
    $
    0.943
    
    
    $
    98
    
    
    Puts purchased2010
    
    
    3,654,000
    
    
    $
    1.038
    
    
    $
    544
    
    
    Puts purchased$
    642
  41




---



##### Table of Contents



Natural Gasoline Put Options
 AssociatedProduction Period
    
    NGL
    
    
    Average
    
    
    Fair ValueEnded December 31,
    
    Volume
    
    
    Price(4)
    
    
    Asset(1)
    
    
    Option Type(gallons)
    
    
    (per gallon)
    
    
    (in thousands)2009
    
    
    3,906,000
    
    
    $
    1.341
    
    
    $
    549
    
    
    Puts purchased2010
    
    
    3,906,000
    
    
    $
    1.345
    
    
    $
    902
    
    
    Puts purchased$
    1,451
 Crude Oil Sales Options (associated with NGL volume)
 Associated
    
    
    AverageProduction Period
    
    Crude
    
    
    NGL
    
    
    Crude
    
    
    Fair ValueEnded 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 purchased2009
    
    
    527,700
    
    
    
    29,874,978
    
    
    $
    84.80
    
    
    
    (647
    )
    
    Calls sold2010
    
    
    486,000
    
    
    
    27,356,700
    
    
    $
    61.24
    
    
    
    4,111
    
    
    Puts purchased2010
    
    
    3,127,500
    
    
    
    213,088,050
    
    
    $
    86.20
    
    
    
    (20,462
    )
    
    Calls sold2010
    
    
    714,000
    
    
    
    45,415,440
    
    
    $
    132.17
    
    
    
    705
    
    
    Calls purchased(5)2011
    
    
    606,000
    
    
    
    33,145,560
    
    
    $
    100.70
    
    
    
    (4,517
    )
    
    Calls sold2011
    
    
    252,000
    
    
    
    13,547,520
    
    
    $
    133.16
    
    
    
    920
    
    
    Calls purchased(5)2012
    
    
    450,000
    
    
    
    25,893,000
    
    
    $
    102.71
    
    
    
    (4,038
    )
    
    Calls sold2012
    
    
    180,000
    
    
    
    9,676,800
    
    
    $
    134.27
    
    
    
    919
    
    
    Calls purchased(5)$
    (22,153
    )
 Crude Oil Sales
 Production Period
    
    
    
    
    
    Average
    
    
    Fair ValueEnded 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 ValueEnded December 31,
    
    Volumes
    
    
    Crude Price(4)
    
    
    Asset/(Liability)(3)
    
    
    Option Type(barrels)
    
    
    (per barrel)
    
    
    (in thousands)2009
    
    
    117,000
    
    
    $
    64.151
    
    
    $
    604
    
    
    Puts purchased2009
    
    
    76,500
    
    
    $
    84.956
    
    
    
    (116
    )
    
    Calls sold2010
    
    
    411,000
    
    
    $
    64.732
    
    
    
    4,450
    
    
    Puts purchased2010
    
    
    234,000
    
    
    $
    88.088
    
    
    
    (1,475
    )
    
    Calls sold2011
    
    
    72,000
    
    
    $
    93.109
    
    
    
    (746
    )
    
    Calls sold2012
    
    
    48,000
    
    
    $
    90.314
    
    
    
    (648
    )
    
    Calls sold$
    2,069Total net APL liability
    
    
    $
    (43,782
    )Total net AHD liability
    
    
    
    (445
    )Total net Company asset
    
    
    
    95,175Total consolidated net asset
    
    
    $
    50,948
  42




---



##### Table of Contents



(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.  September 30,
    
    
    December 31,2009
    
    
    2008Current portion of derivative asset
    
    $
    88,960
    
    
    $
    152,727Long-term derivative asset
    
    
    42,405
    
    
    
    69,451Current 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
  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
   43




---



##### Table of Contents



Level 1
    
    
    Level 2
    
    
    Level 3
    
    
    TotalSERP liability
    
    $
    
    
    
    $
    (3,587
    )
    
    $
    
    
    
    $
    (3,587
    )SERP asset funded in rabbi trust
    
    
    
    
    
    
    3,655
    
    
    
    
    
    
    
    3,655ATN commodity-based derivatives
    
    
    
    
    
    
    99,873
    
    
    
    
    
    
    
    99,873APL commodity-based derivatives
    
    
    
    
    
    
    (39,708
    )
    
    
    1,834
    
    
    
    (37,874
    )Interest rate derivatives
    
    
    
    
    
    
    (11,051
    )
    
    
    
    
    
    
    (11,051
    )Total
    
    $
    
    
    
    $
    49,182
    
    
    $
    1,834
    
    
    $
    51,016
  NGLFixedPrice
    
    
    NGL Sales
    
    
    Crude OilSwaps
    
    
    Options
    
    
    Options
    
    
    TotalBalance  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
    
    
    
    17,071Net change in unrealized gain (loss)(2)
    
    
    (2,265
    )
    
    
    (1,084
    )
    
    
    14,886
    
    
    
    11,537Deferred option premium recognition
    
    
    
    
    
    
    4,126
    
    
    
    2,239
    
    
    
    6,365Net change in other comprehensive loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Transfer to Level 2
    
    
    
    
    
    
    
    
    
    
    32,364
    
    
    
    32,364Balance  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
   44




---



##### Table of Contents



Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
   Three Months Ended
    
    
    Nine Months EndedSeptember 30, 2009
    
    
    September 30, 2009Level 3
    
    
    Total
    
    
    Level 3
    
    
    TotalAsset retirement obligations
    
    $
    125
    
    
    $
    125
    
    
    $
    721
    
    
    $
    721Total
    
    $
    125
    
    
    $
    125
    
    
    $
    721
    
    
    $
    721
 NOTE 12  CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
  Relationship with the Companys Sponsored Investment Partnerships.
 Relationship with Resource America, Inc.
  45




---



##### Table of Contents



Relationship with Laurel Mountain.
 NOTE 13  COMMITMENTS AND CONTINGENCIES
 General Commitments
    Legal Proceedings
   
    
    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);
  46




---



##### Table of Contents




    
    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).
 In re Atlas Energy Resources, LLC Unitholder Litigation
 CNX Gas Company, LLC (CNX) v. Miller Petroleum, Inc.
(Miller)
 NOTE 14  INCOME TAXES
   47




---



##### Table of Contents



NOTE 15  ISSUANCES OF SUBSIDIARY UNITS
       48




---



##### Table of Contents



NOTE 16  CASH DISTRIBUTIONS
  Atlas Pipeline Partners Cash Distributions.
 APL Cash
    
    
    Total APL Cash
    
    
    Total APL CashDistribution
    
    
    Distribution
    
    
    DistributionDate Cash
    
    
    
    per Common
    
    
    to Common
    
    
    to theDistribution
    
    For Quarter
    
    Limited
    
    
    Limited
    
    
    GeneralPaid
    
    Ended
    
    Partner Unit
    
    
    Partners
    
    
    PartnerFebruary 14, 2008
    
    December 31, 2007
    
    $
    0.93
    
    
    $
    36,051
    
    
    $
    5,092May 15, 2008
    
    March 31, 2008
    
    $
    0.94
    
    
    $
    36,450
    
    
    $
    7,891August 14, 2008
    
    June 30, 2008
    
    $
    0.96
    
    
    $
    44,096
    
    
    $
    9,308November 14, 2008
    
    September 30, 2008
    
    $
    0.96
    
    
    $
    44,105
    
    
    $
    9,312February 13, 2009
    
    December 31, 2008
    
    $
    0.38
    
    
    $
    17,463
    
    
    $
    2,545May 13, 2009
    
    March 31, 2009
    
    $
    0.15
    
    
    $
    7,147
    
    
    $
    1,010
    49




---



##### Table of Contents



Atlas Pipeline Holdings Cash Distributions.
 Total CashDate Cash
    
    
    
    Cash Distribution per
    
    
    Distribution to theDistribution Paid or
    
    For Quarter
    
    Common Limited
    
    
    CompanyPayable
    
    Ended
    
    Partner Unit
    
    
    (in thousands)February 19, 2008
    
    December 31, 2007
    
    $
    0.34
    
    
    $
    5,950May 20, 2008
    
    March 31, 2008
    
    $
    0.43
    
    
    $
    7,525August 19, 2008
    
    June 30, 2008
    
    $
    0.51
    
    
    $
    9,082November 19, 2008
    
    September 30, 2008
    
    $
    0.51
    
    
    $
    9,082February 19, 2009
    
    December 31, 2008
    
    $
    0.06
    
    
    $
    1,068
  NOTE 17  BENEFIT PLANS
 Incentive Bonus Plan
  Stock Incentive Plans
  Stock Options
  50




