##### 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, 2010
 o
    
    TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from  to
 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.)
 (Address of principal executive offices) (Zip Code)
 (Registrants telephone number, including area code)
   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
 Yes o No þ
 Yes o No þ
 o
 Yes þ No o
 Yes o
No o
  Large accelerated filer o
    
    Accelerated filer o
    
    Non-accelerated filer o
    
    Small reporting company þ(Do not check if a small reporting company)
 Yes o No þ
   DOCUMENTS INCORPORATED BY REFERENCE




---



##### 



PAGEPART IItems 1. and 2. Business and Properties
    
    
    4Item 1A. Risk Factors
    
    
    20Item 1B. Unresolved Staff Comments
    
    
    26Item 3. Legal Proceedings
    
    
    26Item 4. Reserved
    
    
    26PART IIItem 5. Market For Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
    
    
    27Item 6. Selected Financial Data
    
    
    28Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations
    
    
    29Item 7A. Quantitative and Qualitative Disclosures About Market Risk
    
    
    44Item 8. Financial Statements and Supplementary Data
    
    
    45Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
    
    
    45Item 9A. Controls and Procedures
    
    
    45Item 9B. Other Information
    
    
    47PART IIIItem 10. Directors, Executive Officers and Corporate Governance
    
    
    47Item 11. Executive Compensation
    
    
    47Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
    
    
    47Item 13. Certain Relationships and Related Transactions, and Director Independence
    
    
    47Item 14. Principal Accountant Fees and Services
    
    
    48PART IVItem 15. Exhibits and Financial Statement Schedules
    
    
    48Exhibit 21.1Exhibit 23.1Exhibit 23.2Exhibit 31.1Exhibit 31.2Exhibit 32Exhibit 99.1
   2




---



##### Table of Contents



Cautionary Information about Forward-Looking Statements
  
    
    Changes in or compliance with laws and regulations, particularly those relating to
drilling, derivatives, taxation, safety and protection of the environment;
 
    
    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;
 
    
    Our ability to market and find reliable and economic transportation for our gas;
 
    
    The changing political environment in which we operate;
 
    
    Our ability and the ability of our partners to continue to develop the Atlantic Rim
project;
 
    
    The volumes of production from our oil and gas development properties, which may be
dependent upon issuance by federal and state 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 maintain adequate liquidity in connection with low oil and gas prices;
 
    
    Incorrect estimates of required capital expenditures;
 
    
    The amount and timing of capital deployment in new investment opportunities;
 
    
    Increases in the cost of drilling, completion and gas collection or other costs of
production and operations;
 
    
    Numerous uncertainties inherent in estimating quantities of proved oil and gas reserves
and actual future production rates and associated costs;
 
    
    Our ability to successfully integrate and profitably operate any future acquisitions;
 
    
    The actions of third party co-owners of interests in properties in which we also own an
interest;
 
    
    The credit worthiness of third parties with which we enter into hedging and business
agreements with;
 
    
    Weather, climate change and other natural phenomena;
 
    
    General economic conditions, tax rates or policies, interest rates and inflation rates;
 
    
    The volatility of our stock price;
 
    
    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;
 
    
    Our ability to remedy any deficiencies that may be identified in the review of our
internal controls; and
 
    
    The outcome of any future litigation or similar disputes and the impact on any such
outcome or related settlements.
     3




---



##### Table of Contents



PART I
 
 ITEMS 1. AND 2. BUSINESS AND PROPERTIES
 General
  Overview and Strategy
     
    
    15.3 Bcfe of reserve additions attributed to the purchase of additional working interest
in the Atlantic Rim properties, completed in July 2010.
    
    Extensions and discoveries totaling 17.0 Bcfe of reserves as the result of organic
growth from development drilling in the Pinedale Anticline. Improved pricing allowed us to
add new proved undeveloped reserves from wells in this area that had previously been
uneconomic.
 Reserves
 Other Significant Developments since
December 31, 2009
  4




---



##### Table of Contents



Operations
   Basin
    
    Gross Acres
    
    
    Net AcresWashakie Basin
    
    
    140,064
    
    
    
    57,112Wind River Basin
    
    
    51,026
    
    
    
    3,043Powder River Basin
    
    
    48,051
    
    
    
    18,074Utah Overthrust
    
    
    46,440
    
    
    
    21,146Greater Green River Basin
    
    
    38,530
    
    
    
    3,264Huntington Basin
    
    
    36,045
    
    
    
    30,264Other
    
    
    45,750
    
    
    
    24,099Total
    
    
    405,906
    
    
    
    157,002
  The Atlantic Rim Coal Bed Natural Gas Project
     5




---



##### Table of Contents



Catalina Unit
      Eastern Washakie Midstream Pipeline LLC
   6




---



##### Table of Contents



Sun Dog Unit
  Doty Mountain Unit
  Other Acreage
  The Pinedale Anticline in the Green River Basin of Wyoming
      7




---



##### Table of Contents



The Wind River Basin in Central Wyoming
  Madden Anticline
    South Waltman
  The Moxa Arch and Other Areas in Southwest Wyoming
   8




---



##### Table of Contents



Exploration Projects
  Proposed Exploration of Niobrara Shale Formation
  Area
    
    Gross Acres
    
    
    Net AcresAtlantic Rim
    
    
    60,390
    
    
    
    39,376DJ Basin  Wyoming
    
    
    4,954
    
    
    
    4,954DJ Basin  Nebraska
    
    
    4,198
    
    
    
    4,198Power River Basin
    
    
    15,643
    
    
    
    15,643Laramie/Hanna Basin
    
    
    8,669
    
    
    
    8,669Wind River Basin
    
    
    640
    
    
    
    640Total Niobrara Acreage
    
    
    94,494
    
    
    
    73,480
  Main Fork Unit in Utah
  Nevada
  Reserves
  
    
    The new SEC standards require us to 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 us.
    
    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 if we can establish with reasonable certainty that these reserves are
economically producible. In prior years, we were not permitted to establish proved
undeveloped reserves beyond those immediately adjacent to the drilling unit containing a
producing well.
  9




---



##### Table of Contents



As of December 31,2010 (1)
    
    
    2009 (1)
    
    
    2008Oil
    
    
    Natural Gas
    
    
    Oil
    
    
    Natural Gas
    
    
    Oil
    
    
    Natural Gas(Bbls)
    
    
    (Mcf)
    
    
    (Bbls)
    
    
    (Mcf)
    
    
    (Bbls)
    
    
    (Mcf)PROVEDDeveloped
    
    
    235,808
    
    
    
    73,049,048
    
    
    
    312,963
    
    
    
    64,296,948
    
    
    
    295,698
    
    
    
    63,007,126Undeveloped
    
    
    145,443
    
    
    
    39,719,466
    
    
    
    106,250
    
    
    
    25,479,722
    
    
    
    124,491
    
    
    
    23,323,694Total proved reserves
    
    
    381,251
    
    
    
    112,768,514
    
    
    
    419,213
    
    
    
    89,776,670
    
    
    
    420,189
    
    
    
    86,330,820
 (1)
    
    We adopted the SECs revisions to the oil and gas reporting requirements effective
December 31, 2009.    10




---



##### Table of Contents



As of December 31,2010 (1)
    
    
    2009 (1)
    
    
    2008Present value of estimated future net cash flows
before income taxes, discounted at 10% (2)
    
    $
    143,694
    
    
    $
    91,133
    
    
    $
    155,766Reconciliation of non-GAAP financial measure:PV-10
    
    $
    143,694
    
    
    $
    91,133
    
    
    $
    155,766Less: Undiscounted income taxes
    
    
    (50,732
    )
    
    
    (14,279
    )
    
    
    (58,313
    )Plus: 10% discount factor
    
    
    21,982
    
    
    
    5,853
    
    
    
    24,602Discounted income taxes
    
    
    (28,750
    )
    
    
    (8,426
    )
    
    
    33,711Standardized measure of discounted future
net cash flows
    
    $
    114,944
    
    
    $
    82,707
    
    
    $
    122,055
 (1)
    
    We 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, 2010, 2009, and 2008, respectively, were $3.95
per MMBtu and $75.96 per barrel of oil; $3.04 per MMBtu and $57.65 per barrel of oil; and
$4.61 per MMBtu and $38.67 per barrel of oil. These prices are adjusted by field for quality,
transportation fees and regional prices differentials.   11




---



##### Table of Contents



Production
  For the Year Ended December 31,2010
    
    
    2009
    
    
    2008Oil (Bbls)
    
    
    Gas (MMcf)
    
    
    Oil (Bbls)
    
    
    Gas (MMcf)
    
    
    Oil (Bbls)
    
    
    Gas (MMcf)Production:Atlantic Rim
    
    
    
    
    
    
    6,729
    
    
    
    
    
    
    
    6,677
    
    
    
    
    
    
    
    4,473Pinedale Anticline
    
    
    15,413
    
    
    
    1,760
    
    
    
    16,741
    
    
    
    1,961
    
    
    
    14,674
    
    
    
    1,547Other
    
    
    10,611
    
    
    
    514
    
    
    
    12,186
    
    
    
    524
    
    
    
    10,994
    
    
    
    540Company total
    
    
    26,024
    
    
    
    9,003
    
    
    
    28,927
    
    
    
    9,162
    
    
    
    25,668
    
    
    
    6,560Average sales price
($/Bbl or $/Mcf)Atlantic Rim (1)
    
    
    N/A
    
    
    $
    4.08
    
    
    
    N/A
    
    
    $
    5.42
    
    
    
    N/A
    
    
    $
    5.86Pinedale Anticline
    
    $
    66.80
    
    
    $
    4.21
    
    
    $
    47.40
    
    
    $
    3.39
    
    
    $
    77.10
    
    
    $
    6.62Other
    
    $
    75.51
    
    
    $
    4.36
    
    
    $
    57.49
    
    
    $
    3.09
    
    
    $
    77.42
    
    
    $
    6.39Company average
    
    $
    70.35
    
    
    $
    4.12
    
    
    $
    51.65
    
    
    $
    4.85
    
    
    $
    77.24
    
    
    $
    6.08Average production
cost ($/mcfe)Atlantic Rim (2)
    
    
    
    $1.10
    
    
    
    
    
    $0.85
    
    
    
    
    
    $1.17Pinedale Anticline
    
    
    
    $0.68
    
    
    
    
    
    $0.53
    
    
    
    
    
    $0.51Other
    
    
    
    $1.88
    
    
    
    
    
    $1.67
    
    
    
    
    
    $1.49Company average
    
    
    
    $1.06
    
    
    
    
    
    $0.83
    
    
    
    
    
    $1.04
 (1)
    
    Our average gas price in the Atlantic Rim includes the settlements on our financial
hedges that due to accounting rules, are included in price risk management activities on
the consolidated statement of operations, totaling $5,316, $3,503, and $2,698, for the
years ended December 31, 2010, 2009 and 2008, 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 our subsidiary, Eastern Washakie Midstream, which are eliminated in
consolidation. Derivative Instruments
  RemainingContractual
    
    
    Daily
    
    
    
    
    
    PriceType of Contract
    
    Volume
    
    
    Production
    
    Term
    
    Price
    
    Index (1)Fixed Price Swap
    
    
    2,920,000
    
    
    8,000
    
    01/11-12/11
    
    $7.07
    
    CIGCostless Collar
    
    
    1,060,000
    
    
    5,000
    
    08/09-07/11
    
    $4.50 floor
    
    NYMEX$7.90 ceilingCostless Collar
    
    
    1,670,000
    
    
    5,000
    
    12/09-11/11
    
    $4.50 floor
    
    NYMEX$9.00 ceilingTotal
    
    
    5,650,000
 (1)
    
    CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month.
NYMEX refers to quoted prices on the New York Mercantile Exchange.  12




---



##### Table of Contents



Daily
    
    
    
    
    
    
    PriceType of Contract
    
    Production
    
    
    Term
    
    Price
    
    IndexFixed Price Swap
    
    
    10,000
    
    
    01/12-12/12
    
    $5.05
    
    NYMEXFixed Price Swap
    
    
    6,000
    
    
    01/13-12/13
    
    $5.16
    
    NYMEXCostless Collar
    
    
    6,000
    
    
    01/13-12/13
    
    $5.00 floor
    
    NYMEX$5.35 ceiling
  Productive Wells
  Oil
    
    
    GasState
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    NetWyoming
    
    
    93
    
    
    
    6.0353
    
    
    
    1,074
    
    
    
    101.5472Other
    
    
    39
    
    
    
    4.4946
    
    
    
    5
    
    
    
    0.0855Total
    
    
    132
    
    
    
    10.5299
    
    
    
    1,079
    
    
    
    101.6327
 Drilling Activity
  For the Year Ended December 31,2010
    
    
    2009
    
    
    2008Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    NetDevelopmentOil
    
    
    13
    
    
    
    0.04
    
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    0.05Gas
    
    
    26
    
    
    
    2.08
    
    
    
    42
    
    
    
    3.12
    
    
    
    178
    
    
    
    27.59Dry Holes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    0.69Water Injection
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    14
    
    
    
    5.42Water Supply
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    1.00
    
    
    
    
    
    
    
    Other
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5
    
    
    
    2.67Total
    
    
    39
    
    
    
    2.12
    
    
    
    43
    
    
    
    4.12
    
    
    
    199
    
    
    
    36.42
  Finding and Development Costs
    13




---



##### Table of Contents



As of December 312010
    
    
    2009
    
    
    2008Proved Developed (MMcfe)
    
    
    3,021
    
    
    
    10,543
    
    
    
    17,196Proved Undeveloped (MMcfe)
    
    
    13,941
    
    
    
    11,761
    
    
    
    9,441Total Proved Reserves Added (Mmcfe)
    
    
    16,962
    
    
    
    22,304
    
    
    
    26,637One year finding and development
costs per Mcfe
    
    $
    0.68
    
    
    $
    0.91
    
    
    $
    1.47
   Acreage
   Developed Acres (1)
    
    
    Undeveloped Acres (2)
    
    
    Total AcresState
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    NetWyoming
    
    
    121,541
    
    
    
    10,936
    
    
    
    140,820
    
    
    
    84,710
    
    
    
    262,361
    
    
    
    95,646Nevada
    
    
    
    
    
    
    
    
    
    
    36,045
    
    
    
    30,264
    
    
    
    36,045
    
    
    
    30,264Utah
    
    
    637
    
    
    
    16
    
    
    
    46,440
    
    
    
    21,146
    
    
    
    47,077
    
    
    
    21,162Other
    
    
    5,544
    
    
    
    2,678
    
    
    
    7,930
    
    
    
    4,997
    
    
    
    13,474
    
    
    
    7,675Total
    
    
    127,722
    
    
    
    13,630
    
    
    
    231,235
    
    
    
    141,117
    
    
    
    358,957
    
    
    
    154,747
  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 our 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.  14




---



##### Table of Contents



Expiring AcreageYear
    
    Gross
    
    
    Net2011
    
    
    18,244
    
    
    
    6,2822012
    
    
    12,837
    
    
    
    7,3992013 and thereafter
    
    
    374,825
    
    
    
    143,321Total
    
    
    405,906
    
    
    
    157,002
 Other Significant Developments since December 31, 2009
  Working Interest AfterUnit
    
    Working Interest Acquired
    
    
    Purchase (1)Catalina
    
    
    3.08
    %
    
    
    72.40
    %Sun Dog
    
    
    12.57
    %
    
    
    21.46
    %Doty Mountain
    
    
    1.15
    %
    
    
    18.00
    %
 (1)
    
    Our working interest in the Unit will continue to change as additional wells are drilled
and acreage is added to the Units participating area.   Marketing and Major Customers
    15




---



##### Table of Contents



Title to Properties
  Seasonality
   Competition
  Government Regulations
  We are
subject to various governmental regulations and environmental risks that may cause us to incur
substantial costs.
  16




---



##### Table of Contents




    
    the BLM and the Bureau of Ocean Energy Management, Regulation and
Enforcement (BOEMRE) (formerly the Minerals Management Service),
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;
    
    the 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; and
    
    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; and
    Environmental Laws and Regulations
     17




---



##### Table of Contents



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.
 Glossary
  Bbl.
 Bcf.
 Bcfe.
 Btu.
 Darcy.
 Development well.
 Dry hole
 Estimated net proved reserves.
  18




---



##### Table of Contents



Exploratory well.
 Economically producible.
 Field.
 Gross acre.
 Gross well.
 MBbl.
 Mcf.
 Millidarcy.
 Mcfe
 MMcf.
 MMcfe.
 MMBtu.
 Net acres or net wells.
 Permeability.
 Productive well.
 Proved developed reserves.
 Proved reserves.
 Proved undeveloped reserves.
 PV-10 value.
 Royalty.
  19




---



##### Table of Contents



Royalty interest.
 Undeveloped acreage.
 Working interest
 
 ITEM 1A.
    
    RISK FACTORS
  Our operations are subject to governmental risks that may impact our operations.
  
    
    Climate Change. Climate-change legislation establishing a cap-and-trade plan for
greenhouse gases (GHGs) was approved by the U.S. House of Representatives in 2010. 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. The EPA now purports to have a basis to begin regulating emissions of GHGs under the
federal Clean Air Act.
    
    Taxes. President Obama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, eliminating the immediate deduction for intangible
drilling and development costs and eliminating the deduction from income for domestic
production activities relating to oil and natural-gas exploration and development.
    
    Hydraulic Fracturing. 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. Concern around the exploration and development of shale gas using hydraulic
fracturing has continued to grow, which may give rise to additional regulation in this
area. The U.S. Congress continues to consider 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. This legislation, if adopted, could establish
an additional level of regulation and permitting at the federal level. In addition, the
State of Wyoming, where the Company conducts substantially all of its operations, approved
new reporting requirements involving hydraulic fracturing in 2010.
  20




---



##### Table of Contents




    
    Derivatives. The Dodd-Frank Act passed in July 2010 expanded federal regulation of
financial derivative instruments, including credit default swaps, commodity derivatives and
other over-the-counter derivatives. Although under the current definitions within the Dodd
Frank Act we would meet the qualifications for exemption status with respect to the
requirement to post cash collateral in all hedging transactions, it is not possible at this
time to predict the final impact of any final regulations adopted.
 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 find reliable and economic markets for our gas production.
  We may be unable to develop our existing acreage due to the change in the political environment or
environmental and social pressures around natural resource development.
    21




---



##### Table of Contents



Our operations require substantial capital and we may be unable to fund our planned capital
expenditures.
  
    
    general economic and financial market conditions;
    
    our proved reserves;
    
    our ability to acquire, locate and produce new reserves;
    
    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 revised borrowing base, we may have 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 or additional properties to pledge as collateral;
 
    
    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; and
 
    
    additional financing in the future for working capital, capital expenditures,
acquisitions, general corporate or other purposes may have higher costs and more
restrictive covenants.
  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.
    22




---



##### Table of Contents



The exploration, development and operation of oil and gas properties involve substantial risks that
may result in a total loss of investment.
  
    
    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 reserves and future net revenues may differ significantly from our estimates.
   23




---



##### Table of Contents



Acquisitions are a part of our business strategy and are subject to many risks and uncertainties.
    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.
  We are exposed to counterparty credit risk as a result of our receivables and hedging transactions.
      24




---



##### Table of Contents



We may be unable to find additional reserves, which would adversely impact our ability to sustain
production levels.
  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.
  Provisions in our corporate documents and Maryland law could delay or prevent a change of control
of Double Eagle, even if that change would be beneficial to our stockholders.
  Our industry experiences numerous operating hazards that could result in substantial losses.
    25




---



##### Table of Contents



Our prices, net income and cash flows may be impacted adversely by new taxes.
  Weak economic conditions could negatively impact our business.
  The trading volatility and price of our common stock may be affected by many factors.
  
    
    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 1B.
    
    UNRESOLVED STAFF COMMENTS
  
 ITEM 3.
    
    LEGAL PROCEEDINGS
   
 ITEM 4.
    
    RESERVED
  26




---



##### 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
    
    
    LowMarch 31, 2010
    
    $
    5.00
    
    
    
    4.01June 30, 2010
    
    
    5.53
    
    
    
    4.14September 30, 2010
    
    
    4.48
    
    
    
    3.90December 31, 2010
    
    $
    5.45
    
    
    $
    4.14March 31, 2009
    
    
    11.23
    
    
    
    3.00June 30, 2009
    
    
    6.49
    
    
    
    3.62September 30, 2009
    
    
    5.40
    
    
    
    3.75December 31, 2009
    
    $
    6.02
    
    
    $
    4.04
  Holders
 Dividends
  Issuer Purchases of Equity Securities
  Total Number of Shares
    
    
    Maximum Number ofPurchased as Part of
    
    
    Shares that May Yet BeTotal Number of Shares
    
    
    Average Price Paid per
    
    
    Publically Announced
    
    
    Purchased Under thePeriod
    
    Purchased
    
    
    Share
    
    
    Plans or Programs
    
    
    Plans or ProgramsOctober 2010
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    November 2010
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    December 2010
    
    
    2,025
    (1)
    
    $
    4.93
    
    
    
    
    
    
    
    
 (1)
    
    None of the shares were repurchased as part of publicly announced plans or programs. All
such purchases were from employees for settlement of payroll taxes due at the time of
restricted stock vesting. All repurchased shares were subsequently retired.  27




---



##### Table of Contents



ITEM 6.
    
