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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

for the fiscal year ended December 31, 2009


o		TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No. 1-33571

DOUBLE EAGLE PETROLEUM CO.

(Name of registrant as specified in its charter)


Maryland		83-0214692

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

1675 Broadway, Suite 2200, Denver, CO 80202
(Address of principal executive offices) (Zip Code)

(303) 794-8445

(Registrant’s telephone number, including area code)

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


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

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


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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

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

Large accelerated filer o

Accelerated filer o

Non-accelerated filer þ
(Do not check if a smaller reporting company)

Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). Yes o No þ

The aggregate market value of the voting common stock held by non-affiliates of the registrant at the close of business on June 30, 2009, was $44,813,473.

The number of shares of the registrant’s common stock outstanding as of March 1, 2010 was 11,106,109.

Portions of the registrant’s definitive proxy statement relating to its 2010 annual meeting of stockholders to be filed within 120 days after December 31, 2009, are incorporated by reference in Part III of this Form 10-K.

The terms “Double Eagle”, “Company”, “we”, “our”, and “us” refer to Double Eagle Petroleum Co. and its subsidiaries, as a consolidated entity, unless the context suggests otherwise. We have included technical terms important to an understanding of our business under “Glossary”, in Items 1 and 2, “Business and Properties”, of this Annual Report on Form 10-K for the year ended December 31, 2009 (the “Form 10-K”). Throughout this document we make statements that are classified as “forward-looking”. Please refer to the “Cautionary Information about Forward-Looking Statements” section of this document for an explanation of these types of statements. Dollar amounts set forth herein are in thousands unless otherwise noted.

PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

General

We are an independent energy company engaged in the exploration, development, production and sale of natural gas and crude oil, primarily in Rocky Mountain Basins of the western United States. Double Eagle was incorporated in the State of Wyoming in January 1972 and reincorporated in the State of Maryland in February 2001. From 1995 to 2006, our common shares were publicly traded on the NASDAQ Capital Market under the symbol “DBLE”. On December 15, 2006, our common shares began trading on the NASDAQ Global Select Market. Our Series A Cumulative Preferred Stock (“Preferred Stock”) was issued on the NASDAQ Capital Market, under the symbol “DBLEP” on July 3, 2007. It began trading under the symbol “DBLEP” on the NASDAQ Global Select Market on September 30, 2007. Our corporate offices are located at 1675 Broadway, Suite 2200, Denver, Colorado 80202, telephone number (303) 794-8445. Our operations office is located at 777 Overland Trail, Casper, Wyoming 82601, telephone number (307) 237-9330. Our website is www.dble.com.

Overview and Strategy

Our objective is to increase long-term stockholder value by implementing our corporate strategy of economically growing our reserves and production through the development of our existing core properties, partnering on selective exploration projects, and pursuing strategic acquisitions that expand or complement our existing operations.

Our operations currently are focused on our two core development properties located in southwestern Wyoming. We have coal bed methane reserves and production in the Atlantic Rim area of the Eastern Washakie Basin and tight sands gas reserves and production in the Pinedale Anticline. Currently, the Company does not have any active exploration projects.

As of December 31, 2009, we had estimated proved reserves of 89.8 Bcf of natural gas and 419 MBbl of oil, or a total of 92.3 Bcfe. This represents a net increase in reserve quantities of 4% from the prior year, after adjustments for extensions and discoveries, current year production and revision of estimates. Our proved reserves are calculated based upon the Securities Exchange Commission’s (“SEC”) new rules that went into effect on December 31, 2009. Please refer to the Reserves section within Part I of this Form 10-K for more information about the new SEC oil and gas reporting guidelines. The new SEC standards require that the Company calculate the quantity of oil and gas reserves that are economically producible using a simple 12-month average price, using the first-day-of-the-month price for each month within the 12-month reporting period. For the year ended December 31, 2008 and prior reserve reports, however, pricing was based upon the price on the last day of the fiscal year. Historically, natural gas prices are higher during the winter months due to cold weather and increased demand. As natural gas comprises 97% of our total reserves, this change in pricing methodology had a significant negative impact on the pricing used in determining our reserves. Using this change in price determination, the average gas price used in calculating the December 31, 2009 reserves decreased by $1.57, or 34%, per MMBtu from the December 31, 2008 price of $4.61 MMBtu. The decrease in price shortened the economic life of certain existing wells and negatively impacted our year-end reserve estimate. The natural gas price on the last day of the 2009 fiscal year was $5.54 per MMBtu, which is the price that would have been used to estimate year-end reserves under the reserve calculation method used for fiscal year 2008 and prior years. The reserve estimate at December 31, 2009 includes additions of 22.3 Bcfe, reflecting a reserve replacement ratio of 239%. In addition, we were able to realize a minor increase in our proved undeveloped reserves due to a change in the SEC rules that allows for more than a one well offset from proved reserves in well-defined fields. The proved oil and gas reserves, at December 31, 2009, have a PV-10 value of approximately$91.1 million, a decrease of 41% from the prior year due primarily to lower pricing (as discussed above), offset slightly by reserve extensions and discoveries. (See reconciliation of the PV-10 non-GAAP financial measure to the standardized measure under Reserves on page 10). Of these proved reserves, 72% were proved developed and 97% were natural gas.

During 2009, we invested $21.1 million in capital expenditures related to the development of our existing properties, down approximately $43.9 million from our 2008 capital expenditures. Due to the changes in the economic environment that occurred late in 2008, and the decline in natural gas prices, the Company’s strategy was to hold capital expenditures consistent with our 2009 operating cash flow. Management focused its 2009 spending primarily on non-operated drilling on the Pinedale Anticline. Historically, drilling on the Pinedale Anticline has had a high rate of return and management determined that continuing to participate in the drilling in the area was consistent with the Company’s long-term strategic plans. The Company also spent a portion of the 2009 expenditure total on well completion and enhancement projects within the Catalina Unit and at the non-operated Sun Dog and Doty Mountain units.

We continually assess projects that are currently in progress and those proposed for future development to determine the risk and estimated rate of return, including our non-operated projects (primarily the Pinedale Anticline and the Doty Mountain and Sun Dog Units in the Atlantic Rim). Our estimated capital budget for 2010 is approximately $15-$20 million for drilling up to eight wells within the Catalina Unit, and ongoing non-operated development programs on the Pinedale Anticline and within the Sun Dog and Doty Mountain Units. The Catalina drilling will be focused on drilling delineation wells to enhance our understanding of the field and the extent of production that can be expected as we move our drilling down into the Washakie Basin. These wells are not expected to become part of the Catalina Unit until further drilling physically connects them to the Unit. As such, our working interest in each of these wells will be based on the acreage ownership, and will vary. The 2010 capital budget does not include the impact of any potential future exploration projects or possible acquisitions. Although our emphasis is on developing low risk projects and increasing our acreage position of potential drilling prospects, we are continually evaluating exploration opportunities, and if a potential opportunity is identified that complements our areas of expertise, it may be pursued.

We expect to fund our 2010 capital expenditures with cash provided by operating activities and funds made available through our $75 million credit facility. We may find it necessary in the future to raise additional funds through private placements or registered offerings of equity or debt.

We also continue to evaluate acquisition opportunities that complement our existing operations, offer economies of scale and/or provide further development, exploitation and exploration opportunities. In addition to potential acquisitions, we also may decide to divest of certain non-core assets or enter into strategic partnerships or joint ventures related to our assets that are not currently considered in our expected 2010 capital expenditures.

Operations

As of December 31, 2009, we owned interests in a total of 1,172 producing wells and had an acreage position of 359,830 gross acres (114,369 net), of which 218,555 gross acres (102,325 net) are undeveloped, in what we believe are natural gas prone basins primarily located in the Rocky Mountains. Two developing areas, the Atlantic Rim coal bed natural gas play and the Pinedale Anticline, accounted for 90% of our proved developed reserves as of December 31, 2009, and over 94% of our 2009 production.

As of December 31, 2009, our estimated acreage holdings by basin are:


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

Total		359,830		114,369

Our project development focus is in areas where our core competencies can provide us with competitive advantages. We intend to grow our reserves and production primarily through our current areas of development, which are as follows:

The Atlantic Rim Coal Bed Natural Gas Project

Located in south central Wyoming, from the town of Baggs at the south end, to the town of Rawlins at the north end, the Atlantic Rim play is a 40-mile long trend in the Eastern Washakie Basin, in which we have an interest in 50,937 gross acres (29,735 net acres). The Mesaverde coals in this area differ from those found in the Powder River Basin in that they are thinner zones, but have higher gas content. Nevertheless, the productivity of coal beds is dependent not only on specific natural gas content, but also on favorable permeability to natural gas. The primary areas currently being developed within the Atlantic Rim are the Catalina Unit, for which we are the operator, and our non-operated interests in the Sun Dog and the Doty Mountain Units.

On May 21, 2007, the Record of Decision on the Atlantic Rim Environmental Impact Statement (“EIS”), was published in the Federal Register. The EIS allows for the drilling of up to 1,800 coal-bed methane wells and 200 conventional oil and gas wells in the Atlantic Rim area, of which 268 of the potential well sites are in the Company-operated Catalina Unit. Subsequent to the Record of Decision, several appeals against the EIS have been filed and denied. Currently, there is one appeal from conservation groups still pending and there is also an outstanding suit before the Interior Board of Land Appeals. We do not believe these actions have merit and expect them to be denied.

During 2009, we recognized net sales volumes from the coal bed natural gas projects in the Atlantic Rim of 6.7 Bcfe, which represented 72% of our total 2009 natural gas equivalent sales volume. The wells have historically been very economic, and we intend to continue to focus our efforts on the drilling of up to eight wells in the Catalina Unit in 2010. Anadarko Petroleum Corporation (“Anadarko”), the operator of the Doty Mountain and Sun Dog Units, has indicated to us that it intends to drill up to 10 new wells in the Atlantic Rim in 2010.

Catalina Unit

The Catalina Unit consists of 21,725 total acres (8,944 net acres) that the Company operates. Over the past three years, the Catalina Unit has increased from the 14 original producing wells in the Cow Creek Field to 70 production wells as of December 31, 2009. During 2007, we drilled 33 producing wells and three injection wells. As part of our 2008 drilling program, we drilled 24 potential producing wells, and six injections wells. Five of the potential producing wells were complete and producing in 2008. One of the 24 potential producing wells was determined to be non-productive and was plugged and abandoned in the fourth quarter of 2008. This well encountered a major structural fault, resulting in the absence of the mesaverde coals at that location. While the well was plugged and abandoned, knowing the location of the fault will assist the Company in locating future well positions to avoid another dry hole. Wells beyond this fault are believed to be productive.

In the first half of 2009, the Company completed 15 of the 18 remaining wells that were drilled in 2008, that had not been hooked up to the sales line at the end of 2008. In September 2009, the Company began a well-enhancement program within the Catalina Unit to perform workovers on approximately 30 existing wells that had experienced production declines over the past year. The Company is still in process of assessing the results of the work-over program.

We acquired our initial 100% working interest in the Cow Creek Field from KCS Mountain Resources in April 1999. The 14 original producing wells in the Cow Creek Field that Double Eagle operated became a part of the Catalina Unit participating area on December 21, 2007, when the new wells drilled by the Company during 2007 established production levels specified in the Unit agreement. Upon reaching required production levels, the Unit participating area was established. Unitization is a type of sharing arrangement by which owners of operating and non-operating working interests pool their property interests in a producing area to form a single operating unit. Units are designed to improve efficiency and economics of developing and producing an area. The share that each interest owner receives is based upon the respective acreage contributed by each owner in the participating area (“PA”) as a percentage of the entire acreage of the PA. The PA and our associated working interest will change as more wells and acreage are added to the PA. In 2007, 33 producing wells were drilled and cased, bringing our working interest to 73.84%. With the drilling of the 24 new wells in 2008, our working interest in the Catalina Unit decreased to 69.31%. As we continue to expand the Catalina Unit, our working interest will continue to change. We anticipate our working interest will be approximately 51.23% upon the planned development of the existing acreage.

Production in the Catalina Unit resulted in net sales volumes to us of 5.9 Bcf in 2009 (compared to 4.0 Bcf in 2008 and 1.5 Bcf in 2007), which represented 63% of our total sales volumes for 2009. Our daily net production at the Catalina Unit was 16,154 Mcf.

Coal-bed methane gas wells involve removing gas trapped within the coal itself, through removal of water. Often, the wells are completely saturated with water. As water is removed, gas is able to flow to the wellbore. In 2008, we were granted a permit by the BLM to treat water removed from the wells, for release on the surface. We engaged EMIT Technologies Inc (“EMIT”) to construct a pilot waste water treatment facility within the Catalina Unit. The Company pays EMIT a fee per barrel of water processed. The EMIT plant has capacity to treat and release up to 10,000 barrels of water per day. We are currently the only company in the Atlantic Rim area to receive such a permit. Alternatively, water can be injected back into the ground through injection wells.

Eastern Washakie Midstream Pipeline LLC

The Company owns, through its wholly-owned subsidiary, Eastern Washakie Midstream Pipeline LLC, a 13-mile pipeline and gathering assets, which connect the Catalina Unit with the pipeline system owned by Southern Star Central Gas Pipeline, Inc. The pipeline provides us with access to the interstate gas markets, and the ability to move third party gas. We have an agreement in place for transportation and gathering of all Catalina Unit production volumes that move through our pipeline, for which we receive a third party fee per Mcf of gas transported. The pipeline has a transportation capacity of approximately 125 MMcf per day. The pipeline’s current usage is less than 25% of capacity. The pipeline is expected to provide, but does not guarantee, reliable transportation for future development by the Company and third party operators in the Atlantic Rim of the Eastern Washakie Basin. EWM also owns survey and right of way permits for a potential line extension to the Wyoming Interstate Company (“WIC”).

Doty Mountain Unit

The Doty Mountain Unit is adjacent to and northeast of the Catalina Unit. The Mesaverde coals at Doty Mountain are thicker than in the Catalina Unit and have higher gas contents. Permeability was measured at over 150 millidarcies in the main coal. Anadarko operates this 24,817 acre unit in which we own 3,280 gross and 3,280 net acres of leasehold working interest. As of December 31, 2009, we owned a 16.85% interest of the PA in the Unit. This PA and the associated working interest, including ours, will change as more wells and acreage are added to the PA. The Doty Mountain Unit was established in 2005 and Anadarko operates 60 production wells within this unit. Eleven of these wells are still awaiting completion. We recognized a total net production from the Doty Mountain Unit of 298 MMcf in 2009, or an average of 817 Mcf (net) per day.

Sun Dog Unit

The Sun Dog Unit is adjacent to and east of the Catalina Unit. Anadarko operates the 23,468 acre unit in which we own 3,886 gross and 2,045 net acres of working interest. The Sun Dog Unit was established in 2005 and as of December 31, 2009, we owned an 8.89% working interest of the PA in the Unit. As of December 31, 2009, there were 114 production wells within the Unit. During 2009, the operator performed well workovers, including fracture stimulation on approximately 11 existing wells within the Sun Dog Unit. We are currently awaiting additional water injection capacity in the Sun Dog Unit, and therefore we have not yet realized a production increase related to these workovers. The operator has indicated that at least one of the ten wells expected to be drilled in 2010 will be an injection well in the Sun Dog Unit. During 2009, we recognized a total net production from the Sun Dog Unit of 483 MMcf, or an average daily net production of 1,323 Mcf per day.

Other Acreage

We own interests in additional acreage in the Atlantic Rim that may provide other opportunities for future development.

The Pinedale Anticline in the Green River Basin of Wyoming

The Pinedale Anticline is in southwestern Wyoming, 10 miles south of the town of Pinedale. Questar operates 2,400 acres in the Mesa Unit in which we hold a net acreage position of 110 acres. The Mesa Unit on the Pinedale Anticline includes 130 non-operated wells producing approximately 22% of our total production for 2009. Our net production from the Mesa Unit in 2009 was 2.1 Bcfe, or 5,648 Mcfe per day, net to our interest.

As of December 31, 2009, in the Mesa “A” PA, there were 22 producing wells, in which we hold a 0.312% overriding royalty interest. Our net acre position is at least 1.875 net acres under a gross of 600 acres in the “A” Participating Area.

In the Mesa “B” PA, where we have an 8% average working interest in the shallow producing formations and a 12.5% average working interest in the deep producing formations, there were 74 producing wells that produced 1,302 MMcfe in 2009, net to our interest. We have a net acreage position of 64 net acres under a gross of 800 acres in the shallower formations in the “B” Participating Area, and 100 net acres under a gross of 800 acres in the deep producing formations. Seventeen, of the 74 wells came on-line for production during the second, third and fourth quarters of 2009. We are also currently participating in the drilling of 16 additional wells, which are expected to be completed during 2010 at a rate of eight in May, four in July and four in August. We believe the operator will drill an additional 12-16 wells in the Mesa “B” PA in second half of 2010.

In the Mesa “C” PA, where we have a working interest of 6.4%, 34 wells produced 756 MMcfe in 2009, net to our interest. We have 65.27 net acres under a gross of 1,000 acres in the “C” Participating Area.

At year end, we had working interests or overriding royalty interests in a total of 4,840 acres in and around this developing natural gas field. It is anticipated that this property will continue to produce significant revenues for us in the foreseeable future.

The Wind River Basin in Central Wyoming

Located in central Wyoming, the Wind River Basin is home to Wyoming’s first oil production, which began in 1884. Since that time, numerous fields have been discovered in the Basin, including two very large natural gas accumulations, the Madden Anticline and the Cave Gulch/Waltman Fields. We have interests in 50,226 gross acres, (2,243 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 lying in the deepest part of the Wind River Basin. Through unitization, we acquired a 0.349% working interest in the Madden Sour Gas PA in the Madden Deep Unit and the Lost Cabin Gas Processing Plant in late 2006, at a cost of approximately $2.5 million. Under the current approved PA, we have 504.74 gross acres (84.14 net acres) that are included in the 24,088 acre participating area. In total, we own an approximate 16.67% working interest in 734.25 acres on the Madden Anticline that potentially could be included in the Madden Sour Gas PA. The unit’s primary operator, Conoco/Phillips (formerly Burlington Resources “BR”) plans to continue to drill additional wells in the unit.

The Madden Sour Gas Participating Area produced 177 MMcf net to our interest of gas in 2009 from seven wells. These are long-lived wells with large producing rates and reserves.

We have not been paid any of the proceeds generated by the sale of gas produced from the Madden Deep Unit over the period beginning with the effective date of the 4^th PA revision through June 30, 2007. We began receiving payments for our share of the sales on July 1, 2007. Along with other plaintiffs, we filed a lawsuit on August 24, 2007, in the District Court of Fremont County, Wyoming, against Conoco/Phillips and other defendants who own working interests in the Madden Deep Unit. We, and the other plaintiffs in the case, are asserting that, under the gas balancing agreement, we are entitled to receive either monetary damages or our respective shares of the gas produced from the Madden Deep Unit over at least the period from February 1, 2002, through June 30, 2007. We have recognized the sales and have recorded a related account receivable of $292, net of allowance, for uncollectible amounts for the period November 1, 2006 through June 30, 2007. Subsequent to June 20, 2007, we have recognized the sales, and have been paid the proceeds due to us. The ultimate outcome of this lawsuit cannot be determined at this time and, as a result, we have not recognized any amount of sales proceeds for the period February 1, 2002 through October 30, 2006. Sulfur sales are not subject to a gas balancing agreement, and, accordingly, we received the proceeds for our share of sulfur sales dating back to February 2002 and continue to receive our respective share on an ongoing basis.

We also own interests, which are restricted in depth and size, in over 12,000 additional acres on the Madden Anticline. Additionally, we operate and produce from one lower Fort Union well and one upper Fort Union well outside of the unit. We will continue to produce these two wells and evaluate the potential for offsets.

South Waltman

The South Waltman acreage is located approximately 15 miles southeast of the Madden Anticline and three miles south of the Cave Gulch field in the Wind River Basin. The field was discovered by Chevron in 1959. We purchased interest in this leasehold in 1996. Double Eagle operates this property and owns an average working interest of 46%. To date,

we have drilled two wells within South Waltman; the Waltman 24-24 well and the Waltman 34-24 well. In August 2008, we drilled the Waltman 24-24 well to its total depth of 9,397 feet. We began producing the upper and lower gas zones in August 2009. We are awaiting the stabilization of the gas and flow rate at this well in order to determine its long term production potential. The Waltman 34-24 well was drilled in December 2007 to a total depth of 9,202 feet. Numerous gas zones were found between the depth of 4,350 feet and 8,960 feet. However, due to unfavorable hole conditions, we were only able to run casing to 6,639 feet. The well was completed at a depth of approximately 4,350 feet, and is awaiting compression and gathering. We have the option on offsetting acreage to drill up to eight additional wells in the future.