---



##### Table of Contents



Three Months EndedSeptember 30,2009
    
    
    2008Weighted
    
    
    
    
    
    
    WeightedNumber
    
    
    Average
    
    
    Number
    
    
    Averageof Unit
    
    
    Exercise
    
    
    of Unit
    
    
    ExerciseOptions
    
    
    Price
    
    
    Options
    
    
    PriceOutstanding, beginning of period
    
    
    3,537,132
    
    
    $
    16.96
    
    
    
    3,540,380
    
    
    $
    16.89Granted
    
    
    7,500
    
    
    $
    19.75
    
    
    
    
    
    
    
    Exercised
    
    
    (6,411
    )
    
    $
    11.32
    
    
    
    (28,155
    )
    
    $
    11.32Forfeited
    
    
    (30,000
    )
    
    $
    35.82
    
    
    
    
    
    
    
    Outstanding, end of period(1)(2)
    
    
    3,508,221
    
    
    $
    16.81
    
    
    
    3,512,225
    
    
    $
    16.94Non-cash compensation expense
recognized
 (in thousands)
    
    $
    494
    
    
    
    
    
    
    $
    983
 Nine Months EndedSeptember 30,2009
    
    
    2008Weighted
    
    
    
    
    
    
    WeightedNumber
    
    
    Average
    
    
    Number
    
    
    Averageof Unit
    
    
    Exercise
    
    
    of Unit
    
    
    ExerciseOptions
    
    
    Price
    
    
    Options
    
    
    PriceOutstanding, beginning of period
    
    
    3,495,351
    
    
    $
    16.97
    
    
    
    2,715,380
    
    
    $
    12.10Granted
    
    
    107,500
    
    
    $
    13.80
    
    
    
    825,000
    
    
    $
    32.68Exercised(3)
    
    
    (19,067
    )
    
    $
    11.32
    
    
    
    (28,155
    )
    
    $
    11.32Cancelled
    
    
    (15,187
    )
    
    $
    11.32
    
    
    
    
    
    
    
    Forfeited
    
    
    (60,376
    )
    
    $
    23.49
    
    
    
    
    
    
    
    Outstanding, end of period(1)(2)
    
    
    3,508,221
    
    
    $
    16.81
    
    
    
    3,512,225
    
    
    $
    16.94Options exercisable, end of period(4)
    
    
    2,745,408
    
    
    $
    13.30
    
    
    
    2,350,298
    
    
    $
    11.61Non-cash compensation expense
recognized 
(in thousands)
    
    $
    2,388
    
    
    
    
    
    
    $
    2,941Available 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.  51




---



##### Table of Contents



Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Expected 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
    
    
    
    6.25Fair value of stock options granted
    
    $
    9.80
    
    
    
    
    
    
    $
    5.23
    
    
    $
    11.75
 Deferred Units and Restricted Shares
    Three Months EndedSeptember 30,2009
    
    
    2008Weighted
    
    
    
    
    
    
    WeightedAverage
    
    
    
    
    
    
    AverageNumber
    
    
    Grant Date
    
    
    Number
    
    
    Grant Dateof Units
    
    
    Fair Value
    
    
    of Units
    
    
    Fair ValueNon-vested shares outstanding,
beginning of period
    
    
    12,534
    
    
    $
    23.80
    
    
    
    12,364
    
    
    $
    23.53Granted
    
    
    24,663
    
    
    $
    22.10
    
    
    
    396
    
    
    $
    37.69Matured(1)
    
    
    (5,123
    )
    
    $
    22.43
    
    
    
    (248
    )
    
    $
    20.14Forfeited
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Non-vested shares outstanding,
end of period(2)
    
    
    32,074
    
    
    $
    22.71
    
    
    
    12,512
    
    
    $
    24.05Non-cash compensation expense
recognized
 (in thousands)
    
    $
    93
    
    
    
    
    
    
    $
    25
  52




---



##### Table of Contents



Nine Months EndedSeptember 30,2009
    
    
    2008Weighted
    
    
    
    
    
    
    WeightedAverage
    
    
    
    
    
    
    AverageNumber
    
    
    Grant Date
    
    
    Number
    
    
    Grant Dateof Units
    
    
    Fair Value
    
    
    of Units
    
    
    Fair ValueNon-vested shares outstanding,
beginning of period
    
    
    12,512
    
    
    $
    24.05
    
    
    
    21,114
    
    
    $
    14.61Granted
    
    
    29,468
    
    
    $
    21.04
    
    
    
    1,920
    
    
    $
    46.87Matured(1)
    
    
    (9,906
    )
    
    $
    19.43
    
    
    
    (10,522
    )
    
    $
    9.27Forfeited
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Non-vested shares outstanding, end of
period(2)
    
    
    32,074
    
    
    $
    22.71
    
    
    
    12,512
    
    
    $
    24.05Non-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.  Employee Stock Ownership Plan
    53




---



##### Table of Contents



Supplemental Employment Retirement Plan (SERP)
    September 30,
    
    
    December 31,2009
    
    
    2008Other liabilities
    
    $
    (3,587
    )
    
    $
    (3,209
    )Accumulated other comprehensive income
    
    
    187
    
    
    
    255Deferred income tax asset
    
    
    110
    
    
    
    150Net amount recognized
    
    $
    (3,290
    )
    
    $
    (2,804
    )
  Amended and Restated Atlas Energy, Inc. Assumed Long-Term Incentive Plan
   Restricted Stock and Phantom Units.
  54




---



##### Table of Contents



WeightedAverageGrant DateUnits
    
    
    Fair ValueNon-vested units outstanding at December 31, 2008
    
    
    768,829
    
    
    $
    23.86Granted
    
    
    28,523
    
    
    
    16.48Vested
    
    
    (13,073
    )
    
    
    21.70Forfeited
    
    
    (46,000
    )
    
    
    31.12Non-vested units outstanding at September 29, 2009
    
    
    738,279
    
    
    
    23.16Units converted on September 29, 2009(1)
    
    
    118,125
    
    
    
    N/ANon-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 .
  WeightedAverageWeighted
    
    
    Remaining
    
    
    AggregateAverage
    
    
    Contractual
    
    
    IntrinsicExercise
    
    
    Term
    
    
    ValueUnits
    
    
    Price
    
    
    (in years)
    
    
    (in thousands)Outstanding at December 31, 2008
    
    
    1,902,902
    
    
    $
    24.17Granted
    
    
    5,000
    
    
    
    25.78Exercised
    
    
    
    
    
    
    Forfeited or expired
    
    
    (123,600
    )
    
    
    31.96Outstanding at September 29, 2009
    
    
    1,784,302
    
    
    $
    23.64
    
    
    
    7.34Stock options converted on
September 29, 2009
    
    
    285,488
    
    
    
    N/A
    
    
    
    N/ANon-vested stock options
outstanding at September 30,
2009
    
    
    2,069,790
    
    
    $
    20.36
    
    
    
    7.34
    
    
    $
    14,402
  55




---



##### Table of Contents



Options Outstanding
    
    
    Options ExercisableWeightedAverage
    
    
    Weighted
    
    
    
    
    
    
    WeightedNumber of
    
    
    Remaining
    
    
    Average
    
    
    Number of
    
    
    AverageRange of
    
    Shares
    
    
    Contractual
    
    
    Exercise
    
    
    Shares
    
    
    ExerciseExercise 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
    
    
    $
    21.00Stock options
converted on September 29, 2009(1)
    
    
    285,488
    
    
    
    N/A
    
    
    
    N/A
    
    
    
    44,850
    
    
    
    N/AConverted 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.  AHD Long-Term Incentive Plan
  AHD Phantom Units.
  56




---



##### Table of Contents



Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Outstanding, beginning of period
    
    
    181,300
    
    
    
    225,475
    
    
    
    226,300
    
    
    
    220,825Granted(1)
    
    
    500
    
    
    
    
    
    
    
    500
    
    
    
    4,650Matured
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Forfeited
    
    
    
    
    
    
    
    
    
    
    (45,000
    )
    
    
    Outstanding, end of period(2)
    
    
    181,800
    
    
    
    225,475
    
    
    
    181,800
    
    
    
    225,475Non-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.  AHD Unit Options.
 Three Months Ended September 30,2009
    
    
    2008Weighted
    
    
    
    
    
