##### 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, 2006
 o
    
    TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 Commission
File No. 0-6529
 DOUBLE EAGLE PETROLEUM CO.
  Maryland
    
    83-021469(State or other jurisdiction of incorporation or organization)
    
    (I.R.S. Employer Identification No.)
 777 Overland Trail (P.O. Box 766) Casper, Wyoming
    
    82601(Address of principal executive offices)
    
    (Zip Code)
 (Registrants telephone number, including area code)
  Title of each class
    
    Name of each exchange on which registeredNone
    
    None
  Title of each class
    
    Name of each exchange on which registered$.10 Par Value Common Stock
    
    NASDAQ Global Select Market
 o þ
 o þ
 þ o
 þ
  o þ o
 o þ
  .




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##### Table of Contents



PAGEForward-looking Statements
    
    
    3PART IItems 1. and 2. Business and Properties
    
    
    4General
    
    
    4Overview and Strategy
    
    
    4Operations
    
    
    5Other Recent Developments
    
    
    10Reserves
    
    
    11Production
    
    
    12Delivery Contracts
    
    
    12Productive Wells
    
    
    13Drilling Activity
    
    
    13Finding and Development Costs
    
    
    13Acreage
    
    
    14Marketing and Major Customers
    
    
    15Title to Properties
    
    
    16Seasonality
    
    
    16Competition
    
    
    16Government Regulations
    
    
    16Employees and Office Space
    
    
    17Available Information
    
    
    18Glossary
    
    
    18Item 1A. Risk Factors
    
    
    20Item 1B. Unresolved Staff Comments
    
    
    23Item 3. Legal Proceedings
    
    
    23Item 4. Submission of Matters to a Vote of Security Holders
    
    
    23PART IIItem 5. Market for Registrants Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities
    
    
    23Item 6. Selected Financial Data
    
    
    26Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations
    
    
    27Item 7A. Quantitative and Qualitative Disclosures about Market Risk
    
    
    39Item 8. Financial Statements and Supplementary Data
    
    
    40Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
    
    
    40Item 9A. Controls and Procedures
    
    
    41Item 9B. Other Information
    
    
    44PART IIIItem 10. Directors, Executive Officers and Corporate Governance
    
    
    44Item 11. Executive Compensation
    
    
    44Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
    
    
    44Item 13. Certain Relationships and Related Transactions
    
    
    44Item 14. Principal Accountant Fees and Services
    
    
    44PART IVItem 15. Exhibits and Financial Statement Schedules
    
    
    44SubsidiariesConsent of Hein & Associates LLPConsent of Netherland, Sewell & AssociatesCertification of CEO Pursuant to Section 302Certification of CFO Pursuant to Section 302Certification Pursuant to Section 906
 2




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FORWARD-LOOKING STATEMENTS
 This Annual Report on Form 10-K includes forward-looking statements as defined by the Securities
and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe
harbor protections provided under the Private Securities Litigation Reform Act of 1995. All
statements, other than statements of historical facts, included in this Form 10-K that address
activities, events or developments that we expect, believe or anticipate will or may occur in the
future are forward-looking statements. These forward-looking statements are based on assumptions
which we believe are reasonable based on current expectations and projections about future events
and industry conditions and trends affecting our business. However, whether actual results and
developments will conform to our expectations and predictions is subject to a number of risks and
uncertainties that, among other things, could cause actual results to differ materially from those
contained in the forward-looking statements, including without limitation the Risk Factors set
forth in this Form 10-K and the following:
 
    
    The cost and effects on our business of weather and other natural phenomena;
    
    General economic and political conditions, including governmental energy policies, tax
rates or policies and inflation rates;
    
    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 meet growth projections;
    
    Our ability to obtain, or a decline in, oil or gas productions;
    
    The issuance of drilling, environmental and other permits, by federal, state, and
tribal governments, or agencies thereof, may affect the volume of production from our
developed properties;
    
    Incorrect estimates of required capital expenditures;
    
    The amount and timing of capital deployment in new investment opportunities;
    
    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.
 New factors that could cause actual results to differ materially from those described in
forward-looking statements emerge from time to time, and it is not possible for us to predict all
such factors, or the extent to which any such factor or combination of factors may cause actual
results to differ from those contained in any forward-looking statement. We assume no obligation to
update publicly any such forward -looking statements, whether as a result of new information,
future events, or otherwise.
 3




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##### Table of Contents



PART I
 
 ITEMS 1. AND 2. BUSINESS AND PROPERTIES
 
 General
   http://www.dble.us
 
 Overview and Strategy
  
    
    economically growing reserves and production through the development of our existing properties;
    
    selectively pursuing high potential exploration projects where we have accumulated
detailed geological knowledge; and
    
    selectively pursuing strategic acquisitions that may expand or complement our existing
operations.
     4




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Operations
   Basin
    
    Gross Acres
    
    Net AcresGreater Green River Basin
    
    
    199,831
    
    
    
    71,968Hanna Basin
    
    
    24,947
    
    
    
    6,181Huntington Basin
    
    
    166,806
    
    
    
    164,571Powder River Basin
    
    
    44,104
    
    
    
    5,687Wind River Basin
    
    
    50,986
    
    
    
    2,365Other
    
    
    69,715
    
    
    
    2,190Total
    
    
    556,389
    
    
    
    252,962
  The Atlantic Rim Coal Bed Natural Gas Project in south central Wyoming
     5




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Cow Creek Field
    Doty Mountain Unit
 ,
  Sun Dog Unit
  6




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Other Units
    Cow Creek Deep
   South Fillmore
   The Pinedale Anticline in the Green River Basin of Wyoming
  7




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The Wind River Basin in central Wyoming
  Madden Anticline
  8




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Madden Field and Long Butte Field
  South Sand Draw
  The Moxa Arch in southwest Wyoming
  The Christmas Meadows Prospect in Utah
     9




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Nevada
  Rattlesnake Prospect
  Eastern Washakie Midstream Pipeline LLC
  
 Other Recent Developments
    10




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Reserves
  Oil and gas reserve estimates:
 As of December 31,2006
    
    
    2005
    
    
    2004Proved developed oil reserves (Bbls)
    
    
    254,346
    
    
    
    199,931
    
    
    
    181,397Proved undeveloped oil reserves (Bbls)
    
    
    105,819
    
    
    
    128,821
    
    
    
    96,658Total proved oil reserves (Bbls)
    
    
    360,165
    
    
    
    328,752
    
    
    
    278,055Proved developed gas reserves (Mcf)
    
    
    30,075,467
    
    
    
    23,032,277
    
    
    
    17,161,577Proved undeveloped gas reserves (Mcf)
    
    
    18,421,252
    
    
    
    24,202,058
    
    
    
    17,773,169Total proved gas reserves (Mcf)
    
    
    48,496,719
    
    
    
    47,234,335
    
    
    
    34,934,746Total proved gas equivalents (Mcfe) (1)
    
    
    50,657,709
    
    
    
    49,206,847
    
    
    
    36,603,076Present value of estimated future net
cash flows before income taxes,
discounted at 10% (2)
    
    $
    67,639
    
    
    $
    126,776
    
    
    $
    68,605Reconciliation of non-GAAP financial measure:PV-10
    
    $
    67,639
    
    
    $
    126,776
    
    
    $
    68,605Less: Undiscounted income taxes
    
    
    (42,578
    )
    
    
    (74,738
    )
    
    
    (32,972
    )Plus: 10% discount factor
    
    
    24,972
    
    
    
    39,255
    
    
    
    15,897Discounted income taxes
    
    
    17,606
    
    
    
    35,483
    
    
    
    17,075Standardized measure of discounted future
net cash flows
    
    $
    50,033
    
    
    $
    91,293
    
    
    $
    51,530
 
 (1)
    
    Oil is converted to Mcf of gas equivalent at one barrel per six Mcf.(2)
    
    The present value of estimated future net cash flows as of each date shown was calculated
using oil and gas prices being received by each respective property as of that date. The
average prices utilized for December 31, 2006, 2005, and 2004, respectively, were $4.46 per
Mcf and $57.75 per barrel of oil; $7.72 per Mcf and $57.75 per barrel of oil; and $5.51 per
Mcf and $40.04 per barrel of oil.  11




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Production
  For the Year Ended December 31,2006
    
    2005
    
    2004Quantities:Oil (Bbls)
    
    
    12,729
    
    
    
    15,470
    
    
    
    16,886Gas (MMcf)
    
    
    3,141
    
    
    
    2,976
    
    
    
    2,560Average sales price:Oil ($/Bbl)
    
    
    57.90
    
    
    
    49.26
    
    
    
    37.61Gas($/Mcf)
    
    
    5.57
    
    
    
    6.62
    
    
    
    4.85Average Production Cost ($/Mcfe)
    
    
    1.11
    
    
    
    1.24
    
    
    
    0.81Average Production Tax ($/Mcfe)
    
    
    0.69
    
    
    
    0.82
    
    
    
    0.62
 
 Delivery Contracts
  RemainingContractual
    
    Daily
    
    
    
    
    
    FixedProperty
    
    Volume
    
    Production
    
    Term
    
    Price/McfCow Creek
    
    
    90,000
    
    
    
    1,000
    
    
    
    07/06 - 03/07
    
    
    $
    5.4290,000
    
    
    
    1,000
    
    
    
    07/06 - 03/07
    
    
    $
    6.28181,000
    
    
    
    1,000
    
    
    
    07/06 - 06/07
    
    
    $
    5.94181,000
    
    
    
    1,000
    
    
    
    07/06 - 06/07
    
    
    $
    6.32304,000
    
    
    
    1,000
    
    
    
    11/06 - 10/07
    
    
    $
    5.84Company Total
    
    
    846,000
  12




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Productive Wells
  Oil
    
    GasState
    
    Gross
    
    Net
    
    Gross
    
    NetColorado
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    0.0590Mississippi
    
    
    2
    
    
    
    0.0009
    
    
    
    
    
    
    
    Montana
    
    
    2
    
    
    
    0.0960
    
    
    
    
    
    
    
    North Dakota
    
    
    23
    
    
    
    0.2965
    
    
    
    
    
    
    
    Oklahoma
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    0.0065Utah
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    0.0200Wyoming
    
    
    86
    
    
    
    5.9940
    
    
    
    604
    
    
    
    33.1914Total
    
    
    113
    
    
    
    6.3874
    
    
    
    609
    
    
    
    33.2769
 
 Drilling Activity
  For the Year Ended December 31,2006
    
    2005
    
    2004Gross
    
    Net
    
    Gross
    
    Net
    
    Gross
    
    NetExploratoryOil
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    Gas
    
    
    2
    
    
    
    1.26
    
    
    
    25
    
    
    
    0.62
    
    
    
    38
    
    
    
    6.61Dry Holes
    
    
    1
    
    
    
    0.33
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Water Injection
    
    
    
    
    
    
    
    
    
    
    3
    
    
    
    2.02
    
    
    
    2
    
    
    
    0.52Other
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3
    
    
    
    1.59
    
    
    
    28
    
    
    
    2.64
    
    
    
    41
    
    
    
    7.13DevelopmentOil
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    0.03Gas
    
    
    87
    
    
    
    7.32
    
    
    
    75
    
    
    
    1.13
    
    
    
    64
    
    
    
    2.78Dry Holes
    
    
    1
    
    
    
    0.21
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Water Injection
    
    
    4
    
    
    
    0.82
    
    
    
    
    
    
    
    
    
    
    
    4
    
    
    
    1.14Other
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    0.0592
    
    
    
    8.35
    
    
    
    75
    
    
    
    1.13
    
    
    
    70
    
    
    
    4.00Total
    
    
    95
    
    
    
    9.94
    
    
    
    103
    
    
    
    3.77
    
    
    
    111
    
    
    
    11.13
  
 Finding and Development Costs
  13




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As of December 31,2006
    
    2005
    
    2004Proved developed (MMcfe)
    
    
    11,863
    
    
    
    9,051
    
    
    
    3,900Proved undeveloped (MMcfe)
    
    
    (1,468
    )
    
    
    6,622
    
    
    
    11,411Total proved reserves added
    
    
    10,395
    
    
    
    15,673
    
    
    
    15,311
  .
 
