Escalera Resources (ESCR) 10-K 2006 FY Annual report

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.

(Name of registrant as specified in its charter)

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)

(307) 237-9330

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
None	None

Securities registered pursuant to Section 12(g) of the Act:

Title of each class	Name of each exchange on which registered
$.10 Par Value Common Stock	NASDAQ Global Select Market

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yeso Noþ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yeso Noþ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.þ

Indicate by check mark if the registrant is a large accelerated filer, an accelerated filer, or a non accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filero           Accelerated filerþ        Non-accelerated filero

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).
YesoNoþ

The aggregate market value of the voting common stock held by non-affiliates of the registrant at the close of business on June 30, 2006, was $128,831,587.

The number of shares of the registrant’s common stock outstanding as of March 28, 2007 was 9,141,104 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Certain information required by Items 10, 11, 12, 13 and 14 of Part III is incorporated by reference from portions of the registrant’s definitive proxy statement relating to its 2007 annual meeting of stockholders to be filed within 120 days after December 31, 2006.

DOUBLE EAGLE PETROLEUM CO.
FORM 10-K
TABLE OF CONTENTS

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

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The terms “Double Eagle”, “Company”, “we”, “our”, and “us” refer to Double Eagle Petroleum Co. and its subsidiary, as a consolidated entity, unless the context suggests otherwise. We have included technical terms important to an understanding of our business under “Glossary”, in Items 1 and 2, “Business and Properties”, of this Form 10-K.

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.

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PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

General

We are 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. Our principal properties are located in southwestern Wyoming, where we have coal bed methane reserves and production in the Atlantic Rim area of the Eastern Washakie Basin and tight sands gas reserves and production in the Pinedale Anticline.

Double Eagle was incorporated in the State of Wyoming in January 1972 and reincorporated in the State of Maryland in February 2001. Our common shares have been publicly traded on the NASDAQ Stock Exchange under the symbol “DBLE” since 1995. In December 2006, our common shares began trading on the NASDAQ Global Select Market.

Our principal executive offices are located at 777 Overland Trail, Casper, Wyoming 82601, and our telephone number is (307) 237-9330. Our web site ishttp://www.dble.us.

Overview and Strategy

Our objective is to increase stockholder value by pursuing our corporate strategy of:

• 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.

As of December 31, 2006, we had estimated proved reserves of 48.5 Bcf of natural gas and 360 MBbl of oil, or a total of 50.7 Bcfe, with a PV-10 value of approximately $67.6 million (see reconciliation of the PV-10 non-GAAP financial measure to the standardized measure under Reserves on page 11). Of these reserves, 62% was proved developed and 96% was natural gas. This represents a net increase in reserve volumes of 3.0% and a 46.7% decrease in the PV-10 value from the prior year, due primarily to a pricing decrease for reserve calculation purposes of $3.26 per Mcf of natural gas (while the price per Bbl of oil remained constant), somewhat offset by the increase in reserve volumes from December 31, 2005 to December 31, 2006. Our reserve estimates change continuously and are evaluated by us annually. Changes in the market price of natural gas, as well as the effects of production, acquisitions, dispositions and exploratory development activities may have a significant effect on the quantities and future values of our reserves.

During 2006, we invested $21.5 million in capital expenditures related to exploration and development. For 2007, we have budgeted approximately $50 million for ongoing development programs in the Atlantic Rim and Pinedale Anticline. The increase in budgeted spending represents a 133% increase over 2006. In addition to development of our reserves in our core areas, we believe in engaging in exploratory efforts that may lead to new core areas in the future. The 2007 budget estimate of $50 million does not include the impact of any potential future exploration projects, ongoing exploration/development activities at Christmas Meadows, Cow Creek Unit Deep #2 or South Fillmore, or possible asset purchases. We continually evaluate our opportunities, and if a potential opportunity is identified that complements our identified areas of expertise, it may be pursued.

We expect to fund our future capital expenditures with cash provided by operating activities, funds made available through our $50 million credit facility, and from our $200 million shelf registration statement.

We intend to selectively pursue acquisitions that are strategic to our core areas of operation. Although we have historically grown our reserves and production organically without acquisitions, we continue to evaluate acquisition opportunities that complement our existing operations, offer economies of scale and provide further development, exploitation and exploration opportunities. In addition to potential acquisitions, we may also divest certain non-core assets.

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Operations

As of December 31, 2006, we owned interests in a total of 664 producing wells and had an interest in 556,389 gross acres (252,962 net), of which 433,648 gross acres (247,629 net) are undeveloped, in what we believe are natural gas prone basins of the Rocky Mountains and Nevada. Two developing areas, the Atlantic Rim coal bed natural gas play and the Pinedale Anticline, accounted for over 69% of our proved developed reserves as of December 31, 2006, and over 88% of our 2006 production (net of imbalance activity).

As of December 31, 2006, our estimated acreage holdings by basin are:

Basin	Gross Acres		Net Acres
Greater Green River Basin		199,831		71,968
Hanna Basin		24,947		6,181
Huntington Basin		166,806		164,571
Powder River Basin		44,104		5,687
Wind River Basin		50,986		2,365
Other		69,715		2,190
Total		556,389		252,962

Our focus is in areas where our geological and managerial expertise can provide us with competitive advantages. We intend to grow our reserves and production through our current areas of exploration and development, which are as follows:

The Atlantic Rim Coal Bed Natural Gas Project in south central Wyoming

Since the first test of the Mesaverde coal beds along the Atlantic Rim of the Washakie Basin in south central Wyoming during the year 2000, 165 producing wells have been drilled by Anadarko and 14 producing wells have been drilled by Double Eagle. This resulted in net sales volumes from the Atlantic Rim to Double Eagle of 1.8 Bcf in 2006 (net of prior years’ imbalance activity), which represented 58% of our total 2006 sales volumes. These wells have been very economic, and we will continue development when the Environmental Impact Study (“EIS”) is completed (see further discussion below).

This play is a 40-mile long trend located in south central Wyoming, from the town of Baggs at the south end, to the town of Rawlins at the north end. The Mesaverde coals in this area differ from those found in the Powder River Basin in that they are thinner zones, but have higher gas content much like the coal beds found in the Uinta Basin of Utah where there are several very successful coal bed projects. Nevertheless, the productivity of coal beds is dependent not only on specific natural gas content, but also on favorable permeability to natural gas. The 14 wells that Double Eagle operates have good permeability as they average more than 1,000 Bbls of water per day per gas well. The Company has acquired interests in 53,570 gross acres (30,387 net acres) along the Atlantic Rim.

On December 1, 2006, the final EIS for the Atlantic Rim CBM (coalbed methane) Development was published in the Federal Register. The Bureau of Land Management (“BLM”) has indicated that it plans to issue the Record of Decision in the first half of 2007. The Record of Decision could potentially allow the drilling of 1,800 CBM wells and 200 conventional wells, based on limits of disturbance per section and the entire EIS area. This well count is the original well number proposed by Anadarko, Double Eagle and Warren Resources and provides for development of the area on 80-acre spacing. We plan to start drilling with two rigs in July 2007 and proceed to drill, over a period of three to five years, up to 268 gross new wells, which would constitute 110 net new wells to our interest, and participate in the drilling of additional wells in units operated by Anadarko and Warren Resources, with a possible total allowed by the EIS of 1,800 gross CBM wells (259 net wells to Double Eagle).

Our current areas of development included within the Atlantic Rim are the Cow Creek Field (14 operated wells, in which we own 100% working interest), the Sun Dog Unit (12 non-operated wells, in which we have a 4.545% working interest see additional comments at “Sun Dog Unit” below related to 2007 expected change in interest percentage), and the Doty Mountain Unit (24 non-operated wells, in which we have a 20.55% working interest).

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Cow Creek Field

We acquired a 100% working interest in the Cow Creek Field in the heart of the Atlantic Rim Coal Bed Natural Gas Project from KCS Mountain Resources in April 1999. The field had one producing gas well, the Cow Creek #1-12, which was producing, sporadically, 140 Mcf of gas per day from the Dakota and Frontier Formations at 8,000 feet. In 2000, two wells in the Mesaverde coals were completed. One of these wells produced at an average rate of 58 Mcf per day during August 2000. The other well was converted to a water injection well. We drilled four additional locations in August 2001 and began selling gas in November 2001. While drilling the wells, we encountered excellent gas shows and the coals were cored to evaluate the gas content. We drilled four additional wells in September 2002, which were connected to the sales line in November 2002. We drilled five additional wells in the fall of 2003, and began producing them in 2004. The water to gas ratio is dropping in each of the wells. The five wells drilled around the existing producing wells in the fall of 2003 have helped draw down the reservoir pressure, and we believe they will continue to increase the gas volumes along the crest of the structure.

Double Eagle operates the 14 wells in the Cow Creek Field that produced 2.02 Bcf gross of natural gas in 2006 or an average of 395 Mcf of natural gas per day per well. This resulted in net sales volumes to Double Eagle of 1.617 Bcf in 2006 (compared to 1.646 Bcf in 2005 and 1.448 Bcf in 2004), which represented 54% of our total sales volumes. In December 2006, the 14 wells averaged 371 Mcf per day per well.

Additional drilling is currently on hold until the EIS is completed, which is expected in the first half of 2007. We look forward to being able to drill additional wells in this unit and significantly expand our production from this play. We believe we will be able to drill up to 34 additional producing wells in Cow Creek Field in 2007. After the final Record of Decision is received and we again begin drilling, the Cow Creek Unit will become part of a larger, new unit operated by Double Eagle, the Catalina Unit, which has 268 potential additional drilling locations (110 net to us). The future gas from these wells will be transported to interstate markets via the 13-mile pipeline we constructed in 2005.

Doty Mountain Unit

The Doty Mountain Unit is a coal bed natural gas project located six miles to the northeast of the Cow Creek Field. This unit is a 24,817 acre unit in which Double Eagle owns 3,280 gross and 3,280 net acres of leasehold working interest. We own a 20.55% working interest (calculated giving consideration to wells expected to be hooked up in 2007) in the 3,244 acre Participation Area established for the coal bed natural gas production in the unit. This Participation Area and the associated working interest changes as more wells and acreage are added to the Participation Area. Anadarko drilled and completed 24 wells in this pod and completed the infrastructure at the end of 2004. Gas sales began in March 2005. An additional 27 wells (23 planned producing wells and 4 water injection wells) began drilling during 2006, resulting in 22 producing wells expected to be put on line in 2007. The Mesaverde coals at Doty Mountain are thicker than at Cow Creek and have higher gas contents. Permeability was measured at over 150 millidarcies in the main coal. These wells are dewatering and produced a total of .45 Bcf in 2006,or an average of 51 Mcf per well per day. In December 2006, the 24 wells averaged 54 Mcf per day per well.

We began receiving and selling our share of Doty Mountain production in July 2006. We expect to begin making up our production imbalance for Doty Mountain Unit in early 2007. See Item 15, Note 1 to the Notes to the Consolidated Financial Statements for additional discussion of production imbalances.

Sun Dog Unit

The Sun Dog Unit is adjacent to and east of Cow Creek Field. Anadarko operates the 23,468 acre unit in which Double Eagle owns 3,886 gross and 2,045 net acres of working interest. We own 4.545% working interest in the 1,766 acre Participation Area established for the first coal bed natural gas production in the unit. This Participation Area associated working interest changes as more wells and acreage are added to the Participation Area. Anadarko initially drilled 10 wells in which we originally had no economic interest. The 10 wells have been producing since July 2002. In 2005, Anadarko drilled two additional producers on acreage in which we had an interest. The Participating Area was then established to include our two wells and the 10 Anadarko producers. The success of this area, which is not as structurally advantaged as Cow Creek, helps in evaluating our similar acreage. Additional drilling is scheduled in the Sun Dog Unit after issuance of the Record of Decision. We have been informed by Anadarko that it plans to drill 69 additional producing wells and 6 water injection wells in the Sun Dog Unit during 2007, at which time our interest in the Participating Area is expected

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to increase to 8.3%. During 2006, the 12 wells at the Sun Dog Unit produced a total of 1.62 Bcf of gas, or an average of 369 Mcf per well per day. In December 2006, the 12 wells averaged 357 Mcf per day per well.

We have not received our share of any Sun Dog Unit gas yet. We expect to begin making up our production imbalance for Sun Dog Unit in early 2007. See Item 15, Note 1 to the Notes to the Consolidated Financial Statements for additional discussion of production imbalances.

Other Units

We also have small interests in the Brown Cow, Jolly Roger and Red Rim Units that are all operated by Anadarko. As of December 31, 2006, no significant gas sales had occurred from these units.

Atlantic Rim Exploratory Tests

In addition to development of our existing Atlantic Rim properties, we also engaged in exploratory/development efforts at the Cow Creek Deep #2 (a Madison test near our coalbed natural gas production at Cow Creek) and the South Fillmore prospect just north of Cow Creek.

