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10KSB 1 d22988e10ksb.htm FORM 10-KSB
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U.S. Securities And Exchange Commission

Washington, D.C. 20549

FORM 10-KSB

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2004

o TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the transition period from to

Commission File No. 0-6529

DOUBLE EAGLE PETROLEUM CO.

(Name of small business issuer in its charter)

Maryland 83-0214692

(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)

777 Overland Trail (P.O. Box766) Casper, Wyoming 82601

(Address of principal executive offices) (Zip Code)

Issuer’s telephone number, including area code (307) 237-9330

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:

$.10 Par Value Common Stock

(Title of Class)

Check whether the issuer (1) 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. Yes þ No o

Check if there is no disclosure of delinquent filers in response to Item405 of Regulation S-B contained in this form, and no
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disclosure will be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated

by reference in Part III of this Form10-KSB or any amendment to this Form10-KSB. þ

Issuer’s revenues for the fiscal year ended December 31, 2004 were $13,267,073.

The aggregate market value of the voting stock held by non-affiliates computed based on the average of the closing bid and

asked prices of such stock as of March 16, 2005, was $184,901,979.*

(APPLICABLE ONLYTO CORPORATEREGISTRANTS)

The number of shares outstanding of each of the issuer’s classes of common equity as of March 16, 2005 was as follows:

$.10 Par Value Common Stock 8,548,404

*Without assuming that any of the issuer’s directors or executive officers, or the entity that owns 350,000 shares, is an affiliate,

the shares of which they are beneficial owners have been deemed to be owned by affiliates solely for this calculation.

Double Eagle PetroleumCo.

Form10-KSB for the year Ended December 31, 2004

Table of Contents

PART I

Items 1. and 2. Description of Business and Properties 2

Item3. Legal Proceedings 16

Item4. Submission of Matters to a Vote of Security Holders 16

PART II

Item5. Market for Common Equity and Related Stockholder Matters 17

Item6. Management’s Discussion and Analysis or Plan of Operations 18

Item7. Financial Statements F-1

Item8. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure 26

Item8A. Controls and Procedures 26

Item8B. Other Information 26

PART III

Item9. Directors, Executive Officers, Promoters and Control Persons; Compliance With Section 16(a) of

the Exchange Act

27

Item10. Executive Compensation 29

Item11. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder 34
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Matters

Item12. Certain Relationships and Related Transactions 35

Item13. Exhibits 35

Item14. Principal Accountant Fees and Services 36

Signatures 38

Exhibits

Certification of CEO Pursuant to Section 302

Certification of CFO Pursuant to Section 302

Certification Pursuant to Section 906

Restated Audit Committee Charter

Code of Business Conduct and Ethics

Whistleblower Procedures

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PART I

ITEMS 1 and 2. DESCRIPTION OF BUSINESS AND PROPERTIES

Overview

Double Eagle PetroleumCo., which was formed as a Wyoming Corporation on January 13, 1972, and reincorporated in

February 2001 in the State of Maryland, explores for, develops, produces and sells crude oil and natural gas. The Company

concentrates its activities in areas in which it believes it has accumulated detailed geologic knowledge and developed

significant management experience. Current areas of exploration and development activity for the Company include the Green

River Basin in southwestern Wyoming, the Powder River Basin in northeastern Wyoming, the Washakie Basin in south central

Wyoming, the Wind River Basin in central Wyoming, and the Christmas Meadows area in northeastern Utah. As of

December 31, 2004, the Company owned interests in a total of 524 producing wells, with natural gas constituting approximately

96 percent of its production and oil constituting approximately four percent (assuming sixmcf of gas production equals one

barrel of oil production). The Company also has undeveloped acreage in other basins and is evaluating the possibility of

additional activity in other areas. See “Principal Areas Of Oil And Gas Activity”.

Effective February 4, 2003, the Company changed its fiscal year end fromAugust 31 to December 31. Unless otherwise stated,

references contained in this report to fiscal year 2002 are based on an August 31 year end, and fiscal years thereafter are based

on a December 31 year end.

Forward-Looking Statements

This Form10-KSB includes “forward-looking statements” within the meaning of Section 27A of the Securities Act Of 1933, as

amended (the “Securities Act”), and Section 21E of the Securities Exchange Act Of 1934, as amended (the “Exchange Act”). All

statements other than statements of historical fact, included in this Form10-KSB are forward-looking statements. These

forward-looking statements include, without limitation, statements located under “ITEMS 1 AND 2. DESCRIPTION OF

BUSINESS AND PROPERTIES—Business Strategy”, “—Principal Areas Of Oil And Gas Activity”, “—Zeolite Claims”, and “—

Reserves”, “ITEM 6. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIALCONDITION AND RESULTS OF

OPERATIONS – Financial Conditions, Liquidity And Capital Resources”, and Notes to the Financial Statements located

elsewhere herein regarding the Company’s financial position and liquidity, the amount of and its ability to make debt service

payments, its strategies, financial instruments, and other matters. In addition, the words ‘‘believe,’’ ‘‘may,’’ ‘‘could,’’ ‘‘will,’’

‘‘when,’’ ‘‘estimate,’’ ‘‘continue,’’ ‘‘anticipate,’’ ‘‘intend,’’ ‘‘expect’’ and similar expressions, as they relate to Double Eagle,

our business or our management, are intended to identify forward-looking statements. Although the Company believes that the

expectations reflected in these forward-looking statements are reasonable, it can give no assurance that these expectations will

prove to be correct. Important factors that could cause actual results to differ materially fromthe Company’s expectations are

disclosed in this Form10-KSB, including without limitation in the “—Risk Factors” section below and in conjunction with the

forward-looking statements included in this Form10-KSB.

The Company’s intentions and expectations described in this Form10-KSB with respect to possible exploration and other

testing activities concerning properties in which it holds interests may be deemed to be forward-looking statements. These

statements are made based on management’s current assessment of the exploratory merits of the particular property in light of

the geological information available at the time and based on the Company’s relative interest in the property and its estimate of

its share of the exploration costs. Subsequently obtained information concerning the merits of any property as well as

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changes in estimated exploration costs and ownership interests may result in revisions to management’s expectations and

intentions, and thus the Company may delete one or more of these intended exploration activities. Further, circumstances

beyond the Company’s control may cause such prospects to be eliminated fromfurther consideration as exploration prospects.

Actual results could differ materially fromthese forward-looking statements as a result of, among other things:

• failure to obtain, or a decline in, oil or gas production, or a decline in oil or gas prices,

• incorrect estimates of required capital expenditures,

• increases in the cost of drilling, completion and gas collection or other costs of production and operations,

• an inability to meet growth projections, and

• other risk factors set forth under ‘‘—Risk Factors’’ in this annual report.

Business Strategy

The Company’s strategy is to increase its cash flow and oil and gas reserves by developing and marketing oil and gas

prospects. Upon marketing a prospect to another entity, the Company will attempt to receive a promoted or carried interest in

the initial well for the prospect. The Company will then participate proportionately in the drilling of any development wells on

the prospect.

During 2004, we expended a significant amount of time evaluating oil and gas producing properties for acquisition. We believe

that acquisitions could provide a way for the Company to grow, and these efforts are intended to continue during 2005. The

Company intends to balance it’s evaluation efforts with its exploration and development plans.

The Company owns interests varying fromvery small percentages to large percentages in its oil and gas prospects. These

interests and prospects are described below under “Principal Areas Of Oil And Gas Activity”. They are owned directly by the

Company, and the remaining interests in these prospects are owned by various industry partners. During 2005, we intend to

develop our prospects using our cash balances, together with cash flow fromoperations, our bank line of credit, and, possibly,

sales of a portion of our interests to industry partners. If our available cash fromthese sources does not satisfy our need for

capital, our activities may be limited to a lower level or we may attempt to raise additional capital. We anticipate that any

limitations on our activities would include expending smaller amounts in our principal areas of activity, attempting to sell a

larger portion of our interests in our prospects, and retaining a royalty interest or a smaller working interest in those prospects

that we believe we would be able to retain if we were not limited by our available cash. Raising additional capital is generally

dilutive to existing stockholders and never certain of success.

We have focused our efforts on exploration for and development of natural gas reserves that constitute approximately 95% of

our total existing reserves as of December 31, 2004. The demand for natural gas as a primary source of domestic energy is

increasing and is becoming the preferred fuel for the future.

Double Eagle has worked to assemble an array of exploration and development projects that range fromoffset locations of

existing fields to high risk “wildcat” ventures with large but uncertain potential. We intend to use most of our available capital

funds on projects having lower risk and to seek to find industry partners to pay part or all of our drilling costs for the

exploration of the higher risk plays. This strategy is intended to provide the Company and its stockholders with exposure to

virtually all levels of risk profiles in the oil and gas business.

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Wyoming Acreage by Geologic Basin

December 31, 2004

Basin Gross Acres Net Acres

Wind River 28,709 3,686

Powder River 41,144 5,168

Washakie 123,833 50,886

Green River 35,974 3,823

Southwestern Wyoming 159,807 54,709

PRINCIPAL AREAS OF OIL AND GAS ACTIVITY

SUMMARY

In 2004, the Mesa Unit on the Pinedale Anticline produced 34% of our production and at year end constituted 63% of our

proved reserves. Cow Creek Unit in the Eastern Washakie coal bed natural gas play produced 54% of our production in 2004

and constituted 30.5% of our proved reserves at year end.

In 2005, we will concentrate our efforts on: (1) drilling the initial test well on our Christmas Meadows Prospect, (2) developing

the facilities and infrastructure in the Eastern Washakie coal bed natural gas play to prepare for a major development drilling

programin 2006, after the Environmental Impact Study is completed, (3) continuing the development of the tight gas sands on

the Pinedale Anticline, and (4) drilling additional deep tests at Cow Creek.

SOUTHWESTERN WYOMING

We own interests in 159,807 gross acres in the natural gas prone basins of southwestern Wyoming. Two developing areas, the

Pinedale Anticline and the eastern Washakie Coal Bed natural gas play, accounted for over 93.5% of our proved reserves as of

December 31, 2004, and over 88% of our 2004 production. Continued drilling is expected in these two areas in 2005.

PINEDALEANTICLINE

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

fromArco. 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 fromKCS 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 sister company, Questar Exploration, took over operations fromUltra on the Mesa Unit lands and began an

aggressive development project. Two of the first three wells in this project were drilled on our leasehold 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

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production rates in excess of 11 million cubic feet per day. In 2004, the three Participating Areas of the Mesa Unit produced a

total of 56.2 billion cubic feet of natural gas and 439,364 barrels of oil. Our net production fromthe Mesa Unit in 2004 was

793 million cubic feet and 4,431 barrels of oil.

In the Mesa “A” Participating Area, where we have an overriding royalty interest, there were 13 producing wells that

produced a total of 13.5 million cubic feet of natural gas and 127 barrels of oil in 2004 to our interest. We have an overriding

royalty interest of .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 24 producing wells that produced 503 million cubic feet of natural

gas and 3,863 barrels of oil in 2004 to our interest. We have a net acre position of 100 net acres under a gross of 800 acres in the

“B” Participating Area.

In the Mesa “C” Participating Area, where we have a carried 6.4% working interest after payout, 13 wells produced 277 million

cubic feet and 441 barrels of oil per day in 2004 to our interest. We have 65.27 net acres under 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, it appears that we will move in and out of payout as additional wells are drilled.

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 and expanding

gas market in southern California. It is anticipated that this property will continue to produce significant revenues for us in the

future.

EASTERN WASHAKIECOAL BED NATURAL GAS PROJECT

This play is a 40-mile long trend located in south central Wyoming, fromthe town of Baggs at the south end, and to the town

of Rawlins at the north end. Over 100 wells have been drilled by Double Eagle or Anadarko to evaluate the potential of the

Mesaverde coal beds in this trend. The Mesaverde coals in this area differ fromthose 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. Several wells in our Eastern Washakie play have shown

extended production of over 500 mcfpd with over 1,000 barrels of water per day. The Company has acquired interests in 60,081

acres (29,661 net acres) and controls operations on over 250 undrilled locations on 80 acre spacing. Results fromthe early

exploratory drilling by these companies have been very encouraging. The following descriptions are of development areas

along the fairway for this play.

