##### Table of Contents



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
 Washington, D.C. 20549
 FORM 10-K
 þ
    
    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 for the fiscal year ended December 31, 2009
 o
    
    TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 Commission File No. 1-33571
 DOUBLE EAGLE PETROLEUM CO.
  Maryland
    
    83-0214692(State or other jurisdiction of incorporation or organization)
    
    (I.R.S. Employer Identification No.)
 1675 Broadway, Suite 2200, Denver, CO 80202
  
  Title of each class
    
    Name of each exchange on which registeredNone
    
    None
  Title of each class
    
    Name of each exchange on which registered$.10 Par Value Common Stock
    
    NASDAQ Global Select Market$.10 Par Value Series A Cumulative Preferred Stock
    
    NASDAQ Global Select Market
 o þ
 o þ
 þ o
 o
 o o
  Large accelerated filer o
Accelerated filer o
Non-accelerated filer þ(Do not check if a smaller reporting company)
Smaller reporting company o
 o þ




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##### 



PAGEPART IItems 1. and 2.
    
    Business and Properties
    
    
    3General
    
    
    3Overview and Strategy
    
    
    3Operations
    
    
    4Reserves
    
    
    9Production
    
    
    12Derivative Instruments
    
    
    12Productive Wells
    
    
    13Drilling Activity
    
    
    13Finding and Development Costs
    
    
    14Acreage
    
    
    15Other Significant Developments Since December 31, 2008
    
    
    15Marketing and Major Customers
    
    
    16Title to Properties
    
    
    16Seasonality
    
    
    16Competition
    
    
    16Government Regulations
    
    
    17Cautionary Information About Forward-looking Statements
    
    
    18Employees and Office Space
    
    
    19Available Information
    
    
    19Glossary
    
    
    20Item 1A.
    
    Risk Factors
    
    
    21Item 3.
    
    Legal Proceedings
    
    
    28Item 4.
    
    Reserved
    
    
    28PART IIItem 5.
    
    Market for
Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
    
    
    29Item 6.
    
    Selected Financial Data
    
    
    32Item 7.
    
    Managements Discussion and Analysis of Financial Condition and Results of Operations
    
    
    32Item 7A.
    
    Quantitative and Qualitative Disclosures about Market Risk
    
    
    48Item 8.
    
    Financial Statements and Supplementary Data
    
    
    49Item 9.
    
    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
    
    
    49Item 9A.
    
    Controls and Procedures
    
    
    49Item 9B.
    
    Other Information
    
    
    52PART IIIItem 10.
    
    Directors, Executive Officers and Corporate Governance
    
    
    52Item 11.
    
    Executive Compensation
    
    
    52Item 12.
    
    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
    
    
    52Item 13.
    
    Certain Relationships and Related Transactions
    
    
    52Item 14.
    
    Principal Accountant Fees and Services
    
    
    52PART IVItem 15.
    
    Exhibits and Financial Statement Schedules
    
    
    53EX-21.1EX-23.1EX-23.2EX-31.1EX-31.2EX-32EX-99.1
  2




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##### Table of Contents



PART I
 
 ITEMS 1. AND 2. BUSINESS AND PROPERTIES
 
 General
  
 Overview and Strategy
   Reserves
 3




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Operations
   Basin
    
    Gross Acres
    
    
    Net AcresWashakie Basin
    
    
    117,926
    
    
    
    39,882Wind River Basin
    
    
    50,226
    
    
    
    2,243Utah Overthrust
    
    
    46,440
    
    
    
    21,146Huntington Basin
    
    
    46,372
    
    
    
    39,127Greater Green River Basin
    
    
    38,530
    
    
    
    3,264Powder River Basin
    
    
    32,367
    
    
    
    2,390Other
    
    
    27,969
    
    
    
    6,317Total
    
    
    359,830
    
    
    
    114,369
  4




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The Atlantic Rim Coal Bed Natural Gas Project
    Catalina Unit
     5




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Eastern Washakie Midstream Pipeline LLC
  Doty Mountain Unit
  Sun Dog Unit
  Other Acreage
  The Pinedale Anticline in the Green River Basin of Wyoming
   6




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The Wind River Basin in Central Wyoming
  Madden Anticline
   th
  South Waltman
  7




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The Moxa Arch and Other Areas in Southwest Wyoming
  Exploration Projects
  Main Fork Unit in Utah
  Nevada
    8




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##### Table of Contents



Reserves
  
    
    The new SEC standards require that the Company calculate the quantity and PV-10 value of
oil and gas reserves that are economically producible using a simple 12-month average
price, using the first-day-of-the-month applicable commodity price within the 12-month
period prior to the reporting period end. Prior to this rule change, oil and gas reserves
were calculated using the price as of the last day of the reporting period, which was
December
31 for the Company. Historically, natural gas prices are higher during the winter months
due to cold weather and increased demand. As 97% of our reserves are natural gas, this
change in pricing methodology had a significant negative impact on the pricing used in
determining our reserves. The average price used for our 2009 reserve estimate was $3.04 per
MMbtu and $57.65 per barrel For comparability, using the year-end pricing methodology as
required in 2008 and prior years, the Company would have used a price of $5.54 per
Mmbtu and $76.00 per barrel to determine the quantity and PV-10 amount of economically
producible reserves.
 
    
    The SECs modified definition of proved undeveloped oil and gas reserves had a modest
favorable impact on the Companys estimate of reserves as of December 31, 2009. The new
definition allows for proved undeveloped reserves to be established for reserves in
drilling units beyond those immediately adjacent to the drilling unit containing a
producing well. In prior years, the Company was not permitted to establish proved
undeveloped reserves beyond those immediately adjacent to the drilling unit containing a
producing well. This change was of benefit to the Company in well-defined fields, such as
the Pinedale Anticline.
   As of December 31,2009(1)
    
    
    2008
    
    
    2007Oil
    
    
    Natural Gas
    
    
    Oil
    
    
    Natural Gas
    
    
    Oil
    
    
    Natural Gas(Bbls)
    
    
    (Mcf)
    
    
    (Bbls)
    
    
    (Mcf)
    
    
    (Bbls)
    
    
    (Mcf)PROVEDDeveloped
    
    
    312,963
    
    
    
    64,296,948
    
    
    
    295,698
    
    
    
    63,007,126
    
    
    
    253,478
    
    
    
    44,782,553Undevolped
    
    
    106,250
    
    
    
    25,479,722
    
    
    
    124,491
    
    
    
    23,323,694
    
    
    
    159,334
    
    
    
    26,471,312Total proved reserves
    
    
    419,213
    
    
    
    89,776,670
    
    
    
    420,189
    
    
    
    86,330,820
    
    
    
    412,812
    
    
    
    71,253,865
 9




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##### Table of Contents



(1)
    
    The Company adopted the SECs revisions to the oil and gas reporting requirements effective
December 31, 2009.    Total Proved
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Future EstimatedReserves
    
    
    Price
    
    
    Price
    
    
    Future Cash
    
    
    Production and(MMcfe)
    
    
    per Mmbtu
    
    
    barrel of oil
    
    
    Inflows
    
    
    Development Costs
    
    
    Pre-tax PV-10Year End Pricing
    
    
    114,162
    
    
    $
    5.54
    
    
    $
    76.00
    
    
    $
    622,178
    
    
    
    (216,364
    )
    
    $
    229,763SEC Pricing
    
    
    92,292
    
    
    
    3.04
    
    
    
    57.65
    
    
    
    276,374
    
    
    
    (121,938
    )
    
    
    91,133Difference vs.SEC Pricing
    
    
    21,870
    
    
    $
    2.50
    
    
    $
    18.35
    
    
    $
    345,804
    
    
    $
    (94,426
    )
    
    $
    138,630
  10




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As of December 31,2009(1)
    
    
    2008
    
    
    2007Present value of estimated future net cash flows
before income taxes, discounted at 10% (2)
    
    $
    91,133
    
    
    $
    155,766
    
    
    $
    182,594Reconciliation of non-GAAP financial measure:PV-10
    
    $
    91,133
    
    
    $
    155,766
    
    
    $
    182,594Less: Undiscounted income taxes
    
    
    (14,279
    )
    
    
    (58,313
    )
    
    
    (96,370
    )Plus: 10% discount factor
    
    
    5,853
    
    
    
    24,602
    
    
    
    44,075Discounted income taxes
    
    
    (8,426
    )
    
    
    (33,711
    )
    
    
    (52,295
    )Standardized measure of discounted future
net cash flows
    
    $
    82,707
    
    
    $
    122,055
    
    
    $
    130,299
 
 (1)
    
    The Company adopted the SECs revisions to the oil and gas reporting requirements as of
December 31, 2009.(2)
    
    The average prices utilized for December 31, 2009, 2008, and 2007, respectively, were $3.04
per MMBtu and $57.65 per barrel of oil; $4.61 per MMBtu and $38.67 per barrel of oil; and
$5.99 per MMBtu and $86.67 per barrel of oil.  11




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##### Table of Contents



Production
  For the Year Ended December 31,2009
    
    
    2008
    
    
    2007Production:
    
    Oil (Bbls)
    
    Gas (MMcf)
    
    Oil (Bbls)
    
    Gas (MMcf)
    
    Oil (Bbls)
    
    Gas (MMcf)Atlantic Rim
    
    
    
    
    
    
    6,677
    
    
    
    
    
    
    
    4,473
    
    
    
    
    
    
    
    1,708Pinedale Anticline
    
    
    16,741
    
    
    
    1,961
    
    
    
    14,674
    
    
    
    1,547
    
    
    
    6,097
    
    
    
    754Other
    
    
    12,186
    
    
    
    524
    
    
    
    10,994
    
    
    
    540
    
    
    
    7,866
    
    
    
    466Company total
    
    
    28,927
    
    
    
    9,162
    
    
    
    25,668
    
    
    
    6,560
    
    
    
    13,963
    
    
    
    2,928Average sales price ($/Bbl or $/Mcf)Atlantic Rim (1)
    
    
    N/A
    
    
    $
    5.42
    
    
    
    N/A
    
    
    $
    5.86
    
    
    
    N/A
    
    
    $
    5.52Pinedale Anticline
    
    $
    47.40
    
    
    $
    3.39
    
    
    $
    77.10
    
    
    $
    6.62
    
    
    $
    63.93
    
    
    $
    5.03Other
    
    $
    57.49
    
    
    $
    3.09
    
    
    $
    77.42
    
    
    $
    6.39
    
    
    $
    62.08
    
    
    $
    4.17Company average
    
    $
    51.65
    
    
    $
    4.85
    
    
    $
    77.24
    
    
    $
    6.08
    
    
    $
    63.17
    
    
    $
    5.18
 Average production cost ($/mcfe)Atlantic Rim (2)
    
    $
    0.85
    
    
    $
    1.17
    
    
    $
    2.68Pinedale Anticline
    
    $
    0.53
    
    
    $
    0.51
    
    
    $
    0.63Other
    
    $
    1.67
    
    
    $
    1.49
    
    
    $
    1.22Company average
    
    $
    0.83
    
    
    $
    1.04
    
    
    $
    1.89
 
 (1)
    
    Our average gas price in the Atlantic Rim includes the settlements on our financial
hedges which due to accounting rules, is included in our price risk management activities
line on the Consolidated Statement of Operations, totaling $3,503, $2,698, and $0, for the
years ended December 31, 2009, 2008 and 2007, respectively.(2)
    
    Production costs, on a dollars per Mcfe basis, is calculated by dividing production
costs, as stated on the consolidated statement of operations, by total production volumes
during the period. This calculation for the Atlantic Rim excludes certain gathering costs
incurred by the Companys subsidiary, Eastern Washakie Midstream, which are eliminated in
consolidation. 
 Derivative Instruments
  12




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RemainingContractual
    
    Daily
    
    
    
    
    
    
    
    
    
    PriceType of Contract
    
    Volume
    
    Production
    
    Term
    
    Price
    
    Index (1)Fixed Price Swap
    
    
    4,380,000
    
    
    
    12,000
    
    
    
    1/10-12/10
    
    
    $
    4.30
    
    
    CIGCostless Collar
    
    
    2,885,000
    
    
    
    5,000
    
    
    
    8/09-7/11
    
    
    $4.50 floor
    
    NYMEX$7.90 ceilingCostless Collar
    
    
    3,495,000
    
    
    
    5,000
    
    
    
    12/09-11/11
    
    
    $4.50 floor
    
    NYMEX$9.00 ceilingFixed Price Swap
    
    
    2,920,000
    
    
    
    8,000
    
    
    
    1/11-12/11
    
    
    $
    7.07
    
    
    CIGTotal
    
    
    13,680,000
 
 (1)
    
    NYMEX refers to quoted prices on the New York Mercantile Exchange. CIG refers to the
Colorado Interstate Gas price as quoted on the first day of each month.  
 Productive Wells
  Oil
    
    GasState
    
    Gross
    
    Net
    
    Gross
    
    NetWyoming
    
    
    86
    
    
    
    5.99
    
    
    
    1,048
    
    
    
    99.47Other
    
    
    33
    
    
    
    4.49
    
    
    
    5
    
    
    
    0.09Total
    
    
    119
    
    
    
    10.48
    
    
    
    1,053
    
    
    
    99.56
 
 Drilling Activity
  13




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For the Year Ended December 31,2009
    
    2008
    
    2007Gross
    
    Net
    
    Gross
    
    Net
    
    Gross
    
    NetExploratoryOil
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Gas
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    0.50Dry Holes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    0.98Water Injection
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Other
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    1.48DevelopmentOil
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    0.05
    
    
    
    
    
    
    
    Gas
    
    
    42
    
    
    
    3.12
    
    
    
    178
    
    
    
    27.59
    
    
    
    223
    
    
    
    35.06Dry Holes
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    0.69
    
    
    
    
    
    
    
    Water Injection
    
    
    
    
    
    
    
    
    
    
    14
    
    
    
    5.42
    
    
    
    9
    
    
    
    2.72Water Supply
    
    
    1
    
    
    
    1.00
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Other
    
    
    
    
    
    
    
    
    
    
    5
    
    
    
    2.67
    
    
    
    1
    
    
    
    0.0843
    
    
    
    4.12
    
    
    
    199
    
    
    
    36.42
    
    
    
    233
    
    
    
    37.86Total
    
    
    43
    
    
    
    4.12
    
    
    
    199
    
    
    
    36.42
    
    
    
    235
    
    
    
    39.34
  
 Finding and Development Costs
   As of December 312009
    
    
    2008
    
    
    2007Proved Developed (MMcfe)
    
    
    10,543
    
    
    
    17,196
    
    
    
    21,888Proved Undeveloped (MMcfe)
    
    
    11,761
    
    
    
    9,441
    
    
    
    23,317Total Proved Reserves Added
    
    
    22,304
    
    
    
    26,637
    
    
    
    45,205One year finding and development
costs per Mcfe
    
    $
    0.91
    
    
    $
    1.47
    
    
    $
    0.99
   14




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Acreage
   Developed Acres (1)
    
    Undeveloped Acres (2)
    
    Total AcresState
    
    Gross
    
    Net
    
    Gross
    
    Net
    
    Gross
    
    NetWyoming
    
    
    121,541
    
    
    
    9,125
    
    
    
    88,615
    
    
    
    39,223
    
    
    
    210,156
    
    
    
    48,348Nevada
    
    
    
    
    
    
    
    
    
    
    46,372
    
    
    
    39,127
    
    
    
    46,372
    
    
    
    39,127Utah
    
    
    637
    
    
    
    16
    
    
    
    46,440
    
    
    
    21,146
    
    
    
    47,077
    
    
    
    21,162Other
    
    
    5,544
    
    
    
    2,678
    
    
    
    3,732
    
    
    
    799
    
    
    
    9,276
    
    
    
    3,477Total
    
    
    127,722
    
    
    
    11,819
    
    
    
    185,159
    
    
    
    100,295
    
    
    
    312,881
    
    
    
    112,114
  Developed Acres (1)
    
    Undeveloped Acres (2)
    
    Total AcresState
    
    Gross
    
    Net
    
    Gross
    
    Net
    
    Gross
    
    NetWyoming
    
    
    10,464
    
    
    
    162
    
    
    
    27,763
    
    
    
    1,547
    
    
    
    38,227
    
    
    
    1,709Other
    
    
    3,089
    
    
    
    63
    
    
    
    5,633
    
    
    
    483
    
    
    
    8,722
    
    
    
    546Total
    
    
    13,553
    
    
    
    225
    
    
    
    33,396
    
    
    
    2,030
    
    
    
    46,949
    
    
    
    2,255
 
 (1)
    
    Developed acreage is acreage assigned to producing wells for the spacing unit of the
producing formation. Developed acreage in certain of the Companys properties that include
multiple formations with different well spacing requirements may be considered undeveloped for
certain formations, but have only been included as developed acreage in the presentation
above.(2)
    
    Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a
point that would permit the production of commercial quantities of oil and gas regardless of
whether such acreage contains proved reserves.   Expiring AcreageFiscal Year
    
    Gross
    
    Net2010
    
    
    17,021
    
    
    
    12,2582011
    
    
    22,351
    
    
    
    5,9132012 and thereafter
    
    
    320,458
    
    
    
    96,198Total
    
    
    359,830
    
    
    
    114,369
 
 Other Significant Developments since December 31, 2008
  15




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Marketing and Major Customers
   
 Title to Properties
  
 Seasonality
   
 Competition
  16




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Government Regulations
   We are subject to various governmental regulations and environmental risks that may
cause us to incur substantial costs.
  
    
    the Bureau of Land Management (BLM) and the Minerals Management
Service (MMS), which under laws such as the Federal Land Policy
and Management Act, Endangered Species Act, National Environmental
Policy Act and Outer Continental Shelf Lands Act have certain
authority over our operations on federal lands, particularly in
the Rocky Mountains and deepwater Gulf of Mexico;
    
    the US Environmental Protection Agency (EPA) and the Occupational
Safety and Health Administration, which under laws such as the
Comprehensive Environmental Response, Compensation and Liability
Act, as amended, the Resource Conservation and Recovery Act, as
amended, the Oil Pollution Act of 1990, the Clean Air Act, the
Clean Water Act, the Occupational Safety and Health Act and the
recent Final Mandatory Reporting of Greenhouse Gases Rule have
certain authority over environmental, health and safety matters
affecting our operations ;
    
    the Federal Energy Regulatory Commission, which under laws such as
the Energy Policy Act of 2005 has certain authority over the
marketing and transportation of crude oil and natural gas;
    
    other federal agencies with certain authority over our business,
such as the Internal Revenue Service and the SEC, as well as the
NYSE upon which shares of our common stock are traded.
   Environmental Laws and Regulations
  17




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Cautionary Information about Forward-Looking Statements
  
    
    Our ability to maintain adequate liquidity in connection with low oil and gas prices;
    
    The changing political environment in which we operate
    
    Our ability to continue to develop our Atlantic Rim project;
    
    Our ability to obtain, or a decline in, oil or gas production, or a decline in oil or
gas prices;
    
    Our ability to increase our natural gas and oil reserves;
    
    Incorrect estimates of required capital expenditures;
    
    The amount and timing of capital deployment in new investment opportunities;
    
    The volumes of production from our oil and gas development properties, which may be
dependent upon issuance by federal, state, and tribal governments, or agencies thereof, of
drilling, environmental and other permits, and the availability of specialized
contractors, work force, and equipment;
    
    Our future capital requirements and availability of capital resources to fund capital
expenditures;
    
    Our ability to successfully integrate and profitably operate any future acquisitions;
    
    Increases in the cost of drilling, completion and gas collection or other costs of
production and operations;
    
    The possibility that we may be required to take impairment charges to reduce the
carrying value of some of our long-lived assets when indicators of impairment emerge;
    
    Numerous uncertainties inherent in estimating quantities of proved oil and gas reserves
and actual future production rates and associated costs;
 18




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##### Table of Contents




    
    Our ability to remedy any deficiencies that may be identified in the review of our
internal controls;
    
    The credit worthiness of third-parties which we enter into business agreements with;
    
    General economic conditions, tax rates or policies, interest rates and inflation rates;
    
    Changes in or compliance with laws and regulations, particularly those relating to
taxation, safety and protection of the environment;
    
    Weather, climate change and other natural phenomena;
    
    Industry and market changes, including the impact of consolidations and changes in
competition;
    
    The effect of accounting policies issued periodically by accounting standard-setting
bodies;
    
    The actions of third party co-owners of interests in properties in which we also own an
interest;
    
    The cost and effects on our business, including insurance, resulting from terrorist
actions or natural disasters and responses to such actions or events;
    
    The volatility of our stock price; and
    
    The outcome of any future litigation or similar disputes and the impact on any such
outcome or related settlements.
   