    
    WeightedNumber
    
    
    Average
    
    
    Number
    
    
    Averageof Unit
    
    
    Exercise
    
    
    of Unit
    
    
    ExerciseOptions
    
    
    Price
    
    
    Options
    
    
    PriceOutstanding, beginning of period
    
    
    955,000
    
    
    $
    20.54
    
    
    
    1,215,000
    
    
    $
    22.56Granted
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Matured
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Forfeited
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Outstanding, end of period(1)(2)
    
    
    955,000
    
    
    $
    20.54
    
    
    
    1,215,000
    
    
    $
    22.56Options exercisable, end of period
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Non-cash compensation expense
recognized 
(in thousands)
    
    $
    222
    
    
    
    
    
    
    $
    309
  57




---



##### Table of Contents



Nine Months Ended September 30,2009
    
    
    2008Weighted
    
    
    
    
    
    
    WeightedNumber
    
    
    Average
    
    
    Number
    
    
    Averageof Unit
    
    
    Exercise
    
    
    of Unit
    
    
    ExerciseOptions
    
    
    Price
    
    
    Options
    
    
    PriceOutstanding, beginning of period
    
    
    1,215,000
    
    
    $
    22.56
    
    
    
    1,215,000
    
    
    $
    22.56Granted
    
    
    100,000
    
    
    $
    3.24
    
    
    
    
    
    
    
    Matured
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Forfeited
    
    
    (360,000
    )
    
    $
    22.56
    
    
    
    
    
    
    
    Outstanding, end of period(1)(2)
    
    
    955,000
    
    
    $
    20.54
    
    
    
    1,215,000
    
    
    $
    22.56Options 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.   Nine Months EndedSeptember 30, 2009Expected 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
   58




---



##### Table of Contents



APL Phantom Units.
  Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Outstanding, beginning of period
    
    
    76,721
    
    
    
    149,923
    
    
    
    126,565
    
    
    
    129,746Granted(1)
    
    
    
    
    
    
    
    
    
    
    2,000
    
    
    
    54,296Matured(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
    
    
    
    138,063Non-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.   59




---



##### Table of Contents



APL Unit Options.
 Three Months Ended September 30,2009
    
    
    2008Weighted
    
    
    
    
    
    
    WeightedNumber
    
    
    Average
    
    
    Number
    
    
    Averageof Unit
    
    
    Exercise
    
    
    of Unit
    
    
    ExerciseOptions
    
    
    Price
    
    
    Options
    
    
    PriceOutstanding, 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
    
    
    2008Weighted
    
    
    
    
    
    
    WeightedNumber
    
    
    Average
    
    
    Number
    
    
    Averageof Unit
    
    
    Exercise
    
    
    of Unit
    
    
    ExerciseOptions
    
    
    Price
    
    
    Options
    
    
    PriceOutstanding, 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.  60




---



##### Table of Contents



Nine Months EndedSeptember 30, 2009Expected 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
  NOTE 18  OPERATING SEGMENT INFORMATION
  Three Months Ended September 30,
    
    
    Nine Months Ended September 30,2009
    
    
    2008 (c)
    
    
    2009 (c)
    
    
    2008 (c)Gas and oil productionRevenues (a)
    
    $
    65,986
    
    
    $
    81,235
    
    
    $
    207,908
    
    
    $
    236,417Costs and expenses
    
    
    (12,128
    )
    
    
    (12,688
    )
    
    
    (33,217
    )
    
    
    (35,735
    )Segment profit
    
    $
    53,858
    
    
    $
    68,547
    
    
    $
    174,691
    
    
    $
    200,682Well construction and completionRevenues
    
    $
    81,496
    
    
    $
    116,987
    
    
    $
    257,231
    
    
    $
    343,466Costs and expenses
    
    
    (69,138
    )
    
    
    (101,727
    )
    
    
    (218,236
    )
    
    
    (298,666
    )Segment profit
    
    $
    12,358
    
    
    $
    15,260
    
    
    $
    38,995
    
    
    $
    44,800Other (a)Revenues
    
    $
    14,259
    
    
    $
    3,380
    
    
    $
    23,999
    
    
    $
    13,116Costs and expenses
    
    
    (10,350
    )
    
    
    (2,890
    )
    
    
    (19,290
    )
    
    
    (8,206
    )Segment profit
    
    $
    3,909
    
    
    $
    490
    
    
    $
    4,709
    
    
    $
    4,910Atlas Pipeline (b)Revenues (c)
    
    $
    200,537
    
    
    $
    553,561
    
    
    $
    521,918
    
    
    $
    945,864Revenues  affiliates
    
    
    
    
    
    
    12,021
    
    
    
    16,766
    
    
    
    32,768Equity 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
    )
  61




---



##### Table of Contents



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
    
    
    $
    200,682Well construction and completion
    
    
    12,358
    
    
    
    15,260
    
    
    
    38,995
    
    
    
    44,800Other
    
    
    3,909
    
    
    
    490
    
    
    
    4,709
    
    
    
    4,910Atlas Pipeline
    
    
    42,077
    
    
    
    231,731
    
    
    
    82,440
    
    
    
    (13,481
    )Total segment profit (loss)
    
    
    112,202
    
    
    
    316,028
    
    
    
    300,835
    
    
    
    236,911Gain 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
    
    
    
    11,842Income (loss) from continuing
operations before income tax provision
(benefit)
    
    $
    (10,602
    )
    
    $
    225,543
    
    
    $
    62,769
    
    
    $
    (45,916
    )Capital expendituresGas and oil production
    
    $
    33,824
    
    
    $
    89,165
    
    
    $
    129,818
    
    
    $
    224,179Well construction and completion
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Atlas Pipeline
    
    
    7,116
    
    
    
    81,714
    
    
    
    137,610
    
    
    
    223,768Corporate and other
    
    
    548
    
    
    
    135
    
    
    
    967
    
    
    
    791Total capital expenditures
    
    $
    41,488
    
    
    $
    171,014
    
    
    $
    268,395
    
    
    $
    448,738
 September 30,
    
    
    December 31,2009
    
    
    2008 (c)Balance sheetGoodwillGas and oil production
    
    $
    21,527
    
    
    $
    21,527Well construction and completion
    
    
    13,639
    
    
    
    13,639Atlas Pipeline
    
    
    
    
    
    
    $
    35,166
    
    
    $
    35,166Total assetsGas and oil production
    
    $
    2,201,175
    
    
    $
    2,210,563Well construction and completion
    
    
    12,760
    
    
    
    16,399Atlas Pipeline (c)
    
    
    2,139,561
    
    
    
    2,157,590Discontinued operations
    
    
    
    
    
    
    255,606Corporate 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.   62




---



##### Table of Contents



NOTE 19  SUBSEQUENT EVENTS
   Natural Gas Fixed Price Swaps
 ProductionPeriod Ending
    
    
    
    
    
    AverageDecember 31,
    
    Volumes
    
    
    Fixed Price(MMBtu)
    
    
    (per MMBtu)2010
    
    
    2,520,000
    
    
    $
    6.2502011
    
    
    1,260,000
    
    
    $
    6.863
 Natural Gas Costless Collars
 ProductionPeriod Ending
    
    
    
    
    
    
    
    AverageDecember 31,
    
    Option Type
    
    Volumes
    
    
    Floor and Cap(MMBtu)
    
    
    (per MMBtu)2012
    
    Puts purchased
    
    
    3,480,000
    
    
    $
    6.5502012
    
    Calls sold
    
    
    3,480,000
    
    
    $
    7.7502013
    
    Puts purchased
    
    
    3,480,000
    
    
    $
    6.7002013
    
    Calls sold
    
    
    3,480,000
    
    
    $
    7.800
   
 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
   63




---



##### Table of Contents



KEY PERFORMANCE INDICATORS
  
    
    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;
  64




---



##### Table of Contents




    
    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.
  
    
    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.
  
    
    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.
  
    
    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).
  65




---



##### Table of Contents



OTHER OWNERSHIP INTERESTS
  
    
    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.
  