COW CREEKFIELD

We acquired the Cow Creek Field in the heart of the Eastern Washakie Coal Bed Natural Gas Project fromKCS Mountain

Resources in April 1999. The field had one producing gas well, the Cow Creek #1-12, which was producing, sporadically,

140,000 cubic feet of gas per day fromthe Dakota and Frontier Formations at 8,000 feet. In the year 2000, we re-completed two

wells in the Mesaverde coals. One of these wells produced at an average rate of 58,000 cubic feet 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 contents. We drilled four additional wells in September 2002, and we completed

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and connected themto the sales line in November 2002. We drilled five additional wells in the fall of 2003, and began producing

themin 2004. On March 17, 2004, nine coal bed wells produced 4.848 million cubic feet of gas and sold 4.530 million cubic feet of

natural gas. On March 17, 2005, fourteen coal bed wells, including the nine that were producing the prior year, produced

6.626 million cubic feet of natural gas and sold 6.086 million cubic feet of natural gas. The water to gas ratio is dropping in each

of the wells, although the volume of water has not diminished significantly. 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 increase the gas volumes along

the crest of the structure. We look forward to being able to drill additional wells in this pod to properly test the economic

potential of these coals. Additional drilling is currently on hold until the Environmental Impact Study is completed which is

expected in the fourth quarter of 2005. Total production at the Cow Creek Unit in 2003 was 490 million cubic feet net to us and

1,448 million cubic feet net to us in 2004.

SUN DOGUNIT

The Sun Dog Unit is adjacent to and east of Cow Creek Field. Anadarko operates the unit in which Double Eagle has an interest

in 1,378 acres. Anadarko initially drilled ten wells in which Double Eagle had no financial interest. The ten wells have been

producing since July 2002 and appear to have started the desorption process. In 2005, Anadarko has drilled two additional

producers on acreage in which Double Eagle has an interest. Our interest in these two wells will translate into a small interest in

these two wells and the previous ten producers, all of which together comprise the Sun Dog Unit. We have not received the

final accounting to know our exact interest in the twelve producing wells at the Sun Dog Unit. 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 completion of the Environmental Impact Statement. During 2004, the ten wells at the Sun Dog Unit produced

a total of 1,084 million cubic feet of gas, or an average of 297 mcf per well per day. In December 2004, the wells averaged 453 mcf

per day.

DOTYMOUNTAIN POD

The Doty Mountain Pod is a coal bed methane pilot project located sixmiles to the northeast of the Cow Creek Field. Anadarko

operates the unit in which Double Eagle has an interest in 3,280 acres. Anadarko drilled and completed 24 wells in this pod and

was completing the infrastructure at the end of 2004. Gas sales began in March 2005. The Mesaverde coals at Doty Mountain

were thicker than at Cow Creek and had higher gas contents. Permeability was measured at over 150 millidarcies in the main

coal. We are optimistic about this project, and we expect to have 25.9% working interest in the twenty-four wells after the

Participating Area is established.

OTHER UNITS

Double Eagle also has small interests in the Brown Cow, Blue Sky, Jolly Roger and Red RimUnits that are all operated by

Anadarko. As of December 31, 2004, no significant gas sales had occurred fromthese units.

ROCKYMOUNTAIN OVERTHRUST

The Rocky Mountain Overthrust runs fromCanada to Mexico and consists of many traps created as the Pacific Continental

plate was thrust over the Continental Plate. Traps creating oil and gas fields have been located primarily in Canada and

Wyoming, and several large fields have been discovered by other companies since the 1970s. The region is still relatively

unexplored because, despite large reserve potential, exploration in this area is very expensive and risky, and seismic data has

not been very reliable.

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CHRISTMAS MEADOWS PROSPECT

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. After nearly ten years of

addressing various regulatory hurdles in this environmentally sensitive area, Double Eagle and its partner, John Lockridge,

intend to drill this prospect in 2005.

The Christmas Meadows Prospect has a long history. In the 1970s Gulf noted the structure on a regionalseismic 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. Double Eagle acquired its 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 Double Eagle as its agent. Double Eagle has purchased the Chevron leasehold and

has farmouts fromAmerac (now Unit Corp.) and Judy Yates, and finally acquired the open offset acreage at a BLM auction in

November 2003. Combined with new leases purchased at lease sales, Double Eagle and Lockridge control 41,237 acres, of which

23,577 acres are included in the Table Top Federal Exploratory Unit.

Prospective formations range fromdepths of 5,000 to 23,000 feet, and range in age fromMississippian 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 is

projected to a depth of 16,000 feet, and we believe it has a high risk, high reward potential. There is also engineering risk to

consider, as there is a time deadline once operations commence and the overlying structure is complexand potentially difficult

to drill.

The Company has expended considerable resources in preparing to drill this prospect, projected to spud in summer 2005. The

update of the EIS was completed in January 2005, clearing the final regulatory hurdle to commence operations. Forest Service

has informed us that operations may commence as soon after July 1, 2005 as moisture levels in the soil permit.

Along with our partners, we have acquired licenses to six2D 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.

Double Eagle now owns 61% interest in the prospect and is the operator. It is the company’s intention to retain 25% working

interest, and Double Eagle is actively seeking partners for the remaining 36%.

SAGECREEKPROSPECT

We hold a 60% working interest in 1,892 acres of leases in the Sage Creek Prospect in the southwestern Montana portion of the

overthrust belt. We believe that this area appears to have potentialsimilar to other areas in the Wyoming portion of the

overthrust belt. Amoco, Exxon and Marathon did seismic work and drilled wells in this area during the 1980s, but found no

commercial deposits. Our main emphasis is directed at testing a well location that was permitted in 1986 by Amoco, but was

never drilled. This area is close to a Wilderness Study Area, and the Bureau of Land Management is conducting an

environmental impact statement and updating its Resource Management Plan prior to offering oil and gas leases. This process

is expected to be completed in August 2005. Our current leasehold is suspended until then.

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WIND RIVER BASIN

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 28,709 gross acres and 3,686 net acres of leases in this Basin.

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 Burlington. We own a significant working interest in 1,571 acres on the anticline and interests that are restricted in depth

and size in an additional 12,000 acres.

Madden FieldandLong Butte Field

In 2004, the Madden Field was combined with the Long Butte Field, and produced over 152 billion cubic feet of natural gas,

making the field’s cumulative production over one trillion cubic feet fromsixformations at depths of 3,000 to 25,000 feet. In

2004, our net production at Madden was 12,815 mcf. The unit’s primary operator, Burlington Resources, plans to drill a number

of additional wells to produce fromthe lower Fort Union and the deep Madison. We operate and produce fromone lower Fort

Union well and one upper Fort Union well. The Company will produce these two wells to evaluate the potential for offsets.

Since the Long Butte Field was combined with Madden Field, we will have the opportunity to participate in the deep Paleozoic

producing wells and the associated gas plant. We are currently evaluating the economics of paying the costs of joining this

large and expensive producing area. We had net production fromthe Long Butte Participating Areas of 22,313 mcf in 2004.

SOUTHSAND 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 five years and currently have 1,054 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 in 2005. Our net production

at South Sand Draw was 31,110 mcf in 2004.

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MINING

ZEOLITECLAIMS

Since 1972, we have owned mining claims covering 320 acres of land in Lander County, Nevada and 640 acres of land in

Owyhee County, Idaho. Due to natural outcrops, other sampling and analysis, the claims are believed to overlie significant

deposits of clinoptilolite, which is one of 34 naturally occurring zeolites. Although the existence of these deposits has been

indicated for some time, no commercial mining operations have been conducted on the claims because significant markets for

zeolites have not yet been developed. Zeolites currently are utilized commercially for small consumption items such as cat litter,

deodorant and aquariumfilter material, but the amount of consumption fromthese markets has not justified large scale

production to date. In 2001, we had the opportunity to submit bids to supply zeolite for several wastewater projects. While we

were not successful in securing these particular bids, we will continue to respond to opportunities of this nature. We also

joined with another company to formulate a Zeolite/Bentonite mixture designed as an improved cat litter. We intend to continue

our efforts to find an industrial use for our zeolites.

PRODUCTION

The following table sets forth oil and gas production fromour net interests in producing properties for the year ended

December 31, 2004 and December 31, 2003.

Year ended December 31,

2004 2003

Quantities

Oil (Bbls) 16,886 17,344

Gas (Mcf) 2,559,557 1,320,850

Average Sales Price

Oil ($/Bbl) 37.59 28.37

Gas ($/Mcf) 4.85 4.23

Average Production Cost ($/Mcfe) 0.81 0.72

Average Production Tax($/Mcfe) 0.62 0.51

Our oil and gas production is sold on the spot market or sold at the monthly indexexcept for sixfirmcommitment contracts.

These contracts commit us to sell 2,188,000 mmbtus of gas related to these contracts over a 27 month period beginning

January 1, 2005. The quantity, termand price per mmbtu are as follows:

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Price

Quantity Per Day Term ($/Mmbtu)

1,000 Mmbtu 1/05 - 4/05 5.31

1,000 Mmbtu 1/05 - 10/06 5.50

1,000 Mmbtu 1/05 - 10/05 5.80

500 Mmbtu 2/05 - 1/06 5.30

500 Mmbtu 2/05 - 1/06 5.30

1,000 Mmbtu 4/05 - 3/07 6.00

During the year ended December 31, 2004, purchases by Summit Energy, LLC represented more than 76 percent of our total

revenues. We believe the Company would be able to locate alternate customers in the event of the loss of this customer.

Reserve Replacement Costs

For the one year period ending December 31, 2004, the Company increased its reserves by 15.2 bcfe. During the same period,

Double Eagle expended $8.7 million in finding and development costs, defined as development and exploration costs incurred

by the Company during 2004. This activity resulted in a one year finding and development cost in 2004 of $.57 per mcfe. Proved

undeveloped reserves represented 75% of the increase in total reserves. The increase in proved undeveloped reserves is

largely attributed to two areas, Double Eagle’s operated field at Cow Creek, and the Mesa C, a non operated field, where Double

Eagle’s carried working interest paid out in April 2004. After an Environmental Impact Study is completed and filed which is

expected to occur by the end of 2005, Double Eagle intends to continue its development drilling programat Cow Creek in 2006.

Drilling on the Mesa C Unit is expected to continue over the next five years during which time the drilling of 20 new wells is

planned.

For the most recent three year and four month period including the 12 months ended December 31, 2004, December 31, 2003,

and August 31, 2002, we added 30.97 bcfe of reserves and expended $23.81 million. During the three year and four month

period, the Company achieved a finding and development cost of $.77 per mcfe.

Productive Wells

The following table categorizes certain information concerning the productive wells in which the Company owned an interest

as of December 31, 2004. We operate 23 wells in the State of Wyoming. We do not operate wells in any other State .

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Oil Gas

Gross Net Gross Net

Colorado — — 2 .0590

Mississippi 2 .0009 — —

Montana 2 .0960 — —

North Dakota 23 .2965 — —

Oklahoma — — 2 —

Utah — — 1 .0200

Wyoming 86 5.994 406 21.2781

Total 113 6.3874 411 21.3571

Wells Drilled

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 .

Year Ended December 31,

2004 2003

Gross Net Gross Net

Exploratory

Oil 1 — — —

Gas 38 6.61 1 .02

Dry Holes — — 1 .86

Salt Water Disposal 2 .52 — —

Other — — — —

Subtotal 41 7.13 2 .88

Development

Oil 1 .03 2 .04

Gas 64 2.78 34 5.37

Dry Holes — — — —

Salt Water Disposal 4 1.14 — —

Other 1 .05 — —

Subtotal 70 4.00 36 5.41

Total 111 11.13 38 6.29

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

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RESERVES

The reserves at December 31, 2004 and December 31, 2003 presented below were reviewed by Netherland, Sewell and

Associates. All reserves are located within the continental United States. The reserve estimates are developed using geological

and engineering data and interests and burdens 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. The outside reserve engineers reviewed over 99% of our reserves. The

notes following the table should be read in connection with the reserve estimates.

Oil & Gas Reserves (1) December 31,

2004 2003

Proved Developed Oil Reserves (Bbls) 181,397 179,228

Proved Undeveloped Oil Reserves (Bbls) 96,658 29,729

Total Proved Oil Reserves (Bbls) 278,055 208,957

Proved Developed Gas Reserves (Mcf) 17,161,577 16,055,045

Proved Undeveloped Gas Reserves (Mcf) 17,773,169 6,763,935

Total Proved Gas Reserves (Mcf) 34,934,746 22,818,980

Total Proved Gas Equivalents (Mcfe) (3) 36,603,076 24,072,722

Present Value of Estimated Future Net Revenues Before Income Taxes, Discounted At 10% (2)

(4) $68,604,700 $56,325,300

(1) The Company’s annual reserve reports are prepared as of the last day of the Company’s fiscal year.

(2) The present value of estimated future net revenues as of each period 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, 2003 and 2004,

respectively, were $5.75 per mcf and $30.20 per barrel of oil (2003), and $5.51 per mcf and $40.25 per barrel of oil (2004).

(3) Oil is converted to mcf of gas equivalent at one barrel equals 6,000 cubic feet.

(4) The “Present Value of Estimated Future Net Revenues Before Income Taxes Discounted At 10%”, is referred to as the

“Standardized Measure”.