 Employees and Office Space
  
 Available Information
 http://www.dble.com/
 
 http://www.dble.com/
 Information on our website is not incorporated by reference into this Form 10-K and should not be
considered a part of this document.
 19




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##### Table of Contents



Glossary
  Bbl.
 Bcf.
 Bcfe.
 Darcy.
 Development well.
 Dry hole
 Estimated net proved reserves.
 Exploratory well.
 Economically producible.
 Farmout
 Field.
 Gross acre.
 Gross well.
 MBbl.
 Mcf.
 Millidarcy.
 Mcfe
 MMcf.
 MMcfe.
 MMBtu.
 Net acres or net wells.
 Permeability.
 20




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##### Table of Contents



Productive well.
 Proved developed reserves.
 Proved reserves.
 Proved undeveloped reserves.
 PV-10 value.
 Recompletion.
 Royalty.
 Royalty interest.
 Undeveloped acreage.
 Working interest
 
 ITEM 1A.
    
    RISK FACTORS
  Our operations are subject to governmental risks that may impact our operations.
  21




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##### Table of Contents




    
    Climate Change. Climate-change legislation establishing a cap-and-trade plan for
green-house gases (GHGs) has been approved by the U.S. House of Representatives. It is not
possible at this time to predict whether or when the U.S. Senate may act on climate-change
legislation.
    
    The U.S. Environmental Protection Agency (EPA) has also taken recent action related to
GHGs. Based on recent developments; the EPA now purports to have a basis to begin
regulating emissions of GHGs under existing provisions of the federal Clean Air Act.
    
    Taxes. The U.S. Presidents Fiscal Year 2011 Budget Proposal includes provisions that
would, if enacted, make significant changes to United States tax laws. These changes
include, but are not limited to, (i) eliminating the immediate deduction for intangible
drilling and development costs, (ii) eliminating the deduction from income for domestic
production activities relating to oil and natural-gas exploration and development, and
(iii) implementing certain international tax reforms.
    
    Hydraulic Fracturing. The U.S. Congress is currently considering legislation to amend
the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil
and natural-gas industry in the hydraulic-fracturing process. Hydraulic fracturing involves
the injection of water, sand and chemicals under pressure into rock formations to stimulate
natural gas production. We find that the use of hydraulic fracturing is necessary to
produce commercial quantities of crude oil and natural gas from many reservoirs.
Currently, regulation of hydraulic fracturing is primarily conducted at the state level
through permitting and other compliance requirements. This legislation, if adopted, could
establish an additional level of regulation and permitting at the federal level.
    
    Derivatives. The U.S. Congress is currently considering derivatives reform legislation
focusing on expanding Federal regulation surrounding the use of financial derivative
instruments, including credit default swaps, commodity derivatives and other
over-the-counter derivatives. Among the recommendations included in the proposals are the
requirements for centralized clearing or settling of such derivatives as well as the
expansion of collateral margin requirements for certain derivative market participants.
Although we do not currently know the exact form any final legislation or rule-making
activity will take, any restriction on the use of OTC instruments could have a significant
impact on our business. Limits on the use of OTC instruments could significantly reduce our
ability to execute strategic price hedges to reduce price uncertainty and to protect cash
flows. In addition, cash collateral requirements could create significant liquidity issues
and exchange system trades may restrict our ability to execute derivative instruments to
fit our strategic needs.
 We may be unable to develop our existing acreage due to the change in the political environment and
administration.
  We may be unable to further develop our coal bed methane projects in the Atlantic Rim, which would
have a significant adverse effect on our current growth opportunities.
  22




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##### Table of Contents



We cannot predict the future price of oil and natural gas and an extended decline in prices
could hurt our profitability, financial condition and ability to grow.
  We may be unable to fund our planned capital expenditures.
  
    
    general economic and financial market conditions;
    
    oil and natural gas prices; and
    
    our market value and operating performance.
  Indebtedness may limit our liquidity and financial flexibility.
   
    
    a portion of our cash flows from operating activities must be used to service our
indebtedness and is not available for other purposes;
    
    we may be at a competitive disadvantage as compared to similar companies that have less
debt;
    
    our credit facility limits the amounts we can borrow to a borrowing base amount, determined by our lenders
in their sole discretion. The lenders can unilaterally adjust the borrowing base and the
borrowings permitted to be outstanding under the credit facility. Any decrease in the
borrowing base could limit our ability to fund operations or future development;
    
    Upon any downward adjustment of the borrowing base, if the outstanding borrowings are in
excess of the
 23




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##### Table of Contents



revised borrowing base, we have the option to repay our indebtedness in
excess of the borrowing base immediately, or in six monthly installments, or pledge
additional properties as collateral. We may not have sufficient funds to make such
repayments under our credit facility.
 
    
    the covenants contained in the agreements governing our outstanding indebtedness and
future indebtedness may limit our ability to borrow additional funds, pay dividends and
make certain investments and may also affect our flexibility in planning for, and reacting
to, changes in the economy and in our industry;
    
    additional financing in the future for working capital, capital expenditures,
acquisitions, general corporate or other purposes may have higher costs and more
restrictive covenants;
    
    additional financing in the future is likely to have higher costs due to the negative
impact of the credit market crisis which restricted access to the bond markets; and
    
    we may be more vulnerable to general adverse economic and industry conditions.
  We are exposed to counterparty credit risk as a result of our receivables and hedging transactions.
    Our credit facility has borrowing base restrictions, which could adversely affect our operations.
   The unavailability or high cost of drilling rigs, equipment, supplies, personnel and other oil
field services could adversely affect our ability to execute our exploration and development plans
on a timely basis and within our budget.
  24




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##### Table of Contents



We do not control all of our operations and development projects.
   
    
    timing and amount of capital expenditures;
    
    expertise and financial resources;
    
    inclusion of other participants in drilling wells; and
    
    use of technology.
  Competition in the oil and natural gas industry is intense, and many of our competitors have
greater financial and other resources than we do.
  
    
    seeking to acquire desirable producing properties or new leases for future exploration;
    
    seeking to acquire the equipment and expertise necessary to develop and operate our
properties; and
    
    Retention and hiring of skilled employees.
  We could be adversely impacted by a variety of changes in the oil and gas market which are beyond
our control.
  We may be unable to find additional reserves, which would adversely impact our ability to sustain
production levels.
  The exploration, development and operation of oil and gas properties involve substantial risks that
may result in a total loss of investment.
  25




---



##### Table of Contents




    
    unexpected drilling conditions;
    
    pressure or irregularities in formations;
    
    equipment failures or accidents;
    
    adverse changes in prices;
    
    weather conditions;
    
    shortages in experienced labor; and
    
    shortages or delays in the delivery of equipment.
  
    
    unusual or unexpected geological formations, pressures, equipment failures or accidents,
fires, explosions, blowouts, cratering, pollution and other environmental risks;
    
    shortages or delays in the availability of drilling rigs and the delivery of equipment;
and
    
    loss of circulation of drilling fluids or other conditions.
  Our industry experiences numerous operating hazards that could result in substantial losses.
   Our prices, net income and cash flows may be impacted adversely by new taxes.
  Our reserves and future net revenues may differ significantly from our estimates.
  26




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##### Table of Contents



Acquisitions are a part of our business strategy and are subject to the risks and uncertainties of
evaluating recoverable reserves and potential liabilities.
    We depend on key personnel.
  Declining economic conditions could negatively impact our business.
  27




---



##### Table of Contents



The trading volatility and price of our common stock may be affected by many factors.
  
    
    The current financial crisis, which has caused significant market volatility worldwide;
    
    Governmental action or inaction in light of key indicators of economic activity or
events that can significantly influence U.S. financial markets, and media reports and
commentary about economic or other matters, even when the matter in question does not
directly relate to our business; and
    
    Trading activity in our common stock, which can be a reflection of changes in the prices
for oil and gas, or market commentary or expectations about our business and overall
industry.
 
 ITEM 3. LEGAL PROCEEDINGS
    
 ITEM 4. RESERVED
 28




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##### Table of Contents



PART II
 
 ITEM 5. MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURTIES.
 Common Stock
 Market Information.
  Quarter Ended
    
    High
    
    LowDecember 31, 2009
    
    $
    6.02
    
    
    $
    4.04September 30, 2009
    
    
    5.40
    
    
    
    3.75June 30, 2009
    
    
    6.49
    
    
    
    3.62March 31, 2009
    
    
    11.23
    
    
    
    3.00December 31, 2008
    
    $
    13.76
    
    
    $
    4.02September 30, 2008
    
    
    18.99
    
    
    
    12.55June 30, 2008
    
    
    19.91
    
    
    
    16.91March 31, 2008
    
    
    17.25
    
    
    
    13.05
  Holders
 Dividends
 29




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##### Table of Contents



Performance Graph
 Comparison of Five-Year Cumulative Total Return Among
Double Eagle Petroleum Co., the Standard and Poors 500 Stock Index, and the Peer Group Index
Total Return (Stock Price Plus Reinvested Dividends)
 
 December 31,January 1, 2005
    
    2005
    
    2006
    
    2007
    
    2008
    
    2009Double Eagle Petroleum
    
    $
    100.00
    
    
    $
    105.64
    
    
    $
    127.14
    
    
    $
    81.62
    
    
    $
    36.35
    
    
    $
    22.37Peer Group
    
    $
    100.00
    
    
    $
    184.91
    
    
    $
    180.66
    
    
    $
    180.90
    
    
    $
    132.80
    
    
    $
    116.82S&P500
    
    $
    100.00
    
    
    $
    103.00
    
    
    $
    117.03
    
    
    $
    121.16
    
    
    $
    74.53
    
    
    $
    92.01
   Series A Cumulative Preferred Stock
 Market Information.
 30




---



##### Table of Contents



Quarter Ended
    
    High
    
    LowDecember 31, 2009
    
    $
    24.00
    
    
    $
    20.50September 30, 2009
    
    
    23.00
    
    
    
    18.15June 30, 2009
    
    
    21.40
    
    
    
    15.50March 31, 2009
    
    
    22.01
    
    
    
    12.90December 31, 2008
    
    $
    21.35
    
    
    $
    14.00September 30, 2008
    
    
    19.75
    
    
    
    18.79June 30, 2008
    
    
    27.00
    
    
    
    25.50March 31, 2008
    
    
    30.20
    
    
    
    23.40
  Holders
 Dividends
 Redemption Provisions.
 Redemption Date on or Before
    
    Redemption PriceJune 30, 2010
    
    $
    25.50June 30, 2011
    
    $
    25.25June 30, 2012 or thereafter
    
    $
    25.00
 Liquidation Preference.
 Voting Rights.
 31




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##### Table of Contents



ITEM 6. SELECTED FINANCIAL DATA
  Year Ended December 31,2009
    
    2008
    
    2007
    
    2006
    
    2005(In thousands, except per share and volume data)Statement of Operations InformationTotal operating revenues
    
    $
    44,791
    
    
    $
    49,578
    
    
    $
    17,197
    
    
    $
    19,032
    
    
    $
    20,496Income (loss) from operations (1)
    
    $
    3,884
    
    
    $
    15,949
    
    
    $
    (17,909
    )
    
    $
    3,695
    
    
    $
    5,985Net income (loss)
    
    $
    1,209
    
    
    $
    10,381
    
    
    $
    (11,603
    )
    
    $
    2,109
    
    
    $
    3,965Net income (loss) attributable to
common stock
    
    $
    (2,514
    )
    
    $
    6,658
    
    
    $
    (13,413
    )
    
    $
    2,109
    
    
    $
    3,965Net income (loss) per common share:Basic
    
    $
    (0.25
    )
    
    $
    0.73
    
    
    $
    (1.47
    )
    
    $
    0.24
    
    
    $
    0.46Diluted
    
    $
    (0.25
    )
    
    $
    0.73
    
    
    $
    (1.47
    )
    
    $
    0.24
    
    
    $
    0.46Balance Sheet InformationTotal assets
    
    $
    150,494
    
    
    $
    171,989
    
    
    $
    84,597
    
    
    $
    64,406
    
    
    $
    44,211Line of credit
    
    $
    34,000
    
    
    $
    24,639
    
    
    $
    3,445
    
    
    $
    13,221
    
    
    $
    3,000Total long-term liabilities
    
    $
    44,684
    
    
    $
    33,011
    
    
    $
    5,895
    
    
    $
    17,184
    
    
    $
    5,732Stockholders equity and preferred stock
    
    $
    84,696
    
    
    $
    92,875
    
    
    $
    66,596
    
    
    $
    33,042
    
    
    $
    29,778Cash Flow InformationNet cash provided by (used in):Operating activities
    
    $
    22,062
    
    
    $
    22,904
    
    
    $
    5,166
    
    
    $
    10,951
    
    
    $
    10,319Investing activities
    
    $
    (21,461
    )
    
    $
    (40,778
    )
    
    $
    (42,056
    )
    
    $
    (22,241
    )
    
    $
    (16,259
    )Financing activities
    
    $
    5,081
    
    
    $
    17,749
    
    
    $
    36,404
    
    
    $
    10,470
    
    
    $
    3,701Total proved reserves(2)Oil (MBbl)
    
    
    419
    
    
    
    420
    
    
    
    413
    
    
    
    360
    
    
    
    329Gas (MMcf)
    
    
    89,777
    
    
    
    86,331
    
    
    
    71,254
    
    
    
    48,497
    
    
    
    47,234MMcfe
    
    
    92,292
    
    
    
    88,852
    
    
    
    73,731
    
    
    
    50,657
    
    
    
    49,207Net production volumesOil (Bbl)
    
    
    28,927
    
    
    
    25,668
    
    
    
    13,963
    
    
    
    12,729
    
    
    
    15,470Gas (Mcf)
    
    
    9,162,362
    
    
    
    6,559,662
    
    
    
    2,928,335
    
    
    
    3,140,653
    
    
    
    2,976,094Mcfe
    
    
    9,335,924
    
    
    
    6,713,670
    
    
    
    3,012,113
    
    
    
    3,217,027
    
    
    
    3,068,914
 
 (1)
    
    Effective January 1, 2006, Double Eagle adopted the provisions of ASC 718  Stock
Compensation.(2)
    
    Effective December 31, 2009, Double Eagle adopted the SECs new oil and gas reserve
reporting guidelines. 
 ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 (Amounts in thousands of dollars, except share, per share data, and amounts per unit of production)
 The following discussion includes forward-looking statements. Such statements are described in the
section entitled Forward-Looking Statements on page 18 of this Form 10-K.
 32




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##### Table of Contents



BUSINESS OVERVIEW
  Reserves
  Developments since December 31, 2008:
   
    
    At our Company-operated Catalina Unit, located within the Atlantic Rim, we completed
and began producing 15 wells that were drilled as part of the 2008 drilling program. We
also began a well workover and production enhancement program in the third quarter of
2009. This program targeted certain existing wells, which had experienced production
declines over the past year. The Company is still in process of assessing the results of
the workover program.
    