Cow Creek Deep

In 1959, Sohio drilled the Cow Creek Unit #1 well to the Tensleep and tested natural gas. Sohio elected to produce the much more prolific and permeable Nugget Sandstone at 9,600 feet, and the Tensleep was never completed. Log calculations indicate pay in the Tensleep and, based on those calculations as well as our 3-D seismic survey, a location was selected at what we believed to be the top of the Cow Creek Anticline.

We began drilling the Cow Creek Unit Deep #2 development well, in which we have an 84% working interest, on June 1, 2006, with an expected total depth of 12,360 feet. At the Cow Creek Unit Deep #2 well, we drilled to 9,922 feet and ran casing to that point. We 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.

South Fillmore

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 Field. We are operating the well and have a 100% working interest in the first well, the PH State 16-1, and approximately a 66.67% working interest after payout in any offset wells. The prospect includes six sections of leases encompassing 3,840 acres and a farmout from Anadarko and Warren Resources on two additional sections encompassing 1,280 acres. The target for this well is the Lewis Sandstone and Mesaverde Sandstone and coals.

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 tubing 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 in early 2007.

The Pinedale Anticline in the Green River Basin of Wyoming

The Pinedale Anticline is in southwestern Wyoming, 10 miles south of the town of Pinedale. In the late 1960s, a subsidiary of Questar Corporation, Wexpro, drilled three wells in the Mesa Unit. The wells encountered gas, but the tight formations would not yield gas at a commercial rate. We entered the Pinedale Anticline in 1991, acquiring working and overriding royalty interests from Arco. We also acquired undeveloped leasehold acreage that we sold to Ultra in 1997, retaining an overriding royalty interest. In September 1998, we acquired additional working interests from KCS Mountain Resources. The area remained idle until late 1997 when a new operator, Ultra Petroleum, drilled three wells and used new fracture stimulation techniques developed 20 miles south in the prolific Jonah Field. The production rates were substantially greater than with prior efforts. Wexpro’s affiliate, Questar Exploration, took over operations from Ultra on the Mesa Unit lands

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and began an aggressive development project. Two of the first three wells in this project were drilled on leaseholds in the Mesa “B” Participating Area in which we have an interest. The first well drilled by Questar, the Mesa #3, reached total depth of 13,055 feet on October 4, 1999. The Mesa #3 and the subsequent Mesa #6 well were both completed with initial production rates in excess of 11 MMcf per day.

We are continuing our participation with the operator, Questar, in the development of the Mesa Field on the Pinedale Anticline (73 non-operated wells producing approximately 31% of our total production for 2006). In 2006, the three Participating Areas of the Mesa Unit produced a total of 33.8 Bcf of natural gas and 256 MBbls of oil. Our net production from the Mesa Unit in 2006 was 906 MMcf and 4,455 Bbls of oil. This is a 14.8% decrease from 2005. We also 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 they intend to hook up an additional seven wells as soon as regulations allow in 2007. We believe the operator will drill approximately 15 to 20 additional wells on acreage in which we have an interest in 2007.

In the Mesa “A” Participating Area, where we have an overriding royalty interest, there were 29 producing wells that produced a total of 62 MMcf of natural gas and 1,030 Bbls of oil in 2006 to our interest. Our overriding royalty interest is .312%, with a net acre position of at least 1.875 net acres under a gross of 600 acres in the “A” Participating Area.

In the Mesa “B” Participating Area, where we have an 8% working interest in the shallow producing formations and a 12.5% working interest in the deep producing formations, there were 33 producing wells that produced 596 MMcf of natural gas and 3,330 Bbls of oil in 2006 to our interest. We have a net acre position of 64 net acres under a gross of 800 acres in the shallower formations in the “B” Participating Area and 100 net acres under a gross of 800 acres in the deep producing formations.

In the Mesa “C” Participating Area, where we have a carried 6.4% working interest after payout, 11 wells produced 248 MMcf and 95 Bbls of oil in 2006 to our interest. We have 65.27 net acres under a gross of 1,000 acres in the “C” Participating Area. Payout is on a block basis and will occur whenever profits exceed costs within the participating area. Therefore, we will move in and out of payout as additional wells are drilled. As of December 31, 2006, we are again not in a paid out status, after being in a paid out status for a large portion of 2006.

At year end, we had working interests or overriding royalty interests in 4,840 acres in and around this developing natural gas field. An expansion of the Kern River Pipeline, which was completed in May 2003, connects this field to a large gas market in southern California. It is anticipated that this property will continue to produce significant revenues for us in the foreseeable future.

The Wind River Basin in central Wyoming

Located in central Wyoming, the Wind River Basin is home to Wyoming’s first oil production, which began in 1884. Since that time, numerous fields have been discovered in the Basin, including two very large natural gas accumulations, the Madden Anticline and the Cave Gulch Fields. We have interests in 50,986 gross acres, constituting 2,365 net acres, of leases in this Basin. We were offered an interest in the Madden Sour Gas Participating Area in the Madden Deep Unit and the sour gas plant at Madden Field at an initial cost of approximately $3.5 million. This was considered to be an excellent opportunity at the present natural gas prices, so we have moved forward with the transaction. The Madden Sour Gas Participating Area produced 10.6 Bcf of gas in December 2006 from 7 wells. These are long-lived wells with large producing rates and reserves. Our interest in the Madden Sour Gas Participating Area is currently producing approximately 650 Mcf net daily, with our first receipt of production being November 2006.

Madden Anticline

The Madden Anticline is located in central Wyoming, 65 miles west of the town of Casper. The anticline is 20 miles long and six miles wide laying in the deepest part of the Wind River Basin. Two large natural gas fields, Madden and Long Butte, are being drilled and developed on the anticline. The Madden and Long Butte Units were merged in 2004, but the Long Butte Unit Mesaverde and Cody Participating Areas have remained separate and are operated by Moncrief. The Madden Unit is operated by Conoco/Phillips. We own an approximate 16.67 % working interest in 734.25 acres on the anticline that potentially could be included in the Madden Sour Gas Participating Area. With the current approved participating area, 504.74 gross acres (84.14 net acres) is included in the 24,088 acre participating area. We have a 0.3493% working interest in the deep participating area. Repayment for our gas that was produced and sold from the date at which the Participating Area became effective, February 2002, through October 31, 2006, is being handled through the new operator, Conoco/Phillips. Sulfur sales are not subject to a gas balancing agreement, and, accordingly, we

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received the proceeds for our share of sulfur sales from February 2002 through October 2006, which was $68,000 net to us. We also own interests, which are restricted in depth and size, in over 12,000 additional acres on the Madden Anticline.

Madden Field and Long Butte Field

In 2005, the deep Paleozoic formations, or “Sour Gas” zones, of the Madden Field and Long Butte Field were combined, and they produced 159 Bcf of natural gas in 2006, making the field’s cumulative production over 1.5 trillion cubic feet from six formations at depths of 3,000 to 25,000 feet. In 2006, our net production at Madden was 227.1 MMcfe. The unit’s primary operator, Conoco/Phillips (formerly Burlington Resources), plans to continue to drill additional wells in the unit. Additionally, we operate and produce from one lower Fort Union well and one upper Fort Union well outside of the unit. We will continue to produce these two wells and evaluate the potential for offsets.

South Sand Draw

The South Sand Draw Field is located in the southern portion of the Wind River Basin approximately 36 miles southeast of Riverton, Wyoming. We have been acquiring leases near the field for six years and currently have 1,495 acres under lease, in which our working interest is 75%. In October 1999, we and our partner acquired the final lease and drilled a 6,500 foot test well in spring 2001. The South Sand Draw Unit #11-36 was completed as a Muddy Sandstone producer and in October 2001 began selling gas. Additional drillable prospects exist on the east side of our leasehold and may be drilled, although a final decision has not been made. Our net production at South Sand Draw was 14.6 MMcf in 2006.

The Moxa Arch in southwest Wyoming

We are continuing our participation in further development drilling on the Moxa Arch (126 non-operated wells). On the Moxa Arch, we were involved in 31 development wells with working interests ranging from 0.27% to 16.27% in 2006.

The Christmas Meadows Prospect in Utah

Christmas Meadows is a structural dome in the southwest corner of the prolific Green River Basin, in Summit County, Utah. The dome is overlain by the Wyoming Overthrust Belt and the North Flank Thrust of the Uinta Mountains.

The Christmas Meadows Prospect has a long history. In the 1970s Gulf noted the structure on a regional seismic grid. Further seismic surveys by Gulf, American Quasar, Amoco, Chevron, Sohio, and others support the existence of the structural dome. Amoco staked a location to test the structure to 19,000 feet in 1982, but had still not been issued a permit in 1986 when it abandoned its efforts. We acquired our first leasehold in the prospect in 1984. Chevron formed a federal unit in 1989 and staked a well but abandoned its efforts in 1994 after not getting a permit or offset acreage offered for sale. Chevron turned the project over to Amerac, who designated us as its agent. We purchased the Chevron leasehold and secured farmouts from Amerac (now Unit Corp.) and Judy Yates, and finally acquired the open offset acreage at a BLM auction in November 2003 and obtained a drilling permit. Combined with new leases purchased at lease sales, we have interests in 41,237 gross acres, of which 22,875 gross acres are included in the Table Top Federal Exploratory Unit. Along with our partners, we have acquired licenses to six 2D seismic lines, or 60 miles. Five of the lines, or 53 miles, were reprocessed with state-of-the-art pre-stack depth migration. Imaging and understanding of the structure has improved as a result, although the structure map appears very similar to Chevron’s, American Quasar’s and Amoco’s efforts.

Prospective formations range from depths of 4,000 to 23,000 feet, and range in age from Mississippian to Cretaceous. Source rocks, reservoir rocks, structural timing, seal, as well as structure all remain to be determined through the drill bit, but we are encouraged by our analysis of analogous fields in the Wyoming Overthrust Belt and the Green River Basin. The initial well was originally projected to a depth of 16,000 feet, and we believe it has a high risk, high reward potential. There was also engineering risk to consider, as there is a time deadline once operations commence and the overlying structure is complex and potentially difficult to drill.

We expended considerable resources in preparing to drill this prospect. The update of the EIS was completed in January 2005, clearing the final regulatory hurdle to commence operations. In 2005, after nearly ten years of addressing various regulatory hurdles in this environmentally sensitive area, we and our partner, John Lockridge, began preparing this prospect for drilling. Dirt work was completed and 34 inch conductor pipe was set at a depth of 235 feet. Unit Drilling Company Rig #233 moved in to drill this 16,000 foot test on September 9, 2006. Prior to the commencement of drilling, we sold a portion of our working interest to outside partners, leaving us with 26.16% working interest before payout and 31.26% working interest after payout.

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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.

Nevada

Double Eagle has leased 166,806 gross acres, 164,571 net acres, in the Huntington Valley in Elko and White Pine Counties, Nevada. This area was chosen because of excellent hydrocarbon source rock in both the Tertiary and Paleozoic rocks and high heat flow to generate natural gas, as well as certain natural gas shows incurred in limited previous drilling. This, combined with the indication that a mid-basin structural high area exists, made the open acreage position look attractive. We believe that one well will be drilled in the basin in 2007 by another operator and that we will participate to some extent in the well.

Rattlesnake Prospect

We drilled an exploratory test on the Rattlesnake Prospect in the Powder River Basin in northeastern Wyoming in 2006. It was a 7,200 foot wildcat well located twenty-six miles north of Casper, Wyoming. The Rattlesnake Prospect tested the Pennsylvanian Tensleep Formation, but found no reserves.

Eastern Washakie Midstream Pipeline LLC

In January 2006, we began transporting gas through our intrastate gas pipeline, which was constructed in late 2005 and connects the Cow Creek Field with the pipeline system owned by Southern Star Central Gas Pipeline, Inc. The 13-mile pipeline provides us with full access to the interstate gas markets from southern Wyoming, and also provides us with the ability to move third party gas. The pipeline is expected to provide reliable transportation for future development by us in the Atlantic Rim of the Eastern Washakie Basin.

Other Recent Developments

On December 15, 2006, our application to transfer our securities’ listing from the NASDAQ Capital Market to the NASDAQ Global Select Market became effective. The trading symbol for Double Eagle common shares continues to be “DBLE”.

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.

On January 23, 2007, pursuant to the universal shelf registration statement on Form S-3 described above, we announced the closing of a follow-on public offering of 450,000 shares of Common Stock at a price to the public of $21.55 per share. Double Eagle granted to the underwriter a 30-day option to purchase up to an additional 50,000 shares of common stock to cover over-allotments, which was exercised in full by the underwriter. Proceeds from the offering were approximately $10.1 million, including the underwriter’s exercise of its over-allotment option, after deducting the underwriting discounts and commissions and the estimated offering expenses. The net proceeds from this offering were used to pay down the outstanding indebtedness on our revolving line of credit.

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Reserves

The reserve estimates at December 31, 2006, 2005 and 2004 presented below were reviewed by the independent petroleum engineering firm Netherland, Sewell and Associates, Inc. All reserves are located within the continental United States. For the periods presented, Netherland, Sewell and Associates, Inc. evaluated properties representing a minimum of 98% of our reserves, valued at the total estimated future net cash flows before income taxes, discounted at 10% (“PV-10”). The PV-10 values shown in the following table are not intended to represent the current market value of the estimated proved oil and gas reserves owned by Double Eagle. Reserve estimates are inherently imprecise and are continually subject to revisions based on production history, results of additional exploration and development, prices of oil and gas, and other factors. For more information regarding the inherent risks associated with estimating reserves, see Item 1A, “Risk Factors”.