Reference should be made to the supplemental oil and gas information included in this Form10-KSB for additional information

pertaining to the Company’s proved oil and gas reserves as of the end of each of the last three fiscal years.

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ACREAGE

The following tables set forth the gross and net acres of developed and undeveloped oil and gas leases in which the Company

had working interests and royalty interests as of December 31, 2004. The category of “Undeveloped Acreage” in the tables

includes leasehold interests that may have been classified as containing proved undeveloped reserves.

Working Interests

Developed Undeveloped Total

Acres (1) Acres (2) Acres

State Gross Net Gross Net Gross Net

Colorado — — 80 80 80 80

Montana 29 1 2,277 1,174 2,306 1,175

North Dakota 2,240 49 2,560 64 4,800 113

Utah 637 16 45,573 25,923 46,210 25,939

Wyoming 73,554 4,339 121,680 57,711 195,234 62,050

Other — — 49,838 49,838 49,838 49,838

Total 76,460 4,405 222,008 134,790 298,468 139,195

Royalty Interests

Developed Undeveloped Total

Acres (1) Acres (2) 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 9,823 162 29,189 1,528 39,012 1,690

Total 12,912 225 87,733 2,142 100,645 2,367

(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 wellspacing 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 fromthe 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:

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Year Ending Expiring Acreage

Gross Net

December 31, 2005 17,511 11,830

December 31, 2006 11,414 4,657

December 31, 2007 and later 370,188 125,075

Risk Factors

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 adversely affect our

business, operating results and 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 Form10-KSB, and the forward-looking statements included or

incorporated by reference herein describe additional uncertainties associated with our business.

We have hadoperating losses in the past

We have reported net losses for the fiscal years ended August 31, 2002 and for other previous years, as well as for the 4-month

period ended December 31, 2002. There is no assurance that our current or future operations will be profitable.

We dependon a key employee

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 do carry “key man” life insurance on Mr. Hollis in the amount of $1,000,000.

We cannot predict the future price of oil andnatural gas

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 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 couldbe adversely impactedby changes in the oil andgas market

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

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all could adversely affect our ability to produce and market its 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 fromthe sale of

production. The availability of markets is beyond our control.

We may be unable to findadditional reserves

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 drill productive wells at low reserve replacement costs.

Our stock price may be adversely impactedby our choice of accounting method

We use the “successful efforts” method for capitalizing costs of completed oil and gas wells. Under the successful efforts

method, only the costs attributable to successful exploratory wells and the costs of development wells within a producing field

are reflected in property and equipment. Producing and non-producing properties are evaluated periodically and, if conditions

warrant, an impairment allowance is provided. The impairment allowance is a one-time charge to earnings which does not

impact cash flow fromoperating activities, but may result in a negative impression in the investment community and lower

stock prices.

Oil andgas operations are inherently risky

The nature of the oil and gas business involves a variety of risks, including the risks of operating hazards such as fires,

explosions, cratering, blow-outs, and encountering formations with abnormal pressures. The occurrence of any of these risks

could result in losses. We maintain insurance against some, but not all, of these risks. Management believes that the level of

insurance against these risks is reasonable and is in accordance with customary industry practices. The occurrence of a

significant event, however, that is not fully insured could have a material adverse effect on our financial position and results of

operations.

Newgovernment regulation andenvironmental risks couldincrease our costs

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

include:

• the prevention of waste

• the discharge of materials into the environment

• the conservation of oil and natural gas, pollution, permits for drilling operations, drilling bonds, reports concerning

operations

• the spacing of wells

• the 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.

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Our prices may be impactedadversely by newtaxes

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 taxproposals. 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 andfuture net revenues may differ significantly from our estimates

This Form10-KSB contains estimates of our reserves and future net revenues. We prepared these estimates and they were then

reviewed by an independent petroleumengineer. 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 fromthe 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 fromthe estimated amounts. In addition, estimates of reserves are extremely sensitive

to the market prices for oil and gas.

There is limitedliquidity in our shares

There is a limited market for our shares and an investor cannot expect to liquidate his investment regardless of the necessity of

doing so. The prices of our shares are highly volatile. This could have an adverse effect on developing and sustaining the

market for our securities. In addition, there is no assurance that an investor will be in a position to borrow funds using our

shares as collateral.

ITEM 3. LEGAL PROCEEDINGS

We are not a party to any pending legal proceeding (nor is our property subject of a pending legal proceeding) other than

routine litigation incidental to our business that may arise fromtime to time.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS

Not applicable.

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PART II

ITEM 5. MARKET FOR COMMON EQUITYAND RELATED STOCKHOLDER MATTERS

Market Information. Our Common Stock is traded in the over-the-counter market and listed on the Nasdaq SmallCap Stock

Market under the symbol “DBLE”.

The range of high and low sales prices for our Common Stock for each quarterly period fromJanuary 1, 2002 through

December 31, 2004, as reported by Nasdaq, is as follows:

Common Stock (“DBLE”)

($ / Share)

Quarter Ended High Low

March 31, 2002 4.61 3.44

June 30, 2002 5.10 4.05

September 30, 2002 4.05 2.78

December 31, 2002 6.11 3.60

March 31, 2003 7.65 5.54

June 30, 2003 7.95 6.04

September 30, 2003 12.20 7.40

December 31, 2003 16.46 10.11

March 31, 2004 16.60 12.26

June 30, 2004 15.45 12.20

September 30, 2004 18.36 13.60

December 31, 2004 20.43 14.48

On March 16, 2005, the closing sales price for the Common Stock as reported by Nasdaq was $21.78 per share.

Holders On March 16, 2005, the number of holders of record of common stock was 1,536.

Dividends We have not paid any cash dividends since our inception. We anticipate that all earnings will be retained for the

development of our business and that no cash dividends will be paid on our Common Stock in the foreseeable future.

Equity Compensation Plan Information

The following table provides information as of December 31, 2004 with respect to shares of common stock that may be issued

under Double Eagle’s 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.

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(a) (b) (c)

Number of Number of securities

securities to be Weighted- remaining available

issued upon average for future issuance

exercise of exercise price under equity

outstanding of outstanding compensation plans

options, options, (excluding securities

warrants and warrants and reflected in column

Plan category rights rights (a)

Equity Compensation plans approved by security holders 275,843 $14.32 395,371(1)

Equity Compensation plans not approved by security holders 5,000(2) 6.15 —

Total 280,843 10.97 395,371

(1) Represents no shares available for issuance under the 1996 Stock Option Plan, no shares for issuance under the 2000 Stock

Option Plan, 125,371 shares available for issuance under the 2002 Stock Option Plan and 270,000 shares available for issuance

under the 2003 Stock Option and Compensation Plan.

(2) Certain options were granted to directors and officers outside of our plans which were not approved by shareholders. These

options vest over a three year period fromthe grant date and expire three to five years fromthe grant date.

Recent Sales of UnregisteredSecurities

None

ITEM 6. MANAGEMENT’S DISCUSSION AND ANALYSIS OR PLAN OF OPERATIONS

Forward-Looking Statements

This Form10-KSB includes “forward-looking statements” within the meaning of Section 27A of the Securities Act Of 1933, as

amended (the “Securities Act”), and Section 21E of the Securities Exchange Act Of 1934, as amended (the “Exchange Act”). All

statements other than statements of historical fact, included in this Form10-KSB are forward-looking statements. These

forward-looking statements include, without limitation, statements located under “ITEMS 1 AND 2. DESCRIPTION OF

BUSINESS AND PROPERTIES — Business Strategy”, “ — Principal Areas Of Oil And Gas Activity”, “ — Zeolite Claims”, and

“ — Reserves”, “ITEM 6. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIALCONDITION AND RESULTS

OF OPERATIONS — Financial Conditions, Liquidity And Capital Resources”, and Notes to the Financial Statements located

elsewhere herein regarding the Company’s financial position and liquidity, the amount of and its ability to make debt service

payments, its strategies, financial instruments, and other matters. In addition, the words ‘‘believe,’’ ‘‘may,’’ ‘‘could,’’ ‘‘will,’’

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‘‘when,’’ ‘‘estimate,’’ ‘‘continue,’’ ‘‘anticipate,’’ ‘‘intend,’’ ‘‘expect’’ and similar expressions, as they relate to Double Eagle,

our business or our management, are intended to identify forward-looking statements. Although the Company believes that the

expectations reflected in these forward-looking statements are reasonable, it can give no assurance that these expectations will

prove to be correct. Important factors that could cause actual results to differ materially fromthe Company’s expectations are

disclosed in this Form10-KSB, including without limitation in the “ — Risk Factors” section below and in conjunction with the

forward-looking statements included in this Form10-KSB.

The Company’s intentions and expectations described in this Form10-KSB with respect to possible exploration and other

testing activities concerning properties in which it holds interests may be deemed to be forward-looking statements. These

statements are made based on management’s current assessment of the exploratory merits of the particular property in light of

the geological information available at the time and based on the Company’s relative interest in the property and its estimate of

its share of the exploration costs. Subsequently obtained information concerning the merits of any property as well as changes

in estimated exploration costs and ownership interests may result in revisions to management’s expectations and intentions,

and thus the Company may delete one or more of these intended exploration activities. Further, circumstances beyond the

Company’s control may cause such prospects to be eliminated fromfurther consideration as exploration prospects.

Actual results could differ materially fromthese forward-looking statements as a result of, among other things:

• failure to obtain, or a decline in, oil or gas production, or a decline in oil or gas prices,

• incorrect estimates of required capital expenditures,

• increases in the cost of drilling, completion and gas collection or other costs of production and operations,

• an inability to meet growth projections, and

• other risk factors set forth under ‘‘ — Risk Factors’’ in this annual report.

OVERVIEW

Double Eagle PetroleumCo. (“Double Eagle” or the “Company”) is a rapidly growing independent energy company engaged in

the exploration, development, and production of natural gas and crude oil in the Rocky Mountain Basins of the western United

States. The Company’s principal properties are located in Southwestern Wyoming. The Company aggressively pursues

development primarily in the conventional deep gas reserves and production fromthe Pinedale Anticline and the shallow coal

bed methane reserves and production in the Eastern Washakie Basin.

The Company seeks to increase its reserves, production, revenues, and cash flow by focusing on: (i) new coal bed methane

development and enhancement of our field facilities in the Eastern Washakie Basin, (ii) continued participation in the

development of the Mesa Field on the Pinedale Anticline, (iii) selective pursuit of high potential exploration projects, and

(iv) selected acquisition opportunities in areas where we have accumulated detailed geological knowledge and developed

significant management expertise.

During 2004, the Company achieved improved results in several fundamental and strategic areas:

• Production increased 87% in 2004, from1.4 bcfe in 2003 to 2.7 bcfe during 2004. The coal bed methane production at

Cow Creek field accounted for 78% of the increase where the Company’s average daily production increased 196%,

from1,340 mcf per day in 2003 to 3,968 mcf per day in 2004.

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• Oil and gas sales increased 115% in 2004, from$6.1 million in 2003, to $13.1 million in 2004. Production increases

accounted for 75% of the increase and increased prices accounted for the remaining 25% increase.

• Net income after taxes increased 315% from$0.97 million for 2003, to $4.03 million in 2004. Net cash provided by

operating activities increased 130%, from$3.24 million in 2003 to $7.43 million in 2004.

• After accounting for 2004 production of 2.7 bcfe, the Company’s proved reserves increased 63% as year end reserves

increase from24.1bcfe at December 31, 2003 to 36.6 bcfe at December 31, 2004. The Company replaced over 575% of its

production in 2004 at a finding and development cost of $0.57 per Mcfe without acquiring existing reserves fromthird

parties.

• The Company incurred $8.4 million in development costs during the year. Major project spending included $3.2 million

at Cow Creek to complete five wells drilled in 2003, and expand both power generation and compression facilities. The

Company also participated in new development drilling in the Mesa Field of the Pinedale for $2.3 million and additional

drilling in the Eastern Washakie for $2.6 million.

FACTORS AFFECTINGFINANCIAL CONDITION AND LIQUIDITY

Liquidity andCapital Resources

During 2004, we improved our liquidity by increasing our working capital by 153%, from$281,000 at December 31, 2003 to

$710,000 at December 31, 2004. Our working capital decreased in the fourth quarter of 2004 primarily due to significant

development activity during the period. As a result, $3.05 million of capital additions were financed through accounts payable

and accrued liabilities at the end of the year. Consequently, our current liabilities increased 46% over our current liabilities at

December 31, 2003. We anticipate that current cash reserves and first quarter 2005 cash flow will be adequate to satisfy the

Company’s current obligations at year end. The Company has no long termdebt at December 31, 2004. We expect our current

cash reserves, future operating cash flow, and if necessary, availability fromour line of credit will provide adequate resources

to develop our major natural gas projects in the Eastern Washakie Basin and the Pinedale Anticline of Wyoming.