The Moxa Arch and Other Areas in Southwest Wyoming

We continue to participate in developmental drilling on the Moxa Arch and other areas within southwest Wyoming, however, due to the economic downturn and low natural gas prices, drilling in this area slowed significantly in 2009. We have interest in a total of 368 wells in this area, one of which was drilled in 2009. In 2010, natural gas prices will dictate further participation in drilling proposals in this area.

Exploration Projects

During 2009, we did not pursue any significant exploration projects. Existing projects we are involved with are detailed below.

Main Fork Unit in Utah

The Main Fork Unit (formerly the Table Top Unit) is located on 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. In early 2007, drilling at the Table Top Unit #1 (“TTU #1”) well reached the originally planned depth of 15,760 feet. The drilling did not find reservoir rocks with sufficient permeability, and operations were suspended to assess alternative approaches to completing the project. In June 2009, the Bureau of Land Management approved a suspension of operations (“SOP”) and production for all leases within the Main Fork Unit. The SOP stops the expiration of lease terms and halts any lease rentals until an environmental impact study is completed, which is expected to take up to three years to complete. During the EIS, the Company is not prevented from exercising its approved rights to re-enter the TTU #1, or drill a new well at the TTU #3 site. The Company is currently in discussion with a third party regarding possible future drilling of the TTU #1 to drill deeper to the Nugget Sandstone formation at 18,000 feet, or the Madison formation at 22,000-24,000 feet.

Nevada

Double Eagle has leased 46,372 gross acres, 39,127 net acres, in the Huntington Valley in Elko and White Pine Counties, Nevada. During 2007, VF Neuhaus drilled the Straight Flush #17-1 well in Huntington Valley, Nevada. Double Eagle had a 97.3% working interest in the well and further earned additional interests under six sections of land. No commercial deposits of oil and gas were identified and the well was plugged in October 2007. Costs incurred through December 31, 2007 of $1,983 were charged to expense as dry hole costs. The results of drilling by other parties in the Huntington Valley have not been encouraging and in 2008, the Company concluded that it does not plan to renew any of the Nevada leases upon their expiration, and therefore, the related capitalized undeveloped leasehold cost of $741 were written off at December 31, 2008.

Accounting for Suspended Well Costs

Under the Accounting Standards Codification, for companies using the successful efforts method of accounting, exploratory well costs should continue to be capitalized when a well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the well. The costs of drilling an exploratory well cannot be carried as an asset for a period greater than one year from completion of drilling (or abandonment of a project), unless it can be shown that sufficient progress (as defined) has been made in assessing the economic and operational viability of a project. The Company continually evaluates all existing capitalized exploratory well costs to ensure each meets the requirements for capitalization. In 2007, we expensed $5,773 related to Table Top Unit #1, $4,395 related to Cow Creek Unit Deep #2, and $2,759 related to PH State 16-1 in 2007, as we no longer met the capitalization requirements.

Reserves

Effective December 31, 2009, the SEC adopted revisions to the oil and gas reporting standards designed to modernize the disclosures and to better align them with current practices and technology. The Company’s December 31, 2009 reserve estimates include the impact of the SEC revisions. The most noteworthy changes were as follows:

•

The new SEC standards require that the Company calculate the quantity and PV-10 value of oil and gas reserves that are economically producible using a simple 12-month average price, using the first-day-of-the-month applicable commodity price within the 12-month period prior to the reporting period end. Prior to this rule change, oil and gas reserves were calculated using the price as of the last day of the reporting period, which was December 31 for the Company. Historically, natural gas prices are higher during the winter months due to cold weather and increased demand. As 97% of our reserves are natural gas, this change in pricing methodology had a significant negative impact on the pricing used in determining our reserves. The average price used for our 2009 reserve estimate was $3.04 per MMbtu and $57.65 per barrel For comparability, using the year-end pricing methodology as required in 2008 and prior years, the Company would have used a price of $5.54 per Mmbtu and $76.00 per barrel to determine the quantity and PV-10 amount of economically producible reserves.

•

The SEC’s modified definition of proved undeveloped oil and gas reserves had a modest favorable impact on the Company’s estimate of reserves as of December 31, 2009. The new definition allows for proved undeveloped reserves to be established for reserves in drilling units beyond those immediately adjacent to the drilling unit containing a producing well. In prior years, the Company was not permitted to establish proved undeveloped reserves beyond those immediately adjacent to the drilling unit containing a producing well. This change was of benefit to the Company in well-defined fields, such as the Pinedale Anticline.

The Company engaged the independent petroleum engineering firm, Netherland, Sewell & Associates, Inc. (“NSAI”) to prepare the Company’s reserve estimates at December 31, 2009, 2008 and 2007. NSAI is a worldwide leader of petroleum property analysis for industry and financial organizations, and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. David Miller and Mr. John Hattner. Mr. Miller has been practicing consulting petroleum engineering at NSAI since 1997. Mr. Miller is a Registered Professional Engineer in the State of Texas (License No. 96134) and has over 28 years of practical experience in petroleum engineering, with over 12 years experience in the estimation and evaluation of reserves. Mr. Hattner has been practicing consulting petroleum geology at NSAI since 1991. Mr. Hattner is a Certified Petroleum Geologist and Geophysicist in the State of Texas (License No. 559) and has over 29 years of practical experience in petroleum geosciences, with over 18 years experience in the estimation and evaluation of reserves. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geosciences evaluations as well as applying SEC and other industry reserves definitions and guidelines. NSAI evaluated properties representing a minimum of 98% of our reserves, valued at the total estimated future net cash flows before income taxes, discounted at 10% (“PV-10”), for all periods presented below. Senior members of the Company’s finance and geology teams review the final reserve report to ensure the accuracy and completeness of all inputs into the report. NSAI’s report to management, which summarizes the scope of work performed and its conclusions, has been included in this report as Exhibit 99.1

All of the Company’s reserves, as shown in the table below, are located within the continental United States.


	As of December 31,
	2009(1)				2008				2007
	Oil		Natural Gas		Oil		Natural Gas		Oil		Natural Gas
	(Bbls)		(Mcf)		(Bbls)		(Mcf)		(Bbls)		(Mcf)
PROVED
Developed		312,963		64,296,948		295,698		63,007,126		253,478		44,782,553
Undevolped		106,250		25,479,722		124,491		23,323,694		159,334		26,471,312

Total proved reserves		419,213		89,776,670		420,189		86,330,820		412,812		71,253,865


(1)		The Company adopted the SEC’s revisions to the oil and gas reporting requirements effective December 31, 2009.

Reserve estimates are inherently imprecise and are continually subject to revisions based on production history, results of additional exploration and development, prices of oil and gas, and other factors. For more information regarding the inherent risks associated with estimating reserves, see Item 1A, “Risk Factors.”

During the year ended December 31, 2009, we converted approximately 2.5 Bcfe of proved undeveloped reserves into proved developed reserves. The conversion of these undeveloped reserves into developed reserves was primarily due to developmental drilling in the Mesa Units in the Pinedale Anticline. In addition, we had negative revisions of approximately 7.2 Bcfe in proved undeveloped reserves due to the changes in commodity prices. We do not have any material concentrations of reserves that have remained undeveloped for a period of five years or more.

The following table summarizes our estimate of proved reserves at December 31, 2009 under the new SEC oil and gas reserve guidance (“SEC pricing”), compared to our estimated proved reserves as if we had followed the pricing methodology for 2008 and prior year (“year end pricing”). Under the year end pricing, we estimated our proved reserves using the applicable commodity price on the last day of the reporting period, December 31, 2009. In the year end pricing, we assumed that production and development costs remained constant on a per well basis, however, it does reflect an increase in our production and development costs for reserves that became economic using this pricing scenario.


	Total Proved								Future Estimated
	Reserves		Price		Price		Future Cash		Production and
	(MMcfe)		per Mmbtu		barrel of oil		Inflows		Development Costs			Pre-tax PV-10

Year End Pricing		114,162	$	5.54	$	76.00	$	622,178		(216,364	)	$	229,763
SEC Pricing		92,292		3.04		57.65		276,374		(121,938	)		91,133

Difference vs.
SEC Pricing		21,870	$	2.50	$	18.35	$	345,804	$	(94,426	)	$	138,630

As shown in the above table, the change in pricing methodology caused a decrease in our estimated proved reserves of 21.9 Bcfe. Had we been able to utilize the year-end pricing, we would have realized a 28% increase in proved reserves from December 31, 2008.

The table below shows our reconciliation of our PV-10 to our standardized measure of discounted future net cash flows (the most directly comparable measure calculated and presented in accordance with GAAP). PV-10 is our estimate of the present value of future net revenues from estimated proved oil and natural gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our oil and natural gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP. Reference should also be made to the Supplemental Oil and Gas Information included in Item 15, Note 11 to the Notes to the Consolidated Financial Statements for additional information.


	As of December 31,
	2009(1)			2008			2007
Present value of estimated future net cash flows before income taxes, discounted at 10% (2)	$	91,133		$	155,766		$	182,594


Reconciliation of non-GAAP financial measure:
PV-10	$	91,133		$	155,766		$	182,594

Less: Undiscounted income taxes		(14,279	)		(58,313	)		(96,370	)
Plus: 10% discount factor		5,853			24,602			44,075

Discounted income taxes		(8,426	)		(33,711	)		(52,295	)

Standardized measure of discounted future net cash flows	$	82,707		$	122,055		$	130,299


(1)		The Company adopted the SEC’s revisions to the oil and gas reporting requirements as of December 31, 2009.

(2)		The average prices utilized for December 31, 2009, 2008, and 2007, respectively, were $3.04 per MMBtu and $57.65 per barrel of oil; $4.61 per MMBtu and $38.67 per barrel of oil; and $5.99 per MMBtu and $86.67 per barrel of oil.

The PV-10 values shown in the aforementioned table are not intended to represent the current market value of the estimated proved oil and gas reserves owned by Double Eagle. The PV-10 value above does not include the impact of our outstanding financial hedges. Reserve estimates are inherently imprecise and are continually subject to revisions based on production history, results of additional exploration and development, prices of oil and gas, and other factors. For more information regarding the inherent risks associated with estimating reserves, see Item 1A, “Risk Factors.”

Production

The following table sets forth oil and gas production by geographic area from our net interests in producing properties for the years ended December 31, 2009, 2008 and 2007.


	For the Year Ended December 31,
	2009				2008				2007
Production:	Oil (Bbls)		Gas (MMcf)		Oil (Bbls)		Gas (MMcf)		Oil (Bbls)		Gas (MMcf)
Atlantic Rim		—		6,677		—		4,473		—		1,708
Pinedale Anticline		16,741		1,961		14,674		1,547		6,097		754
Other		12,186		524		10,994		540		7,866		466

Company total		28,927		9,162		25,668		6,560		13,963		2,928

Average sales price ($/Bbl or $/Mcf)
Atlantic Rim (1)		N/A	$	5.42		N/A	$	5.86		N/A	$	5.52
Pinedale Anticline	$	47.40	$	3.39	$	77.10	$	6.62	$	63.93	$	5.03
Other	$	57.49	$	3.09	$	77.42	$	6.39	$	62.08	$	4.17
Company average	$	51.65	$	4.85	$	77.24	$	6.08	$	63.17	$	5.18


Average production cost ($/mcfe)
Atlantic Rim (2)	$	0.85	$	1.17	$	2.68
Pinedale Anticline	$	0.53	$	0.51	$	0.63
Other	$	1.67	$	1.49	$	1.22
Company average	$	0.83	$	1.04	$	1.89


(1)		Our average gas price in the Atlantic Rim includes the settlements on our financial hedges which due to accounting rules, is included in our price risk management activities line on the Consolidated Statement of Operations, totaling $3,503, $2,698, and $0, for the years ended December 31, 2009, 2008 and 2007, respectively.

(2)		Production costs, on a dollars per Mcfe basis, is calculated by dividing production costs, as stated on the consolidated statement of operations, by total production volumes during the period. This calculation for the Atlantic Rim excludes certain gathering costs incurred by the Company’s subsidiary, Eastern Washakie Midstream, which are eliminated in consolidation.

Derivative Instruments

We have entered into various derivative instruments to mitigate the risk associated with downward fluctuations in the natural gas price. Historically these derivative instruments have consisted of fixed delivery contracts, swaps, options and costless collars. The duration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operating strategy. Under our current credit agreement, we can hedge up to 90% of the projected proved developed producing reserves for the next 12 month period, and up to 80% of the projected proved producing reserves for the ensuing 24 month period. As of December 31, 2009, we had derivative instruments in place for 77% of our daily net production.

Remaining

Contractual

Daily

Price

Type of Contract

Volume

Production

Term

Price

Index (1)

Fixed Price Swap

4,380,000

12,000

1/10-12/10

4.30

CIG

Costless Collar

2,885,000

5,000

8/09-7/11

$4.50 floor

NYMEX

$7.90 ceiling

Costless Collar

3,495,000

5,000

12/09-11/11

$4.50 floor

NYMEX

$9.00 ceiling

Fixed Price Swap

2,920,000

8,000

1/11-12/11

7.07

CIG

Total

13,680,000


(1)		NYMEX refers to quoted prices on the New York Mercantile Exchange. CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month.

See Item 15, Note 6 to the Notes to the Consolidated Financial Statements for discussion regarding the accounting treatment of our derivative contracts.

Productive Wells

The following table categorizes certain information concerning the productive wells in which we owned an interest as of December 31, 2009. For purposes of this table, wells producing both oil and gas are shown in both columns. We operate 87 producing wells in the state of Wyoming, four wells in Texas and one in Oklahoma, which are included in the table below.


	Oil				Gas
State	Gross		Net		Gross		Net
Wyoming		86		5.99		1,048		99.47
Other		33		4.49		5		0.09

Total		119		10.48		1,053		99.56

Drilling Activity

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


	For the Year Ended December 31,
	2009				2008				2007
	Gross		Net		Gross		Net		Gross		Net
Exploratory
Oil		—		—		—		—		—		—
Gas		—		—		—		—		1		0.50
Dry Holes		—		—		—		—		1		0.98
Water Injection		—		—		—		—		—		—
Other		—		—		—		—		—		—

		—		—		—		—		2		1.48

Development
Oil		—		—		1		0.05		—		—
Gas		42		3.12		178		27.59		223		35.06
Dry Holes		—		—		1		0.69		—		—
Water Injection		—		—		14		5.42		9		2.72
Water Supply		1		1.00		—		—		—		—
Other		—		—		5		2.67		1		0.08

		43		4.12		199		36.42		233		37.86


Total		43		4.12		199		36.42		235		39.34

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

Finding and Development Costs

For the year ended December 31, 2009, we had additions to our proved reserves of 22.3 Bcfe, as compared to our 2009 annual production of 9.3 MMcfe, providing for a reserve replacement ratio of 239%. During the same period, we expended $20.3 million in finding and development costs, defined as costs incurred by the Company in 2009 related to successful exploratory wells and successful and dry development wells. This activity resulted in a one-year finding and development cost in 2009 of $0.91 per Mcfe. “Finding and development costs per Mcfe” is determined by dividing our annual exploratory and development costs, as defined above, by proved reserve additions, including both developed and undeveloped reserves added during the current year (gross amounts, not net of production). We use this measure as one indicator of the overall effectiveness of our exploration and development activities.

In determining the finding and development costs per Mcfe for the years ended December 31, 2009 2008, and 2007, total proved reserve additions consisted of (expressed in Mcfe):


	As of December 31
	2009		2008		2007
Proved Developed (MMcfe)		10,543		17,196		21,888
Proved Undeveloped (MMcfe)		11,761		9,441		23,317

Total Proved Reserves Added		22,304		26,637		45,205


One year finding and development costs per Mcfe	$	0.91	$	1.47	$	0.99

Proved reserves were added in each of 2009, 2008 and 2007 through both incremental additions associated with our higher density spacing of prospective drilling locations on our non-operated properties, as well as through our development drilling activities.

Our finding and development cost per Mcfe measure has certain limitations. Consistent with industry practice, our finding and development costs have historically fluctuated on a year-to-year basis based on a number of factors including the extent and timing of new discoveries, property acquisitions and fluctuations in the commodity prices used to estimate reserves. Due to the timing of proved reserve additions and timing of the related costs incurred to find and develop our reserves, our finding and development costs per Mcfe measure often includes quantities of reserves for which a majority of the costs of development have not yet been incurred. Conversely, the measure also often includes costs to develop proved reserves that had been added in earlier years. Finding and development costs, as measured annually, may not be indicative

of our ability to economically replace oil and natural gas reserves because the recognition of costs may not necessarily coincide with the addition of proved reserves. Our finding and development costs per Mcfe may also be calculated differently than the comparable measure for other oil and gas companies.

Acreage

The following tables set forth the gross and net acres of developed and undeveloped oil and gas leases in which Double Eagle had working interests and royalty interests as of December 31, 2009. Undeveloped acreage includes leasehold interests that may have been classified as containing proved undeveloped reserves.

Acreage by Working Interest:


	Developed Acres (1)				Undeveloped Acres (2)				Total Acres
State	Gross		Net		Gross		Net		Gross		Net
Wyoming		121,541		9,125		88,615		39,223		210,156		48,348
Nevada		—		—		46,372		39,127		46,372		39,127
Utah		637		16		46,440		21,146		47,077		21,162
Other		5,544		2,678		3,732		799		9,276		3,477

Total		127,722		11,819		185,159		100,295		312,881		112,114

Acreage by Royalty Interest:


	Developed Acres (1)				Undeveloped Acres (2)				Total Acres
State	Gross		Net		Gross		Net		Gross		Net
Wyoming		10,464		162		27,763		1,547		38,227		1,709
Other		3,089		63		5,633		483		8,722		546

Total		13,553		225		33,396		2,030		46,949		2,255


(1)		Developed acreage is acreage assigned to producing wells for the spacing unit of the producing formation. Developed acreage in certain of the Company’s properties that include multiple formations with different well spacing requirements may be considered undeveloped for certain formations, but have only been included as developed acreage in the presentation above.

(2)		Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.

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

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


	Expiring Acreage
Fiscal Year	Gross		Net
2010		17,021		12,258
2011		22,351		5,913
2012 and thereafter		320,458		96,198

Total		359,830		114,369

Other Significant Developments since December 31, 2008

In August 2009, we completed our acquisition of Petrosearch Energy Corporation (“Petrosearch”) in exchange for 1.8 million shares of Double Eagle common stock and cash consideration of $873. Upon closing of the acquisition, Petrosearch became a wholly-owned subsidiary of the Company. Through the acquisition, we obtained approximately

$8.6 million of cash, as well as oil and gas properties in North Dakota, Oklahoma and Texas valued in the aggregate at approximately $350.

Effective February 5, 2010, the Company renegotiated its $75 million credit facility, to extend the maturity date from July 31, 2010 to January 31, 2013. The borrowing availability on the facility remained at $45 million, collateralized by our oil and gas properties. There were no material changes to any other terms of the credit facility, including our financial and non-financial covenants. The Company paid approximately $450 in one-time financing fees related to renegotiating this facility.

Marketing and Major Customers

The principal products produced by us are natural gas and crude oil. These products are marketed and sold primarily to purchasers that have access to nearby pipeline facilities. Typically, oil is sold at the wellhead at field-posted prices and natural gas is sold both (i) under contract at negotiated prices based upon factors normally considered in the industry (such as distance from well to pipeline, pressure, quality); and (ii) at spot prices. We currently have no long-term delivery contracts in place.

The marketing of most of our products is performed by a third-party marketing company, Summit Energy, LLC. During the years ended December 31, 2009, 2008 and 2007, we sold 85%, 80%, and 67%, respectively, of our total oil and gas sales volumes to Summit Energy, LLC. There were no other companies that purchased more than 10% of our oil and gas production. Although a substantial portion of our production is purchased by one customer, we do not believe the loss of this customer would have a material adverse effect on our business as other customers would be accessible to us.

Title to Properties

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

Seasonality

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

We have entered into various financial derivative instruments for a portion of our production, which reduces our overall exposure to seasonal demand and resulting commodity price fluctuations. The duration and size of our various derivative contracts depends on our view of market conditions, available contract prices and our operating strategy. As of December 31, 2009, we had derivative instruments in effect for approximately 77% of our daily net production.