 Acreage
  14




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Developed Acres (1)
    
    Undeveloped Acres (2)
    
    Total AcresState
    
    Gross
    
    Net
    
    Gross
    
    Net
    
    Gross
    
    NetColorado
    
    
    
    
    
    
    
    
    
    
    80
    
    
    
    80
    
    
    
    80
    
    
    
    80Montana
    
    
    29
    
    
    
    1
    
    
    
    1,892
    
    
    
    1,135
    
    
    
    1,921
    
    
    
    1,136North Dakota
    
    
    2,240
    
    
    
    49
    
    
    
    2,560
    
    
    
    64
    
    
    
    4,800
    
    
    
    113Utah
    
    
    637
    
    
    
    16
    
    
    
    46,440
    
    
    
    26,447
    
    
    
    47,077
    
    
    
    26,463Wyoming
    
    
    106,282
    
    
    
    5,042
    
    
    
    126,237
    
    
    
    53,076
    
    
    
    232,519
    
    
    
    58,118Nevada
    
    
    
    
    
    
    
    
    
    
    166,806
    
    
    
    164,571
    
    
    
    166,806
    
    
    
    164,571Total
    
    
    109,188
    
    
    
    5,108
    
    
    
    344,015
    
    
    
    245,373
    
    
    
    453,203
    
    
    
    250,481
  Developed Acres (1)
    
    Undeveloped Acres (2)
    
    Total AcresState
    
    Gross
    
    Net
    
    Gross
    
    Net
    
    Gross
    
    NetColorado
    
    
    155
    
    
    
    5
    
    
    
    1,920
    
    
    
    320
    
    
    
    2,075
    
    
    
    325Mississippi
    
    
    160
    
    
    
    1
    
    
    
    
    
    
    
    
    
    
    
    160
    
    
    
    1Montana
    
    
    611
    
    
    
    15
    
    
    
    
    
    
    
    
    
    
    
    611
    
    
    
    15North Dakota
    
    
    1,523
    
    
    
    40
    
    
    
    5,313
    
    
    
    243
    
    
    
    6,836
    
    
    
    283Oklahoma
    
    
    640
    
    
    
    2
    
    
    
    
    
    
    
    
    
    
    
    640
    
    
    
    2Utah
    
    
    
    
    
    
    
    
    
    
    51,311
    
    
    
    51
    
    
    
    51,311
    
    
    
    51Wyoming
    
    
    10,464
    
    
    
    162
    
    
    
    31,089
    
    
    
    1,642
    
    
    
    41,553
    
    
    
    1,804Total
    
    
    13,553
    
    
    
    225
    
    
    
    89,633
    
    
    
    2,256
    
    
    
    103,186
    
    
    
    2,481
 
 (1)
    
    Developed acreage is acreage assigned to producing wells for the spacing unit of the
producing formation. Developed acreage in certain of the Companys properties that include
multiple formations with different well spacing requirements may be considered undeveloped for
certain formations, but have only been included as developed acreage in the presentation
above.(2)
    
    Undeveloped acreage is lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities of oil and gas
regardless of whether such acreage contains proved reserves.   Expiring AcreageFiscal Year
    
    Gross
    
    Net2007
    
    
    15,669
    
    
    
    11,4982008
    
    
    2,612
    
    
    
    2,6122009 and later
    
    
    538,108
    
    
    
    238,852Total
    
    
    556,389
    
    
    
    252,962
 
 Marketing and Major Customers
  15




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Title to Properties
  
 Seasonality
   
 Competition
  
 Government Regulations
 Regulation of Production, Sales and Transportation of Natural Gas and Oil
  16




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Environmental Laws and Regulations
   
 Employees and Office Space
  17




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Available Information
 http://www.dble.us/
 
 http://www.dble.us/
 
 Glossary
  3-D seismic or 3-D data.
 Bbl.
 Bcf.
 Bcfe.
 Boe.
 Darcy.
 Dip meter.
 Development well.
 Dry hole
 Estimated net proved reserves.
 Exploratory well.
 Field.
 Gross acre.
 Gross well.
 18




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MBbl.
 Mcf.
 Mcfe
 Millidarcy.
 MMcf.
 MMcfe.
 MMBtu.
 Net acres or net wells.
 Permeability.
 Productive well.
 Proved developed reserves.
 Proved reserves.
 Proved undeveloped reserves.
 PV-10 value.
 Recompletion.
 Royalty.
 Royalty interest.
 Undeveloped acreage.
 19




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Velocity.
 Working interest
 
 ITEM 1A. RISK FACTORS
  We cannot predict the future price of oil and natural gas and an extended decline in prices could
hurt our business prospects.
  We could be adversely impacted by a variety of changes in the oil and gas market which are beyond
our control.
  We may be unable to find additional reserves, which would adversely impact our revenues.
  We may be unable to fund our planned capital expenditures.
  
    
    general economic and financial market conditions;
    
    oil and natural gas prices; and
    
    our market value and operating performance.
  20




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Our industry experiences numerous operating hazards that could result in substantial losses.
   New government regulation and environmental risks could increase our cost of doing business.
  
    
    prevention of waste;
    
    discharge of materials into the environment;
    
    conservation of oil and natural gas, pollution, permits for drilling operations,
drilling bonds, reports concerning operations;
    
    spacing of wells; and
    
    unitization and pooling of properties.
  Our prices may be impacted adversely by new taxes.
  Our reserves and future net revenues may differ significantly from our estimates.
  Acquisitions are a part of our business strategy and are subject to the risks and uncertainties of
evaluating recoverable reserves and potential liabilities.
  21




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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.
  We do not control all of our operations and development projects.
   
    
    timing and amount of capital expenditures;
    
    expertise and financial resources;
    
    inclusion of other participants in drilling wells; and
    
    use of technology.
  Competition in the oil and natural gas industry is intense, and many of our competitors have
greater financial and other resources than we do.
  
    
    seeking to acquire desirable producing properties or new leases for future exploration; and
    
    seeking to acquire the equipment and expertise necessary to develop and operate our properties.
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We depend on key personnel.
  There is limited liquidity in our shares.
  
 ITEM 1B. UNRESOLVED STAFF COMMENTS
  
 ITEM 3. LEGAL PROCEEDINGS
  
 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
  
 PART II
 
 ITEM 5. MARKET FOR REGRISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURTIES.
 Market Information.
 23




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Quarter Ended
    
    High
    
    LowDecember 31, 2006
    
    $
    29.50
    
    
    $
    18.05September 30, 2006
    
    
    20.52
    
    
    
    15.89June 30, 2006
    
    
    19.40
    
    
    
    14.04March 31, 2006
    
    
    20.68
    
    
    
    15.00December 31, 2005
    
    $
    24.75
    
    
    $
    17.50September 30, 2005
    
    
    25.10
    
    
    
    17.15June 30, 2005
    
    
    22.75
    
    
    
    15.69March 31, 2005
    
    
    21.99
    
    
    
    15.53December 31, 2004
    
    $
    20.43
    
    
    $
    14.48September 30, 2004
    
    
    18.36
    
    
    
    13.60June 30, 2004
    
    
    15.45
    
    
    
    12.20March 31, 2004
    
    
    16.60
    
    
    
    11.53
  Holders
 Dividends
 Equity Compensation Plans.
 (c)Number of securities(a)
    
    
    (b)
    
    
    remaining availableSecurities to
    
    
    Weighted-
    
    
    for future issuancebe issued
    
    
    average
    
    
    under equityupon exercise
    
    
    exercise
    
    
    compensation plansof
    
    
    price of
    
    
    (excluding securitiesoutstanding
    
    
    outstanding
    
    
    reflected in columnPlan category
    
    options
    
    
    options
    
    
    (a))Equity Compensation plans
approved by security
holders
    
    
    325,500
    
    
    $
    17.64
    
    
    
    212,614
    (1)
 
 (1)
    
    Represents no shares available for issuance under the 1996 Stock Option Plan, no shares
available for issuance under the 2000 Stock Option Plan, 101,471 shares available for issuance
under the 2002 Stock Option Plan and 111,143 shares available for issuance under the 2003 Stock
Option and Compensation Plan. Recent Sales of Unregistered Securities.
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Performance Graph
 Comparison of Five-Year Cumulative Total Return Among
Double Eagle Petroleum Co., the NASDAQ U.S. Index and the Peer Group Index
Total Return (Stock Price Plus Reinvested Dividends)
 
   25




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##### Table of Contents



ITEM 6. SELECTED FINANCIAL DATA
  Year endedYear Ended December 31,
    
    August 31,2006
    
    2005
    
    2004
    
    2003
    
    2002
    (1)(In thousands, except per share and volume data)Statement of Operations
InformationTotal operating revenues
    
    $
    19,032
    
    
    $
    20,496
    
    
    $
    13,267
    
    
    $
    6,138
    
    
    $
    2,270Income (loss) from operations
    
    $
    3,695
    
    
    $
    5,985
    
    
    $
    4,451
    
    
    $
    1,136
    
    
    $
    (2,823
    )Net income (loss)
    
    $
    2,109
    
    
    $
    3,965
    
    
    $
    4,028
    
    
    $
    972
    
    
    $
    (2,847
    )Net income (loss) per common
share:Basic
    
    $
    0.24
    
    
    $
    0.46
    
    
    $
    0.48
    
    
    $
    0.14
    
    
    $
    (0.47
    )Fully diluted
    
    $
    0.24
    
    
    $
    0.46
    
    
    $
    0.47
    
    
    $
    0.14
    
    
    $
    (0.47
    )Balance Sheet InformationTotal assets
    
    $
    64,406
    
    
    $
    44,211
    
    
    $
    30,969
    
    
    $
    23,955
    
    
    $
    9,765Line of credit
    
    $
    13,221
    
    
    $
    3,000
    
    
    $
    
    
    
    $
    
    
    
    $
    Total long-term liabilities
    
    $
    17,184
    
    
    $
    5,732
    
    
    $
    583
    
    
    $
    359
    
    
    $
    2,250Stockholders equity
    
    $
    33,042
    
    
    $
    29,778
    
    
    $
    24,927
    
    
    $
    19,856
    
    
    $
    6,377Cash Flow InformationNet cash provided by (used in):Operating activities
    
    $
    10,951
    
    
    $
    10,319
    
    
    $
    7,434
    
    
    $
    3,239
    
    
    $
    119Investing activities
    
    $
    (22,241
    )
    
    $
    (16,259
    )
    
    $
    (7,377
    )
    
    $
    (8,769
    )
    
    $
    (5,034
    )Financing activities
    
    $
    10,470
    
    
    $
    3,701
    
    
    $
    692
    
    
    $
    8,318
    
    
    $
    4,923Total proved reservesOil (MBbl)
    
    
    360
    
    
    
    329
    
    
    
    278
    
    
    
    209
    
    
    
    183Gas (MMcf)
    
    
    48,497
    
    
    
    47,234
    
    
    
    34,935
    
    
    
    22,819
    
    
    
    11,502MMcfe
    
    
    50,657
    
    
    
    49,207
    
    
    