Net cash flow provided by operating activities for 2004 was $7,435,000, representing a 130% increase over the $3,239,000 net

cash flow provided by operating activities for the same period last year. Revenues increased 116% while operating expenses

excluding non cash expenses of depreciation, depletion, amortization, and impairment increased only 75%. During 2004, the

Company incurred $8.40 million on development projects, which included $3.05 million in current liabilities at December 31, 2004.

The Company also funded $2.56 million of property additions fromthe fourth quarter of 2003 which were included in accounts

payable at December 31, 2003. The 2004 capital additions were funded through cash flow fromoperations, existing cash

reserves and an increase in current liabilities at year end.

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The Company incurred $3.17 million to complete wells, stimulate production, and expand our power generation and field

compression facilities at Cow Creek during 2004. We also participated in the continued drilling of new development wells

operated by Questar/Wexpro in the Pinedale Anticline both in the Mesa B Unit and the Mesa C Unit where Double Eagle has a

“carried working interest.” Capital expenditures in the Mesa Units aggregated $2.26 million. Additionally, we expended $2.60

million through participation in 24 new coal bed methane wells drilled by Anadarko at Doty Mountain, which is sixmiles

northeast of our current production at Cow Creek. The additional facilities and wellservicing at Cow Creek increased

production in the first quarter of 2005. On March 17, 2005, the Cow Creek Field produced 6.6 Mcf of natural gas and sold 6.1

Mcf natural gas. New development drilling in the Mesa Field of the Pinedale Anticline during the second half of 2004 increased

our net production in that field by 50% in the fourth quarter of 2004 to over 2.2 Mcfe per day net to the Company. Production at

Doty Mountain is currently not commercial during the dewatering phase.

Capital Requirements

As in 2004, the Company plans to manage its capital budget with the objective of funding capital expenditures with internal

cash flow. The capital budget for 2005 is $8.9 million, which we are anticipating will increase production. The projected

spending will continue to focus on additional development drilling in the Mesa Units on the Pinedale Anticline, further

development drilling in the Eastern Washakie Basin, and several exploration projects, including the Christmas Meadows

prospect in northeastern Utah. In the Mesa B Participating Area of the Mesa Field, the Company participated in the drilling of 6

new development wells during the third quarter of 2004. The Company’s working interest in each of these wells is

approximately 9%. The Company intends to spend $1.5 to $2.0 million on new development drilling at Mesa in 2005. The

Company also intends to participate in new drilling activity in coal bed methane projects operated by Anadarko in Eastern

Washakie. Additionally, the Company has committed to spend approximately $1.2 million on new power generation equipment

at Cow Creek and approximately $700,000 to drill an exploratory well to test the Cow Creek and Deep Creek sands. If no

commercial gas is found, the well will be used as an injection well. The primary exploratory project scheduled during 2005 is the

drilling of the Christmas Meadows prospect in late summer. The Company is currently reviewing its strategic alternatives with

respect to the operation and participation in the project.

Line of Credit

The Company maintains a line of credit with its banking affiliate secured by its oil and gas properties. Currently the Company

has $9 million of availability on the line which may be adjusted annually for changes in reserves and production pricing.

Interest on future borrowings against the line would be assessed at the Bank’s prime rate. The line has been inactive since the

last quarter of 2003.

RESULTS OF OPERATIONS

Year EndedDecember 31, 2004 Comparedwith the Year EndedDecember 31, 2003

Oil and gas sales volume and price comparisons for the indicated periods are set forth below.

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Year Ended Year Ended Percent Percent

December 31, 2004 December 31, 2003 Change Change

Product Volume Price Volume Price Volume Price

Gas 2,559,557 $ 4.85 1,320,850 $ 4.23 +94% +15%

Oil (bbls) 16,846 $ 37.59 17,344 $ 28.37 -3% +33%

Mcfe 2,660,871 $ 4.90 1,424,914 $ 4.26 +87% +18%

Oil and gas sales increased 115% in 2004, compared with 2003, to $13,058,000 from$6,081,000. The increase is due primarily to a

87% increase in gas production, most of which occurred at Cow Creek, our coal bed methane development project in the

Eastern Washakie Basin in South Central Wyoming. The Company’s total average daily production increased to 7,290 mcfe in

2004 compared with average daily production of 3,904 mcfe during 2003. Gas prices continued to escalate during the year and

averaged $5.10 per mcf during the fourth quarter of 2004. The increased revenues associated with higher levels of production

also brought about a corresponding increase in total operating costs and depletion expense. However, the gross margin per

mcfe remains at economically favorable levels, increasing in 2004 by $.38 per mcfe, a 20 % increase over the gross margin per

mcfe in 2003.

Per Mcfe

2004 2003

Average Revenue 4.91 4.27

Production & Ad Valorem 1.46 1.23

Depletion 1.14 1.11

Total Operating Costs 2.60 2.34

Gross Margin 2.31 1.93

Cash flow per mcfe, defined as gross margin plus depletion, increased by $.40 per mcfe, or 13%, from$3.04 per mcfe in 2003 to

$3.45 per mcfe in 2004.

Future Gas Sales Contracts

The Company currently does not enter into hedging agreements as a means of reducing the impact of price volatility. However,

we have entered into fixed delivery contracts for approximately 45% of our current daily production at December 31, 2004. As of

January 1, 2005, the Company has the following open sales delivery contracts associated with future production: (Volume and

Daily Production are expressed in mcfs)

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Average

Daily Price

Property Volume Production Term ($/mcf)

Cow Creek 120,000 1,000 1/05 - 4/05 5.31

669,000 1,000 1/05 - 10/06 5.50

182,500 500 2/05 - 1/06 5.30

730,000 1,000 4/05 - 3/07 6.00

Total Cow Creek 1,701,500

Mesa 304,000 1,000 1/05 -10/05 5.80

182,500 500 2/05 - 1/06 5.30

Total Mesa 486,500

Total Company 2,188,000

The forward gas sales delivery contracts will generate a weighted average price of $5.68 per mcf for 2.2 bcf of contracted gas

sold over the next 27 months beginning in the first quarter of 2005.

Mesa C CarriedWorking Interest

The Company’s “carried working interest” in Participating Area “C” in the Mesa Unit of the Pinedale Anticline was determined

by the operator, Wexpro Company, to have paid out in April 2004. Since the payout, we have recognized monthly production

fromthe participating area of approximately 30,000 mcf per month resulting in incremental revenues of $1.4 million in 2004.

Under the terms of the Participating Area agreement, production revenue earned by the Company could be temporarily

interrupted as new drilling costs are incurred and the property reverts to a “pre payout” status. New drilling was undertaken by

the operator during 2004. However, production revenues fromthe unit offset the capital costs incurred and did not significantly

effect our monthly cash flow for our interest in the participating area.

Other Expenses

General and administrative expenses increased 27% to $1,581,000 in 2004 compared to $1,250,000 in 2003. The Company

incurred additional costs in 2004, in part because of maintaining a Denver office for a full year in 2004, compared to eight

months in 2003. In addition, the Company relocated its Denver area office to the business district in downtown Denver and

increased its office space by 70%. The increase in general and administrative expense is also attributable to additional

employees hired in Denver to accommodate corporate growth. Overall, general and administrative expense per mcfe decreased

in 2004 compared to 2003 by 27%, from$.88 per mcfe in 2003 to $.59 per mcfe in 2004.

The Company impaired the value of its interest in a non-producing property, Cave Gulch, by $155,000 during 2004, as no

progress was made to develop the property by the operator. The Company had previously impaired its cost in the property by

$142,000 at December 31, 2003. The property is now fully impaired.

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Income Taxes

During the second half of 2004, the Company recorded income taxexpense of $450,000.

The income taxexpense has been recognized because the Company has fully offset its net deferred taxasset of $1,048,000 as of

December 31, 2003. This deferred taxestimate is attributed to sustained operating profits which offsets the previously

established valuation allowance. Although the Company expects to continue to generate losses for taxpurposes, the

Company’s sustained net operating income has resulted in a deferred taxposition as required under generally accepted

accounting principles. If the Company continues to generate operating income, as expected, it will be required to recognize

deferred taxexpense at an effective rate of approximately 34% throughout the year.

Net Income

The increased gas production, higher gas prices, and the related increased gross margin per mcfe generated a 315% increase in

net income after provision for taxes during 2004 compared to 2003. Net income escalated to $4.03 million, or $.47 per diluted

share in 2004 from$.97 million, or $.14 per diluted share in 2003. Similarly, net cash flow fromoperating activities, increased

130% when comparing net cash flow fromoperating activities of $7.43 million in 2004 to $3.24 million during 2003.

Critical Accounting Policies andEstimates

The Company’s discussion and analysis of its financial condition and results of operations are based on financialstatements

prepared in accordance with accounting principles generally accepted in the United States. The preparation of its financial

statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities,

revenues and expenses.

The Company recognizes oil and gas revenues for only its ownership percentage of total production in the period delivered

under the entitlement method.

Reclassification

Certain reclassifications have been made to the 2003 financialstatements to conformto the 2004 presentation. Such

reclassifications had no effect on net income.

We believe the following critical accounting policies affect our more significant judgments and estimates used in the

preparation of our financialstatements.

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

fromthe area compared with production fromother 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 fromactual 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

frommay 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.

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Actual production, revenues and expenditures with respect to our reserves will likely vary fromestimates, and such variances

may be material.

Many factors will affect actual net cash flows, including

• the amount and timing of actual production

• supply and demand for natural gas

• curtailments or increases in consumption by natural gas purchasers

• changes in governmental regulations or taxation

Property, Equipment andDepreciation

We follow the successful efforts method of accounting for oil and gas properties. Under this method, all costs incurred in

connection with the exploration for and development of oil and gas reserves are capitalized. Under this method, leasehold costs

are capitalized as incurred. Costs of productive wells, unsuccessful developmental wells and the related costs of productive

leases are capitalized and amortized on a unit-of-production basis through depletion, depreciation, and amortization over the

life of the associated oil and gas reserves Exploratory expenses, including geological and geophysical expenses, and delay

rentals are charged to expense as incurred. Exploratory drilling costs are capitalized but changed to expense if the well is

determined to be unsuccessful.

Oil and gas property costs are periodically evaluated for possible impairment. Impairments are recognized when management

determines that a property’s net book value can not be realized based upon current estimates of expected future cash flows.

Depletion, depreciation, and amortization of oil and gas properties and the periodic assessment for impairment are based on

underlying oil and gas reserve estimates and future cash flows using current oil and gas prices combined with operating and

development costs. Costs associated with production and general corporate activities are expensed in the period incurred.

NewAccounting Pronouncements

The Company intends to adopt SFAS 123R issued by the FASB in December 2004. The effective date of SFAS 123R for public

companies is for interimor annual periods beginning after June 15, 2005. The pronouncement addresses the accounting for

transactions in which an entity exchanges its equity instruments for goods or services.

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DOUBLE EAGLE PETROLEUM CO.

ITEM 7. FINANCIAL STATEMENTS AND ADDITIONAL INFORMATION

Index

Page

Numbers

(1) Report of Registered Independent Public Accounting Firm F-2

Financial Statements:

Balance Sheets as of December 31, 2004 and 2003 F-3

Statements of Operations for the years ended December 31, 2004 and 2003 F-4

Statements of Changes in Stockholders’ Equity for the year ended December 31, 2004 and 2003 F-5

Statements of Cash Flows for the years ended December 31, 2004 and 2003 F-6

Notes to Financial Statements F-7 - F-16

(2) Supplemental Oil and Gas Information (Unaudited) F-17 - F-19

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTINGFIRM

The Shareholders and Board of Directors

Double Eagle PetroleumCo.

Casper, Wyoming

We have audited the accompanying balance sheets of Double Eagle PetroleumCo. as of December 31, 2004 and 2003, and the

related statements of operations, stockholders’ equity, and cash flows for the years ended December 31, 2004 and December 31,

2003. These financialstatements are the responsibility of the Company’s management. Our responsibility is to express an

opinion on these financialstatements based on our audits.

We conducted our audits in accordance with auditing standards of the Public Company Accounting Oversight Board (United

States). Those standards require that we plan and performthe audit to obtain reasonable assurance about whether the financial

statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of

its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a

basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an

opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such

opinion. 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 financialstatement presentation. We believe that our audits provide a reasonable basis for our

opinion.

In our opinion, the financialstatements referred to above present fairly, in all material respects, the financial position of Double

Eagle PetroleumCo. as of December 31, 2004 and 2003 and the results of its operations and its cash flows for the years ended

December 31, 2004 and 2003 in conformity with US generally accepted accounting principles.

HEIN & ASSOCIATES LLP

Denver, Colorado

March 11, 2005

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DOUBLE EAGLE PETROLEUM CO.