Competition

The oil and gas industry is highly competitive and we compete with a substantial number of other companies that have greater financial and other resources. We encounter significant competition particularly in acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring prospective oil and natural gas properties, obtaining sufficient rig availability, obtaining purchasers and transporters of the oil and natural gas we produce and hiring and retaining key employees. There is also competition between oil and natural gas producers and other industries producing energy and fuel. Our competitive position also depends on our geological, geophysical and engineering expertise, and our financial resources. We believe that the location of our leasehold acreage, our exploration, drilling and production expertise and the experience and knowledge of our management and industry partners enable us to compete effectively in our current operating areas. Historically, access to incremental drilling

equipment in certain regions has been difficult, but due to the economic downturn, rig and staff availability is not anticipated to have any material negative impact on our ability to deploy our capital drilling budget for 2010.

Government Regulations

Exploration for, and production and marketing of, crude oil and natural gas are extensively regulated at the federal and state and local levels. Matters subject to regulation include the issuance of drilling permits,allowable rates of production, the methods used to drill and case wells, reports concerning operations, the spacing of wells, the unitization of properties, taxation issues and environmental protection (including climate change). These regulations are under constant review and may be amended or changed from time-to-time in response to economic or political conditions.

Pipelines are also subject to the jurisdiction of various federal, state and local agencies. Our ability to economically produce and sell crude oil and natural gas is affected by a number of legal and regulatory factors, including federal, state and local laws and regulations in the US and laws and regulations of foreign nations. Many of these governmental bodies have issued rules and regulations that are often difficult and costly to comply with, and that carry substantial penalties for failure to comply. These laws, regulations and orders may restrict the rate of crude oil and natural gas production below the rate that would otherwise exist in the absence of such laws, regulations and orders. The regulatory burden on the crude oil and natural gas industry increases our costs of doing business and consequently affects our profitability. See Item 1A. Risk Factors — We are subject to various governmental regulations and environmental risks that may cause us to incur substantial costs.

Examples of US federal agencies with regulatory authority over our exploration for, and production and sale of, crude oil and natural gas include:

	•		the Bureau of Land Management (BLM) and the Minerals Management Service (MMS), which under laws such as the Federal Land Policy and Management Act, Endangered Species Act, National Environmental Policy Act and Outer Continental Shelf Lands Act have certain authority over our operations on federal lands, particularly in the Rocky Mountains and deepwater Gulf of Mexico;

	•		the US Environmental Protection Agency (EPA) and the Occupational Safety and Health Administration, which under laws such as the Comprehensive Environmental Response, Compensation and Liability Act, as amended, the Resource Conservation and Recovery Act, as amended, the Oil Pollution Act of 1990, the Clean Air Act, the Clean Water Act, the Occupational Safety and Health Act and the recent Final Mandatory Reporting of Greenhouse Gases Rule have certain authority over environmental, health and safety matters affecting our operations ;

	•		the Federal Energy Regulatory Commission, which under laws such as the Energy Policy Act of 2005 has certain authority over the marketing and transportation of crude oil and natural gas;

	•		other federal agencies with certain authority over our business, such as the Internal Revenue Service and the SEC, as well as the NYSE upon which shares of our common stock are traded.

In January 2010, the BLM announced that it will be issuing a new draft oil and gas leasing policy that will require, among other things, a more detailed environmental review prior to leasing oil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process. As the policy has not yet been released, we are not able to determine the impact these potential leasing policy changes may have on our business. Most of the states within which we operate have separate agencies with authority to regulate related operational and environmental matters. Some of the counties and municipalities within which we operate have adopted regulations or ordinances that impose additional restrictions on our oil and gas exploration and production.

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

Environmental Laws and Regulations

Our operations are subject to numerous federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may

require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on specified lands within wilderness, wetlands and other protected areas, require remedial measures to mitigate pollution from former operations, such as pit closure and plugging abandoned wells, and impose substantial liabilities for pollution resulting from production and drilling operations. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly waste handling, disposal and cleanup requirements, our business and prospects could be adversely affected.

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

We have made and will continue to make expenditures in our efforts to comply with environmental requirements. We do not believe that we have, to date, expended material amounts in connection with such activities or that compliance with such requirements will have a material adverse effect on our capital expenditures, earnings or competitive position. Although such requirements do have a substantial impact on the crude oil and natural gas industry, they do not appear to affect us to any greater or lesser extent than other companies in the industry.

Cautionary Information about Forward-Looking Statements

This Form 10-K includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation the Risk Factors set forth in this Form 10-K in Part I, “Item 1A. Risk Factors” and the following:

	•		Our ability to maintain adequate liquidity in connection with low oil and gas prices;

	•		The changing political environment in which we operate

	•		Our ability to continue to develop our Atlantic Rim project;

	•		Our ability to obtain, or a decline in, oil or gas production, or a decline in oil or gas prices;

	•		Our ability to increase our natural gas and oil reserves;

	•		Incorrect estimates of required capital expenditures;

	•		The amount and timing of capital deployment in new investment opportunities;

	•		The volumes of production from our oil and gas development properties, which may be dependent upon issuance by federal, state, and tribal governments, or agencies thereof, of drilling, environmental and other permits, and the availability of specialized contractors, work force, and equipment;

	•		Our future capital requirements and availability of capital resources to fund capital expenditures;

	•		Our ability to successfully integrate and profitably operate any future acquisitions;

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

	•		The possibility that we may be required to take impairment charges to reduce the carrying value of some of our long-lived assets when indicators of impairment emerge;

	•		Numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and actual future production rates and associated costs;

	•		Our ability to remedy any deficiencies that may be identified in the review of our internal controls;

	•		The credit worthiness of third-parties which we enter into business agreements with;

	•		General economic conditions, tax rates or policies, interest rates and inflation rates;

	•		Changes in or compliance with laws and regulations, particularly those relating to taxation, safety and protection of the environment;

	•		Weather, climate change and other natural phenomena;

	•		Industry and market changes, including the impact of consolidations and changes in competition;

	•		The effect of accounting policies issued periodically by accounting standard-setting bodies;

	•		The actions of third party co-owners of interests in properties in which we also own an interest;

	•		The cost and effects on our business, including insurance, resulting from terrorist actions or natural disasters and responses to such actions or events;

	•		The volatility of our stock price; and

	•		The outcome of any future litigation or similar disputes and the impact on any such outcome or related settlements.

We may also make material acquisitions or divestitures or enter into financing transactions. None of these events can be predicted with certainty and the possibility of their occurring is not taken into consideration in the forward-looking statements.

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward -looking statements, whether as a result of new information, future events, or otherwise.

Employees and Office Space

As of December 31, 2009, we had 24 full-time employees. None of our employees is subject to a collective bargaining agreement, and we consider our relations with our employees to be excellent. We own 6,765 square feet of office space in Casper, Wyoming, which serves as our operations headquarters. We lease 3,932 square feet of office space in Denver, Colorado, for our principal executive offices. We also assumed two leases as part of the Petrosearch acquisition, including 3,726 square feet of office space in Houston, Texas and 2,103 square feet of office space in Dallas, Texas.

Available Information

Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, and amendments to reports filed or furnished pursuant to Sections 11(a) and 15(d) of the Securities Exchange Act of 1934, as amended, are available on our website at http://www.dble.com/, as soon as reasonably practicable after we electronically file such reports with, or furnish those reports to the Securities and Exchange Commission. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and amendments to reports are available free of charge by writing to:

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

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

Information on our website is not incorporated by reference into this Form 10-K and should not be considered a part of this document.

Glossary

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

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

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

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

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

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

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

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

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

Economically producible. A resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

Farmout. An assignment of interest in a drilling location and related acreage conditioned upon the drilling of a well on that location.

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

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

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

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

Mcf. One thousand cubic feet.

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

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

MMcf. One million cubic feet.

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

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

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

Permeability. The ability, or measurement of a rock’s ability, to transmit fluids, typically measured in darcies or millidarcies. Formations that transmit fluids readily, such as sandstones, are described as permeable and tend to have

many large, well-connected pores. Impermeable formations, such as shales and siltstones, tend to be finer grained or of a mixed grain size, with smaller, fewer, or less interconnected pores.

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

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

Proved reserves. The quantities of oil, natural gas and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs under existing economic conditions and operating conditions.

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

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

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

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

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

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains estimated net proved reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to share in the production. Working interest owners also share a proportionate share of the costs of exploration, development, and production costs.


ITEM 1A.		RISK FACTORS

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

Our operations are subject to governmental risks that may impact our operations.

Our operations have been, and at times in the future may be, affected by political developments and are subject to complex federal, state, tribal, local and other laws and regulations such as restrictions on production, permitting, changes in taxes, deductions, royalties and other amounts payable to governments or governmental agencies, price or gathering-rate controls, hydraulic fracturing and environmental protection regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals

and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws, including environmental and tax laws, and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. For example, currently proposed federal legislation, that, if adopted, could adversely affect our business, financial condition and results of operations, includes the following:

	•		Climate Change. Climate-change legislation establishing a “cap-and-trade” plan for green-house gases (GHGs) has been approved by the U.S. House of Representatives. It is not possible at this time to predict whether or when the U.S. Senate may act on climate-change legislation.

	•		The U.S. Environmental Protection Agency (EPA) has also taken recent action related to GHGs. Based on recent developments; the EPA now purports to have a basis to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act.

	•		Taxes. The U.S. President’s Fiscal Year 2011 Budget Proposal includes provisions that would, if enacted, make significant changes to United States tax laws. These changes include, but are not limited to, (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) eliminating the deduction from income for domestic production activities relating to oil and natural-gas exploration and development, and (iii) implementing certain international tax reforms.

	•		Hydraulic Fracturing. The U.S. Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural-gas industry in the hydraulic-fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. We find that the use of hydraulic fracturing is necessary to produce commercial quantities of crude oil and natural gas from many reservoirs. Currently, regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. This legislation, if adopted, could establish an additional level of regulation and permitting at the federal level.

	•		Derivatives. The U.S. Congress is currently considering derivatives reform legislation focusing on expanding Federal regulation surrounding the use of financial derivative instruments, including credit default swaps, commodity derivatives and other over-the-counter derivatives. Among the recommendations included in the proposals are the requirements for centralized clearing or settling of such derivatives as well as the expansion of collateral margin requirements for certain derivative market participants. Although we do not currently know the exact form any final legislation or rule-making activity will take, any restriction on the use of OTC instruments could have a significant impact on our business. Limits on the use of OTC instruments could significantly reduce our ability to execute strategic price hedges to reduce price uncertainty and to protect cash flows. In addition, cash collateral requirements could create significant liquidity issues and exchange system trades may restrict our ability to execute derivative instruments to fit our strategic needs.

We may be unable to develop our existing acreage due to the change in the political environment and administration.

The anticipated growth and planned expenditures are based upon the presumption that existing leases and regulations will remain intact and allow for the future development of carbon based fuels. With the change in the United States political balance and the unclear and unknown direction that the existing administration will pursue, our ability to develop known and unknown reserves in areas in which we have reserves or leases may be limited, thereby limiting our ability to grow and generate cash flows from operations.

We may be unable to further develop our coal bed methane projects in the Atlantic Rim, which would have a significant adverse effect on our current growth opportunities.

The largest portion of our anticipated growth and planned capital expenditures are expected to be from properties located in the Atlantic Rim that are covered by the Atlantic Rim EIS. In May 2007, the final Record of Decision for the Atlantic Rim EIS was issued, which allowed us, and other operators in the area, to pursue additional coal bed methane drilling. That decision was appealed and stays were requested in an attempt to postpone or cancel the commencement of additional drilling in the Atlantic Rim EIS area. During June, 2007, we were informed by the U.S. Bureau of Land Management (“BLM”) that three separate coalitions of conservation groups appealed, or were in the process of appealing, the approval of the EIS. In September 2007, the request was denied and in November 2007, United States District Judge Richard J. Leon issued his Order and Memorandum Opinion denying a preliminary injunction to stop the Company’s development efforts in the Atlantic Rim EIS area. In June 2008 and January 2009, two of the appeals by conservation groups were denied. Currently there is one appeal from conservation groups still pending. It is unknown whether the third appeal will be successful, which could ultimately prevent future drilling in this area. We believe our interests in this area hold potential

for significant new reserves that we may not be able to replace. If we are unable to pursue our drilling plans in the Atlantic Rim area, we may be required to expend significant financial resources and time to try to find other areas to replace the potential reserves in the Atlantic Rim area, and we can provide no assurances that we will be able to find a suitable replacement, if any. Moreover, we may encounter a number of difficulties when trying to replace the potential inventory of drilling sites currently covered by the Atlantic Rim EIS. See the Risk Factors titled “-We may be unable to find additional reserves, which would adversely impact our ability to sustain production levels” and “-Acquisitions are a part of our business strategy and are subject to the risks and uncertainties of evaluating recoverable reserves and potential liabilities” discussed herein.

We cannot predict the future price of oil and natural gas and an extended decline in prices could hurt our profitability, financial condition and ability to grow.

Our revenues, profitability and liquidity, future rate of growth and carrying value of our oil and gas properties are heavily 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 in the Rocky Mountain region of the Unites States, and in particular Wyoming, have been more adversely affected by the market volatility than other regions of the country, due to insufficient pipeline capacity and the resulting excess supply. Historically, prices have also been affected by actions of federal, state and local agencies, the United States and foreign governments, international cartels, levels of consumer demand, weather conditions, domestic and foreign supply of oil and natural gas, and the price and availability of alternative fuels. 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 may be unable to fund our planned capital expenditures.

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

	•		general economic and financial market conditions;

	•		oil and natural gas prices; and

	•		our market value and operating performance.

We may be unable to execute our operating strategy if we cannot obtain adequate capital. If low oil and natural gas prices, lack of adequate gathering or transportation facilities, operating difficulties or other factors, many of which are beyond our control, cause our revenues and cash flows from operating activities to decrease, we may be limited in our ability to spend the capital necessary to complete our capital expenditures program.

Indebtedness may limit our liquidity and financial flexibility.

As of December 31, 2009, we had long-term indebtedness of $34 million drawn under our bank credit facility.

Our indebtedness affects our operations in several ways, including the following:

	•		a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;

	•		we may be at a competitive disadvantage as compared to similar companies that have less debt;

	•		our credit facility limits the amounts we can borrow to a borrowing base amount, determined by our lenders in their sole discretion. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the credit facility. Any decrease in the borrowing base could limit our ability to fund operations or future development;

	•		Upon any downward adjustment of the borrowing base, if the outstanding borrowings are in excess of the

revised borrowing base, we have the option to repay our indebtedness in excess of the borrowing base immediately, or in six monthly installments, or pledge additional properties as collateral. We may not have sufficient funds to make such repayments under our credit facility.

	•		the covenants contained in the agreements governing our outstanding indebtedness and future indebtedness may limit our ability to borrow additional funds, pay dividends and make certain investments and may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

	•		additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants;

	•		additional financing in the future is likely to have higher costs due to the negative impact of the credit market crisis which restricted access to the bond markets; and

	•		we may be more vulnerable to general adverse economic and industry conditions.

We may incur additional debt in order to fund our exploration, development and acquisition activities. A higher level of indebtedness increases the risk that our liquidity may become impaired and we default on our debt obligations. Our ability to meet our debt obligations and reduce our level of indebtedness depends on future performance. General economic conditions, crude oil and natural gas prices and financial, business and other factors will affect our operations and our future performance. Many of these factors are beyond our control and we may not be able to generate sufficient cash flow to pay the interest on our debt, and future working capital, borrowings and equity financing may not be available to pay or refinance such debt.

We are exposed to counterparty credit risk as a result of our receivables and hedging transactions.

We are exposed to risk of financial loss from trade, hedging activity, and other receivables. We sell our crude oil and natural gas to a variety of purchasers. We monitor the creditworthiness of our counterparties on an ongoing basis. However, disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to perform under the terms of the hedging contracst. We are unable to predict sudden changes in financial market conditions or a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a contract. We use master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be “net settled” at the time of election. “Net settlement” refers to a process by which all transactions between counterparties are resolved into a single amount owed by one party to the other.

During periods of falling commodity prices, such as in late 2008 and first quarter 2009, our hedge receivable positions increase, which increases our counterparty exposure. If the creditworthiness of our counterparties, which are major financial institutions, deteriorates and results in their nonperformance, we could incur a significant loss.

Our credit facility has borrowing base restrictions, which could adversely affect our operations.

Our amended and restated credit facility limits the amounts we can borrow to a borrowing base amount, determined by our lenders in their sole discretion, based upon, among other things, our level of proved reserves and the projected revenues from the oil and natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the credit facility. Any increase in the borrowing base requires the consent of all lenders.

Upon any downward adjustment of the borrowing base, if the outstanding borrowings are in excess of the revised borrowing base, we have the option to repay our indebtedness in excess of the borrowing base immediately, or in six monthly installments, or pledge additional properties as collateral. We may not have sufficient funds to make such repayments under our credit facility.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and other oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment and supplies are sometimes greater and their availability may be limited.

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

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

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

	•		timing and amount of capital expenditures;

	•		expertise and financial resources;

	•		inclusion of other participants in drilling wells; and

	•		use of technology.

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

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

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

	•		seeking to acquire desirable producing properties or new leases for future exploration;

	•		seeking to acquire the equipment and expertise necessary to develop and operate our properties; and

	•		Retention and hiring of skilled employees.

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

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

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

We may be unable to find additional reserves, which would adversely impact our ability to sustain production levels.

Our future operations depend on whether we find, develop or acquire additional reserves that are economically recoverable. Our properties produce oil and gas at a declining rate. Unless we acquire properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves, production and revenues will decline over time.

The exploration, development and operation of oil and gas properties involve substantial risks that may result in a total loss of investment.

The business of exploring for and, to a lesser extent, developing and operating oil and gas properties involves a high degree of business and financial risk, and thus a substantial risk of loss of investment that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Oil and gas drilling and production activities may be

shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:

	•		unexpected drilling conditions;

	•		pressure or irregularities in formations;

	•		equipment failures or accidents;

	•		adverse changes in prices;

	•		weather conditions;

	•		shortages in experienced labor; and

	•		shortages or delays in the delivery of equipment.

We may drill wells that are unproductive or, although productive, do not produce oil and/or natural gas in commercial quantities. Acquisition and completion decisions generally are based on subjective judgments and assumptions that are speculative. We cannot predict with certainty the production potential of a particular property or well. Furthermore, a successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational, or market-related factors, including, but not limited to:

	•		unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks;

	•		shortages or delays in the availability of drilling rigs and the delivery of equipment; and

	•		loss of circulation of drilling fluids or other conditions.

These factors may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered which impair or prevent the production of oil and/or natural gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or toxic substances.

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

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

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

Our prices, net income and cash flows may be impacted adversely by new taxes.

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

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

The estimates of reserves and future net revenues are not exact and are based on many variable and uncertain factors; therefore, the estimates may vary substantially from the actual amounts depending, in part, on the assumptions made and may be subject to adjustment either up or down in the future. This report on Form 10-K contains estimates of our proved oil and natural gas reserves. The process of estimating oil and natural gas reserves requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those estimated. Any significant variance could materially affect the estimated quantities and

the value of our reserves. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of these oil and natural gas reserves and the costs associated with development of these reserves in accordance with SEC regulations, actual capital expenditures will likely vary from estimated capital expenditures, development may not occur as scheduled and actual results may not be as estimated.

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

We could be subject to significant liabilities related to acquisitions. The successful acquisition of producing and non-producing properties requires an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, future oil and gas prices, operating costs and potential environmental and other liabilities, title issues and other factors. It generally is not feasible to review in detail every individual property included in an acquisition. Ordinarily, a review is focused on higher valued properties. Further, even a detailed review of all properties and records may not reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not always inspect every well we acquire, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is performed. We cannot assure you that our future acquisition activity will not result in disappointing results.

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

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

We depend on key personnel.

Our success depends to a significant extent upon the efforts and abilities of our senior management and key employees. The loss of the services of these individuals could have a material adverse effect upon our business and results of operations.

Declining economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions. The consequences of a potential or prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital.

The trading volatility and price of our common stock may be affected by many factors.