    SELECTED FINANCIAL DATA
  Year Ended December 31,2010
    
    
    2009
    
    
    2008
    
    
    2007
    
    
    2006(In thousands, except per share and volume data)Statement of Operations InformationTotal operating revenues
    
    $
    54,984
    
    
    $
    44,791
    
    
    $
    49,578
    
    
    $
    17,197
    
    
    $
    19,032Income (loss) from operations
    
    $
    10,265
    
    
    $
    3,884
    
    
    $
    15,949
    
    
    $
    (17,909
    )
    
    $
    3,695Net income (loss)
    
    $
    5,503
    
    
    $
    1,209
    
    
    $
    10,381
    
    
    $
    (11,603
    )
    
    $
    2,109Net income (loss) attributable to common stock
    
    $
    1,780
    
    
    $
    (2,514
    )
    
    $
    6,658
    
    
    $
    (13,413
    )
    
    $
    2,109Net income (loss) per common share:Basic
    
    $
    0.16
    
    
    $
    (0.25
    )
    
    $
    0.73
    
    
    $
    (1.47
    )
    
    $
    0.24Diluted
    
    $
    0.16
    
    
    $
    (0.25
    )
    
    $
    0.73
    
    
    $
    (1.47
    )
    
    $
    0.24Balance Sheet InformationTotal assets
    
    $
    152,517
    
    
    $
    150,494
    
    
    $
    171,989
    
    
    $
    84,597
    
    
    $
    64,406Balance on credit facility
    
    $
    32,000
    
    
    $
    34,000
    
    
    $
    24,639
    
    
    $
    3,445
    
    
    $
    13,221Total long-term liabilities
    
    $
    61,840
    
    
    $
    44,684
    
    
    $
    33,011
    
    
    $
    5,895
    
    
    $
    17,184Stockholders equity and preferred stock
    
    $
    90,677
    
    
    $
    84,696
    
    
    $
    92,875
    
    
    $
    66,596
    
    
    $
    33,042Cash Flow InformationNet cash provided by (used in):Operating activities
    
    $
    25,044
    
    
    $
    22,062
    
    
    $
    22,904
    
    
    $
    5,166
    
    
    $
    10,951Investing activities
    
    $
    (21,858
    )
    
    $
    (21,461
    )
    
    $
    (40,778
    )
    
    $
    (42,056
    )
    
    $
    (22,241
    )Financing activities
    
    $
    (6,263
    )
    
    $
    5,081
    
    
    $
    17,749
    
    
    $
    36,404
    
    
    $
    10,470Total proved reserves(1)Oil (MBbl)
    
    
    381
    
    
    
    419
    
    
    
    420
    
    
    
    413
    
    
    
    360Gas (MMcf)
    
    
    112,769
    
    
    
    89,777
    
    
    
    86,331
    
    
    
    71,254
    
    
    
    48,497MMcfe
    
    
    115,056
    
    
    
    92,292
    
    
    
    88,852
    
    
    
    73,731
    
    
    
    50,657Net production volumesOil (Bbl)
    
    
    26,024
    
    
    
    28,927
    
    
    
    25,668
    
    
    
    13,963
    
    
    
    12,729Gas (Mcf)
    
    
    9,002,873
    
    
    
    9,162,362
    
    
    
    6,559,662
    
    
    
    2,928,335
    
    
    
    3,140,653Mcfe
    
    
    9,159,017
    
    
    
    9,335,924
    
    
    
    6,713,670
    
    
    
    3,012,113
    
    
    
    3,217,027
 (1)
    
    Effective December 31, 2009, we adopted the SECs new oil and gas reserve reporting
rules. These rules applied to our 2009 and 2010 reserve estimates.  28




---



##### Table of Contents



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 and analysis should be read in conjunction with the Selected Financial
Data and the accompanying consolidated financial statements and related notes included elsewhere
in this Annual Report on Form 10-K. The following discussion contains forward-looking statements
that reflect our future plans, estimates, beliefs and expected performance. The forward-looking
statements are dependent upon events, risks and uncertainties that may be outside our control. See
Cautionary Information About Forward-Looking Statements.
 BUSINESS OVERVIEW
    Reserves Part 1 and 2: Business and Properties
  Developments since December 31, 2009
   29




---



##### Table of Contents




    
    In July 2010, we completed a purchase of additional working interests in the Atlantic
Rim for a total cost of $8.4 million. The transaction was effective January 1, 2010 and
we paid cash of approximately $7.9 million, net of revenue, expense and capital costs
incurred from the effective date through the closing date. The purchase increased our
working interest in the existing development units as follows:
 Working Interest AfterUnit
    
    Working Interest Acquired
    
    
    Purchase (1)Catalina
    
    
    3.08
    %
    
    
    72.40
    %Sun Dog
    
    
    12.57
    %
    
    
    21.46
    %Doty Mountain
    
    
    1.15
    %
    
    
    18.00
    %
 (1)
    
    Our working interest in the Unit will continue to change as additional wells are
drilled and acreage is added to the Units participating area. 
    
    At our company-operated Catalina Unit, we continued to perform well workover and
production enhancement projects on our existing wells. The production enhancement program
focused on existing wells that had experienced production declines over the past two
years.
 
    
    At the Sun Dog Unit, the
operator completed well workovers, including stimulation, of
approximately 15 wells and is in process of adding additional water injection capacity. Management does
not believe we have realized the full benefit of the fracture stimulation in the Sun Dog
Unit due to the insufficient water injection capacity.
 
    
    At the Doty Mountain Unit, the operator added additional compressor capacity in the
first quarter of 2010, which has led to a monthly production increase as of December 31,
2010 of approximately 65% in the Unit. In addition, the operator completed well
workovers, including fracture stimulation of 20 wells in 2010.
 
    
    In the Mesa B Participating Area at the Pinedale Anticline, 16 new wells
were brought on-line during 2010. We are also currently participating in the drilling of
approximately 17 additional wells. These wells were drilled in the fall of 2010, and are
expected to be completed in 2011.
   Our Industry:
   30




---



##### Table of Contents




    
    We have an inventory of what we believe are 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.
 
    
    We attempt to reduce our overall exposure to commodity price fluctuations through the
use of various hedging instruments for some of our production. Our strategic objective is
to hedge at least 50% of our anticipated production on a forward 12 to 24 month basis. 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. Refer to Contracted Volumeson page 41 for the
derivative instruments we had in place as of December 31, 2010.
 
    
    We have acquired additional
acreage in the Niobrara Shale formation in Wyoming and
Nebraska to provide for future exploration potential.
 
    
    We proactively work with state and federal regulatory agencies to facilitate
communication and necessary approvals.
 Development and Exploration Outlook for 2011:
  Atlantic Rim.
 Pinedale Anticline.
    31




---



##### Table of Contents



RESULTS OF OPERATIONS
  As of and for the year ended December 31,
    
    
    Percent change between years2010
    
    
    2009
    
    
    2008
    
    
    2009 to 2010
    
    
    2008 to 2009Total proved reservesOil (MBbl)
    
    
    381
    
    
    
    419
    
    
    
    420
    
    
    
    -9
    %
    
    
    0
    %Gas (MMcf)
    
    
    112,769
    
    
    
    89,777
    
    
    
    86,331
    
    
    
    26
    %
    
    
    4
    %MMcfe
    
    
    115,056
    
    
    
    92,292
    
    
    
    88,852
    
    
    
    25
    %
    
    
    4
    %Net production volumesOil (Bbl)
    
    
    26,024
    
    
    
    28,927
    
    
    
    25,668
    
    
    
    -10
    %
    
    
    13
    %Gas (Mcf)
    
    
    9,002,873
    
    
    
    9,162,362
    
    
    
    6,559,662
    
    
    
    -2
    %
    
    
    40
    %Mcfe
    
    
    9,159,017
    
    
    
    9,335,924
    
    
    
    6,713,670
    
    
    
    -2
    %
    
    
    39
    %Average daily producitonMcfe
    
    
    25,093
    
    
    
    25,578
    
    
    
    18,343
    
    
    
    -2
    %
    
    
    39
    %Average price per unit productionOil (Bbl)
    
    $
    70.35
    
    
    $
    51.65
    
    
    $
    77.24
    
    
    
    36
    %
    
    
    -33
    %Gas (Mcf)
    
    $
    4.12
    
    
    $
    4.85
    
    
    $
    6.08
    
    
    
    -15
    %
    
    
    -20
    %Mcfe
    
    $
    4.25
    
    
    $
    4.92
    
    
    $
    6.23
    
    
    
    -14
    %
    
    
    -21
    %Oil and gas production revenuesOil revenues
    
    $
    1,831
    
    
    $
    1,494
    
    
    $
    1,983
    
    
    
    23
    %
    
    
    -25
    %Gas revenues
    
    
    31,779
    
    
    
    40,904
    
    
    
    37,166
    
    
    
    -22
    %
    
    
    10
    %Total
    
    $
    33,610
    
    
    $
    42,398
    
    
    $
    39,149
    
    
    
    -21
    %
    
    
    8
    %Oil and gas production costsProduction costs
    
    $
    9,708
    
    
    $
    7,754
    
    
    $
    7,007
    
    
    
    25
    %
    
    
    11
    %Production taxes
    
    
    4,563
    
    
    
    3,652
    
    
    
    4,701
    
    
    
    25
    %
    
    
    -22
    %Total
    
    $
    14,271
    
    
    $
    11,406
    
    
    $
    11,708
    
    
    
    25
    %
    
    
    -3
    %Data on a per Mcfe basisAverage price (1)
    
    $
    4.25
    
    
    $
    4.92
    
    
    $
    6.23
    
    
    
    -14
    %
    
    
    -21
    %Production costs (2)
    
    
    1.06
    
    
    
    0.83
    
    
    
    1.04
    
    
    
    28
    %
    
    
    -20
    %Production taxes
    
    
    0.50
    
    
    
    0.39
    
    
    
    0.70
    
    
    
    28
    %
    
    
    -44
    %Depletion and amortization
    
    
    1.98
    
    
    
    1.94
    
    
    
    1.65
    
    
    
    2
    %
    
    
    18
    %Total operating costs
    
    
    3.54
    
    
    
    3.16
    
    
    
    3.39
    
    
    
    12
    %
    
    
    -7
    %Gross margin
    
    $
    0.71
    
    
    $
    1.76
    
    
    $
    2.84
    
    
    
    -60
    %
    
    
    -38
    %Gross margin percentage
    
    
    17
    %
    
    
    36
    %
    
    
    46
    %
    
    
    -53
    %
    
    
    -22
    %
 (1)
    
    Our average gas price per Mcfe realized for the years ended December 31, 2010, 2009 and 2008
is calculated by summing (a) production revenue received from third parties for sale of our
gas, included in oil and gas sales 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 price risk management activities on the consolidated statement of operations,
totaling $5,316, $3,503, and $2,698 for the years ended December 31, 2010, 2009, and 2008,
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 our subsidiary, Eastern
Washakie Midstream, which are eliminated in consolidation. Year ended December 31, 2010 compared to the year ended December 31, 2009
 Oil and gas sales, production volume and price comparisons
 Price Risk Management
  32




---



##### Table of Contents




    
    Average daily net production at the Catalina Unit decreased 9% to 14,705 Mcfe for the
year ended December 31, 2010, as compared to 16,154 Mcfe during 2009. The decrease is
largely the result of what management believes to be the normal production decline for
wells within this field. In addition, the decrease is a result of the continuation of our
well-enhancement program, which began in the third quarter of 2009 and continued throughout
2010. This program requires individual wells to be off-line for periods of time while the
well is worked-over. Finally, the Catalina field also experienced several power outages
during the second quarter of 2010 and the Southern Star pipeline was shut down for
maintenance for several days in April 2010, both of which temporarily halted production.
These decreases were partially offset by the increase in our working interest to 72.40%
from 69.31%, which resulted from our working interest purchase from a third-party in July
2010.
 