    At the Sun Dog Unit, in which the Company currently has a 8.89% working interest,
approximately 17 wells were completed and brought on-line for production during 2009. The
operator also performed well workovers on approximately 11 existing wells, including
fracture stimulation, which had not previously been performed on Sun Dog wells. We have
not yet realized a benefit from the well workovers, as we are awaiting additional water
injection capacity within this unit
    
    In the Mesa B Unit at the Pinedale Anticline, 17 new wells were brought on-line
during the second, third and fourth quarters of 2009. We are also currently participating
in the drilling of 16 additional wells. These wells were spud in the fall of 2009, and
are expected to be completed in 2010 at a rate of eight wells in May, four wells in July,
and four wells in August. We expect the operator will spud 12-16 additional wells in the
second half of 2010.
 33




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##### Table of Contents



Our Industry:
   
    
    We attempt to reduce our overall exposure to commodity price fluctuations through the
use of various hedging instruments for some of our production. The duration of our various
hedging instruments depends on our view of market conditions, available contract prices and
our operating strategy. Use of such hedging instruments may limit the risk of fluctuating
cash flows. As of December 31, 2009, we had derivative instruments in place for
approximately 77% of our current daily net production.
    
    We have an inventory of attractive drilling locations, allowing us to grow reserves and
replace and expand production organically without having to rely solely on acquisitions.
Drilling opportunities in both the Atlantic Rim and the Pinedale Anticline are expected to
last for several years.
 Development Outlook for 2010:
  Atlantic Rim.
 Pinedale Anticline.
  34




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##### Table of Contents



RESULTS OF OPERATIONS
  As of and for the year ended December 31,
    
    
    Percent change between years2009
    
    
    2008
    
    
    2007
    
    
    2008 to 2009
    
    
    2007 to 2008Total proved reservesOil (MBbl)
    
    
    419
    
    
    
    420
    
    
    
    413
    
    
    
    0
    %
    
    
    2
    %Gas (MMcf)
    
    
    89,777
    
    
    
    86,331
    
    
    
    71,254
    
    
    
    4
    %
    
    
    21
    %MMcfe
    
    
    92,292
    
    
    
    88,852
    
    
    
    73,731
    
    
    
    4
    %
    
    
    21
    %Net production volumesOil (Bbl)
    
    
    28,927
    
    
    
    25,668
    
    
    
    13,963
    
    
    
    13
    %
    
    
    84
    %Gas (Mcf)
    
    
    9,162,362
    
    
    
    6,559,662
    
    
    
    2,928,335
    
    
    
    40
    %
    
    
    124
    %Mcfe
    
    
    9,335,924
    
    
    
    6,713,670
    
    
    
    3,012,113
    
    
    
    39
    %
    
    
    123
    %Average daily producitonMcfe
    
    
    25,578
    
    
    
    18,343
    
    
    
    8,252
    
    
    
    39
    %
    
    
    122
    %Average price per unit productionOil (Bbl)
    
    $
    51.65
    
    
    $
    77.24
    
    
    $
    63.17
    
    
    
    -33
    %
    
    
    22
    %Gas (Mcf)
    
    $
    4.85
    
    
    $
    6.08
    
    
    $
    5.18
    
    
    
    -20
    %
    
    
    17
    %Mcfe
    
    $
    4.92
    
    
    $
    6.23
    
    
    $
    5.33
    
    
    
    -21
    %
    
    
    17
    %Oil and gas production revenuesOil revenues
    
    $
    1,494
    
    
    $
    1,983
    
    
    $
    882
    
    
    
    -25
    %
    
    
    125
    %Gas revenues
    
    
    40,904
    
    
    
    37,166
    
    
    
    15,162
    
    
    
    10
    %
    
    
    145
    %Total
    
    $
    42,398
    
    
    $
    39,149
    
    
    $
    16,044
    
    
    
    8
    %
    
    
    144
    %Oil and gas production costsProduction costs
    
    $
    7,754
    
    
    $
    7,007
    
    
    $
    5,696
    
    
    
    11
    %
    
    
    23
    %Production taxes
    
    
    3,652
    
    
    
    4,701
    
    
    
    1,933
    
    
    
    -22
    %
    
    
    143
    %Total
    
    $
    11,406
    
    
    $
    11,708
    
    
    $
    7,629
    
    
    
    -3
    %
    
    
    53
    %Data on a per Mcfe basisAverage price (1)
    
    $
    4.92
    
    
    $
    6.23
    
    
    $
    5.33
    
    
    
    -21
    %
    
    
    17
    %Production costs (2)
    
    
    0.83
    
    
    
    1.04
    
    
    
    1.89
    
    
    
    -20
    %
    
    
    -45
    %Production taxes
    
    
    0.39
    
    
    
    0.70
    
    
    
    0.64
    
    
    
    -44
    %
    
    
    9
    %Depletion and amortization
    
    
    1.94
    
    
    
    1.65
    
    
    
    1.51
    
    
    
    18
    %
    
    
    9
    %Total operating costs
    
    
    3.16
    
    
    
    3.39
    
    
    
    4.04
    
    
    
    -7
    %
    
    
    -16
    %Gross margin
    
    $
    1.76
    
    
    $
    2.84
    
    
    
    1.29
    
    
    
    -38
    %
    
    
    120
    %Gross margin percentage
    
    
    36
    %
    
    
    46
    %
    
    
    24
    %
    
    
    -22
    %
    
    
    92
    %
 
 (1)
    
    Our average gas price per Mcfe realized for the years ended December 31, 2009, 2008 and
2007 is calculated by summing a) production revenue received from third parties for sale of
our gas, included in the oil and gas sales line item on the Consolidated Statement of
Operations, b) settlement of our cash flow hedges included within oil and gas sales on the
Consolidated Statement of Operations and c) realized gain/loss on our financial hedges, which
due to accounting rules is included in our price risk management activities line on the
Consolidated Statement of Operations, totaling $3,503, $2,698, and $0, for the years ended
December 31, 2009, 2008 and 2007, respectively. This amount is divided by the total Mcfe
volume for the period.(2)
    
    Production costs, on a dollars per Mcfe basis, is calculated by dividing production costs, as
stated on the consolidated statement of operations, by total production volumes during the
period. This calculation excludes certain gathering costs incurred by the Companys
subsidiary, Eastern Washakie Midstream, which are eliminated in consolidation. 35




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##### Table of Contents



Year ended December 31, 2009 compared to the year ended December 31, 2008
 Oil and gas sales volume and price comparisons
       36




---



##### Table of Contents



Transportation and gathering revenue
  Price risk management
  Oil and gas production expenses, production taxes, and depreciation, depletion and amortization
    Pipeline operating costs
  General and administrative
  37




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##### Table of Contents



Income taxes
  Year ended December 31, 2008 compared to the year ended December 31, 2007
 Oil and gas sales volume and price comparisons
      38




---



##### Table of Contents



Transportation and gathering revenue
  Price risk management
  Oil and gas production expenses, depreciation, depletion and amortization
   Pipeline operating costs
  Dry hole and impairment
  General and administrative
  39




---



##### Table of Contents



Income taxes
  LIQUIDITY AND CAPITAL RESOURCES
  Our Credit Facility at December 31, 2009
      40




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##### Table of Contents



Capital Expenditures
  Year Ended December 31,2009
    
    
    2008Property acquisition costs
    
    $
    16
    
    
    $
    30Exploration
    
    
    59
    
    
    
    536Development
    
    
    21,042
    
    
    
    64,462$
    21,117
    
    
    $
    65,028
 Year Ended December 31, 2009
      Year Ended December 31, 2008
    41




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##### Table of Contents



Calendar 2010
  Cash Flows
  As of and for the Years Ended December 31,
    
    Percent Change Between Years2009
    
    2008
    
    2007
    
    2008 to 2009
    
    2007 to 2008Financial informationWorking capital
    
    $
    (4,067
    )
    
    $
    (6,314
    )
    
    $
    (7,012
    )
    
    
    36
    %
    
    
    10
    %Balance oustanding on credit facility
    
    $
    34,000
    
    
    $
    24,639
    
    
    $
    3,445
    
    
    
    38
    %
    
    
    615
    %Stockholders equity and preferred stock
    
    $
    84,696
    
    
    $
    92,875
    
    
    $
    66,596
    
    
    
    -9
    %
    
    
    39
    %Net income (loss) attributable to
common stock
    
    $
    (2,514
    )
    
    $
    6,658
    
    
    $
    (13,413
    )
    
    
    -138
    %
    
    
    -150
    %Net income (loss) per common share:Basic
    
    $
    (0.25
    )
    
    $
    0.73
    
    
    $
    (1.47
    )
    
    
    -134
    %
    
    
    150
    %Diluted
    
    $
    (0.25
    )
    
    $
    0.73
    
    
    $
    (1.47
    )
    
    
    -134
    %
    
    
    150
    %Net cash provided by
operating activities
    
    $
    22,062
    
    
    $
    22,904
    
    
    $
    5,166
    
    
    
    -4
    %
    
    
    343
    %Net cash used in
investing activities
    
    $
    (21,461
    )
    
    $
    (40,778
    )
    
    $
    (42,056
    )
    
    
    -47
    %
    
    
    -3
    %Net cash provided by
financing activities
    
    $
    5,081
    
    
    $
    17,749
    
    
    $
    36,404
    
    
    
    -71
    %
    
    
    -51
    %
 Net cash provided by operating activities
   42




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##### Table of Contents



Net cash used in investing activities
  Net cash used in financing activities
  Contractual Obligations
  One year
    
    
    2 - 3
    
    
    4 - 5
    
    
    More thanTotal
    
    
    or less
    
    
    Years
    
    
    Years
    
    
    5 YearsLine of credit (a)
    
    $
    34,000
    
    
    $
    
    
    
    $
    
    
    
    $
    34,000
    
    
    $
    Interest on line of credit (b)
    
    
    4,785
    
    
    
    1,551
    
    
    
    3,102
    
    
    
    132
    
    
    
    Capital leases
    
    
    1,506
    
    
    
    753
    
    
    
    753
    
    
    
    
    
    
    
    Operating leases
    
    
    7,359
    
    
    
    2,019
    
    
    
    3,939
    
    
    
    1,401
    
    
    
    Total contractual cash
commitments
    
    $
    47,650
    
    
    $
    4,323
    
    
    $
    7,794
    
    
    $
    35,533
    
    
    $
    
 
 (a)
    
    The amount listed reflects the balance outstanding as of December 31, 2009. Effective
February 5, 2010, we entered into a amended and restated credit agreement, which extended
the maturity on our credit facility from July 31, 2010 to January 31, 2013. Any balance
outstanding at January 31, 2013, is due at that time.(b)
    
    The interest rate assumed on the credit facility is 4.5% per annum, which is the rate
in effect at December 31, 2009. Off-Balance Sheet Arrangements
   CONTRACTED VOLUMES
 Derivative Instruments
  43




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##### Table of Contents



RemainingContractual
    
    Daily
    
    
    
    
    
    
    PriceType of Contract
    
    Volume
    
    Production
    
    
    Term
    
    Price
    
    Index (1)Fixed Price Swap
    
    4,380,000
    
    
    12,000
    
    
    1/10-12/10
    
    $4.30
    
    CIGCostless Collar
    
    2,885,000
    
    
    5,000
    
    
    8/09-7/11
    
    $4.50 floor
    
    NYMEX$7.90 ceilingCostless Collar
    
    3,495,000
    
    
    5,000
    
    
    12/09-11/11
    
    $4.50 floor
    
    NYMEX$9.00 ceilingFixed Price Swap
    
    2,920,000
    
    
    8,000
    
    
    1/11-12/11
    
    $7.07
    
    CIGTotal
    
    13,680,000
 
 (1)
    
    NYMEX refers to quoted prices on the New York Mercantile Exchange. CIG refers to the
Colorado Interstate Gas price as quoted on the first day of each month.  Other Volumes Contracted
  CRITICAL ACCOUNTING ESTIMATES
  Successful Efforts Method of Accounting
  44




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##### Table of Contents



Reserve Estimates
  Impairment of Long-Lived Assets
  Asset Retirement Obligation
  45




---



##### Table of Contents



Derivative Instruments
   Fair Value of Measurements
   Share-Based Compensation
    Recently Adopted Accounting Pronouncements
 The FASB Accounting
Standards Codification and the Hierarchy of Generally Accepted Accounting Principles
 46




---



##### Table of Contents



New Accounting Pronouncements
  47




---



##### Table of Contents



7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 Interest Rate Risks
  Commodity Price Risks
  Risk Policy and Control
    48




---



##### Table of Contents



RemainingContractual
    
    Daily
    
    
    
    
    
    
    PriceType of Contract
    
    Volume
    
    Production
    
    
    Term
    
    Price
    
    Index (1)Fixed Price Swap
    
    4,380,000
    
    
    12,000
    
    
    1/10-12/10
    
    $4.30
    
    CIGCostless Collar
    
    2,885,000
    
    
    5,000
    
    
    8/09-7/11
    
    $4.50 floor
    
    NYMEX$7.90 ceilingCostless Collar
    
    3,495,000
    
    
    5,000
    
    
    12/09-11/11
    
    $4.50 floor
    
    NYMEX$9.00 ceilingFixed Price Swap
    
    2,920,000
    
    
    8,000
    
    
    1/11-12/11
    
    $7.07
    
    CIGTotal
    
    13,680,000
 
 (1)
    
    NYMEX refers to quoted prices on the New York Mercantile Exchange. CIG refers to the
Colorado Interstate Gas price as quoted on the first day of each month.  
 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
  
 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
  
 ITEM 9A. CONTROLS AND PROCEDURES
 Evaluation of Disclosure Controls and Procedures
  Managements Annual Report on Internal Control Over Financial Reporting
  (i)
    
    pertain to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the Company;(ii)
    
    provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the Company are being made only in
accordance with authorizations of management and directors of the Company; and
 49




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##### Table of Contents



(iii)
    
    provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use or disposition of the Companys assets that could have a material effect
on the financial statements.
  Internal
Control-Integrated Framework
  Changes in Internal Control over Financial Reporting
   50




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##### Table of Contents



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 Internal Control  Integrated
Framework Managements Report on Internal Control Over Financial Reporting
  (a) (b) (c)
  Internal
Control  Integrated Framework
  HEIN & ASSOCIATES LLP
 
 51




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##### Table of Contents



ITEM 9B. OTHER INFORMATION
 .
 
 PART III
 Pursuant to instruction G(3) to Form 10-K, the following Items 10,11,12,13 and 14 will be included
in an amendment to this Form 10-K or in Double Eagles definitive proxy statement for the 2010
annual meeting of stockholders to be filed within 120 days from December 31,
 
 ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
 Code of Conduct and Ethics
 http://www.dble.com
 
 ITEM 11. EXECUTIVE COMPENSATION
  
 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS
 Equity Compensation Plans.
 (c)Number of securities(a)
    
    
    
    
    
    remaining availableNumber of
    
    
    (b)
    
    
    for future issuancesecurities to be
    
    
    Weighted-
    
    
    under equityissued upon
    
    
    average
    
    
    compensation plansexercise of
    
    
    exercise price
    
    
    (excluding securitiesoutstanding
    
    
    of outstanding
    
    
    reflected in columnPlan category
    
    options
    
    
    options
    
    
    (a))Equity Compensation plans
approved by security holders
    
    
    647,897
    
    
    $
    15.06
    
    
    
    138,366
    (1)
 
 (1)
    
    Represents no shares available for issuance under the 1996 Stock Option Plan and the 2000
Stock Option Plan; 14,500 shares available for issuance under the 2002 Stock Option Plan; 33,099
shares available for issuance under the 2003 Stock Option and Compensation Plan and 90,767 shares
available for issuance under the 2007 Stock Incentive Plan. 
 ITEM 13. CERTAIN RELATIONSHIPS, RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
  
 ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICE
 52




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##### Table of Contents



PART IV
 
 ITEM 15. EXHIBITS , FINANCIAL STATEMENT SCHEDULES
  Audit Report of Independent Registered Public Accounting Firm
    
    
    F-1Consolidated Balance Sheets
    
    
    F-2Consolidated Statements of Operations
    
    
    F-3Consolidated Statements of Cash Flows
    
    
    F-4Consolidated Statements of Stockholders Equity
    
    
    F-5Notes to Consolidated Financial Statements
    
    
    F-7
  Exhibits.
 Exhibit No.
    
    Description2.1(a)
    
    Agreement and Plan of Merger, dated March 30, 2009, by and among the
Company, DBLE Acquisition Corporation, and Petrosearch Energy
Corporation (incorporated by reference from Exhibit 2.1 of the
Companys Current Report of Form 8-K dated March 31, 2009)2.1(b)
    
    Form of Voting Agreement (incorporated by reference from Exhibit 2.2
of the Companys Current Report of Form 8-K dated March 31, 2009)3.1(a)
    
    Articles of Incorporation filed with the Maryland Secretary of State
on January 23, 2001 (incorporated by reference from Exhibit 3.1(a) of
the Companys Annual Report on Form 10-KSB for the year ended August
31, 2001).3.1(b)
    
    Certificate of Correction filed with the Maryland Secretary of State
on February 15, 2001 concerning the Articles of Incorporation
(incorporated by reference from Exhibit 3.1(b) of the Companys Annual
Report on Form 10-KSB for the year ended August 31, 2001).3.1(c)
    
    Articles of Merger filed with the Maryland Secretary of State on
February 15, 2001 (incorporated by reference from Exhibit 3.1(c) of
the Companys Annual Report on Form 10-KSB for the year ended August
31, 2001).3.1(d)
    
    Certificate of Correction filed with the Maryland Secretary of State
(incorporated by reference from Exhibit 3 of the Companys Quarterly
Report on Form 10-QSB for the quarter ended November 30, 2001).3.1(e)
    
    Certificate of Correction to the Articles of Incorporation, filed with
the Maryland Department of Assessments and Taxation on June 1, 2007
(incorporated by reference from Exhibit 3.3 of the Companys Current
Report of Form 8-K dated June 29, 2007).3.1(f)
    
    Articles of Amendment, filed with the Maryland Department of
Assessments and Taxation on June 26, 2007 (incorporated by reference
from Exhibit 3.1 of the companys Current report on Form 8-K dated
June 29, 2007).3.1(g)
    
    Articles Supplementary, filed with the Maryland Department of
Assessments and Taxation on June 29, 2007 (incorporated by reference
from Exhibit 3.2 of the Companys Current report of Form 8-K dated
June 29, 2007).
 53




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##### Table of Contents



Exhibit No.
    