BALANCE SHEETS

December 31,

2004 2003

ASSETS

Current assets

Cash and cash equivalents $ 3,669,950 $ 2,920,846

Accounts receivable 2,171,102 1,049,643

Other current assets 328,677 50,730

Total current assets 6,169,729 4,021,219

Properties and equipment

Developed properties 32,293,958 24,376,469

Undeveloped properties 3,026,168 3,017,954

Corporate and other 624,153 441,773

27,836,196

Less accumulated depreciation, depletion and impairment (11,185,792) (8,533,685)

Net properties and equipment 24,758,487 19,302,511

Other assets 41,125 631,187

Total assets $ 30,969,341 $23,954,917

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities

Accounts payable $ 1,597,224 $ 3,256,375

Accrued expenses 2,890,630 139,502

Accrued production taxes 971,710 344,234

Total current liabilities 5,459,564 3,740,111

Non current liabilities

Asset retirement obligation 406,865 358,500

Deferred taxliability 176,000 —

Total non current liabilities 582,865 358,500

Total liabilities 6,042,429 4,098,611

Commitments and contingencies (note 3 and 4)

Common stock, $.10 par value; 10,000,000 shares authorized; issued and outstanding

8,488,404 shares in 2004 and 8,334,404 in 2003 848,840 833,440

Capital in excess of par value 21,224,393 20,197,390

Retained earnings (deficit) 2,853,679 (1,174,524)

Totalstockholders’ equity 24,926,912 19,856,306

Total liabilities and stockholders’ equity $ 30,969,341 $23,954,917

See accompanying notes to financialstatements.

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DOUBLE EAGLE PETROLEUM CO.

STATEMENTS OF OPERATIONS

Year Ended December 31,

2004 2003

Revenues

Oil and gas sales $13,057,906 $6,080,880

Other income 209,167 57,532

Total revenues 13,267,073 6,138,412

Costs and Expenses

Production costs 2,155,600 1,026,591

Production taxes 1,644,770 731,418

Exploration expenses, including dry holes 323,822 231,244

General and administrative 1,581,192 1,249,520

Depreciation, depletion, and amortization of oil and gas properties 2,908,058 1,582,603

Impairment of producing properties 155,321 170,309

Cost of non-producing leases sold — 10,776

Total costs and expenses 8,768,763 5,002,461

Income fromoperations 4,498,310 1,135,951

Other income (expense)

Interest income (expense) 26,928 (174,629)

Other (47,035) —

Total other income (expense) (20,107) (174,629)

Income before income taxes 4,478,203 961,322

Provision for deferred taxes 450,000 —

Income before cumulative effect of change in accounting principle 4,028,203 961,322

Cumulative effect of change in accounting principle — 10,500

Net income $ 4,028,203 $ 971,822

Income per share before cumulative effect of change in accounting principle – basic and diluted .47 $ .14

Cumulative effect of change in accounting principle — —

Net income per common share – basic and diluted $ .47 $ .14

Weighted average shares outstanding – basic 8,469,852 7,027,426

Weighted average shares outstanding – diluted 8,599,020 7,163,206

See accompanying notes to financialstatements.

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DOUBLE EAGLE PETROLEUM CO.

STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

For the two years ended December 31, 2004

Additional Total

Outstanding Common Paid In Retained Stockholders’

Shares Stock Capital Earnings Equity

Balance at December 31, 2002 6,521,518 $652,152 $ 7,786,183 $(2,146,346) 6,291,989

Net income — — — 971,822 971,822

Common stock Issued:

Private placement 1,295,000 129,500 11,464,785 — 11,594,285

Exercise of warrants 300,500 30,050 383,138 — 413,188

Options exercised and shares issued for

compensation 217,386 21,738 563,284 — 585,022

Balance at December 31, 2003 8,334,404 $833,440 $20,197,390 $(1,174,524) $ 19,856,306

Net income — — — 4,028,203 4,028,203

Options exercised and shares issued for

compensation 154,000 15,400 1,026,821 — 1,042,221

Balance at December 31, 2004 8,488,404 848,840 21,224,211 2,853,679 24,926,730

See accompanying notes to financialstatements.

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DOUBLE EAGLE PETROLEUM CO.

STATEMENTS OF CASH FLOWS

Year ended December 31,

2004 2003

Cash Flows fromOperating Activities

Net income $ 4,028,203 $ 971,822

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation, depletion, amortization and accretion of asset retirement obligation 2,923,479 1,588,603

Abandonments and impairments 289,963 190,154

Cumulative effect of change in accounting principle — (10,500)

Gain on sale of other assets (141,451) (24,296)

Directors fees paid in stock 54,240 24,600

Deferred income taxes 450,000 —

Changes in operating assets and liabilities:

Accounts receivable (1,121,459) (175,748)

Prepaid expenses (277,947) (25,565)

Accounts payable and accrued expenses 602,039 500,824

Accrued production taxes 627,476 198,991

Net cash provided by operating activities 7,434,543 3,238,885

Cash Flows frominvesting activities

Proceeds fromsales of properties and assets 269,143 35,072

Other asset 10,000 (40,000)

Additions of producing properties and equipment (7,331,311) (6,478,831)

Acquisitions of corporate and non-producing properties (325,236) (2,284,923)

Net cash used in investing activities (7,377,404) (8,768,682)

Cash flows fromfinancing activities

Issuance of common stock — 11,594,285

Exercise of options and warrants 714,162 973,610

Net borrowings under line of credit arrangements — 2,850,000

Repayment of long-termdebt — (7,100,000)

Other (22,197) —

Net cash provided by financing activities 691,965 8,317,895

Increase in cash and cash equivalents 749,104 2,788,098

Cash and cash equivalents at beginning of period 2,920,846 132,748

Cash and cash equivalents at end of period $ 3,669,950 $ 2,920,846

Supplemental disclosures of cash and non-cash transactions

Cash paid during the year for interest $ 503 $ 193,508

Additions to developed properties included in accounts payable and accrued liabilities $ 3,050,000 $ 1,980,000

Additions to developed properties for retirement obligations $ 55,141 $ 352,500

Additions to other assets included in accounts payable $ — $ 580,062

Directors fees paid in stock 54,240 $ 24,600
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Cashless exercise of options $ — $ 164,430

Equity contribution related to exercise of non-qualified options $ 273,818 —

See accompanying notes to financialstatements.

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DOUBLE EAGLE PETROLEUM CO.

NOTES TO FINANCIAL STATEMENTS

1. Business

Double Eagle was incorporated under Wyoming law in 1972 and reincorporated under Maryland law in February 2001. The

Company explores for, develops, produces and sells crude oil and natural gas and maintains offices in Casper, Wyoming

and Denver, Colorado.

2. Summary of Significant Accounting Policies

Cash and Cash Equivalents

Cash in excess of daily requirements is invested in money markets and certificates of deposit with maturities of 90 days or

less. Such investments are deemed to be cash equivalents for purposes of the financialstatements.

Revenue Recognition

The Company recognizes oil and gas revenues for only its ownership percentage of total production in the period

delivered under the entitlement method.

Oil and Gas Properties

Double Eagle uses the successful efforts method of accounting for oil and gas producing activities. Under this method,

acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including

geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole

drilling costs, are expensed. Development costs, including the costs to drill and equip development wells, and successful

exploratory drilling costs that locate proved reserves, are capitalized. In addition, 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 of the capitalized costs for producing oil and gas properties are computed on the

units-of-production method based on proved oil and gas reserves. Depletion, depreciation and amortization of oil and gas

properties for the years ended December 31, 2004 and 2003, was $2,857,372 and $1,550,239, 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.

Change in Accounting Principle

In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which addresses financial

accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated

asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that

result fromthe 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.

SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be 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

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DOUBLE EAGLE PETROLEUM CO.

NOTES TO FINANCIAL STATEMENTS (continued)

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.

SFAS No. 143 was adopted by the Company as of July 1, 2003. The implementation of SFAS No. 143 resulted in a cumulative

effect of change in accounting principle of $10,500. During 2003, an increase of $353,000 in oil and gas properties reflected the

present value of the future asset retirement obligation and an offsetting increase in liabilities represents the establishment of an

asset retirement obligation liability. For the years ended December 31, 2004 and 2003, an expense of $15,000 and $6,000,

respectively was recorded as accretion expense on the liability. During 2004, the Company recorded an additional $55,000

increase in oil and gas properties and asset retirement obligation liability to reflect the present value of plugging liability on

new wells.

A reconciliation of the changes in the Company’s liability fromadoption at July 1, 2003 to December 31, 2004 is as follows:

Liability fromadoption of SFAS No. 143 July 1, 2003 $352,500

Accretion expense for 2003 6,000

Asset retirement obligation as of December 31, 2003 358,500

Liabilities incurred (net) 32,944

Accretion expense for 2004 15,421

Asset retirement obligation as of December 31, 2004 $406,865

Other Equipment

Office facilities, equipment and vehicles are recorded at cost. Depreciation is recorded using straight-line and accelerated

methods 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, 2004 and 2003 was $50,686 and $32,364, respectively.

Impairment of Long-Lived Assets

SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, requires that an asset be evaluated for impairment

when the carrying amount of an asset exceeds the sumof the undiscounted estimated future cash flows of the asset. In

accordance with the provisions of SFAS 144, 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 sumof the

undiscounted pretaxcash 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 evaluation, consist primarily of oil and gas properties. The Company recognized a

non-cash charge on producing properties during the years ending December 31, 2004 and 2003 of $155,321 and $170,309,

respectively for those properties with carrying values exceeding the expected undiscounted future net cash flows.

Other Assets

Included in other assets in 2003 is a deposit of $580,000 for oil and gas compressors, installed in early 2004.

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DOUBLE EAGLE PETROLEUM CO.

NOTES TO FINANCIAL STATEMENTS (continued)

Stock Based Compensation

The Company has elected to follow APB Opinion No. 25 and related interpretations in accounting for its stock options and

grants to employees and directors since the alternative fair market value accounting provided for under Statement of Financial

Accounting Standards (SFAS) No. 123 requires use of grant valuation models that were not developed for use in valuing

employee stock options and grants. Under APB Opinion No. 25, if the exercise price of the Company stock grants and options

equal the fair value of the underlying stock on the date of grant, no compensation expenses are recognized.

If compensation costs for the Company’s stock-based compensation plans had been determined based on the fair value at the

grant dates for awards under those plans consistent with the method of SFAS No. 123, then the Company’s net income and net

income per share would have been adjusted to the pro forma amounts indicated below:

Year Ended December 31,

2004 2003

Net income as reported $4,028,203 $971,822

Deduct:stock based compensation cost under SFAS 123 (233,323) (62,963)

Pro Forma net income 3,794,880 908,859

Reported net income per common share – basic and diluted .47 .14

Pro forma net income per common share basic and diluted .44 .13

Pro forma information regarding net income is required by SFAS 123. The fair value of options granted was estimated using the

Black-Scholes valuation model. The following weighted average assumptions were used for the years ended December 31, 2004

and December 31, 2003.

Year Ended December 31,

2004 2003

Volatility 71% 55%

Expected life of options (in years) 8 3

Dividend Yield — —

Risk free interest rate 3.0% 2.6%

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DOUBLE EAGLE PETROLEUM CO.

NOTES TO FINANCIAL STATEMENTS (continued)

Income Taxes

Income taxes are determined under an asset and liability approach. The Company follows the asset and liability method of

accounting for deferred income taxes. Deferred taxassets and liabilities are determined based upon the temporary

differences between the financialstatement and taxbasis of assets and liabilities.

Per Share Amounts

Basic net income per share is computed using the weighted average number of common shares outstanding during the

period. Diluted net income per share reflects the potential dilution that would occur if options or other contracts such as

outstanding warrants to issue common stock were exercised using the average market price for the company’s stock for

the period. Total potential dilutive shares at December 31, 2004 and 2003, were 136,676 and 261,486, respectively. In a year

in which a net loss occurs, the conversion of options or other contracts such as options and warrants are ignored as the

conversion would be antidilutive.

Accounting Estimates

The preparation of financialstatements in conformity with accounting principles generally accepted in the United States

requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and

disclosure of contingent assets and liabilities at the date of the financialstatements and the reported amounts of revenues

and expenses during the reporting period. Actual results could differ fromthose estimates. Significant estimates used in

the presentation of these financialstatements include estimated lives of assets and timing and costs associated with the

Company’s asset retirement obligation. Other significant estimates also include proved oil and gas reserves quantities and

the associated present value of estimated future cash flows which are the basis for the calculation of the depreciation,

depletion and impairment for oil and gas properties.

Receivables and Credit Policies

The Company has joint interest billing receivables representing reimbursable operating expenses and other costs due from

third party working interest owners in wells that the Company operates. The receivable is recognized when the cost is

incurred and the related Company’s share of the cost is recorded. The Company also has trade receivables related to oil

and gas sales that are normally due approximately 45 days after production. The Company periodically reviews its

accounts receivable for collectablity and implements timely collection efforts as necessary.