    
    Average daily net production at the Sun Dog and Doty Mountain Units increased 74% for
the year ended December 31, 2010 to 3,731 Mcfe per day from 2,140 Mcfe per day in the prior
year, largely due to our higher working interest in both units. We purchased additional
working interests in the Sun Dog and Doty Mountain Units during the third quarter of 2010,
increasing our working interest in the Sun Dog Unit to 21.46% from 8.89% prior to the
purchase, and the Doty Mountain Unit to 18.00% from 16.5% prior to the purchase. Also, the
operator added additional compressor capacity at the Doty Mountain Unit in the first
quarter of 2010, which boosted production.
   Transportation and gathering revenue
   33




---



##### Table of Contents



Price risk management
  Proceeds from Madden Deep settlement
  Oil and gas production expenses, production taxes, and depreciation, depletion and amortization
    Pipeline operating costs
  Impairment and abandonment of equipment and properties
   34




---



##### Table of Contents



General and administrative
  Income taxes
  Year ended December 31, 2009 compared to the year ended December 31, 2008
 Oil and gas sales volume and price comparisons
      35




---



##### 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
   36




---



##### Table of Contents



Income taxes
  LIQUIDITY AND CAPITAL RESOURCES
   Our Credit Facility at December 31, 2010
      37




---



##### Table of Contents



Capital Expenditures
  Year Ended December 31,2010
    
    
    2009Property acquisition costs
    
    $
    1,043
    
    
    $
    16Exploration
    
    
    73
    
    
    
    59Development
    
    
    20,402
    
    
    
    21,042Total capital expenditures
    
    $
    21,518
    
    
    $
    21,117
 Year Ended December 31, 2010
    Year Ended December 31, 2009
      Calendar 2011 Capital Spending Budget
   38




---



##### Table of Contents



Cash Flows
  As of and for the Years Ended December 31,
    
    
    Percent Change Between Years2010
    
    
    2009
    
    
    2008
    
    
    2009 to 2010
    
    
    2008 to 2009Financial informationWorking capital
    
    $
    7,477
    
    
    $
    (4,067
    )
    
    $
    (6,314
    )
    
    
    284
    %
    
    
    36
    %Balance oustanding on credit facility
    
    $
    32,000
    
    
    $
    34,000
    
    
    $
    24,639
    
    
    
    -6
    %
    
    
    38
    %Stockholders equity and preferred stock
    
    $
    90,677
    
    
    $
    84,696
    
    
    $
    92,875
    
    
    
    7
    %
    
    
    -9
    %Net income (loss) attributable to common stock
    
    $
    1,780
    
    
    $
    (2,514
    )
    
    $
    6,658
    
    
    
    -171
    %
    
    
    -138
    %Net income (loss) per common share:Basic
    
    $
    0.16
    
    
    $
    (0.25
    )
    
    $
    0.73
    
    
    
    164
    %
    
    
    -134
    %Diluted
    
    $
    0.16
    
    
    $
    (0.25
    )
    
    $
    0.73
    
    
    
    164
    %
    
    
    -134
    %Net cash provided by
operating activities
    
    $
    25,044
    
    
    $
    22,062
    
    
    $
    22,904
    
    
    
    14
    %
    
    
    -4
    %Net cash used in
investing activities
    
    $
    (21,858
    )
    
    $
    (21,461
    )
    
    $
    (40,778
    )
    
    
    2
    %
    
    
    -47
    %Net cash (used in)/ provided by
financing activities
    
    $
    (6,263
    )
    
    $
    5,081
    
    
    $
    17,749
    
    
    
    -223
    %
    
    
    -71
    %
 Net cash provided by operating activities
  Contract Volumes
  Net cash used in investing activities
   39




---



##### Table of Contents



Net cash used in financing activities
  Contractual Obligations
  Less than
    
    
    1 - 3
    
    
    3 - 5
    
    
    More thanTotal
    
    
    one year
    
    
    Years
    
    
    Years
    
    
    5 YearsCredit facility (a)
    
    $
    32,000
    
    
    $
    
    
    
    $
    32,000
    
    
    $
    
    
    
    $
    Interest on credit facility (b)
    
    
    3,044
    
    
    
    1,460
    
    
    
    1,584
    
    
    
    
    
    
    
    Capital leases
    
    
    752
    
    
    
    752
    
    
    
    
    
    
    
    
    
    
    
    Operating leases
    
    
    6,631
    
    
    
    2,192
    
    
    
    4,217
    
    
    
    222
    
    
    
    Total contractual cash
commitments
    
    $
    42,427
    
    
    $
    4,404
    
    
    $
    37,801
    
    
    $
    222
    
    
    $
    
 (a)
    
    The amount listed reflects the balance outstanding as of December 31, 2010. Any balance
outstanding is due on January 31, 2013.(b)
    
    The interest rate assumed on the credit facility is 4.5% per annum, which is the rate
in effect at December 31, 2010. Off-Balance Sheet Arrangements
  CONTRACTED VOLUMES
 Derivative Instruments
   40




---



##### Table of Contents



RemainingContractual
    
    
    Daily
    
    
    
    
    
    
    PriceType of Contract
    
    Volume
    
    
    Production
    
    
    Term
    
    Price
    
    Index (1)Fixed Price Swap
    
    
    2,920,000
    
    
    
    8,000
    
    
    01/11-12/11
    
    $7.07
    
    CIGCostless Collar
    
    
    1,060,000
    
    
    
    5,000
    
    
    08/09-07/11
    
    $4.50 floor
    
    NYMEX$7.90 ceilingCostless Collar
    
    
    1,670,000
    
    
    
    5,000
    
    
    12/09-11/11
    
    $4.50 floor
    
    NYMEX$9.00 ceilingTotal
    
    
    5,650,000
 (1)
    
    CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month.
NYMEX refers to quoted prices on the New York Mercantile Exchange.  Daily
    
    
    
    
    
    
    PriceType of Contract
    
    Production
    
    
    Term
    
    Price
    
    IndexFixed Price Swap
    
    
    10,000
    
    
    01/12-12/12
    
    $5.05
    
    NYMEXFixed Price Swap
    
    
    6,000
    
    
    01/13-12/13
    
    $5.16
    
    NYMEXCostless Collar
    
    
    6,000
    
    
    01/13-12/13
    
    $5.00 floor
    
    NYMEX$5.35 ceiling
   Other Volumes Contracted
  CRITICAL ACCOUNTING POLICIES AND ESTIMATES
   41




---



##### Table of Contents



Successful Efforts Method of Accounting
    Reserve Estimates
   42




---



##### Table of Contents



Impairment of Long-Lived Assets
  Asset Retirement Obligations
  Derivative Instruments
   Fair Value of Measurements
   Share-Based Compensation
   43




---



##### Table of Contents



Recently Adopted Accounting Pronouncements
  
 7A.
    
    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 Commodity Price Risks
   Interest Rate Risks
   44




---



##### Table of Contents



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
  Internal
Control-Integrated Framework
  Changes in Internal Control over Financial Reporting
   45




---



##### Table of Contents



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 Internal Control  Integrated
Framework Managements Report on Internal Control Over Financial Reporting
    Internal
Control  Integrated Framework
  HEIN & ASSOCIATES LLP
  46




---



##### 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, 2010, and is
incorporated by reference to this report
 
 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.
 (a)
    
    
    (b)
    
    
    (c)Number of securitiesremaining availableNumber of
    
    
    
    
    
    
    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
    
    
    556,339
    
    
    $
    12.94
    
    
    
    2,167,451
    (1)Equity Compensation plans
not approved by security holders
    
    
    
    
    
    
    
    
    
    
    
 (1)
    
    Represents 58,000 shares available for issuance under the 2002 Stock Option Plan; 111,157
shares available for issuance under the 2003 Stock Option and Compensation Plan, 47,677 shares
available for issuance under the 2007 Stock Incentive Plan and 1,950,617 shares available under the
2010 Stock Incentive Plan. 
 ITEM 13.
    
    CERTAIN RELATIONSHIPS, RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
   47




---



##### Table of Contents



ITEM 14.
    
    PRINCIPAL ACCOUNTANT FEES AND SERVICES
  
 PART IV
 
 ITEM 15.
    
    EXHIBITS AND 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 filed 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 filed 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)
    
    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 filed 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 filed
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 filed
June 29, 2007).
  48




---



##### 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 filed August 28,
2007).3.2
    (a)
    
    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
filed 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-A126 filed 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 filed
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)
    
    Double Eagle Petroleum Co. 2007 Stock Incentive Plan, including the
Form of Incentive Stock Option Agreement and Form of Non-Qualified
Stock Option Agreement (incorporated by reference from Exhibits 10.1,
10.2 and 10.3 to the Companys Current Report on Form 8-K filed May
29, 2007).10.1
    (b)
    
    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 filed September 9, 2008).10.1
    (c)
    
    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 filed September 9, 2008).10.1
    (d)
    
    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 filed September 9,
2008).10.1
    (e)
    
    First Amendment to Amended and Restated Credit Agreement, dated August
6, 2010, between the Company and Bank of Oklahoma, N.A. et al
(incorporated herein by reference from the Companys Current Report on
Form 8-K filed on August 9, 2010).10.1
    (f)
    
    Double Eagle Petroleum Co. 2010 Stock Incentive Plan (incorporated by
reference from Exhibit 10.1 to the Companys Current Report on Form
S-8 filed July 23, 2010).10.1
    (g)
    
    Amended and restated credit agreement dated February 5, 2010, among
the Company and Bank of Oklahoma, N.A., and the other lenders named
therein (incorporated by reference from exhibit 10.1 of the Companys
Current Report on Form 8-K filed February 9, 2010).10.1
    (g)
    
    Amended and restated credit agreement dated February 5, 2010, among
the Company and Bank of Oklahoma, N.A., and the other lenders named
therein (incorporated by reference from exhibit 10.1 of the Companys
Current Report on Form 8-K filed February 9, 2010).10.1
    (f)
    
    Employment Agreement between the Company and Ashley Jenkins, dated
January 4, 2010 (incorporated by reference from Exhibit 10.1 of the
Companys Current Report of Form 8-K filed January 7, 2010).14.1
    
    
    Code of Business Conduct and Ethics (incorporated by reference from
exhibit 99.2 of the Companys Annual Report on Form 10-KSB filed for
the year ended December 31, 20040.21.1
    *
    
    Subsidiaries of registrant.
  49




---



##### Table of Contents



Exhibit No.
    
    Description23.1
    *
    
    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 February 9, 2011.
 