In addition to our operating results and business prospects, many other factors affect the volatility and price of our common stock. The most important of these, some of which are outside our control, are the following:

	•		The current financial crisis, which has caused significant market volatility worldwide;

	•		Governmental action or inaction in light of key indicators of economic activity or events that can significantly influence U.S. financial markets, and media reports and commentary about economic or other matters, even when the matter in question does not directly relate to our business; and

	•		Trading activity in our common stock, which can be a reflection of changes in the prices for oil and gas, or market commentary or expectations about our business and overall industry.

ITEM 3. LEGAL PROCEEDINGS

From time to time, we are involved in various legal proceedings, including the matters discussed below. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters, and while the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.

The Company, along with other plaintiffs, filed a lawsuit on August 24, 2007, in the District Court of Fremont County, Wyoming, against Conoco/Phillips and other defendants who own working interests in the Madden Deep Unit. The Company and the other plaintiffs in the case are asserting that, under the gas balancing agreement, they are entitled to receive either monetary damages or their respective shares of the natural gas produced from the Madden Deep Unit over at least the period February 1, 2002 through June 30, 2007. For the period from November 1, 2006 through June 30, 2007, the Company has recognized the sales and has recorded a related account receivable of $292, net of allowance for uncollectible amounts. Subsequent to June 2007, we continued to recognize sales for our share of production and have consistently collected on the receivables due to us. The ultimate outcome of this lawsuit cannot be determined at this time and, as a result, the Company has not recognized any amount of sales proceeds for the period February 1, 2002 through October 30, 2006. Sulfur sales are not subject to a gas balancing agreement, and, accordingly, we received the proceeds for our share of sulfur sales dating back to February 2002 and continue to receive our respective share on an on-going basis.

On December 18, 2009, Tiberius Capital, LLC (“Plaintiff”), a stockholder of Petrosearch Energy Corporation (“Petrosearch”) prior to the Company’s acquisition (the “Acquisition”) of Petrosearch pursuant to a merger between Petrosearch and a wholly-owned subsidiary of the Company, filed a claim in the US District Court of New York against Petrosearch, the Company, and the individuals who were officers and directors of Petrosearch prior to the Acquisition. In general, the claims against the Company and Petrosearch are that Petrosearch inappropriately denied dissenters’ rights of appraisal under the Nevada Revised Statutes to its stockholders in connection with the Acquisition, that the defendants violated various sections of the Securities Act of 1933 and the Securities Exchange Act of 1934, and that the defendants caused other damages to the stockholders of Petrosearch. The Company does not believe the case has merit, and intends to defend this case vigorously. As of March 4, 2010, service by the Plaintiff has not been made.

ITEM 4. RESERVED

PART II

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

Common Stock

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

The range of high and low sales prices for our Common Stock for each quarterly period from January 1, 2008 through December 31, 2009 as reported by the NASDAQ Stock Market, is set forth below:


Quarter Ended	High		Low
December 31, 2009	$	6.02	$	4.04
September 30, 2009		5.40		3.75
June 30, 2009		6.49		3.62
March 31, 2009		11.23		3.00

December 31, 2008	$	13.76	$	4.02
September 30, 2008		18.99		12.55
June 30, 2008		19.91		16.91
March 31, 2008		17.25		13.05

On February 19, 2010, the closing sales price for the Common Stock as reported by the NASDAQ Global Select Market was $4.36 per share.

Holders. On February 19, 2010, the number of holders of record of our common stock was 1,220.

Dividends. We have not paid or declared any cash dividends on our common stock in the past and do not intend to pay or declare any cash dividends in the foreseeable future. We currently intend to retain future earnings for the future operation and development of our business including exploration, development and acquisition activities. Any future dividends would be subordinate to the full cumulative dividends on all shares of our Series A Preferred Stock.

Performance Graph

Comparison of Five-Year Cumulative Total Return Among
Double Eagle Petroleum Co., the Standard and Poor’s 500 Stock Index, and the Peer Group Index
Total Return (Stock Price Plus Reinvested Dividends)


			December 31,
	January 1, 2005		2005		2006		2007		2008		2009
Double Eagle Petroleum	$	100.00	$	105.64	$	127.14	$	81.62	$	36.35	$	22.37
Peer Group	$	100.00	$	184.91	$	180.66	$	180.90	$	132.80	$	116.82
S&P500	$	100.00	$	103.00	$	117.03	$	121.16	$	74.53	$	92.01

The total return assumes that dividends were reinvested quarterly and is based on a $100 investment on December 31, 2004. During the five year period ended December 31, 2009, Double Eagle’s common stock cumulative annual growth rate was -25.9%, as compared to 3.2% for our Peer Group and -1.7% for the S&P 500 Index.

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

Series A Cumulative Preferred Stock

Market Information. Our Series A Cumulative Preferred Stock (“Series A Preferred Stock”) is currently traded on the NASDAQ Global Select Market under the symbol “DBLEP”. Our Series A Preferred Stock was issued and began trading on July 3, 2007.

The range of high and low sales prices for our Series A Preferred Stock for each quarterly periods beginning January 1, 2008 through December 31, 2009, as reported by the NASDAQ Stock Market, is set forth below:


Quarter Ended	High		Low
December 31, 2009	$	24.00	$	20.50
September 30, 2009		23.00		18.15
June 30, 2009		21.40		15.50
March 31, 2009		22.01		12.90

December 31, 2008	$	21.35	$	14.00
September 30, 2008		19.75		18.79
June 30, 2008		27.00		25.50
March 31, 2008		30.20		23.40

On February 19, 2010, the closing sales price for the Series A Preferred Stock as reported by the NASDAQ Global Select Market was $23.30 per share.

Holders. All shares of the Series A Preferred Stock are held at the Depository Trust Company

Dividends. Holders of Series A Preferred Stock will be entitled to receive, when and as declared by the board of directors, out of funds legally available for the payment of dividends, cumulative cash dividends on the Series A Preferred at a rate of 9.25% per annum of the $25.00 liquidation preference (equal to $2.3125 per annum per share). The Company has paid all quarterly dividends to the holders of the Series A Preferred Stock since their issuance.

Redemption Provisions. The Series A Preferred Stock does not have any stated maturity date and will not be subject to any sinking fund or mandatory redemption provisions, except, under some circumstances upon a Change of Ownership or Control. Except pursuant to the special redemption upon a Change of Ownership or Control, we may not redeem the Series A Preferred Stock prior to June 30, 2012. On and after June 30, 2012, we may redeem the Series A Preferred Stock for cash at our option, in whole or from time to time in part, at a redemption price of $25.00 per share, plus accrued and unpaid dividends (whether or not earned or declared) to the redemption date Following a Change of Ownership or Control of us by a person or entity, other than by a “Qualifying Public Company,” we will be required to redeem the Series A Preferred Stock within 90 days after the date on which the Change of Ownership or Control occurred for cash, at the following price per share, plus accrued and unpaid dividends.


Redemption Date on or Before	Redemption Price
June 30, 2010	$	25.50
June 30, 2011	$	25.25
June 30, 2012 or thereafter	$	25.00

Liquidation Preference. In the event of a liquidation, the holders of the Series A Preferred Stock will have the right to receive $25.00 per share, plus all accrued and unpaid dividends, before any payments are made to the holders of our common stock.

Voting Rights. Holders of the Series A Preferred Stock will generally have no voting rights. However, if cash dividends on any outstanding Series A Preferred Stock are in arrears for any six consecutive or non-consecutive quarterly dividend periods, or if we fail to maintain a national market listing, the holders of the Series A Preferred Stock, voting separately as a class, will have the right to elect two directors to serve on our board of directors in addition to those directors then serving on our board until such time as the national market listing is obtained or the dividend arrearage is eliminated.

ITEM 6. SELECTED FINANCIAL DATA

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


	Year Ended December 31,
	2009			2008			2007			2006			2005
	(In thousands, except per share and volume data)

Statement of Operations Information
Total operating revenues	$	44,791		$	49,578		$	17,197		$	19,032		$	20,496
Income (loss) from operations (1)	$	3,884		$	15,949		$	(17,909	)	$	3,695		$	5,985
Net income (loss)	$	1,209		$	10,381		$	(11,603	)	$	2,109		$	3,965
Net income (loss) attributable to common stock	$	(2,514	)	$	6,658		$	(13,413	)	$	2,109		$	3,965
Net income (loss) per common share:
Basic	$	(0.25	)	$	0.73		$	(1.47	)	$	0.24		$	0.46
Diluted	$	(0.25	)	$	0.73		$	(1.47	)	$	0.24		$	0.46

Balance Sheet Information
Total assets	$	150,494		$	171,989		$	84,597		$	64,406		$	44,211
Line of credit	$	34,000		$	24,639		$	3,445		$	13,221		$	3,000
Total long-term liabilities	$	44,684		$	33,011		$	5,895		$	17,184		$	5,732
Stockholders’ equity and preferred stock	$	84,696		$	92,875		$	66,596		$	33,042		$	29,778

Cash Flow Information
Net cash provided by (used in):
Operating activities	$	22,062		$	22,904		$	5,166		$	10,951		$	10,319
Investing activities	$	(21,461	)	$	(40,778	)	$	(42,056	)	$	(22,241	)	$	(16,259	)
Financing activities	$	5,081		$	17,749		$	36,404		$	10,470		$	3,701

Total proved reserves (2)
Oil (MBbl)		419			420			413			360			329
Gas (MMcf)		89,777			86,331			71,254			48,497			47,234
MMcfe		92,292			88,852			73,731			50,657			49,207

Net production volumes
Oil (Bbl)		28,927			25,668			13,963			12,729			15,470
Gas (Mcf)		9,162,362			6,559,662			2,928,335			3,140,653			2,976,094
Mcfe		9,335,924			6,713,670			3,012,113			3,217,027			3,068,914


(1)		Effective January 1, 2006, Double Eagle adopted the provisions of ASC 718 — Stock Compensation.

(2)		Effective December 31, 2009, Double Eagle adopted the SEC’s new oil and gas reserve reporting guidelines.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Amounts in thousands of dollars, except share, per share data, and amounts per unit of production)

The following discussion includes forward-looking statements. Such statements are described in the section entitled “Forward-Looking Statements” on page 18 of this Form 10-K.

BUSINESS OVERVIEW

We are an independent energy company engaged in the exploration, development, production and sale of natural gas and crude oil, primarily in Rocky Mountain Basins of the western United States. Our core properties are located in southwestern Wyoming. We have coal bed methane reserves and production in the Atlantic Rim Area of the Eastern Washakie Basin and tight gas reserves and production in the Pinedale Anticline. We do not have any active exploration projects at this time.

As of December 31, 2009, we had estimated proved reserves of 89.8 Bcf of natural gas and 419 MBbl of oil, or a total of 92.3 Bcfe, with a PV-10 value of approximately $91.1 million (see reconciliation of the PV-10 non-GAAP financial measure to the standardized measure under the heading Reserves on page 10). Our reserves as of December 31, 2009, were estimated using the Securities Exchange Commission’s (“SEC”) new oil and gas reporting guidelines. The new SEC standards require that the Company calculate the quantity and PV-10 value of oil and gas reserves that are economically producible using a simple 12-month average price, using the first-day-of-the-month applicable commodity price within the 12-month period prior to the reporting period end. For the December 31, 2008 and prior reserve reports, pricing was based upon the price on the last day of the fiscal year. Historically, natural gas prices are higher during the winter months due to cold weather and increased demand. As natural gas comprises 97% of our total reserves, this change in pricing methodology had a significant negative impact on the pricing used in determining our reserves. Using this change in price determination, the gas price used in calculating the December 31, 2009 reserves was decreased by $1.57, or 34%, per MMBtu from the December 31, 2008 price of $4.61 MMBtu. The decrease in price shortened the economic life of certain existing wells and negatively impacted our year-end reserve estimate. The price on the last day of the 2009 fiscal year was $5.54 per MMBtu and $76.00 per barrel of oil, which is the price that would have been used to calculate year-end reserves under the methods used in 2008 and prior years. The use of these prices would have resulted in an increase in reserves of 21.9 Bcfe. The new oil and gas rules did allow us to realize a modest increase in our proved undeveloped reserves due to a change in the SEC rules that allows for more than a one well offset from proved reserves in well-defined fields.

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

Developments since December 31, 2008:

The Company’s focus in 2009 was strengthening the Company’s financial position, while continuing to achieve production and reserve growth at our operated and non-operated properties in the Atlantic Rim and our continued participation in the development of the Pinedale Anticline.

Our oil and gas development program was focused within our core areas in 2009, including the following:

	•		At our Company-operated Catalina Unit, located within the Atlantic Rim, we completed and began producing 15 wells that were drilled as part of the 2008 drilling program. We also began a well workover and production enhancement program in the third quarter of 2009. This program targeted certain existing wells, which had experienced production declines over the past year. The Company is still in process of assessing the results of the workover program.

	•		At the Sun Dog Unit, in which the Company currently has a 8.89% working interest, approximately 17 wells were completed and brought on-line for production during 2009. The operator also performed well workovers on approximately 11 existing wells, including fracture stimulation, which had not previously been performed on Sun Dog wells. We have not yet realized a benefit from the well workovers, as we are awaiting additional water injection capacity within this unit

	•		In the Mesa “B” Unit at the Pinedale Anticline, 17 new wells were brought on-line during the second, third and fourth quarters of 2009. We are also currently participating in the drilling of 16 additional wells. These wells were spud in the fall of 2009, and are expected to be completed in 2010 at a rate of eight wells in May, four wells in July, and four wells in August. We expect the operator will spud 12-16 additional wells in the second half of 2010.

Effective February 5, 2010, the Company renegotiated its $75 million credit facility, to extend the maturity date from July 31, 2010 to January 31, 2013. The credit line on the facility will remain at $45 million, collateralized by our oil and gas properties. There were no material changes to any other terms of the credit facility, including our financial and non-financial covenants. The Company paid approximately $450 in one-time financing fees and related expenses in renegotiating this new facility.

Our Industry:

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

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

	•		We attempt to reduce our overall exposure to commodity price fluctuations through the use of various hedging instruments for some of our production. The duration of our various hedging instruments depends on our view of market conditions, available contract prices and our operating strategy. Use of such hedging instruments may limit the risk of fluctuating cash flows. As of December 31, 2009, we had derivative instruments in place for approximately 77% of our current daily net production.

	•		We have an inventory of attractive drilling locations, allowing us to grow reserves and replace and expand production organically without having to rely solely on acquisitions. Drilling opportunities in both the Atlantic Rim and the Pinedale Anticline are expected to last for several years.

Development Outlook for 2010:

We expect to expend $15-$20 million of capital for development programs in 2010. The drilling activity provided for in the 2010 capital budget is primarily allocated to the projects below.

Atlantic Rim. We intend to drill up to eight delineation wells within the Catalina field during 2010, to further enhance our understanding of the Washakie Basin and determine the future development path of this field. In accordance with our unit operating agreement, these wells will not immediately become part of the Catalina Unit. Rather, they will be added to the Unit when further drilling physically connects each well to the Unit. As such, our working interest in each of these wells will be based on the acreage ownership, and will vary. We also plan to participate in the drilling of approximately 10 wells within the Sun Dog and Doty Mountain Units.

Pinedale Anticline. At the Pinedale Anticline, the operator is in process of drilling 16 wells, which are expected to come on-line at a rate of eight wells in May, four in July, and four in August. We believe the operator will spud 12-16 additional wells in the second half of 2010.

We believe that we have the necessary capital, personnel and available drilling equipment to successfully execute this development program.

RESULTS OF OPERATIONS

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


	As of and for the year ended December 31,									Percent change between years
	2009			2008			2007			2008 to 2009			2007 to 2008
Total proved reserves
Oil (MBbl)		419			420			413			0	%		2	%
Gas (MMcf)		89,777			86,331			71,254			4	%		21	%
MMcfe		92,292			88,852			73,731			4	%		21	%

Net production volumes
Oil (Bbl)		28,927			25,668			13,963			13	%		84	%
Gas (Mcf)		9,162,362			6,559,662			2,928,335			40	%		124	%
Mcfe		9,335,924			6,713,670			3,012,113			39	%		123	%

Average daily produciton
Mcfe		25,578			18,343			8,252			39	%		122	%

Average price per unit production
Oil (Bbl)	$	51.65		$	77.24		$	63.17			-33	%		22	%
Gas (Mcf)	$	4.85		$	6.08		$	5.18			-20	%		17	%
Mcfe	$	4.92		$	6.23		$	5.33			-21	%		17	%

Oil and gas production revenues
Oil revenues	$	1,494		$	1,983		$	882			-25	%		125	%
Gas revenues		40,904			37,166			15,162			10	%		145	%

Total	$	42,398		$	39,149		$	16,044			8	%		144	%


Oil and gas production costs
Production costs	$	7,754		$	7,007		$	5,696			11	%		23	%
Production taxes		3,652			4,701			1,933			-22	%		143	%

Total	$	11,406		$	11,708		$	7,629			-3	%		53	%


Data on a per Mcfe basis
Average price (1)	$	4.92		$	6.23		$	5.33			-21	%		17	%

Production costs (2)		0.83			1.04			1.89			-20	%		-45	%
Production taxes		0.39			0.70			0.64			-44	%		9	%
Depletion and amortization		1.94			1.65			1.51			18	%		9	%

Total operating costs		3.16			3.39			4.04			-7	%		-16	%

Gross margin	$	1.76		$	2.84			1.29			-38	%		120	%

Gross margin percentage		36	%		46	%		24	%		-22	%		92	%


(1)		Our average gas price per Mcfe realized for the years ended December 31, 2009, 2008 and 2007 is calculated by summing a) production revenue received from third parties for sale of our gas, included in the oil and gas sales line item on the Consolidated Statement of Operations, b) settlement of our cash flow hedges included within oil and gas sales on the Consolidated Statement of Operations and c) realized gain/loss on our financial hedges, which due to accounting rules is included in our price risk management activities line on the Consolidated Statement of Operations, totaling $3,503, $2,698, and $0, for the years ended December 31, 2009, 2008 and 2007, respectively. This amount is divided by the total Mcfe volume for the period.

(2)		Production costs, on a dollars per Mcfe basis, is calculated by dividing production costs, as stated on the consolidated statement of operations, by total production volumes during the period. This calculation excludes certain gathering costs incurred by the Company’s subsidiary, Eastern Washakie Midstream, which are eliminated in consolidation.

Year ended December 31, 2009 compared to the year ended December 31, 2008

Oil and gas sales volume and price comparisons

During the year ended December 31, 2009, total net production increased 39% to 9,336 MMcfe as compared to the year ended December 31, 2008. The increase in production volumes was due largely to the addition of wells at our operated Catalina Unit and non-operated well additions in the Atlantic Rim and Pinedale Anticline, offset somewhat by the decrease of our working interest at the Catalina Unit due to unitization.

Unitization is a type of sharing arrangement by which owners of operating and non-operating working interests pool their property interests in a producing area to form a single operating unit. Units are designed to improve efficiency and economics of developing and producing an area. The share that each interest owner receives is based upon the respective acreage contributed by each owner in the participating area (“PA”) as a percentage of the entire acreage of the PA. Prior to December 21, 2007, we owned 100% of the working interest in the Cow Creek Unit. With the formation of the Catalina Unit and expansion of the PA, which included the 14 wells in the original Cow Creek Unit, as well as the 33 wells from the 2007 drilling program, our working interest decreased to 73.84% in the Catalina Unit. In October, 2008, our working interest adjusted again from 73.84% to 69.31% upon reaching certain contractual thresholds in our 2008 drilling program. This PA, and our associated working interest will continue to change as more wells and acreage are added to the PA.

During the year-ended December 31, 2009, average daily net production at the Atlantic Rim increased 50% to 18,294 Mcfe, as compared to 12,221 Mcfe in 2008, largely resulting from the addition of 20 new wells at the Catalina Unit, which were drilled as part of our 2008 drilling program. Five of the twenty-three wells were brought on-line for production during December 2008, with 15 of the remaining 18 wells coming on during 2009. Average daily net production for the year ended December 31, 2009 at the Catalina Unit increased 48% to 16,154 Mcfe, as compared to 10,881 Mcfe during the same prior-year period. Our working interest in the Catalina Unit decreased by approximately 4.5% during the fourth quarter of 2008, which somewhat offset the increase in production from the new wells, as discussed above. Average daily net production, net to our interest, at the Doty Mountain and Sun Dog Units increased 60% to 2,140 Mcfe, as compared to 1,340 Mcfe during the same prior-year period. The increase was due primarily to the addition of approximately 35 wells from the 2008 drilling program at the Sun Dog and Doty Mountain units. There also has been an increase in production from certain existing Doty Mountain wells that were fracture stimulated in late 2008. Our working interest at the Sun Dog Unit also increased from approximately 4.5% in mid-2008 to 8.89% at the end of 2009 due to unit expansion. The operator of the Sun Dog and Doty Mountain units has indicated that it intends to drill 10 wells in 2010, including at least one injection well. The additional injection capacity is expected to lead to increased production at the Sun Dog Unit. In addition, the operator put additional compression into place at the Doty Mountain Unit in the first quarter of 2010, which is expected to increase production.