    
    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
   66




---



##### Table of Contents



RECENT DEVELOPMENTS
     SUBSEQUENT EVENTS
   67




---



##### Table of Contents



Natural Gas Derivative Contracts
  Natural Gas Fixed Price Swaps
 ProductionPeriod Ending
    
    
    
    
    
    AverageDecember 31,
    
    Volumes
    
    
    Fixed Price(MMBtu)
    
    
    (per MMBtu)2010
    
    
    2,520,000
    
    
    $
    6.2502011
    
    
    1,260,000
    
    
    $
    6.863
 Natural Gas Costless Collars
 ProductionPeriod Ending
    
    
    
    
    
    
    
    
    
    AverageDecember 31,
    
    Option Type
    
    
    Volumes
    
    
    Floor and Cap(MMBtu)
    
    
    (per MMBtu)2012
    
    Puts purchased
    
    
    3,480,000
    
    
    $
    6.5502012
    
    Calls sold
    
    
    3,480,000
    
    
    $
    7.7502013
    
    Puts purchased
    
    
    3,480,000
    
    
    $
    6.7002013
    
    Calls sold
    
    
    3,480,000
    
    
    $
    7.800
 Credit Agreement Amendment
   CONTRACTUAL REVENUE ARRANGEMENTS
 Appalachia Natural Gas
 
    
    gas marketers;
 
    
    local distribution companies;
 
    
    industrial or other end-users; and/or
 
    
    companies generating electricity.
 Michigan Natural Gas
  68




---



##### Table of Contents



Crude Oil.
 Investment Partnerships.
 
    
    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
  Natural Gas Supply and Outlook
    69




---



##### Table of Contents



Reserve Outlook
  RESULTS OF OPERATIONS
 GAS AND OIL PRODUCTION
 Production Profile .
 Production Volumes .
 Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Production:(1)(2)Appalachia:(3)Natural gas (MMcf)
    
    
    3,549
    
    
    
    3,057
    
    
    
    10,851
    
    
    
    8,748Oil (000s Bbls)
    
    
    42
    
    
    
    39
    
    
    
    120
    
    
    
    112Total (MMcfe)
    
    
    3,801
    
    
    
    3,291
    
    
    
    11,571
    
    
    
    9,420Michigan/Indiana:Natural gas (MMcf)
    
    
    5,384
    
    
    
    5,561
    
    
    
    15,910
    
    
    
    16,373Oil (000s Bbls)
    
    
    1
    
    
    
    1
    
    
    
    3
    
    
    
    3Total (MMcfe)
    
    
    5,390
    
    
    
    5,567
    
    
    
    15,928
    
    
    
    16,391Total:Natural gas (MMcf)
    
    
    8,933
    
    
    
    8,618
    
    
    
    26,761
    
    
    
    25,121Oil (000s Bbls)
    
    
    43
    
    
    
    40
    
    
    
    123
    
    
    
    115Total (MMcfe)
    
    
    9,191
    
    
    
    8,858
    
    
    
    27,499
    
    
    
    25,811
  70




---



##### Table of Contents



Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Production per day:(1)(2)Appalachia:(3)Natural gas (Mcfd)
    
    
    38,579
    
    
    
    33,228
    
    
    
    39,749
    
    
    
    31,929Oil (Bpd)
    
    
    460
    
    
    
    413
    
    
    
    442
    
    
    
    410Total (Mcfed)
    
    
    41,339
    
    
    
    35,706
    
    
    
    42,401
    
    
    
    34,389Michigan/Indiana:Natural gas (Mcfd)
    
    
    58,519
    
    
    
    60,436
    
    
    
    58,277
    
    
    
    59,755Oil (Bpd)
    
    
    9
    
    
    
    11
    
    
    
    9
    
    
    
    11Total (Mcfed)
    
    
    58,573
    
    
    
    60,502
    
    
    
    58,331
    
    
    
    59,821Total:Natural gas (Mcfd)
    
    
    97,098
    
    
    
    93,664
    
    
    
    98,026
    
    
    
    91,684Oil (bpd)
    
    
    469
    
    
    
    424
    
    
    
    451
    
    
    
    421Total (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
 Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Production Revenues (in thousands):Appalachia:Natural gas
    
    $
    22,802
    
    
    $
    30,430
    
    
    $
    79,873
    
    
    $
    85,440Oil
    
    
    3,185
    
    
    
    3,868
    
    
    
    8,265
    
    
    
    11,753Total
    
    $
    25,987
    
    
    $
    34,298
    
    
    $
    88,138
    
    
    $
    97,193Michigan/Indiana:Natural gas
    
    $
    39,946
    
    
    $
    46,823
    
    
    $
    119,646
    
    
    $
    138,905Oil
    
    
    53
    
    
    
    114
    
    
    
    124
    
    
    
    319Total
    
    $
    39,999
    
    
    $
    46,937
    
    
    $
    119,770
    
    
    $
    139,224Total:Natural gas
    
    $
    62,748
    
    
    $
    77,253
    
    
    $
    199,519
    
    
    $
    224,345Oil
    
    
    3,238
    
    
    
    3,982
    
    
    
    8,389
    
    
    
    12,072Total
    
    $
    65,986
    
    
    $
    81,235
    
    
    $
    207,908
    
    
    $
    236,417Average Sales Price:Natural Gas:Appalachia:Total realized price, after hedge(2)
    
    $
    7.00
    
    
    $
    9.95
    
    
    $
    7.67
    
    
    $
    9.76Total realized price, before hedge(2)
    
    $
    2.92
    
    
    $
    11.13
    
    
    $
    4.06
    
    
    $
    10.62Michigan/Indiana:Total realized price, after hedge(1)
    
    $
    7.49
    
    
    $
    8.88
    
    
    $
    7.67
    
    
    $
    9.13
  71




---



##### Table of Contents



Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Total realized price, before hedge
    
    $
    3.38
    
    
    $
    10.15
    
    
    $
    3.98
    
    
    $
    9.71Total:Total realized price, after hedge(1)(2)
    
    $
    7.29
    
    
    $
    9.26
    
    
    $
    7.67
    
    
    $
    9.35Total realized price, before hedge(2)
    
    $
    3.20
    
    
    $
    10.49
    
    
    $
    4.01
    
    
    $
    10.03Oil:Appalachia:Total realized price, after hedge
    
    $
    75.26
    
    
    $
    101.07
    
    
    $
    68.49
    
    
    $
    104.04Total realized price, before hedge
    
    $
    62.81
    
    
    $
    106.81
    
    
    $
    52.33
    
    
    $
    108.09Michigan/Indiana:Total realized price, after hedge
    
    $
    63.00
    
    
    $
    111.72
    
    
    $
    50.72
    
    
    $
    108.36Total realized price, before hedge
    
    $
    63.00
    
    
    $
    111.72
    
    
    $
    50.72
    
    
    $
    108.36Total:Total realized price, after hedge
    
    $
    75.03
    
    
    $
    101.34
    
    
    $
    68.13
    
    
    $
    104.15Total 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 EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Production Costs (per Mcfe):Appalachia:Lease operating expenses(1)
    
    $
    0.97
    
    
    $
    1.08
    
    
    $
    1.03
    
    
    $
    0.98Production taxes
    
    
    0.01
    
    
    
    0.04
    
    
    
    0.03
    
    
    
    0.04Transportation and compression
    
    
    0.77
    
    
    
    1.18
    
    
    
    0.79
    
    
    
    0.94$
    1.75
    
    
    $
    2.30
    
    
    $
    1.85
    
    
    $
    1.96Michigan/Indiana:Lease operating expenses
    
    $
    0.69
    
    
    $
    0.67
    
    
    $
    0.70
    
    
    $
    0.73Production taxes
    
    
    0.22
    
    
    
    0.63
    
    
    
    0.25
    
    
    
    0.59Transportation and compression
    
    
    0.23
    
    
    
    0.28
    
    
    
    0.24
    
    
    
    0.27$
    1.14
    
    
    $
    1.58
    
    
    $
    1.19
    
    
    $
    1.59Total:Lease operating expenses(1)
    
    $
    0.81
    
    
    $
    0.82
    
    
    $
    0.84
    
    
    $
    0.82Production taxes
    
    
    0.14
    
    
    
    0.41
    
    
    
    0.16
    
    
    
    0.39Transportation 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.  72




---



##### Table of Contents



73




---



##### Table of Contents



PARTNERSHIP MANAGEMENT
 Well Construction and Completion
 Drilling Program Results
 Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Gross:Appalachia
    
    
    27
    
    
    
    242
    
    
    
    153
    
    
    
    733Michigan/Indiana
    
    
    11
    
    
    
    49
    
    
    
    51
    
    
    
    13538
    
    
    
    291
    
    
    
    204
    
    
    
    868Net:Appalachia
    
    
    26
    
    
    
    242
    
    
    
    126
    
    
    
    672Michigan/Indiana
    
    
    11
    
    
    
    49
    
    
    
    44
    
    
    
    13537
    
    
    
    291
    
    
    
    170
    
    
    
    807
  Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Average construction and completion:Revenue per well
    