Oil and gas reserve estimates:

	As of December 31,
	2006			2005			2004
Proved developed oil reserves (Bbls)		254,346			199,931			181,397
Proved undeveloped oil reserves (Bbls)		105,819			128,821			96,658
Total proved oil reserves (Bbls)		360,165			328,752			278,055
Proved developed gas reserves (Mcf)		30,075,467			23,032,277			17,161,577
Proved undeveloped gas reserves (Mcf)		18,421,252			24,202,058			17,773,169
Total proved gas reserves (Mcf)		48,496,719			47,234,335			34,934,746
Total proved gas equivalents (Mcfe) (1)		50,657,709			49,206,847			36,603,076
Present value of estimated future net cash flows before income taxes, discounted at 10% (2)	$	67,639		$	126,776		$	68,605
Reconciliation of non-GAAP financial measure:
PV-10	$	67,639		$	126,776		$	68,605
Less: Undiscounted income taxes		(42,578	)		(74,738	)		(32,972	)
Plus: 10% discount factor		24,972			39,255			15,897
Discounted income taxes		17,606			35,483			17,075
Standardized 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.

The table above also shows our reconciliation of our PV-10 to our standardized measure of discounted future net cash flows (the most directly comparable measure calculated and presented in accordance with GAAP). PV-10 is our estimate of the present value of future net revenues from estimated proved oil and natural gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our oil and natural gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP. Reference should also be made to the Supplemental Oil and Gas Information included in Item 15, Note 6 to the Consolidated Financial Statements for additional information.

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Production

The following table sets forth oil and gas production from our net interests in producing properties for the years ended December 31, 2006, 2005 and 2004. Average production costs in the table do not include pipeline operations costs of $.05/Mcfe which are included in the Consolidated Statement of Operations in the line item Production Costs.

	For the Year Ended December 31,
	2006		2005		2004
Quantities:
Oil (Bbls)		12,729		15,470		16,886
Gas (MMcf)		3,141		2,976		2,560
Average sales price:
Oil ($/Bbl)		57.90		49.26		37.61
Gas($/Mcf)		5.57		6.62		4.85
Average Production Cost ($/Mcfe)		1.11		1.24		0.81
Average Production Tax ($/Mcfe)		0.69		0.82		0.62

Delivery Contracts

Although we do not currently hedge our production prices, we have entered into various fixed delivery contracts at our Cow Creek Field, which reduces our overall exposure to commodity price fluctuations. 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 due to changing commodity prices. As of December 31, 2006, we had sales delivery contracts in effect for approximately 57% of our current daily production (volume and daily production are expressed in Mcf):

	Remaining
	Contractual		Daily				Fixed
Property	Volume		Production		Term		Price/Mcf
Cow Creek		90,000		1,000		07/06 - 03/07	$	5.42
		90,000		1,000		07/06 - 03/07	$	6.28
		181,000		1,000		07/06 - 06/07	$	5.94
		181,000		1,000		07/06 - 06/07	$	6.32
		304,000		1,000		11/06 - 10/07	$	5.84
Company Total		846,000

We also have a transportation agreement for all production volumes through our pipeline, for which we receive a third party fee per Mcf of gas transported.

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Productive Wells

The following table categorizes certain information concerning the productive wells in which we owned an interest as of December 31, 2006. For purposes of this table, wells producing both oil and gas are shown in both columns. We operate 27 wells in the state of Wyoming. We do not operate producing wells in any other state.

	Oil				Gas
State	Gross		Net		Gross		Net
Colorado		—		—		2		0.0590
Mississippi		2		0.0009		—		—
Montana		2		0.0960		—		—
North Dakota		23		0.2965		—		—
Oklahoma		—		—		2		0.0065
Utah		—		—		1		0.0200
Wyoming		86		5.9940		604		33.1914
Total		113		6.3874		609		33.2769

Drilling Activity

We drilled or participated in the drilling of wells as set forth in the following table for the periods indicated. In certain of the wells in which we participate, we have an overriding royalty interest and no working interest.

	For the Year Ended December 31,
	2006				2005				2004
	Gross		Net		Gross		Net		Gross		Net
Exploratory
Oil		—		—		—		—		1		—
Gas		2		1.26		25		0.62		38		6.61
Dry Holes		1		0.33		—		—		—		—
Water Injection		—		—		3		2.02		2		0.52
Other		—		—		—		—		—		—
		3		1.59		28		2.64		41		7.13
Development
Oil		—		—		—		—		1		0.03
Gas		87		7.32		75		1.13		64		2.78
Dry Holes		1		0.21		—		—		—		—
Water Injection		4		0.82		—		—		4		1.14
Other		—		—		—		—		1		0.05
		92		8.35		75		1.13		70		4.00
Total		95		9.94		103		3.77		111		11.13

All our drilling activities are conducted on a contract basis with independent drilling contractors.

Finding and Development Costs

For the year ended December 31, 2006, we increased our proved reserves by 10.4 Bcfe. During the same period, we expended $16.0 million in finding and development costs, defined as development and exploration costs incurred by the Company during 2006. This activity resulted in a one year finding and development cost in 2006 of $1.54 per Mcfe. “Finding and development costs per Mcfe” is determined by dividing our annual development costs incurred and exploration costs incurred on projects completed during the year by gross proved reserve additions, including both developed and undeveloped reserves added during the current year (gross amounts, not net of production). We use this measure as one indicator of the overall effectiveness of exploration and development activities. In determining the finding and development costs per Mcfe for the years ended December 31, 2006, 2005, and 2004, total proved reserve additions consisted of (expressed in Mcfe):

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

Proved reserves were added in each of 2006, 2005 and 2004 through both gross-incremental additions associated with our higher density spacing of prospective drilling locations on our properties, as well as through our development drilling activities.

Our finding and development cost per Mcfe measure has certain limitations. Consistent with industry practice, our finding and development costs have historically fluctuated on a year-to-year basis based on a number of factors including the extent and timing of new discoveries and property acquisitions. Due to the timing of proved reserve additions and timing of the related costs incurred to find and develop our reserves, our finding and development costs per Mcfe measure often includes quantities of reserves for which a majority of the costs of development have not yet been incurred. Conversely, the measure also often includes costs to develop proved reserves that had been added in earlier years. Finding and development costs, as measured annually, may not be indicative of our ability to economically replace oil and natural gas reserves because the recognition of costs may not necessarily coincide with the addition of proved reserves. Our finding and development costs per Mcfe may also be calculated differently than the comparable measure for other oil and gas companies.

Acreage

The following tables set forth the gross and net acres of developed and undeveloped oil and gas leases in which Double Eagle had working interests and royalty interests as of December 31, 2006. Undeveloped acreage includes leasehold interests that may have been classified as containing proved undeveloped reserves.

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Acreage by Working Interest:

	Developed Acres (1)				Undeveloped Acres (2)				Total Acres
State	Gross		Net		Gross		Net		Gross		Net
Colorado		—		—		80		80		80		80
Montana		29		1		1,892		1,135		1,921		1,136
North Dakota		2,240		49		2,560		64		4,800		113
Utah		637		16		46,440		26,447		47,077		26,463
Wyoming		106,282		5,042		126,237		53,076		232,519		58,118
Nevada		—		—		166,806		164,571		166,806		164,571
Total		109,188		5,108		344,015		245,373		453,203		250,481

Acreage by Royalty Interest:

	Developed Acres (1)				Undeveloped Acres (2)				Total Acres
State	Gross		Net		Gross		Net		Gross		Net
Colorado		155		5		1,920		320		2,075		325
Mississippi		160		1		—		—		160		1
Montana		611		15		—		—		611		15
North Dakota		1,523		40		5,313		243		6,836		283
Oklahoma		640		2		—		—		640		2
Utah		—		—		51,311		51		51,311		51
Wyoming		10,464		162		31,089		1,642		41,553		1,804
Total		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.

Substantially all of the leases summarized in the preceding table will expire at the end of their respective primary terms unless the existing leases are renewed or production has been obtained from the acreage subject to the lease prior to that date, in which event the lease will remain in effect until the cessation of production.

The following table sets forth the gross and net acres subject to leases summarized in the preceding table that will expire during the periods indicated:

	Expiring Acreage
Fiscal Year	Gross		Net
2007		15,669		11,498
2008		2,612		2,612
2009 and later		538,108		238,852
Total		556,389		252,962

Marketing and Major Customers

The principal products produced by us are natural gas and crude oil, which products are marketed and sold primarily to purchasers that have access to nearby pipeline facilities. Typically, oil is sold at the wellhead at field-posted prices and

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natural gas is sold both (i) under contract at negotiated prices based upon factors normally considered in the industry (such as distance from well to pipeline, pressure, quality); and (ii) at spot prices. As of December 31, 2006, there were 846,000 Mcf of future production volumes under contract at prices ranging from $5.42 to $6.32 per Mcf.

The marketing of most of our products is performed by a third party marketing company, Summit Energy, LLC. During the years ended December 31, 2006, 2005 and 2004, sales to Summit Energy accounted for 75%, 68% and 76%, respectively, of our total oil and gas production revenue. There were no other companies that purchased more than 10% of our oil and gas production. Although a substantial portion of our production is purchased by one customer, we do not believe the loss of this customer would have a material adverse effect on our business as other customers would be accessible to us.

Title to Properties

Substantially all of our working interests are held pursuant to leases from third parties. A title opinion is usually obtained prior to the commencement of drilling operations on properties. We have obtained title opinions or conducted a thorough title review on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. The majority of the value of our properties is subject to a mortgage under our credit facility, customary royalty interests, liens for current taxes, and other burdens that we believe do not materially interfere with the use of or affect the value of such properties. We also perform a title investigation before acquiring undeveloped leasehold interests.

Seasonality

Generally, but not always, the demand and price levels for natural gas increase during the colder winter months and decrease during the warmer summer months. Pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations.

We have entered into various fixed delivery contracts for a portion of our production, which reduces our overall exposure to seasonal demand and resulting commodity price fluctuations. The duration of our various fixed delivery contracts depends on our view of market conditions, available contract prices and our operating strategy. As of December 31, 2006, we had sales delivery contracts in effect for approximately 57% of our current daily production.

Competition

The oil and gas industry is extremely competitive, particularly in the acquisition of prospective oil and natural gas properties and oil and gas reserves. Our competitive position also depends on our geological, geophysical and engineering expertise, and our financial resources. We believe that the location of our leasehold acreage, our exploration, drilling and production expertise and the experience and knowledge of our management and industry partners enable us to compete effectively in our current operating areas. Currently, access to incremental drilling equipment in certain regions is difficult, but is not, at this time, anticipated to have any material negative impact on our ability to deploy our capital drilling budget for 2007.

Government Regulations

Regulation of Production, Sales and Transportation of Natural Gas and Oil

Natural gas and oil operations are subject to various federal, state and local governmental and environmental regulations that may change from time to time, including, but not limited to, regulations governing natural gas and oil production, federal and state regulations governing environmental quality and pollution control and state limits on allowable rates of production by well or proration unit. These regulations may affect the amount of natural gas and oil available for sale, the availability of adequate pipeline and other regulated transportation and processing facilities and the marketing of competitive fuels. State and federal regulations generally are intended to prevent waste of natural gas and oil, protect rights to produce natural gas and oil between owners in a common reservoir, control the amount of natural gas and oil produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted.

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Federal legislation and regulatory controls have historically affected the manner in which our production is transported. Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission (“FERC”) regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated natural gas prices for all “first sales” of natural gas, including all sales of our production. As a result, all of our domestically produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may be in effect. The FERC’s jurisdiction over interstate natural gas transportation, however, was not affected by the Decontrol Act. Our sales of oil and natural gas are not currently regulated and are made at market prices.

We participate in a substantial percentage of our wells on a non-operated basis, and may be accordingly limited in our ability to control some risks associated with these natural gas and oil operations. We believe that operations where we own interests, whether operated or not, comply in all material respects with the applicable laws and regulations and that the existence and enforcement of these laws and regulations have no more restrictive an effect on our operations than on other similar companies in the energy industry.

Additional proposals and proceedings that might affect the oil and gas industry are pending before Congress, the FERC, the Minerals Management Service, state commissions and the courts. We cannot predict when or whether any such proposals may become effective or the overall effect any laws or regulations resulting from these proposals and proceedings may have on our operations.

No material portion of our business is currently subject to re-negotiation of profits or termination of contracts or subcontracts at the election of the federal government.

Environmental Laws and Regulations

Our operations are subject to numerous federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on specified lands within wilderness, wetlands and other protected areas, require remedial measures to mitigate pollution from former operations, such as pit closure and plugging abandoned wells, and impose substantial liabilities for pollution resulting from production and drilling operations. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly waste handling, disposal and cleanup requirements, our business and prospects could be adversely affected. At this time, we have no plans to make any material capital expenditures for environmental control facilities.