Average daily net production in the Pinedale Anticline increased 26% for the year ended December 31, 2008, to 5,648 Mcfe, as compared to 4,467 Mcfe in the prior year. The increase was the result of the addition of 17 new wells in the Mesa “B” Unit during the second, third and fourth quarters of 2009. Although there has been an increase in production due to the new wells in the Mesa Unit, the operator has indicated that it has kept production volumes in this field relatively fixed due to the low gas prices in the Rocky Mountain region. This is consistent with management’s expectations and knowledge of the wells within this unit and therefore we do not believe we have realized the full benefit of having these new wells on-line for production. The operator is in process of drilling 16 wells, which are expected to come on at a rate of rate of eight wells in May, four wells in July, and four wells in August 2010.

During the year ended December 31, 2009, average daily net production at the Madden Unit increased to 484 Mcfe as compared to 407 Mcfe in the prior year. The sour gas plant experienced significant operational issues during the first half of 2008, which limited the output of natural gas. The sour gas plant was fully operational during 2009.

During the year ended December 31, 2009, oil and gas sales increased 8% to $42,398, as compared to the year ended December 31, 2008. This increase in oil and gas sales was driven by the overall production volume growth discussed above. The production growth however, was significantly offset by the decrease in our average gas price realized. During 2009, our average gas price realized decreased 20% to $4.85 from $6.08, as compared to a decrease of 64% in the average CIG index price. Our price did not increase consistent with the CIG index prices due to the fixed price contracts and economic hedges we had in place throughout 2009.

Transportation and gathering revenue

Transportation and gathering revenue increased 29%, to $6,179 for the year ended December 31, 2009, as compared to $4,788 during the prior year. The Company receives a fee for gathering and transporting third-party gas through our intrastate gas pipeline, which connects the Catalina Unit with the interstate pipeline system owned by Southern Star Central Gas Pipeline, Inc. The growth in revenue is due to an increase in the fee charged to third parties in July 2008, and higher production volumes at the Catalina Unit. With additional compression, the pipeline is expected to have approximately 125 MMcf per day capacity, which is expected to be sufficient to handle the development of the Catalina Unit and also additional third party gas from other non-operated properties in the Atlantic Rim proximity.

Price risk management

We recorded a net loss on our derivative contracts of $(4,295) for the year ended December 31, 2009, as compared to a net gain of $5,329 for the year ended December 31, 2008. The net loss consisted of an unrealized non-cash loss of $(7,798), which represents the change in the fair value on our economic hedges at December 31, 2009, based on the future expected prices of the related commodities, and a net realized gain of $3,503 related to the cash settlement of some of our economic hedges.

Oil and gas production expenses, production taxes, and depreciation, depletion and amortization

During the year ended December 31, 2009, well production costs increased 11% to $7,754, as compared to $7,007 during the prior year, and production costs in dollars per Mcfe decreased 20%, or $0.21, to $0.83, as compared to the same prior- year period. The increase in production costs is attributable to higher lease operating expenses, primarily at the Sun Dog Unit due to our increase in our working interest percentage, at the Mesa Unit as a result of an increase in the number of operated wells, and at the Madden Unit due to maintenance costs at the lost cabin gas plant. Offsetting these increases, was a decrease in well workover costs. The decrease in production costs on a per Mcfe basis, is largely attributable to excellent cost control and operating efficiencies gained from the increased production at the Company-operated Catalina Unit.

Production taxes for the year ended December 31, 2009 decreased 22% to $3,652, as compared to $4,701 during 2008, and production taxes, on a dollars per Mcfe basis, decreased 44%, or $0.31 to $0.39, as compared to the same prior-year period. The Company pays taxes on the proceeds received upon the sale of our gas to counterparties. In periods of low market prices, a larger portion of our revenue is related to cash received from the settlement of financial derivative instruments we have in place, rather than the cash received for the physical sale of our gas in the open market. This results in an overall reduction in production taxes, as well as a reduction of production taxes expressed on a dollars per Mcfe basis.

During the year ended December 31, 2009, total depreciation, depletion and amortization expenses (“DD&A”) increased 62% to $18,562, as compared to $11,473 in the prior year, and depletion and amortization related to producing assets increased 64% to $18,136, as compared to $11,078 in the prior year. The increase is due primarily to the higher capital balances at the Catalina, Sun Dog, Doty Mountain and Mesa units. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 18%, or $0.29, to $1.94, as compared to the prior year.

Pipeline operating costs

Pipeline operating costs increased 16% to $3,701 for the year ended December 31, 2009, as compared to the prior year. The increase is largely attributable to higher compressor rental costs of $844, due to expansion of the Catalina Unit and the Company’s strategic change in the fourth quarter of 2008 to leasing compressor equipment rather than compressor ownership.

General and administrative

General and administrative expenses increased 20% to $6,718 as compared to $5,604 in the prior year. The increase was due largely to $513 of transaction costs related to the acquisition of Petrosearch in the third quarter, higher non-cash stock-based compensation expense of $260 due to additional grants to employees, additional salary and salary-related expenses due primarily to headcount additions throughout 2008 of $270, higher legal fees of $140, and higher audit and tax fees of $100. These increases were offset by lower board of directors compensation costs of $161 and lower software fees of $133 primarily related to our 2008 accounting system implementation.

Income taxes

During the year ended December 31, 2009, we recorded income tax expense of $902, as compared to income tax expense of $5,343 during the prior year. Our income tax expense reflects an effective book rate of 42.7% in 2009. The higher than expected effective book rate reflects the tax effect of the permanent difference caused by acquisition costs related to the Petrosearch acquisition and stock option expense in 2009. We expect to continue to generate losses for federal income tax reporting purposes, and anticipate net income from operations in future years, which has resulted in a deferred tax position reported under U.S. generally accepted accounting principles. We do not anticipate any required payments for current tax liabilities in the near future. We have a net operating loss carry-forward (“NOL’s”) of $32.8 million at December 31, 2009. The Company has evaluated the need to provide a valuation allowance on the amount recorded as the net operating loss carry-forward, and management has concluded that no valuation allowance is required as of December 31, 2009. In reaching this conclusion, management considered that the Company expects to generate income in excess of our NOL’s by continuing to develop our core assets. In addition, the Company routinely considers the sale of non-core assets, which is likely to generate a tax gain, as the tax cost per Mcfe of our assets is generally lower than the current market rates being paid in the open market for gas producing properties. Our current NOL’s do not begin to expire for 11 years

Year ended December 31, 2008 compared to the year ended December 31, 2007

Oil and gas sales volume and price comparisons

During the year ended December 31, 2008, total net production increased 123% to 6,714 MMcfe as compared to the year ended December 31, 2007. The increase in production volumes was due largely to the addition of wells at our operated Catalina Unit and non-operated well additions in the Atlantic Rim and Pinedale Anticline, offset somewhat by the decrease of our working interest at the Catalina Unit due to unitization.

During the year-ended December 31, 2008, average daily net production at the Atlantic Rim increased 161% to 12,221 Mcfe, as compared to 4,678 Mcfe in 2007, largely resulting from the addition of 33 new wells at the Catalina Unit, which were drilled in 2007. Average daily net production for the year ended December 31, 2008 at the Catalina Unit increased 167% to 10,881 Mcfe, as compared to 4,068 Mcfe during the same prior-year period. These wells were partially brought on-line during the fourth quarter of 2007, with the remaining wells coming on during the first six months of 2008. Additionally, we drilled 24 potential producing wells during 2008, of which five were completed and producing at December 31, 2008. The increase in production at the Catalina Unit was offset by a decrease in our working interest at Catalina. Prior to December 21, 2007, we owned 100% of the working interest in the Cow Creek Unit. With the formation of the Catalina Unit and expansion of the PA, our working interest decreased to 73.84% in the Catalina Unit. In October, 2008, our working interest adjusted again from 73.84% to 68.35% upon reaching certain contractual thresholds in our 2008 drilling program. Average daily net production, net to our interest, at the Doty Mountain and Sun Dog Units increased 120% to 1,340 Mcfe, as compared to 610 Mcfe during the same prior-year period. The increase was due primarily to the addition of 64 wells from the Sun Dog Unit’s 2007 drilling program.

Average daily net production in the Pinedale Anticline increased 106% for the year ended December 31, 2008, to 4,467 Mcfe, as compared to 2,166 Mcfe in the prior year. The increase was the result of the addition of 22 new wells in the Mesa “B” Unit during the second and third quarters of 2008. This increase was offset slightly by the natural production decline typical of wells in the Mesa Unit. We are also participating in the drilling of 20 additional wells at the Pinedale Anticline. These wells were spud in the fall of 2008, and are expected to be completed in 2009.

During the year ended December 31, 2008, average daily net production at the Madden Unit decreased to 407 Mcfe as compared to 502 Mcfe in the prior year. The decrease in production was largely due to operational difficulties at the sour gas plant in the first half of 2008.

During the year ended December 31, 2008, oil and gas sales increased 144% to $39,149, as compared to the year ended December 31, 2007. This increase in oil and gas sales was driven by both the volume increase discussed above, as well as an increase in our average gas price realized. During 2008, our average gas price realized increased 17% to $6.23 from $5.33, as compared to an increase of 61% in the average CIG index price. Our price did not increase consistent with the CIG index prices due to the fixed price contracts and economic hedges we had in place throughout 2008.

Transportation and gathering revenue

Transportation and gathering revenue increased 426%, to $4,788 for the year ended December 31, 2008, as compared to $910 during the prior year. The growth in revenue is due to an increase in the fee charged to third parties and higher production volumes at the Catalina Unit.

Price risk management

We recorded a net gain on our derivative contracts of $5,329 for the year ended December 31, 2008. This amount consists of an unrealized gain of $2,631, which represents the change in the fair value on our economic hedges at December 31, 2008, based on the future expected prices of the related commodities, and a net realized gain of $2,698 related to the settlement of some of our economic hedges. We had no derivative instruments accounted for under mark-to-market accounting at December 31, 2007.

Oil and gas production expenses, depreciation, depletion and amortization

During the year ended December 31, 2008, well production costs increased 23% to $7,007, as compared to $5,696 during the prior year, and production costs in dollars per Mcfe decreased 45%, or $0.85, to $1.04, as compared to the same prior- year period. The increase in production costs is due primarily to a $1,235 million increase in the lease operating expenses at the Catalina Unit, as 33 new wells were brought on-line during the fourth quarter of 2007 and the first six months of 2008. We also brought five additional wells on-line in December 2008. In addition, transportation costs increased by $585 at the Sun Dog and Doty Mountain Units. Offsetting these increases, was a decrease in well workover costs. The decrease in production costs on a per Mcfe basis, is largely attributed to operating efficiencies gained from the increased production at the Company-operated Catalina Unit and lower well workover costs, partially offset by increased transportation costs at our non-operated Sun Dog and Doty Mountain units.

During the year ended December 31, 2008, total depreciation, depletion and amortization expenses (“DD&A”) increased 126% to $11,473, as compared to $5,068 in the prior year, and depletion and amortization related to producing assets increased 143% to $11,078, as compared to $4,550 in the prior year. The increase is due primarily to increased capital expenditures at the Catalina, Sun Dog, and Mesa units, increased production levels, and a decrease in the reserve estimates at the Doty Mountain Unit used in the calculation of DD&A. This increase was partially offset by an increase in the reserve estimates used in the calculation of DD&A at the Catalina and Mesa units, which caused a decrease in the expense recognized during the period. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 9%, or $0.14, to $1.65, as compared to the prior year.

Pipeline operating costs

Pipeline operating costs totaled $3,190 for the year ended December 31, 2008, which represented an increase over 2007 of 395%. The increase is due to the expansion of the Catalina Unit and related transportation assets, and compressor rental costs.

Dry hole and impairment

Dry hole and impairment expense decreased to $1,654 for the year ended December 31, 2008, as compared to $17,631 for the year ended December 31, 2007. The 2008 expense primarily relates to a $741 write-off of our Nevada leases, as the Company has determined that it will not develop the Nevada properties in the future, and will does not plan to renew the leases. We also made rental payments of $340 on other undeveloped leaseholds. In 2007, the Company wrote off the following exploratory costs that did not meet the requirements for continued capitalization; Cow Creek Unit Deep #2 ($4,395), the PH State 16-1 ($2,759), Table Top Unit #1 ($5,773) and the Straight Flush 17-1 ($1,983).

General and administrative

General and administrative expenses increased 36% to $5,604 as compared to $4,133 in the prior year. The increase was due largely to higher non-cash stock-based compensation expense of $688 due to additional grants to employees, higher Board of Director related costs of $241, additional costs related to the implementation of our new accounting software of $174, additional salary and salary-related expenses due primarily to headcount additions of $289, and $61 related to the two reserve studies performed in 2008. These increases were offset partially by a $174 decrease in audit and tax related fees.

Income taxes

During the year ended December 31, 2008, we recorded an income tax expense of $5,343, as compared to an income tax benefit of $6,143 during the prior year. Our income tax expense reflects an effective book rate of 34.0% in 2008. The lower than expected effective book rate reflects the tax effect of the permanent difference caused by the stock option expense in 2008. We had NOL’s of $30.3 million at December 31, 2008.

LIQUIDITY AND CAPITAL RESOURCES

Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our financing facilities and proceeds from offerings of equity securities. The primary uses of our liquidity and capital resources have been in the development and exploration of oil and gas properties. In the past, the sources of liquidity and capital have been sufficient to meet our needs and finance the growth of our business. We believe that the liquidity available from these sources will meet the anticipated short and long-term requirements of the Company. We can give no assurances that these historical sources of liquidity and capital resources will be available for future development projects, and we may be required to seek additional or alternative financing sources.

Our Credit Facility at December 31, 2009

At December 31, 2009, the Company had a $75 million credit facility in place, with $45 million available for borrowing, based upon several factors, including the Company’s borrowing base and the commitment amounts from participating banks. The credit facility is collateralized by the oil and gas producing properties and other assets of the Company. As of December 31, 2009, the interest rate on the line of credit, calculated in accordance with the agreement was 4.5%. At December 31, 2009, the Company had $34 million outstanding on the facility, which was used primarily to fund the 2008 drilling program at the Catalina, Sun Dog and Doty Mountain units, and the 2008 and 2009 drilling programs at the Mesa Units.

Effective February 5, 2010, the Company entered into an amended and restated credit agreement, which extended the maturity of the original agreement from July 31, 2010 to January 31, 2013, and we have accordingly classified our credit facility as a long-term liability at December 31, 2009. If we had been unable to modify our credit agreement and extend the maturity date, the lenders would have had the right to request payment of all outstanding balance at July 31, 2010.

We are subject to certain financial and non-financial covenants with respect to the above credit facility, including requirements to maintain (i) a current ratio, as defined, of at least 1.0 to 1.0, (ii) a ratio of earnings before interest, taxes, depreciation, depletion, amortization, exploration and other non-cash items (“EBITDAX”) to interest plus dividends, of 1.5 to 1.0 and (iii) a funded debt to EBITAX ratio of less than 3.5 to 1.0. As of December 31, 2009, we were in compliance with all covenants under the facility. If any of the covenants are violated, and the Company is unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.

Our borrowing base is subject to redetermination each June 15 and December 15, beginning June 15, 2010. We currently have a borrowing base in excess of our current borrowing availability.

We believe that the amounts available under the amended and restated credit facility, combined with our net cash from operating activities, will provide us with sufficient funds to meet future financial covenants, develop new reserves, maintain our current facilities, and complete our 2010 capital expenditure program. Depending on the timing and amounts of future projects, we may be required to seek additional sources of capital. While we believe that we would be able to secure additional capital through financing or equity offerings, if required, we can provide no assurance that we will be able to do so or as to the terms of any additional capital. Our borrowing base is determined based on the financial institutions assessment of current and future commodity prices, primarily natural gas available to the Company. An assessment of available borrowing base is done semi-annually. Should natural gas commodity prices significantly decrease for extended periods of time, the Company’s borrowing base could be reduced, thus limiting the future amounts of funds under the current facility.

Capital Expenditures

Our primary capital expenditures by type for the years ended December 31, 2009 and 2008 were:


	Year Ended December 31,
	2009		2008
Property acquisition costs	$	16	$	30
Exploration		59		536
Development		21,042		64,462

	$	21,117	$	65,028

Year Ended December 31, 2009

Our projects in 2009 focused our resources to the enhancement and production maximization of our core projects in the Atlantic Rim and the participation in development drilling on the Pinedale Anticline. The total capital costs incurred at the Catalina Unit in 2009 was $1,870, net to our working interest. In 2009, we completed 15 of 18 remaining wells from the 2008 drilling program at the Catalina Unit. Three of the wells drilled in 2008 were not connected to the sales line as of December 31, 2009.

Capital expenditures recorded for the Sun Dog and Doty Mountain Units in 2009 totaled $4,031, net to our interest. In 2009, we participated in the continuation and completion of the 2008 drilling program at the Sun Dog and Doty Mountain Units, as well as well workovers, including fracture stimulation, on 11 wells at the Sun Dog Unit. Approximately 17 Sun Dog wells were completed and came on-line for production in 2009. Eleven wells at the Doty Mountain Unit were still awaiting completion at December 31, 2009.

We also incurred capital costs of $13,373, net to our interest, related to the Pinedale Anticline development, as we participated in the drilling and completion of 17 new wells in the Mesa Units in the Pinedale Anticline. We also participated in the drilling of 16 additional wells in the second half of 2009, which are expected to be completed in the second and third quarters of 2010.

In July 2009, the company incurred capital costs, net to our interest, of $919 to complete and hook-up the Waltman 24-24 well. This well began producing in August 2009.

There was no significant exploration or property acquisition activity in 2009.

Year Ended December 31, 2008

Our development projects in 2008 focused our core projects in the Atlantic Rim and the Pinedale Anticline, as well as developmental drilling in the South Waltman acreage. The total cost of development at the Catalina Unit in 2008 was $44,048, net to our working interest. In 2008, we completed 27 of the 33 wells in the Catalina Unit that were not completed at December 31, 2007. In addition, we drilled an additional 24 potential producing wells and six injections wells, and installed partial infrastructure for 24 additional well sites that we expect to drill in future years. Of the 24 potential producing wells drilled in 2008, five were producing as of December 31, 2008. One of the 24 potential producing wells was determined to be a developmental dry hole.

Capital expenditures recorded at the Sun Dog and Doty Mountain Units in 2008 totaled $4,106, net to our interest. In 2008, we participated in the continuation of the 2007 drilling program in the Sun Dog Unit, and the 2008 drilling program at the Sun Dog and Doty Mountain Units. Sixty-four wells drilled during 2007 were completed in 2008 in the Sun Dog Unit, and the operator drilled an additional 63 producing wells in the units in the third and fourth quarters of 2008.

We also incurred capital costs of $13,007, net to our interest, related to the Pinedale Anticline development, as we participated in the continuation of the 2007 drilling program in the Mesa Units in the Pinedale Anticline. In 2008, the operator completed 18 wells in the Mesa “B” Unit that were spud in 2007, and drilled and completed an additional four wells in second and third quarters of 2008.

In 2008, we continued the drilling of the Waltman 34-24 in the Wind River basin, which was spud in December 2007. In August 2008, we also drilled the Waltman 24-24 well to a depth of 9,397 feet. We incurred capital costs of $2,352 related to the Waltman wells in 2008, net to our interest.

There was no significant exploration activity in 2008.

Calendar 2010

For 2010, we have budgeted approximately $15-$20 million for on-going non-operated development projects at the Pinedale Anticline and well production enhancement projects in the Atlantic Rim. We also currently plan to drill up to eight wells within in the Catalina Unit in 2010. The 2010 capital budget does not include the impact of potential future exploration projects or possible acquisitions. We continually evaluate our opportunities, and if a potential opportunity is identified that complements our identified areas of expertise, it may be pursued.