    $
    2,328
    
    
    $
    483
    
    
    $
    1,487
    
    
    $
    511Cost per well
    
    
    1,975
    
    
    
    420
    
    
    
    1,261
    
    
    
    444Gross profit per well
    
    $
    353
    
    
    $
    63
    
    
    $
    226
    
    
    $
    67Gross profit margin
    
    $
    12,358
    
    
    $
    15,260
    
    
    $
    38,995
    
    
    $
    44,800Net wells drilled and completed:Marcellus Shale
    
    
    22
    
    
    
    26
    
    
    
    64
    
    
    
    68Chattanooga Shale
    
    
    4
    
    
    
    30
    
    
    
    9
    
    
    
    75Michigan/Indiana
    
    
    11
    
    
    
    
    
    
    
    44
    
    
    
    Other  shallow
    
    
    
    
    
    
    186
    
    
    
    53
    
    
    
    52937
    
    
    
    242
    
    
    
    170
    
    
    
    672
  74




---



##### Table of Contents



Administration and Oversight
  Well Services
    75




---



##### Table of Contents



TRANSMISSION, GATHERING & PROCESSING
    Three Months Ended
    
    
    Nine Months EndedTransmission, Gathering and
    
    September 30,
    
    
    September 30,Processing
    
    2009
    
    
    2008(1)
    
    
    2009
    
    
    2008(1)Atlas Energy:Revenue
    
    $
    6,098
    
    
    $
    4,886
    
    
    $
    16,210
    
    
    $
    15,151Expense
    
    
    (7,972
    )
    
    
    (8,531
    )
    
    
    (24,205
    )
    
    
    (24,293
    )Gross Margin
    
    $
    (1,874
    )
    
    $
    (3,645
    )
    
    $
    (7,995
    )
    
    $
    (9,142
    )Atlas Pipeline:Revenue
    
    $
    199,505
    
    
    $
    418,077
    
    
    $
    555,929
    
    
    $
    1,235,976Expense
    
    
    (159,890
    )
    
    
    (333,851
    )
    
    
    (458,384
    )
    
    
    (992,113
    )Gross Margin
    
    $
    39,615
    
    
    $
    84,226
    
    
    $
    97,545
    
    
    $
    243,863Eliminations:Revenue
    
    $
    
    
    
    $
    (12,021
    )
    
    $
    (16,766
    )
    
    $
    (32,768
    )Expense
    
    
    
    
    
    
    8,394
    
    
    
    11,837
    
    
    
    23,902Gross Margin
    
    $
    
    
    
    $
    (3,627
    )
    
    $
    (4,929
    )
    
    $
    (8,866
    )Total:Revenue
    
    $
    205,603
    
    
    $
    410,942
    
    
    $
    555,373
    
    
    $
    1,218,359Expense
    
    
    (167,862
    )
    
    
    (333,988
    )
    
    
    (470,752
    )
    
    
    (992,504
    )Gross Margin
    
    $
    37,741
    
    
    $
    76,954
    
    
    $
    84,621
    
    
    $
    225,855
 
 (1)
    
    Restated to reflect amounts reclassified to discontinued operations due to APLs sale
of its NOARK gas gathering and interstate pipeline system.  76




---



##### Table of Contents



GAIN ON ASSET SALES
  LOSS ON MARK-TO-MARKET DERIVATIVES
    77




---



##### Table of Contents



OTHER COSTS AND EXPENSES
 General and Administrative
  Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008(1)
    
    
    2009(1)
    
    
    2008(1)General and Administrative expenses:Atlas Energy
    
    $
    22,532
    
    
    $
    14,435
    
    
    $
    54,631
    
    
    $
    43,916Atlas Pipeline and Atlas Pipeline Holdings
    
    
    9,534
    
    
    
    (1,788
    )
    
    
    26,988
    
    
    
    14,676Total
    
    $
    32,066
    
    
    $
    12,647
    
    
    $
    81,619
    
    
    $
    58,592
 
 (1)
    
    Restated to reflect amounts reclassified to discontinued operations due to APLs sale
of its NOARK gas gathering and interstate pipeline system.   Depreciation, depletion and amortization
  Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008(1)
    
    
    2009(1)
    
    
    2008(1)Depreciation, depletion and amortization:Atlas Energy
    
    $
    24,563
    
    
    $
    23,584
    
    
    $
    79,863
    
    
    $
    68,339APL and AHD
    
    
    21,897
    
    
    
    20,741
    
    
    
    67,564
    
    
    
    61,200Total
    
    $
    46,460
    
    
    $
    44,325
    
    
    $
    147,427
    
    
    $
    129,539
 
 (1)
    
    Restated to reflect amounts reclassified to discontinued operations due to APLs sale
of its NOARK gas gathering and interstate pipeline system.  78




---



##### Table of Contents



Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Depletion Expense (in thousands):Appalachia
    
    $
    9,383
    
    
    $
    9,544
    
    
    $
    34,645
    
    
    $
    25,942Michigan/Indiana
    
    
    14,103
    
    
    
    13,164
    
    
    
    41,967
    
    
    
    39,886Total
    
    $
    23,486
    
    
    $
    22,708
    
    
    $
    76,612
    
    
    $
    65,828Depletion expense as a
percentage of gas and oil
production
    
    
    36
    %
    
    
    28
    %
    
    
    37
    %
    
    
    28
    %Depletion per Mcfe:Appalachia
    
    $
    2.47
    
    
    $
    2.84
    
    
    $
    2.99
    
    
    $
    2.75Michigan/Indiana
    
    $
    2.62
    
    
    $
    2.40
    
    
    $
    2.63
    
    
    $
    2.43Total
    
    $
    2.55
    
    
    $
    2.57
    
    
    $
    2.79
    
    
    $
    2.55
   Interest Expense
  Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008(1)
    
    
    2009(1)
    
    
    2008(1)Interest Expense:Atlas Energy
    
    $
    19,133
    
    
    $
    14,769
    
    
    $
    47,184
    
    
    $
    42,580APL and AHD
    
    
    28,621
    
    
    
    22,562
    
    
    
    77,138
    
    
    
    63,958Total
    
    $
    47,754
    
    
    $
    37,331
    
    
    $
    124,322
    
    
    $
    106,538
 
 (1)
    
    Restated to reflect amounts reclassified to discontinued operations due to APLs sale
of its NOARK gas gathering and interstate pipeline system.  79




---



##### Table of Contents



Income Taxes
  Income from Discontinued Operations
   80




---



##### Table of Contents



Income (Loss) Attributable to Non-controlling Interests
   Liquidity and Capital Resources
  
    
    capital expenditures and working capital deficits through the retention of cash,
additional borrowings and capital raised through investment partnerships; and
    
    debt principal payments through additional borrowings as they become due or by the
issuance of additional common shares.
     81




---



##### Table of Contents



Cash Flows  Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008
    Capital Requirements
  
    
    capital expenditures we make to expand our capital asset base for longer than the
short-term and include new leasehold interests and the development and exploitation of
existing leasehold interests through acquisitions and investments in our drilling
partnerships; and
    
    our commitment to invest a maximum of $20.0 million in Lightfoot, of which we had
invested $10.7 million at September 30, 2009.
  82




---



##### Table of Contents



Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008(1)
    
    
    2009
    
    
    2008(1)Atlas Energy
    
    $
    34,372
    
    
    $
    89,300
    
    
    $
    130,785
    
    
    $
    224,970Atlas Pipeline
    
    
    7,116
    
    
    
    81,714
    
    
    
    137,610
    
    
    
    223,768Total
    
    $
    41,488
    
    
    $
    171,014
    
    
    $
    268,395
    
    
    $
    448,738
 
 (1)
    
    Restated to reflect amounts reclassified to discontinued operations due to APLs sale
of its NOARK gas gathering and interstate pipeline system.    Atlas Pipeline Partners
  Off Balance Sheet Arrangements
   83




---



##### Table of Contents



Issuances of Subsidiary Common Units
  Atlas Pipeline Partners and Atlas Pipeline Holdings
    Shelf
Registration Statement
  Dividends
   84




---



##### Table of Contents



Critical Accounting Policies and Estimates
  Fair Value of Financial Instruments
  Level 1 
 Level 2 
 Level 3 
    85




---



##### Table of Contents



Recently Adopted Accounting Standards
       86




---



##### Table of Contents



87




---



##### Table of Contents



88




---



##### Table of Contents



Recently Issued Accounting Standards
   MODERNIZATION OF OIL AND GAS REPORTING
  
    
    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.
    