    36,603
    
    
    
    24,073
    
    
    
    12,600Net production volumesOil (Bbl)
    
    
    12,729
    
    
    
    15,470
    
    
    
    16,886
    
    
    
    17,344
    
    
    
    20,566Gas (Mcf)
    
    
    3,140,653
    
    
    
    2,976,094
    
    
    
    2,559,557
    
    
    
    1,320,850
    
    
    
    1,009,543Mcfe
    
    
    3,217,027
    
    
    
    3,068,914
    
    
    
    2,660,873
    
    
    
    1,424,914
    
    
    
    1,132,939
 
 (1)
    
    Beginning in 2003, we changed our fiscal year-end from August 31 to December 31.  26




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##### 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 includes forward-looking statements. Such statements are described in the
section entitled Forward-Looking Statements immediately preceding Part 1, Items 1and 2, of this
Form 10-K.
 BUSINESS OVERVIEW
    Developments since December 31, 2005:
   
    
    At the Atlantic Rim, we participated in the drilling of 27 wells at the Doty Mountain
Unit (of which 22 producing wells are expected to be completed in 2007), with both Doty
Mountain and Sun Dog Units (as well as our Cow Creek Unit) awaiting the Record of Decision
on the Environmental Impact Study (EIS), which will allow the operators to resume
drilling new wells. For further information regarding the EIS, see continued discussion
within this section below. Double Eagle has 20.55% and 4.545% (changing to 8.3% as 2007 wells
are completed  see additional comments below) working interest in the Doty Mountain and
Sun Dog Units, respectively. We began receiving and selling our share of Doty Mountain
production in July 2006. We expect to begin making up our production imbalances
(currently in an under-produced position) for Doty Mountain and Sun Dog Units in early
2007. See Item 15, Note 1 to the Notes to the Consolidated Financial Statements for
additional discussion of production imbalances.
    
    We began drilling the Cow Creek Unit Deep #2 development well on June 1, 2006, with an
expected total depth of 12,360 feet. Double Eagle has an 84% interest in this well. We
drilled to 9,922 feet, ran casing to that point and are reworking the seismic data with
the additional well data compiled. The well bore appears to have gas
zones above a depth of 5,500
feet. However, the beds below 5,500 feet were not at the highest
point in the structure. If possible, we would like to be able to use this well to directionally drill to
the high point in the field for the deep beds. The reworking of the seismic should assist
us in attempting to spot the top of the deep anticline. We expect to have a rig back on
this well in the first six months of 2007.
    
    At the Pinedale Anticline, we participated in the drilling of 14 wells before winter
grazing stipulations halted activity on November 15, 2006. Seven of the 14 wells have been
put on line and are producing natural gas. The operator has represented to us that it
intends to hook up the additional seven new wells as early as regulations will allow in
2007.
    
    On the Moxa Arch, we were involved in 31 development gas wells with working interests
ranging from 0.27% to 16.27%.
 27




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##### Table of Contents




    
    At Christmas Meadows, we started the drilling of the Table Top Unit #1 well on September
8, 2006 at 235 feet, at the base of the conductor pipe that was set in the summer of 2005.
This prospect has been on hold since 1982 due to regulatory hurdles, because it is near the
High Uinta Mountain Wilderness Area. First, Amoco, then Chevron, and now Double Eagle have
fought these regulatory hurdles to be able to drill this well. We began drilling this
wildcat well, originally expected to be drilled to approximately 16,000 feet, to test the
Frontier and Dakota formations on a seismically-defined anticline. On February 26, 2007
the Table Top Unit #1 well at the Christmas Meadows Prospect was at 15,760 feet when it was
decided that it would be plugged back to the base of the 9.625 inch casing at a depth of
11,393 feet. We plan to get a larger rig and continue down to test the Nugget sandstones
at approximately 18,000 feet. Having met the obligation for the Unit test, the 41,237
acres of leases will have at least two years of term remaining. A new Federal Exploratory
Unit will be formed to test the deeper objectives. The Table Top Unit #1 well did not find
reservoir rocks with sufficient permeability in the Cretaceous formation. However, the
structural position and seismic lines that have been shot appear to support the existence
of a large anticline. The dip meter data and drift while drilling suggest that the crest
of the anticline is about half a mile to the southeast. We will rework the seismic with
the known velocities that we penetrated in the Table Top Unit #1 well and attempt to steer
the well to the crest of the anticline at the Nugget depth. We will also consider the
possibility of attempting to drill to test the Madison carbonates at a depth of
approximately 23,000 feet.
    
    On March 2, 2006, we began drilling an 8,000 foot Mesaverde test on our South Fillmore
Prospect, which is twelve miles north of Cow Creek. At the initial South Fillmore well, a
fracture stimulation of the sandstone next to the coal was successfully completed August 9,
2006. Rates as of August 21, 2006, were 900 Mcf per day, 60 Bbls of oil per day and 444
Bbls of water per day on a 32/64 inch choke with the casing pressure of 1,000 psi and
flowing tube pressure of 200 psi. Production equipment has been assembled on the location
to conduct a two week test of the well. There have been weather and equipment delays, but
the test is expected to be competed soon. Double Eagle has a 100% working interest in the
first well, the PH State 16-1, and approximately a 67% working interest after payout in any
offset wells in the South Fillmore Prospect.
    
    At the Rattlesnake Prospect, we started drilling the Rattlesnake 24-19 well on July 18,
2006, and did not find a commercial deposit of oil and gas. The well has been plugged and
abandoned, and the related well costs of $278 were written off in 2006.
    28




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##### Table of Contents



Our Industry:
   
    
    We attempt to reduce our overall exposure to commodity price fluctuations through the
use of various fixed delivery contracts for some of our production. The duration of our
various fixed delivery contracts depends on our view of market conditions, available
contract prices and our operating strategy. Use of such contracts may limit the risk of
fluctuating cash flows. As of December 31, 2006, we had sales delivery contracts in effect
for approximately 57% of our current daily production.
    
    We have an inventory of attractive drilling locations, allowing us to grow reserves and
replace and expand production organically without having to rely solely on acquisitions.
Drilling opportunities in both the Atlantic Rim and the Pinedale Anticline are expected to
last for several years.
    
    On December 15, 2006, we announced that our universal shelf registration statement on
Form S-3 with the Securities and Exchange Commission was declared effective. The
universal shelf on Form S-3 now permits, but does not obligate, Double Eagle to sell, in
one or more public offerings, shares of newly issued common stock, shares of newly issued
preferred stock (subject to stockholder approval), warrants, stock purchase contracts,
stock purchase units or debt securities, or any combination of such securities, for
proceeds in an aggregate amount of up to $200 million. The terms of any offerings under the
shelf registration will be determined at the time of the offering and will be stated in a
prospectus supplement.
 29




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##### Table of Contents



Development Outlook for 2007:
 Atlantic Rim.
 Pinedale Anticline.
 Other.
  30




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##### Table of Contents



RESULTS OF OPERATIONS
  As of, and for the year ended, December 31,
    
    
    Percent change between years2006
    
    
    2005
    
    
    2004
    
    
    2005 to 2006
    
    
    2004 to 2005Excluding
Imbalance Activity:Net production volumesOil (Bbl)
    
    
    12,729
    
    
    
    15,470
    
    
    
    16,886
    
    
    
    -18
    %
    
    
    -8
    %Gas (Mcf)
    
    
    2,894,894
    
    
    
    2,976,094
    
    
    
    2,559,557
    
    
    
    -3
    %
    
    
    16
    %Mcfe
    
    
    2,971,268
    
    
    
    3,068,914
    
    
    
    2,660,873
    
    
    
    -3
    %
    
    
    15
    %Average daily productionMcfe
    
    
    8,140
    
    
    
    8,408
    
    
    
    7,290
    
    
    
    -3
    %
    
    
    15
    %Including
Imbalance Activity:Net production volumesOil (Bbl)
    
    
    12,729
    
    
    
    15,470
    
    
    
    16,886
    
    
    
    -18
    %
    
    
    -8
    %Gas (Mcf)
    
    
    3,140,653
    
    
    
    2,976,094
    
    
    
    2,559,557
    
    
    
    6
    %
    
    
    16
    %Mcfe
    
    
    3,217,027
    
    
    
    3,068,914
    
    
    
    2,660,873
    
    
    
    5
    %
    
    
    15
    %Average daily productionMcfe
    
    
    8,814
    
    
    
    8,408
    
    
    
    7,290
    
    
    
    5
    %
    
    
    15
    %Average price per unit productionOil (Bbl)
    
    $
    57.90
    
    
    $
    49.26
    
    
    $
    37.61
    
    
    
    18
    %
    
    
    31
    %Gas (Mcf)
    
    $
    5.57
    
    
    $
    6.62
    
    
    $
    4.85
    
    
    
    -16
    %
    
    
    36
    %Mcfe
    
    $
    5.67
    
    
    $
    6.66
    
    
    $
    4.91
    
    
    
    -15
    %
    
    
    36
    %Oil and gas production revenuesOil revenues
    
    $
    737
    
    
    $
    762
    
    
    $
    635
    
    
    
    -3
    %
    
    
    20
    %Gas revenues
    
    
    17,491
    
    
    
    19,689
    
    
    
    12,423
    
    
    
    -11
    %
    
    
    58
    %Total
    
    $
    18,228
    
    
    $
    20,451
    
    
    $
    13,058
    
    
    
    -11
    %
    
    
    57
    %Oil and gas production costsProduction costs
    
    $
    3,560
    
    
    $
    3,800
    
    
    $
    2,156
    
    
    
    -6
    %
    
    
    76
    %Production taxes
    
    
    2,209
    
    
    
    2,523
    
    
    
    1,645
    
    
    
    -12
    %
    
    
    53
    %Total
    
    $
    5,769
    
    
    $
    6,323
    
    
    $
    3,801
    
    
    
    -9
    %
    
    
    66
    %Data on a per Mcfe basisAverage price
    
    $
    5.67
    
    
    $
    6.66
    
    
    $
    4.91
    
    
    
    -15
    %
    
    
    36
    %Production costs, exluding pipeline
    
    
    1.11
    
    
    
    1.24
    
    
    
    0.81
    
    
    
    -10
    %
    
    
    53
    %Production taxes
    
    
    0.69
    
    
    
    0.82
    
    
    
    0.62
    
    
    
    -16
    %
    
    
    32
    %Depletion and amortization
    
    
    1.29
    
    
    
    1.17
    
    
    
    0.98
    
    
    
    10
    %
    
    
    19
    %Total operating costs
    
    
    3.09
    
    
    
    3.23
    
    
    
    2.41
    
    
    
    -4
    %
    
    
    34
    %Gross margin
    
    $
    2.58
    
    
    $
    3.43
    
    
    $
    2.50
    
    
    
    -25
    %
    
    
    37
    %Gross margin percentage
    
    
    46
    %
    
    
    52
    %
    
    
    51
    %
 31




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##### Table of Contents



Year ended December 31, 2006 compared to the year ended December 31, 2005
 Oil and gas sales volume and price comparisons
  Transportation revenue
  Oil and gas production expenses, depreciation, depletion and amortization
    General and administrative
  32




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##### Table of Contents



Income taxes
  Year ended December 31, 2005 compared to the year ended December 31, 2004
 Oil and gas sales volume and price comparisons
  Oil and gas production expenses, depreciation, depletion and amortization
   General and administrative expense
  Income taxes
  LIQUIDITY AND CAPITAL RESOURCES
  33




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##### Table of Contents



As of and for the Years Ended December 31,
    
    Percent Change Between Years2006
    
    2005
    
    2004
    
    2005 to 2006
    
    2004 to 2005Financial informationWorking capital
    
    $
    (7,006
    )
    