Cash Flows

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


	As of and for the Years Ended December 31,									Percent Change Between Years
	2009			2008			2007			2008 to 2009			2007 to 2008
Financial information
Working capital	$	(4,067	)	$	(6,314	)	$	(7,012	)		36	%		10	%
Balance oustanding on credit facility	$	34,000		$	24,639		$	3,445			38	%		615	%
Stockholders’ equity and preferred stock	$	84,696		$	92,875		$	66,596			-9	%		39	%
Net income (loss) attributable to common stock	$	(2,514	)	$	6,658		$	(13,413	)		-138	%		-150	%

Net income (loss) per common share:
Basic	$	(0.25	)	$	0.73		$	(1.47	)		-134	%		150	%
Diluted	$	(0.25	)	$	0.73		$	(1.47	)		-134	%		150	%

Net cash provided by operating activities	$	22,062		$	22,904		$	5,166			-4	%		343	%
Net cash used in investing activities	$	(21,461	)	$	(40,778	)	$	(42,056	)		-47	%		-3	%
Net cash provided by financing activities	$	5,081		$	17,749		$	36,404			-71	%		-51	%

Net cash provided by operating activities

Operating activities provided cash of $22,062 in 2009, $22,904 in 2008, and $5,166 in 2007. The primary sources of cash in 2009 were $1,209 of net income, which was net of non-cash charges of $18,693 related to DD&A and accretion expenses, a non-cash loss on derivative contracts of $7,798, and stock-based compensation expense of $1,484. In addition, we had a decrease of $13,884 in the accounts receivable balances related to operations. Our receivable balance was especially high at December 31, 2008 due to joint interest billing related to the 2008 Catalina drilling program. These increases were partially offset by the decrease in the accounts payable and accrued liabilities from operations of $18,998.

Product prices and volumes are expected to have a significant influence on our future net cash flow provided by operating activities. Oil and gas prices dropped sharply late in 2008 and remained low for much of 2009. During these periods, we rely heavily on cash received from our hedging program. We do have a portion of 2010 volumes hedged; however, if we again see a cratering in the market price of natural gas, it will become increasingly difficult to generate the same levels of cash flow that we saw in 2008 and 2009.

Net cash used in investing activities

During 2009 net cash used in investing activities totaled $21,461, as compared to $40,778 and 42,056 in 2008 and 2007, respectively. Our 2009 capital expenditures were primarily related to the completion of the 2008 drilling program at our operated properties in the Catalina Unit as well as our share of costs for non-operated development wells in the Pinedale Anticline. During the third quarter of 2009, we acquired Petrosearch in exchange for 1.8 million shares of Double Eagle common stock and cash consideration of $873. We assumed 100% of the assets and liabilities of Petrosearch, including cash and cash equivalents totaling $8,606. The net cash to the Company from this acquisition was $7,733. We also had cash outflows of $513 for transaction costs related to the acquisition. Refer to Note 3 in the Notes to the Consolidated Financial Statements for additional details regarding the Petrosearch acquisition.

Net cash used in financing activities

Cash provided by financing activities totaled $5,081 million in 2009 as compared to $17,749 in 2008 and $36,404 in 2007. The major financing inflow of cash in 2009 was from our credit facility, which was used to fund expenditures related to our 2008 and 2009 drilling program. This inflow of cash was partially offset by four quarterly Series A Preferred Stock dividend payments totaling $3,723.

Contractual Obligations

The impact that our contractual obligations as of December 31, 2009 are expected to have on our liquidity and cash flow in future periods is:


			One year		2 - 3		4 - 5		More than
	Total		or less		Years		Years		5 Years
Line of credit (a)	$	34,000	$	—	$	—	$	34,000	$	—
Interest on line of credit (b)		4,785		1,551		3,102		132		—
Capital leases		1,506		753		753		—		—
Operating leases		7,359		2,019		3,939		1,401		—

Total contractual cash commitments	$	47,650	$	4,323	$	7,794	$	35,533	$	—


(a)		The amount listed reflects the balance outstanding as of December 31, 2009. Effective February 5, 2010, we entered into a amended and restated credit agreement, which extended the maturity on our credit facility from July 31, 2010 to January 31, 2013. Any balance outstanding at January 31, 2013, is due at that time.

(b)		The interest rate assumed on the credit facility is 4.5% per annum, which is the rate in effect at December 31, 2009.

Off-Balance Sheet Arrangements

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

From time to time, we enter into contracts that might be construed as off-balance sheet obligations but are normal in the day-to-day course of business in the oil and gas industry. Those contracts include the forward sales contracts discussed directly below under Contracted Volumes. We do not believe we will be affected by these contracts materially differently than other similar companies in the energy industry.

CONTRACTED VOLUMES

Derivative Instruments

market conditions, available contract prices and our operating strategy. Under our current credit agreement, we can hedge up to 90% of the projected proved developed producing reserves for the next 12 month period, and up to 80% of the projected proved producing reserves for the ensuing 24 month period. As of December 31, 2009, we had derivative instruments in place for 77% of our daily net production.

Our outstanding derivative instruments as of December 31, 2009 are summarized below (volume and daily production are expressed in Mcf):

Remaining

Contractual

Daily

Price

Type of Contract

Volume

Production

Term

Price

Index (1)

Fixed Price Swap

4,380,000

12,000

1/10-12/10

$4.30

CIG

Costless Collar

2,885,000

5,000

8/09-7/11

$4.50 floor

NYMEX

$7.90 ceiling

Costless Collar

3,495,000

5,000

12/09-11/11

$4.50 floor

NYMEX

$9.00 ceiling

Fixed Price Swap

2,920,000

8,000

1/11-12/11

$7.07

CIG

Total

13,680,000


(1)		NYMEX refers to quoted prices on the New York Mercantile Exchange. CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month.

See Item 15, Note 6 to the Notes to the Consolidated Financial Statements for additional discussion of hedge accounting.

Other Volumes Contracted

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

CRITICAL ACCOUNTING ESTIMATES

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

Successful Efforts Method of Accounting

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

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

The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in hopes of finding an oil and gas field that will be the focus of future development drilling activity. The initial exploratory wells may be unsuccessful and will be expensed.

Reserve Estimates

Our estimates of oil and natural gas reserves, by necessity, are projections based on geological and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and natural gas prices, future operating costs, severance and excise taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and gas properties and/or the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. We engage independent reserve engineers to review a substantial portion of our reserves. In 2009, Netherland, Sewell & Associates, Inc. evaluated properties representing 99% of our reserves, valued at the total estimated future net cash flows before income taxes, discounted at 10% (“PV-10”).

Impairment of Long-Lived Assets

The Company reviews the carrying values of its long-lived assets periodically, or whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. The long-lived assets of the Company, which are subject to periodic evaluation, consist primarily of oil and gas properties and undeveloped leaseholds. The Company recorded non-cash impairment charges on properties included in Developed Properties of $0, $0, and $2,141, for the years ended December 31, 2009, 2008 and 2007, respectively. The Company wrote-off undeveloped leaseholds in the amount of $417, $743, and $91, for the years ended December 31, 2009. 2008, and 2007, respectively.

Asset Retirement Obligation

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

Derivative Instruments

We use derivative instruments to hedge exposures to oil and gas production cash-flow risks caused by fluctuating commodity prices. All derivatives are initially, and subsequently, measured at estimated fair value and recorded as liabilities or assets on the Consolidated Balance Sheet. Certain of our derivative instruments qualify for cash flow hedge accounting, under which the change in fair value is recorded as a component of accumulated other comprehensive income and is subsequently reclassified into earnings as the contract settles. For derivative contracts that do not qualify, or for which we do not elect cash flow hedge accounting, changes in the estimated fair value of the contracts are recorded as unrealized gains and losses in the price risk management activities line item in the accompanying Consolidated Statement of Operations.

The determination of which contracts meet the definition of a derivative as well as the fair value measurement of identified derivative instruments is subject to interpretation. We use our judgment to analyze which contracts meet the definition of a derivative instrument and to determine the fair value of each instrument identified.

Fair Value of Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at measurement date and establishes a three level hierarchy for measuring fair value. In determining the fair value of the Company’s derivative instruments, the Company considers quoted market prices in active markets and quotes from counterparties, the credit rating of each counterparty, and the Company’s own credit rating.

In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

Share-Based Compensation

We measure and recognize compensation expense for all share-based payment awards (including stock options and stock awards) made to employees and directors based on the estimated fair value. Compensation expense for equity-classified awards is measured at the grant date based on the fair value of the award and is recognized as an expense in earnings over the requisite service period using a graded vesting method. Total share-based compensation expense for equity-classified awards, was $1,484 during the year ended December 31 2009. As of December 31, 2009, total estimated unrecognized compensation expense from unvested stock options and stock grants was $2,654, which is expected to be recognized over a period of five years.

We use the Black-Scholes valuation model to determine the fair value of each stock option. Expected volatilities are based on the historical volatility of Double Eagle’s stock over a period consistent with that of the expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in Double Eagle’s stock price and historical exercise behavior. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms.

We measure the fair value of the stock awards based upon the fair market value of our common stock on the date of grant and recognize any resulting compensation expense ratably over the associated service period, which is generally the vesting term of the stock awards. We recognize these compensation costs net of a forfeiture rate, if applicable, and recognize the compensation costs for only those shares expected to vest. We typically estimate forfeiture rates based on historical experience, while also considering the duration of the vesting term of the option or stock award. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation expense could be different from what we have recorded in the current period.

Recently Adopted Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board (“FASB”) issued ASC 105, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (“ASC 105”). The Accounting Standards Codification (“ASC”) has become the source of authoritative U.S. GAAP recognized by the FASB to be applied by

nongovernment entities. It also modifies the GAAP hierarchy to include only two levels of GAAP; authoritative and non-authoritative. The Company adopted ASC 105 effective July 1, 2009. Pursuant to the provisions of ASC 105, the Company has updated references to GAAP in its financial statements issued for the year ended December 31, 2009. The adoption of ASC 105 did not have an impact on the Company’s financial position, results of operations or cash flows.

In September 2006, the ASC guidance for fair value measurements was updated to define fair value, establish a framework for measuring fair value, and expand disclosures related to fair value. The Company adopted the updated guidance for assets and liabilities measured at fair value on a recurring basis on January 1, 2008. In February 2008, the FASB issued an update to the guidance, which delayed the effective date for nonfinancial assets and liabilities, including asset retirement obligations, that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually). The Company adopted the updated guidance for nonfinancial assets and liabilities on January 1, 2009. In April 2009, the guidance was again updated to provide additional guidance on determining fair value when the volume and level of activity for the asset or liability have significantly decreased and identifying circumstances that indicate when a transaction is not orderly. The Company adopted this guidance April 1, 2009. In August 2009, the ASC provided further guidance related to the fair value of liabilities. This update provides clarification for circumstances in which: (i) a quoted price in an active market for the identical liability is not available, (ii) the liability has a restriction that prevents its transfer, and (iii) the identical liability is traded as an asset in an active market in which no adjustments to the quoted price of an asset are required. The Company adopted this update effective October 1, 2009. None of the aforementioned adoptions related to fair value had a material impact on its financial position, results of operations or cash flows.

In May 2009, the ASC guidance for subsequent events was updated to establish general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The Company adopted this guidance effective April 1, 2009. See Item 15, Note 10 for the Company’s disclosures about subsequent events.

In June 2008, the ASC guidance was updated to provide clarification as to whether instruments granted in share-based payment transactions are participating securities prior to vesting, and therefore, need to be included in computing earnings per share under the two-class method provided under ASC 260 — Earnings Per Share. The Company adopted this standard effective January 1, 2009. The adoption of this guidance did not have a material impact on the Company’s financial position, results of operations or cash flows.

In March 2008, the ASC guidance for derivatives and hedging instruments was updated for enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items (if any) are accounted for, and how they affect the Company’s financial position, financial performance and cash flows. The Company adopted the updated guidance effective January 1, 2009. See Item 15, Note 6 for the Company’s disclosures about its derivative instruments and hedging activities.

In November 2007, the ASC guidance for business combinations was updated to provide new guidance for recognizing and measuring the assets and goodwill acquired and liabilities assumed in an acquisition. The updated guidance also broadened the definition of a business combination and requires an entity to recognize transaction costs separately from the acquisition. The Company adopted the updated guidance effective January 1, 2009 and applied it to the acquisition of Petrosearch completed on August 6, 2009 (see Item 15, Note 3).

In January 2010, the ASC guidance for reporting oil and gas reserves was updated to align the oil and gas reserve estimation and disclosure requirements with the requirements in the SEC’s final rule, Modernization of the Oil and Gas Reporting Requirements. The new guidance expands the definition of reserves, which allows consideration of new technologies. In addition, oil and gas reserves are reported using an average, first-day-of-the-month price based on the prior 12-month period, rather than year-end prices. The new rule is effective for annual reporting periods ending on or after December 31, 2009. The Company adopted these provisions effective December 31, 2009. The application of the new rules increased our DD&A expense for the fourth quarter by approximately $147, and decreased our net income attributable to common shareholders by $84, or $.01 per diluted share. Refer to Item 15, Note 11 for the Company’s disclosures about its oil and gas reserves.

New Accounting Pronouncements

In January 2010, the FASB issued ASC Update No. 2010-06, an additional update to the ASC guidance for fair value measurements. The new guidance requires additional disclosures about (1) the different classes of assets and liabilities

measured at fair value, (2) the valuation techniques and inputs used, (3) the activity in Level 3 fair value measurements, and (4) the transfers between Levels 1, 2, and 3. The updated guidance is effective for annual and interim periods beginning December 15, 2009, except for the disclosures about the activity in Level 3 fair value measurements, for which the new guidance is effective for fiscal years beginning after December 15, 2010. The adoption of ASC Update 2010-06 is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.

7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risks

At December 31, 2009 we had $34,000 outstanding on our existing credit agreement. Effective February 5, 2010, the Company entered into an amended and restated credit agreement with various lenders, which extended the maturity date on the existing agreement from July 31, 2010, to January 31, 2013. The amended and restated agreement reconfirmed the committed credit line of $45 million. We pay interest on outstanding borrowings under credit facility at interest rates that fluctuate based upon changes in the prime lending rate. As the interest rate is variable and reflective of current market conditions, the carrying value approximates the fair value. Assuming no change in the amount outstanding at December 31, 2009, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $340 before taxes. As of December 31, 2009, the interest rate on the line of credit, calculated in accordance with the agreement was 4.5%.

Commodity Price Risks

Our major market risk exposure is in the pricing applicable to our natural gas and oil production. Pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for oil production and natural gas has been volatile and unpredictable for several years. The prices we receive for production depend on many factors, many of which are outside of our control. For the year ended December 31, 2009, our income before income taxes would have changed by $1,591 for each $0.50 change per Mcf in natural gas prices and $25 for each $1.00 change per Bbl in crude oil prices.

Risk Policy and Control

We control the extent of our risk management activities through policies and procedures that involve senior management and were approved by the Company’s Board of Directors. Senior management is responsible for proposing equity hedge recommendations, execution of the approved hedging plan, oversight of the risk management process including methodologies used for valuation and risk measurement and presenting policy changes to the Board. The Company’s Board of Directors is responsible for approving risk management policies and for establishing the Company’s overall risk tolerance levels.

The primary objective of our commodity price risk management policy is to preserve and enhance the value of the Company’s equity gas production. In order to accomplish this objective, we may enter into equity hedge agreements, within approved limits, in order to protect our equity production from fluctuations in commodity prices and the resulting impact on cash flow, net income and earnings per share.

Our outstanding derivative instruments as of December 31, 2009 are summarized below (volume and daily production are expressed in Mcf):

Remaining

Contractual

Daily

Price

Type of Contract

Volume

Production

Term

Price

Index (1)

Fixed Price Swap

4,380,000

12,000

1/10-12/10

$4.30

CIG

Costless Collar

2,885,000

5,000

8/09-7/11

$4.50 floor

NYMEX

$7.90 ceiling

Costless Collar

3,495,000

5,000

12/09-11/11

$4.50 floor

NYMEX

$9.00 ceiling

Fixed Price Swap

2,920,000

8,000

1/11-12/11

$7.07

CIG

Total

13,680,000


(1)		NYMEX refers to quoted prices on the New York Mercantile Exchange. CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month.

As with most derivative instruments, our derivative contracts contain provisions which may allow for another party to require security from the counterparty to ensure performance under the contract. The security may be in the form of, but not limited to, a letter of credit, security interest or a performance bond. Neither party in any of our derivative contracts has required any form of security guarantee as of December 31, 2009.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 11a-15(e) and 15d-15(e)) as of the end of the period covered by this annual report on Form 10-K. Based upon this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective in ensuring that material information required to be disclosed is included in the reports that we file with the Securities and Exchange Commission.

Management’s Annual Report on Internal Control Over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 11a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that:

	(i)		pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

	(ii)		provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

(iii)

provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

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

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2009.

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

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during our fiscal quarter ended December 31, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

(The remainder of this page was intentionally left blank)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders
Double Eagle Petroleum Co.

We have audited Double Eagle Petroleum Co.’s (the “Company”) internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

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

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (a) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (b) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (c) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

In our opinion, Double Eagle Petroleum Co. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of Double Eagle Petroleum Co. and our report dated March 3, 2010 expressed an unqualified opinion.

HEIN & ASSOCIATES LLP

Denver, Colorado
March 3, 2010

ITEM 9B. OTHER INFORMATION

None.

PART III

Pursuant to instruction G(3) to Form 10-K, the following Items 10,11,12,13 and 14 will be included in an amendment to this Form 10-K or in Double Eagle’s definitive proxy statement for the 2010 annual meeting of stockholders to be filed within 120 days from December 31, 2009, and is incorporated by reference to this report

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Code of Conduct and Ethics

We maintain a code of ethics applicable to our Board of Directors, principal executive officer, and principal financial officer, as well as all of our other employees. A copy of the Code of Business Conduct and Ethics and our Whistleblower Procedures may be found on our website at http://www.dble.com under the Corporate Governance section.

ITEM 11. EXECUTIVE COMPENSATION

Incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Equity Compensation Plans. The following table provides information as of December 31, 2009 with respect to shares of common stock that may be issued under our existing equity compensation plans. We have five equity compensation plans—the 1996 Stock Option Plan, the 2000 Stock Option Plan, the 2002 Stock Option Plan, the 2003 Stock Option and Compensation Plan and the 2007 Stock Incentive Plan.

(c)

Number of securities

(a)

remaining available

Number of

(b)

for future issuance

securities to be

Weighted-

under equity

issued upon

average

compensation plans

exercise of

exercise price

(excluding securities

outstanding

of outstanding

reflected in column

Plan category

options

(a))

Equity Compensation plans approved by security holders

647,897

15.06

138,366

(1)


(1)		Represents no shares available for issuance under the 1996 Stock Option Plan and the 2000 Stock Option Plan; 14,500 shares available for issuance under the 2002 Stock Option Plan; 33,099 shares available for issuance under the 2003 Stock Option and Compensation Plan and 90,767 shares available for issuance under the 2007 Stock Incentive Plan.

ITEM 13. CERTAIN RELATIONSHIPS, RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICE

Incorporated herein by reference.

PART IV

ITEM 15. EXHIBITS , FINANCIAL STATEMENT SCHEDULES

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


Audit Report of Independent Registered Public Accounting Firm			F-1
Consolidated Balance Sheets			F-2
Consolidated Statements of Operations			F-3
Consolidated Statements of Cash Flows			F-4
Consolidated Statements of Stockholders’ Equity			F-5
Notes to Consolidated Financial Statements			F-7

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

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


Exhibit No.		Description

2.1(a)		Agreement and Plan of Merger, dated March 30, 2009, by and among the Company, DBLE Acquisition Corporation, and Petrosearch Energy Corporation (incorporated by reference from Exhibit 2.1 of the Company’s Current Report of Form 8-K dated March 31, 2009)

2.1(b)		Form of Voting Agreement (incorporated by reference from Exhibit 2.2 of the Company’s Current Report of Form 8-K dated March 31, 2009)

3.1(a)		Articles of Incorporation filed with the Maryland Secretary of State on January 23, 2001 (incorporated by reference from Exhibit 3.1(a) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).

3.1(b)		Certificate of Correction filed with the Maryland Secretary of State on February 15, 2001 concerning the Articles of Incorporation (incorporated by reference from Exhibit 3.1(b) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).