 *
    
    Filed with this Form 10-K.  50




---



##### Table of Contents



SIGNATURES
  DOUBLE EAGLE PETROLEUM CO.Date:  March 8, 2011
    /s/ Richard DoleRichard DoleChief Executive Officer  Date:March 8, 2011
    /s/ Richard DolePrincipal Executive OfficerChief Executive OfficerDate:March 8, 2011
    /s/ Kurtis S. HooleyChief Financial OfficerPrincipal Accounting OfficerDate:   March 8, 2011
    /s/ Sigmund BalabanSigmund Balaban, DirectorDate:   March 8, 2011
    /s/ Roy G. CoheeRoy G. Cohee, DirectorDate:   March 8, 2011
    /s/ Brent HathawayBrent Hathaway, DirectorDate:   March 8, 2011
    /s/ David W. WilsonDavid W. Wilson, Director  51




---



##### Table of Contents



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




---



##### Table of Contents



(Amounts in thousands of dollars except share and per share data)
 December 31,
    
    
    December 31,2010
    
    
    2009ASSETSCurrent assets:Cash and cash equivalents
    
    $
    2,605
    
    
    $
    5,682Cash held in escrow
    
    
    615
    
    
    
    611Accounts receivable, net
    
    
    5,396
    
    
    
    6,772Assets from price risk management
    
    
    9,622
    
    
    
    Other current assets
    
    
    3,653
    
    
    
    3,982Total current assets
    
    
    21,891
    
    
    
    17,047Oil and gas properties and equipment, successful efforts method:Developed properties
    
    
    188,143
    
    
    
    165,279Wells in progress
    
    
    4,039
    
    
    
    7,544Gas transportation pipeline
    
    
    5,465
    
    
    
    5,465Undeveloped properties
    
    
    3,062
    
    
    
    2,502Corporate and other assets
    
    
    1,982
    
    
    
    1,914202,691
    
    
    
    182,704Less accumulated depreciation, depletion and amortization
    
    
    (72,226
    )
    
    
    (53,682
    )Net properties and equipment
    
    
    130,465
    
    
    
    129,022Assets from price risk management
    
    
    
    
    
    
    3,566Other assets
    
    
    161
    
    
    
    859TOTAL ASSETS
    
    $
    152,517
    
    
    $
    150,494LIABILITIES, PREFERRED STOCK, AND STOCKHOLDERS EQUITYCurrent liabilities:Accounts payable
    
    $
    7,295
    
    
    $
    6,177Accrued expenses
    
    
    3,535
    
    
    
    6,918Liabilities from price risk management
    
    
    
    
    
    
    4,739Accrued production taxes
    
    
    2,757
    
    
    
    2,439Capital lease obligations, current portion
    
    
    545
    
    
    
    533Other current liabilities
    
    
    282
    
    
    
    308Total current liabilities
    
    
    14,414
    
    
    
    21,114Credit facility
    
    
    32,000
    
    
    
    34,000Asset retirement obligation
    
    
    5,848
    
    
    
    4,807Liabilities from price risk management
    
    
    
    
    
    
    430Deferred tax liability
    
    
    9,578
    
    
    
    4,620Capital lease obligations, long-term portion
    
    
    
    
    
    
    545Other long-term liabilities
    
    
    
    
    
    
    282Total liabilities
    
    
    61,840
    
    
    
    65,798Preferred stock, $0.10 par value; 10,000,000 shares authorized; 
1,610,000 shares issued and outstanding as of
December 31, 2010 and December 31, 2009
    
    
    37,972
    
    
    
    37,972Stockholders equity:Common stock, $0.10 par value; 50,000,000 shares authorized;
11,165,305 issued and 11,155,080 outstanding at December 31, 2010
and 11,090,725 issued and outstanding at December 31, 2009
    
    
    1,116
    
    
    
    1,109Additional paid-in capital
    
    
    44,583
    
    
    
    43,640Retained earnings (accumulated deficit)
    
    
    1,438
    
    
    
    (342
    )Accumulated other comprehensive income
    
    
    5,568
    
    
    
    2,317Total stockholders equity
    
    
    52,705
    
    
    
    46,724TOTAL LIABILITIES, PREFERRED STOCK AND STOCKHOLDERS EQUITY
    
    $
    152,517
    
    
    $
    150,494
   F-2




---



##### Table of Contents



(Amounts in thousands of dollars except share and per share data)
 Year ended December 31,2010
    
    
    2009
    
    
    2008RevenuesOil and gas sales
    
    $
    33,610
    
    
    $
    42,398
    
    
    $
    39,149Transportation and gathering revenue
    
    
    5,549
    
    
    
    6,179
    
    
    
    4,788Price risk management activities
    
    
    11,512
    
    
    
    (4,295
    )
    
    
    5,329Proceeds from Madden Deep settlement
    
    
    3,841
    
    
    
    
    
    
    
    Other income
    
    
    472
    
    
    
    509
    
    
    
    312Total revenues
    
    
    54,984
    
    
    
    44,791
    
    
    
    49,578Costs and expensesProduction costs
    
    
    9,708
    
    
    
    7,754
    
    
    
    7,007Production taxes
    
    
    4,563
    
    
    
    3,652
    
    
    
    4,701Exploration expenses including dry hole costs
    
    
    163
    
    
    
    103
    
    
    
    911Pipeline operating costs
    
    
    4,152
    
    
    
    3,701
    
    
    
    3,190Impairment and abandonment of equipment
and properties
    
    
    1,583
    
    
    
    417
    
    
    
    743General and administrative
    
    
    5,976
    
    
    
    6,718
    
    
    
    5,604Depreciation, depletion and amortization
    
    
    18,574
    
    
    
    18,562
    
    
    
    11,473Total costs and expenses
    
    
    44,719
    
    
    
    40,907
    
    
    
    33,629Income from operations
    
    
    10,265
    
    
    
    3,884
    
    
    
    15,949Interest expense, net
    
    
    (1,538
    )
    
    
    (1,773
    )
    
    
    (225
    )Income before income taxes
    
    
    8,727
    
    
    
    2,111
    
    
    
    15,724Provision for deferred income taxes
    
    
    (3,224
    )
    
    
    (902
    )
    
    
    (5,343
    )NET INCOME
    
    $
    5,503
    
    
    $
    1,209
    
    
    $
    10,381Preferred stock dividends
    
    
    (3,723
    )
    
    
    (3,723
    )
    
    
    (3,723
    )Net income (loss) attributable to common stock
    
    $
    1,780
    
    
    $
    (2,514
    )
    
    $
    6,658Net income (loss) per common share:Basic
    
    $
    0.16
    
    
    $
    (0.25
    )
    
    $
    0.73Diluted
    
    $
    0.16
    
    
    $
    (0.25
    )
    
    $
    0.73Weighted average shares outstanding:Basic
    
    
    11,123,131
    
    
    
    9,955,582
    
    
    
    9,159,865Diluted
    
    
    11,123,131
    
    
    
    9,955,582
    
    
    
    9,161,985
   F-3




---



##### Table of Contents



(Amounts in thousands of dollars)
 Year ended December 31,2010
    
    
    2009
    
    
    2008Cash flows from operating activities:Net income (loss)
    
    $
    5,503
    
    
    $
    1,209
    
    
    $
    10,381Adjustments to reconcile net income (loss) to net cash
provided by operating activities:Depreciation, depletion, amortization and accretion of
asset retirement obligation
    
    
    18,714
    
    
    
    18,693
    
    
    
    11,648Abandonment of non-producing properties and leases
    
    
    480
    
    
    
    417
    
    
    
    743Non-cash gain on transfer of ARO to a third party
    
    
    (164
    )
    
    
    
    
    
    
    Settlement of asset retirement obligation
    
    
    
    
    
    
    (266
    )
    
    
    Non cash revenue from carried interest
    
    
    (2,123
    )
    
    
    (2,044
    )
    
    
    (1,665
    )Impairment of equipment and properties
    
    
    1,103
    
    
    
    
    
    
    
    Provision for deferred taxes
    
    
    3,181
    
    
    
    902
    
    
    
    5,343Directors fees paid in stock
    
    
    196
    
    
    
    177
    
    
    
    128Non-cash loss (gain) on derivative contracts
    
    
    (6,196
    )
    
    
    7,798
    
    
    
    (2,631
    )Non-cash employee stock option expense
    
    
    760
    
    
    
    1,307
    
    
    
    1,050Gain on sale of working interest in non-producing property
    
    
    (290
    )
    
    
    (283
    )
    
    
    (90
    )Changes in current assets and liabilities:Decrease (Increase) in deposit held in escrow
    
    
    (4
    )
    
    
    (6
    )
    
    
    114Decrease (Increase) in accounts receivable
    
    
    2,049
    
    
    
    13,884
    
    
    
    (17,522
    )Decrease (Increase) in other current assets
    
    
    (179
    )
    
    
    (150
    )
    
    
    (2,871
    )Increase (Decrease) in accounts payable
    
    
    80
    
    
    
    (14,544
    )
    
    
    15,461Increase (Decrease) in accrued expenses
    
    
    2,845
    
    
    
    (4,454
    )
    
    
    47Increase (Decrease) in accrued production taxes
    
    
    (911
    )
    
    
    (578
    )
    
    
    2,768`NET CASH PROVIDED BY OPERATING ACTIVITIES
    
    
    25,044
    
    
    
    22,062
    
    
    
    22,904Cash flows from investing activities:Additions of producing properties and equipment
    
    
    (12,861
    )
    
    
    (28,542
    )
    
    
    (44,378
    )Additions of corporate and non-producing properties
    
    
    (1,135
    )
    
    
    (139
    )
    
    
    (878
    )Proceeds from sales of properties and assets
    
    
    6
    
    
    
    
    
    
    
    4,478Net cash received from Petrosearch acquisition
    
    
    
    
    
    
    7,733
    
    
    
    Purchase of additional Atlantic Rim working interest
    
    
    (7,868
    )
    
    
    
    
    
    
    Payment of Petrosearch transaction costs
    
    
    
    
    
    
    (513
    )
    
    
    NET CASH USED IN INVESTING ACTIVITIES
    
    
    (21,858
    )
    
    
    (21,461
    )
    
    
    (40,778
    )Cash flows from financing activities:Dividends paid on preferred stock
    
    
    (3,723
    )
    
    
    (3,723
    )
    
    
    (3,723
    )Net borrowings/(payments) on line of credit
    
    
    (2,000
    )
    
    
    9,361
    
    
    
    21,194Proceeds from Company stock plans
    
    
    
    
    
    
    
    
    
    
    278Principal payments on capital lease obligations
    
    
    (533
    )
    
    
    (522
    )
    
    
    Tax withholdings related to net share settlement
of restricted stock awards
    
    
    (14
    )
    
    
    (39
    )
    
    
    Issuance of stock under Company stock plans
    
    
    7
    
    
    
    4
    
    
    
    NET CASH (USED IN) /PROVIDED BY FINANCING ACTIVITIES
    
    
    (6,263
    )
    
    
    5,081
    
    
    
    17,749Change in cash and cash equivalents
    
    
    (3,077
    )
    
    
    5,682
    
    
    
    (125
    )Cash and cash equivalents at beginning of period
    
    
    5,682
    
    
    
    
    
    
    
    125CASH AND CASH EQUIVALENTS AT END OF PERIOD
    
    $
    2,605
    
    
    $
    5,682
    
    
    $
    Supplemental disclosure of cash and non-cash transactions:Cash paid for interest
    
    $
    1,894
    
    
    $
    2,151
    
    
    $
    657Interest capitalized
    
    $
    192
    
    
    $
    485
    
    
    $
    705Cash paid for income taxes
    
    $
    44
    
    
    $
    
    
    
    $
    Receivables due from joint-interest partners related to change in working
interest
    
    $
    
    
    
    $
    
    
    
    $
    193Share-based compensation expense
    
    $
    956
    
    
    $
    1,484
    
    
    $
    1,178Additions to developed properties included in current liabilities
    
    $
    4,685
    
    
    $
    10,245
    
    
    $
    20,299Additions to developed properties for retirement obligations
    
    $
    1,063
    
    
    $
    94
    
    
    $
    2,584Issuance 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




---



##### 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, 2008
    
    
    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
    
    
    
    54,903Comprehensive 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-5




---



##### 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, 2009
    
    
    11,090,725
    
    
    $
    1,109
    
    
    $
    43,640
    
    
    $
    (342
    )
    
    $
    2,317
    
    
    $
    46,724Comprehensive lossNet income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5,503
    
    
    
    
    
    
    
    5,503Net change in derivative
instrument fair value, net
of tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3,251
    
    
    
    3,251Total comprehensive
income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    8,754Share-based compensation
expense, exclusive of amounts
withheld for payroll taxes
    
    
    18,700
    
    
    
    2
    
    
    
    752
    
    
    
    
    
    
    
    
    
    
    
    754Directors fees paid in stock
    
    
    45,655
    
    
    