    $
    (2,804
    )
    
    $
    710
    
    
    
    -150
    %
    
    
    -495
    %Line of credit
    
    $
    13,221
    
    
    $
    3,000
    
    
    $
    
    
    
    
    341
    %
    
    
    Stockholders equity
    
    $
    33,042
    
    
    $
    29,778
    
    
    $
    24,927
    
    
    
    11
    %
    
    
    19
    %Net income
    
    $
    2,109
    
    
    $
    3,965
    
    
    $
    4,028
    
    
    
    -47
    %
    
    
    -2
    %Net income per common share:Basic
    
    $
    0.24
    
    
    $
    0.46
    
    
    $
    0.48
    
    
    
    -48
    %
    
    
    -4
    %Fully diluted
    
    $
    0.24
    
    
    $
    0.46
    
    
    $
    0.47
    
    
    
    -48
    %
    
    
    -2
    %Net cash provided by
operating activities
    
    $
    10,951
    
    
    $
    10,319
    
    
    $
    7,434
    
    
    
    6
    %
    
    
    39
    %Net cash used in
investing activities
    
    $
    (22,241
    )
    
    $
    (16,259
    )
    
    $
    (7,377
    )
    
    
    37
    %
    
    
    120
    %Net cash provided by
financing activities
    
    $
    10,470
    
    
    $
    3,701
    
    
    $
    692
    
    
    
    183
    %
    
    
    435
    %
  Capital Requirements
  Year Ended December 31,2006
    
    
    2005
    
    
    2004Property acquisition costs
    
    $
    100
    
    
    $
    407
    
    
    $
    297Exploration
    
    
    11,304
    
    
    
    3,693
    
    
    
    324Development
    
    
    10,046
    
    
    
    14,873
    
    
    
    8,367$
    21,450
    
    
    $
    18,973
    
    
    $
    8,988
 34




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##### Table of Contents



35




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##### Table of Contents



Contractual Obligations
  One year
    
    
    2 - 3
    
    
    4 - 5
    
    
    More thanTotal
    
    
    or less
    
    
    Years
    
    
    Years
    
    
    5 YearsLine of credit (a) (b)
    
    $
    13,221
    
    
    $
    
    
    
    $
    
    
    
    $
    13,221
    
    
    $
    Interest on line of credit (c)
    
    
    3,414
    
    
    
    955
    
    
    
    1,910
    
    
    
    549
    
    
    
    Operating leases
    
    
    137
    
    
    
    72
    
    
    
    46
    
    
    
    19
    
    
    
    Total contractual cash
commitments
    
    $
    16,772
    
    
    $
    1,027
    
    
    $
    1,956
    
    
    $
    13,789
    
    
    $
    
 
 (a)
    
    The amount listed reflects the balance outstanding as of December 31, 2006. Any
balance outstanding at July 31, 2010, is due at that time.(b)
    
    $10.1 million of the line of credit balance was repaid with the proceeds from a
secondary offering of our common stock in January 2007.(c)
    
    The interest rate assumed on the credit facility is 7.125% per annum, which was the
rate in effect at December 31, 2006. Our Current Credit Facility
    Access to Capital Markets
   Off-Balance Sheet Arrangements
   36




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##### Table of Contents



CONTRACTED VOLUMES
  RemainingContractual
    
    
    Daily
    
    
    
    
    
    
    FixedProperty
    
    Volume
    
    
    Production
    
    
    Term
    
    
    Price/McfCow Creek
    
    
    90,000
    
    
    
    1,000
    
    
    
    07/06 - 03/07
    
    
    $
    5.4290,000
    
    
    
    1,000
    
    
    
    07/06 - 03/07
    
    
    $
    6.28181,000
    
    
    
    1,000
    
    
    
    07/06 - 06/07
    
    
    $
    5.94181,000
    
    
    
    1,000
    
    
    
    07/06 - 06/07
    
    
    $
    6.32304,000
    
    
    
    1,000
    
    
    
    11/06 - 10/07
    
    
    $
    5.84Company Total
    
    
    846,000
  CRITICAL ACCOUNTING ESTIMATES
  Successful Efforts Method of Accounting
   37




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##### Table of Contents



Reserve Estimates
  Impairment of Long-Lived Assets
  Asset Retirement Obligation
  Stock-based compensation
  38




---



##### Table of Contents



ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 Interest Rate Risks
   Commodity Price Risks
   39




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##### Table of Contents



ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
  
 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
  40




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##### Table of Contents



ITEM 9A. CONTROLS AND PROCEDURES
 (a) Evaluation of Disclosure Controls and Procedures
  (b) Managements Annual Report on Internal Control Over Financial Reporting
  (i)
    
    pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the
assets of the Company;(ii)
    
    provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and
expenditures of the Company are being made only in accordance with
authorizations of management and directors of the Company; and(iii)
    
    provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use or disposition of the
Companys assets that could have a material effect on the financial
statements.
  Internal
Control-Integrated Framework
     41




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##### Table of Contents



(c) Managements Corrective Actions
  
    
    Redesign control to include detailed steps and instructions on performance of
control procedures;
    
    Ensure employees who are performing controls understand responsibilities and how to
perform said responsibilities;
    
    Design and implement a detailed check list to be completed prior to approval of
reserve report and inclusion in any Company reports or filings.
 (d) Changes in Internal Control Over Financial Reporting
   42




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##### Table of Contents



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
        43




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##### Table of Contents



ITEM 9B. OTHER INFORMATION
 .
 
 PART III
 Pursuant to instruction G(3) to Form 10-K, the following Items 10,11,12,13 and 14 are incorporated
by reference to the information provided in Double Eagles definitive proxy statement for the 2007
annual meeting of stockholders to be filed within 120 days from December 31, 2006.
 
 ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
 
 ITEM 11. EXECUTIVE COMPENSATION
 
 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
 
 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
 
 ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICE
 
 PART IV
 
 ITEM 15. EXHIBITS AND REPORTS ON FORM 8-K
  Audit Report of Independent Registered Public Accounting Firm
    
    F1Consolidated Balance Sheet
    
    F2Consolidated Statement of Operations
    
    F3Consolidated Statement of Cash Flows
    
    F4Consolidated Statement of Stockholders Equity
    
    F5Notes to Consolidated Financial Statements
    
    F6
  Exhibits.
 44




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##### Table of Contents



Exhibit No.
    
    Description3.1(a)
    
    Articles of Incorporation filed with the Maryland Secretary of State on January 23, 2001
(incorporated by reference from Exhibit 3.1(a) of the Companys Annual Report on Form
10-KSB for the year ended August 31, 2001).3.1(b)
    
    Certificate of Correction filed with the Maryland Secretary of State on February 15,
2001 concerning the Articles of Incorporation (incorporated by reference from Exhibit
3.1(b) of the Companys Annual Report on Form 10-KSB for the year ended August 31, 2001).3.1(c)
    
    Articles of Merger filed with the Maryland Secretary of State on February 15, 2001
(incorporated by reference from Exhibit 3.1(c) of the Companys Annual Report on Form
10-KSB for the year ended August 31, 2001).3.1(d)
    
    Certificate of Correction filed with the Maryland Secretary of State (incorporated by
reference from Exhibit 3 of the Companys Quarterly Report on Form 10-QSB for the quarter
ended November 30, 2001).3.2
    
    Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Companys Annual
Report on Form 10-KSB, filed for the year ended August 31, 2001).4.1
    
    Form of Warrant Agreement concerning Common Stock Purchase Warrants (incorporated by
reference from Exhibit 4.3 of the Amendment No. 1 to the Registrants Registration
Statement on Form SB-2 filed on November 27, 1996, SEC Registration No. 333-14011).10.1
    
    Debt Modification Agreement, effective August 1, 2006, including Commercial Loan
Agreement dated January 3, 2000, between Double Eagle Petroleum Co. and American National
Bank (filed as Exhibit 10.1 to the registrants Quarterly Report on Form 10-Q for the
quarter ended June 30, 2006, and incorporated herein by reference).14.1
    
    Code of Business Conduct and Ethics (filed as Exhibit 99.2 to the registrants Annual
Report on Form 10-KSB for the year ended December 31, 2004, and incorporated herein by
reference).21.1*
    
    Subsidiaries of registrant.23.1*
    
    Consent of Hein & Associates LLP.23.2*
    
    Consent of Netherland, Sewell & Associates.31.1*
    
    Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.31.2*
    
    Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.32*
    
    Certification Pursuant to 18 U.S.C. Section 1350 as adopted pursuant to section 906 of
the Sarbanes-Oxley Act of 2002.
 
 *
    
    Filed with this Form 10-K. 45




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##### Table of Contents



SIGNATURES
  DOUBLE EAGLE PETROLEUM CO.
 Date:
March 30, 2007
    
    /s/ Stephen H. HollisStephen H. Hollis,Chief Executive Officer,President and Director
  Date: March 30, 2007
    
    /s/ Stephen H. HollisStephen H. Hollis,Chief Executive Officer,President and DirectorDate: March 30, 2007
    
    /s/ Lonnie R. BrockLonnie R. BrockChief Financial OfficerDate: March 30, 2007
    
    /s/ Sigmund BalabanSigmund Balaban, DirectorDate: March 30, 2007
    
    /s/ Roy G. CoheeRoy G. Cohee, DirectorDate: March 30, 2007
    
    /s/ Richard DoleRichard Dole, Director
 46




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##### Table of Contents



Share-Based Payment
  
 F-1




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##### Table of Contents



(Amounts in thousands of dollars except share and per share data)
 December 31,2006
    
    
    2005ASSETSCurrent assets:Cash and cash equivalents
    
    $
    611
    
    
    $
    1,431Cash held in escrow
    
    
    707
    
    
    
    Accounts receivable
    
    
    5,047
    
    
    
    4,248Other current assets
    
    
    809
    
    
    
    218Total current assets
    
    
    7,174
    
    
    
    5,897Oil and gas properties and equipment, successful efforts method:Developed properties
    
    
    53,677
    
    
    
    41,146Wells in progress
    
    
    13,839
    
    
    
    2,946Gas transportation pipeline
    
    
    5,412
    
    
    
    5,379Undeveloped properties
    
    
    3,313
    
    
    
    3,213Corporate and other assets
    
    
    1,024
    
    
    
    74877,265
    
    
    
    53,432Less accumulated depreciation, depletion and amortization
    
    
    (20,079
    )
    
    
    (15,174
    )Net properties and equipment
    
    
    57,186
    
    
    
    38,258Other assets
    
    
    46
    
    
    
    56TOTAL ASSETS
    
    $
    64,406
    
    
    $
    44,211LIABILITIES AND STOCKHOLDERS EQUITYCurrent liabilities:Accounts payable
    
    $
    7,964
    
    
    $
    2,798Accrued expenses
    
    
    5,125
    
    
    
    4,246Accrued production taxes
    
    
    1,091
    
    
    
    1,657Total current liabilities
    
    
    14,180
    
    
    
    8,701Line of credit
    
    
    13,221
    
    
    
    3,000Asset retirement obligation
    
    
    694
    
    
    
    513Deferred tax liability
    
    
    3,269
    
    
    
    2,219Total liabilities
    
    
    31,364
    
    
    
    14,433Commitments and contingencies (Note 4)Stockholders equity:Common stock, $0.10 par value; 50,000,000 shares authorized;
8,641,104 and 8,590,604 shares issued and outstanding as of
December 31, 2006 and 2005, respectively
    
    
    864
    
    
    
    859Additional paid-in capital
    
    
    23,251
    
    
    