    Description3.1(h)
    
    Articles Supplementary of Junior Participating Preferred Stock, Series
B, dated as of August 21, 2007 (incorporated by reference from Exhibit
3.1 of the Companys Current report of Form 8-K dated August 28,
2007).3.2(a)
    
    Bylaws of the Company (incorporated by reference from Exhibit 3.2 of
the Companys Annual Report on Form 10-KSB, filed for the year ended
August 31, 2001).3.2(b)
    
    Bylaws of the Company, as amended and restated on March 14, 2007
(incorporated by reference from Exhibit 3.2 of the Companys Current
report on Form 8-K, filed on March 14, 2007).3.2(c)
    
    Second Amendment and Restated Bylaws of the Company (incorporated by
reference from Exhibit 3.2 of the Companys Current report on Form 8-K
dated June 11, 2007).4.1(a)
    
    Form of Warrant Agreement concerning Common Stock Purchase Warrants
(incorporated by reference from Exhibit 4.3 of the Amendment No. 1 to
the Companys Registration Statement on Form SB-2 filed on November
27, 1996, SEC Registration No. 333-14011).4.1(b)
    
    Shareholder Rights Agreement, dated as of August 24, 2007
(incorporated herein by reference to the Companys Current report on
Form 8-A filed on August 24, 2007).4.1(c)
    
    Articles Supplementary, filed with the Maryland Department of
Assessments and Taxation on June 29, 2007 (incorporated by reference
from Exhibit 3.2 of the Companys Current report on Form 8-K dated
June 29, 2007).4.1(d)
    
    Articles Supplementary of Junior Participating Preferred Stock, Series
B, dated as of August 21, 2007 (incorporated by reference from Exhibit
3.1 of the Companys Current report of Form 8-K dated August 28,
2007).10.1(a)
    
    Debt Modification Agreement, effective August 1, 2006, including
Commercial Loan Agreement dated January 3, 2000, between Double Eagle
Petroleum Co. and American National Bank (filed as Exhibit 10.1 to the
Companys Quarterly Report on Form 10-Q for the quarter ended June 30,
2006, and incorporated herein by reference).10.1(b)
    
    Debt Modification Agreement, effective July 1, 2007, between Double
Eagle Petroleum Co. and American National Bank (incorporated by
reference from Exhibit 10.1 to the Companys Current report on Form
8-K dated July 5, 2007).10.1(c)
    
    Credit Agreement dated February 26, 2009 between Double Eagle
Petroleum Co. and Bank of Oklahoma, N.A. et.al (incorporated by
reference from Exhibit 10.1 to the Companys Current report on Form
8-K dated February 26, 2009).10.1(d)
    
    Promissory Term Note dated February 26, 2009 between Double Eagle
Petroleum Co. and Bank of Oklahoma, N.A. (incorporated by reference
from Exhibit 10.2 to the Companys Current report on Form 8-K dated
February 26, 2009).10.1(e)
    
    Revolving Notes dated February 26, 2009 between Double Eagle Petroleum
Co. and Bank of Oklahoma, N.A. et.al (incorporated by reference from
Exhibit 10.3 to the Companys Current report on Form 8-K dated
February 26, 2009).10.1(f)
    
    Double Eagle Petroleum Co. 2007 Stock Incentive Plan, Form of
Incentive Stock Option Agreement and Form of Non-Qualified Stock
Option Agreement (incorporated by reference from Exhibit 10.1, 10.2
and 10.3 to the Companys Current report on Form 8-K dated May 29,
2007).10.1(g)
    
    Employment Agreement between the Company and Richard Dole, dated
September 4 2008 (incorporated by reference from Exhibit 10.1 of the
Companys Current Report of Form 8-K dated September 9, 2008).10.1(h)
    
    Employment Agreement between the Company and Kurtis Hooley, dated
September 4, 2008 (incorporated by reference from Exhibit 10.2 of the
Companys Current Report of Form 8-K dated September 9, 2008).
 54




---



##### Table of Contents



Exhibit No.
    
    Description10.1(i)
    
    Employment Agreement between the Company and D. Steven Degenfelder,
dated September 4, 2008 (incorporated by reference from Exhibit 10.3
of the Companys Current Report of Form 8-K dated September 9, 2008).10.1(j)
    
    Employment Agreement between the Company and Robert Reiner, dated
September 4, 2008 (incorporated by reference from Exhibit 10.4 of the
Companys Current Report of Form 8-K dated September 9, 2008).10.1(k)
    
    Employment Agreement between the Company and Aubrey Harper, dated
September 4, 2008 (incorporated by reference from Exhibit 10.5 of the
Companys Current Report of Form 8-K dated September 9, 2008).10.1(i)
    
    First Amendment to Credit Agreement dated July 22, 2009 between Double
Eagle Petroleum Co. and Bank of Oklahoma, N.A. et.al (incorporated by
reference from Exhibit 10.1 of the Companys Current Report of Form
8-K dated July 22, 2009).14.1
    
    Code of Business Conduct and Ethics (filed as Exhibit 99.2 to the
Companys Annual Report on Form 10-KSB for the year ended December 31,
2004, and incorporated herein by reference).21.1*
    
    Subsidiaries of registrant.23.1*
    
    Consent of Hein & Associates LLP.23.2*
    
    Consent of Netherland, Sewell & Associates, Inc.31.1*
    
    Certification of Principal Executive Officer and Chief Executive
Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31.2*
    
    Certification of Principal Accounting Officer and Chief Financial
Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.32*
    
    Certification Pursuant to 18 U.S.C. Section 1150 as adopted pursuant
to section 906 of the Sarbanes-Oxley Act of 2002.99.1*
    
    Report of Netherland, Sewell & Associates, Inc. dated January 28, 2010.
 
 *
    
    Filed with this Form 10-K. 55




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##### Table of Contents



SIGNATURES
  DOUBLE EAGLE PETROLEUM CO.
 Date: March 4, 2010
    
    /s/ Richard DoleRichard DoleChief Executive OfficerDate: March 4, 2010
    
    /s/ Kurtis S. HooleyKurtis S. HooleyChief Financial Officer
  Date:March 4, 2010
    
    /s/ Richard DolePrincipal Executive OfficerChief Executive OfficerDate:March 4, 2010
    
    /s/ Kurtis S. HooleyChief Financial OfficerPrincipal Accounting OfficerDate: March 4, 2010
    
    /s/ Sigmund BalabanSigmund Balaban, DirectorDate: March 4, 2010
    
    /s/ Roy G. CoheeRoy G. Cohee, DirectorDate: March 4, 2010
    
    /s/ Brent HathawayBrent Hathaway, Director
 56




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##### Table of Contents



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
    Internal Control 
Integrated Framework
 HEIN & ASSOCIATES LLP
 
 F-1




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##### Table of Contents



DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED BALANCE SHEETS(Amounts in thousands of dollars except share and per share data)
 December 31,
    
    
    December 31,2009
    
    
    2008ASSETSCurrent assets:Cash and cash equivalents
    
    $
    5,682
    
    
    $
    Cash held in escrow
    
    
    611
    
    
    
    605Accounts receivable, net
    
    
    6,772
    
    
    
    21,381Assets from price risk management
    
    
    
    
    
    
    14,290Other current assets
    
    
    3,982
    
    
    
    3,513Total current assets
    
    
    17,047
    
    
    
    39,789Oil and gas properties and equipment, successful efforts method:Developed properties
    
    
    165,279
    
    
    
    133,516Wells in progress
    
    
    7,544
    
    
    
    18,518Gas transportation pipeline
    
    
    5,465
    
    
    
    5,465Undeveloped properties
    
    
    2,502
    
    
    
    2,907Corporate and other assets
    
    
    1,914
    
    
    
    1,920182,704
    
    
    
    162,326Less accumulated depreciation, depletion and amortization
    
    
    (53,682
    )
    
    
    (35,253
    )Net properties and equipment
    
    
    129,022
    
    
    
    127,073Deferred tax asset
    
    
    
    
    
    
    Assets from price risk management
    
    
    3,566
    
    
    
    5,029Other assets
    
    
    859
    
    
    
    98TOTAL ASSETS
    
    $
    150,494
    
    
    $
    171,989LIABILITIES, PREFERRED STOCK, AND STOCKHOLDERS EQUITYCurrent liabilities:Accounts payable
    
    $
    6,177
    
    
    $
    35,488Accrued expenses
    
    
    6,918
    
    
    
    6,794Liabilities from price risk management
    
    
    4,739
    
    
    
    Accrued production taxes
    
    
    2,439
    
    
    
    3,017Capital lease obligations, current portion
    
    
    533
    
    
    
    522Other current liabilities
    
    
    308
    
    
    
    282Total current liabilities
    
    
    21,114
    
    
    
    46,103Credit facility
    
    
    34,000
    
    
    
    24,639Asset retirement obligation
    
    
    4,807
    
    
    
    4,208Liabilities from price risk management
    
    
    430
    
    
    
    Deferred tax liability
    
    
    4,620
    
    
    
    2,470Capital lease obligations, long-term portion
    
    
    545
    
    
    
    1,078Other long-term liabilities
    
    
    282
    
    
    
    616Total liabilities
    
    
    65,798
    
    
    
    79,114Preferred stock, $0.10 par value; 10,000,000 shares authorized;
1,610,000 shares issued and outstanding as of
December 31, 2009 and December 31, 2008
    
    
    37,972
    
    
    
    37,972Stockholders equity:Common stock, $0.10 par value; 50,000,000 shares authorized;
11,090,725 and 9,192,356 shares issued and outstanding as of
December 31, 2009 and December 31, 2008, respectively
    
    
    1,109
    
    
    
    919Additional paid-in capital
    
    
    43,640
    
    
    
    35,122Retained earnings (accumulated deficit)
    
    
    (342
    )
    
    
    2,172Accumulated other comprehensive income
    
    
    2,317
    
    
    
    16,690Total stockholders equity
    
    
    46,724
    
    
    
    54,903TOTAL LIABILITIES, PREFERRED STOCK AND STOCKHOLDERS EQUITY
    
    $
    150,494
    
    
    $
    171,989
  F-2




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##### Table of Contents



(Amounts in thousands of dollars except share and per share data)
 Year ended December 31,2009
    
    
    2008
    
    
    2007RevenuesOil and gas sales
    
    $
    42,398
    
    
    $
    39,149
    
    
    $
    16,044Transportation and gathering revenue
    
    
    6,179
    
    
    
    4,788
    
    
    
    910Price risk management activities
    
    
    (4,295
    )
    
    
    5,329
    
    
    
    Other income
    
    
    509
    
    
    
    312
    
    
    
    243Total revenues
    
    
    44,791
    
    
    
    49,578
    
    
    
    17,197Costs and expensesProduction costs
    
    
    7,754
    
    
    
    7,007
    
    
    
    5,696Production taxes
    
    
    3,652
    
    
    
    4,701
    
    
    
    1,933Exploration expenses including dry hole costs
    
    
    103
    
    
    
    911
    
    
    
    15,399Pipeline operating costs
    
    
    3,701
    
    
    
    3,190
    
    
    
    645Impairment and abandonment of equipment
and properties
    
    
    417
    
    
    
    743
    
    
    
    2,232General and administrative
    
    
    6,718
    
    
    
    5,604
    
    
    
    4,133Depreciation, depletion and amortization
    
    
    18,562
    
    
    
    11,473
    
    
    
    5,068Total costs and expenses
    
    
    40,907
    
    
    
    33,629
    
    
    
    35,106Income (loss) from operations
    
    
    3,884
    
    
    
    15,949
    
    
    
    (17,909
    )Interest (expense) income, net
    
    
    (1,773
    )
    
    
    (225
    )
    
    
    163Income (loss) before income taxes
    
    
    2,111
    
    
    
    15,724
    
    
    
    (17,746
    )(Provision) benefit for deferred income taxes
    
    
    (902
    )
    
    
    (5,343
    )
    
    
    6,143NET INCOME (LOSS)
    
    $
    1,209
    
    
    $
    10,381
    
    
    $
    (11,603
    )Preferred stock dividends
    
    
    (3,723
    )
    
    
    (3,723
    )
    
    
    (1,810
    )Net income (loss) attributable to common stock
    
    $
    (2,514
    )
    
    $
    6,658
    
    
    $
    (13,413
    )Net income (loss) per common share:Basic
    
    $
    (0.25
    )
    
    $
    0.73
    
    
    $
    (1.47
    )Diluted
    
    $
    (0.25
    )
    
    $
    0.73
    
    
    $
    (1.47
    )Weighted average shares outstanding:Basic
    
    
    9,955,582
    
    
    
    9,159,865
    
    
    
    9,114,622Diluted
    
    
    9,955,582
    
    
    
    9,161,985
    
    
    
    9,114,622
  F-3




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##### Table of Contents



(Amounts in thousands of dollars)
 Year ended December 31,2009
    
    
    2008
    
    
    2007Cash flows from operating activities:Net income (loss)
    
    $
    1,209
    
    
    $
    10,381
    
    
    $
    (11,603
    )Adjustments to reconcile net income (loss) to net cash
provided by operating activities:Depreciation, depletion, amortization and accretion of
asset retirement obligation
    
    
    18,693
    
    
    
    11,648
    
    
    
    5,062Abandonment of non-producing properties and leases
    
    
    417
    
    
    
    743
    
    
    
    14,941Bad debt expense
    
    
    
    
    
    
    
    
    
    
    559Settlement of asset retirement obligation
    
    
    (266
    )
    
    
    
    
    
    
    Non cash revenue from carried interest
    
    
    (2,044
    )
    
    
    (1,665
    )
    
    
    Impairment of equipment and properties
    
    
    
    
    
    
    
    
    
    
    2,234Provision for deferred taxes
    
    
    902
    
    
    
    5,343
    
    
    
    (6,143
    )Directors fees paid in stock
    
    
    177
    
    
    
    128
    
    
    
    90Non-cash loss (gain) on derivative contracts
    
    
    7,798
    
    
    
    (2,631
    )
    
    
    Non-cash employee stock option expense
    
    
    1,307
    
    
    
    1,050
    
    
    
    362Gain on sale of working interest in non-producing property
    
    
    (283
    )
    
    
    (90
    )
    
    
    (98
    )Changes in current assets and liabilities:Decrease (Increase) in deposit held in escrow
    
    
    (6
    )
    
    
    114
    
    
    
    (12
    )Decrease (Increase) in accounts receivable
    
    
    13,884
    
    
    
    (17,522
    )
    
    
    824Decrease (Increase) in other current assets
    
    
    (150
    )
    
    
    (2,871
    )
    
    
    223Increase (Decrease) in accounts payable
    
    
    (14,544
    )
    
    
    15,461
    
    
    
    (1,890
    )Increase (Decrease) in accrued expenses
    
    
    (4,454
    )
    
    
    47
    
    
    
    739Increase (Decrease) in accrued production taxes
    
    
    (578
    )
    
    
    2,768
    
    
    
    (122
    )NET CASH PROVIDED BY OPERATING ACTIVITIES
    
    
    22,062
    
    
    
    22,904
    
    
    
    5,166Cash flows from investing activities:Additions of producing properties and equipment
    
    
    (28,542
    )
    
    
    (44,378
    )
    
    
    (41,550
    )Additions of corporate and non-producing properties
    
    
    (139
    )
    
    
    (878
    )
    
    
    (750
    )Proceeds from sales of properties and assets
    
    
    
    
    
    
    4,478
    
    
    
    244Net cash received from Petrosearch acquisition
    
    
    7,733Payment of Petrosearch transaction costs
    
    
    (513
    )
    
    
    
    
    
    
    NET CASH USED IN INVESTING ACTIVITIES
    
    
    (21,461
    )
    
    
    (40,778
    )
    
    
    (42,056
    )Cash flows from financing activities:Net proceeds from sale of common stock
    
    
    
    
    
    
    
    
    
    
    9,990Net proceeds from sale of preferred stock
    
    
    
    
    
    
    
    
    
    
    37,972Dividends paid on preferred stock
    
    
    (3,723
    )
    
    
    (3,723
    )
    
    
    (1,810
    )Net borrowings/(payments) on line of credit
    
    
    9,361
    
    
    
    21,194
    
    
    
    (9,776
    )Proceeds from Company stock plans
    
    
    
    
    
    
    278
    
    
    
    28Principal payments on capital lease obligations
    
    
    (522
    )
    
    
    
    
    
    
    Tax withholdings related to net share settlement
of restricted stock awards
    
    
    (39
    )
    
    
    
    
    
    
    Issuance of stock under Company stock plans
    
    
    4
    
    
    
    
    
    
    
    NET CASH PROVIDED BY FINANCING ACTIVITIES
    
    
    5,081
    
    
    
    17,749
    
    
    
    36,404Change in cash and cash equivalents
    
    
    5,682
    
    
    
    (125
    )
    
    
    (486
    )Cash and cash equivalents at beginning of period
    
    
    
    
    
    
    125
    
    
    
    611CASH AND CASH EQUIVALENTS AT END OF PERIOD
    
    $
    5,682
    
    
    $
    
    
    
    $
    125Supplemental disclosure of cash and non-cash transactions:Cash paid for interest
    
    $
    2,151
    
    
    $
    657
    
    
    $
    426Interest capitalized
    
    $
    485
    
    
    $
    705
    
    
    $
    279Cash paid for income taxes
    
    $
    
    
    
    $
    
    
    
    $
    Receivables due from joint-interest partners related to change in working
interest
    
    $
    
    
    
    $
    193
    
    
    $
    Share-based compensation expense
    
    $
    1,484
    
    
    $
    1,178
    
    
    $
    452Additions to developed properties included in current liabilities
    
    $
    10,245
    
    
    $
    20,299
    
    
    $
    4,908Additions to
developed properties for asset retirement obligations
    
    $
    94
    
    
    $
    2,584
    
    
    $
    757Issuance of common stock in connection with the acquisition of Petrosearch
    
    $
    7,260
    
    
    $
    
    
    