The National Environmental Policy Act (“NEPA”) requires a thorough review of the environmental impacts of “major federal actions” and a determination of whether proposed actions on federal land would result in “significant impact”. For oil and gas operations on federal lands or requiring federal permits, NEPA review can increase the time for obtaining approval and impose additional regulatory burdens on the natural gas and oil industry, thereby increasing our costs of doing business and our profitability. The federal Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also know as the “Superfund” law, imposes liability, without regard to fault, on certain classes of persons with respect to the release of a “hazardous substance” into the environment. Our operations may also be subject to the Endangered Species Act, the National Historic Preservation Act and a variety of other federal, state and local review, mitigation, permitting, reporting, and registration requirements relating to protection of the environment. We believe that we, as operators, and the outside operators with which we do business are in substantial compliance with current applicable federal, state and local environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse effect on us. Nevertheless, changes in environmental laws have the potential to adversely affect operations.

Employees and Office Space

As of December 31, 2006, we had 17 full-time employees. None of our employees is subject to a collective bargaining agreement, and we consider our relations with our employees to be excellent. We own 6,765 square feet of office space in Casper, Wyoming, which serves as the corporate and operations headquarters. We lease 3,932 square feet of office space in Denver, Colorado, for our administrative offices.

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Available Information

Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, and amendments to reports filed or furnished pursuant to Sections 13(a) and 15(d) of the Securities Exchange Act of 1934, as amended, are available on our website athttp://www.dble.us/, as soon as reasonably practicable after we electronically file such reports with, or furnish those reports to, the Securities and Exchange Commission. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and amendments to reports are available free of charge by writing to:

Double Eagle Petroleum Co.
John Campbell, Investor Relations
1675 Broadway, Suite 2200
Denver, CO 80202

We maintain a code of ethics applicable to our Board of Directors, principal executive officer, and principal financial officer, as well as all of our other employees. A copy of our Code of Business Conduct and Ethics and our Whistleblower Procedures may be found on our website athttp://www.dble.us/, under the Corporate Governance section. These documents are also available in print to any shareholder who requests them. Requests for these documents may be submitted to the above address.

Glossary

The terms defined in this section are used throughout this Annual Report on Form 10-K.

3-D seismic or 3-D data.Seismic data that are acquired and processed to yield a three-dimensional picture of the subsurface.

Bbl.One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf.Billion cubic feet, used in reference to natural gas.

Bcfe.Billion cubic feet of gas equivalent. Gas equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.

Boe.Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.

Darcy.A standard unit of measure of permeability of a porous medium.

Dip meter.A wireline well log that measures the orientation of each rock layer in a well.

Development well.A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive in an attempt to recover proved undeveloped reserves.

Dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Estimated net proved reserves.The estimated quantities of oil, gas and gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Exploratory well.A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir beyond its known extent.

Field.An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition

Gross acre.An acre in which a working interest is owned.

Gross well.A well in which a working interest is owned.

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MBbl.One thousand barrels of oil or other liquid hydrocarbons.

Mcf.One thousand cubic feet.

Mcfe. One thousand cubic feet of gas equivalent. Gas equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.

Millidarcy.One thousandth of a darcy and is a commonly used unit for reservoir rocks. See definition of darcy above.

MMcf.One million cubic feet.

MMcfe.One million cubic feet of gas equivalent. Gas equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.

MMBtu.One million British Thermal Units. A British Thermal Unit is the amount of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

Net acres or net wells.The sum of our fractional working interests owned in gross acres or gross wells.

Permeability.The ability, or measurement of a rock’s ability, to transmit fluids, typically measured in darcies or millidarcies. Formations that transmit fluids readily, such as sandstones, are described as permeable and tend to have many large, well-connected pores. Impermeable formations, such as shales and siltstones, tend to be finer grained or of a mixed grain size, with smaller, fewer, or less interconnected pores.

Productive well.A well that is producing oil or gas or that is capable of production.

Proved developed reserves.Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves.The estimated quantities of oil, gas and gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves.Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

PV-10 value.The present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure calculation, it does provide an indicative representation of the relative value of the company on a comparative basis to other companies and from period to period.

Recompletion.The completion for production from an existing wellbore in another formation other than that in which the well has previously been completed.

Royalty.The share paid to the owner of mineral rights expressed as a percentage of gross income from oil and gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well.

Royalty interest.An interest in an oil and gas property entitling the owner to shares of oil and gas production free of costs of exploration, development and production.

Undeveloped acreage.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 estimated net proved reserves.

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Velocity.The rate at which a wave travels through a medium. Its usage in geophysics is as a property of a medium-i.e., distance divided by travel time. Velocity can be determined from laboratory measurements, acoustic logs, vertical seismic profiles or from velocity analysis of seismic data. Velocity can vary vertically, laterally and azimuthally in anisotropic media such as rocks, and tends to increase with depth in the Earth because compaction reduces porosity.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to share in the production.

ITEM 1A. RISK FACTORS

Investing in our securities involves risk. In evaluating the Company, careful consideration should be given to the following risk factors, in addition to the other information included or incorporated by reference in this annual report. Each of these risk factors could materially adversely affect our business, operating results or financial condition, as well as adversely affect the value of an investment in our common stock. In addition, the ‘‘Forward-Looking Statements’’ located in this Form 10-K, and the forward-looking statements included or incorporated by reference herein describe additional uncertainties associated with our business.

We cannot predict the future price of oil and natural gas and an extended decline in prices could hurt our business prospects.

Our revenues, profitability and liquidity are substantially dependent upon prevailing prices for natural gas and oil, which can be extremely volatile and in recent years have been depressed by excess total domestic and imported supplies. Prices also are affected by actions of federal, state and local agencies, the United States and foreign governments, and international cartels. In addition, sales of oil and natural gas are seasonal in nature, leading to substantial differences in cash flow at various times throughout the year. These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil and natural gas. Any substantial or extended decline in the price of oil and/or natural gas would have a material adverse effect on our financial condition and results of operations, including reduced cash flow and borrowing capacity. All of these factors are beyond our control.

We could be adversely impacted by a variety of changes in the oil and gas market which are beyond our control.

The marketability of our oil and gas production depends in part upon the availability, proximity and capacity of gas gathering systems, pipelines and processing facilities. Federal and state regulation of oil and gas production and transportation, general economic conditions, changes in supply and changes in demand all could adversely affect our ability to produce and market oil and natural gas. If market factors were to change dramatically, the financial impact could be substantial because we would incur expenses without receiving revenues from the sale of production. The availability of markets is beyond our control.

We may be unable to find additional reserves, which would adversely impact our revenues.

Our revenues depend on whether we acquire or find additional reserves. Unless we acquire properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced. Our planned exploration and development projects may not result in significant additional reserves.

We may be unable to fund our planned capital expenditures.

We spend and will continue to spend a substantial amount of capital for the acquisition, exploration, exploitation, development and production of oil and gas reserves. We have historically addressed our short and long-term liquidity needs through the use of cash flow provided by operating activities, borrowing under bank credit facilities, and the issuance of equity. Without adequate financing we may not be able to successfully execute our operating strategy. The availability of these sources of capital will depend upon a number of factors, some of which are beyond our control. These factors include:

• general economic and financial market conditions;

• oil and natural gas prices; and

• our market value and operating performance.

We may be unable to execute our operating strategy if we cannot obtain adequate capital. If low oil and natural gas prices, lack of adequate gathering or transportation facilities, operating difficulties or other factors, many of which are beyond our

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control, cause our revenues and cash flows from operating activities to decrease, we may be limited in our ability to spend the capital necessary to complete our capital expenditures program.

Our industry experiences numerous operating hazards that could result in substantial losses.

The exploration, development and operation of oil and gas properties also involve a variety of operating risks including the risk of fire, explosions, blowouts, cratering, pipe failure, abnormally pressured formations, natural disasters, acts of terrorism or vandalism, and environmental hazards, including oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. These industry related operating risks can result in injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations which could result in substantial losses.

We maintain insurance against some, but not all, of the risks described above. Such insurance may not be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. Acts of terrorism and certain potential natural disasters may change our ability to obtain adequate insurance coverage. The occurrence of a significant event that is not fully insured or indemnified against could materially and adversely affect our financial condition and operations.

New government regulation and environmental risks could increase our cost of doing business.

The production and sale of oil and gas are subject to a variety of federal, state and local government regulations. These include:

• 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.

Many jurisdictions have at various times imposed limitations on the production of oil and gas by restricting the rate of flow for oil and gas wells below their actual capacity to produce. Because current regulations covering our operations are subject to change at any time, and despite our belief that we are in substantial compliance with applicable environmental and other government laws and regulations, we may incur significant costs for compliance in the future.

Our prices may be impacted adversely by new taxes.

The federal, state and local governments in which we operate impose taxes on the oil and gas products we sell. In the past, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. In addition, many states have raised state taxes on energy sources and additional increases may occur. We cannot predict whether any of these measures would have an adverse impact on oil and natural gas prices.

Our reserves and future net revenues may differ significantly from our estimates.

The estimates of reserves and future net revenues are not exact and are based on many variable and uncertain factors; therefore, the estimates may vary substantially from the actual amounts depending, in part, on the assumptions made and may be subject to adjustment either up or down in the future. The actual amounts of production, revenues, taxes, development expenditures, operating expenses, and quantities of recoverable oil and gas reserves to be encountered may vary substantially from the estimated amounts. In addition, estimates of reserves are extremely sensitive to the market prices for oil and gas.

Acquisitions are a part of our business strategy and are subject to the risks and uncertainties of evaluating recoverable reserves and potential liabilities.

We could be subject to significant liabilities related to acquisitions. The successful acquisition of producing and non-producing properties requires an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, future oil and gas prices, operating costs and potential environmental and other liabilities, title issues and other factors. It generally is not feasible to review in detail every individual property included in an acquisition. Ordinarily, a review is focused on higher valued properties. Further, even a detailed review of all properties and records

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may not reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not always inspect every well we acquire, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is performed. We cannot assure you that our future acquisition activity will not result in disappointing results.

In addition, there is strong competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our strategy of completing acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to pursue our acquisition strategy may be hindered if we are not able to obtain financing or regulatory approvals.

Acquisitions often pose integration risks and difficulties. In connection with future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations. Possible future acquisitions could result in our incurring additional debt, contingent liabilities and expenses, all of which could have a material adverse effect on our financial condition and operating results.

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.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment and supplies are sometimes greater and their availability may be limited. As a result of increasing levels of exploration and production in response to strong prices of crude oil and natural gas, the demand for oilfield services has risen and the costs of these services has increased.

We do not control all of our operations and development projects.

Certain all of our business activities are conducted through operating agreements under which we own partial interests in oil and natural gas wells.

If we do not operate wells in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The failure of an operator of our wells to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s:

• timing and amount of capital expenditures;

• expertise and financial resources;

• inclusion of other participants in drilling wells; and

• use of technology.

Since we do not have a majority interest in most wells we do not operate, we may not be in a position to remove the operator in the event of poor performance.

Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial and other resources than we do.

We operate in the highly competitive areas of oil and natural gas exploration, development and production. We face intense competition from both major and other independent oil and natural gas companies in each of the following areas:

• 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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Many of our competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to develop and exploit our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment.

We depend on key personnel.

We are highly dependent on the services of Stephen H. Hollis, our President and Chief Executive Officer. The loss of Mr. Hollis could have a material adverse effect on us. We carry “key man” life insurance on Mr. Hollis in the amount of $1,000,000. Furthermore, competition for experienced personnel is intense. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected.

There is limited liquidity in our shares.

There is a limited market for our shares of common stock and an investor may not be able to liquidate his or her investment regardless of the necessity of doing so. The price of our shares is highly volatile. This could have an adverse effect on developing and sustaining the market for our securities. If the market price of our common stock declines significantly, you may be unable to resell your common stock at or above the public offering price. We cannot assure you that the market price of our common stock will not fluctuate or decline significantly, including a decline below the public offering price, in the future. In addition, the stock markets in general can experience considerable price and volume fluctuations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

We are not a party to any legal proceeding (nor is our property subject of a pending legal proceeding) other than routine litigation incidental to our business that may arise from time to time.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

There were no matters submitted to a vote of security holders during the quarter ended December 31, 2006.

PART II

ITEM 5. MARKET FOR REGRISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURTIES.

Market Information.Our Common Stock is currently traded on the NASDAQ Global Select Market under the symbol “DBLE”. Prior to December 15, 2006, and since 1995, our Common Stock traded on the NASDAQ Capital Market under the symbol “DBLE”.

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The range of high and low sales prices for our Common Stock for each quarterly period from January 1, 2004 through December 31, 2006, as reported by the NASDAQ Stock Market, is:

Quarter Ended	High		Low
December 31, 2006	$	29.50	$	18.05
September 30, 2006		20.52		15.89
June 30, 2006		19.40		14.04
March 31, 2006		20.68		15.00
December 31, 2005	$	24.75	$	17.50
September 30, 2005		25.10		17.15
June 30, 2005		22.75		15.69
March 31, 2005		21.99		15.53
December 31, 2004	$	20.43	$	14.48
September 30, 2004		18.36		13.60
June 30, 2004		15.45		12.20
March 31, 2004		16.60		11.53

On March 28, 2007, the closing sales price for the Common Stock as reported by the NASDAQ Global Select Market was $18.61 per share.