    22,101Retained earnings
    
    
    8,927
    
    
    
    6,818Total stockholders equity
    
    
    33,042
    
    
    
    29,778TOTAL LIABILITIES AND STOCKHOLDERS EQUITY
    
    $
    64,406
    
    
    $
    44,211
  F-2




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##### Table of Contents



(Amounts in thousands of dollars except share and per share data)
 Year ended December 31,2006
    
    
    2005
    
    
    2004RevenuesOil and gas sales
    
    $
    18,228
    
    
    $
    20,451
    
    
    $
    13,058Transportation revenue
    
    
    523
    
    
    
    
    
    
    
    Other income, net
    
    
    281
    
    
    
    45
    
    
    
    209Total revenues
    
    
    19,032
    
    
    
    20,496
    
    
    
    13,267Costs and expensesProduction costs
    
    
    3,730
    
    
    
    3,800
    
    
    
    2,156Production taxes
    
    
    2,209
    
    
    
    2,523
    
    
    
    1,645Exploration expenses including dry hole costs
    
    
    530
    
    
    
    747
    
    
    
    324General and administrative
    
    
    3,959
    
    
    
    3,015
    
    
    
    1,628Depreciation, depletion and amortization
    
    
    4,909
    
    
    
    4,069
    
    
    
    2,908Impairment of equipment and properties
    
    
    
    
    
    
    357
    
    
    
    155Total costs and expenses
    
    
    15,337
    
    
    
    14,511
    
    
    
    8,816Income from operations
    
    
    3,695
    
    
    
    5,985
    
    
    
    4,451Interest (expense) income, net
    
    
    (187
    )
    
    
    23
    
    
    
    27Income before income taxes
    
    
    3,508
    
    
    
    6,008
    
    
    
    4,478Provision for deferred income taxes
    
    
    (1,399
    )
    
    
    (2,043
    )
    
    
    (450
    )NET INCOME
    
    $
    2,109
    
    
    $
    3,965
    
    
    $
    4,028Net income per common share:Basic
    
    $
    0.24
    
    
    $
    0.46
    
    
    $
    0.48Fully diluted
    
    $
    0.24
    
    
    $
    0.46
    
    
    $
    0.47Weighted average shares outstanding:Basic
    
    
    8,632,567
    
    
    
    8,564,228
    
    
    
    8,469,852Fully diluted
    
    
    8,655,587
    
    
    
    8,628,476
    
    
    
    8,599,020
  F-3




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##### Table of Contents



(Amounts in thousands of dollars)
 Year ended December 31,2006
    
    
    2005
    
    
    2004Cash flows from operating activities:Net income
    
    $
    2,109
    
    
    $
    3,965
    
    
    $
    4,028Adjustments to reconcile net income to net cash provided
by operating activities:Depreciation, depletion and amortization
    
    
    4,909
    
    
    
    4,088
    
    
    
    2,923Abandonment of non-producing properties
    
    
    20
    
    
    
    106
    
    
    
    135Impairment of equipment and properties
    
    
    
    
    
    
    357
    
    
    
    155Provision for deferred income taxes
    
    
    1,399
    
    
    
    2,043
    
    
    
    450Directors fees paid in stock
    
    
    97
    
    
    
    160
    
    
    
    54Non-cash employee stock option expense
    
    
    460
    
    
    
    26
    
    
    
    Other
    
    
    
    
    
    
    7
    
    
    
    (141
    )Changes in current assets and liabilities:Increase in deposit held in escrow
    
    
    (707
    )
    
    
    
    
    
    
    Increase in accounts receivable
    
    
    (799
    )
    
    
    (2,076
    )
    
    
    (1,121
    )Decrease (increase) in other current assets
    
    
    (591
    )
    
    
    111
    
    
    
    (278
    )Increase (decrease) in accounts payable
    
    
    4,118
    
    
    
    (938
    )
    
    
    (436
    )Increase in accrued expenses
    
    
    502
    
    
    
    1,785
    
    
    
    1,038Increase (decrease) in accrued production taxes
    
    
    (566
    )
    
    
    685
    
    
    
    627NET CASH PROVIDED BY OPERATING ACTIVITIES
    
    
    10,951
    
    
    
    10,319
    
    
    
    7,434Cash flows from investing activities:Additions of producing properties and equipment
    
    
    (21,861
    )
    
    
    (16,248
    )
    
    
    (7,331
    )Additions of corporate and non-producing properties
    
    
    (390
    )
    
    
    (567
    )
    
    
    (325
    )Proceeds from sales of properties and assets
    
    
    
    
    
    
    571
    
    
    
    269(Additions) reductions of other assets
    
    
    10
    
    
    
    (15
    )
    
    
    10NET CASH USED IN INVESTING ACTIVITIES
    
    
    (22,241
    )
    
    
    (16,259
    )
    
    
    (7,377
    )Cash flows from financing activities:Net borrowings on line of credit
    
    
    10,221
    
    
    
    3,000
    
    
    
    Exercise of options
    
    
    353
    
    
    
    701
    
    
    
    714Settlement of options
    
    
    (104
    )
    
    
    
    
    
    
    Other
    
    
    
    
    
    
    
    
    
    
    (22
    )NET CASH PROVIDED BY FINANCING ACTIVITIES
    
    
    10,470
    
    
    
    3,701
    
    
    
    692Change in cash and cash equivalents
    
    
    (820
    )
    
    
    (2,239
    )
    
    
    749Cash and cash equivalents at beginning of period
    
    
    1,431
    
    
    
    3,670
    
    
    
    2,921CASH AND CASH EQUIVALENTS AT END OF PERIOD
    
    $
    611
    
    
    $
    1,431
    
    
    $
    3,670Supplemental disclosure of cash and non-cash transactions:Cash paid for interest
    
    $
    490
    
    
    $
    57
    
    
    $
    503Interest capitalized
    
    $
    293
    
    
    $
    43
    
    
    $
    Additions to developed properties included in current liabilities
    
    $
    6,183
    
    
    $
    4,758
    
    
    $
    3,050Additions to developed properties for retirement obligations
    
    $
    171
    
    
    $
    87
    
    
    $
    55Directors fees paid in stock
    
    $
    97
    
    
    $
    160
    
    
    $
    54Stock option expense
    
    $
    460
    
    
    $
    
    
    
    $
    
  F-4




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##### Table of Contents



(Amounts in thousands of dollars except share data)
 Additional
    
    
    
    
    
    
    TotalOustanding
    
    
    Common
    
    
    Paid-In
    
    
    Retained
    
    
    StockholdersShares
    
    
    Stock
    
    
    Capital
    
    
    Earnings
    
    
    EquityBalance at
January 1, 2004
    
    
    8,334,404
    
    
    $
    834
    
    
    $
    20,198
    
    
    $
    (1,175
    )
    
    $
    19,857Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    4,028
    
    
    
    4,028Stock options exercised
and shares issued for
compensation
    
    
    154,000
    
    
    
    15
    
    
    
    1,027
    
    
    
    
    
    
    
    1,042Balance at
December 31, 2004
    
    
    8,488,404
    
    
    $
    849
    
    
    $
    21,225
    
    
    $
    2,853
    
    
    $
    24,927Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3,965
    
    
    
    3,965Stock options exercised
and shares issued for
compensation
    
    
    102,200
    
    
    
    10
    
    
    
    876
    
    
    
    
    
    
    
    886Balance at
December 31, 2005
    
    
    8,590,604
    
    
    $
    859
    
    
    $
    22,101
    
    
    $
    6,818
    
    
    $
    29,778Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,109
    
    
    
    2,109Stock options exercised
    
    
    44,500
    
    
    
    4
    
    
    
    349
    
    
    
    
    
    
    
    353Shares issued and expense
recognized for stock-
based compensation
    
    
    6,000
    
    
    
    1
    
    
    
    801
    
    
    
    
    
    
    
    802Balance at
December 31, 2006
    
    
    8,641,104
    
    
    $
    864
    
    
    $
    23,251
    
    
    $
    8,927
    
    
    $
    33,042
  F-5




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##### Table of Contents



DOUBLE EAGLE PETROLEUM CO.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS  (Amounts in thousands of dollars except share and per share data)
 1.
    
    Business Description and Summary of Significant Accounting PoliciesDescription of Operations and Basis of PresentationDouble Eagle Petroleum Co. (Double Eagle or the Company) is an independent energy company
engaged in the exploration, development, production and sale of natural gas and crude oil,
primarily in the Rocky Mountain Basins of the western United States. Double Eagle was
incorporated in the State of Wyoming in January 1972, and reincorporated in the State of
Maryland in February 2001.During the second quarter of 2006, the Company transferred assets held related to its 13-mile
intrastate gas pipeline (the Pipeline) to Eastern Washakie Midstream LLC, a wholly owned
subsidiary of Double Eagle, which was formed on February 10, 2006. The Pipeline, which was
constructed in late 2005, became operational in January 2006, and connects the Cow Creek Field
to the interstate pipeline system owned by Southern Star Central Gas Pipeline, Inc. Beginning in
the second quarter of 2006, Double Eagle presented consolidated financial statements to reflect
the consolidation of the two entities for reporting purposes (collectively, the Company). All
inter-company balances and transactions have been eliminated in consolidation for all periods
presented in this Form 10-K.The Company has no interests in any unconsolidated entities, nor does it have any unconsolidated
special purpose entities.Certain reclassifications have been made to amounts reported in previous years to conform to the
2006 presentation.Cash and Cash EquivalentsCash and cash equivalents includes all cash balances and any highly liquid investments with an
original maturity of 90 days or less.Accounts ReceivableThe Company records estimated oil and gas revenue receivable from third parties at its net
revenue interest. The Company also reflects costs incurred on behalf of joint interest partners
in accounts receivable. Management periodically reviews accounts receivable amounts for
collectability. No allowance for doubtful accounts was considered necessary at December 31,
2006, 2005 and 2004.Use of Estimates in the Preparation of Financial StatementsThe preparation of financial statements in conformity with accounting principles generally
accepted in the United States requires management to make estimates and assumptions that affect
the reported amounts of oil and gas reserves, assets and liabilities and disclosure on
contingent assets and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual results could differ from
those estimates. Estimates of oil and gas reserve quantities provide the basis for calculation
of depletion, depreciation, and amortization, and impairment, each of which represents a
significant component of the consolidated financial statements.The Company accounts for gas imbalances under the entitlement method, whereby a working interest
owner records revenue based on its share of entitled production. At December 31, 2005, based on
information received from our third party producers, the Companys gas imbalances were
considered immaterial. During the fourth quarter 2006, updated information from third party
producers, was received which indicated that the imbalance for certain properties generally was
larger than originally estimated. As a result, the Company revised the estimated gas imbalance.
The effect of this change in estimate, recorded in the fourth quarter, was to increase revenues
by $857 and net income by $449 or, $.05 per share of common stock for the three and twelve month
periods ended December 31, 2006.
 F-6