    5
    
    
    
    191
    
    
    
    
    
    
    
    
    
    
    
    196Dividends declared & paid
on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (3,723
    )
    
    
    
    
    
    
    (3,723
    )Balance at
December 31, 2010
    
    
    11,155,080
    
    
    $
    1,116
    
    
    $
    44,583
    
    
    $
    1,438
    
    
    $
    5,568
    
    
    $
    52,705
   F-6




---



##### 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 Policies
 Description of Operations
  Principles of Consolidation and Basis of Presentation
    Cash and Cash Equivalents
  Cash Held in Escrow
  Accounts Receivable
  Use of Estimates in the Preparation of Financial Statements
  Concentration of Credit Risk
   F-7




---



##### Table of Contents



Revenue Recognition and Gas Balancing
  Oil and Gas Producing Activities
      (amounts in thousands).
 2010
    
    
    2009
    
    
    2008Beginning balance at January 1,
    
    $
    
    
    
    $
    
    
    
    $
    692Additions to capitalized exploratory well costs pending
the determination of proved reserves
    
    
    
    
    
    
    
    
    
    
    Reclassifications to wells, facilities and equipment
based on the determination of proved reserves
    
    
    
    
    
    
    
    
    
    
    (692
    )Capitalized exploratory well costs charged to expense
    
    
    
    
    
    
    
    
    
    
    Ending balance at December 31,
    
    $
    
    
    
    $
    
    
    
    $
    
  F-8




---



##### Table of Contents



Asset Retirement Obligations
    For the year ended December 31,2010
    
    
    2009Beginning asset retirement obligation
    
    $
    4,807
    
    
    $
    4,208Additional liabilites assumed through
acquisition of Petrosearch
    
    
    
    
    
    
    640Liabilities incurred
    
    
    24
    
    
    
    4Liabilities settled
    
    
    (164
    )
    
    
    (266
    )Accretion expense
    
    
    142
    
    
    
    131Changes in ownership interest
    
    
    1,041
    
    
    
    213Revision to estimated cash flows
    
    
    (2
    )
    
    
    (123
    )Ending asset retirement obligation
    
    $
    5,848
    
    
    $
    4,807
 Impairment of Long-Lived Assets
     F-9




---



##### Table of Contents



Corporate and Other Assets
  Major Customers
  Industry Segment and Geographic Information
  Employee Benefit Plan
  Income Taxes
  Earnings Per Share
   F-10




---



##### Table of Contents



The following table shows the calculation of basic and diluted weighted average shares
outstanding and EPS for the periods indicated:
 For the year ended December 31,2010
    
    
    2009
    
    
    2008Net income (loss)
    
    $
    5,503
    
    
    $
    1,209
    
    
    $
    10,381Preferred stock dividends
    
    
    (3,723
    )
    
    
    (3,723
    )
    
    
    (3,723
    )Income (loss) attributable to common stock
    
    $
    1,780
    
    
    $
    (2,514
    )
    
    $
    6,658Weighted average shares:Weighted average shares  basic
    
    
    11,123,131
    
    
    
    9,955,582
    
    
    
    9,159,865Dilutive effect of stock options outstanding
at the end of period
    
    
    
    
    
    
    
    
    
    
    2,120Weighted average shares  fully diluted
    
    
    11,123,131
    
    
    
    9,955,582
    
    
    
    9,161,985Earnings (loss) per share:Basic
    
    $
    0.16
    
    
    $
    (0.25
    )
    
    $
    0.73Diluted
    
    $
    0.16
    
    
    $
    (0.25
    )
    
    $
    0.73
 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 31,2010
    
    
    2009
    
    
    2008Potential common shares
    
    
    68,647
    
    
    
    84,177
    
    
    
    56,249
 Stock Based Compensation
  Shareholder Rights Plan
     F-11




---



##### Table of Contents



Fair Value of Financial Instruments
  Derivative Financial Instruments
  Other Comprehensive Income
   Recently Adopted Accounting Pronouncements
  2.
    
    Line of Credit
 At December 31, 2010, the Company had a $75 million revolving line of credit in place with $55
million available for borrowing based on several factors, including the 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, 2010, the balance outstanding on the credit facility of $32,000 has been used
to fund the past three years of development of the Catalina Unit and other non-operated projects
in the Atlantic Rim, as well as projects in the Pinedale Anticline.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, 2010, the interest rate on the line of credit was 4.5%.
For the years ended December 31, 2010, 2009 and 2008, the Company incurred interest expense on
the credit facility of $1,510, $1,778, and $705, respectively. Of the total interest incurred,
the Company capitalized interest costs of $192, $485 and $705 for the years ended December 31,
2010, 2009 and 2008, respectively.
  F-12




---



##### Table of Contents



3.
    
    Purchase of Additional Atlantic Rim Working Interests
  Working Interest AfterUnit
    
    Working Interest Acquired
    
    
    Purchase (1)Catalina
    
    
    3.08
    %
    
    
    72.40
    %Sun Dog
    
    
    12.57
    %
    
    
    21.46
    %Doty Mountain
    
    
    1.15
    %
    
    
    18.00
    %
 (1)
    
    The Companys working interest in the Unit will continue to change as additional wells
are drilled and acreage is added to the Units participating area. The effective date of the
transaction was January 1, 2010. The total cost of the purchase was $8,417. The total cash paid by the Company was $7,868, net of revenue,
expense and capital costs incurred from the effective date through the closing date.
 The Company recorded an
additional asset retirement obligation in conjunction with the purchase, totaling $1,041.
 4.
    
    Acquisition of Petrosearch
 On August 6, 2009, the Company acquired 100% of the common and preferred shares of Petrosearch
in exchange for approximately 1.8 million shares of the Companys 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 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.
Petrosearch was an independent crude oil and natural gas exploration and production company,
with properties in Texas and Oklahoma. The Companys results of operations include the effect
of the Petrosearch acquisition from the closing date.
 The aggregate purchase price was calculated as follows:
 Aggregrate value of Double Eagle common stock issued
    
    $
    7,260Cash consideration given to Petrosearch shareholders
    
    
    873Purchase Price
    
    $
    8,133
  F-13




---



##### Table of Contents



The acquisition of Petrosearch was 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 purchase price was allocated
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 was 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 was not deductible for tax
purposes.
 Transaction costs related to the merger totaled $513, and were recorded on the consolidated
statement of pperations within general and administrative expenses in the 2009 period.
 5.
    
    Income Taxes
 The provision for income taxes consists of:
 For the year ended December 31,2010
    
    
    2009
    
    
    2008Current taxes
    
    $
    
    
    
    $
    
    
    
    $
    Deferred taxes
    
    
    3,224
    
    
    
    902
    
    
    
    5,343Total income tax expense
    
    $
    3,224
    
    
    $
    902
    
    
    $
    5,343
 The tax effects of temporary differences that gave rise to the deferred tax liabilities and
deferred tax assets as of December 31, 2010 and 2009 were:
 As of December 31,2010
    
    
    2009Deferred tax assets:Net operating loss carry-forward
    
    $
    11,607
    
    
    $
    11,597Asset retirement obligation
    
    
    2,059
    
    
    
    1,683Share-based compensation
    
    
    458
    
    
    
    315Accrued compensation
    
    
    22
    
    
    
    17Derivative instruments
    
    
    
    
    
    
    560Net gas imbalance
    
    
    146
    
    
    
    53Other
    
    
    43
    
    
    
    614,335
    
    
    
    14,231Deferred tax liabilities:Derivative instruments
    
    
    (3,389
    )
    
    
    Net basis difference in oil and gas properties
    
    
    (20,524
    )
    
    
    (18,852
    )Net deferred tax liability
    
    $
    (9,578
    )
    
    $
    (4,621
    )
  F-14




---



##### Table of Contents



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.
 At December 31, 2010, the Company had a net operating loss carry forward for regular income tax
reporting purposes of approximately $32.7 million, which will begin expiring in 2021.
 The following table shows the reconciliation of the Companys effective tax rate to the expected
federal tax rate for the years ended December 31, 2010 and 2009:
 For the year ended December 31,2010
    
    
    2009Expected federal tax rate
    
    
    35.00
    %
    
    
    35.00
    %Effect of permanent differences
    
    
    1.40
    %
    
    
    16.52
    %State tax rate
    
    
    0.22
    %
    
    
    0.02
    %Other
    
    
    0.33
    %
    
    
    -8.84
    %Effective tax rate
    
    
    36.95
    %
    
    
    42.70
    %
 ASC 740 guidance requires that the Company evaluate all monetary tax positions taken, and
recognize a liability for any uncertain tax 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, 2010 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 2007 and for state and local tax authorities for
years before 2006.
 6.
    
    Commitments and Contingencies
 Derivative Instruments
 To 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 outstanding at December 31, 2010 are summarized as follows (volume and daily
production are expressed in Mcf):
 RemainingContractual
    
    
    Daily
    
    
    
    
    
    
    
    
    
    
    PriceType of Contract
    
    Volume
    
    
    Production
    
    
    Term
    
    
    Price
    
    
    Index (1)Fixed Price Swap
    
    
    2,920,000
    
    
    
    8,000
    
    
    
    01/11-12/11
    
    
    $7.07
    
    
    
    CIGCostless Collar
    
    
    1,060,000
    
    
    
    5,000
    
    
    
    08/09-07/11
    
    
    $4.50 floor
    
    NYMEX$7.90 ceilingCostless Collar
    
    
    1,670,000
    
    
    
    5,000
    
    
    
    12/09-11/11
    
    
    $4.50 floor
    
    NYMEX$9.00 ceilingTotal
    
    
    5,650,000
 (1)
    
    CIG refers to the Colorado Interstate Gas price as quoted on the first day of each
month. NYMEX refers to quoted prices on the New York Mercantile Exchange. In January 2011, the Company entered into three additional derivative contracts. Refer to
Notes 7, 8 and 11 for additional information regarding the Companys derivative contracts.
  F-15




---



##### Table of Contents



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,
2010 and 2009, totaled $1,600, and is included in the developed properties line on the balance
sheet. Related accumulated depreciation was approximately $1,067 and $533 at December 31, 2010
and 2009, respectively. The amortization of the capital lease balance is recorded within DD&A
expense on the consolidated statement of operations.
 Future minimum lease payments under noncancelable capital leases at December 31, 2010 are as
follows:
 LeaseYear ending December 31,
    
    Commitments2011
    
    $
    752Less: Executory costs
    
    
    200Less: Amounts representing interest
    
    
    20Present value of minimum lease payments
    
    $
    532
 Operating Lease Commitments
 The Company has entered into an operating lease through August 2015 for approximately 7,470
square feet of office space in Denver, Colorado. 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,
    