Holders. On March 28, 2007, the number of holders of record of our common stock was 1,349.

Dividends. We have not paid or declared any cash dividends on our common stock in the past and do not intend to pay or declare any cash dividends in the foreseeable future. We currently intend to retain future earnings for the future operation and development of our business including exploration, development and acquisition activities.

Equity Compensation Plans.The following table provides information as of December 31, 2006 with respect to shares of common stock that may be issued under our existing equity compensation plans. We have four equity compensation plans—the 1996 Stock Option Plan, the 2000 Stock Option Plan, the 2002 Stock Option Plan and the 2003 Stock Option and Compensation Plan.

					(c)
					Number of securities
	(a)		(b)		remaining available
	Securities to		Weighted-		for future issuance
	be issued		average		under equity
	upon exercise		exercise		compensation plans
	of		price of		(excluding securities
	outstanding		outstanding		reflected in column
Plan 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.Since the filing of our quarterly report on Form 10-Q for the third quarter of 2006, we have not sold any unregistered securities, nor have we issued any stock options, the sale and/or issuance of which was required to be reported in a Form 8-K or in this Form 10-K.

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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)

The total return assumes that dividends were reinvested quarterly and is based on a $100 investment on December 31, 2001. During the five year period ended December 31, 2006, Double Eagle’s common stock cumulative annual growth rate was 46.5%, compared to 4.8% for the NASDAQ U.S. Index and 32.7% for our Peer Group.

The Peer Group Index is comprised of the following companies, which are selected by Company management: Abraxas Petroleum Corp., American Oil & Gas, Aurora Oil & Gas Corp., Brigham Exploration Co., Contango Oil & Gas Company, Credo Petroleum Corp., Dune Energy Inc., Exploration Co. of Delaware Inc., FX Energy Inc., Gasco Energy Inc., GMX Resources Inc., Quest Resource Corp., and Teton Energy Corp.

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ITEM 6. SELECTED FINANCIAL DATA

The following selected financial information should be read in conjunction with our financial statements and the accompanying notes.

													Year ended
	Year Ended December 31,												August 31,
	2006			2005			2004			2003			2002			(1)
	(In thousands, except per share and volume data)
Statement of Operations Information
Total operating revenues	$	19,032		$	20,496		$	13,267		$	6,138		$	2,270
Income (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 Information
Total assets	$	64,406		$	44,211		$	30,969		$	23,955		$	9,765
Line of credit	$	13,221		$	3,000		$	—		$	—		$	—
Total long-term liabilities	$	17,184		$	5,732		$	583		$	359		$	2,250
Stockholders’ equity	$	33,042		$	29,778		$	24,927		$	19,856		$	6,377
Cash Flow Information
Net cash provided by (used in):
Operating activities	$	10,951		$	10,319		$	7,434		$	3,239		$	119
Investing activities	$	(22,241	)	$	(16,259	)	$	(7,377	)	$	(8,769	)	$	(5,034	)
Financing activities	$	10,470		$	3,701		$	692		$	8,318		$	4,923
Total proved reserves
Oil (MBbl)		360			329			278			209			183
Gas (MMcf)		48,497			47,234			34,935			22,819			11,502
MMcfe		50,657			49,207			36,603			24,073			12,600
Net production volumes
Oil (Bbl)		12,729			15,470			16,886			17,344			20,566
Gas (Mcf)		3,140,653			2,976,094			2,559,557			1,320,850			1,009,543
Mcfe		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.

We have never declared cash dividends on our common shares.

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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

We are an independent energy company engaged in the exploration, development, production and sales of natural gas and crude oil, primarily in the Rocky Mountain Basins of the western United States. Our principal properties are located in southwestern Wyoming. We have coal bed methane reserves and production in the Atlantic Rim Area of the Eastern Washakie Basin and tight gas reserves and production in the Pinedale Anticline.

As of December 31, 2006, we had estimated proved reserves of 48.5 Bcf of natural gas and 360 MBbl of oil, or a total of 50.7 Bcfe, with a PV-10 value of approximately $67.6 million (see reconciliation of the PV-10 non-GAAP financial measure to the standardized measure under the heading Reserves on page 11). As of December 31, 2006, we controlled approximately 245,373 net undeveloped acres, representing approximately 97% of our total net acreage position.

We intend to increase our reserves, production, revenues, and cash flow by focusing on: (i) new coal bed methane gas development and enhancement of field facilities on operated and non-operated properties in the Atlantic Rim; (ii) continued participation in the development of the Mesa Field on the Pinedale Anticline; (iii) selective pursuit of high potential exploration projects where we have accumulated detailed geological knowledge; and (iv) selective pursuit of strategic acquisitions that may expand or complement our existing operations.

Developments since December 31, 2005:

Fiscal year 2006 was a year spent investing in our future, both in terms of the development of our existing properties and the commencement of several exploratory drilling projects.

We participated in an active oil and gas development program within our core areas in 2006:

• 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%.

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In addition to development of our existing properties, we also engaged in exploratory efforts at the Christmas Meadows prospect in northeastern Utah, the South Fillmore prospect just north of Cow Creek and the Rattlesnake prospect in Wyoming:

• 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.

In January 2006, we began transporting gas through our intrastate gas pipeline, which was constructed in late 2005 and connects the Cow Creek Field with the pipeline system owned by Southern Star Central Gas Pipeline, Inc. The 13-mile pipeline provides us with full access to the interstate gas markets from southern Wyoming, and also provides us with the ability to move third party gas. The pipeline was constructed at a cost of approximately $5,412 and will provide reliable transportation for future development by us in the Atlantic Rim.

We account for gas imbalances under the entitlement method, whereby a working interest owner records revenue based on its share of entitled production, which is not always the amount of production the owner receives from month to month. 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 an 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. We intend to start recouping our under-taken production in early 2007 and believe we can make up the entire balance in 2007. Since the receivable is valued at $3.13 per Mcf, any price actually realized above that amount will be recorded as additional revenues at that time. The under-produced owner controls when the amounts are recouped, so we cannot predict when the payable will be liquidated.

We were offered a 0.3493% interest in the Madden Sour Gas Participating Area in the Madden Deep Unit and the sour gas plant at Madden Field in the Wind River Basin in Wyoming at an initial cost of approximately $3.5 million, as part of the combination of the Madden Field and the Long Butte Field deep Paleozoic formations. This was considered to be an excellent opportunity at the present natural gas prices, so we moved forward with the transaction. The Madden Sour Gas Participating Area produced 119 Bcf of gas in 2006 from 7 wells. These are long-lived wells with large producing rates and reserves. Our interest in the Madden Sour Gas Participating Area is currently producing approximately 650 Mcf net daily to us, with our first receipt of production being for November 2006.

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On December 1, 2006, the final EIS for the Atlantic Rim CBM (coalbed methane) Development was published in the Federal Register. The BLM has indicated that it plans to issue the Record of Decision in the first half of 2007. Drilling can proceed after the Record of Decision is issued. The Record of Decision could potentially allow the drilling of 1,800 CBM wells and 200 conventional wells, based on limits of disturbance per section and the entire EIS area. This well count is the original well number proposed by Anadarko, Double Eagle and Warren Resources and provides for development of the area on 80-acre spacing. Double Eagle expects to drill 268 gross wells (110 net wells) in its Catalina Unit and participate in the drilling of additional wells in units operated by Anadarko and Warren Resources, with a possible total of 1,800 gross CBM wells (259 net wells to Double Eagle). We have been informed by Anadarko that it plans to drill 69 additional producing wells (5.7 net to Double Eagle) in the Sun Dog Unit during 2007, at which time our interest in that unit increases to 8.3%.

On January 23, 2007, pursuant to the universal shelf registration statement on Form S-3 for $200 million filed on December 15, 2006, we announced the closing of a follow-on public offering of 450,000 shares of Common Stock at a price to the public of $21.55 per share. Double Eagle granted the underwriter a 30-day option to purchase up to an additional 50,000 shares of common stock to cover over-allotments, which was exercised in full by the underwriter. Proceeds from the offering were approximately $10.1 million, including the underwriter’s exercise of its over-allotment option, after deducting the underwriting discounts and commissions and the estimated offering expenses. We used the net proceeds from this offering to pay down the outstanding indebtedness on our revolving line of credit.

Our Industry:

The exploration for, and the acquisition, development, production, and sale of, natural gas and crude oil is highly competitive and capital intensive. As in any commodity business, the market price of the commodity produced and the costs associated with finding, acquiring, extracting, and financing the operation are critical to profitability and long-term value creation for stockholders. Generating reserve and production growth while containing costs represents an ongoing focus for management, and is made particularly important in our business by the natural production and reserve decline associated with oil and gas properties. In addition to developing new reserves, we compete to acquire additional reserves, which involve judgments regarding recoverable reserves, future oil and gas prices, operating costs and potential environmental and other liabilities, title issues and other factors. During periods of historically high oil and gas prices, third party contractor and material cost increases are more prevalent due to increased competition for goods and services. Other challenges we face include attracting and retaining qualified personnel, gaining access to equipment and supplies and maintaining access to capital on sufficiently favorable terms.

We have taken the following steps to mitigate the challenges we face:

• 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.

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Development Outlook for 2007:

Atlantic Rim.We believe that the Record of Decision for the Atlantic Rim CBM Development EIS will be issued in the first half of 2007, which will allow all parties that operate properties in the Atlantic Rim to resume drilling July 15, 2007. Our plans are to drill up to 34 new wells in the Catalina Unit. We have already contracted to have two rigs working full time in the field beginning July 15. The costs of the wells are estimated to be from $525 to $638 per well, with additional costs incurred for the infrastructure (including water treatment, gathering, compression, electricity and roadwork) in the Catalina Unit in 2007 of approximately $15,000. Anadarko plans to complete the drilling in the Doty Mountain Unit that it began in 2006 (expected to result in 22 new producing wells in 2007), which changed our interest in the unit to 20.55%. Anadarko has also informed us that it intends to drill 75 wells (69 producing and 6 water injection wells) during 2007 in the Sun Dog Unit, at an average cost of approximately $1,000 per well. Anadarko will have three rigs working in the Sun Dog Unit beginning July 15. As the drilling in Sun Dog begins, our interest in that unit will increase to 8.3%.

Pinedale Anticline.Since we are not the operator in the Pinedale Anticline, we must rely on historical activity levels and representations made by the operator (Questar) related to estimating expected completion and drilling activity in 2007. The operator has informed us that the seven remaining wells that were drilled in late 2006 will be completed and hooked up as soon as possible in 2007, with the remainder shortly thereafter. We believe that 15 to 20 wells in which we have an interest will be drilled in the Pinedale Anticline in 2007.

Other.Depending on the results of our ongoing drilling/testing at Christmas Meadows, Cow Creek Unit Deep #2 and South Fillmore, additional development drilling projects may also be possible in 2007.

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RESULTS OF OPERATIONS

The table below provides a year-to-year overview of selected reserve, production and financial information. The information contained in the table below should be read in conjunction with our consolidated financial statements and accompanying notes included in this Form 10-K.

	As of, and for the year ended, December 31,									Percent change between years
	2006			2005			2004			2005 to 2006			2004 to 2005
Excluding Imbalance Activity:
Net production volumes
Oil (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 production
Mcfe		8,140			8,408			7,290			-3	%		15	%
Including Imbalance Activity:
Net production volumes
Oil (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 production
Mcfe		8,814			8,408			7,290			5	%		15	%
Average price per unit production
Oil (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 revenues
Oil 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 costs
Production 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 basis
Average 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	%

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Year ended December 31, 2006 compared to the year ended December 31, 2005

Oil and gas sales volume and price comparisons

During the year ended December 31, 2006, oil and gas sales decreased 11% to $18,228, and total gas production increased approximately 6%, when compared to the prior year. The decrease in oil and gas sales was driven by lower gas prices, resulting primarily from the unusually high prices of 2005, due to the heavy hurricane season in the Gulf, and unusually high storage volumes late in 2006, due to higher than normal fall and early winter temperatures across the country. We should also note that our actual average price per Mcfe received for 2006 was $5.85 if we exclude the net gas imbalance activity. The increase in total gas production is primarily attributable to the recording of 245,759 Mcfe of net gas imbalances due us somewhat offset by lower production at Mesa and Cow Creek. Mesa production decreased 14.8% to a net average daily production of 2,556 Mcfe, as compared to 3,000 Mcfe per day in the prior year. While the Mesa decreases are the result of normal production declines, the operator at Mesa has informed us that it intends to continue new drilling projects in 2007 to better maintain or increase production levels. Seven wells began producing in the fourth quarter of 2006, and, currently, seven additional wells are awaiting hook-up at Mesa (three in Mesa Unit A, two in Mesa Unit B and two in Mesa Unit C). Average net daily production at Cow Creek decreased by 1.8% to 4,431 Mcfe, due primarily to workovers completed during the first and fourth quarters. The decreased production at Mesa and Cow Creek was partially offset by increased production at our other properties, which made up approximately 14.2% of our production (net of imbalance activity) during the year ended December 31, 2006. Average daily production volumes at our other properties increased by 34.4% to 1,156 Mcfe, due largely to the receipt of initial revenues from Doty Mountain production beginning in the third quarter of 2006 and the recording of the gas imbalances due us from past production at Doty Mountain and Sun Dog Units.