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##### Table of Contents



Concentration of Credit RiskFinancial instruments which potentially subject the Company to credit risk are accounts
receivable. Substantially all of the Companys receivables are within the oil and gas industry,
including those from the Companys third party marketing company. Collectability is dependent
upon the financial wherewithal of each individual company as well as the general economic
conditions of the industry. The receivables are not collateralized. To date, the Company has
had minimal bad debts.Revenue Recognition and Gas BalancingThe Company accounts for gas imbalances under the entitlement method, whereby a working interest
owner records revenue based on its share of entitled production. An over-produced owner would
record the excess of the amount taken over its entitled share as a reduction in revenues and a
payable while the under-produced owner records revenue and a receivable for the imbalance
amount. The Companys imbalance position at December 31, 2006 resulted in an
imbalance receivable of 292 MMcf, or $914, and an imbalance payable of 46 MMcf, or $203. See
additional discussion in Use of Estimates in Preparation of Financial Statements above.Oil and Gas Producing ActivitiesDouble Eagle uses the successful efforts method of accounting for its oil and gas producing
activities. Under this method of accounting, all property acquisition costs and costs of
exploration and development wells are capitalized when incurred, pending determination of
whether the well has found proved reserves. If an exploratory well does not find proved
reserves, the costs of drilling the well are charged to expense. The costs of development wells
are capitalized whether productive or nonproductive. The Company had no exploratory well costs
that had been suspended for one year or more as of December 31, 2006, 2005 or 2004.Geological and geophysical costs, and the costs of carrying and retaining unproved leaseholds
are expensed as incurred. The Company limits the total amount of unamortized capitalized costs
for each property to the value of future net revenues, based on current prices and costs.Depreciation, depletion and amortization (DD&A) of capitalized costs for producing oil and gas
properties is provided on a field-by-field basis using the units-of-production method, based on
proved oil and gas reserves. DD&A takes into consideration restoration, dismantlement and
abandonment costs and the anticipated proceeds for equipment salvage.Depreciation, depletion and amortization of oil and gas
properties for the years ended December 31, 2006, 2005 and 2004,
was $4,163, $3,583, and $2,619, respectively.Double Eagle invests in unevaluated oil and gas properties for the purpose of exploration and
development of proved reserves. The costs of unproved leases which become productive are
reclassified to proved properties when proved reserves are discovered on the property. Unproved
oil and gas interests are carried at the lower of cost or estimated fair market value and are
not subject to amortization.Asset Retirement ObligationsLegal obligations associated with the retirement of long-lived assets result from the
acquisition, construction, development and normal use of the asset. The Companys asset
retirement obligations relate primarily to the retirement of oil and gas properties and related
production facilities, lines and other equipment used in the field operations. The fair value
of a liability for an asset retirement obligation is recognized in the period in which it is
incurred, if a reasonable estimate of fair value can be made. The fair value of the liability
is added to the carrying amount of the associated asset. This additional carrying amount is
then depreciated over the life of the asset. The liability increases due to the passage of time
based on the time value of money until the obligation is settled.For the years ended December 31, 2006, 2005 and 2004, an expense of $15, $20 and $15,
respectively, was recorded as accretion expense on the liability and included in depletion,
depreciation and amortization. During 2006, 2005 and 2004, the Company recorded an additional
$170, $86 and $55, respectively, in oil and gas properties and asset retirement obligation
liability to reflect the present value of plugging liability on new wells.
 F-7




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##### Table of Contents



A reconciliation of the Companys asset retirement obligation liability:
 For the year ended December 31,2006
    
    
    2005Beginning asset retirement obligation
    
    $
    513
    
    
    $
    407Liabilities incurred
    
    
    87
    
    
    
    39Liabilities settled
    
    
    (4
    )
    
    
    Accretion expense
    
    
    15
    
    
    
    20Revision to estimated cash flows
    
    
    83
    
    
    
    47Ending asset retirement obligation
    
    $
    694
    
    
    $
    513
 Impairment of Long-Lived AssetsThe Company reviews the carrying values of its long-lived assets whenever events or changes in
circumstances indicate that such carrying values may not be recoverable. If, upon review, the
sum of the undiscounted pretax cash flows is less than the carrying value of the asset group,
the carrying value is written down to estimated fair value. Individual assets are grouped for
impairment purposes at the lowest level for which there are identifiable cash flows that are
largely independent of the cash flows of other groups of assets, generally on a field-by-field
basis. The fair value of impaired assets is determined based on quoted market prices in active
markets, if available, or upon the present values of expected future cash flows using discount
rates commensurate with the risks involved in the asset group. The long-lived assets of the
Company, which are subject to periodic evaluation, consist primarily of oil and gas properties
and undeveloped leaseholds. The Company recognized a non-cash charge on producing properties
during the years ending December 31, 2006, 2005 and 2004 of $0, $357, and $155, respectively,
for those properties with carrying values exceeding the expected undiscounted future net cash
flows. The Company also recognized a charge of $278 on a dry hole exploratory project during
the year for the plugging and abandonment of the Rattlesnake well.The Companys pipeline is recorded at cost, which totaled $5,412 as of December 31, 2006.
Depreciation is recorded using the straight-line method over a 25 year estimated useful life.
The useful life may be limited to the useful life of current and future recoverable reserves
serviced by the pipeline.Corporate and Other AssetsOffice facilities, equipment and vehicles are recorded at cost. Depreciation is recorded using
the straight-line method over the estimated useful lives of 10 to 30 years for office
facilities, 3 to 10 years for office equipment, and 7 years for vehicles. Depreciation expense
for the years ended December 31, 2006, 2005 and 2004 was $107, $100 and $51, respectively.Major CustomersSales to one major unaffiliated customer for years ended December 31, 2006, 2005 and 2004, were
$13,649, $14,000, and $9,900, respectively. The Company believes that it is not dependent upon
this customer due to the nature of its product. No other single customer accounted for 10% or
more of revenues in 2006, 2005 or 2004.Industry Segment and Geographic InformationThe Company operates in one industry segment, which is the exploration, development, production
and sale of natural gas and crude oil, and all of the Companys operations are conducted in the
Continental United Sates. Consequently, the Company currently reports as a single industry
segment. The activities of our gas transportation subsidiary are immaterial to the financial
statements taken as a whole and therefore are not viewed by management as a discrete reporting
segment.Employee Benefit PlanThe Company maintains a Simplified Employee Pension Plan covering substantially all employees
meeting minimum eligibility requirements. Employer contributions are determined solely at
managements discretion. Employer contributions for years ended 2006, 2005 and 2004 were $87,
$63, and $39, respectively.
 F-8




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##### Table of Contents



Income TaxesDeferred income taxes are provided on the difference between the tax basis of an asset or
liability and its carrying amount in the financial statements. This difference will result in
taxable income or deduction in future periods when the reported amount of the asset or liability
is recovered or settled, respectively.Earnings Per ShareBasic earnings per share (EPS) is calculated by dividing net income by the weighted average
number of shares of common stock outstanding during the period. Fully diluted earnings per share
incorporates the treasury stock method to measure the dilutive impact of outstanding stock
options by including the effect of outstanding vested and unvested options in the average number
of common shares outstanding during the period.Calculation of basic and fully diluted weighted average shares outstanding and EPS for the
periods indicated:
 For the year ended December 31,2006
    
    
    2005
    
    
    2004Net income
    
    $
    2,109
    
    
    $
    3,965
    
    
    $
    4,028Weighted average shares:Weighted average shares  basic
    
    
    8,632,567
    
    
    
    8,564,228
    
    
    
    8,469,852Dilution effect of stock options outstanding
at the end of period
    
    
    23,020
    
    
    
    64,248
    
    
    
    129,168Weighted average shares  fully diluted
    
    
    8,655,587
    
    
    
    8,628,476
    
    
    
    8,599,020Earnings per share:Basic
    
    $
    0.24
    
    
    $
    0.46
    
    
    $
    0.48Fully diluted
    
    $
    0.24
    
    
    $
    0.46
    
    
    $
    0.47
  For the years ended December 31,2006
    
    
    2005
    
    
    2004Options to purchase common stock
    
    
    18,621
    
    
    
    
    
    
    
    
 Stock Based CompensationEffective January 1, 2006, Double Eagle adopted the provisions of Statement of Financial
Accounting Standards No. 123 (revised 2004)  Share-Based Payment (SFAS 123(R)), which
requires the measurement and recognition of compensation expense for all share-based payment
awards (including stock options) made to employees and directors based on estimated fair value.
Compensation expense for equity-classified awards is measured at the grant date based on the
fair value of the award and is recognized as an expense in earnings over the requisite service
period using a graded vesting method. The Company adopted SFAS 123(R) using the modified
prospective transition method. Under this transition method, compensation cost recognized during
the year ended December 31, 2006 includes the cost for options which were granted prior to
January 1, 2006, as determined under the provisions of SFAS 123(R).Prior to the adoption of the provisions of SFAS 123(R), Double Eagle accounted for the Plans
under Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees,
(APB 25), and related interpretations and disclosure requirements established by SFAS 123 
Accounting for Stock-Based Compensation, as amended by SFAS No. 148  Accounting for Stock-Based
Compensation  Transition and Disclosure. The following table illustrates the effect on net
income and earnings per share as if the fair-value recognition provisions of SFAS 123(R) were
applied to all of the Companys share-based compensation awards for the prior periods indicated:
 F-9




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##### Table of Contents



For the year ended December 31,2005
    
    

    2004Net income, as reported
    
    $
    3,965
    
    
    $
    4,028Add: Share-based employee compensation
expense included in reported net income
    
    
    26
    
    
    
    26Deduct: Total share-based employee
compensation expense determined under the
fair value based method for all awards
    
    
    (686
    )
    
    
    (233
    )Pro forma net income
    
    $
    3,305
    
    
    $
    3,821Basic Earnings Per Share:As reported
    
    $
    0.46
    
    
    $
    0.48Pro forma
    
    $
    0.39
    
    
    $
    0.45Diluted Earnings Per Share:As reported
    
    $
    0.46
    
    
    $
    0.47Pro forma
    
    $
    0.38
    
    
    $
    0.44
 For additional information regarding our stock-based compensation plans, refer to Note 5.Fair Value of Financial InstrumentsThe Companys financial instruments including cash and cash equivalents, accounts receivable and
accounts payable are carried at a cost, which approximates fair value due to the short-term
maturity of these instruments. The recorded value of the Companys credit facility approximates
its fair value as it bears interest at a floating rate.New accounting pronouncementsIn September 2006, the SEC issued Staff Accounting Bulletin No. 108 (SAB 108) to address
diversity in practice in quantifying financial statement misstatements. SAB 108 requires
registrants to quantify errors using both a balance sheet and an income statement approach and
to evaluate whether either approach results in quantifying a misstatement that, when all
relevant quantitative and qualitative factors are considered, is material. SAB 108 is effective
for fiscal years ending after November 15, 2006, allowing a one-time transitional cumulative
effect adjustment to retained earnings as of January 1, 2006 for errors that were not previously
deemed material, but are material under the guidance in SAB 108. The Company has applied the
guidance in SAB 108, and there are no material effects on the Companys financial position,
results of operations or cash flows.In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards No. 157 (SFAS 157). The Statement defines fair value,
establishes a framework for measuring fair value in generally accepted accounting principles
(GAAP), and expands disclosures about fair value measurements. This Statement is effective
for financial statements issued for fiscal years beginning after November 15, 2007, and interim
periods within those fiscal years. The adoption of SFAS 157 is not expected to have a material
effect on the Companys financial position, results of operations or cash flows.In July 2006, the FASB released FASB Interpretation No. 48  Accounting for Uncertainty in
Income Taxes, an interpretation of FASB Statement No. 109 (FIN 48). FIN 48 clarifies the
accounting and reporting for uncertainties in income taxes recognized in an enterprises
financial statements in accordance with Statement of Financial Accounting Standards No. 109 
Accounting for Income Taxes (SFAS 109) and prescribes a recognition threshold and measurement
attribute for the financial statement recognition and measurement of a tax position taken or
expected to be taken in a tax return. FIN 48 is effective for fiscal years beginning after
December 15, 2006 with the impact of adoption to be reported as a cumulative effect of an
accounting change. The adoption of FIN 48 is not expected to have a material effect on the
Companys financial position, results of operations or cash flows.
 F-10




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##### Table of Contents



2.
    