    Commitments2011
    
    
    2,1922012
    
    
    2,6832013
    
    
    1,5342014
    
    
    1312015 and thereafter
    
    
    91Total
    
    $
    6,631
 Total expense from operating leases totaled $1,935, $2,575 and $419 in 2010, 2009, and 2008,
respectively.
 Litigation and Contingencies
 From time to time, the Company is involved in various legal proceedings, including the matters
discussed below. These proceedings are subject to the uncertainties inherent in any litigation.
The Company is defending itself vigorously in all such matters, and while the ultimate outcome
and impact of any proceeding cannot be predicted with certainty, management believes that the
resolution of any proceeding will not have a material adverse effect on the Companys financial
condition or results of operations.
 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 that own working
interests fin the Madden Deep Unit. The Company and the other plaintiffs in the case asserted
that, under the gas balancing agreement, they were entitled to receive either monetary damages or
their respective shares of the natural gas produced from the Madden Deep Unit over at least the
period February 1, 2002 through June 30,
2007. In the third quarter of 2010, the Company signed a settlement agreement with many of the
defendants in the lawsuit, in which the Company received cash proceeds of approximately $4,061.
Prior to the settlement, the Company had not recognized any amount of sales proceeds for the
period February 1, 2002 through October 30, 2006. For the period from November 1, 2006 through
June 30, 2007, the Company had recognized the sales and had recorded a related account receivable
of $292, net of allowance for uncollectible amounts. As such, the Company recorded $3,841 within
proceeds from Madden Deep Unit settlement on the consolidated statements of operations for the
year ended December 31, 2010. 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 has continued to receive its respective share on an on-going basis.
  F-16




---



##### Table of Contents



On December 18, 2009, Tiberius Capital, LLC (Plaintiff), a stockholder of Petrosearch prior to
the Companys acquisition (the Acquisition) of Petrosearch pursuant to a merger between
Petrosearch and a wholly-owned subsidiary of the Company, filed a claim in the U.S. District
Court of New York against Petrosearch, the Company, and the individuals who were officers and
directors of Petrosearch prior to the Acquisition. In general, the claims against the Company
and Petrosearch are that Petrosearch inappropriately denied dissenters rights of appraisal under
the Nevada Revised Statutes to its stockholders in connection with the Acquisition, that the
defendants violated various sections of the Securities Act of 1933 and the Securities Exchange
Act of 1934, and that the defendants caused other damages to the stockholders of Petrosearch.
The Plaintiff is seeking monetary damages. The Company does not believe the case has merit, and
is defending this case vigorously. There has been no judgments or decisions to date on this
litigation.
 7.
    
    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 contracts, costless collars and
swaps, to manage the price risk associated with its 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 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 its consolidated balance sheets, and accounts for the derivative instruments as either cash
flow hedges or mark to market derivative instruments. On the statements of cash flow, 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
creditworthy. 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. The Company was in an overall asset position with each
of its counterparties at December 31, 2010, and no party in any of its derivative contracts has
required any form of security guarantee.
 Cash flow hedges
 Derivative instruments that are designated and qualify as cash flow hedges are recorded at fair
value on the consolidated balance sheets 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.
  F-17




---



##### Table of Contents



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 consolidated balance sheets and changes in fair value are
recognized in the price risk management activities line on the consolidated statement of
operations. 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.
 The Company had 5,650 MMcf hedged under derivative contracts as of December 31, 2010. Refer to
Note 6 for a detailed breakout of the contracts.
 The table below contains a summary of all the Companys derivative positions reported on the
consolidated balance sheet as of December 31, 2010, 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 - current
    
    $
    8,594Total
    
    
    
    $
    8,594
 Derivatives not designated ashedging instruments under ASC 815
    
    Balance Sheet Location
    
    Fair ValueAssetsCommodity derivatives
    
    Assets from price risk management - current
    
    $
    1,028Total
    
    
    
    $
    1,028
 The before-tax effect of derivative instruments in cash flow hedging relationships on the
consolidated statement of operations for the year ended December 31, 2010 was as follows:
 Derivatives Designated as Cash Flow Hedging Instruments under ASC 815
 Amount of Gain (Loss) Recognizedin OCI 1 on Derivatives for theYear Ended December 31,2010
    
    
    2009Commodity contracts
    
    $
    5,038
    
    
    $
    2,616
 Amount of Gain Reclassified fromLocation of Gain Reclassified
    
    Accumulated OCI into Income for thefrom Accumulated OCI 1
    
    Year Ended December 31,into Income (effective portion)
    
    2010
    
    
    2009Oil and gas sales
    
    $
    
    
    
    $
    15,740
 1
    
    Other comprehensive income (OCI). Year Ended December 31,2010
    
    
    2009Location of Gain Recognized in Income (Ineffective) Portion
and Amount Excluded from Effectiveness Testing
    
    
    N/A
    
    
    
    N/A
  F-18




---



##### Table of Contents



The before-tax effect of derivative instruments not designated as hedging instruments on the
consolidated statement of operations for the year ended December 31, 2010 was as follows:
 Amount of Loss Recognized in Incomeon Derivative for theLocation of Gain/Loss Recognized
    
    Year Ended December 31,in Income on Derivatives
    
    2010
    
    
    2009Price risk management activities
    
    $
    11,512
    
    
    $
    (4,295
    )
 Refer to Note 8 for additional information regarding the valuation of the Companys derivative
instruments, Note 6 for the listing of the current contracts the Company had in place as of
December 31, 2010 and Note 11 for information on the additional contracts the Company entered
into subsequent to December 31, 2010.
 8.
    
    Fair Value Measurements
 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 determines its estimate of the fair value of derivative instruments using a market
approach based on several factors, 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, 2010, 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.
  F-19




---



##### Table of Contents



Credit facility
 The recorded value of the Companys credit facility approximates fair value as it bears interest
at a floating rate.
 Impairment of Long-lived Assets
 The Company reviews the carrying values of its long-lived assets annually or whenever events or
changes in circumstances indicate that such carrying values may not be recoverable. 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
impairment analysis performed by the Company may utilize Level 3 inputs.
 In the fourth quarter of 2010, the Company completed a reevaluation of its non-producing Waltman
34-24 well, and determined that it does not have economically recoverable reserves. Management
plans to plug and abandon the well in 2011. Based on managements internal assumptions, the
carrying costs of this well were written down to $0, which approximates fair value, and resulted
in an impairment charge of $1,103, which is included in earnings in 2010.
 Asset Retirement Obligations
 The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic
410, Asset Retirement and Environmental Obligations. The income valuation technique is
utilized by the Company to determine the fair value of the liability at the point of inception
by taking into account 1) the cost of abandoning oil and gas wells, which is based on the
Companys historical experience for similar work, or estimates from independent third-parties;
2) the economic lives of its properties, which is based on estimates from reserve engineers; 3)
the inflation rate; and 4) the credit adjusted risk-free rate, which takes into account the
Companys credit risk and the time value of money. Given the unobservable nature of the inputs,
the initial measurement of the asset retirement obligation liability is deemed to use Level 3
inputs. There were no asset retirement obligations measured at fair value within the
consolidated balance sheet at December 31, 2010.
 The following table provides a summary of the fair values of assets and liabilities measured at
fair value at December 31, 2010:
 Level 1
    
    
    Level 2
    
    
    Level 3
    
    
    TotalAssetsDerivative instruments -
Commodity forward contracts
    
    $
    
    
    
    $
    9,622
    
    
    $
    
    
    
    $
    9,622Total assets at fair value
    
    $
    
    
    
    $
    9,622
    
    
    $
    
    
    
    $
    9,622
 The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or
Level 3 of the fair value measurement hierarchy during the year ended December 31, 2010.
 9.
    
    Series A Cumulative Preferred Stock
 In 2007, the stockholders of the Company amended the Companys
Articles of Incorporation to allow for the issuance of 10,000,000
shares of preferred stock, and the Company subsequently completed a
public offering of 1,610,000 shares of 9.25% Series A Cumulative
Preferred Stock at a price of $25.00 per share.
  F-20




---



##### Table of Contents



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 its 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 the Company 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, 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 the Company 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 the Companys Board of Directors in addition
to those directors then serving on the Board until such time as the national market listing is
obtained or the dividend arrearage is eliminated.
 10.
    
    Compensation Plans
 The Company 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 the Companys common 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,
2010, there were 58,000 and 111,157 options available for grant under the 2002 and 2003 Stock
Option Plans, respectively.
 The Companys stockholders have also approved the 2007 Stock Incentive Plan (2007 Plan) and
the 2010 Stock Incentive Plan, (2010 Plan) which allow 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 these plans. These awards vest annually over various periods of
up to five years of continuous service. As of December 31, 2010, there were 47,677 and
1,950,617 shares available for grant under the 2007 and 2010 Plans, respectively.
 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, 2010, 2009 and 2008, total
share-based compensation expense for equity-classified awards, was $956, $1,484, and $1,178,
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 the Companys common 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 31,2010
    
    
    2009
    
    
    2008Weighted-average volatility
    
    
    57-60%
    
    
    
    51%
    
    
    
    40-41%Expected dividends
    
    
    0.00%
    
    
    
    0.00%
    
    
    
    0.00%Expected term (in years)
    
    
    4-5
    
    
    
    5
    
    
    
    4-5Risk-free rate
    
    
    1.23%-2.65%
    
    
    
    1.72%
    
    
    
    2.42%-3%Expected forfeiture rate
    
    
    8-12%
    
    
    
    7.00%
    
    
    
    5%-7%
  F-21




---



##### Table of Contents



Summary of option activity during the year ended December 31, 2010:
 Weighted-Weighted-
    
    
    AverageAverage
    
    
    Remaining
    
    
    AggregateExercise
    
    
    Contractual
    
    
    IntrinsicOptions:
    
    Shares
    
    
    Price
    
    
    Term (in years)
    
    
    ValueOutstanding at January 1, 2010
    
    
    647,897
    
    
    $
    15.06
    
    
    
    4.7Granted
    
    
    97,880
    
    
    $
    4.52Exercised
    
    
    
    
    
    $
    Cancelled/expired
    
    
    (189,438
    )
    
    $
    15.83Outstanding at December 31, 2010
    
    
    556,339
    
    
    $
    12.94
    
    
    
    4.4
    
    
    $
    35Exercisable at December 31, 2010
    
    
    291,652
    
    
    $
    14.62
    
    
    
    3.5
    
    
    $
    5
 The weighted average grant date fair value price per share of options granted during the three
years ended December 31, 2010, 2009, and 2008 was $4.52, $7.79 and $14.91, respectively. No
options were exercised during 2010 or 2009. During the year ended December 31, 2008, 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. As of December 31, 2010, 2009 and 2008, the
intrinsic value of options vested and exercisable was $5, $0 and $0, respectively.
 Stock options outstanding and currently exercisable at December 31, 2010 were as follows:
 OptionsOutstanding
    
    
    
    
    
    
    Options ExercisableWeighted 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$4.30 - $7.79
    
    
    157,880
    
    
    
    6.6
    
    
    $
    5.68
    
    
    
    31,076
    
    
    $
    5.26$14.00- $16.60
    
    
    300,959
    
    
    
    4.3
    
    
    $
    14.76
    
    
    
    186,576
    
    
    $
    14.36$17.86 - $19.55
    
    
    77,500
    
    
    
    1.4
    
    
    $
    18.74
    
    
    
    58,000
    
    
    $
    18.86$20.21 - $23.61
    
    
    20,000
    
    
    
    1.4
    
    
    $
    20.43
    
    
    
    16,000
    
    
    $
    20.43556,339
    
    
    
    4.4
    
    
    $
    12.94
    
    
    
    291,652
    
    
    $
    14.62
 As of December 31, 2010, there was $895 of total unrecognized stock-based compensation
expense related to stock options to be recognized over a weighted-average period of 2.39 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
recognizes 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.
  F-22




---



##### Table of Contents



Nonvested stock awards as of December 31, 2010 and changes for the year ended December 31, 2010
were as follows:
 Weighted-AverageGrant DateShares
    
    
    Fair ValueStock Awards:Outstanding at January 1, 2010
    
    
    87,448
    
    
    $
    12.38Granted
    
    
    79,714
    
    
    $
    4.26Vested
    
    
    (66,617
    )
    
    $
    7.02Forfeited/returned
    
    
    (17,241
    )
    
    $
    14.78Nonvested at December 31, 2010
    
    
    83,304
    
    
    $
    8.40
 As of December 31, 2010, there was $633 of unrecognized stock-based compensation expense related
to nonvested stock awards. This cost is expected to be recognized over a weighted-average
period of 2.7 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,
2010, the Company had 8,660 warrants outstanding with an exercise price of $21.25 that expire in
December 2011. In February 2010, 14,691 warrants with an exercise price of $46.19 expired and
in November 2010 10,310 warrants with an exercise price of $34.64 expired. The warrants had no
intrinsic value at December 31, 2010.
 11.
    