3.1(c)		Articles of Merger filed with the Maryland Secretary of State on February 15, 2001 (incorporated by reference from Exhibit 3.1(c) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).

3.1(d)		Certificate of Correction filed with the Maryland Secretary of State (incorporated by reference from Exhibit 3 of the Company’s Quarterly Report on Form 10-QSB for the quarter ended November 30, 2001).

3.1(e)		Certificate of Correction to the Articles of Incorporation, filed with the Maryland Department of Assessments and Taxation on June 1, 2007 (incorporated by reference from Exhibit 3.3 of the Company’s Current Report of Form 8-K dated June 29, 2007).

3.1(f)		Articles of Amendment, filed with the Maryland Department of Assessments and Taxation on June 26, 2007 (incorporated by reference from Exhibit 3.1 of the company’s Current report on Form 8-K dated June 29, 2007).

3.1(g)		Articles Supplementary, filed with the Maryland Department of Assessments and Taxation on June 29, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report of Form 8-K dated June 29, 2007).


Exhibit No.		Description

3.1(h)		Articles Supplementary of Junior Participating Preferred Stock, Series B, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current report of Form 8-K dated August 28, 2007).

3.2(a)		Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Annual Report on Form 10-KSB, filed for the year ended August 31, 2001).

3.2(b)		Bylaws of the Company, as amended and restated on March 14, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K, filed on March 14, 2007).

3.2(c)		Second Amendment and Restated Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K dated June 11, 2007).

4.1(a)		Form of Warrant Agreement concerning Common Stock Purchase Warrants (incorporated by reference from Exhibit 4.3 of the Amendment No. 1 to the Company’s Registration Statement on Form SB-2 filed on November 27, 1996, SEC Registration No. 333-14011).

4.1(b)		Shareholder Rights Agreement, dated as of August 24, 2007 (incorporated herein by reference to the Company’s Current report on Form 8-A filed on August 24, 2007).

4.1(c)		Articles Supplementary, filed with the Maryland Department of Assessments and Taxation on June 29, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K dated June 29, 2007).

4.1(d)		Articles Supplementary of Junior Participating Preferred Stock, Series B, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current report of Form 8-K dated August 28, 2007).

10.1(a)		Debt Modification Agreement, effective August 1, 2006, including Commercial Loan Agreement dated January 3, 2000, between Double Eagle Petroleum Co. and American National Bank (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, and incorporated herein by reference).

10.1(b)		Debt Modification Agreement, effective July 1, 2007, between Double Eagle Petroleum Co. and American National Bank (incorporated by reference from Exhibit 10.1 to the Company’s Current report on Form 8-K dated July 5, 2007).

10.1(c)		Credit Agreement dated February 26, 2009 between Double Eagle Petroleum Co. and Bank of Oklahoma, N.A. et.al (incorporated by reference from Exhibit 10.1 to the Company’s Current report on Form 8-K dated February 26, 2009).

10.1(d)		Promissory Term Note dated February 26, 2009 between Double Eagle Petroleum Co. and Bank of Oklahoma, N.A. (incorporated by reference from Exhibit 10.2 to the Company’s Current report on Form 8-K dated February 26, 2009).

10.1(e)		Revolving Notes dated February 26, 2009 between Double Eagle Petroleum Co. and Bank of Oklahoma, N.A. et.al (incorporated by reference from Exhibit 10.3 to the Company’s Current report on Form 8-K dated February 26, 2009).

10.1(f)		Double Eagle Petroleum Co. 2007 Stock Incentive Plan, Form of Incentive Stock Option Agreement and Form of Non-Qualified Stock Option Agreement (incorporated by reference from Exhibit 10.1, 10.2 and 10.3 to the Company’s Current report on Form 8-K dated May 29, 2007).

10.1(g)		Employment Agreement between the Company and Richard Dole, dated September 4 2008 (incorporated by reference from Exhibit 10.1 of the Company’s Current Report of Form 8-K dated September 9, 2008).

10.1(h)		Employment Agreement between the Company and Kurtis Hooley, dated September 4, 2008 (incorporated by reference from Exhibit 10.2 of the Company’s Current Report of Form 8-K dated September 9, 2008).


Exhibit No.		Description

10.1(i)		Employment Agreement between the Company and D. Steven Degenfelder, dated September 4, 2008 (incorporated by reference from Exhibit 10.3 of the Company’s Current Report of Form 8-K dated September 9, 2008).

10.1(j)		Employment Agreement between the Company and Robert Reiner, dated September 4, 2008 (incorporated by reference from Exhibit 10.4 of the Company’s Current Report of Form 8-K dated September 9, 2008).

10.1(k)		Employment Agreement between the Company and Aubrey Harper, dated September 4, 2008 (incorporated by reference from Exhibit 10.5 of the Company’s Current Report of Form 8-K dated September 9, 2008).

10.1(i)		First Amendment to Credit Agreement dated July 22, 2009 between Double Eagle Petroleum Co. and Bank of Oklahoma, N.A. et.al (incorporated by reference from Exhibit 10.1 of the Company’s Current Report of Form 8-K dated July 22, 2009).

14.1		Code of Business Conduct and Ethics (filed as Exhibit 99.2 to the Company’s Annual Report on Form 10-KSB for the year ended December 31, 2004, and incorporated herein by reference).

21.1*		Subsidiaries of registrant.

23.1*		Consent of Hein & Associates LLP.

23.2*		Consent of Netherland, Sewell & Associates, Inc.

31.1*		Certification of Principal Executive Officer and Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Principal Accounting Officer and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32*		Certification Pursuant to 18 U.S.C. Section 1150 as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.

99.1*		Report of Netherland, Sewell & Associates, Inc. dated January 28, 2010.


*		Filed with this Form 10-K.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders
Double Eagle Petroleum Co.

We have audited the accompanying consolidated balance sheets of Double Eagle Petroleum Co. and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Double Eagle Petroleum Co. and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Double Eagle Petroleum Co.’s and subsidiaries’ internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 3, 2010 expressed an unqualified opinion on the effectiveness of Double Eagle Petroleum Co.’s internal control over financial reporting.

HEIN & ASSOCIATES LLP

Denver, Colorado
March 3, 2010

F-1

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


	December 31,			December 31,
	2009			2008
ASSETS
Current assets:
Cash and cash equivalents	$	5,682		$	—
Cash held in escrow		611			605
Accounts receivable, net		6,772			21,381
Assets from price risk management		—			14,290
Other current assets		3,982			3,513

Total current assets		17,047			39,789


Oil and gas properties and equipment, successful efforts method:
Developed properties		165,279			133,516
Wells in progress		7,544			18,518
Gas transportation pipeline		5,465			5,465
Undeveloped properties		2,502			2,907
Corporate and other assets		1,914			1,920

		182,704			162,326
Less accumulated depreciation, depletion and amortization		(53,682	)		(35,253	)

Net properties and equipment		129,022			127,073

Deferred tax asset		—			—
Assets from price risk management		3,566			5,029
Other assets		859			98

TOTAL ASSETS	$	150,494		$	171,989


LIABILITIES, PREFERRED STOCK, AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	6,177		$	35,488
Accrued expenses		6,918			6,794
Liabilities from price risk management		4,739			—
Accrued production taxes		2,439			3,017
Capital lease obligations, current portion		533			522
Other current liabilities		308			282

Total current liabilities		21,114			46,103

Credit facility		34,000			24,639
Asset retirement obligation		4,807			4,208
Liabilities from price risk management		430			—
Deferred tax liability		4,620			2,470
Capital lease obligations, long-term portion		545			1,078
Other long-term liabilities		282			616

Total liabilities		65,798			79,114


Preferred stock, $0.10 par value; 10,000,000 shares authorized; 1,610,000 shares issued and outstanding as of December 31, 2009 and December 31, 2008		37,972			37,972


Stockholders’ equity:
Common stock, $0.10 par value; 50,000,000 shares authorized; 11,090,725 and 9,192,356 shares issued and outstanding as of December 31, 2009 and December 31, 2008, respectively		1,109			919
Additional paid-in capital		43,640			35,122
Retained earnings (accumulated deficit)		(342	)		2,172
Accumulated other comprehensive income		2,317			16,690

Total stockholders’ equity		46,724			54,903


TOTAL LIABILITIES, PREFERRED STOCK AND STOCKHOLDERS’ EQUITY	$	150,494		$	171,989

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

F-2

DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands of dollars except share and per share data)


	Year ended December 31,
	2009			2008			2007

Revenues
Oil and gas sales	$	42,398		$	39,149		$	16,044
Transportation and gathering revenue		6,179			4,788			910
Price risk management activities		(4,295	)		5,329			—
Other income		509			312			243

Total revenues		44,791			49,578			17,197


Costs and expenses
Production costs		7,754			7,007			5,696
Production taxes		3,652			4,701			1,933
Exploration expenses including dry hole costs		103			911			15,399
Pipeline operating costs		3,701			3,190			645
Impairment and abandonment of equipment and properties		417			743			2,232
General and administrative		6,718			5,604			4,133
Depreciation, depletion and amortization		18,562			11,473			5,068


Total costs and expenses		40,907			33,629			35,106


Income (loss) from operations		3,884			15,949			(17,909	)

Interest (expense) income, net		(1,773	)		(225	)		163


Income (loss) before income taxes		2,111			15,724			(17,746	)

(Provision) benefit for deferred income taxes		(902	)		(5,343	)		6,143


NET INCOME (LOSS)	$	1,209		$	10,381		$	(11,603	)


Preferred stock dividends		(3,723	)		(3,723	)		(1,810	)


Net income (loss) attributable to common stock	$	(2,514	)	$	6,658		$	(13,413	)


Net income (loss) per common share:
Basic	$	(0.25	)	$	0.73		$	(1.47	)

Diluted	$	(0.25	)	$	0.73		$	(1.47	)


Weighted average shares outstanding:
Basic		9,955,582			9,159,865			9,114,622

Diluted		9,955,582			9,161,985			9,114,622

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

F-3

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


	Year ended December 31,
	2009			2008			2007
Cash flows from operating activities:
Net income (loss)	$	1,209		$	10,381		$	(11,603	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion of asset retirement obligation		18,693			11,648			5,062
Abandonment of non-producing properties and leases		417			743			14,941
Bad debt expense		—			—			559
Settlement of asset retirement obligation		(266	)		—			—
Non cash revenue from carried interest		(2,044	)		(1,665	)		—
Impairment of equipment and properties		—			—			2,234
Provision for deferred taxes		902			5,343			(6,143	)
Directors fees paid in stock		177			128			90
Non-cash loss (gain) on derivative contracts		7,798			(2,631	)		—
Non-cash employee stock option expense		1,307			1,050			362
Gain on sale of working interest in non-producing property		(283	)		(90	)		(98	)
Changes in current assets and liabilities:
Decrease (Increase) in deposit held in escrow		(6	)		114			(12	)
Decrease (Increase) in accounts receivable		13,884			(17,522	)		824
Decrease (Increase) in other current assets		(150	)		(2,871	)		223
Increase (Decrease) in accounts payable		(14,544	)		15,461			(1,890	)
Increase (Decrease) in accrued expenses		(4,454	)		47			739
Increase (Decrease) in accrued production taxes		(578	)		2,768			(122	)


NET CASH PROVIDED BY OPERATING ACTIVITIES		22,062			22,904			5,166


Cash flows from investing activities:
Additions of producing properties and equipment		(28,542	)		(44,378	)		(41,550	)
Additions of corporate and non-producing properties		(139	)		(878	)		(750	)
Proceeds from sales of properties and assets		—			4,478			244
Net cash received from Petrosearch acquisition		7,733
Payment of Petrosearch transaction costs		(513	)		—			—


NET CASH USED IN INVESTING ACTIVITIES		(21,461	)		(40,778	)		(42,056	)


Cash flows from financing activities:
Net proceeds from sale of common stock		—			—			9,990
Net proceeds from sale of preferred stock		—			—			37,972
Dividends paid on preferred stock		(3,723	)		(3,723	)		(1,810	)
Net borrowings/(payments) on line of credit		9,361			21,194			(9,776	)
Proceeds from Company stock plans		—			278			28
Principal payments on capital lease obligations		(522	)		—			—
Tax withholdings related to net share settlement of restricted stock awards		(39	)		—			—
Issuance of stock under Company stock plans		4			—			—


NET CASH PROVIDED BY FINANCING ACTIVITIES		5,081			17,749			36,404


Change in cash and cash equivalents		5,682			(125	)		(486	)

Cash and cash equivalents at beginning of period		—			125			611


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	5,682		$	—		$	125


Supplemental disclosure of cash and non-cash transactions:
Cash paid for interest	$	2,151		$	657		$	426
Interest capitalized	$	485		$	705		$	279
Cash paid for income taxes	$	—		$	—		$	—
Receivables due from joint-interest partners related to change in working interest	$	—		$	193		$	—
Share-based compensation expense	$	1,484		$	1,178		$	452
Additions to developed properties included in current liabilities	$	10,245		$	20,299		$	4,908
Additions to developed properties for asset retirement obligations	$	94		$	2,584		$	757
Issuance of common stock in connection with the acquisition of Petrosearch	$	7,260		$	—		$	—
Fair value of asset received in connection with the acquisition of Petrosearch	$	9,151		$	—		$	—
Fair value of liabilities assumed in connection with the acquisition of Petrosearch	$	1,018		$	—		$	—

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

F-4

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


										Accumulated
	Shares of									Other			Total
	Common Stock				Additional Paid-		Retained			Comprehensive			Stockholders’
	Outstanding		Common Stock		In Capital		Earnings			Income (loss)			Equity
Balance at January 1, 2007		8,641,104	$	864	$	23,251	$	8,927		$	—		$	33,042
Comprehensive loss
Net loss		—		—		—		(11,603	)		—			(11,603	)
Net change in derivative instrument fair value, net of tax		—		—		—		—			(1,475	)		(1,475	)

Total comprehensive loss														(13,078	)

Stock options exercised		2,000		—		27		—			—			27
Compensation expense from common stock options		—		—		362		—			—			362
Directors fees paid in stock		5,001		1		90		—			—			91
Sale of common stock		500,000		50		9,940		—			—			9,990
Dividends declared & paid on preferred stock		—		—		—		(1,810	)		—			(1,810	)

Balance at December 31, 2007		9,148,105		915		33,670		(4,486	)		(1,475	)		28,624
Comprehensive income
Net income		—		—		—		10,381			—			10,381
Net change in derivative instrument fair value, net of tax		—		—		—		—			18,253			18,253
Reclassification to earnings, net of tax		—		—		—		—			(88	)		(88	)

Total comprehensive income														28,546

Stock options exercised		15,000		1		275		—			—			276
Share-based compensation expense		—		—		1,050		—			—			1,050
Directors fees paid in stock		7,805		1		127		—			—			128
Issuance of common shares upon restricted stock vesting		21,446		2		—		—			—			2
Dividends declared & paid on preferred stock		—		—		—		(3,723	)		—			(3,723	)

Balance at December 31, 2008		9,192,356	$	919	$	35,122	$	2,172		$	16,690		$	54,903

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

F-5

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


										Accumulated
	Shares of									Other			Total
	Common Stock				Additional Paid-		Retained			Comprehensive			Stockholders’
	Outstanding		Common Stock		In Capital		Earnings			Income (loss)			Equity
Balance at December 31, 2008		9,192,356	$	919	$	35,122	$	2,172		$	16,690		$	54,903
Comprehensive loss
Net income		—		—		—		1,209			—			1,209
Net change in derivative instrument fair value, net of tax		—		—		—		—			1,367			1,367
Reclassification to earnings, net of tax		—		—		—		—			(15,740	)		(15,740	)

Total comprehensive loss														(13,164	)

Shares issued in connection with Petrosearch acquisition		1,791,733		179		7,080		—			—			7,259
Share-based compensation expense, exclusive of amounts withheld for payroll taxes		79,912		8		1,264		—			—			1,272
Directors fees paid in stock		26,724		3		174		—			—			177
Dividends declared & paid on preferred stock		—		—		—		(3,723	)		—			(3,723	)

Balance at December 31, 2009		11,090,725	$	1,109	$	43,640	$	(342	)	$	2,317		$	46,724

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

F-6

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

1.		Business Description and Summary of Significant Accounting Policies

		Description of Operations

		Double Eagle Petroleum Co. (“Double Eagle” or the “Company”) is an independent energy company engaged in the exploration, development, production and sale of natural gas and crude oil, primarily in the Rocky Mountain Basins of the western United States. Double Eagle was incorporated in the State of Wyoming in January 1972, and reincorporated in the State of Maryland in February 2001.

		Principles of Consolidation and Basis of Presentation

		The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries Petrosearch Energy Corporation (“Petrosearch”) and Eastern Washakie Midstream LLC (“EWM”) (collectively, the “Company”). The Company acquired Petrosearch in August 2009 and has operations in Texas, Oklahoma, and North Dakota. EWM owns and operates a 13-mile intrastate gas pipeline (the “Pipeline”). The Company has an agreement with EWM, under which the Company pays a fee to EWM to gather and compress gas produced at the Catalina Unit. All intercompany transactions, including our share of the fee related to gas gathering are eliminated in consolidation for all periods presented in this Form 10-K.

		The Company has no interests in any unconsolidated entities, nor does it have any unconsolidated special purpose entities.

		Certain reclassifications have been made to amounts reported in previous years to conform to the 2009 presentation. Such reclassifications had no effect on net income.

		Cash and Cash Equivalents

		Cash and cash equivalents includes all cash balances and any highly liquid investments with an original maturity of 90 days or less.

		Cash Held in Escrow

		The Company has received deposits representing partial prepayments of the expected capital expenditures from third party working interest owners in the Table Top Unit #1 exploration project. The unexpended portion of the deposits at December 31, 2009 and 2008 totaled $611 and $605, respectively.

		Accounts Receivable

		The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company recorded an allowance for uncollectible receivables of $0, $0, and $559 for the periods ended December 31, 2009, 2008 and 2007, respectively.

		Use of Estimates in the Preparation of Financial Statements

		The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure on contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of oil and gas reserve quantities provide the basis for calculation of depletion, depreciation, and amortization, and impairment, each of which represents a significant component of the consolidated financial statements.

		Concentration of Credit Risk

		Financial instruments which potentially subject the Company to credit risk consist of our accounts receivable and our derivative financial instruments. Substantially all of the Company’s receivables are within the oil and gas industry, including those from the

F-7

Company’s third party marketing company. Collectability is dependent upon the financial wherewithal of each individual company as well as the general economic conditions of the industry. The receivables are not collateralized.

		The Company currently uses two counterparties for its derivative financial instruments. The Company continually reviews the credit worthiness of our counterparties, which are generally energy companies. In addition, the Company uses master netting agreements which allow the Company, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If the Company chooses to elect early termination, all asset and liability positions with the defaulting counterparty would be “net settled” at the time of election. “Net settlement” refers to a process by which all transactions between counterparties are resolved into a single amount owed by one party to the other.

		Revenue Recognition and Gas Balancing

		The Company recognizes oil and gas revenues for its ownership percentage of total production under the entitlement method, whereby the working interest owner records revenue based on its share of entitled production, regardless of whether the Company has taken its ownership share of such volumes. An over-produced owner would record the excess of the amount taken over its entitled share as a reduction in revenues and a payable while the under-produced owner records revenue and a receivable for the imbalance amount. The Company’s imbalance position with various third party operators at December 31, 2009 resulted in an imbalance receivable of 128 MMcf, or $446, and an imbalance payable of 188 MMcf, or $721.

		Oil and Gas Producing Activities

		Double Eagle uses the successful efforts method of accounting for its oil and gas producing activities. Under this method of accounting, all property acquisition costs and costs of exploration and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive.

		Geological and geophysical costs and the costs of carrying and retaining unproved leaseholds are expensed as incurred. The Company limits the total amount of unamortized capitalized costs for each property to the value of future net revenues, based on expected future prices and costs.

		Depreciation, depletion and amortization (“DD&A”) of capitalized costs for producing oil and gas properties is provided on a field-by-field basis using the units-of-production method, based on proved oil and gas reserves. DD&A takes into consideration restoration, dismantlement and abandonment costs and the anticipated proceeds for equipment salvage.

		Depreciation, depletion and amortization of oil and gas properties for the years ended December 31, 2009, 2008, and 2007, was $18,136, $11,078, and $4,550, respectively.