New Accounting Pronouncements

The Company intends to adopt SFAS 123R issued by the FASB in December 2004. The effective date of SFAS 123R for

public companies is for interimor annual periods beginning after June 15, 2005. The pronouncement addresses the

accounting for transactions in which an entity exchanges its equity instruments for goods or services.

3. Line of Credit

The Company maintains a $9 million revolving line of credit collateralized by oil and gas producing properties as part of its

cash management program. The interest rate on the line of credit is at the prime rate published in the Wall Street Journal.

The interest rate on the line of credit was 5.25% at December 31, 2004. The line of credit matures on April 30, 2006. During

the year ended December 31, 2003, the Company took advances against the line totaling $2,850,000. On October 31, 2003,

the line was fully paid and no additional draws against the line have been made. The Company had no balances

outstanding under this line of credit at December 31, 2004 or December 31, 2003.

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DOUBLE EAGLE PETROLEUM CO.

NOTES TO FINANCIAL STATEMENTS (continued)

4. Commitments andContingencies

Gas Sales Commitments

The Company committed to sell 2,188,000 Mmbtu of gas over a 27 month period beginning January 1, 2005 under sixcontracts

for quantities, terms, and prices as described below. Should the Company be unable to deliver the gas, which is not

anticipated, it would be required to purchase such amounts on the open market to fulfill the terms of these contracts.

Price

Quantity Per Day Term ($/Mmbtu)

1,000 Mmbtu 1/05 - 4/05 5.31

1,000 Mmbtu 1/05 - 10/06 5.50

1,000 Mmbtu 1/05 - 10/05 5.80

500 Mmbtu 2/05 - 1/06 5.30

500 Mmbtu 2/05 - 1/06 5.30

1,000 Mmbtu 4/05 - 3/07 6.00

Major Customers

Sales to one major unaffiliated customer for years ended December 31, 2004 and December 31, 2003, are $9,881,000 and

$4,587,000, respectively. The Company, however, believes that it is not dependent upon this customer due to the nature of its

product, but as described above, has entered into sales contracts with this customer to deliver gas. The Company has no

other single customer that accounted for 10% or more of revenues in 2004 or 2003.

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. The lease agreement requires payments of approximately $61,300 in 2005, $66,900 in 2006, $72,500

in 2007 and $30,900 in 2008. Rent expense for the Denver office was approximately $5,900 in the two months ended

December 31, 2004.

The Company also, leases office facilities in Littleton, Colorado under an operating lease agreement that expires April 30, 2006.

The lease agreement requires payments of $33,000 in 2005 and $11,000 in 2006. Effective February 1, 2005, the Company

entered into a 16 month sub lease agreement for its Littleton facilities. The Company receives monthly payments of $2,069 for

this space that will aggregate $33,100 over the remaining termof the lease. The sublease substantially offsets the lease

obligation and no further accrual has been recorded. Rent expense for this facility in 2004 and 2003 was $31,000 and $20,000

respectively. The Company has no other capital leases and no operating lease commitments.

Employee Benefit Plan

The Company maintains a Simplified Employee Pension Plan covering substantially all employees meeting minimumeligibility

requirements. Employer contributions are determined solely at management’s discretion. Employer contributions for years

ended 2004 and 2003 were $38,898 and $24,260, respectively.

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DOUBLE EAGLE PETROLEUM CO.

NOTES TO FINANCIAL STATEMENTS (continued)

5. Income Taxes

The taxeffects of temporary differences that gave rise to significant portions of the deferred taxliabilities and deferred tax

assets as of December 31, 2004 and December 31, 2003 were as follows:

Year Ended December 31,

2004 2003

Deferred taxassets:

Net operating loss carry-forwards $ 1,700,000 $ 1,921,000

Percentage depletion carry-forward 146,000 160,000

Asset retirement obligation 138,000 123,000

1,984,000 2,204,000

Deferred taxliabilities – net difference in oil and gas properties (2,160,000) (1,156,000)

Net deferred taxasset (liability) (176,000) 1,048,000

Valuation allowance: — (1,048,000)

Net deferred taxassets $ (176,000) $ —

At December 31, 2004, the Company had a net operating loss carryforward for regular income taxreporting purposes of

approximately $5 million, which will begin expiring in 2007.

Reconciliation of the Company’s effective taxrate of 10% to the expected federal taxrate of 34% is as follows:

2004 2003

Expected Federal TaxRate 34% 34%

Permanent Differences – Change in Valuation Allowance (24%) (34%)

Effective TaxRate 10% 0%

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DOUBLE EAGLE PETROLEUM CO.

NOTES TO FINANCIAL STATEMENTS (continued)

6. Stockholders’ Equity

Sale of Common Stock – Private Placement

In October 2003, the Company initiated a private placement of its common stock and sold 1,295,000 shares of restricted stock

at $9.00 per share. In connection with the offering, the Company incurred $61,000 of costs against the gross proceeds of

$11,655,000. Since that time, the Company has registered with the Securities and Exchange Commission the resale of these

shares under a registration statement on FormS-3 that became effective July 9, 2004.

Stock Options

Stock option plans approved by the stockholders provide for granting of options to employees, directors and others for

purchase of common stock generally at prices between the “bid” and “ask” prices at the time of grant. Generally, options

granted prior to 2004 expire three years after the date of grant. On March 23, 2004 the Company issued stock options to senior

management that vest twenty percent each year on the anniversary of the grant over the next five years beginning one year

fromthe date of issue. The options fromthe 2004 grant expire five years after the grants vest. The changes in the outstanding

stock options during the years ended December 31, 2004 and 2003 are summarized as follows:

December 31, 2004 December 31, 2003

Weighted Average Weighted Average

Shares Exercise Price Shares Exercise Price

Beginning of period 180,626 $ 5.43 203,786 $ 3.75

Granted 176,100 13.90 61,486 8.19

Exercised/Purchased (74,140) 4.75 (84,646) 3.20

Expired (6,743) 14.83 — —

End of period 275,843 $ 14.32 180,626 $ 5.43

Unoptioned shares Available at year end 395,371 564,728

Number of shares exercisable 156,676 180,626

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DOUBLE EAGLE PETROLEUM CO.

NOTES TO FINANCIAL STATEMENTS (continued)

Stock Options (continued)

On occasion, the Board of Directors grants stock options not covered under the plans approved by the stockholders to

individuals and companies that performservices for the Company. The changes in the outstanding stock options during the

year ended December 31, 2004 and 2003 are summarized as follows:

December 31, 2004 December 31, 2003

Weighted Average Weighted Average

Shares Exercise Price Shares Exercise Price

Beginning of year 80,860 $ 4.54 305,964 $ 4.49

Granted — — — —

Exercised for cash 75,860 4.44 (91,854) 3.25

Cashless exercise — — (32,886) —

Expired — — (100,364) 4.68

End of year 5,000 $ 6.15 80,860 $ 4.54

The fair value per share of options granted, as determined under the Black Scholes method, in 2004 and 2003, were $10.09 and

$3.07, respectively.

During 2003, the Company issued 32,886 shares of common stock under a cashless exercise of 100,000 options based on the

difference between the market price at the date of exercise and the option price. No expense was recorded, as the fair value of

the options immediately prior to exercise equaled the fair value of the stock received.

Total options outstanding as of December 31, 2004 are 280,843. The options and weighted average exercise prices are as

follows:

Weighted Average

Expiration Shares Exercise Price

Year 2005 60,000 $ 3.80

Year 2006 44,733 $ 8.19

Year 2009 13,333 $ 14.88

Year 2010 or later 162,777 $ 14.06

Total 280,843

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DOUBLE EAGLE PETROLEUM CO.

NOTES TO FINANCIAL STATEMENTS (continued)

Stock Warrants

In December 1998, the Company issued 374,750 warrants at $1.375 per share between the “bid” and “ask” prices on the day of

grant. By December 31, 2003, all warrants were exercised prior to their expiration date.

7. RelatedParty Transactions

A company owned by an individual who was a member of the board of directors untilJune 8, 2004 acted as the operator on a

property owned by Double Eagle. That company also performs services on other producing properties in which Double Eagle

owns an interest and on drilling projects in which Double Eagle participates. Amounts paid by Double Eagle to the company

were $50,205 and $68,241 for the years ended December 31, 2004 and 2003, respectively.

8. Oil andGas 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, 2004 and December 31, 2003 are as follows:

December 31,

2004 2003

Developed properties $ 32,293,958 $24,376,469

Undeveloped properties 3,026,168 3,017,954

35,320,126 27,394,423

Accumulated depreciation, depletion and impairment allowance (10,947,541) (8,346,123)

Net capitalized costs $ 24,372,585 $19,048,300

Costs incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities

Costs incurred in property acquisitions, exploration, and development activities for the year ended December 31, 2004 and

2003 were as follows:

December 31,

2004 2003

Property acquisitions – unproved $ 297,323 $ 2,287,510

Exploration 323,822 231,244

Development 8,366,749 7,564,244

Total $8,987,894 $10,082,998

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DOUBLE EAGLE PETROLEUM CO.

NOTES TO FINANCIAL STATEMENTS (continued)

Results of Operations from Oil and Gas Producing Activities

The results of operations for the Company’s oil and gas producing activities for the year ended December 31, 2004 and 2003

were:

December 31,

2004 2003

Operating revenues $13,057,906 $6,080,880

Costs and expenses

Production 3,800,370 1,758,009

Exploration 323,822 231,244

Depreciation, depletion and impairment 3,012,692 1,720,548

7,136,884 3,709,801

Income before Income Taxes $ 5,921,022 $2,371,079

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DOUBLE EAGLE PETROLEUM CO.

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Gas Reserves

The reserves at December 31, 2004 and December 31, 2003 presented below were reviewed by Netherland Sewell and

Associates. 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 year ended December 31, 2004 and 2003, are as

follows:

December 31,

2004 2003

Natural Gas (Mcf)

Beginning of year 22,818,980 16,810,164

Revisions of prior estimates 13,606 (2,013,517)

Extensions and discoveries 14,661,717 9,343,183

Production (2,559,557) (1,320,850)

End of year 34,934,746 22,818,980

Proved developed reserves 17,161,577 16,055,045

% of proved developed reserves 49% 70%

December 31,

2004 2003

Oil (Barrels)

Beginning of year 208,957 222,473

Revisions of prior estimates 16,062 (25,115)

Extensions and discoveries 89,886 28,943

Sales of reserves in place (19,964) —

Production (16,886) (17,344)

End of year 278,055 208,957

Proved developed reserves 163,765 179,228

% of proved developed reserves 59% 86%

95% of the proved developed gas reserves and 100% of the proved developed oil reserves were in producing status as of

December 31, 2004.

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DOUBLE EAGLE PETROLEUM CO.

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

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

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.

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 fromthose 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 fromthe

rate of production assumed in these calculations; (3) selection of a 10% discount rate 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 taxexpense has been

computed by applying year-end statutory rates to future pretaxnet cash flows and the utilization of net operating loss carryforwards. Use of a 10% discount rate is required by SFAS 69. As of December 31, 2004, the average spot daily price of natural

gas was $5.515 as compared to monthly indexprices of $6.13 at OPAL and $6.20 for CIG.

Management does not rely solely upon the following information in making 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.

Standardized Measure is as follows:

December 31,

2004 2003

Future Cash Inflows $202,358,000 $136,525,000

Future Production Costs (60,424,000) (34,734,000)

Future Development Costs (9,465,000) (3,593,000)

Future Income Tax (32,972,000) (23,508,000)

Future net cash flows 99,497,000 74,690,000

10% Discount (47,967,000) (31,849,000)

Discounted Future Net Cash Flows $ 51,530,000 $ 42,841,000

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DOUBLE EAGLE PETROLEUM CO.

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

The following is an analysis of the changes in the Standardized Measure:

Years Ended December 31,

2004 2003

Balance, beginning of the year $42,841,000 $14,563,000

Sales of oil and gas, net of production costs (9,258,000) (4,323,000)

Extensions and discoveries 28,865,000 23,423,000

Net change in sales prices, net of production costs (4,122,000) 21,171,000

Previously estimated development cost incurred 2,115,000 670,000

Changes in future development costs (6,958,000) (1,307,000)

Sales of reserves in place (766,000) —

Revisions of quantity estimates 329,000 (2,760,000)

Accretion of discount 4,284,000 1,456,000

Net change in income taxes (4,902,000) (9,538,000)

Changes in rates of production and other (898,000) (514,000)

Balance, end of the year $51,530,000 $42,841,000

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ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTINGAND FINANCIAL

DISCLOSURE

There have been no disagreements between the Company and its independent auditors on any matter of accounting principles

or practices or financialstatement disclosure or auditing scope or procedure since the Company’s inception of a nature which,

if not resolved, would have caused the accountant to make reference in connection with its report.