    $
    Fair value of asset received in connection with the acquisition of Petrosearch
    
    $
    9,151
    
    
    $
    
    
    
    $
    Fair value of liabilities assumed in connection with the acquisition of
Petrosearch
    
    $
    1,018
    
    
    $
    
    
    
    $
    
  F-4




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##### Table of Contents



(Amounts in thousands of dollars except share data)
 AccumulatedShares of
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Other
    
    
    TotalCommon Stock
    
    
    
    
    
    
    Additional Paid-
    
    
    Retained
    
    
    Comprehensive
    
    
    StockholdersOutstanding
    
    
    Common Stock
    
    
    In Capital
    
    
    Earnings
    
    
    Income (loss)
    
    
    EquityBalance at
January 1, 2007
    
    
    8,641,104
    
    
    $
    864
    
    
    $
    23,251
    
    
    $
    8,927
    
    
    $
    
    
    
    $
    33,042Comprehensive lossNet loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (11,603
    )
    
    
    
    
    
    
    (11,603
    )Net change in derivative
instrument fair value, net
of tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (1,475
    )
    
    
    (1,475
    )Total comprehensive
loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (13,078
    )Stock options exercised
    
    
    2,000
    
    
    
    
    
    
    
    27
    
    
    
    
    
    
    
    
    
    
    
    27Compensation expense from
common stock options
    
    
    
    
    
    
    
    
    
    
    362
    
    
    
    
    
    
    
    
    
    
    
    362Directors fees paid in stock
    
    
    5,001
    
    
    
    1
    
    
    
    90
    
    
    
    
    
    
    
    
    
    
    
    91Sale of common stock
    
    
    500,000
    
    
    
    50
    
    
    
    9,940
    
    
    
    
    
    
    
    
    
    
    
    9,990Dividends declared & paid
on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (1,810
    )
    
    
    
    
    
    
    (1,810
    )Balance at
December 31, 2007
    
    
    9,148,105
    
    
    
    915
    
    
    
    33,670
    
    
    
    (4,486
    )
    
    
    (1,475
    )
    
    
    28,624Comprehensive incomeNet income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    10,381
    
    
    
    
    
    
    
    10,381Net change in derivative
instrument fair value, net
of tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    18,253
    
    
    
    18,253Reclassification to earnings, net
of tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (88
    )
    
    
    (88
    )Total comprehensive
income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    28,546Stock options exercised
    
    
    15,000
    
    
    
    1
    
    
    
    275
    
    
    
    
    
    
    
    
    
    
    
    276Share-based compensation
expense
    
    
    
    
    
    
    
    
    
    
    1,050
    
    
    
    
    
    
    
    
    
    
    
    1,050Directors fees paid in stock
    
    
    7,805
    
    
    
    1
    
    
    
    127
    
    
    
    
    
    
    
    
    
    
    
    128Issuance of common shares
upon restricted stock vesting
    
    
    21,446
    
    
    
    2
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2Dividends declared & paid
on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (3,723
    )
    
    
    
    
    
    
    (3,723
    )Balance at
December 31, 2008
    
    
    9,192,356
    
    
    $
    919
    
    
    $
    35,122
    
    
    $
    2,172
    
    
    $
    16,690
    
    
    $
    54,903
  F-5




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##### Table of Contents



(Amounts in thousands of dollars except share data)
 AccumulatedShares of
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Other
    
    
    TotalCommon Stock
    
    
    
    
    
    
    Additional Paid-
    
    
    Retained
    
    
    Comprehensive
    
    
    StockholdersOutstanding
    
    
    Common Stock
    
    
    In Capital
    
    
    Earnings
    
    
    Income (loss)
    
    
    EquityBalance at
December 31, 2008
    
    
    9,192,356
    
    
    $
    919
    
    
    $
    35,122
    
    
    $
    2,172
    
    
    $
    16,690
    
    
    $
    54,903Comprehensive lossNet income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,209
    
    
    
    
    
    
    
    1,209Net change in derivative
instrument fair value, net
of tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,367
    
    
    
    1,367Reclassification to earnings, net
of tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (15,740
    )
    
    
    (15,740
    )Total comprehensive
loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (13,164
    )Shares issued in connection with
Petrosearch acquisition
    
    
    1,791,733
    
    
    
    179
    
    
    
    7,080
    
    
    
    
    
    
    
    
    
    
    
    7,259Share-based compensation
expense, exclusive of amounts
withheld for payroll taxes
    
    
    79,912
    
    
    
    8
    
    
    
    1,264
    
    
    
    
    
    
    
    
    
    
    
    1,272Directors fees paid in stock
    
    
    26,724
    
    
    
    3
    
    
    
    174
    
    
    
    
    
    
    
    
    
    
    
    177Dividends declared & paid
on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (3,723
    )
    
    
    
    
    
    
    (3,723
    )Balance at
December 31, 2009
    
    
    11,090,725
    
    
    $
    1,109
    
    
    $
    43,640
    
    
    $
    (342
    )
    
    $
    2,317
    
    
    $
    46,724
  F-6




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##### Table of Contents



DOUBLE EAGLE PETROLEUM CO.


NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS  (Amounts in thousands of dollars except share and per share data)
 1.
    
    Business Description and Summary of Significant Accounting PoliciesDescription of OperationsDouble Eagle Petroleum Co. (Double Eagle or the Company) is an independent energy company
engaged in the exploration, development, production and sale of natural gas and crude oil,
primarily in the Rocky Mountain Basins of the western United States. Double Eagle was
incorporated in the State of Wyoming in January 1972, and reincorporated in the State of
Maryland in February 2001.Principles of Consolidation and Basis of PresentationThe consolidated financial statements include the accounts of the Company and its wholly owned
subsidiaries Petrosearch Energy Corporation (Petrosearch) and Eastern Washakie Midstream LLC
(EWM) (collectively, the Company). The Company acquired Petrosearch in August 2009 and has
operations in Texas, Oklahoma, and North Dakota. EWM owns and operates a 13-mile intrastate gas
pipeline (the Pipeline). The Company has an agreement with EWM, under which the Company pays
a fee to EWM to gather and compress gas produced at the Catalina Unit. All intercompany
transactions, including our share of the fee related to gas gathering are eliminated in
consolidation for all periods presented in this Form 10-K.The Company has no interests in any unconsolidated entities, nor does it have any unconsolidated
special purpose entities.Certain reclassifications have been made to amounts reported in previous years to conform to the
2009 presentation. Such reclassifications had no effect on net income.Cash and Cash EquivalentsCash and cash equivalents includes all cash balances and any highly liquid investments with an
original maturity of 90 days or less.Cash Held in EscrowThe Company has received deposits representing partial prepayments of the expected capital
expenditures from third party working interest owners in the Table Top Unit #1 exploration
project. The unexpended portion of the deposits at December 31, 2009 and 2008 totaled $611 and
$605, respectively.Accounts ReceivableThe Company records estimated oil and gas revenue receivable from third parties at its net
revenue interest. The Company also reflects costs incurred on behalf of joint interest partners
in accounts receivable. Management periodically reviews accounts receivable amounts for
collectability and records its allowance for uncollectible receivables under the specific
identification method. The Company recorded an allowance for uncollectible receivables of $0,
$0, and $559 for the periods ended December 31, 2009, 2008 and 2007, respectively.Use of Estimates in the Preparation of Financial StatementsThe preparation of financial statements in conformity with accounting principles generally
accepted in the United States requires management to make estimates and assumptions that affect
the reported amounts of oil and gas reserves, assets and liabilities and disclosure on
contingent assets and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual results could differ from
those estimates. Estimates of oil and gas reserve quantities provide the basis for calculation
of depletion, depreciation, and amortization, and impairment, each of which represents a
significant component of the consolidated financial statements.Concentration of Credit RiskFinancial instruments which potentially subject the Company to credit risk consist of our
accounts receivable and our derivative financial instruments. Substantially all of the
Companys receivables are within the oil and gas industry, including those from the
 F-7




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##### Table of Contents



Companys third party marketing company. Collectability is dependent upon the financial
wherewithal of each individual company as well as the general economic conditions of the
industry. The receivables are not collateralized.
 The Company currently uses two counterparties for its derivative financial instruments. The
Company continually reviews the credit worthiness of our counterparties, which are generally
energy companies. In addition, the Company uses master netting agreements which allow the
Company, in the event of default, to elect early termination of all contracts with the
defaulting counterparty. If the Company chooses to elect early termination, all asset and
liability positions with the defaulting counterparty would be net settled at the time of
election. Net settlement refers to a process by which all transactions between counterparties
are resolved into a single amount owed by one party to the other.Revenue Recognition and Gas BalancingThe Company recognizes oil and gas revenues for its ownership percentage of total production
under the entitlement method, whereby the working interest owner records revenue based on its
share of entitled production, regardless of whether the Company has taken its ownership share of
such volumes. An over-produced owner would record the excess of the amount taken over its
entitled share as a reduction in revenues and a payable while the under-produced owner records
revenue and a receivable for the imbalance amount. The Companys imbalance position
with various third party operators at December 31, 2009 resulted in an imbalance receivable of
128 MMcf, or $446, and an imbalance payable of 188 MMcf, or $721.Oil and Gas Producing ActivitiesDouble Eagle uses the successful efforts method of accounting for its oil and gas producing
activities. Under this method of accounting, all property acquisition costs and costs of
exploration and development wells are capitalized when incurred, pending determination of
whether the well has found proved reserves. If an exploratory well does not find proved
reserves, the costs of drilling the well are charged to expense. The costs of development wells
are capitalized whether productive or nonproductive.Geological and geophysical costs and the costs of carrying and retaining unproved leaseholds are
expensed as incurred. The Company limits the total amount of unamortized capitalized costs for
each property to the value of future net revenues, based on expected future prices and costs.Depreciation, depletion and amortization (DD&A) of capitalized costs for producing oil and gas
properties is provided on a field-by-field basis using the units-of-production method, based on
proved oil and gas reserves. DD&A takes into consideration restoration, dismantlement and
abandonment costs and the anticipated proceeds for equipment salvage.Depreciation, depletion and amortization of oil and gas properties for the years ended December
31, 2009, 2008, and 2007, was $18,136, $11,078, and $4,550, respectively.Double Eagle invests in unevaluated oil and gas properties for the purpose of future exploration
and development of proved reserves. The costs of unproved leases which become productive are
reclassified to proved properties when proved reserves are discovered on the property. Unproved
oil and gas interests are carried at the lower of cost or estimated fair market value and are
not subject to amortization.The following table reflects the net changes in capitalized exploratory well costs during the
years ended December 31, 2009, 2008 and 2007 and amounts include costs capitalized and
subsequently expensed in the same period (amounts in thousands).
 2009
    
    
    2008
    
    
    2007Beginning balance at January 1,
    
    $
    
    
    
    $
    692
    
    
    $
    11,541Additions to capitalized exploratory well costs pending
the determination of proved reserves
    
    
    
    
    
    
    
    
    
    
    5,727Reclassifications to wells, facilities and equipment
based on the determination of proved reserves
    
    
    
    
    
    
    (692
    )
    
    
    (1,666
    )Capitalized exploratory well costs charged to expense
    
    
    
    
    
    
    
    
    
    
    (14,910
    )Ending balance at December 31,
    
    $
    
    
    
    $
    
    
    
    $
    692
 F-8




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##### Table of Contents



Asset Retirement ObligationsLegal obligations associated with the retirement of long-lived assets result from the
acquisition, construction, development and normal use of the asset. The Companys asset
retirement obligations relate primarily to the retirement of oil and gas properties and related
production facilities, lines and other equipment used in the field operations. The fair value
of a liability for an asset retirement obligation is recognized in the period in which it is
incurred, if a reasonable estimate of fair value can be made. The fair value of the liability
is added to the carrying amount of the associated asset. This additional carrying amount is
then depreciated over the life of the asset. The liability increases due to the passage of time
based on the time value of money until the obligation is settled.For the years ended December 31, 2009, 2008 and 2007, an expense of $131, $175, and $25,
respectively, was recorded as accretion expense on the liability and included in production
costs on the Consolidated Statement of Operations. During 2009 and 2008, the Company recorded
an additional $521, and $2,661, respectively, in oil and gas properties and asset retirement
obligation liability to reflect the present value of plugging liability on new wells and
revisions to estimated cash flows added during the respective years.A reconciliation of the Companys asset retirement obligation liability:
 For the year ended December 31,2009
    
    
    2008Beginning asset retirement obligation
    
    $
    4,208
    
    
    $
    1,449Additional liabilites assumed through
acquisition of Petrosearch
    
    
    640
    
    
    
    Liabilities incurred
    
    
    4
    
    
    
    995Liabilities settled
    
    
    (266
    )
    
    
    Accretion expense
    
    
    131
    
    
    
    175Changes in ownership interest
    
    
    213
    
    
    
    (77
    )Revision to estimated cash flows
    
    
    (123
    )
    
    
    1,666Ending asset retirement obligation
    
    $
    4,807
    
    
    $
    4,208
 Impairment of Long-Lived AssetsThe Company reviews the carrying values of its long-lived assets whenever events or changes in
circumstances indicate that such carrying values may not be recoverable. If, upon review, the
sum of the undiscounted pretax cash flows is less than the carrying value of the asset group,
the carrying value is written down to estimated fair value. Individual assets are grouped for
impairment purposes at the lowest level for which there are identifiable cash flows that are
largely independent of the cash flows of other groups of assets, generally on a field-by-field
basis. The fair value of impaired assets is determined based on quoted market prices in active
markets, if available, or upon the present values of expected future cash flows using discount
rates commensurate with the risks involved in the asset group. The long-lived assets of the
Company, which are subject to periodic evaluation, consist primarily of oil and gas properties
and undeveloped leaseholds. The Company recognized a non-cash charge on producing properties
during the years ending December 31, 2009, 2008 and 2007 of $0, $0, and $2,141, respectively,
and a non-cash charge on undeveloped leaseholds during the years ending December 31, 2009, 2008
and 2007 of $417, $743, and $91, respectively.The Companys pipeline facilities are recorded at cost, which totaled $5,465 as of December 31,
2009. Depreciation is recorded using the straight-line method over a 25 year estimated useful
life. The useful life may be limited to the useful life of current and future recoverable
reserves serviced by the pipeline. The Company evaluated the expected useful life of the
pipeline assets as of December 31, 2009 and determined that the assets are expected to be
utilized for at least the estimated useful life used in the depreciation calculation.Corporate and Other AssetsOffice facilities, equipment and vehicles are recorded at cost. Depreciation is recorded using
the straight-line method over the estimated useful lives of 10 to 40 years for office
facilities, 3 to 10 years for office equipment, and 7 years for vehicles. Depreciation expense
for the years ended December 31, 2009, 2008 and 2007 was $206, $177, and $160, respectively.
 F-9




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##### Table of Contents



Major CustomersThe Company had sales to one major unaffiliated customer for years ended December 31, 2009, 2008
and 2007, totaling $41,149 $32,045, and $11,530, respectively. No other single customer
accounted for 10% or more of revenues in 2009, 2008, or 2007. Although a substantial portion of
our production is purchased by one customer, the Company does not believe the loss of this
customer would have a material adverse effect on the Companys business as other customers would
be accessible.Industry Segment and Geographic InformationThe Company operates in one industry segment, which is the exploration, development, production
and sale of natural gas and crude oil, and all of the Companys operations are conducted in the
Continental United States. Consequently, the Company currently reports as a single industry
segment. The Companys transportation and gathering subsidiary provides services exclusively
for our gas marketing company and all of the revenue generated by this subsidiary is related to
volumes produced from the Catalina Unit. Segmentation of such net income would not provide a
better understanding of the Companys performance, and is not viewed by management as a discrete
reporting segment. However, gross revenue and expense related to our transportation and
gathering subsidiary are presented as separate line items in the accompanying Consolidated
Statement of Operations.Employee Benefit PlanThe Company maintains a Simplified Employee Pension Plan covering substantially all employees
meeting minimum eligibility requirements. Employer contributions are determined solely at
managements discretion. Employer contributions for years ended 2009, 2008 and 2007 were $183,
$117, and $118, respectively.Income TaxesIncome taxes are accounted for under the asset and liability method. Deferred taxes assets or
liabilities are recorded based on the difference between the tax basis of an asset or liability
and its carrying amount in the financial statements. This difference will result in taxable
income or deduction in future periods when the reported amount of the asset or liability is
recovered or settled, respectively.Earnings Per ShareBasic earnings per share (EPS) is calculated by dividing net income (loss) attributable to
common stock by the weighted average number of shares of common stock outstanding during the
period. Diluted earnings per share incorporates the treasury stock method to measure the
dilutive impact of potential common stock equivalents by including the effect of outstanding
vested and unvested stock options and unvested stock awards in the average number of common
shares outstanding during the period.Calculation of basic and diluted weighted average shares outstanding and EPS for the periods
indicated:
 For the year ended December 31,2009
    
    
    2008
    
    
    2007Net income (loss)
    
    $
    1,209
    
    
    $
    10,381
    
    
    $
    (11,603
    )Preferred stock dividends
    
    
    (3,723
    )
    
    
    (3,723
    )
    
    
    (1,810
    )Income (loss) attributable to common stock
    
    $
    (2,514
    )
    
    $
    6,658
    
    
    $
    (13,413
    )Weighted average shares:Weighted average shares  basic
    
    
    9,955,582
    
    
    
    9,159,865
    
    
    
    9,114,622Dilutive effect of stock options outstanding
at the end of period
    
    
    
    
    
    
    2,120
    
    
    
    Weighted average shares  fully diluted
    
    
    9,955,582
    
    
    
    9,161,985
    
    
    
    9,114,622Earnings (loss) per share:Basic
    
    $
    (0.25
    )
    
    $
    0.73
    
    
    $
    (1.47
    )Diluted
    
    $
    (0.25
    )
    
    $
    0.73
    
    
    $
    (1.47
    )
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The following options and stock awards that could be potentially dilutive in future periods
were not included in the computation of diluted net income (loss) per share because the effect
would have been anti-dilutive for the periods indicated:
 For the years ended December 31,2009
    