    Line of
Credit
As part of its cash management program, effective August 1, 2006, the Company entered into a new
$50 million revolving line of credit collateralized by oil and gas producing properties,
replacing the previously existing revolving line of credit described below. The initial
borrowing base is $25 million and all outstanding balances on the line of credit mature on July
31, 2010. As of December 31, 2006, the interest rate on the line of credit, calculated in
accordance with the agreement at 1.125% below the posted Wall Street Journal Prime Rate, was
7.125%, and the outstanding balance of $13,221 was used to fund capital expenditures.The Company is subject to certain financial and non-financial covenants with respect to the
above credit facility, including a requirement to maintain a current ratio, plus the line of
credit availability, of at least 1.0 to 1.0. As of December 31, 2006, the Company was in
compliance with all such covenants. Should any of the covenants with respect to the above
credit facility be violated, and if the Company was unable to negotiate a waiver or amendment
thereof, the lender would have the right to declare an event of default, terminate the remaining
commitment and accelerate all principal and interest outstanding.Prior to August 1, 2006, the Company maintained a $9 million revolving line of credit
collateralized by oil and gas producing properties. The interest rate on the line of credit was
0.5% below the posted Wall Street Journal Prime Rate. On August 1, 2006, all borrowings
outstanding under this facility were transferred to the new credit facility described above.For the years ended December 31, 2006, 2005, and 2004, interest expense totaled $480, $14 and
$0, respectively. We capitalized interest costs of $293, $43 and $0 for the years ended December
31, 2006, 2005, and 2004, respectively.3.
    
    Income TaxesThe provision for income taxes consists of:
 For the year ended December 31,2006
    
    
2005
    
    
2004Current taxes
    
    $
    
    
    
    $
    
    
    
    $
    Deferred taxes
    
    
    1,399
    
    
    
    2,043
    
    
    
    450Total income tax expense
    
    $
    1,399
    
    
    $
    2,043
    
    
    $
    450
 The tax effects of temporary differences that gave rise to the deferred tax liabilities and
deferred tax assets as of December 31, 2006 and 2005 were:
 As of December 31,2006
    
    
    2005Deferred tax assets:Net operating loss carry-forward
    
    $
    3,671
    
    
    $
    4,339Accrued compensation
    
    
    68
    
    
    
    Percentage depletion carry-forward
    
    
    153
    
    
    
    146Asset retirement obligation
    
    
    247
    
    
    
    14Stock option expense carry-forward
    
    
    
    
    
    
    174,139
    
    
    
    4,516Deferred tax liabilities:Net gas imbalance receivable
    
    
    (265
    )
    
    
    Net basis difference in oil and gas properties
    
    
    (7,143
    )
    
    
    (6,735
    )Net deferred tax liability
    
    $
    (3,269
    )
    
    $
    (2,219
    )
 At December 31, 2006, the Company had a net operating loss carry forward for regular income
tax reporting purposes of approximately $10.3 million, which will begin expiring in 2021.
 F-11




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##### Table of Contents



Reconciliation of the Companys effective tax rate to the expected federal tax rate is:
 For the year ended December 31,2006
    
    
    2005Expected federal tax rate
    
    
    35.00
    %
    
    
    34.00
    %Effect of non-deductibility of SFAS 123(R)Incentive Stock Option Expense and other permanent differences
    
    
    4.37
    %
    
    
    0.00
    %State tax rate and other
    
    
    0.52
    %
    
    
    0.00
    %Effective tax rate
    
    
    39.89
    %
    
    
    34.00
    %
 4.
    
    Commitments and ContingenciesGas Sales CommitmentsThe Company has committed to sell a total of 846,000 Mcf under five third-party gas sales
contracts. Should the Company be unable to deliver the gas commitment, it would be required to
purchase such amounts on the open market to fulfill the terms of these contracts. Certain
provisions of the contracts, including quantities, terms and prices, are:
 RemainingContractual
    
    
    Daily
    
    
    
    
    
    
    FixedProperty
    
    Volume
    
    
    Production
    
    
    Term
    
    
    Price/McfCow Creek
    
    
    90,000
    
    
    
    1,000
    
    
    
    07/06 - 03/07
    
    
    $
    5.4290,000
    
    
    
    1,000
    
    
    
    07/06 - 03/07
    
    
    $
    6.28181,000
    
    
    
    1,000
    
    
    
    07/06 - 06/07
    
    
    $
    5.94181,000
    
    
    
    1,000
    
    
    
    07/06 - 06/07
    
    
    $
    6.32304,000
    
    
    
    1,000
    
    
    
    11/06 - 10/07
    
    
    $
    5.84Company Total
    
    
    846,000
 Lease CommitmentsIn October 2004, the Company entered into a 42 month operating lease agreement for approximately
3,900 square feet of office space in Denver, Colorado. Rent expense for the Denver office was
approximately $58, $61, and $6 in 2006, 2005 and 2004, respectively. The Company also maintains
operating leases on 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:
 Year ending
    
    LeaseDecember 31,
    
    commitments2007
    
    $
    722008
    
    
    362009
    
    
    102010
    
    
    102011
    
    
    9Thereafter
    
    
    Total
    
    $
    137
 F-12




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##### Table of Contents



Contingencies
 The Company has initiated discussions with the operator regarding the Companys participation in
the Madden Sour Gas Participating Area in the Madden Deep Unit and the sour gas plant at Madden
Field. The Company is asserting that it is entitled to receive a cash settlement for its past
share of production for the period February 1, 2002 through October 31, 2006 (the Company is
paying its share of expenses and began participating in revenues on November 1, 2006). The
ultimate outcome and settlement amount of this issue cannot be determined at this time and no
amount has been recognized for possible collection of any asserted claims.
 5.
    
    Compensation PlansDouble Eagle has outstanding stock options issued to employees under four stock option plans,
approved by the Companys shareholders (collectively the Plans). The options have been
granted with an exercise price equal to the market price of Double Eagles stock on the date of
grant, vest annually over various periods from two to five years of continuous service, and
expire over various periods up to ten years from the date of grant.Effective January 1, 2006, Double Eagle adopted the provisions of SFAS 123(R), which requires
the measurement and recognition of compensation expense for all share-based payment awards
(including stock options) made to employees and directors based on estimated fair value. The
Company previously accounted for the Plans under APB 25, and related interpretations and
disclosure requirements established by SFAS 123  Accounting for Stock-Based Compensation, as
amended by SFAS No. 148  Accounting for Stock-Based Compensation  Transition and Disclosure.
In March 2005, the SEC issued SAB 107, relating to SFAS 123(R). Double Eagle considered the
guidance of SAB 107 in our adoption of SFAS 123 (R).Under APB 25, no compensation expense was recorded for Double Eagles stock options issued under
the qualified Plans. The pro forma effects on net income and earnings per share for qualified
stock options were disclosed in a footnote to the financial statements. Under APB 25,
compensation expense for non-qualified stock options with stock appreciation rights features was
recorded utilizing the market price of Double Eagles stock at each period-end to determine the
vested intrinsic value of the stock appreciation rights.Under SFAS 123(R), compensation expense for equity-classified awards, such as Double Eagles
stock options issued under the Plans, is measured at the grant date based on the fair value of
the award and is recognized as an expense in earnings over the requisite service period using a
graded vesting method.The Company adopted SFAS 123(R) using the modified prospective transition method. Under this
transition method, compensation cost recognized in 2006 includes the cost for options which were
granted prior to January 1, 2006, as determined under the provisions of SFAS 123(R). There was
no cumulative effect of the impact of adoption of SFAS 123(R) on liability-classified awards to
the consolidated financial statements. During the year ended December 31, 2006, total
share-based compensation expense for equity-classified awards, was $460, or $.05 cents per share
of common stock, and is reflected in General and administrative expense in the Consolidated
Statement of Operations. As of December 31, 2006, total estimated unrecognized compensation
expense from unvested stock options was $1,601, which is expected to be recognized over a period
of five years.The Company uses the Black-Scholes valuation model to determine the fair value of each option
award. Expected volatilities are based on the historical volatility of Double Eagles stock over
a period consistent with that of the expected terms of the options. The expected terms of the
options are estimated based on factors such as vesting periods, contractual expiration dates,
historical trends in Double Eagles stock price and historical exercise behavior. The risk-free
rates for periods within the contractual life of the options are based on the yields of U.S.
Treasury instruments with terms comparable to the estimated option terms. Assumptions used in
estimating fair value of share-based awards for the periods indicated:
 For the year ended December 31,2006
    
    2005
    
    2004Weighted-average volatility
    
    
    40% - 44
    %
    
    
    42
    %
    
    
    71
    %Expected dividends
    
    
    0.00
    %
    
    
    0.00
    %
    
    
    0.00
    %Expected term (in years)
    
    
    2 - 4
    
    
    
    5
    
    
    
    8Risk-free rate
    
    
    4.68% - 5.10
    %
    
    
    3.50
    %
    
    
    3.00
    %Expected forfeiture rate
    
    
    5% - 10
    %
    
    
    0.00
    %
    
    
    0.00
    %
 F-13




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##### Table of Contents



Weighted-AverageRemainingWeighted-Average
    
    
    Contractual Term
    
    
    AggregateOptions:
    
    Shares
    
    
    Exercise Price
    
    
    (in years)
    
    
    Intrinsic ValueOutstanding at January 1, 2006
    
    
    354,243
    
    
    $
    15.38
    
    
    
    3.5Granted
    
    
    112,500
    
    
    $
    19.53Exercised
    
    
    (44,500
    )
    
    $
    7.92Cancelled/expired
    
    
    (96,743
    )
    
    $
    16.39Outstanding at December 31, 2006
    
    
    325,500
    
    
    $
    17.64
    
    
    
    3.8
    
    
    $
    2,248Exerciseable at December 31, 2006
    
    
    101,700
    
    
    $
    16.46
    
    
    
    2.8
    
    
    $
    823Outstanding at January 1, 2005
    
    
    275,843
    
    
    $
    14.32
    
    
    
    2.5Granted
    
    
    249,500
    
    
    $
    18.43Exercised
    
    
    (93,600
    )
    
    $
    7.52Cancelled/expired
    
    
    (77,500
    )
    
    $
    17.00Outstanding at December 31, 2005
    
    
    354,243
    
    
    $
    15.38
    
    
    
    3.5
    
    
    $
    1,807Exerciseable at December 31, 2005
    
    
    202,743
    
    
    $
    13.48
    
    
    
    2.2
    
    
    $
    919Outstanding at January 1, 2004
    
    
    256,486
    
    
    $
    5.43
    
    
    
    0.8Granted
    
    
    176,100
    
    
    $
    13.90Exercised
    
    
    (150,000
    )
    
    $
    4.75Cancelled/expired
    
    
    (6,743
    )
    
    $
    14.83Outstanding at December 31, 2004
    
    
    275,843
    
    
    $
    14.32
    
    
    
    2.5
    
    
    $
    2,325Exerciseable at December 31, 2004
    
    
    156,676
    
    
    $
    5.44
    
    
    
    1.1
    
    
    $
    1,714
   OptionsOutstanding
    
    
    
    
    
    
    Options ExerciseableWeighted 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
    
    
    Exerciseable
    
    
    per Share$14.00 - $16.21
    
    
    105,000
    
    
    
    3.3
    
    
    $
    14.29
    
    
    
    54,000
    
    
    $
    14.57$18.01 - $23.61
    
    
    220,500
    
    
    
    4.0
    
    
    $
    19.23
    
    
    
    47,700
    
    
    $
    18.59325,500
    
    
    
    3.8
    
    
    $
    17.64
    
    
    
    101,700
    
    
    $
    16.46
 F-14




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##### Table of Contents



6.
    