    Subsequent Events
 In January 2011, the Company entered into the following new hedging agreements:
 Daily
    
    
    
    
    
    
    
    
    
    
    PriceType of Contract
    
    Production
    
    
    Term
    
    
    Price
    
    
    IndexFixed Price Swap
    
    
    10,000
    
    
    
    1/12-12/12
    
    
    $5.05
    
    
    
    NYMEXFixed Price Swap
    
    
    6,000
    
    
    
    1/13-12/13
    
    
    $5.16
    
    
    
    NYMEXCostless Collar
    
    
    6,000
    
    
    
    1/13-12/13
    
    
    $5.00 floor
    
    
    NYMEX$5.35 ceiling
 Effective March 7, 2011, the Company amended its credit facility to increase the borrowing
availability on the line of credit from $55 million to $60 million. Borrowings under the
revolving line of credit will bear interest at a daily rate equal to
either (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. The credit facility
will no longer have a 4.5% floor. Any balance outstanding on the facility matures on January
31, 2013.
 The Company has noted no additional events, other than noted above, that require recognition or
disclosure at December 31, 2010.
  F-23




---



##### Table of Contents



12.
    
    Supplemental Information on Oil and Gas Producing Activities
 Capitalized Costs Relating to Oil and Gas Producing Activities
 The 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, 2010, 2009, and 2008 are:
 As of December 31,2010
    
    
    2009
    
    
    2008Developed properties
    
    $
    188,143
    
    
    $
    165,279
    
    
    $
    133,516Wells in progress
    
    
    4,039
    
    
    
    7,544
    
    
    
    18,518Undeveloped properties
    
    
    3,062
    
    
    
    2,502
    
    
    
    2,907195,244
    
    
    
    175,325
    
    
    
    154,941Accumulated depletion
and amortization
    
    
    (70,200
    )
    
    
    (52,041
    )
    
    
    (33,905
    )Net capitalized costs
    
    $
    125,044
    
    
    $
    123,284
    
    
    $
    121,036
 Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities
 Costs incurred in property acquisitions, exploration, and development activities for the years
ended December 31, 2010, 2009 and 2008 were:
 For the year ended December 31,2010
    
    
    2009
    
    
    2008Property acquisitions  unproved
    
    $
    1,043
    
    
    $
    16
    
    
    $
    30Exploration
    
    
    73
    
    
    
    59
    
    
    
    536Development
    
    
    20,402
    
    
    
    21,466
    
    
    
    64,462Total
    
    $
    21,518
    
    
    $
    21,541
    
    
    $
    65,028
 Results of Operations from Oil and Gas Producing Activities
 The table below shows the results of operations for the Companys oil and gas producing
activities for the years ended December 31, 2010, 2009 and 2008. All production is from within
the continental United States.
 For the year ended December 31,2010
    
    
    2009
    
    
    2008Operating revenues (1)
    
    $
    38,926
    
    
    $
    45,901
    
    
    $
    41,847Costs and expenses:Production
    
    
    14,271
    
    
    
    11,406
    
    
    
    11,708Exploration
    
    
    163
    
    
    
    103
    
    
    
    911Depletion, amortization and impairment
    
    
    19,262
    
    
    
    18,136
    
    
    
    11,078Total costs and expenses
    
    
    33,696
    
    
    
    29,645
    
    
    
    23,697Income (loss) before income taxes
    
    
    5,230
    
    
    
    16,256
    
    
    
    18,150Income tax expense
    
    
    1,842
    
    
    
    5,693
    
    
    
    6,356Results of operations
    
    $
    3,388
    
    
    $
    10,563
    
    
    $
    11,794
 (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, 2010, 2009 and 2008, the settlements on
derivatives totaled $5,316, $3,503 and $2,698, respectively.  F-24




---



##### Table of Contents



Oil and Gas Reserves (Unaudited)
 The reserves at December 31, 2010, 2009 and 2008 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, 2010, 2009, and 2008 are:
 For the year ended December 31,2010
    
    
    2009
    
    
    2008Oil
    
    
    Gas
    
    
    Oil
    
    
    Gas
    
    
    Oil
    
    
    Gas(Bbl)
    
    
    (Mcf)
    
    
    (Bbl)
    
    
    (Mcf)
    
    
    (Bbl)
    
    
    (Mcf)Beginning of year
    
    
    419,213
    
    
    
    89,776,670
    
    
    
    420,189
    
    
    
    86,330,820
    
    
    
    412,812
    
    
    
    71,253,865Revisions of estimates
    
    
    (48,196
    )
    
    
    (66,921
    )
    
    
    (42,417
    )
    
    
    (9,323,380
    )
    
    
    (33,439
    )
    
    
    (4,637,562
    )Extensions and discoveries
    
    
    36,258
    
    
    
    16,744,470
    
    
    
    61,932
    
    
    
    21,931,592
    
    
    
    65,429
    
    
    
    26,244,840Purchases of reserves
    
    
    
    
    
    
    15,317,168
    
    
    
    8,436
    
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (26,024
    )
    
    
    (9,002,873
    )
    
    
    (28,927
    )
    
    
    (9,162,362
    )
    
    
    (24,613
    )
    
    
    (6,530,323
    )End of year
    
    
    381,251
    
    
    
    112,768,514
    
    
    
    419,213
    
    
    
    89,776,670
    
    
    
    420,189
    
    
    
    86,330,820Proved developed reserves
    
    
    235,808
    
    
    
    73,049,048
    
    
    
    287,276
    
    
    
    64,195,169
    
    
    
    295,698
    
    
    
    63,007,126Percentage of proved
developed reserves
    
    
    62
    %
    
    
    65
    %
    
    
    69
    %
    
    
    72
    %
    
    
    70
    %
    
    
    73
    %
 As of December 31, 2010, the Company had estimated proved reserves of 112.8 Bcf of natural
gas and 381 MBbl of oil, or a total of 115.1 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 Company
adopted this guidance effective December 31, 2009. 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.
 As of December 31, 2010, 88% of the proved developed gas reserves and 96% 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 years ended December 31, 2010 and 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, 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.
  F-25




---



##### Table of Contents



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 31,2010
    
    
    2009
    
    
    2008Future cash inflows
    
    $
    441,761
    
    
    $
    276,374
    
    
    $
    406,017Future production costs
    
    
    (153,980
    )
    
    
    (105,161
    )
    
    
    (118,299
    )Future development costs
    
    
    (34,218
    )
    
    
    (16,777
    )
    
    
    (18,275
    )Future income taxes
    
    
    (50,732
    )
    
    
    (14,279
    )
    
    
    (58,313
    )Future net cash flows
    
    
    202,831
    
    
    
    140,157
    
    
    
    211,13010% annual discount
    
    
    (87,887
    )
    
    
    (57,450
    )
    
    
    (89,075
    )Standardized measure of
discounted future net cash flows
    
    $
    114,944
    
    
    $
    82,707
    
    
    $
    122,055
 Principal changes in the Standardized Measure for the years ended December 31, 2010, 2009 and
2008:
 2010
    
    
    2009
    
    
    2008Standard measure, as of January 1,
    
    
    82,707
    
    
    $
    122,055
    
    
    $
    130,299Sales of oil and gas produced, net of production costs
    
    
    (19,339
    )
    
    
    (30,992
    )
    
    
    (26,846
    )Extensions and discoveries
    
    
    22,726
    
    
    
    22,506
    
    
    
    49,511Net change in prices and production costs related to future production
    
    
    42,308
    
    
    
    (62,838
    )
    
    
    (63,682
    )Development costs incurred during the year
    
    
    277
    
    
    
    13,043
    
    
    
    11,181Changes in estimated future development costs
    
    
    (15,446
    )
    
    
    (3,516
    )
    
    
    (5,188
    )Purchases of reserves in place
    
    
    20,566
    
    
    
    201
    
    
    
    Revisions of quantity estimates
    
    
    (1,592
    )
    
    
    (10,460
    )
    
    
    (9,119
    )Accretion of discount
    
    
    7,360
    
    
    
    13,257
    
    
    
    15,919Net change in income taxes
    
    
    (20,324
    )
    
    
    25,285
    
    
    
    18,576Changes in timing and other
    
    
    (4,299
    )
    
    
    (5,834
    )
    
    
    1,404Aggregate change
    
    
    32,237
    
    
    
    (39,348
    )
    
    
    (8,244
    )Standardized measure, as of December 31,
    
    
    114,944
    
    
    $
    82,707
    
    
    $
    122,055
 12.
    
    Quarterly Financial Data (Unaudited)
 Summary of the unaudited financial data for each quarter for the years ended December 31, 2010
and 2009 (in thousands except per share data):
 Fourth
    
    
    
    
    
    
    Second
    
    
    FirstQuarter
    
    
    Third Quarter
    
    
    Quarter
    
    
    QuarterYear ended December 31, 2010Oil and gas sales
    
    $
    7,352
    
    
    $
    7,601
    
    
    $
    7,608
    
    
    $
    11,049Income (loss) from operations
    
    $
    (3,520
    )
    
    $
    4,870
    
    
    $
    (1,016
    )
    
    $
    9,931Net income (loss)
    
    $
    (2,579
    )
    
    $
    2,862
    
    
    $
    (889
    )
    
    $
    6,109Net income (loss) attributable to common stock
    
    $
    (3,510
    )
    
    $
    1,932
    
    
    $
    (1,820
    )
    
    $
    5,178Basic net income (loss) per common share
    
    $
    (0.32
    )
    
    $
    0.17
    
    
    $
    (0.16
    )
    
    $
    0.47Diluted net income (loss) per common share
    
    $
    (0.32
    )
    
    $
    0.17
    
    
    $
    (0.16
    )
    
    $
    0.47Year ended December 31, 2009Oil and gas sales
    
    $
    11,737
    
    
    $
    9,669
    
    
    $
    10,492
    
    
    $
    10,500Income from operations
    
    $
    1,705
    
    
    $
    641
    
    
    $
    (352
    )
    
    $
    1,890Net income (loss)
    
    $
    28
    
    
    $
    416
    
    
    $
    (242
    )
    
    $
    1,007Net income attributable to common stock
    
    $
    (903
    )
    
    $
    (514
    )
    
    $
    (1,173
    )
    
    $
    76Basic net income (loss) per common share
    
    $
    (0.08
    )
    
    $
    (0.05
    )
    
    $
    (0.13
    )
    
    $
    0.01Diluted net income (loss) per common share
    
    $
    (0.08
    )
    
    $
    (0.05
    )
    
    $
    (0.13
    )
    
    $
    0.01
  F-26