    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 its 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.
  89




---



##### Table of Contents



ITEM 3: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
  General
    Interest Rate Risk.
   90




---



##### Table of Contents



Commodity Price Risk
    91




---



##### Table of Contents



92




---



##### Table of Contents



Interest Fixed Rate Swap
 ContractNotional
    
    
    
    
    
    
    Period Ended
    
    
    Fair ValueTerm
    
    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
    )Total Net Liability
    
    
    $
    (4,698
    )
 Natural Gas Fixed Price Swaps
 ProductionPeriod Ending
    
    
    
    
    
    Average
    
    
    Fair ValueDecember 31,
    
    Volumes
    
    
    Fixed Price
    
    
    Asset(mmbtu)(3)
    
    
    (per mmbtu)(3)
    
    
    (in thousands)(1)2009
    
    
    10,340,000
    
    
    $
    8.242
    
    
    $
    36,1162010
    
    
    31,880,000
    
    
    $
    7.708
    
    
    
    47,6822011
    
    
    20,720,000
    
    
    $
    7.040
    
    
    
    3,4032012
    
    
    19,680,000
    
    
    $
    7.223
    
    
    
    4,1192013
    
    
    13,260,000
    
    
    $
    7.082
    
    
    
    235$
    91,555
 Natural Gas Costless Collars
 ProductionPeriod Ending
    
    
    
    
    
    
    
    
    
    Average
    
    
    Fair ValueDecember 31,
    
    Option Type
    
    
    Volumes
    
    
    Floor and Cap
    
    
    Asset/(Liability)(mmbtu)(3)
    
    
    (per mmbtu)(3)
    
    
    (in thousands)(1)2009
    
    Puts purchased
    
    
    60,000
    
    
    $
    11.000
    
    
    $
    3702009
    
    Calls sold
    
    
    60,000
    
    
    $
    15.350
    
    
    
    2010
    
    Puts purchased
    
    
    3,360,000
    
    
    $
    7.839
    
    
    
    6,0212010
    
    Calls sold
    
    
    3,360,000
    
    
    $
    9.007
    
    
    
    2011
    
    Puts purchased
    
    
    9,540,000
    
    
    $
    6.523
    
    
    
    8082011
    
    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
 ProductionPeriod Ending
    
    
    
    
    
    Average
    
    
    Fair ValueDecember 31,
    
    Volumes
    
    
    Fixed Price
    
    
    Asset/(Liability)(Bbl)(3)
    
    
    (per Bbl)(3)
    
    
    (in thousands)(2)2009
    
    
    14,600
    
    
    $
    99.319
    
    
    $
    4242010
    
    
    48,900
    
    
    $
    97.400
    
    
    
    1,1342011
    
    
    42,600
    
    
    $
    77.460
    
    
    
    112012
    
    
    33,500
    
    
    $
    76.855
    
    
    
    (74
    )2013
    
    
    10,000
    
    
    $
    77.360
    
    
    
    (29
    )$
    1,466
  93




---



##### Table of Contents



Crude Oil Costless Collars
 ProductionPeriod Ending
    
    
    
    
    
    
    
    
    
    Average
    
    
    Fair ValueDecember 31,
    
    Option Type
    
    
    Volumes
    
    
    Floor and Cap
    
    
    Asset/(Liability)(Bbl)(3)
    
    
    (per Bbl)(3)
    
    
    (in thousands)(2)2009
    
    Puts purchased
    
    
    9,000
    
    
    $
    85.000
    
    
    $
    1342009
    
    Calls sold
    
    
    9,000
    
    
    $
    116.561
    
    
    
    2010
    
    Puts purchased
    
    
    31,000
    
    
    $
    85.000
    
    
    
    4682010
    
    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
    )$
    481Total ATN net asset
    
    
    $
    95,175
 
 (1)
    
    Fair value based on forward NYMEX natural gas prices, as applicable.(2)
    
    Fair value based on forward WTI crude oil prices, as applicable.(3)
    
    Mmbtu represents million British thermal units; Bbl represents barrels. Atlas Pipeline Partners and Atlas Pipeline Holdings.
  Early Termination of Derivative ContractsThree Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Net 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
    )
  94




---



##### Table of Contents



Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2009
    
    
    2008
    
    
    2009
    
    
    2008Loss 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
    
    
    
    41,271Gain (loss) from cash
settlement and non-cash
recognition of non-qualifying
derivatives(2)
    
    
    (10,165
    )
    
    
    (84,207
    )
    
    
    3,225
    
    
    
    (280,696
    )Loss from cash settlement of
interest rate
derivatives(3)
    
    
    (3,321
    )
    
    
    (708
    )
    
    
    (9,500
    )
    
    
    (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)(4)
    
    
    (60
    )
    
    
    
    
    
    
    (256
    )
    
    
    
 
 (1)
    
    Included within transmission, gathering and processing revenue on our consolidated
statements of operations.(2)
    
    Included within (gain) loss on mark-to-market derivatives, net on our consolidated statements
of operations.(3)
    
    Included within interest expense on our consolidated statements of operations.(4)
    
    Reclassification due to reduction of outstanding borrowings being hedged.  September 30, 2009Asset Derivatives
    
    
    Liability DerivativesBalance Sheet
    
    
    
    
    
    
    Balance SheetLocation
    
    
    Fair Value
    
    
    Location
    
    
    Fair ValueDerivatives not designated as hedging instruments:Interest rate contracts
    

    N/A
    
    $
    
    
    
    Current portion of derivative liability
    
    $
    (6,352
    )Commodity contracts
    
    Current portion of derivative asset
    
    
    4,514Commodity contracts
    
    Long-term derivative asset
    
    
    1,980Commodity 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
    )
  95




---



##### Table of Contents



Derivatives not designated as hedging instrumentsThree months ended September 30, 2009Gain (Loss)
    
    
    Gain (Loss) Reclassified from
    
    
    Gain (Loss) Recognized in IncomeRecognized in
    
    
    Accumulated OCI into Income
    
    
    (Ineffective Portion and AmountAccumulated
    
    
    (Effective Portion)
    
    
    Excluded from Effectiveness Testing)OCI
    
    
    Amount
    
    
    Location
    
    
    Amount
    
    
    LocationInterest rate contracts(1)
    
    $
    30
    
    
    $
    (3,419
    )
    
    Interest expense
    
    $
    (951
    )
    
    Gain (loss) on mark-to-market derivativesCommodity contracts(1)
    
    
    
    
    
    
    (10,294
    )
    
    Transmission, gathering and processing revenue
    
    
    (13,671
    )
    
    Gain (loss) on mark-to-market derivativesCommodity 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 instrumentsNine months ended September 30, 2009Gain (Loss)
    
    
    Gain (Loss) Reclassified from
    
    
    Gain (Loss) Recognized in IncomeRecognized in
    
    
    Accumulated OCI into Income
    
    
    (Ineffective Portion and AmountAccumulated
    
    
    (Effective Portion)
    
    
    Excluded from Effectiveness Testing)OCI
    
    
    Amount
    
    
    Location
    
    
    Amount
    
    
    LocationInterest rate contracts(1)
    
    $
    (2,411
    )
    
    $
    (9,599
    )
    
    Interest expense
    
    $
    (1,147
    )
    
    Gain (loss) on mark-to-market derivativesCommodity contracts(1)
    
    
    
    
    
    
    (37,158
    )
    
    Transmission, gathering and processing revenue
    
    
    (36,579
    )
    
    Gain (loss) on mark-to-market derivativesCommodity contracts(2)
    
    
    
    
    
    
    
    
    
    N/A
    
    
    
    20,155
    
    
    Gain (loss) on mark-to-market derivatives$
    (2,411
    )
    
    $
    (46,757
    )
    
    
    
    
    
    $
    (17,571
    )
 
 (1)
    
    Hedges previously designated as cash flow hedges(2)
    
    Dedesignated cash flow hedges and non-designated hedges  96




---



##### Table of Contents



Interest Fixed-Rate Swap
 Notional
    
    
    
    
    
    
    Contract Period
    
    
    Fair ValueTerm
    
    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 liability
    
    $
    (445
    )
 
 (1)
    
    Fair value based on independent, third-party
statements, supported by observable levels at which transactions are executed in the
marketplace.  Interest Fixed-Rate Swap
 Notional
    
    
    
    
    
    
    Contract Period
    
    
    Fair ValueTerm
    
    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 ValueEnded December 31,
    
    Volumes
    
    
    Fixed Price
    
    
    Asset(3)2009
    
    
    120,000
    
    
    $
    8.000
    
    
    $
    390
 Natural Gas Basis Sales
 Production Period
    
    
    