Transportation revenue

During the year ended December 31, 2006, we recorded $523 in transportation revenue for moving third party gas through our intrastate gas pipeline, which was constructed in late 2005 and connects the Cow Creek Field with the interstate pipeline system owned by Southern Star Central Gas Pipeline, Inc. With additional compression, the pipeline is expected to have a 100 MMcf per day capacity, which is enough to handle the development of the Catalina Unit.

Oil and gas production expenses, depreciation, depletion and amortization

During the year ended December 31, 2006, well production costs decreased 6% to $3,560, as compared to $3,800 during the prior year, and production costs in dollars per Mcfe decreased 10%, or $0.13, to $1.11, as compared to the same prior year period. The production cost per Mcfe decrease is largely attributed to receiving our first revenues from Doty Mountain production in 2006 and to significant Cow Creek workovers in early 2005, as well as the elimination of third party transportation costs at Cow Creek in 2006 due to implementation of our new pipeline. Production taxes remained relatively constant from year-to-year at slightly higher than 12% of revenues.

During the year ended December 31, 2006, total depreciation, depletion and amortization expenses increased 21% to $4,909, as compared to $4,069 in the prior year, and depletion and amortization related to producing assets increased 16% to $4,163, as compared to $3,583 in the prior year. The increase is due primarily to production beginning at Doty Mountain and Sun Dog Units in 2006, and an increase in capital expenditures at Mesa. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 10%, or $0.12, to $1.29, as compared to the prior year. The depreciation of the new pipeline, which totaled $213 for the year ended December 31, 2006, also contributed to the overall increase in total depreciation, depletion and amortization.

During the year ended December 31, 2006, the Rattlesnake prospect in Wyoming was drilled and determined to be a dry hole. A charge to income of $278 is included in the consolidated statement of operations.

General and administrative

During the year ended December 31, 2006, general and administrative expenses increased 31% to $3,959 as compared to $3,015 in the prior year. The increase was due largely to employee stock option expenses totaling $460, incurred pursuant to the adoption of SFAS 123(R) on January 1, 2006, and $357 for professional fees, related to establishing and implementing our Sarbanes Oxley compliance systems. For additional information regarding the adoption of SFAS 123(R), see “—Recently Adopted Accounting Pronouncement” and Item 15, Note 5 of the Notes to the Consolidated Financial Statements.

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Income taxes

During the year ended December 31, 2006, we recorded an income tax expense of $1,399, as compared to $2,043 during the prior year. Our income tax expense reflects an effective book rate of 39.9% in 2006. The higher than expected effective book rate reflects the tax effect of the permanent difference caused by the stock option expense related to the adoption of SFAS 123(R) not being deductible for income tax purposes. Although we expect to continue to generate losses for federal income tax reporting purposes, our sustained net income from operations has resulted in a deferred tax position required under generally accepted accounting principles. We do not anticipate any required payments for current tax liabilities in the near future. We have a net operating loss carry-forward of $10.3 million at December 31, 2006.

Year ended December 31, 2005 compared to the year ended December 31, 2004

Oil and gas sales volume and price comparisons

During the year ended December 31, 2005, oil and gas sales increased 57% to $20,451 from $13,058. The increase is due primarily to a 16% increase in gas production from the Pinedale Anticline and the Cow Creek Field, and a 36% increase in gas prices. Total average daily production increased to 8,408 Mcfe in 2005, as compared to 7,290 Mcfe in the prior year. Average gas prices increased during the year and averaged $8.63 per Mcf during the fourth quarter of 2005.

Oil and gas production expenses, depreciation, depletion and amortization

During the year ended December 31, 2005, production costs increased 76% to $3,800, as compared to $2,156 in the prior year, and production costs in dollars per Mcfe increased 53%, or $.43, to $1.24. The increase, both in terms of total dollars and dollars per Mcfe is due primarily to an increase in third party gathering costs at Cow Creek and Mesa, and an increase in costs related to workovers completed at Cow Creek during the first quarter of 2005. Production taxes remained relatively constant from year to year at slightly higher than 12% of revenues.

During the year ended December 31, 2005, total depreciation, depletion and amortization expense increased $1,161 or 40% to $4,069 for 2005, as compared to the prior year, and depletion and amortization related to producing assets increased 37% to $3,583, as compared to $2,619 in the prior year. The increase is due to a 15% increase in production and additional capital expenditures on producing properties. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 19%, or $0.19, to $1.17, as compared to the prior year.

General and administrative expense

During the year ended December 31, 2005, general and administrative expenses increased 85% to $3,015, as compared to $1,628 in 2004. Sixty-three percent of this increase, or $874, resulted from the hiring of additional personnel to meet staffing needs, and an overall increase in compensation and benefit costs to remain competitive in the industry. Professional, audit and legal fees incurred primarily for the implementation of compliance with the Sarbanes Oxley Act of 2002 accounted for 21%, or $291, of the 2005 increase. The remainder of the 2005 increase was due to numerous individually immaterial items.

Income taxes

During the year ended December 31, 2005, we recorded income tax expense of $2,043, as compared to $450 during the prior year. Our income tax expense reflects an effective book rate of approximately 34%. Although we expect to continue to generate losses for federal income tax reporting purposes, our sustained net income from operations has resulted in a deferred tax position required under generally accepted accounting principles. We do not anticipate any required payments for current tax liabilities in the near future. We have a net operating loss carry-forward of $12.4 million at December 31, 2005.

LIQUIDITY AND CAPITAL RESOURCES

Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our financing facilities and proceeds from offerings of equity securities. In the past, these sources have been sufficient to meet our needs and finance the growth of our business. We can give no assurances that the historical sources of liquidity and capital resources will be available for future development projects, and we may be required to

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seek additional or alternative financing sources. Product prices and volumes, as well as the timely collection of receivables and the availability of oil field services and supplies such as concrete, pipe and compression equipment are all expected to have a significant influence on our future net cash provided by operating activities. Additionally, our future growth will be dependent upon the success and timing of our exploration and production activities, new project development, efficient operation of our facilities and our ability to obtain financing at favorable terms.

We believe that the amounts available under our $50 million bank line of credit and the possibility of offerings of securities, including securities issued under our $200 million shelf registration statement, together with the net cash provided by operating activities, will provide us with sufficient funds to develop new reserves, maintain our current facilities and complete our current capital expenditure program. Depending on the timing and amount of future projects, we may be required to seek additional sources of capital. While we believe that we would be able to secure additional financing if required, we can provide no assurance that we will be able to do so or as to the terms of any additional financing.

The table below provides a year-to-year overview of selected financial information that addresses our overall financial condition, liquidity, and cash flow activities. The information contained in the table below should be read in conjunction with our consolidated financial statements and accompanying notes included in this Form 10-K.

	As of and for the Years Ended December 31,									Percent Change Between Years
	2006			2005			2004			2005 to 2006			2004 to 2005
Financial information
Working 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	%

The working capital deficit noted above has increased from 2005 to 2006 largely due to the accounts payable and accrued expenses related to ongoing exploratory drilling operations at Christmas Meadows and $3.5 million for our share of the Madden project (discussed under Capital Requirements below) at December 31, 2006. The decrease in Net cash provided by operating activities is discussed in detail in the section Results of Operations in this MD&A above. The increases in both Net cash used in investing activities and Net cash provided by financing activities result from the exploration and development drilling activities discussed in the section Capital Requirements in this MD&A below.

Capital Requirements

Our primary capital needs for the three years ended December 31, 2006, 2005 and 2004 were:

	Year Ended December 31,
	2006		2005		2004
Property acquisition costs	$	100	$	407	$	297
Exploration		11,304		3,693		324
Development		10,046		14,873		8,367
	$	21,450	$	18,973	$	8,988

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We commenced four exploratory/development drilling projects in 2006 and 2005: (i) the Rattlesnake exploratory prospect in Wyoming; (ii) the South Fillmore exploratory prospect just north of Cow Creek; (iii) the Cow Creek Unit Deep #2 development prospect to deeper formations in our Cow Creek Field, and (iv) the Christmas Meadows exploratory prospect in northeast Utah. The Rattlesnake prospect was drilled and determined to be a dry hole during the third quarter 2006. We recorded a charge for the dry hole in the third quarter of $278. In the third quarter of 2006, we completed drilling at the South Fillmore prospect, north of the Cow Creek Field and are currently testing the well’s production potential. Additionally, we drilled the Cow Creek Deep #2, a Madison test near our coalbed natural gas production at Cow Creek, to 9,922 feet, ran casing to that point and are reworking the seismic data with the additional well data compiled. We expect to complete the drilling and testing of the Cow Creek Deep #2 in the first six months of 2007. We reached the originally planned total depth at the Christmas Meadows exploratory test well in the first quarter of 2007. The Table Top Unit #1 well at Christmas Meadows did not find reservoir rocks with sufficient permeability in the Cretaceous formation. We plan to get a larger rig and continue down to test the Nugget sandstones at approximately 18,000 feet and will consider the possibility of attempting to drill to test the Madison carbonates at approximately 23,000 feet. At December 31, 2006, our combined cost of the three open projects was $11,642. In the event that these wells are unsuccessful, we may be required to impair all or a portion of the costs incurred.

Our development projects in 2006 included the Atlantic Rim, in which we participated in the drilling of 27 wells (22 producing wells to be put on line in 2007, 1 development dry hole and 4 water injection wells) at the Doty Mountain Unit. Double Eagle has 20.55% working interest in Doty Mountain. At the Pinedale Anticline, we participated in the completion 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. On the Moxa Arch, we were involved in 31 development gas wells with working interests ranging from 0.27% to 16.27%. Our purchase of a 0.3493% interest in the Madden Sour Gas Participating Area in the Madden Deep Unit and the sour gas plant at the Madden Field in the Wind River Basin in Wyoming at an initial cost of approximately $3.5 million is also included in development projects for 2006.

Our development projects in 2005 included the building of our intrastate gas pipeline, which connects the Cow Creek Field with the pipeline system owned by Southern Star Central Gas Pipeline, Inc. The 13-mile pipeline provides us with full access to the interstate gas markets from southern Wyoming, and also provides us with the ability to move third party gas. The pipeline was constructed at a cost of $5,412 and will provide reliable transportation for future development by us in the Catalina Unit on the Atlantic Rim. Other development projects included the development of power generation and water processing facilities at Cow Creek, costing $4,600; continued participation in the drilling of new development wells operated by Wexpro in the Pinedale Anticline in the Mesa B and C Units, costing $3,300; and non-operated development coalbed natural gas projects in the Atlantic Rim totaling $1,200.

In 2004, we incurred $3,170 to complete wells, stimulate production, and expand our power generation and field compression facilities at Cow Creek. We also participated in the continued drilling of new development wells operated by Questar/Wexpro in the Mesa Units of the Pinedale Anticline. Capital expenditures in the Mesa Units aggregated $2,260. Additionally, we participated in 24 new coal bed methane wells drilled by Anadarko at Doty Mountain, costing $2,600.

For 2007, we have budgeted approximately $50 million for ongoing development programs in the Atlantic Rim and Pinedale Anticline. The budgeted spending represents a 133% increase over 2006. In addition to development of our reserves in our core areas, we believe in engaging in exploratory efforts that may lead to new core areas in the future. The 2007 budget does not include the impact of any potential future exploration projects, ongoing exploration or development activities at Christmas Meadows, Cow Creek Unit Deep #2 or South Fillmore, or possible asset purchases. We continually evaluate our opportunities, and if a potential opportunity is identified that complements our identified areas of expertise, it may be pursued.

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Contractual Obligations

The impact that our contractual obligations as of December 31, 2006 are expected to have on our liquidity and cash flow in future periods is:

			One year		2 - 3		4 - 5		More than
	Total		or less		Years		Years		5 Years
Line 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

As part of our cash management program, effective August 1, 2006, we entered into a new $50 million revolving line of credit secured by our oil and gas producing properties, replacing our previously existing revolving line of credit, as 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 balance outstanding of $13.2 million was used to fund capital expenditures.

We are 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, we were in compliance with all the covenants. If our covenants are violated, and we are 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, we maintained a $9 million revolving line of credit collateralized by our 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.

Access to Capital Markets

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.

On January 23, 2007, pursuant to the universal shelf registration statement on Form S-3 described above, we announced the closing of a follow-on public offering of 450,000 shares of Common Stock at a price to the public of $21.55 per share. Double Eagle granted to the underwriter a 30-day option to purchase up to an additional 50,000 shares of common stock to cover over-allotments, which option was exercised in full by the underwriter. Proceeds from the offering were approximately $10.1 million, including the underwriter’s exercise of its over-allotment option, after deducting the underwriting discounts and commissions and the estimated offering expenses. We used the net proceeds from this offering to pay down the outstanding indebtedness on our revolving line of credit.