    Supplemental Information on Oil and Gas Producing ActivitiesCapitalized Costs Relating to Oil and Gas Producing ActivitiesThe aggregate amount of capitalized costs relating to crude oil and natural gas producing
activities and the aggregate amount of related accumulated depreciation, depletion and
amortization at December 31, 2006, 2005 and 2004 are:
 As of December 31,2006
    
    
    2005
    
    
    2004Developed properties
    
    $
    53,677
    
    
    $
    41,146
    
    
    $
    32,294Undeveloped properties
    
    
    3,313
    
    
    
    3,213
    
    
    
    3,02656,990
    
    
    
    44,359
    
    
    
    35,320Accumulated depletion and amortization
    
    
    (19,442
    )
    
    
    (14,854
    )
    
    
    (10,947
    )Net capitalized costs
    
    $
    37,548
    
    
    $
    29,505
    
    
    $
    24,373
 Costs incurred in Oil and Gas Property Acquisitions, Exploration and Development ActivitiesCosts incurred in property acquisitions, exploration, and development activities for the years
ended December 31, 2006, 2005 and 2004 were:
 For the year ended December 31,2006
    
    
    2005
    
    
    2004Property acquisitions  unproved
    
    $
    100
    
    
    $
    407
    
    
    $
    297Exploration
    
    
    11,304
    
    
    
    3,693
    
    
    
    324Development
    
    
    10,046
    
    
    
    14,873
    
    
    
    8,367Total
    
    $
    21,450
    
    
    $
    18,973
    
    
    $
    8,988
 The following table reflects the net changes in capitalized exploratory well costs during 2006,
2005 and 2004, and does not include amounts that were capitalized and either subsequently
expensed or reclassified to producing well costs in the same period. No exploratory well costs
have been capitalized for a period greater than one year from the completion of exploratory
drilling.
 As of December 31,2006
    
    
    2005
    
    
    2004Beginning balance at January 1
    
    $
    2,941
    
    
    $
    
    
    
    $
    Capitalized exploratory well costs charged to expense upon the adoption of FSP FAS 19-1
    
    
    
    
    
    
    
    
    
    
    Additions to capitalized exploratory well costs pending the determination of proved reserves
    
    
    5,400
    
    
    
    2,941
    
    
    
    Reclassification to wells, facilities, and equipment based on the determination of proved reserves
    
    
    (2,356
    )
    
    
    
    
    
    
    Capitalized exploratory well costs charged to expense
    
    
    (278
    )
    
    
    
    
    
    
    Ending balance at December 31
    
    $
    5,707
    
    
    $
    2,941
    
    
    $
    
 F-15




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##### Table of Contents



Results of Operations from Oil and Gas Producing Activities
  For the year ended December 31,2006
    
    
    2005
    
    
    2004Operating revenues
    
    $
    18,228
    
    
    $
    20,451
    
    
    $
    13,058Costs and expenses:Production
    
    
    5,769
    
    
    
    6,323
    
    
    
    3,801Exploration
    
    
    530
    
    
    
    747
    
    
    
    324Depletion, amortization and impairment
    
    
    4,163
    
    
    
    3,939
    
    
    
    2,774Total costs and expenses
    
    
    10,462
    
    
    
    11,009
    
    
    
    6,899Income before income taxes
    
    $
    7,766
    
    
    $
    9,442
    
    
    $
    6,159
 Oil and
Gas Reserves (Unaudited)
   For the year ended December 31,2006
    
    
    2005
    
    
    2004Oil
    
    
    Gas
    
    
    Oil
    
    
    Gas
    
    
    Oil
    
    
    Gas(Bbl)
    
    
    (Mcf)
    
    
    (Bbl)
    
    
    (Mcf)
    
    
    (Bbl)
    
    
    (Mcf)Beginning of year
    
    
    328,752
    
    
    
    47,234,335
    
    
    
    278,055
    
    
    
    34,934,746
    
    
    
    208,957
    
    
    
    22,818,980Revisions of estimates
    
    
    41,546
    
    
    
    (5,976,392
    )
    
    
    7,451
    
    
    
    (198,036
    )
    
    
    16,062
    
    
    
    13,606Extensions and discoveries
    
    
    2,596
    
    
    
    10,379,429
    
    
    
    58,716
    
    
    
    15,473,719
    
    
    
    89,886
    
    
    
    14,661,717Sales of reserves in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (19,964
    )
    
    
    Production
    
    
    (12,729
    )
    
    
    (3,140,653
    )
    
    
    (15,470
    )
    
    
    (2,976,094
    )
    
    
    (16,886
    )
    
    
    (2,559,557
    )End of year
    
    
    360,165
    
    
    
    48,496,719
    
    
    
    328,752
    
    
    
    47,234,335
    
    
    
    278,055
    
    
    
    34,934,746Proved developed reserves
    
    
    254,346
    
    
    
    30,075,467
    
    
    
    199,931
    
    
    
    23,032,277
    
    
    
    181,397
    
    
    
    17,161,577Percentage of proved
developed reserves
    
    
    71
    %
    
    
    62
    %
    
    
    61
    %
    
    
    49
    %
    
    
    65
    %
    
    
    49
    %
  Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves (Unaudited)
  F-16




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##### Table of Contents



As of December 31,2006
    
    
    2005
    
    
    2004Future cash inflows
    
    $
    246,270
    
    
    $
    400,671
    
    
    $
    202,358Future production costs
    
    
    (65,650
    )
    
    
    (112,025
    )
    
    
    (60,424
    )Future development costs
    
    
    (17,049
    )
    
    
    (19,168
    )
    
    
    (9,465
    )Future income taxes
    
    
    (42,578
    )
    
    
    (74,738
    )
    
    
    (32,972
    )Future net cash flows
    
    
    120,993
    
    
    
    194,740
    
    
    
    99,49710% annual discount
    
    
    (70,960
    )
    
    
    (103,447
    )
    
    
    (47,967
    )Standardized measure of
discounted future net cash flows
    
    $
    50,033
    
    
    $
    91,293
    
    
    $
    51,530
  2006
    
    
    2005
    
    
    2004Standard measure, as of January 1,
    
    $
    91,293
    
    
    $
    51,530
    
    
    $
    42,841Sales of oil and gas produced, net of production costs
    
    
    (12,460
    )
    
    
    (14,128
    )
    
    
    (9,258
    )Extensions and discoveries
    
    
    14,724
    
    
    
    43,610
    
    
    
    28,865Net change in prices and production costs related to future production
    
    
    (44,698
    )
    
    
    34,004
    
    
    
    (4,122
    )Development costs incurred during the year
    
    
    3,147
    
    
    
    1,290
    
    
    
    2,115Changes in estimated future development costs
    
    
    (10,632
    )
    
    
    (9,816
    )
    
    
    (6,958
    )Sales of reserves in place
    
    
    
    
    
    
    
    
    
    
    (766
    )Revisions of quantity estimates
    
    
    (7,749
    )
    
    
    (384
    )
    
    
    329Accretion of discount
    
    
    6,764
    
    
    
    14,315
    
    
    
    6,386Net change in income taxes
    
    
    13,299
    
    
    
    (22,186
    )
    
    
    (4,563
    )Changes in timing and other
    
    
    (3,655
    )
    
    
    (6,942
    )
    
    
    (3,339
    )Aggregate Change
    
    
    (41,260
    )
    
    
    39,763
    
    
    
    8,689Standardized measure, as of December 31,
    
    $
    50,033
    
    
    $
    91,293
    
    
    $
    51,530
 F-17




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##### Table of Contents



Quarterly Financial Data (Unaudited)
  Fourth
    
    
    Third

    
    
    SecondQuarter
    
    
    Quarter
    
    
    Quarter
    
    
    First QuarterYear ended December 31, 2006Oil and gas sales
    
    $
    5,420
    
    
    $
    4,163
    
    
    $
    4,052
    
    
    $
    4,593Income from operations
    
    $
    1,409
    
    
    $
    526
    
    
    $
    449
    
    
    $
    1,311Net income
    
    $
    666
    
    
    $
    341
    
    
    $
    264
    
    
    $
    838Basic net income per common share
    
    $
    0.07
    
    
    $
    0.04
    
    
    $
    0.03
    
    
    $
    0.10Fully diluted net income per common share
    
    $
    0.07
    
    
    $
    0.04
    
    
    $
    0.03
    
    
    $
    0.10Year ended December 31, 2005Oil and gas sales
    
    $
    6,320
    
    
    $
    5,233
    
    
    $
    4,334
    
    
    $
    4,564Income from operations
    
    $
    2,084
    
    
    $
    1,488
    
    
    $
    1,167
    
    
    $
    1,246Net income
    
    $
    1,389
    
    
    $
    975
    
    
    $
    776
    
    
    $
    825Basic net income per common share
    
    $
    0.16
    
    
    $
    0.11
    
    
    $
    0.09
    
    
    $
    0.10Fully diluted net income per common share
    
    $
    0.17
    
    
    $
    0.11
    
    
    $
    0.09
    
    
    $
    0.09
 F-18




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##### Table of Contents



Exhibit Index
 Exhibit No.
    
    Description3.1(a)
    
    Articles of Incorporation filed with the Maryland Secretary of State on
January 23, 2001 (incorporated by reference from Exhibit 3.1(a) of the Companys Annual
Report on Form 10-KSB for the year ended August 31, 2001).3.1(b)
    
    Certificate of Correction filed with the Maryland Secretary of State on
February 15, 2001 concerning the Articles of Incorporation (incorporated by reference from
Exhibit 3.1(b) of the Companys Annual Report on Form 10-KSB for the year ended August 31,
2001).3.1(c)
    
    Articles of Merger filed with the Maryland Secretary of State on February
15, 2001 (incorporated by reference from Exhibit 3.1(c) of the Companys Annual Report on
Form 10-KSB for the year ended August 31, 2001).3.1(d)
    
    Certificate of Correction filed with the Maryland Secretary of State
(incorporated by reference from Exhibit 3 of the Companys Quarterly Report on Form 10-QSB
for the quarter ended November 30, 2001).3.2
    
    Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the
Companys Annual Report on Form 10-KSB, filed for the year ended August 31, 2001).4.1
    
    Form of Warrant Agreement concerning Common Stock Purchase Warrants
(incorporated by reference from Exhibit 4.3 of the Amendment No. 1 to the
Registrants Registration Statement on Form SB-2 filed on November 27, 1996, SEC
Registration No. 333-14011).10.1
    
    Debt Modification Agreement, effective August 1, 2006, including Commercial
Loan Agreement dated January 3, 2000, between Double Eagle Petroleum Co. and American
National Bank (filed as Exhibit 10.1 to the registrants Quarterly Report on Form 10-Q for
the quarter ended June 30, 2006, and incorporated herein by reference).14.1
    
    Code of Business Conduct and Ethics (filed as Exhibit 99.2 to the registrants
Annual Report on Form 10-KSB for the year ended December 31, 2004, and incorporated herein
by reference).21.1*
    
    Subsidiaries of registrant.23.1*
    
    Consent of Hein & Associates LLP.23.2*
    
    Consent of Netherland, Sewell & Associates.31.1*
    
    Certification of Chief Executive Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.31.2*
    
    Certification of Chief Financial Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.32*
    
    Certification Pursuant to 18 U.S.C. Section 1350 as adopted pursuant to section
906 of the Sarbanes-Oxley Act of 2002.
 
 *
    
    Filed with this Form 10-K.