    
    
    Average
    
    
    Fair ValueEnded 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
    )
 Natural Gas Purchases  Fixed Price Swaps
 Production Period
    
    
    
    
    
    Average
    
    
    Fair ValueEnded 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
    )
  97




---



##### Table of Contents



Natural Gas Basis Purchases
 Production Period
    
    
    
    
    
    Average
    
    
    Fair ValueEnded December 31,
    
    Volumes
    
    
    Fixed Price
    
    
    Asset(3)(mmbtu)(6)
    
    
    (per mmbtu)(6)
    
    
    (in thousands)2009
    
    
    3,690,000
    
    
    $
    (0.659
    )
    
    $
    1,5082010
    
    
    6,600,000
    
    
    $
    (0.590
    )
    
    
    1,193$
    2,701
 Natural Gas Liquids  Fixed Price Swap
 Production Period
    
    
    
    
    
    Average
    
    
    Fair ValueEnded December 31,
    
    Volumes
    
    
    Fixed Price
    
    
    Liability(2)(gallons)
    
    
    (per gallon)
    
    
    (in thousands)2009
    
    
    5,544,000
    
    
    $
    0.754
    
    
    $
    (762
    )
 Ethane Put Options
 AssociatedProduction Period
    
    NGL
    
    
    Average
    
    
    Fair ValueEnded 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
 AssociatedProduction Period
    
    NGL
    
    
    Average
    
    
    Fair ValueEnded 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
 AssociatedProduction Period
    
    NGL
    
    
    Average
    
    
    Fair ValueEnded December 31,
    
    Volume
    
    
    Price(4)
    
    
    Liability(1)
    
    
    Option Type(gallons)
    
    
    (per gallon)
    
    
    (in thousands)2009
    
    
    126,000
    
    
    $
    0.5890
    
    
    $
    (20
    )
    
    Puts purchased
 Normal Butane Put Options
 AssociatedProduction Period
    
    NGL
    
    
    Average
    
    
    Fair ValueEnded December 31,
    
    Volume
    
    
    Price(4)
    
    
    Asset(1)
    
    
    Option Type(gallons)
    
    
    (per gallon)
    
    
    (in thousands)2009
    
    
    3,654,000
    
    
    $
    0.943
    
    
    $
    98
    
    
    Puts purchased2010
    
    
    3,654,000
    
    
    $
    1.038
    
    
    $
    544
    
    
    Puts purchased$
    642
  98




---



##### Table of Contents



Natural Gasoline Put Options
 AssociatedProduction Period
    
    NGL
    
    
    Average
    
    
    Fair ValueEnded December 31,
    
    Volume
    
    
    Price(4)
    
    
    Asset(1)
    
    
    Option Type(gallons)
    
    
    (per gallon)
    
    
    (in thousands)2009
    
    
    3,906,000
    
    
    $
    1.341
    
    
    $
    549
    
    
    Puts purchased2010
    
    
    3,906,000
    
    
    $
    1.345
    
    
    $
    902
    
    
    Puts purchased$
    1,451
 Crude Oil Sales Options (associated with NGL volume)
 Associated
    
    
    AverageProduction Period
    
    Crude
    
    
    NGL
    
    
    Crude
    
    
    Fair ValueEnded 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 purchased2009
    
    
    527,700
    
    
    
    29,874,978
    
    
    $
    84.80
    
    
    
    (647
    )
    
    Calls sold2010
    
    
    486,000
    
    
    
    27,356,700
    
    
    $
    61.24
    
    
    
    4,111
    
    
    Puts purchased2010
    
    
    3,127,500
    
    
    
    213,088,050
    
    
    $
    86.20
    
    
    
    (20,462
    )
    
    Calls sold2010
    
    
    714,000
    
    
    
    45,415,440
    
    
    $
    132.17
    
    
    
    705
    
    
    Calls purchased(5)2011
    
    
    606,000
    
    
    
    33,145,560
    
    
    $
    100.70
    
    
    
    (4,517
    )
    
    Calls sold2011
    
    
    252,000
    
    
    
    13,547,520
    
    
    $
    133.16
    
    
    
    920
    
    
    Calls purchased(5)2012
    
    
    450,000
    
    
    
    25,893,000
    
    
    $
    102.71
    
    
    
    (4,038
    )
    
    Calls sold2012
    
    
    180,000
    
    
    
    9,676,800
    
    
    $
    134.27
    
    
    
    919
    
    
    Calls purchased(5)$
    (22,153
    )
 Crude Oil Sales
 Production Period
    
    
    
    
    
    Average
    
    
    Fair ValueEnded 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 ValueEnded December 31,
    
    Volumes
    
    
    Crude Price(4)
    
    
    Asset(Liability)(3)
    
    
    Option Type(barrels)
    
    
    (per barrel)
    
    
    (in thousands)2009
    
    
    117,000
    
    
    $
    64.151
    
    
    $
    604
    
    
    Puts purchased2009
    
    
    76,500
    
    
    $
    84.956
    
    
    
    (116
    )
    
    Calls sold2010
    
    
    411,000
    
    
    $
    64.732
    
    
    
    4,450
    
    
    Puts purchased2010
    
    
    234,000
    
    
    $
    88.088
    
    
    
    (1,475
    )
    
    Calls sold2011
    
    
    72,000
    
    
    $
    93.109
    
    
    
    (746
    )
    
    Calls sold2012
    
    
    48,000
    
    
    $
    90.314
    
    
    
    (648
    )
    
    Calls sold$
    2,069Total net APL liability
    
    
    $
    (43,782
    )Total net AHD liability
    
    
    
    (445
    )Total net Company asset
    
    
    
    95,175Total consolidated net asset
    
    
    $
    50,948
 
 (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.  99




---



##### Table of Contents



(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.  September 30,
    
    
    December 31,2009
    
    
    2008Current portion of derivative asset
    
    $
    88,960
    
    
    $
    152,727Long-term derivative asset
    
    
    42,405
    
    
    
    69,451Current portion of derivative liability
    
    
    (46,570
    )
    
    
    (73,776
    )Long-term derivative liability
    
    
    (33,847
    )
    
    
    (59,103
    )Total net asset
    
    $
    50,948
    
    
    $
    89,299
  
 ITEM 4. CONTROLS AND PROCEDURES
     100




---



##### Table of Contents



PART II. OTHER INFORMATION
 
 ITEM 1. LEGAL PROCEEDINGS
  
    
    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);
    
    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).
 In re Atlas Energy Resources, LLC Unitholder Litigation
 CNX Gas Company, LLC (CNX) v. Miller Petroleum, Inc. (Miller)
   101




---



##### Table of Contents



ITEM 1A. RISK FACTORS
  The combined company resulting from the merger may fail to realize the anticipated cost savings,
growth opportunities and synergies and other benefits anticipated from the merger, which could
adversely affect the value of our common stock.
  Lawsuits have been filed against ATN, certain officers and members of its board of directors and us
challenging the merger, and any adverse judgment for monetary damages could have a material adverse
effect on the operations of the combined company.
  
 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
  Votes In
    
    
    Votes AgainstNominees
    
    Favor
    
    
    or WithheldMark C. Biderman
    
    
    36,690,458
    
    
    
    149,980Gayle P.W. Jackson
    
    
    36,979,160
    
    
    
    150,278
  Votes in Favor
    
    Votes Against
    
    Votes in Abstention/Broker Non-Votes30,376,096
    
    6,730,237
    
    23,101
  102




---



##### Table of Contents



Votes in Favor
    
    Votes Against
    
    Votes in Abstention/Broker Non-Votes33,443,782
    
    38,050
    
    4,466
  Votes in Favor
    
    Votes Against
    
    Votes in Abstention/Broker Non-Votes25,089,398
    
    8,375,507
    
    21,394
 
 ITEM 6. EXHIBITS
 Exhibit No.
    