Off-Balance Sheet Arrangements

We do not participate in transactions that generate relationships with unconsolidated entities or financial partnerships. Such entities are often referred to as structured finance or special purpose entities (“SPEs”) or variable interest entities (“VIEs”). SPEs and VIEs can be established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. We were not involved in any unconsolidated SPEs or VIEs at any time during any of the periods presented in this Form 10-K.

From time to time, we enter into contracts that might be construed as off-balance sheet obligations but are normal in the day-to-day course of business in the oil and gas industry. Those contracts include the forward sales contracts discussed

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directly below under Contracted Volumes. We do not believe we will be affected by these contracts materially differently than other similar companies in the energy industry.

CONTRACTED VOLUMES

Although we do not currently hedge our production prices, we have entered into various fixed delivery contracts for some of the production from our Cow Creek Field, allowing us to effectively “lock in” a portion of our future production of natural gas at prices which we considered favorable to Double Eagle at the time we entered into the contract. For the year ended December 31, 2006, the weighted average price of our contracted volumes from the Cow Creek Field exceeded the weighted average spot price for the open market volumes from the Cow Creek Field. Thus, the contracts resulted in additional revenue recognized by the Company of approximately $1.4 million. If the market price increases above our contract prices during the contract terms, we would be selling natural gas related to the contracts at less than the market. As of December 31, 2006, we had sales delivery contracts in effect for approximately 57% of our total current daily production (volume and daily production are expressed in Mcf):

	Remaining
	Contractual		Daily				Fixed
Property	Volume		Production		Term		Price/Mcf
Cow Creek		90,000		1,000		07/06 - 03/07	$	5.42
		90,000		1,000		07/06 - 03/07	$	6.28
		181,000		1,000		07/06 - 06/07	$	5.94
		181,000		1,000		07/06 - 06/07	$	6.32
		304,000		1,000		11/06 - 10/07	$	5.84
Company Total		846,000

All production volumes through our pipeline are subject to a transportation agreement for which we receive a third party fee per Mcf.

CRITICAL ACCOUNTING ESTIMATES

This discussion and analysis of our financial condition and results of operations are based on the consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of our financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 1, “Business Description and Summary of Significant Accounting Policies”, of the Notes to the Consolidated Financial Statements, included in Item 15 of this Annual Report on Form 10-K. In the following discussion, we have identified the accounting estimates which we consider as the most critical to aid in fully understanding and evaluating our reported financial results. Estimates regarding matters that are inherently uncertain require difficult, subjective or complex judgments on the part of our management. We analyze our estimates, including those related to oil and gas reserves, oil and gas properties, income taxes, contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe reasonable under the circumstances. Actual results may differ from these estimates.

Successful Efforts Method of Accounting

We account for our natural gas and crude oil exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells, and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses, and delay rentals for oil and gas leases are charged to expense as incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory which will ultimately determine the proper accounting

37

treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled which have targeted geologic structures which are both developmental and exploratory in nature and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs may require managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in hopes of finding an oil and gas field that will be the focus of future development drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. At December 31, 2006, we have three exploratory projects at a combined to-date cost of $11,509 and intend to complete the projects, including final economic assessment, in 2007.

Reserve Estimates

Our estimates of oil and natural gas reserves, by necessity, are projections based on geological and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and natural gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and gas properties and/or the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

Impairment of Long-Lived Assets

We review the carrying values of our 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.

Asset Retirement Obligation

We recognize an estimated liability for future costs associated with the abandonment of our oil and gas properties. We base our estimate of the liability on our historical experience in abandoning oil and gas wells projected into the future based on our current understanding of federal and state regulatory requirements. Our present value calculations require us to estimate the economic lives of our properties, assume what future inflation rates apply to external estimates as well as determine what credit adjusted risk-free rate to use. The statement of operations impact of these estimates is reflected in our depreciation, depletion and amortization calculations and occurs over the remaining life of our oil and gas properties.

Stock-based compensation

Effective January 1, 2006, we 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 the

38

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. We 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). Total share-based compensation expense for equity-classified awards, was $460 during the year ended December 31 2006. 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.

We use 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.

Prior to our adoption of the provisions of SFAS 123(R), we previously 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.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risks

We pay interest on outstanding borrowings under our revolving credit facility at interest rates that fluctuate based upon changes in the prime lending rate. As the interest rate is variable and reflective of current market conditions, the carrying value approximates the fair value. Assuming no change in the amount outstanding at December 31, 2006, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $134,000 before taxes.

Effective August 1, 2006, we entered into a $50 million revolving line of credit which replaced our previously existing revolving line of credit. 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 balance outstanding was $13.2 million.

Commodity Price Risks

Our major market risk exposure is in the pricing applicable to our natural gas and oil production. Pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for oil production and natural gas has been volatile and unpredictable for several years. The prices we receive for production depend on many factors outside of our control. For the year ended December 31, 2006, our income before income taxes would have changed by $1.3 million for each $0.50 change per Mcf in natural gas prices (excluding any imbalance activity) and $11,000 for each $1.00 change per Bbl in crude oil prices.

Although we do not currently hedge our production prices, we have entered into various fixed delivery contracts for some of the production from our Cow Creek Field, allowing us to effectively “lock in” a portion of our future production of natural gas at prices which we considered favorable to Double Eagle at the time we entered into the contract. For the year ended December 31, 2006, the weighted average price of our contracted volumes from the Cow Creek Field exceeded the weighted average spot price for the open market volumes from the Cow Creek Field. Thus, the contracts resulted in additional revenue recognized by the Company of approximately $1.4 million. If the market price increases above our contract prices during the contract terms, we would be selling natural gas related to the contracts at less than the market. As of December 31, 2006, we had sales delivery contracts in effect for approximately 57% of our total current daily production (volume and daily production are expressed in Mcf. These fixed delivery contracts, which have differing expiration dates, are summarized in the table presented above under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contracted Volumes.”

39

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by this item is included in Item 15, “Exhibits, Financial Statements and Financial Statement Schedules.”

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

40

ITEM 9A. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this annual report. We identified a material weakness in our internal control over financial reporting and, as a result of this material weakness, we concluded that our disclosure controls and procedures were not effective as of December 31, 2006.

(b) Management’s Annual Report on Internal Control Over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that:

(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.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control-Integrated Framework.

A material weakness is a significant deficiency, or combination of significant deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected by the entity’s internal control over financial reporting. As of December 31, 2006, the Company identified the following material weakness:

The Company did not perform timely and sufficient review to verify the information supplied by the Company’s third party reserve engineers in the Company’s December 31, 2006 reserve report. Thus, management’s oversight and review related to the reserve report was not effective. These deficiencies in internal control over financial reporting could have resulted in misstatements in the Company’s 2006 reserve related disclosures and depletion expense. The misstatements were corrected prior to issuance of the Company’s 2006 consolidated financial statements, included elsewhere in this Form 10-K.

As a result of the aforementioned material weakness, management concluded that the Company’s internal control over financial reporting as of December 31, 2006 was not effective.

The Company’s independent registered public accounting firm, Hein & Associates LLP, has issued a report on management’s assessment of the Company’s internal control over financial reporting.

41

(c) Management’s Corrective Actions

During the first fiscal quarter of 2007, management took the following steps to address the material weakness identified in Item 9A(b):

• 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

There were no changes in our internal control over financial reporting during our fiscal quarter ended December 31, 2006 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

(The remainder of this page was intentionally left blank)

42

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors Double Eagle Petroleum Co.
Denver, Colorado

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting that Double Eagle Petroleum Co. (“Double Eagle “) did not maintained effective internal control over financial reporting as of December 31, 2006, because of the effect of the material weakness identified in management’s assessment, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Double Eagle’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weakness has been identified and included in management’s assessment:

The Company did not perform timely and sufficient review to verify the information supplied by the Company’s third party reserve engineers in the Company’s December 31, 2006 reserve report. Thus, management’s oversight and review related to the reserve report was not effective. These deficiencies in internal control over financial reporting could have resulted in misstatements in the Company’s 2006 reserve related disclosures and depletion expense. The misstatements were corrected prior to issuance of the Company’s 2006 consolidated financial statements, included elsewhere in this Form 10-K.

This material weakness was considered in determining the nature, timing and extent of audit tests applied in our audit of the 2006 financial statement, and this report does not affect out report dated March 29, 2007 on those financial statements.

In our opinion, management’s assessment that Double Eagle did maintain effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by COSO. Also in our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, Double Eagle has not maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by COSO.

43

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of Double Eagle Petroleum Co. and our report dated March 29, 2007 expressed an unqualified opinion.

/s/ Hein & Associates LLP
HEIN & ASSOCIATES LLP

Denver, Colorado
March 29, 2007

ITEM 9B. OTHER INFORMATION

None.

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

(a)(1) and (a)(2) Financial Statements And Financial Statement Schedules

Audit Report of Independent Registered Public Accounting Firm	F1
Consolidated Balance Sheet	F2
Consolidated Statement of Operations	F3
Consolidated Statement of Cash Flows	F4
Consolidated Statement of Stockholders’ Equity	F5
Notes to Consolidated Financial Statements	F6

All other schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Consolidated Financial Statements and Notes thereto.

(b)Exhibits.The following exhibits are filed with or incorporated by reference into this report on Form 10-K:

44

Exhibit No.	Description
3.1(a)	Articles of Incorporation filed with the Maryland Secretary of State on January 23, 2001 (incorporated by reference from Exhibit 3.1(a) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
3.1(b)	Certificate of Correction filed with the Maryland Secretary of State on February 15, 2001 concerning the Articles of Incorporation (incorporated by reference from Exhibit 3.1(b) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
3.1(c)	Articles of Merger filed with the Maryland Secretary of State on February 15, 2001 (incorporated by reference from Exhibit 3.1(c) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
3.1(d)	Certificate of Correction filed with the Maryland Secretary of State (incorporated by reference from Exhibit 3 of the Company’s Quarterly Report on Form 10-QSB for the quarter ended November 30, 2001).
3.2	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

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act Of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

DOUBLE EAGLE PETROLEUM CO.

Date: March 30, 2007	/s/ Stephen H. Hollis
	Stephen H. Hollis,
	Chief Executive Officer,
	President and Director

Pursuant to the requirements of the Securities Exchange Act Of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date: March 30, 2007	/s/ Stephen H. Hollis
	Stephen H. Hollis,
	Chief Executive Officer,
	President and Director
Date: March 30, 2007	/s/ Lonnie R. Brock
	Lonnie R. Brock
	Chief Financial Officer
Date: March 30, 2007	/s/ Sigmund Balaban
	Sigmund Balaban, Director
Date: March 30, 2007	/s/ Roy G. Cohee
	Roy G. Cohee, Director
Date: March 30, 2007	/s/ Richard Dole
	Richard Dole, Director

46

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders of Double Eagle Petroleum Co.:

Denver, Colorado

We have audited the balance sheets of Double Eagle Petroleum Co. (the “Company”) as of December 31, 2006 and 2005, and the related statements of income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provided a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years ended in the period December 31, 2006, in conformity with U.S. generally accepted accounting principles.

As discussed in note 5 to the accompanying consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123(R),Share-Based Payment.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 29, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an adverse opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ Hein & Associates LLP
Denver, Colorado
March 29, 2007

F-1

DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED BALANCE SHEET
(Amounts in thousands of dollars except share and per share data)

	December 31,
	2006			2005
ASSETS
Current assets:
Cash and cash equivalents	$	611		$	1,431
Cash held in escrow		707			—
Accounts receivable		5,047			4,248
Other current assets		809			218
Total current assets		7,174			5,897
Oil and gas properties and equipment, successful efforts method:
Developed properties		53,677			41,146
Wells in progress		13,839			2,946
Gas transportation pipeline		5,412			5,379
Undeveloped properties		3,313			3,213
Corporate and other assets		1,024			748
		77,265			53,432
Less accumulated depreciation, depletion and amortization		(20,079	)		(15,174	)
Net properties and equipment		57,186			38,258
Other assets		46			56
TOTAL ASSETS	$	64,406		$	44,211
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	7,964		$	2,798
Accrued expenses		5,125			4,246
Accrued production taxes		1,091			1,657
Total current liabilities		14,180			8,701
Line of credit		13,221			3,000
Asset retirement obligation		694			513
Deferred tax liability		3,269			2,219
Total liabilities		31,364			14,433
Commitments 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			859
Additional paid-in capital		23,251			22,101
Retained earnings		8,927			6,818
Total stockholders’ equity		33,042			29,778
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	64,406		$	44,211

The accompanying notes are an integral part of the consolidated financial statements.

F-2

DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED STATEMENT OF OPERATIONS

(Amounts in thousands of dollars except share and per share data)

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

The accompanying notes are an integral part of the consolidated financial statements.