    
    2008
    
    
    2007Potential common shares
    
    
    84,177
    
    
    
    56,249
    
    
    
    6,643
 Stock Based CompensationThe Company measures and recognizes compensation expense for all share-based payment awards
(including stock options and stock awards) made to employees and directors based on estimated
fair value. Compensation expense for equity-classified awards is measured at the grant date
based on the fair value of the award and is recognized as an expense in earnings over the
requisite service period using a graded vesting method.Shareholder Rights PlanIn 2007, the Board of Directors of the Company adopted a Shareholder Rights Plan (Rights
Plan). Under the Rights Plan, the Company issued a dividend of one Preferred Share Purchase
Right for each outstanding share of common stock held by stockholders of record on September 4,
2007. The Rights Plan is intended to safeguard against abusive takeover tactics that limit the
ability of all shareholders to realize the long-term value of their investment in Double Eagle.
The Rights Plan was not adopted in response to any specific takeover effort, and will not
prevent a takeover, but should encourage anyone seeking to acquire Double Eagle to negotiate
with the Board prior to attempting a takeover.Each right initially entitles stockholders to purchase a fractional share of the Companys
Series B Junior Participating Preferred Stock at an exercise price of $45. However, the rights
are not immediately exercisable and will become exercisable only upon the occurrence of certain
events. If a person or group acquires, or announces a tender or exchange offer that would
result in the acquisition of 20% or more of the Companys common stock while the Rights Plan
remains in place, then, unless the rights are redeemed by the Company for $.01 per right, the
rights will become exercisable by all rights holders, except the acquiring person or group, for
            shares of the Companys common stock having a value of twice the rights then-current exercise
price.There are 75,000 shares of the Companys Series B Junior Participating Preferred Stock, par
value $.10, authorized with no shares outstanding at December 31, 2009.Fair Value of Financial InstrumentsThe Companys financial instruments including cash and cash equivalents, accounts receivable and
accounts payable are carried at a cost, which approximates fair value due to the short-term
maturity of these instruments. The recorded value of the Companys credit facility approximates
its fair value as it bears interest at a floating rate. The Company accounts for certain
derivative contracts as cash flow hedges, with the effective portion of gains and losses related
to the changes in the fair value recorded in accumulated other comprehensive income, a component
of Stockholders equity. The Company also marks to market other derivative instruments not
accounted for as cash flow hedges, with the change in fair values recorded within the price risk
management line on the Consolidated Statement of Operations. Reference is made to Notes 6 and 7
of the Notes to the Consolidated Financial Statements.Derivative Financial InstrumentsThe Company uses derivative instruments, primarily forwards, swaps, and collars, to hedge risk
associated with fluctuating commodity prices. The Company does not use derivative instruments
for speculative purposes. See Notes 5 and 6 for a full description of our derivative activities
and related accounting policies.
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Other Comprehensive IncomeComprehensive income (loss) consists of net income (loss) and changes to the Companys
derivative instruments that are treated as cash flow hedges, including realized and unrealized
gains and losses as well as changes in fair value, net of tax.Accumulated other comprehensive income is reported as a separate component of Stockholders
equity and is made up of the change in the fair market value of cash flow hedges, net of tax.
The Companys accumulated other comprehensive income related to cash flow hedges at December 31,
2009 totaled $2,317, which is net of taxes in the amount of $1,249. As of December 31, 2009,
the Company expected to reclassify $0 of the accumulated other comprehensive income balance to
earnings in one year or less, as none of the contracts settle prior to 2011.Recently Adopted Accounting PronouncementsIn June 2009, the Financial Accounting Standards Board (FASB) issued ASC 105, The FASB
Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles
(ASC 105). The Accounting Standards Codification (ASC) has become the source of
authoritative U.S. GAAP recognized by the FASB to be applied by nongovernment entities. It also
modifies the GAAP hierarchy to include only two levels of GAAP; authoritative and
non-authoritative. The Company adopted ASC 105 effective July 1, 2009. Pursuant to the
provisions of ASC 105, the Company has updated references to GAAP in its financial statements
issued for the year ended December 31, 2009. The adoption of ASC 105 did not have an impact on
the Companys financial position, results of operations or cash flows.In September 2006, the ASC guidance for fair value measurements was updated to define fair
value, establish a framework for measuring fair value, and expand disclosures related to fair
value. The Company adopted the updated guidance for assets and liabilities measured at fair
value on a recurring basis on January 1, 2008. In February 2008, the FASB issued an update to
the guidance, which delayed the effective date for nonfinancial assets and liabilities,
including asset retirement obligations, that are recognized or disclosed at fair value on a
nonrecurring basis (less frequent than annually). The Company adopted the updated guidance for
nonfinancial assets and liabilities on January 1, 2009. In April 2009, the guidance was again
updated to provide additional guidance on determining fair value when the volume and level of
activity for the asset or liability have significantly decreased and identifying circumstances
that indicate when a transaction is not orderly. The Company adopted this guidance April 1,
2009. In August 2009, the ASC provided further guidance related to the fair value of
liabilities. This update provides clarification for circumstances in which: (i) a quoted price
in an active market for the identical liability is not available, (ii) the liability has a
restriction that prevents its transfer, and (iii) the identical liability is traded as an asset
in an active market in which no adjustments to the quoted price of an asset are required. The
Company adopted this update effective October 1, 2009. None of the aforementioned adoptions
related to fair value had a material impact on its financial position, results of operations or
cash flows.In May 2009, the ASC guidance for subsequent events was updated to establish general standards
of accounting for and disclosures of events that occur after the balance sheet date but before
financial statements are issued or are available to be issued. The Company adopted this guidance
effective April 1, 2009. See Note 10 for the Companys disclosures about subsequent events.In June 2008, the ASC guidance was updated to provide clarification as to whether instruments
granted in share-based payment transactions are participating securities prior to vesting, and
therefore, need to be included in computing earnings per share under the two-class method
provided under ASC 260  Earnings Per Share. The Company adopted this standard effective
January 1, 2009. The adoption of this guidance did not have a material impact on the Companys
financial position, results of operations or cash flows.In March 2008, the ASC guidance for derivatives and hedging instruments was updated for enhanced
disclosures about how and why an entity uses derivative instruments, how derivative instruments
and related hedged items (if any) are accounted for, and how they affect the Companys financial
position, financial performance and cash flows. The Company adopted the updated guidance
effective January 1, 2009. See Note 6 for the Companys disclosures about its derivative
instruments and hedging activities.In November 2007, the ASC guidance for business combinations was updated to provide new guidance
for recognizing and measuring the assets and goodwill acquired and liabilities assumed in an
acquisition. The updated guidance also broadened the definition of a
business combination and requires an entity to recognize transaction costs separately from the
acquisition. The Company adopted the updated guidance effective January 1, 2009 and applied it
to the acquisition of Petrosearch completed on August 6, 2009 (see Note 3).
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In January 2010, the ASC guidance for reporting oil and gas reserves was updated to align the
oil and gas reserve estimation and disclosure requirements with the requirements in the SECs
final rule, Modernization of the Oil and Gas Reporting Requirements. The new guidance expands
the definition of reserves, which allows consideration of new technologies. In addition, oil
and gas reserves are reported using an average, first-day-of-the-month price based on the prior
12-month period, rather than year-end prices. The new rule is effective for annual reporting
periods ending on or after December 31, 2009. The Company adopted these provisions effective
December 31, 2009. The new standards are applied prospectively as a change in accounting
principle that is inseparable from a change in accounting estimate. The application of the new
rules increased our DD&A expense for the fourth quarter by approximately $147, and decreased our
net income attributable to common shareholders by $84, or $.01 per diluted share. Refer to Note
11 for the Companys disclosures about its oil and gas reserves.New Accounting PronouncementsIn January 2010, the FASB issued ASC Update No. 2010-06, an additional update to the ASC
guidance for fair value measurements. The new guidance requires additional disclosures about
(1) the different classes of assets and liabilities measured at fair value, (2) the valuation
techniques and inputs used, (3) the activity in Level 3 fair value measurements, and (4) the
transfers between Levels 1, 2, and 3. The updated guidance is effective for annual and interim
periods beginning December 15, 2009, except for the disclosures about the activity in Level 3
fair value measurements, for which the new guidance is effective for fiscal years beginning
after December 15, 2010. The adoption of ASC Update 2010-06 is not expected to have a material
impact on the Companys financial position, results of operations or cash flows.
 2.
    
    Line of CreditAs part of the Companys cash management program, at December 31, 2009, the Company had a $75
million revolving line of credit in place with a $45 million available for borrowing based on
several factors, including our current borrowing base and the commitment levels by participating
banks. The credit facility is collateralized by the Companys oil and gas producing properties.As of December 31, 2009, the balance outstanding of $34,000 was used to fund capital
expenditures primarily on our Catalina Unit expansion and other non-operated projects in the
Atlantic Rim in 2008, as well as projects in the Pinedale Anticline in 2008 and 2009.Borrowings under the revolving line of credit bear interest at the greater of (i) 4.5% or (ii) a
daily rate equal to the greater of (a) the Federal Funds rate, plus 0.5%, the Prime Rate or the
Eurodollar Rate plus 1%, plus (b) a margin ranging between 1.25% and 2.0% depending on the level
of funds borrowed. As of December 31, 2009, the interest rate on the line of credit was 4.5%.
For the years ended December 31, 2009, 2008, and 2007, the Company incurred interest expense on
the line of credit of $1,778, $705, and $433, respectively. Of the total interest incurred, the
Company capitalized interest costs of $485, $705, and $279, for the years ended December 31,
2009, 2008, and 2007, respectively.Under the facility, the Company is subject to both financial and non-financial covenants. The
financial covenants include maintaining (i) a current ratio, as
defined, of at least 1.0 to 1.0, (ii) a
ratio of earnings before interest, taxes, depreciation, depletion, amortization, exploration and
other non-cash items (EBITDAX) to interest plus
dividends, of greater than 1.5 to 1.0 and (iii) a funded
debt to EBITDAX ratio of less than 3.5 to 1.0. As of December 31, 2009, the Company was in compliance with
all financial covenants. If the covenants are violated, and the Company is unable to negotiate
a waiver or amendment thereof, the lender would have the right to declare an event of default,
terminate the remaining commitment and accelerate all principal and interest outstanding.Effective February 5, 2010, the Company renegotiated its credit agreement primarily to extend
the maturity date of the facility from July 31, 2010 to January 31, 2013. The borrowing
availability on the facility will remain at $45 million. There were no material changes to any
other terms of the credit facility, including our financial and non-financial covenants. The
Company paid approximately $450 in one-time financing fees related to renegotiating this
facility.
 3
    
    Acquisition of Petrosearch Energy CorporationOn August 6, 2009 (Effective Closing Date), the Company acquired 100% of the common and
preferred shares of Petrosearch in exchange for approximately 1.8 million shares of Double Eagle
common stock, valued at approximately $7.3 million, and cash consideration of $873, for a total
purchase price of approximately $8.1 million. Effective with the acquisition, each Petrosearch
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shareholder received .0433 shares of Double Eagle common stock and $0.0211 for each share of
Petrosearch common stock and Petrosearch preferred stock, on an as converted basis, such
shareholder held. As result of the merger, Petrosearch became a wholly-owned subsidiary of the
Company. Richard Dole, who is and was, at the time of the merger, Chairman, President and Chief
Executive Officer of Double Eagle and Petrosearch, will continue to serve as Chairman, President
and Chief Executive Officer. The Board of Directors of Double Eagle will consist of five
directors, four existing directors of Double Eagle and one future director to be designated by
Petrosearch.
 Petrosearch is an independent crude oil and natural gas exploration and production company, with
properties in Texas and Oklahoma. Petrosearch had approximately $8,606 in cash and cash
equivalents at the time of acquisition. The Company believes that the acquisition of
Petrosearch has enhanced the Companys ability to finance its current operations and future
developmental projects, thereby providing an opportunity to increase reserves. Petrosearch
contributed revenue of $79 and earnings of $(146) for the period from August 6 to December 31,
2009.
 The aggregate purchase price is estimated as follows:
 Aggregrate value of Double Eagle common stock issued
    
    $
    7,260Cash consideration given to Petrosearch shareholders
    
    
    873Purchase Price
    
    $
    8,133
 The acquisition of Petrosearch has been accounted for under the purchase method of
accounting. Under the purchase method of accounting, the purchase price is allocated to the
assets acquired and liabilities assumed based on their estimated fair values. The allocation of
the purchase price has been estimated as follows:
 Cash and cash equivalents
    
    $
    8,606Accounts receivables, net of allowance
    
    
    5Prepaid expense & other current assets
    
    
    134Oil and gas properties
    
    
    350Goodwill
    
    
    56Accounts payable and other current liabilities
    
    
    (378
    )Asset retirement obligation
    
    
    (640
    )$
    8,133
 Of the total estimated purchase price, approximately $56 has been allocated to goodwill.
Goodwill represents the excess of the purchase price of an acquired business over the fair value
of the underlying net tangible and intangible assets. Goodwill is not amortized, rather, the
goodwill will be tested for impairment, at least annually, or more frequently if there is an
indication of impairment. The goodwill resulting from this acquisition is not deductible for
tax purposes.Transaction costs related to the merger totaled $513, and are recorded on the Consolidated
Statement of Operations within the general and administrative expenses line on the statement of
operations.Supplemental Pro Forma Results (unaudited)The following pro forma financial information represents the combined results for the Company
and Petrosearch for the years ended December 31, 2009 and 2008 as if the acquisition had
occurred on January 1, 2009 and January 1, 2008. The pro forma
financial information includes adjustments to reflect Petrosearch as if its crude oil and
natural gas properties had been accounted for under the successful efforts method of accounting,
not the full cost method of accounting. The pro forma financial information is not intended to
represent or be indicative of the consolidated results of operations or financial condition of
the
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Company that would have been reported had the acquisition been completed as of the dates
presented, and should not be taken as representative of the future consolidated results of
operations or financial condition of the Company.
 For the year ended December 31,2009
    
    
    2008Net revenues
    
    $
    44,847
    
    
    $
    50,978Operating
income
    
    $
    3,314
    
    
    $
    8,528Net income (loss) attributable to common shareholders
    
    $
    (2,828
    )
    
    $
    10,410Basic and diluted net income (loss) per share
    
    $
    (0.28
    )
    
    $
    0.95
 4.
    
    Income TaxesThe provision for income taxes consists of:
 For the year ended December 31,2009
    
    
    2008
    
    
    2007Current taxes
    
    $
    
    
    
    $
    
    
    
    $
    Deferred taxes
    
    
    902
    
    
    
    5,343
    
    
    
    (6,143
    )Total income tax expense
    
    $
    902
    
    
    $
    5,343
    
    
    $
    (6,143
    )
 The tax effects of temporary differences that gave rise to the deferred tax liabilities and
deferred tax assets as of December 31, 2009 and 2008 were:
 As of December 31,2009
    
    
    2008Deferred tax assets:Net operating loss carry-forward
    
    $
    11,597
    
    
    $
    10,691Asset retirement obligation
    
    
    1,683
    
    
    
    1,474Share-based compensation
    
    
    315
    
    
    
    167Accrued compensation
    
    
    17
    
    
    
    94Derivative instruments
    
    
    560
    
    
    
    Net gas imbalance
    
    
    53Other
    
    
    6
    
    
    
    514,231
    
    
    
    12,431Deferred tax liabilities:Net gas imbalance
    
    
    
    
    
    
    (32
    )Net basis difference in oil and gas properties
    
    
    (18,852
    )
    
    
    (14,869
    )Net deferred tax asset (liability)
    
    $
    (4,621
    )
    
    $
    (2,470
    )
 In assessing the realizability of the deferred tax assets, management considers whether it
is more likely than not that some or all of the deferred tax assets will not be realized. The
ultimate realization of the deferred tax assets is dependent upon the generation of future
taxable income during the periods in which the use of such net operating losses are allowed.
Among other items, management considers the scheduled reversal of deferred tax liabilities, tax
planning strategies and projected future taxable income.
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At December 31, 2009, the Company had a net operating loss carry forward for regular income
tax reporting purposes of approximately $32.8 million, which will begin expiring in 2021.Reconciliation of the Companys effective tax rate to the expected federal tax rate is:
 For the year ended December 31,2009
    
    2008Expected federal tax rate
    
    
    35.00
    %
    
    
    35.00
    %Effect of permanent differences
    
    
    16.52
    %
    
    
    -1.06
    %State tax rate
    
    
    0.02
    %
    
    
    0.04
    %Other
    
    
    -8.84
    %
    
    
    0.00
    %Effective tax rate
    
    
    42.70
    %
    
    
    33.98
    %
 The ASC guidance requires that the Company evaluate all tax positions taken, and recognize
a liability for any positions that are not more likely than not to be sustained by the tax
authorities. The Company has not recorded any liabilities, or interest and penalties, as of
December 31, 2009 related to uncertain tax positions.The Company files income tax returns in the U.S. and various state jurisdictions. There are
currently no federal or state income tax examinations underway for these jurisdictions.
Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the
Internal Revenue Service for tax years before 2005 and for state and local tax authorities for
years before 2004. The Companys tax years of 2004 and forward are subject to examination by
federal and state taxing authorities.5.
    