    Description2.1
    
    
    Agreement and Plan of Merger, dated as of April 27, 2009, by
and among Atlas Energy Resources, LLC, Atlas America, Inc.,
Atlas Energy Management, Inc. and Merger Sub, as defined
therein(11)3.1
    
    
    Amended and Restated Certificate of Incorporation(15)3.2
    
    
    Amended and Restated Bylaws(15)4.1
    
    
    Form of stock certificate(2)10.1
    
    
    Indenture dated as of January 23, 2008 among Atlas Energy
Operating Company, LLC, Atlas Energy Finance Corp., as Issuers,
the subsidiaries named therein, as Guarantors, and U.S. Bank
National Association, as Trustee(17)10.2
    
    
    Form of 10.75% Senior Note due 2018 (included as an exhibit to
the Indenture filed as Exhibit 4.2 hereto)10.3
    
    
    Senior Indenture dated July 16, 2009 among Atlas Energy
Operating Company, LLC, Atlas Energy Finance Corp., as Issuers,
the subsidiaries named therein, as Guarantors, and U.S. Bank
National Association, as Trustee(18)10.4
    
    
    First Supplemental Indenture date July 16, 2009(18)10.5
    
    
    Form of Note 12.125% Senior Notes due 2017 (contained in Annex
A to the First Supplemental Indenture filed as Exhibit 4.5
hereto)10.6
    
    
    Tax Matters Agreement between Atlas America, Inc. and Resource America, Inc. dated
May 14, 2004(5)10.7
    
    
    Transition Services Agreement between Atlas America, Inc. and Resource America, Inc.
dated May 14, 2004(5)10.8
    (a)
    
    Employment Agreement for Edward E. Cohen dated May 14, 2004(5)
  103




---



##### Table of Contents



Exhibit No.
    
    Description10.8
    (b)
    
    Amendment to Employment Agreement dated as of December 31, 2008(12)10.9
    (a)
    
    Agreement for Services among Atlas America, Inc. and Richard Weber, dated April 5,
2006(6)10.9
    (b)
    
    Amendment No. 1 to Agreement for Services dated as of April 26, 2007(7)10.9
    (c)
    
    Amendment No. 2 to Agreement for Services dated as of December 18, 2008(12)10.10
    
    
    Management Agreement, dated as of December 18, 2006, among Atlas Energy Resources, LLC,
Atlas Energy Operating Company, LLC and Atlas Energy Management, Inc.(4)10.11
    
    
    Stock Incentive Plan(12)10.12
    
    
    2009 Stock Incentive Plan(15)10.13
    
    
    Assumed Long-Term Incentive Plan(24)10.14
    
    
    Atlas America Employee Stock Ownership Plan(8)10.15
    
    
    Atlas America, Inc. Investment Savings Plan(8)10.16
    
    
    Form of Stock Award Agreement(9)10.17
    
    
    Amended and Restated Annual Incentive Plan for Senior Executives(10)10.18
    
    
    Employment Agreement between Atlas America, Inc. and Jonathan Z. Cohen dated as of
January 30, 2009(12)10.19
    
    
    Securities Purchase Agreement dated April 7, 2009, by and between Atlas Pipeline
Mid-Continent, LLC and Spectra Energy Partners OLP, LP(16)10.19
    (a)
    
    Revolving Credit Agreement dated as of July 26, 2006 by and among Atlas Pipeline
Holdings, L.P., Atlas Pipeline Partners GP, LLC, Wachovia Bank, National Association
and the lenders thereto(16)10.19
    (b)
    
    First Amendment to Revolving Credit Agreement dated as of June 1, 2009(13)10.20
    
    
    Promissory Note dated as of June 1, 2009 by Atlas Pipeline Holdings, L.P.(13)10.21
    
    
    Guaranty Note dated as of June 1, 2009 by Atlas Pipeline Holdings, L.P.(13)10.22
    
    
    Guaranty, Subordination and Cash Collateral Agreement dated as of June 1, 2009 in favor
of Wachovia Bank, National Association(13)10.23
    (a)
    
    Revolving Credit Agreement, dated as of June 29, 2007, among Atlas Energy Operating
Company, LLC its subsidiaries, J.P. Morgan Chase Bank, N.A., as Administrative Agent
and the other lenders signatory thereto(19)10.23
    (b)
    
    First Amendment to Credit Agreement, dated as of October 25, 2007(20)10.23
    (c)
    
    Second Amendment to Credit Agreement, dated as of April 9, 2009(21)10.23
    (d)
    
    Third Amendment to Credit Agreement, dated as of July 10, 2009(22)10.24
    
    
    ATN Option Agreement dated as of June 1, 2009, by and among APL Laurel Mountain, LLC,
Atlas Pipeline Operating Partnership, L.P. and Atlas Energy Resources,
LLC(14)
  104




---



##### Table of Contents



Exhibit No.
    
    Description10.25
    
    
    Amended and Restated Limited Liability Company Agreement of Laurel Mountain Midstream,
LLC dated as of June 1, 2009(14)10.26
    
    
    Employment Agreement for Matthew A. Jones dated July 1, 2009(16)10.27
    
    
    Gas Gathering Agreement for Natural Gas on the Legacy Appalachian System dated as of
June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas
Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble LLC, Resource
Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline
Operating Partnership, L.P.(25) Specific terms in this exhibit have been
redacted, as marked three asterisks (***), because confidential treatment for those
terms has been requested. The redacted material has been separately filed with the
Securities and Exchange Commission.31.2
    
    
    Gas Gathering Agreement for Natural Gas on the Expansion Appalachian System dated as of
June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas
Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble LLC, Resource
Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline
Operating Partnership, L.P.(25) Specific terms in this exhibit have been
redacted, as marked three asterisks (***), because confidential treatment for those
terms has been requested. The redacted material has been separately filed with the
Securities and Exchange Commission.31.1
    
    
    Rule 13(a)-14(a)/15d-14(a) Certification31.2
    
    
    Rule 13(a)-14(a)/15d-14(a) Certification32.1
    
    
    Section 1350 Certification32.2
    
    
    Section 1350 Certification
 (1)
    
    Previously filed as an exhibit to our Form 8-K filed on June 14, 2005(2)
    
    Previously filed as an exhibit to our registration statement on Form S-1 (registration no.
333-112653)(3)
    
    [Intentionally Omitted](4)
    
    Previously filed as an exhibit to our Form 10-K for the year ended December 31, 2006(5)
    
    Previously filed as an exhibit to our Form 10-Q for the quarter ended June 30, 2004(6)
    
    Previously filed as an exhibit to our Form 10-Q for the quarter ended June 30, 2006(7)
    
    Previously filed as an exhibit to our Form 8-K filed on May 1, 2007(8)
    
    Previously filed as an exhibit to our Form 10-K for the year ended September 30, 2005(9)
    
    Previously filed as an exhibit to our Form 10-Q for the quarter ended December 31, 2005(10)
    
    Previously filed as an exhibit to our definitive proxy statement filed May 8, 2008(11)
    
    Previously filed as an exhibit to our Form 8-K filed on April 27, 2009(12)
    
    Previously filed as an exhibit to our Form 10-K for the year ended December 31, 2008(13)
    
    Previously filed as an exhibit to our Form 8-K filed on June 2, 2009(14)
    
    Previously filed as an exhibit to our Form 8-K filed on June 5, 2009(15)
    
    Previously filed as an exhibit to our Form 8-K filed on September 30, 2009(16)
    
    Previously filed as an exhibit to our Form 10-Q for the quarter ended June 30, 2009(17)
    
    Previously filed as an exhibit to Atlas Energy Resources, LLCs Form 8-K filed on January 24, 2008  105




---



##### Table of Contents



(18)
    
    Previously filed as an exhibit to Atlas Energy Resources, LLCs Form 8-K filed on July 17, 2009(19)
    
    Previously filed as an exhibit to Atlas Energy Resources, LLCs Form 8-K filed on June 29, 2007(20)
    
    Previously filed as an exhibit to Atlas Energy Resources, LLCs Form 8-K filed on October 26, 2007(21)
    
    Previously filed as an exhibit to Atlas Energy Resources, LLCs Form 8-K filed on April 17, 2009(22)
    
    Previously filed as an exhibit to Atlas Energy Resources, LLCs Form 8-K filed on July 24, 2009(23)
    
    Previously filed as an exhibit to Atlas Energy Resources, LLCs Form 8-K filed on December 22, 2006(24)
    
    Previously filed as an exhibit to our Form S-8 filed on September 30, 2009(25)
    
    Previously filed as an exhibit to Atlas Energy Resources, LLCs Form 10-Q for the quarter
ended June 30, 2009  106




---



##### Table of Contents



SIGNATURES
  ATLAS ENERGY, INC.Date:  November 9, 2009
    By:
    /s/ EDWARD E. COHENEdward E. CohenChairman of the Board and Chief Executive OfficerDate:  November 9, 2009
    By:
    /s/ MATTHEW A. JONESMatthew A. JonesChief Financial OfficerDate:  November 9, 2009
    By:
    /s/ SEAN P. MCGRATHSean P. McGrathChief Accounting Officer  107