ITEM 8A. CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures. Based on an evaluation carried out under the supervision and with the

participation of our management, including our Chief Executive Officer and Chief Financial Officer, during the 90-day period

prior to the filing of this report, our Chief Executive Officer and Chief Financial Officer believe that our disclosure controls and

procedures, as of the date of this report, and as defined in Securities Exchange Act Rules 13a-14 and 15d-14, are, to the best of

their knowledge, effective.

Changes in internal controls. Subsequent to the date of this evaluation, our Chief Executive Officer and Chief Financial Officer

are not aware of any significant changes in our internal controls over financial reporting, including any corrective actions with

regard to significant deficiencies and material weakness, or in other factors that could significantly affect these controls to

ensure that information required to be disclosed by us, in reports that we file or submit under the Securities Act, is recorded,

processed, summarized, and reported within the time periods specified in Securities and Exchange Commission rules and

regulations.

ITEM 8B. OTHER INFORMATION

None

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PART III

ITEM 9. DIRECTORS AND EXECUTIVE OFFICERS OF REGISTRANT

Directors and Executive Officers:

The directors and executive officers of the Company are as follows:

Name Age Positions

Stephen H. Hollis 54 Chairman of The Board; President; and Director

David C. Milholm 55 Chief Financial Officer

D. Steven Degenfelder 48 Vice President

C. K. Adams 64 Vice President of Engineering and Production

Beth McBride 47 Vice President of Exploration

Carol A. Osborne 53 Corporate Secretary

Roy G. Cohee 55 Director

Thomas A. Prendergast 70 Director

Stephen H. Hollis has served as the President and Chief Executive Officer of the Company since January 1994 and previously

served as a Vice-President of the Company fromDecember 1989 through January 1994. Mr. Hollis has served as a Director of

the Company since December 1989. Mr. Hollis has served as the Vice-President of Hollis Oil & Gas Co., a small oil and gas

company, since January 1994 and served as the President of Hollis Oil & Gas Co. fromJune 1986 through January 1994.

Mr. Hollis was a geologist for an affiliate of United Nuclear Corporation from1974 to 1977 and a consulting geologist from1977

to 1979. In 1979, Mr. Hollis joined Marathon Oil Company and held various positions until 1986, when he founded Hollis Oil &

Gas Co. Mr. Hollis is a past President of the Wyoming Geological Association and past President of the Rocky Mountain

Section of the AAPG. Mr. Hollis received a B.A. Degree in Geology fromthe University of Pennsylvania in 1972 and a Masters

Degree in Geology fromBryn Mawr College in 1974.

David C. Milholmhas served as our Chief Financial Officer since May 1, 2003. Prior to joining the Company, Mr. Milholm

served as a financial consultant to several energy companies between 2001 and 2003. From1995 to 2001, Mr. Milholmserved as

Vice President, Chief Operating Officer and Chief Financial Officer of AlloSource, a Denver based biomedical company. Before

that Mr. Milholmheld Controller positions with Western Gas Resources, BWAB Inc. and Wintershall Oil and Gas Corp. Mr.

Milholmbegan his career with Price Waterhouse Cooper in Denver where he became a Certified Public Accountant.

Mr. Milholmreceived his MBA fromthe University of Denver in 1973 and his BSBA in Accounting fromColorado State

University in 1972.

D. Steven Degenfelder has served as a Vice President since February 1998. Mr. Degenfelder began his career in the oil and gas

business as a roustabout in the oil fields of southeast New Mexico. After graduating fromcollege, he held various land

management positions with Marathon Oil Company from1979 to 1981, Paintbrush PetroleumCorporation from1981 to 1985 and

TyrexOil Company from1985 to 1995, where he served as Vice President and Director. Mr. Degenfelder served as Deputy

Director of the Wyoming Office of State Lands and Investments from1995 to 1997. He currently serves on the Board of

Directors of the PetroleumAssociation of Wyoming and is Chairman of the Natrona County Planning and Zoning Commission.

He is a member of the American Association of Professional Landmen and is past

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President of the Wyoming Association of Professional Landmen. Mr. Degenfelder is a Certified Professional Landman and

received his degree in Business Administration fromTexas Tech University in 1979.

C. K. (Keith) Adams began serving as Vice President of Engineering and Production in the Company’s Casper office in

January 2005. Mr. Adams has over 40 years of experience in drilling, completion, producing facilities design, construction and

management of oil and gas operations. Mr. Adams previously worked for Skelly Oil Company, Mobil Oil Corporation, LeClair

Operating Company, and in 1971 through 1985 was a principal in McIlnay – Adams & Company, Inc. which he co-founded and

co-owned. During the period 1985 through 2005, Mr. Adams founded and operated Hydrocarbon Engineers, a consulting

engineering firmbased in Casper, WY. From1993 – 2005 Mr. Adams formed and operated Intermountain Production LLC, a

small independent oil and gas producer. Mr. Adams is a Registered Professional Engineer in Wyoming and Colorado. He

received his BS/PetroleumEngineering degree fromthe University of Wyoming in 1964.

Beth McBride began serving as Vice President of Exploration in the Company’s Denver office in January 2005. Ms. McBride

served as a Director of the Company fromJanuary 25, 2001 untilJune 8, 2004. She has been President and member of the Board

of Directors of Legacy Energy Corporation since co-founding the company in 1990. Legacy Energy Corporation is a privately

held oil and gas exploration company in Denver, Colorado. Ms. McBride was a geophysicist for Superior Oil Company in

Houston, Texas from1981 through 1984, and held various exploration positions with Mobil Oil Corporation in Dallas, Texas and

Denver, Colorado from1985 to 1990. Ms. McBride received a B.Sc. degree in Geophysical Engineering fromColorado School of

Mines in 1980.

Carol A. Osborne has served as the Secretary of the Company since January 1996 and previously served as the Assistant

Secretary of the Company fromDecember 1989 untilJanuary 1996. In addition, Ms. Osborne has served as the Company’s

Office Manager since 1981.

Roy G. Cohee has served as a Director of the Company since January 25, 2001. He has served as President of C & Y

Transportation Co. since 1986. C & YTransportation Co. started business in Casper, Wyoming in 1966 and is a privately held

company focused on the transportation and storage of oil field equipment and supplies throughout the Western U.S. and

Canada. Mr. Cohee has been with C & YTransportation Co. since its beginning in 1966. Mr. Cohee was elected to his first term

in the Wyoming House of Representatives in 1998 and currently in his second termand sits on the House Highways and

Transportation Committee and the House Revenue Committee.

Thomas A. Prendergast is a Certified Public Accountant and graduated fromFordhamUniversity in 1955 with a Bachelor of

Science Degree. He has served as a Director of the Company since July 2002. Since 1986, Mr. Prendergast has been Chairman of

the Board of Scot Holdings, Inc., a Texas based investment company. Mr. Prendergast also served as Chairman of Market

Guide, Inc. until September 1999, when it merged with another internet company. Mr. Prendergast has served as a Director on

16 public boards in various industries. Mr. Prendergast was a founder and President of the El Paso Community College in El

Paso, Texas, where he served for thirteen years.

2004 Meetings andCommittees of the Boardof Directors

Double Eagle’s Board of Directors held four meetings during the year ended December 31, 2004. Each director attended at least

75% of the Board and committee meetings he or she was eligible to attend. The standing committees of the board include the

Audit Committee and the Compensation Committee. The Audit Committee and the Compensation Committee each consists

entirely of non-employee directors.

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The Board has not appointed a nominating committee.

The Audit Committee reviews the adequacy of systems and procedures for preparing the financialstatements and the

suitability of internal financial controls. The Audit Committee also reviews and approves the scope and performance of the

independent auditors’ work. Thomas A. Prendergast and Roy G. Cohee serve as members of the Audit Committee and Thomas

A. Prendergast serves as chairman of the Audit Committee. The Audit Committee met four times during the year ended

December 31, 2004.

Audit Committee Financial Expert

Thomas A. Prendergast qualifies as an audit committee financial expert, as defined by the Securities Exchange Act, and serves

on our audit committee. He is independent as defined by the applicable listing standards of the Nasdaq Stock Market.

Audit Committee Charter

Our Board of Directors has adopted a written charter for the Audit Committee. The Committee will review and assess the

adequacy of the Audit Committee charter annually.

Code of Ethics

We have adopted a code of ethics that applies to our executive officers, including Mr. Hollis, our President and Chief Executive

Officer, and Mr. Milholm, our Chief Financial Officer.

Section 16(a) Beneficial OwnershipReporting Compliance

Section 16 (a) of the Securities Exchange Act of 1934, as amended requires our directors, executive officers, and holders of more

than 10% of our Common Stock to file with the Securities And Exchange Commission initial reports of ownership and reports of

changes in ownership of Common Stock and other equity securities. We believe that during the fiscal year ended December 31,

2004, our officers, directors and holders of more than 10% of our outstanding Common Stock complied with all Section 16(a)

filing requirements. In making these statements, we have relied upon the written representations of our directors and officers.

ITEM 10. EXECUTIVECOMPENSATION

Summary Compensation Table

The following table sets forth in summary formthe compensation received during each of our last three completed fiscal years

by Stephen H. Hollis, our Chief Executive Officer and President, David C. Milholm, our Chief Financial Officer, D. Steven

Degenfelder, Vice President and by Bob D. Brady, Jr., former Vice President of the Company (collectively, the “Named

Executive Officers”). Other than the “Named Executive Officers”, no employee of the Company received totalsalary and bonus

exceeding $100,000 during any of the last three fiscal years.

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Annual Compensation

Long-Term

Compensation

Long-Term Securities

Name and Year Salary (1) Bonus Compensation Underlying Other Annual

Principal Position Ended ($) ($) Restricted Stock Options Compensation ($)

Stephen H. Hollis, 2004 135,000 35,000 — 35,000 —

Chief Executive 2003 108,000 68,592 — 12,000 —

Officer and President 2002 72,000 48,000 — 25,000 —

David C. Milholm, 2004 97,500 19,500 — 40,000 —

Chief Financial 2003 60,000 10,000 — 6,743 —

Officer 2002 — — — — —

D. Steven 2004 97,500 19,500 — 30,000 —

Degenfelder, Vice 2003 91,250 26,849 10,000 —

President 2002 101,901 35,441 20,000 —

Bob D. Brady, Jr., 2004 18,333 — — — —

Vice President (2) 2003 109,000 13,000 — 6,743 —

2002 72,674 — $ 48,000 — —

(1) The dollar value of base salary (cash and non-cash) received

(2) Mr. Brady’s employment with us terminated on February 20, 2004

Option Grants Table

The following table sets forth information concerning individual grants of stock options made during the fiscal year ended

December 31, 2004 to the Company’s Named Executive Officers. See “Stock Option Plans”.

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Option Grants for Year Ended December 31, 2004

% of Total

Number Options Granted

Options to Employees Exercise or Base Expiration

Name Granted During the Year Price ($/Shares) Date

Stephen H. Hollis, 35,000 19.9% $14.00 (1)

Chief Executive Officer and President

David C Milholm 30,000 22.7% $14.00 (1)

Chief Financial Officer 10,000 $6.31 (2)

40,000

D. Steven Degenfelder 30,000 17.0% $14.00 (1)

Vice President

Carol Osborne 20,000 11.4% $14.00 (1)

Corporate Secretary

Peter M. Mueller 32,500 $15.20 (3)

Chief Operating Officer 10,000 $15.20 (4)

42,500 24.2%

(1) 20% of the options issued vest each year for five years beginning March 23, 2005.

(2) 33% of the options issued vest each year for three years beginning May 1, 2004. Each option will expire on the fifth

anniversary of the date it first became exercisable, if not exercised earlier.

(3) Mr. Mueller’s employment with the Company terminated February 15, 2005. Each option will expire on the fifth anniversary

of the date it first became exercisable, if not exercised earlier. Therefore, none of the options issued will vest since the first

vesting date for 20% of the issued options would have been August 18, 2005.

(4) The options vested at time of issue and had an expiration date of August 18, 2014. However, the options must be exercised

within 90 days of his termination. The 90 days will elapse on May 15, 2005.

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Aggregated Option Exercises and Year-End Option Value Table.

The following table sets forth information concerning each exercise of stock options during 2004 and unexercised options

held by the Named Executive Officers at the year ended December 31, 2004.

Aggregated Option Exercises for Year Ended December 31, 2004 and Year-End Option Values

Value of

Unexercised

Number of In-The-Money

Unexercised Options Options at

at Fiscal Fiscal Year-End

Number of Shares Year-End (3) (4)

Acquired Value Exercisable/ Exercisable/

Name On Exercise (1) Realized (2) Unexercisable Unexercisable

Stephen H. Hollis, 50,000 $ 580,950 12,000/35,000 $157,920/185,850

Chief Executive Officer and President

D. Steven Degenfelder 40,000 470,760 10,000/30,000 131,600/159,300

Carol Osborne 20,000 232,380 6,000/20,000 78,960/106,200

(1) The number of shares received upon exercise of options during the year ended December 31, 2004.