    Commitments and ContingenciesDerivative InstrumentsTo partially mitigate the Companys exposure to adverse fluctuations in the prices of natural
gas, the Company has entered into various derivative contracts. The terms of the Companys
hedging instruments are summarized as follows (volume and daily production are expressed in
Mcf):
 Contractual
    
    
    Daily
    
    
    
    
    
    
    
    
    
    
    PriceType of Contract
    
    Volume
    
    
    Production
    
    
    Term
    
    
    Price
    
    
    Index (1)Fixed Price Swap
    
    
    4,380,000
    
    
    
    12,000
    
    
    
    1/10-12/10
    
    
    $
    4.30
    
    
    CIGCostless Collar
    
    
    2,885,000
    
    
    
    5,000
    
    
    
    8/09-7/11
    
    
    $4.50 floor
    
    NYMEX$7.90 ceilingCostless Collar
    
    
    3,495,000
    
    
    
    5,000
    
    
    
    12/09-11/11
    
    
    $4.50 floor
    
    NYMEX$9.00 ceilingFixed Price Swap
    
    
    2,920,000
    
    
    
    8,000
    
    
    
    1/11-12/11
    
    
    $
    7.07
    
    
    CIGTotal
    
    
    13,680,000
 
 (1)
    
    NYMEX refers to quoted prices on the New York Mercantile Exchange. CIG refers to the
Colorado Interstate Gas price as quoted on the first day of each month. Refer to Note 6 for additional information related to the accounting treatment of the
Companys derivative contracts.
 Capital Lease Commitments
 The Company leases certain compressor equipment in the Catalina Unit under a noncancelable, 36
month term lease agreement that is accounted for as a capital lease. The effective interest
rate on the capital leases is 2.125%. The property under capital lease at both December 31,
2009 and 2008, totaled $1,600, and is included in the developed properties line on the balance
sheet. Related accumulated depreciation was approximately $533 and $0 at December 31, 2009 and 2008,
respectively. The amortization of the capital lease balance is recorded within DD&A expense on
the Consolidated Statement of Operations.
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Future minimum lease payments under noncancelable capital leases at December 31, 2009 are as
follows (in thousands):
 LeaseYear ending December 31,
    
    Commitments2010
    
    $
    7532011
    
    
    753Total minimum lease payments
    
    $
    1,506Less: Executory costs
    
    
    400Less: Amounts representing interest
    
    
    40Present value of minimum lease payments
    
    $
    1,066
 Operating Lease CommitmentsThe Company has entered into an operating lease through August 2013 for approximately 3,900
square feet of office space in Denver, Colorado. In addition, the Company assumed two office
leases as part of the Petrosearch acquisition, both of which expire in 2010. The Company also
maintains operating leases on certain compressor equipment in the Catalina Unit and various
pieces of office equipment in both the Casper and Denver offices. The total annual minimum
lease payments for the next five years and thereafter are:
 LeaseYear ending December 31,
    
    Commitments2010
    
    
    2,0192011
    
    
    1,9722012
    
    
    1,9672013
    
    
    1,4012014 and thereafter
    
    
    Total
    
    $
    7,359
 Total expense from operating leases totaled $2,575, $419, and $62 in 2009, 2008 and 2007,
respectively.
 Litigation and Contingencies
 From time to time, the Company is subject to litigation, claims and governmental and regulatory
proceedings, including the matter discussed below. It is the opinion of the Companys
management that current claims and litigation involving the Company are not likely to have a
material adverse effect on its consolidated financial position, cash flows or results of
operations.
 Through unitization, the Company acquired an interest in the Madden Sour Gas Participating Area
in the Madden Deep Unit and the Lost Cabin Gas Processing Plant in late 2006, at a cost of
approximately $2.5 million. The Madden Sour Gas Participating Area produced 10 Mcf net to our
interest of gas in December 2007 from seven wells. These are long-lived wells with large
producing rates and reserves. Double Eagle has a 0.349% working interest in the deep
participating area.
 The Company has not been paid any of the proceeds generated by the sale of gas produced from the
Madden Deep Unit over the period beginning the effective date of the Unit through June 30, 2007.
Double Eagle began receiving payments for its share of the sales on July 1, 2007. The Company,
along with other plaintiffs, filed a lawsuit on August 24, 2007, in the District Court of
Fremont County, Wyoming, against Conoco/Phillips and other defendants who own working interests
in the Madden Deep Unit. The Company
and the other plaintiffs in the case are asserting that, under the gas balancing agreement, they
are entitled to receive either monetary damages or their respective shares of the gas produced
from the Madden Deep Unit over at least the period February 1, 2002 through June 30, 2007.
Sulfur sales are not subject to a gas balancing agreement, and, accordingly, the Company
received the proceeds for its share of sulfur sales dating back to February 2002 and continues
to receive its respective share on an on-going basis. The Company has recognized the sales and
has recorded a related account receivable of $292, net of allowance for uncollectible amounts of
$292, for the period November 1, 2006 through June 30, 2007. The ultimate outcome of this
lawsuit cannot be determined at this time and, as a result, the Company has not recognized any
amount of sales proceeds for the period February 1, 2002 through October 30, 2006.
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6.
    
    Derivative Instruments
 The Companys primary market exposure is to adverse fluctuations in the prices of natural gas.
The Company uses derivative instruments, primarily forward sales, costless collars and swaps, to
manage the price risk associated with equity gas production, and the resulting impact on cash
flow, net income, and earnings per share. The Company does not use derivative instruments for
speculative purposes.
 The extent of the Companys risk management activities is controlled through policies and
procedures that involve senior management and were approved by the Companys Board of Directors.
Senior management is responsible for proposing equity hedge recommendations, execution of the
approved hedging plan, oversight of the risk management process including methodologies used for
valuation and risk measurement and presenting policy changes to the Board. The Companys Board
of Directors is responsible for approving risk management policies and for establishing the
Companys overall risk tolerance levels. The duration of the various derivative instruments
depends on senior managements view of market conditions, available contract prices and the
Companys operating strategy. Under the Companys credit agreement, the Company can hedge up to
90% of the projected proved developed producing reserves for the next 12 month period, and up to
80% of the projected proved producing reserves for the ensuing 24 month period.
 The Company recognizes its derivative instruments as either assets or liabilities at fair value
on our consolidated balance sheet, except for certain instruments which qualify for accounting
treatment exception under normal purchases and normal sales. See additional discussion of
these instruments below. The Company accounts for the commodity forward contracts that do not
qualify for this exception as either cash flow hedges or mark to market derivative instruments.
On the cash flow statement, the cash flows from these instruments are classified as operating
activities.
 Derivative instruments expose the Company to counterparty credit risk. The Company enters into
these contracts with third parties and financial institutions that it considers to be credit
worthy. In addition, the Companys master netting agreements reduce credit risk by permitting
the Company to net settle for transactions with the same counterparty.
 As with most derivative instruments, the Companys derivative contracts contain provisions which
may allow for another party to require security from the counterparty to ensure performance
under the contract. The security may be in the form of, but not limited to, a letter of credit,
security interest or a performance bond. None of the Companys counterparties have required
any type of security to be posted as of December 31, 2009.
 Cash flow hedges
 Derivative instruments that are designated and qualify as cash flow hedges are recorded at fair
value on the balance sheet and the effective portion of the change in fair value is reported as
a component of accumulated other comprehensive income (AOCI) and is subsequently reclassified
into the oil and gas sales line on the consolidated statement of operations as the contracts
settle. In order to qualify as cash flow hedges, the instruments must be designated as such and
the changes in fair value must be highly correlated with the changes in price of our equity
production. The Company formally documents the relationship between the derivative instruments
and the hedged production, as well as the Companys risk management objective and strategy for
the particular derivative contracts. This process includes linking all derivatives that are
designated as cash flow hedges to the specific forecasted sale of gas at its physical location
as well as routinely evaluating the effectiveness of the cash flow hedges. The Company seeks to
minimize the ineffectiveness of the cash flow hedges by entering into contracts indexed to
regional index prices associated with pipelines in proximity to the Companys areas of
production. As the Companys cash flow hedges contain the same index as the Companys sales
contracts; this results in hedges that are highly correlated with the underlying hedged item
 Mark to market hedging instruments
 Unrealized gains and losses resulting from derivatives not designated as cash flow hedges are
recorded at fair value on the balance sheet and changes in fair value are recognized in the
price risk management activities line on the consolidated statement of operations currently.
Realized gains and losses resulting from the contract settlement of derivatives not designated
as cash flow hedges also are recorded in the price risk management activities line on the
consolidated statement of operations.
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The table below contains a summary of all the Companys derivative positions reported on the
consolidated balance sheet as of December 31, 2009, presented gross of any master netting
arrangements:
 Derivatives designated as hedginginstruments under ASC 815
    
    Balance Sheet Location
    
    
    Fair ValueAssetsCommodity derivatives
    
    Assets from price risk management  long term
    
    
    3,566Total
    
    
    
    
    
    $
    3,566
 Derivatives not designated ashedging instruments under ASC 815
    
    Balance Sheet Location
    
    
    Fair ValueAssetsCommodity derivatives
    
    Liabilities from price risk management  current
    
    $
    105LiabilitiesCommodity derivatives
    
    Liabilities from price risk management  current
    
    
    (4,844
    )Liabilities from price risk management  long term
    
    
    (430
    )Total
    
    
    
    
    
    $
    (5,169
    )
 The before-tax effect of derivative instruments in cash flow hedging relationships on the
consolidated statement of operations for the year ended December 31, 2009 was as follows:
 Location of GainGain (Loss)
    
    
    
    
    
    
    
    
    
    Recognized in IncomeRecognized in OCI1
    
    
    
    
    
    Gain Reclassified
    
    (Ineffective Portion andon Derivative
    
    
    
    
    
    from Accumulated
    
    Amount Excluded from(effective portion)
    
    Location
    
    OCI1into Income
    
    Effectiveness testing)Cash flow hedges:Commodity contracts
    
    $
    2,616
    
    
    Oil and gas sales
    
    $
    15,740
    
    
    
    N/A
 
 1 Other comprehensive income (OCI). The before-tax effect of derivative instruments not designated as hedging instruments on the
consolidated statement of operations for the year ended December 31, 2009 was as follows:
 Loss Recognized inIncome onLocation
    
    DerivativePrice risk management
activites
    
    $
    (4,295
    )
 Normal purchases and normal sales
 During the year ended December 31, 2009, the Company had fixed delivery contracts for production
from Sun Dog and Doty Mountain at the Atlantic Rim and the Pinedale Anticline that qualified for
accounting under the normal purchases and normal sales exception. Physical delivery contracts
may meet the criteria for this accounting exception so long as it is probable both at inception
and throughout the life of the contract that the contract will result in physical delivery and
will not net settle. Under the normal purchases and normal sales accounting treatment, the
Company records the revenue upon contract settlement in oil and
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##### Table of Contents



gas sales on the consolidated statement of operations. All of the Companys contracts that
qualified for this treatment had settled prior to December 31, 2009.
 Refer to Note 6 for additional information regarding the valuation of the Companys derivative
instruments, and Note 5 for the listing of the current contracts the Company had in place as of
December 31, 2009.
 7.      Fair Value of Financial Instruments
 The Company records certain of its assets and liabilities on the balance sheet at fair value.
Fair value is defined as the price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants at the measurement date (exit
price). A three-level valuation hierarchy has been established to allow readers to understand
the transparency of inputs to the valuation of an asset or liability as of the measurement date.
The three levels are defined as follows:
 
    
    Level 1  Quoted prices (unadjusted) for identical assets or liabilities in active
markets.
    
    Level 2  Quoted prices for similar assets or liabilities in active markets; quoted
prices for identical or similar assets or liabilities in markets that are not active; and model-derived
valuations whose inputs or significant value drivers are observable.
    
    Level 3  Unobservable inputs that reflect the Companys own assumptions.
 The following describes the valuation methodologies the Company uses for its fair value
measurements.
 Cash and cash equivalents
 Cash and cash equivalents include all cash balances and any highly liquid investments with an
original maturity of 90 days or less. The carrying amount approximates fair value because of the
short maturity of these instruments.
 Derivative instruments
 The Company considers several factors in determining its estimate of fair value, including
quoted market prices in active markets, quotes from third parties, the credit rating of each
counterparty, and the Companys own credit rating. The Company also performs an internal
valuation to ensure the reasonableness of third-party quotes.
 In consideration of counterparty credit risk, the Company assessed the possibility of whether
each counterparty to the derivative would default by failing to make any contractually required
payments. Additionally, the Company considers that it is of substantial credit quality and has
the financial resources and willingness to meet its potential repayment obligations associated
with the derivative transactions.
 At December 31, 2009, the types of derivative instruments utilized by the Company included
costless collars and swaps. The natural gas derivative markets are highly active. Although the
Companys cash flow and economic hedges are valued using public indices, the instruments
themselves are traded with third-party counterparties and are not openly traded on an exchange.
As such, the Company has classified these instruments as Level 2.
 Credit facility
 The recorded value of the Companys credit facility approximates fair value as it bears interest
at a floating rate.
 Asset retirement obligations
 The Company recognizes an estimated liability for future costs associated with the abandonment
of our oil and gas properties. The Companys asset retirement obligation is measured using
primarily Level 3 inputs. The significant unobservable inputs include the cost of abandoning
oil and gas wells, which is based on the Companys historical experience for similar work, and
estimates from
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##### Table of Contents



independent third parties, the economic lives of our properties, the inflation rate, and the
credit adjusted risk-free rate. The Company bases its estimate of the liability on its
historical experience and current estimated costs.
 The following table provides a summary of the fair values of assets and liabilities measured at
fair value:
 Level 1
    
    Level 2
    
    Level 3
    
    TotalAssetsDerivative instruments
    
    $
    
    
    
    $
    3,566
    
    
    $
    
    
    
    $
    3,566Total assets at fair value
    
    $
    
    
    
    $
    3,566
    
    
    $
    
    
    
    $
    3,566LiabilitiesDerivative instruments
    
    $
    
    
    
    $
    5,169
    
    
    $
    
    
    
    $
    5,169Asset retirement obligation
    
    $
    
    
    
    
    
    
    
    
    4,807
    
    
    $
    4,807Total liabilities at fair value
    
    $
    
    
    
    $
    5,169
    
    
    $
    4,807
    
    
    $
    9,976
 Refer to Note 1 for the Level 3 rollforward of the asset retirement obligation.
 8.
    
    Series A Cumulative Preferred Stock
 In 2007, the shareholders of the Company amended the Companys
Articles of Incorporation to allow for the issuance of 10,000,000
shares of preferred stock, and subsequently completed a public
offering of 1,610,000 shares of 9.25% Series A Cumulative Preferred
Stock at a price to the public of $25.00 per share.
 Holders of the Series A Preferred Stock are entitled to receive, when and as declared by the
Board of Directors, dividends at a rate of 9.25% per annum ($2.3125 per annum per share). The
Series A Preferred Stock does not have any stated maturity date and will not be subject to any
sinking fund or mandatory redemption provisions, except, under some circumstances upon a Change
of Ownership or Control. Except pursuant to the special redemption
upon a Change of Ownership
or Control, the Company may not redeem the Series A Preferred Stock prior to June 30, 2012. On
or after June 30, 2012, the Company may redeem the Series A Preferred Stock for cash at our
option, in whole or from time to time in part, at a redemption price of $25.00 per share, plus
accrued and unpaid dividends (whether or not earned or declared) to
the redemption date. The shares of Series A Preferred Stock are classified outside of permanent equity on the
accompanying Consolidated Balance Sheets due to the following redemption provision. Following a
Change of Ownership or Control of us by a person or entity, other than by a Qualifying Public
Company, the Company will be required to redeem the Series A Preferred Stock within 90 days
after the date on which the Change of Ownership or Control occurred for cash, at the following
price per share, plus accrued and unpaid dividends.
 Redemption Date on or Before
    
    Redemption PriceJune 30, 2010
    
    $
    25.50June 30, 2011
    
    $
    25.25June 30, 2012 or thereafter
    
    $
    25.00
 In the event of liquidation, the holders of the Series A Preferred Stock will have the
right to receive $25.00 per share, plus all accrued and unpaid dividends, before any payments
are made to the holders or our common stock.
 Holders of the Series A Preferred Stock will generally have no voting rights. However, if cash
dividends on any outstanding Series A Preferred Stock are in arrears for any six consecutive or
non-consecutive quarterly dividend periods, or if Double Eagle fails to maintain a national
market listing, the holders of the Series A Preferred Stock, voting separately as a class, will
have the right to elect
two directors to serve on our board of directors in addition to those directors then serving on
our board until such time as the national market listing is obtained or the dividend arrearage
is eliminated.
 9.
    