F-3

DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Amounts in thousands of dollars)

	Year ended December 31,
	2006			2005			2004
Cash flows from operating activities:
Net income	$	2,109		$	3,965		$	4,028
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		4,909			4,088			2,923
Abandonment of non-producing properties		20			106			135
Impairment of equipment and properties		—			357			155
Provision for deferred income taxes		1,399			2,043			450
Directors’ fees paid in stock		97			160			54
Non-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			1,038
Increase (decrease) in accrued production taxes		(566	)		685			627
NET CASH PROVIDED BY OPERATING ACTIVITIES		10,951			10,319			7,434
Cash 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	)		10
NET 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			714
Settlement of options		(104	)		—			—
Other		—			—			(22	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		10,470			3,701			692
Change in cash and cash equivalents		(820	)		(2,239	)		749
Cash and cash equivalents at beginning of period		1,431			3,670			2,921
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	611		$	1,431		$	3,670
Supplemental disclosure of cash and non-cash transactions:
Cash paid for interest	$	490		$	57		$	503
Interest capitalized	$	293		$	43		$	—
Additions to developed properties included in current liabilities	$	6,183		$	4,758		$	3,050
Additions to developed properties for retirement obligations	$	171		$	87		$	55
Directors’ fees paid in stock	$	97		$	160		$	54
Stock option expense	$	460		$	—		$	—

The accompanying notes are an integral part of the consolidated financial statements.

F-4

DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
(Amounts in thousands of dollars except share data)

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

The accompanying notes are an integral part of the consolidated financial statements.

F-5

DOUBLE EAGLE PETROLEUM CO.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Amounts in thousands of dollars except share and per share data)

1.	Business Description and Summary of Significant Accounting Policies
	Description of Operations and Basis of Presentation
	Double 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 Equivalents
	Cash and cash equivalents includes all cash balances and any highly liquid investments with an original maturity of 90 days or less.
	Accounts Receivable
	The 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 Statements
	The 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

Concentration of Credit Risk

Financial 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 Balancing

The 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 Activities

Double 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 Obligations

Legal 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

A reconciliation of the Company’s asset retirement obligation liability:

	For the year ended December 31,
	2006			2005
Beginning asset retirement obligation	$	513		$	407
Liabilities incurred		87			39
Liabilities settled		(4	)		—
Accretion expense		15			20
Revision to estimated cash flows		83			47
Ending asset retirement obligation	$	694		$	513

Impairment of Long-Lived Assets

The 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 Assets

Office 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 Customers

Sales 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 Information

The 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 Plan

The 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

Income Taxes

Deferred 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 Share

Basic 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		2004
Net income	$	2,109	$	3,965	$	4,028
Weighted average shares:
Weighted average shares — basic		8,632,567		8,564,228		8,469,852
Dilution effect of stock options outstanding at the end of period		23,020		64,248		129,168
Weighted average shares — fully diluted		8,655,587		8,628,476		8,599,020
Earnings per share:
Basic	$	0.24	$	0.46	$	0.48
Fully diluted	$	0.24	$	0.46	$	0.47

The following options that could be potentially dilutive in future periods were not included in the computation of diluted net income per share because the effect would have been anti-dilutive for the periods indicated:

	For the years ended December 31,
	2006		2005		2004
Options to purchase common stock		18,621		—		—

Stock Based Compensation

Effective 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

	For the year ended December 31,
	2005			2004
Net income, as reported	$	3,965		$	4,028
Add: Share-based employee compensation expense included in reported net income		26			26
Deduct: Total share-based employee compensation expense determined under the fair value based method for all awards		(686	)		(233	)
Pro forma net income	$	3,305		$	3,821
Basic Earnings Per Share:
As reported	$	0.46		$	0.48
Pro forma	$	0.39		$	0.45
Diluted Earnings Per Share:
As reported	$	0.46		$	0.47
Pro forma	$	0.38		$	0.44

For additional information regarding our stock-based compensation plans, refer to Note 5.

Fair Value of Financial Instruments

The 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 pronouncements

In 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

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 Taxes
	The provision for income taxes consists of:

	For the year ended December 31,
	2006		2005		2004
Current taxes	$	—	$	—	$	—
Deferred taxes		1,399		2,043		450
Total 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			2005
Deferred tax assets:
Net operating loss carry-forward	$	3,671		$	4,339
Accrued compensation		68			—
Percentage depletion carry-forward		153			146
Asset retirement obligation		247			14
Stock option expense carry-forward		—			17
		4,139			4,516
Deferred 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

Reconciliation of the Company’s effective tax rate to the expected federal tax rate is:

	For the year ended December 31,
	2006			2005
Expected 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 Contingencies
	Gas Sales Commitments
	The 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:

	Remaining
	Contractual		Daily				Fixed
Property	Volume		Production		Term		Price/Mcf
Cow Creek		90,000		1,000		07/06 - 03/07	$	5.42
		90,000		1,000		07/06 - 03/07	$	6.28
		181,000		1,000		07/06 - 06/07	$	5.94
		181,000		1,000		07/06 - 06/07	$	6.32
		304,000		1,000		11/06 - 10/07	$	5.84
Company Total		846,000

Lease Commitments

In 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	Lease
December 31,	commitments
2007	$	72
2008		36
2009		10
2010		10
2011		9
Thereafter		—
Total	$	137

F-12

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 Plans
	Double 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			2004
Weighted-average volatility		40% - 44	%		42	%		71	%
Expected dividends		0.00	%		0.00	%		0.00	%
Expected term (in years)		2 - 4			5			8
Risk-free rate		4.68% - 5.10	%		3.50	%		3.00	%
Expected forfeiture rate		5% - 10	%		0.00	%		0.00	%

F-13

Summary of option activity during the years ended December 31, 2006, 2005 and 2004:

						Weighted-Average
						Remaining
				Weighted-Average		Contractual Term		Aggregate
Options:	Shares			Exercise Price		(in years)		Intrinsic Value
Outstanding at January 1, 2006		354,243		$	15.38		3.5
Granted		112,500		$	19.53
Exercised		(44,500	)	$	7.92
Cancelled/expired		(96,743	)	$	16.39
Outstanding at December 31, 2006		325,500		$	17.64		3.8	$	2,248
Exerciseable at December 31, 2006		101,700		$	16.46		2.8	$	823
Outstanding at January 1, 2005		275,843		$	14.32		2.5
Granted		249,500		$	18.43
Exercised		(93,600	)	$	7.52
Cancelled/expired		(77,500	)	$	17.00
Outstanding at December 31, 2005		354,243		$	15.38		3.5	$	1,807
Exerciseable at December 31, 2005		202,743		$	13.48		2.2	$	919
Outstanding at January 1, 2004		256,486		$	5.43		0.8
Granted		176,100		$	13.90
Exercised		(150,000	)	$	4.75
Cancelled/expired		(6,743	)	$	14.83
Outstanding at December 31, 2004		275,843		$	14.32		2.5	$	2,325
Exerciseable at December 31, 2004		156,676		$	5.44		1.1	$	1,714

The weighted average grant date fair value of options granted during the three years ended December 31, 2006, 2005, and 2004 was $19.53, $14.25, and $10.09, respectively. During the year ended December 31, 2006, (i) the total intrinsic value, or the difference between the exercise price and the market price on the date of exercise, of all options exercised was $501; and (ii) the fair value of options vested was $2,497. As of December 31, 2006, shares available for grant under the Plans were 212,614.

Stock options outstanding and currently exercisable at December 31, 2006 are:

			Options
			Outstanding				Options Exerciseable
			Weighted Average		Weighted				Weighted
	Number of		Remaining		Average		Number of		Average
Range of Exercise	Options		Contractual Life		Exercise Price		Options		Exercise Price
Prices 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	$	18.59
		325,500		3.8	$	17.64		101,700	$	16.46

F-14

6.	Supplemental Information on Oil and Gas Producing Activities
	Capitalized Costs Relating to Oil and Gas Producing Activities
	The aggregate amount of capitalized costs relating to crude oil and natural gas producing activities and the aggregate amount of related accumulated depreciation, depletion and amortization at December 31, 2006, 2005 and 2004 are:

	As of December 31,
	2006			2005			2004
Developed properties	$	53,677		$	41,146		$	32,294
Undeveloped properties		3,313			3,213			3,026
		56,990			44,359			35,320
Accumulated 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 Activities

Costs 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		2004
Property acquisitions — unproved	$	100	$	407	$	297
Exploration		11,304		3,693		324
Development		10,046		14,873		8,367
Total	$	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		2004
Beginning 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

Results of Operations from Oil and Gas Producing Activities

The results of operations for the Company’s oil and gas producing activities for the years ended December 31, 2006, 2005 were:

	For the year ended December 31,
	2006		2005		2004
Operating revenues	$	18,228	$	20,451	$	13,058
Costs and expenses:
Production		5,769		6,323		3,801
Exploration		530		747		324
Depletion, amortization and impairment		4,163		3,939		2,774
Total costs and expenses		10,462		11,009		6,899
Income before income taxes	$	7,766	$	9,442	$	6,159

Oil and Gas Reserves (Unaudited)

The reserves at December 31, 2006, 2005 and 2004 presented below were reviewed by Netherland, Sewell and Associates, Inc. All reserves are located within the continental United States. The reserve estimates are developed using geological and engineering data and interests and burden information developed by the Company. Reserve estimates are inherently imprecise and are continually subject to revisions based on production history, results of additional exploration and development, prices of oil and gas, and other factors.

Estimated net quantities of proved developed reserves of oil and gas for the years ended December 31, 2006, 2005, and 2004 are:

	For the year ended December 31,
	2006						2005						2004
	Oil			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			22,818,980
Revisions of estimates		41,546			(5,976,392	)		7,451			(198,036	)		16,062			13,606
Extensions and discoveries		2,596			10,379,429			58,716			15,473,719			89,886			14,661,717
Sales 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			34,934,746
Proved developed reserves		254,346			30,075,467			199,931			23,032,277			181,397			17,161,577
Percentage of proved developed reserves		71	%		62	%		61	%		49	%		65	%		49	%

As of December 31, 2006, 91% of the proved developed gas reserves and 100% of the proved developed oil reserves were in producing status.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)

The following information has been developed utilizing procedures prescribed by SFAS 69 “Disclosures about Oil and Gas Producing Activities” and based on natural gas and crude oil reserves and production volumes estimated by the Company. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative or realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.

F-16

The Company believes that the following factors should be taken into account in reviewing the following information: (1) future costs and selling prices will probably differ from those required to be used in these calculations; (2) due to future market conditions and governmental regulations, actual rates of production achieved in future years may vary significantly from the rate of production assumed in these calculations; (3) selection of a 10% discount rate, as required by SFAS 69, is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and (4) future net revenues may be subject to different rates of income taxation.

Under the Standardized Measure, future cash inflows were estimated by applying year-end oil and gas prices to the estimated future production of year-end proved reserves. Futures cash inflows were reduced by estimated future development and production costs based upon year-end costs in order to arrive at net cash flow before tax. Future income tax expense has been computed by applying year-end statutory rates to future pretax net cash flows and the utilization of net operating loss carry-forwards.

Management does not rely solely upon the following information to make investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable, as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

Information with respect to the Company’s Standardized Measure:

	As of December 31,
	2006			2005			2004
Future cash inflows	$	246,270		$	400,671		$	202,358
Future 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			99,497
10% annual discount		(70,960	)		(103,447	)		(47,967	)
Standardized measure of discounted future net cash flows	$	50,033		$	91,293		$	51,530

Principal changes in the Standardized Measure for the years ended December 31, 2006, 2005 and 2004:

	2006			2005			2004
Standard measure, as of January 1,	$	91,293		$	51,530		$	42,841
Sales of oil and gas produced, net of production costs		(12,460	)		(14,128	)		(9,258	)
Extensions and discoveries		14,724			43,610			28,865
Net 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			2,115
Changes in estimated future development costs		(10,632	)		(9,816	)		(6,958	)
Sales of reserves in place		—			—			(766	)
Revisions of quantity estimates		(7,749	)		(384	)		329
Accretion of discount		6,764			14,315			6,386
Net 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			8,689
Standardized measure, as of December 31,	$	50,033		$	91,293		$	51,530

F-17

7.Quarterly Financial Data (Unaudited)

Summary of the unaudited financial data for each quarter for the years ended December 31, 2006 and 2005 (in thousands except per share data):

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

F-18

Exhibit Index

Exhibit No.	Description
3.1(a)	Articles of Incorporation filed with the Maryland Secretary of State on January 23, 2001 (incorporated by reference from Exhibit 3.1(a) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
3.1(b)	Certificate of Correction filed with the Maryland Secretary of State on February 15, 2001 concerning the Articles of Incorporation (incorporated by reference from Exhibit 3.1(b) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
3.1(c)	Articles of Merger filed with the Maryland Secretary of State on February 15, 2001 (incorporated by reference from Exhibit 3.1(c) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
3.1(d)	Certificate of Correction filed with the Maryland Secretary of State (incorporated by reference from Exhibit 3 of the Company’s Quarterly Report on Form 10-QSB for the quarter ended November 30, 2001).
3.2	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.