(2) With respect to options exercised during the Company’s year ended December 31, 2004, the dollar value of the difference

between the option exercise price and the market value of the option shares purchased on the date of the exercise of the

options.

(3) The total number of unexercised options held as of December 31, 2004, separated between those options that were

exercisable and those options that were not exercisable.

(4) For all unexercised options held as of December 31, 2004, the aggregate dollar value of the excess of the market value of

the stock underlying those options over the exercise price of those unexercised options, based on the closing price of

the Company’s Common Stock on December 31, 2004. The closing bid price for the Company’s Common Stock on

December 31, 2004 was $ 19.31 per share.

Stock Option Plans

The 1996 Stock Option Plan.

In May 1996, our Board of Directors approved our 1996 Stock Option Plan (the “1996 Plan”), which subsequently was approved

by our stockholders. Pursuant to the 1996 Plan, we may grant options to purchase an aggregate of 200,000 shares of our

common stock to key employees, directors, and other persons who have or are contributing to our success. The options

granted pursuant to the 1996 Plan may be either incentive options qualifying for beneficial taxtreatment for the recipient or

non-qualified options. The 1996 Plan is administered by an option committee that determines the terms of the options subject to

the requirements of the 1996 Plan. At December 31, 2003, no options to purchase shares of Common Stock were outstanding

under the 1996 Plan and no additional options could be granted under the 1996 Plan.

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The 2000 Stock Option Plan

In December 1999, our Board of Directors approved the Company’s 2000 Stock Option Plan (the “2000 Plan”), which was

subsequently approved by our stockholders. Pursuant to the 2000 Plan, we may grant options to purchase an aggregate of

200,000 shares of our common stock to key employees, directors, and other persons who have or are contributing to our

success. The options granted pursuant to the 2000 Plan may be either incentive options qualifying for beneficial taxtreatment

for the recipient or non-qualified options. The 2000 Plan is administered by an option committee that determines the terms of

the options, subject to the requirements of the 2000 Plan. At December 31, 2003, options to purchase 145,354 shares of Common

Stock were outstanding under the 2000 Plan and no additional options to purchase could be granted under the 2000 Plan.

The 2002 Stock Option Plan

In December 2001, our Board of Directors approved our 2002 Stock Option Plan (the “2002 Plan”), which subsequently was

approved by our stockholders. Pursuant to the 2002 Plan, we may grant options to purchase an aggregate of 300,000 shares of

our common stock to key employees, directors, and other persons who have or are contributing to our success. The options

granted pursuant to the 2002 Plan may be either incentive options qualifying for beneficial taxtreatment for the recipient or

non-qualified options. The 2002 Plan is administered by an option committee that determines the terms of the options subject to

the requirements of the 2002 Plan. At December 31, 2003, options to purchase 11,272 shares of Common Stock were outstanding

under the 2002 Plan and options to purchase an additional 284,728 shares could be granted under the 2002 Plan.

2003 Stock Option and Compensation Plan

In November 2002, our Board of Directors approved our 2003 Stock Option And Compensation Plan (the “2003 Plan”), which

was subsequently approved by our stockholders. Pursuant to the 2003 Plan, we may grant options to purchase an aggregate of

300,000 shares of our Common Stock to key employees, directors, and other persons who have or are contributing to our

success. The options granted pursuant to the 2003 Plan may be incentive options qualifying for beneficial taxtreatment for the

recipient or they may be non-qualified options. The 2003 Plan is administered by an option committee that determines the terms

of the options subject to the requirements of the 2003 Plan, except that the option committee shall not administer the 2003 Plan

with respect to automatic grants of shares and options to directors of the Company who are not also employees of the

Company (“Outside Directors”). The option committee may be the entire Board or a committee of the Board. Outside Directors

automatically receive options to purchase 10,000 shares pursuant to the 2003 Plan at the time of their election as an Outside

Director and thereafter on the first business day after each annual meeting of stockholders if still an Outside Director at that

time. These Outside Directors options are exercisable at the time of grant. The exercise price for options granted to Outside

Directors is equal to the fair market value of our common stock on the date of grant. All options granted to Outside Directors

expire three years after the date of grant. The 2003 Plan also provides that Outside Directors will receive 2,000 shares of

common stock at the time of their election as an Outside Director and on the first business day after each annual meeting of

stockholders during the termof the 2003 Plan while they remain Outside Directors. At December 31, 2003, no options to

purchase shares of common stock were outstanding and 20,000 shares of common stock had been issued under the 2003 Plan,

and options to purchase an additional 280,000 shares could be granted under the Plan.

Compensation of Outside Directors

Outside Directors are paid $500 for each meeting of the Board of Directors that they attend. In addition, each Outside Director

will receive 2,000 shares of common stock and options to purchase 5,000 shares each

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year pursuant to the 2003 Plan. Directors also are reimbursed for expenses incurred in attending meetings and for other

expenses incurred on our behalf. In June 2004, we issued 2,000 shares of common stock to each outside Director at that time

and each Outside Director at that time was granted options to purchase 5,000 shares of Common Stock for $13.56 per share.

These options expire June 9, 2009.

ITEM 11. SECURITYOWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table summarizes certain information as of March 16, 2005 with respect to the beneficial ownership of our

common stock (i) by our directors, (ii) by stockholders known by us to own 5% or more of our common stock, and (iii) by all

executive officers and directors as a group.

As of March 16, 2005

Percentage of

Class

Name And Address of Number of Beneficially

Beneficial Owner Shares Owned

Stephen H. Hollis 720,200(1) 8.41%

3350 Misty Mountain Road

Casper, Wyoming 82601

Roy G. Cohee 36,825(2) *

2046 Rustic Drive

Casper, Wyoming 82601

Thomas A. Prendergast 38,600(5) *

725 Montoya Oak

El Paso, Texas 79932

Directors and Officers as a group 988,756(1)(2)

(Eight Persons) (3)(4)(5) 11.49%

Hollis Oil & Gas Co. (4) 350,000 4.09%

* Less than one percent.

(1) Includes options held by Mr. Hollis to purchase 12,000 shares for $6.15 per share that expire on February 4, 2006 and

options to purchase 7,000 for $14.00 that expire on March 23, 2010 and that became exercisable on March 23, 2005. In

addition to 351,200 shares owned directly by Mr. Hollis, the table above includes 350,000 shares of common stock owned

by Hollis Oil & Gas Co. Mr. Hollis is an officer, director and 51 percent owner of Hollis Oil & Gas Co.

(2) Includes options to purchase 5,000 shares for $6.15 per share that expire on February 4, 2006 and options to purchase

5,000 shares for $13.56 per share that expire on July 9, 2009.

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(3) In addition to the shares described in footnotes (1), (2), and (5), the shares owned by Directors and Executive Officers as a

group, includes (i) 30,270 shares, options to purchase 6,000 shares for $14.00 per share that expire on March 23, 2010 that

became exercisable on March 23, 2005 held by D. Steven Degenfelder, our Vice President; (iii) options to purchase 6,743

shares for $14.83 per share that expire on November 11, 2006, options to purchase 3,333 shares for $6.31 per share that

expire on May 1, 2009, and options to purchase 6,000 shares for $14.00 per share that expire on March 23, 2010 and that

became exercisable on March 23, 2005 held by David C. Milholm, our Chief Financial Officer; and (iv) 30,100 shares held by

Beth McBride, our Vice President of Exploration.

(4) The shares owned by Hollis Oil & Gas Company are shown or included as beneficially owned three times in the table:

once as beneficially owned by Hollis Oil & Gas Company, again under the beneficial ownership of Mr. Hollis, and also as a

part of the shares beneficially owned by Directors and Executive Officers as a group.

(5) Includes 24,600 shares beneficially owned of record by Scot Holding Inc., which is wholly-owned by Mr. Prendergast’s

family of which Mr. Prendergast is a Director and Chairman, 4,000 shares held by Mr. Prendergast and options to purchase

5,000 shares for $6.15 per share that expire on February 4, 2006 and options to purchase 5,000 shares for $13.56 per share

that expire on June 9, 2009 held by Mr. Prendergast.

ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

A company owned by Ken M. Daraie, a member of the Board of Directors untilJune 8, 2004, acts as operator on a property

owned by us. That company also performs services on other producing properties in which Double Eagle owns an interest and

on drilling projects in which Double Eagle participates. Amounts paid by Double Eagle to this company were $50,205 and

$68,241, for the year ended December 31, 2004 and fiscal 2003, respectively.

ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K

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

See “ITEM 7. FINANCIAL STATEMENTS AND SUPPLEMENTARYDATA — Index” on page F-1(a)

(a)(3) Exhibits.

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 fromExhibit 3.1(a) of the Company’s Annual Report on Form10-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 fromExhibit 3.1(b) of the Company’s Annual Report on

Form10-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

fromExhibit 3.1(c) of the Company’s Annual Report on Form10- KSB for the year ended August 31, 2001).

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Exhibit No. Description

3.1(d) Certificate of Correction filed with the Maryland Secretary of State (incorporated by reference fromExhibit 3 of

the Company’s Quarterly Report on Form10-QSB for the quarter ended November 30, 2001).

3.2 Bylaws (incorporated by reference fromExhibit 3.2 of the Company’s Annual Report on Form10-KSB for the

year ended August 31, 2001).

4.1 Formof 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 FormSB-2 filed on

November 27, 1996, SEC Registration No. 333-14011).

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

99.1 Restated Audit Committee Charter

99.2 Code of Business Conduct and Ethics

99.3 Whistleblower Procedures

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees

The aggregate fees billed for professionalservices rendered by HEIN & Associates LLP (“HEIN”) for its audit of our

annual financialstatements and its review of our financialstatements included in Forms 10-QSB in fiscal years 2004 and

2003 were $68,025 and $41,640 respectively.

Audit Related Fees

The aggregate fees billed for audit related services by HEIN in years 2004 and 2003 were $4,360 and $ 0, respectively.

These fees were accrued in connection with the implementation of new accounting pronouncements.

Tax Fees

The aggregate fees billed by our independent auditors in each of years 2004 and 2003 for professionalservices for tax

compliance, taxadvice or taxplanning were $7,000 and $0, respectively.

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All Other Fees

There were no fees billed in by our independent auditors each of years 2003 and 2004 for professionalservices other

than the services described above.

Audit Committee Pre-Approval

Our Audit Committee Charter provides that either (i) the Audit Committee shall pre-approve all auditing and nonauditing services of the independent auditor, subject to de minimus exceptions for other than audit, review or attest

services that are approved by the Audit Committee prior to completion of the audit; or (ii) that the engagement of the

independent auditor be entered into pursuant to pre-approved policies and procedures established by the Audit

Committee, provided that the policies and procedures are detailed as to the particular services and the Audit Committee

is informed of each service. The Audit Committee pre-approved 100% of HEIN fees for audit services in year 2003 and

2004. Audit-related fees for services performed by HEIN in years 2003 and 2004 were not recognized by us at the time of

the engagement to be non-audit services. Except as indicated above, there were no fees other than audit fees for years

2003 and 2004, and the auditors engaged performed all the services described above with their full time permanent

employees.

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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 31, 2005 /s/ Stephen H. Hollis

Stephen H. Hollis,

Chief Executive Officer and President

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 31, 2005 /s/ Stephen H. Hollis

Stephen H. Hollis,

Chief Executive Officer,

President and Director

Date: March 31, 2005 /s/ David C. Milholm

David C. Milholm

Chief Financial Officer

Date: March 31, 2005 /s/Roy G. Cohee

Roy G. Cohee, Director

Date: March 31, 2005 /s/Thomas A. Prendergast

Thomas A. Prendergast, Director

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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 fromExhibit 3.1(a) of the Company’s Annual Report on Form10-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 fromExhibit 3.1(b) of the Company’s Annual Report on

Form10-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

fromExhibit 3.1(c) of the Company’s Annual Report on Form10- KSB for the year ended August 31, 2001).

3.1(d) Certificate of Correction filed with the Maryland Secretary of State (incorporated by reference fromExhibit 3 of

the Company’s Quarterly Report on Form10-QSB for the quarter ended November 30, 2001).

3.2 Bylaws (incorporated by reference fromExhibit 3.2 of the Company’s Annual Report on Form10-KSB for the

year ended August 31, 2001).

4.1 Formof 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 FormSB-2 filed on

November 27, 1996, SEC Registration No. 333-14011).

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

99.1 Restated Audit Committee Charter

99.2 Code of Business Conduct and Ethics

99.3 Whistleblower Procedures