    Compensation Plans
 Double Eagle has outstanding stock options issued to employees under various stock option plans,
approved by the Companys stockholders (collectively the Plans). The options have been
granted with an exercise price equal to the market price of Double
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##### Table of Contents



Eagles stock on the date of grant, vest annually over various periods from two to five years of
continuous service, and expire over various periods up to ten years from the date of grant. As
of December 31, 2009, there were 14,500 and 33,099 options available for grant under the 2002
and 2003 Stock Option Plans, respectively.
 In 2007, the Companys shareholders approved the 2007 Stock Incentive Plan (2007 Plan), which
allows both stock options and stock awards to be granted to the Companys employees, directors,
consultants, and other persons designated by the Compensation Committee of the Board of
Directors. In 2008, the Company began granting stock awards and stock options under this plan.
These awards vest annually over various periods of three to five years of continuous service.
As of December 31, 2009, there were 90,767 shares available for grant under the 2007 Plan.
 The Company accounts for its stock compensation in accordance with the provisions of ASC 718,
which requires the measurement and recognition of compensation expense for all share-based
payment awards (including stock options and stock awards) made to employees and directors based
on estimated fair value. During the years ended December 31, 2009, 2008 and 2007, total
share-based compensation expense for equity-classified awards, was $1,484, $1,178 and $552,
respectively, and is reflected in general and administrative expense in the Consolidated
Statement of Operations.
 Stock Options
 The Company uses the Black-Scholes valuation model to determine the fair value of each option
award. Expected volatilities are based on the historical volatility of Double Eagles stock over
a period consistent with that of the expected terms of the options. The expected terms of the
options are estimated based on factors such as vesting periods, contractual expiration dates,
historical trends in Double Eagles stock price and historical exercise behavior. The risk-free
rates for periods within the contractual life of the options are based on the yields of U.S.
Treasury instruments with terms comparable to the estimated option terms.
 Assumptions used in estimating fair value of share-based awards for the periods indicated:
 For the year ended December 31,2009
    
    2008
    
    2007Weighted-average volatility
    
    
    51
    %
    
    
    40 - 41
    %
    
    
    42
    %Expected dividends
    
    
    0.00
    %
    
    
    0.00
    %
    
    
    0.00
    %Expected term (in years)
    
    
    5
    
    
    
    4.5
    
    
    
    4.25Risk-free rate
    
    
    1.72
    %
    
    
    2.42% - 3
    %
    
    
    4.58
    %Expected forfeiture rate
    
    
    7.00
    %
    
    
    5% - 7
    %
    
    
    7.00
    %
 Summary of option activity during the year ended December 31, 2009:
 Weighted-AverageRemainingWeighted-Average
    
    
    Contractual Term
    
    
    AggregateOptions:
    
    Shares
    
    
    Exercise Price
    
    
    (in years)
    
    
    Intrinsic ValueOutstanding at January 1, 2009
    
    
    626,897
    
    
    $
    15.68
    
    
    
    5.1Granted
    
    
    50,500
    
    
    $
    7.79Exercised
    
    
    
    
    
    $
    Cancelled/expired
    
    
    (29,500
    )
    
    $
    15.83Outstanding at December 31, 2009
    
    
    647,897
    
    
    $
    15.06
    
    
    
    4.7
    
    
    $
    Exerciseable at December 31, 2009
    
    
    281,359
    
    
    $
    12.77
    
    
    
    3.7
    
    
    $
    
 The weighted average grant date fair value price per share of options granted during the
three years ended December 31, 2009, 2008, and 2007 was $7.79, $14.91, and $17.86, respectively.
No options were exercised during 2009. During the years ended December
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##### Table of Contents



31, 2008, and 2007, the total intrinsic value, or the difference between the exercise price and
the market price on the date of exercise, of all options exercised
was $276 and $150. As of December 31, 2009, 2008, and 2007, the fair value of
options vested and exercisable was $0, $0, and $2,255.
 Stock options outstanding and currently exercisable at December 31, 2009 are:
 Options
    
    
    
    
    
    Options ExercisableOutstandingWeighted Average
    
    Weighted
    
    
    
    
    
    WeightedNumber of
    
    Remaining
    
    Average
    
    Number of
    
    AverageRange of Exercise
    
    Options
    
    Contractual Life
    
    Exercise Price
    
    Options
    
    Exercise PricePrices per Share
    
    Outstanding
    
    (in years)
    
    per Share
    
    Exercisable
    
    per Share$6.78 - $7.79
    
    
    65,500
    
    
    
    6.8
    
    
    $
    7.60
    
    
    
    3,000
    
    
    $
    6.94$14.00 - $16.21
    
    
    420,897
    
    
    
    5.3
    
    
    $
    14.70
    
    
    
    191,359
    
    
    $
    10.34$17.86 - $19.55
    
    
    134,000
    
    
    
    2.4
    
    
    $
    18.55
    
    
    
    70,500
    
    
    $
    17.61$20.21 - $23.61
    
    
    27,500
    
    
    
    2.5
    
    
    $
    21.30
    
    
    
    16,500
    
    
    $
    21.30647,897
    
    
    
    4.7
    
    
    $
    15.06
    
    
    
    281,359
    
    
    $
    12.77
 As of December 31, 2009, there was $1,637 of total unrecognized stock-based compensation
expense related to stock options to be recognized over a weighted-average period of 2.89 years.
 Stock awards
 The Company measures the fair value of the stock awards based upon the fair market value of its
common stock on the date of grant and recognize the resulting compensation expense ratably over
the associated service period, which is generally the vesting term of the stock awards. The
Company recognizes these compensation costs net of a forfeiture rate, if applicable, and
recognize the compensation costs for only those shares expected to vest. The forfeiture rates
are based on historical experience, while also considering the duration of the vesting term of
the award.
 Nonvested stock awards as of December 31, 2009 and changes for the year ended December 31, 2009
were as follows:
 Weighted-Average GrantStock Awards:
    
    Shares
    
    Date Fair ValueOutstanding at January 1, 2009
    
    
    94,762
    
    
    $
    14.70Granted
    
    
    105,837
    
    
    $
    4.22Vested
    
    
    (113,151
    )
    
    $
    6.69Forfeitures
    
    
    
    
    
    $
    Nonvested at December 31, 2009
    
    
    87,448
    
    
    $
    12.38
 As of December 31, 2009, there was $1,017 of unrecognized stock-based compensation expense
related to nonvested stock awards. This cost is expected to be recognized over a
weighted-average period of 3.7 years.
 As part of the acquisition of Petrosearch, the Company assumed all outstanding warrants to
purchase common stock that had been issued by Petrosearch prior to the merger. At December 31,
2009, the Company had three tranches of warrants outstanding; 14,691 warrants with an exercise
price of $46.19 that expire in February 2010; 10,310 warrants with an exercise price of $34.64
that expire November 2010; and 8,660 warrants with an exercise price of $21.25 that expire
December 2011. The warrants had no intrinsic value at December 31, 2009.
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10.
    
    Subsequent EventsEffective February 5, 2010, the Company entered into an amended and restated credit agreement
with its lenders, primarily to extend the maturity date of the facility from July 31, 2010 to
January 31, 2013. No other material changes were made to the agreement. In accordance with
ASC 470, the Company reclassified its credit facility balance from a current liability to a
long-term liability on the Consolidated Balance Sheet as of December 31, 2009.The Company has noted no additional events, other than noted above, that require recognition or
disclosure at December 31, 2009.
 11.
    
    Supplemental Information on Oil and Gas Producing ActivitiesCapitalized Costs Relating to Oil and Gas Producing ActivitiesThe aggregate amount of capitalized costs relating to crude oil and natural gas producing
activities and the aggregate amount of related accumulated depreciation, depletion and
amortization at December 31, 2009, 2008 and 2007 are:
 As of December 31,2009
    
    
    2008
    
    
    2007Developed properties
    
    $
    165,279
    
    
    $
    133,516
    
    
    $
    61,394Wells in progress
    
    
    7,544
    
    
    
    18,518
    
    
    
    29,768Undeveloped properties
    
    
    2,502
    
    
    
    2,907
    
    
    
    3,147175,325
    
    
    
    154,941
    
    
    
    94,309Accumulated depletion and amortization
    
    
    (52,041
    )
    
    
    (33,905
    )
    
    
    (22,218
    )Net capitalized costs
    
    $
    123,284
    
    
    $
    121,036
    
    
    $
    72,091
 Costs incurred in Oil and Gas Property Acquisitions, Exploration and Development ActivitiesCosts incurred in property acquisitions, exploration, and development activities for the years
ended December 31, 2009, 2008 and 2007 were:
 For the year ended December 31,2009
    
    
    2008
    
    
    2007Property acquisitions  unproved
    
    $
    16
    
    
    $
    30
    
    
    $
    316Exploration
    
    
    59
    
    
    
    536
    
    
    
    3,600Development
    
    
    21,466
    
    
    
    64,462
    
    
    
    41,337Total
    
    $
    21,541
    
    
    $
    65,028
    
    
    $
    45,253
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##### Table of Contents



Results of Operations from Oil and Gas Producing ActivitiesThe table below shows the results of operations for the Companys oil and gas producing
activities for the years ended December 31, 2009, 2008 and 2007. All production is from within
the continental United States.
 For the year ended December 31,2009
    
    
    2008
    
    
    2007Operating revenues (1)
    
    $
    45,901
    
    
    $
    41,847
    
    
    $
    16,044Costs and expenses:Production
    
    
    11,406
    
    
    
    11,708
    
    
    
    7,629Exploration
    
    
    103
    
    
    
    911
    
    
    
    15,399Depletion, amortization and impairment
    
    
    18,136
    
    
    
    11,078
    
    
    
    6,691Total costs and expenses
    
    
    29,645
    
    
    
    23,697
    
    
    
    29,719Income (loss) before income taxes
    
    
    16,256
    
    
    
    18,150
    
    
    
    (13,675
    )Income tax expense
    
    
    5,693
    
    
    
    6,356
    
    
    
    (4,789
    )Results of operations
    
    $
    10,563
    
    
    $
    11,794
    
    
    $
    (8,886
    )
 
 (1)
    
    Operating revenues are comprised of the oil and gas sales from the Consolidated
Statement of Operations, plus settlements on the Companys financial hedges during the
period. For the years ended December 31, 2009, 2008 and 2007, the settlements on
derivatives totaled $3,503, $2,698, and $0, respectively. Oil and Gas Reserves (Unaudited)The reserves at December 31, 2009, 2008 and 2007 presented below were reviewed by the
independent engineering firm, Netherland, Sewell & Associates, Inc. All reserves are located
within the continental United States. The reserve estimates are developed using geological and
engineering data and interests and burden information developed by the Company. Reserve
estimates are inherently imprecise and are continually subject to revisions based on production
history, results of additional exploration and development, prices of oil and gas, and other
factors.Estimated net quantities of proved developed reserves of oil and gas for the years ended
December 31, 2009, 2008, and 2007 are:
 For the year ended December 31,2009
    
    2008
    
    2007Oil
    
    Gas
    
    Oil
    
    Gas
    
    Oil
    
    Gas(Bbl)
    
    (Mcf)
    
    (Bbl)
    
    (Mcf)
    
    (Bbl)
    
    (Mcf)Beginning of year
    
    
    420,189
    
    
    
    86,330,820
    
    
    
    412,812
    
    
    
    71,253,865
    
    
    
    360,165
    
    
    
    48,496,719Revisions of estimates
    
    
    (42,417
    )
    
    
    (9,323,380
    )
    
    
    (33,439
    )
    
    
    (4,637,562
    )
    
    
    (112,093
    )
    
    
    (18,449,972
    )Extensions and discoveries
    
    
    61,932
    
    
    
    21,931,592
    
    
    
    65,429
    
    
    
    26,244,840
    
    
    
    178,208
    
    
    
    44,135,456Purchases of reserves
    
    
    8,436
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (28,927
    )
    
    (9,162,362
    )
    
    
    (24,613
    )
    
    
    (6,530,323
    )
    
    
    (13,468
    )
    
    
    (2,928,338
    )End of year
    
    
    419,213
    
    
    
    89,776,670
    
    
    
    420,189
    
    
    
    86,330,820
    
    
    
    412,812
    
    
    
    71,253,865Proved developed reserves
    
    
    287,276
    
    
    
    64,195,169
    
    
    
    295,698
    
    
    
    63,007,126
    
    
    
    253,478
    
    
    
    44,782,553Percentage of proved
developed reserves
    
    
    69
    %
    
    
    72
    %
    
    
    70
    %
    
    
    73
    %
    
    
    61
    %
    
    
    63
    %
 As of December 31, 2009, the Company had estimated proved reserves of 89.8 Bcf of natural
gas and 419 MBbl of oil, or a total of 92.3 Bcfe. The proved reserves were estimated in
accordance with ASC 2010-3, which updated the guidance for reporting oil and gas reserves to
align the oil and gas reserve estimation and disclosure requirements with the requirements in
the SECs final rule, Modernization of the Oil and Gas Reporting Requirements. The new reserve
guidance changed the pricing methodology
used to estimate reserves to an average, first-day-of-the-month price based on the prior
12-month period. For the year ended December 31, 2008 and 2007, however, pricing was based upon
the price on the last day of the fiscal year. Using this change in price determination, the
average natural gas price used in calculating the December 31, 2009 reserves decreased to $3.04
per
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##### Table of Contents



MMBtu from the December 31, 2008 price of $4.61 MMBtu. The decrease in price shortened the
economic life of certain existing wells and caused a downward revision in reserves. If the
Company had used the prior-year pricing methodology for its calculation of its 2009 estimated
proved reserves, the Company would have reported higher proved reserves of approximately 21.9
Bcfe. In addition, ASC 2010-3 allows for more than a one well offset from proved reserves in
well-defined fields. This provided additional reserves in the Catalina Unit and Mesa Unit.
 As of December 31, 2009, 76% of the proved developed gas reserves and 100% of the proved
developed oil reserves were in producing status. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
(Unaudited)The following information has been developed utilizing procedures prescribed by ASC 932
Extractive Activities  Oil and Gas, and is based on natural gas and crude oil reserves and
production volumes estimated by the Company. It may be useful for certain comparison purposes,
but should not be solely relied upon in evaluating the Company or its performance. Further,
information contained in the following table should not be considered as representative or
realistic assessments of future cash flows, nor should the Standardized Measure of Discounted
Future Net Cash Flows be viewed as representative of the current value of the Company.The Company believes that the following factors should be taken into account in reviewing the
following information: (1) future costs and selling prices will likely differ from those
required to be used in these calculations; (2) due to future market conditions and governmental
regulations, actual rates of production achieved in future years may vary significantly from the
rate of production assumed in these calculations; (3) selection of a 10% discount rate, as
required under the accounting codification, is arbitrary and may not be reasonable as a measure
of the relative risk inherent in realizing future net oil and gas revenues; and (4) future net
revenues may be subject to different rates of income taxation.Under the Standardized Measure, for the year ended December 31, 2009, future cash inflows were
estimated by applying the new SEC 12-month average pricing of oil and gas relating to the
Companys proved reserves to the year-end quantities of those reserves. For the years ended
December 31, 2008 and 2007, future cash inflows were computed by applying the former SEC end of
year pricing of oil and gas relating to the Companys proved reserves to the year-end quantities
of those reserves. Future cash inflows were reduced by estimated future development and
production costs based upon year-end costs in order to arrive at net cash flow before tax.
Future income tax expense has been computed by applying year-end statutory rates to future
pretax net cash flows and the utilization of net operating loss carry-forwards.Management does not rely solely upon the following information to make investment and operating
decisions. Such decisions are based upon a wide range of factors, including estimates of
probable, as well as proved reserves, and varying price and cost assumptions considered more
representative of a range of possible economic conditions that may be anticipated.Information with respect to the Companys Standardized Measure:
 As of December 31,2009
    
    
    2008
    
    
    2007Future cash inflows
    
    $
    276,374
    
    
    $
    406,017
    
    
    $
    462,655Future production costs
    
    
    (105,161
    )
    
    
    (118,299
    )
    
    
    (102,515
    )Future development costs
    
    
    (16,777
    )
    
    
    (18,275
    )
    
    
    (23,651
    )Future income taxes
    
    
    (14,279
    )
    
    
    (58,313
    )
    
    
    (96,370
    )Future net cash flows
    
    
    140,157
    
    
    
    211,130
    
    
    
    240,11910% annual discount
    
    
    (57,450
    )
    
    
    (89,075
    )
    
    
    109,820Standardized measure of
discounted future net cash flows
    
    $
    82,707
    
    
    $
    122,055
    
    
    $
    130,299
 F-26




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##### Table of Contents



Principal changes in the Standardized Measure for the years ended December 31, 2009, 2008
and 2007:
 2009
    
    
    2008
    
    
    2007Standard measure, as of January 1,
    
    $
    122,055
    
    
    $
    130,299
    
    
    $
    50,033Sales of oil and gas produced, net of production costs
    
    
    (30,992
    )
    
    
    (26,846
    )
    
    
    (8,416
    )Extensions and discoveries
    
    
    22,506
    
    
    
    49,511
    
    
    
    118,002Net change in prices and production costs related to
future production
    
    
    (62,838
    )
    
    
    (63,682
    )
    
    
    41,821Development costs incurred during the year
    
    
    13,043
    
    
    
    11,181
    
    
    
    9,924Changes in estimated future development costs
    
    
    (3,516
    )
    
    
    (5,188
    )
    
    
    (24,107
    )Purchases of reserves in place
    
    
    201
    
    
    
    
    
    
    
    Revisions of quantity estimates
    
    
    (10,460
    )
    
    
    (9,119
    )
    
    
    (50,750
    )Accretion of discount
    
    
    13,257
    
    
    
    15,919
    
    
    
    6,764Net change in income taxes
    
    
    25,285
    
    
    
    18,576
    
    
    
    (18,064
    )Changes in timing and other
    
    
    (5,834
    )
    
    
    1,404
    
    
    
    5,092Aggregate Change
    
    
    (39,348
    )
    
    
    (8,244
    )
    
    
    80,266Standardized measure, as of December 31,
    
    $
    82,707
    
    
    $
    122,055
    
    
    $
    130,299
 12.
    
    Quarterly Financial Data (Unaudited)Summary of the unaudited financial data for each quarter for the years ended December 31, 2009
and 2008 (in thousands except per share data):
 Fourth
    
    
    
    
    
    Second
    
    FirstQuarter
    
    Third Quarter
    
    Quarter
    
    QuarterYear ended December 31, 2009Oil and gas sales
    
    $
    11,737
    
    
    $
    9,669
    
    
    $
    10,492
    
    
    $
    10,500Income from operations
    
    $
    1,705
    
    
    $
    641
    
    
    $
    (352
    )
    
    $
    1,890Net income
    
    $
    28
    
    
    $
    416
    
    
    $
    (242
    )
    
    $
    1,007Net income (loss) attributable to common stock
    
    $
    (903
    )
    
    $
    (514
    )
    
    $
    (1,173
    )
    
    $
    76Basic net income per common share
    
    $
    (0.08
    )
    
    $
    (0.05
    )
    
    $
    (0.13
    )
    
    $
    0.01Diluted net income per common share
    
    $
    (0.08
    )
    
    $
    (0.05
    )
    
    $
    (0.13
    )
    
    $
    0.01Year ended December 31, 2008Oil and gas sales (1)
    
    $
    9,710
    
    
    $
    11,662
    
    
    $
    10,981
    
    
    $
    6,796Income from operations
    
    $
    3,287
    
    
    $
    4,464
    
    
    $
    5,189
    
    
    $
    3,009Net income
    
    $
    2,338
    
    
    $
    2,907
    
    
    $
    3,273
    
    
    $
    1,863Net income attributable to common stock
    
    $
    1,407
    
    
    $
    1,977
    
    
    $
    2,342
    
    
    $
    932Basic net income per common share
    
    $
    0.15
    
    
    $
    0.22
    
    
    $
    0.26
    
    
    $
    0.10Diluted net income per common share
    
    $
    0.15
    
    
    $
    0.22
    
    
    $
    0.26
    
    
    $
    0.10
 F-27