		Double Eagle invests in unevaluated oil and gas properties for the purpose of future exploration and development of proved reserves. The costs of unproved leases which become productive are reclassified to proved properties when proved reserves are discovered on the property. Unproved oil and gas interests are carried at the lower of cost or estimated fair market value and are not subject to amortization.

		The following table reflects the net changes in capitalized exploratory well costs during the years ended December 31, 2009, 2008 and 2007 and amounts include costs capitalized and subsequently expensed in the same period (amounts in thousands).


	2009		2008			2007
Beginning balance at January 1,	$	—	$	692		$	11,541

Additions to capitalized exploratory well costs pending the determination of proved reserves		—		—			5,727
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		—		(692	)		(1,666	)
Capitalized exploratory well costs charged to expense		—		—			(14,910	)


Ending balance at December 31,	$	—	$	—		$	692

F-8

		Asset Retirement Obligations

		Legal obligations associated with the retirement of long-lived assets result from the acquisition, construction, development and normal use of the asset. The Company’s asset retirement obligations relate primarily to the retirement of oil and gas properties and related production facilities, lines and other equipment used in the field operations. The fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled.

		For the years ended December 31, 2009, 2008 and 2007, an expense of $131, $175, and $25, respectively, was recorded as accretion expense on the liability and included in production costs on the Consolidated Statement of Operations. During 2009 and 2008, the Company recorded an additional $521, and $2,661, respectively, in oil and gas properties and asset retirement obligation liability to reflect the present value of plugging liability on new wells and revisions to estimated cash flows added during the respective years.

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


	For the year ended December 31,
	2009			2008

Beginning asset retirement obligation	$	4,208		$	1,449

Additional liabilites assumed through acquisition of Petrosearch		640			—
Liabilities incurred		4			995
Liabilities settled		(266	)		—
Accretion expense		131			175
Changes in ownership interest		213			(77	)
Revision to estimated cash flows		(123	)		1,666


Ending asset retirement obligation	$	4,807		$	4,208

		Impairment of Long-Lived Assets

		The Company reviews the carrying values of its long-lived assets whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. The long-lived assets of the Company, which are subject to periodic evaluation, consist primarily of oil and gas properties and undeveloped leaseholds. The Company recognized a non-cash charge on producing properties during the years ending December 31, 2009, 2008 and 2007 of $0, $0, and $2,141, respectively, and a non-cash charge on undeveloped leaseholds during the years ending December 31, 2009, 2008 and 2007 of $417, $743, and $91, respectively.

		The Company’s pipeline facilities are recorded at cost, which totaled $5,465 as of December 31, 2009. Depreciation is recorded using the straight-line method over a 25 year estimated useful life. The useful life may be limited to the useful life of current and future recoverable reserves serviced by the pipeline. The Company evaluated the expected useful life of the pipeline assets as of December 31, 2009 and determined that the assets are expected to be utilized for at least the estimated useful life used in the depreciation calculation.

		Corporate and Other Assets

		Office facilities, equipment and vehicles are recorded at cost. Depreciation is recorded using the straight-line method over the estimated useful lives of 10 to 40 years for office facilities, 3 to 10 years for office equipment, and 7 years for vehicles. Depreciation expense for the years ended December 31, 2009, 2008 and 2007 was $206, $177, and $160, respectively.

F-9

		Major Customers

		The Company had sales to one major unaffiliated customer for years ended December 31, 2009, 2008 and 2007, totaling $41,149 $32,045, and $11,530, respectively. No other single customer accounted for 10% or more of revenues in 2009, 2008, or 2007. Although a substantial portion of our production is purchased by one customer, the Company does not believe the loss of this customer would have a material adverse effect on the Company’s business as other customers would be accessible.

		Industry Segment and Geographic Information

		The Company operates in one industry segment, which is the exploration, development, production and sale of natural gas and crude oil, and all of the Company’s operations are conducted in the Continental United States. Consequently, the Company currently reports as a single industry segment. The Company’s transportation and gathering subsidiary provides services exclusively for our gas marketing company and all of the revenue generated by this subsidiary is related to volumes produced from the Catalina Unit. Segmentation of such net income would not provide a better understanding of the Company’s performance, and is not viewed by management as a discrete reporting segment. However, gross revenue and expense related to our transportation and gathering subsidiary are presented as separate line items in the accompanying Consolidated Statement of Operations.

		Employee Benefit Plan

		The Company maintains a Simplified Employee Pension Plan covering substantially all employees meeting minimum eligibility requirements. Employer contributions are determined solely at management’s discretion. Employer contributions for years ended 2009, 2008 and 2007 were $183, $117, and $118, respectively.

		Income Taxes

		Income taxes are accounted for under the asset and liability method. Deferred taxes assets or liabilities are recorded based on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements. This difference will result in taxable income or deduction in future periods when the reported amount of the asset or liability is recovered or settled, respectively.

		Earnings Per Share

		Basic earnings per share (“EPS”) is calculated by dividing net income (loss) attributable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share incorporates the treasury stock method to measure the dilutive impact of potential common stock equivalents by including the effect of outstanding vested and unvested stock options and unvested stock awards in the average number of common shares outstanding during the period.

		Calculation of basic and diluted weighted average shares outstanding and EPS for the periods indicated:


	For the year ended December 31,
	2009			2008			2007

Net income (loss)	$	1,209		$	10,381		$	(11,603	)
Preferred stock dividends		(3,723	)		(3,723	)		(1,810	)

Income (loss) attributable to common stock	$	(2,514	)	$	6,658		$	(13,413	)

Weighted average shares:
Weighted average shares — basic		9,955,582			9,159,865			9,114,622
Dilutive effect of stock options outstanding at the end of period		—			2,120			—

Weighted average shares — fully diluted		9,955,582			9,161,985			9,114,622


Earnings (loss) per share:
Basic	$	(0.25	)	$	0.73		$	(1.47	)

Diluted	$	(0.25	)	$	0.73		$	(1.47	)

F-10

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


	For the years ended December 31,
		2009	2008	2007

Potential common shares		84,177	56,249	6,643

		Stock Based Compensation

		The Company measures and recognizes compensation expense for all share-based payment awards (including stock options and stock awards) made to employees and directors based on estimated fair value. Compensation expense for equity-classified awards is measured at the grant date based on the fair value of the award and is recognized as an expense in earnings over the requisite service period using a graded vesting method.

		Shareholder Rights Plan

		In 2007, the Board of Directors of the Company adopted a Shareholder Rights Plan (“Rights Plan”). Under the Rights Plan, the Company issued a dividend of one Preferred Share Purchase Right for each outstanding share of common stock held by stockholders of record on September 4, 2007. The Rights Plan is intended to safeguard against abusive takeover tactics that limit the ability of all shareholders to realize the long-term value of their investment in Double Eagle. The Rights Plan was not adopted in response to any specific takeover effort, and will not prevent a takeover, but should encourage anyone seeking to acquire Double Eagle to negotiate with the Board prior to attempting a takeover.

		Each right initially entitles stockholders to purchase a fractional share of the Company’s Series B Junior Participating Preferred Stock at an exercise price of $45. However, the rights are not immediately exercisable and will become exercisable only upon the occurrence of certain events. If a person or group acquires, or announces a tender or exchange offer that would result in the acquisition of 20% or more of the Company’s common stock while the Rights Plan remains in place, then, unless the rights are redeemed by the Company for $.01 per right, the rights will become exercisable by all rights holders, except the acquiring person or group, for shares of the Company’s common stock having a value of twice the right’s then-current exercise price.

		There are 75,000 shares of the Company’s Series B Junior Participating Preferred Stock, par value $.10, authorized with no shares outstanding at December 31, 2009.

		Fair Value of Financial Instruments

		The Company’s financial instruments including cash and cash equivalents, accounts receivable and accounts payable are carried at a cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s credit facility approximates its fair value as it bears interest at a floating rate. The Company accounts for certain derivative contracts as cash flow hedges, with the effective portion of gains and losses related to the changes in the fair value recorded in accumulated other comprehensive income, a component of Stockholder’s equity. The Company also marks to market other derivative instruments not accounted for as cash flow hedges, with the change in fair values recorded within the price risk management line on the Consolidated Statement of Operations. Reference is made to Notes 6 and 7 of the Notes to the Consolidated Financial Statements.

		Derivative Financial Instruments

		The Company uses derivative instruments, primarily forwards, swaps, and collars, to hedge risk associated with fluctuating commodity prices. The Company does not use derivative instruments for speculative purposes. See Notes 5 and 6 for a full description of our derivative activities and related accounting policies.

F-11

		Other Comprehensive Income

		Comprehensive income (loss) consists of net income (loss) and changes to the Company’s derivative instruments that are treated as cash flow hedges, including realized and unrealized gains and losses as well as changes in fair value, net of tax.

		Accumulated other comprehensive income is reported as a separate component of Stockholders’ equity and is made up of the change in the fair market value of cash flow hedges, net of tax. The Company’s accumulated other comprehensive income related to cash flow hedges at December 31, 2009 totaled $2,317, which is net of taxes in the amount of $1,249. As of December 31, 2009, the Company expected to reclassify $0 of the accumulated other comprehensive income balance to earnings in one year or less, as none of the contracts settle prior to 2011.

		Recently Adopted Accounting Pronouncements

		In June 2009, the Financial Accounting Standards Board (“FASB”) issued ASC 105, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (“ASC 105”). The Accounting Standards Codification (“ASC”) has become the source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernment entities. It also modifies the GAAP hierarchy to include only two levels of GAAP; authoritative and non-authoritative. The Company adopted ASC 105 effective July 1, 2009. Pursuant to the provisions of ASC 105, the Company has updated references to GAAP in its financial statements issued for the year ended December 31, 2009. The adoption of ASC 105 did not have an impact on the Company’s financial position, results of operations or cash flows.

		In September 2006, the ASC guidance for fair value measurements was updated to define fair value, establish a framework for measuring fair value, and expand disclosures related to fair value. The Company adopted the updated guidance for assets and liabilities measured at fair value on a recurring basis on January 1, 2008. In February 2008, the FASB issued an update to the guidance, which delayed the effective date for nonfinancial assets and liabilities, including asset retirement obligations, that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually). The Company adopted the updated guidance for nonfinancial assets and liabilities on January 1, 2009. In April 2009, the guidance was again updated to provide additional guidance on determining fair value when the volume and level of activity for the asset or liability have significantly decreased and identifying circumstances that indicate when a transaction is not orderly. The Company adopted this guidance April 1, 2009. In August 2009, the ASC provided further guidance related to the fair value of liabilities. This update provides clarification for circumstances in which: (i) a quoted price in an active market for the identical liability is not available, (ii) the liability has a restriction that prevents its transfer, and (iii) the identical liability is traded as an asset in an active market in which no adjustments to the quoted price of an asset are required. The Company adopted this update effective October 1, 2009. None of the aforementioned adoptions related to fair value had a material impact on its financial position, results of operations or cash flows.

		In May 2009, the ASC guidance for subsequent events was updated to establish general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The Company adopted this guidance effective April 1, 2009. See Note 10 for the Company’s disclosures about subsequent events.

		In June 2008, the ASC guidance was updated to provide clarification as to whether instruments granted in share-based payment transactions are participating securities prior to vesting, and therefore, need to be included in computing earnings per share under the two-class method provided under ASC 260 — Earnings Per Share. The Company adopted this standard effective January 1, 2009. The adoption of this guidance did not have a material impact on the Company’s financial position, results of operations or cash flows.

		In March 2008, the ASC guidance for derivatives and hedging instruments was updated for enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items (if any) are accounted for, and how they affect the Company’s financial position, financial performance and cash flows. The Company adopted the updated guidance effective January 1, 2009. See Note 6 for the Company’s disclosures about its derivative instruments and hedging activities.

		In November 2007, the ASC guidance for business combinations was updated to provide new guidance for recognizing and measuring the assets and goodwill acquired and liabilities assumed in an acquisition. The updated guidance also broadened the definition of a business combination and requires an entity to recognize transaction costs separately from the acquisition. The Company adopted the updated guidance effective January 1, 2009 and applied it to the acquisition of Petrosearch completed on August 6, 2009 (see Note 3).

F-12

		In January 2010, the ASC guidance for reporting oil and gas reserves was updated to align the oil and gas reserve estimation and disclosure requirements with the requirements in the SEC’s final rule, Modernization of the Oil and Gas Reporting Requirements. The new guidance expands the definition of reserves, which allows consideration of new technologies. In addition, oil and gas reserves are reported using an average, first-day-of-the-month price based on the prior 12-month period, rather than year-end prices. The new rule is effective for annual reporting periods ending on or after December 31, 2009. The Company adopted these provisions effective December 31, 2009. The new standards are applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate. The application of the new rules increased our DD&A expense for the fourth quarter by approximately $147, and decreased our net income attributable to common shareholders by $84, or $.01 per diluted share. Refer to Note 11 for the Company’s disclosures about its oil and gas reserves.

		New Accounting Pronouncements

		In January 2010, the FASB issued ASC Update No. 2010-06, an additional update to the ASC guidance for fair value measurements. The new guidance requires additional disclosures about (1) the different classes of assets and liabilities measured at fair value, (2) the valuation techniques and inputs used, (3) the activity in Level 3 fair value measurements, and (4) the transfers between Levels 1, 2, and 3. The updated guidance is effective for annual and interim periods beginning December 15, 2009, except for the disclosures about the activity in Level 3 fair value measurements, for which the new guidance is effective for fiscal years beginning after December 15, 2010. The adoption of ASC Update 2010-06 is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.

2.		Line of Credit

		As part of the Company’s cash management program, at December 31, 2009, the Company had a $75 million revolving line of credit in place with a $45 million available for borrowing based on several factors, including our current borrowing base and the commitment levels by participating banks. The credit facility is collateralized by the Company’s oil and gas producing properties.

		As of December 31, 2009, the balance outstanding of $34,000 was used to fund capital expenditures primarily on our Catalina Unit expansion and other non-operated projects in the Atlantic Rim in 2008, as well as projects in the Pinedale Anticline in 2008 and 2009.

		Borrowings under the revolving line of credit bear interest at the greater of (i) 4.5% or (ii) a daily rate equal to the greater of (a) the Federal Funds rate, plus 0.5%, the Prime Rate or the Eurodollar Rate plus 1%, plus (b) a margin ranging between 1.25% and 2.0% depending on the level of funds borrowed. As of December 31, 2009, the interest rate on the line of credit was 4.5%. For the years ended December 31, 2009, 2008, and 2007, the Company incurred interest expense on the line of credit of $1,778, $705, and $433, respectively. Of the total interest incurred, the Company capitalized interest costs of $485, $705, and $279, for the years ended December 31, 2009, 2008, and 2007, respectively.

		Under the facility, the Company is subject to both financial and non-financial covenants. The financial covenants include maintaining (i) a current ratio, as defined, of at least 1.0 to 1.0, (ii) a ratio of earnings before interest, taxes, depreciation, depletion, amortization, exploration and other non-cash items (“EBITDAX”) to interest plus dividends, of greater than 1.5 to 1.0 and (iii) a funded debt to EBITDAX ratio of less than 3.5 to 1.0. As of December 31, 2009, the Company was in compliance with all financial covenants. If the covenants are violated, and the Company is unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.

		Effective February 5, 2010, the Company renegotiated its credit agreement primarily to extend the maturity date of the facility from July 31, 2010 to January 31, 2013. The borrowing availability on the facility will remain at $45 million. There were no material changes to any other terms of the credit facility, including our financial and non-financial covenants. The Company paid approximately $450 in one-time financing fees related to renegotiating this facility.

3		Acquisition of Petrosearch Energy Corporation

		On August 6, 2009 (“Effective Closing Date”), the Company acquired 100% of the common and preferred shares of Petrosearch in exchange for approximately 1.8 million shares of Double Eagle common stock, valued at approximately $7.3 million, and cash consideration of $873, for a total purchase price of approximately $8.1 million. Effective with the acquisition, each Petrosearch

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shareholder received .0433 shares of Double Eagle common stock and $0.0211 for each share of Petrosearch common stock and Petrosearch preferred stock, on an as converted basis, such shareholder held. As result of the merger, Petrosearch became a wholly-owned subsidiary of the Company. Richard Dole, who is and was, at the time of the merger, Chairman, President and Chief Executive Officer of Double Eagle and Petrosearch, will continue to serve as Chairman, President and Chief Executive Officer. The Board of Directors of Double Eagle will consist of five directors, four existing directors of Double Eagle and one future director to be designated by Petrosearch.

Petrosearch is an independent crude oil and natural gas exploration and production company, with properties in Texas and Oklahoma. Petrosearch had approximately $8,606 in cash and cash equivalents at the time of acquisition. The Company believes that the acquisition of Petrosearch has enhanced the Company’s ability to finance its current operations and future developmental projects, thereby providing an opportunity to increase reserves. Petrosearch contributed revenue of $79 and earnings of $(146) for the period from August 6 to December 31, 2009.

The aggregate purchase price is estimated as follows:


Aggregrate value of Double Eagle common stock issued	$	7,260
Cash consideration given to Petrosearch shareholders		873

Purchase Price	$	8,133

The acquisition of Petrosearch has been accounted for under the purchase method of accounting. Under the purchase method of accounting, the purchase price is allocated to the assets acquired and liabilities assumed based on their estimated fair values. The allocation of the purchase price has been estimated as follows:


Cash and cash equivalents	$	8,606
Accounts receivables, net of allowance		5
Prepaid expense & other current assets		134
Oil and gas properties		350
Goodwill		56
Accounts payable and other current liabilities		(378	)
Asset retirement obligation		(640	)

	$	8,133

		Of the total estimated purchase price, approximately $56 has been allocated to goodwill. Goodwill represents the excess of the purchase price of an acquired business over the fair value of the underlying net tangible and intangible assets. Goodwill is not amortized, rather, the goodwill will be tested for impairment, at least annually, or more frequently if there is an indication of impairment. The goodwill resulting from this acquisition is not deductible for tax purposes.

		Transaction costs related to the merger totaled $513, and are recorded on the Consolidated Statement of Operations within the general and administrative expenses line on the statement of operations.

		Supplemental Pro Forma Results (unaudited)

		The following pro forma financial information represents the combined results for the Company and Petrosearch for the years ended December 31, 2009 and 2008 as if the acquisition had occurred on January 1, 2009 and January 1, 2008. The pro forma financial information includes adjustments to reflect Petrosearch as if its crude oil and natural gas properties had been accounted for under the successful efforts method of accounting, not the full cost method of accounting. The pro forma financial information is not intended to represent or be indicative of the consolidated results of operations or financial condition of the

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Company that would have been reported had the acquisition been completed as of the dates presented, and should not be taken as representative of the future consolidated results of operations or financial condition of the Company.


	For the year ended December 31,
	2009			2008

Net revenues	$	44,847		$	50,978


Operating income	$	3,314		$	8,528


Net income (loss) attributable to common shareholders	$	(2,828	)	$	10,410


Basic and diluted net income (loss) per share	$	(0.28	)	$	0.95

4.		Income Taxes

		The provision for income taxes consists of:


	For the year ended December 31,
	2009		2008		2007

Current taxes	$	—	$	—	$	—
Deferred taxes		902		5,343		(6,143	)


Total income tax expense	$	902	$	5,343	$	(6,143	)

The tax effects of temporary differences that gave rise to the deferred tax liabilities and deferred tax assets as of December 31, 2009 and 2008 were:


	As of December 31,
	2009			2008

Deferred tax assets:
Net operating loss carry-forward	$	11,597		$	10,691
Asset retirement obligation		1,683			1,474
Share-based compensation		315			167
Accrued compensation		17			94
Derivative instruments		560			—
Net gas imbalance		53
Other		6			5

		14,231			12,431


Deferred tax liabilities:
Net gas imbalance		—			(32	)
Net basis difference in oil and gas properties		(18,852	)		(14,869	)

Net deferred tax asset (liability)	$	(4,621	)	$	(2,470	)

In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which the use of such net operating losses are allowed. Among other items, management considers the scheduled reversal of deferred tax liabilities, tax planning strategies and projected future taxable income.

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		At December 31, 2009, the Company had a net operating loss carry forward for regular income tax reporting purposes of approximately $32.8 million, which will begin expiring in 2021.

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


	For the year ended December 31,
	2009			2008
Expected federal tax rate		35.00	%		35.00	%
Effect of permanent differences		16.52	%		-1.06	%
State tax rate		0.02	%		0.04	%
Other		-8.84	%		0.00	%

Effective tax rate		42.70	%		33.98	%

		The ASC guidance requires that the Company evaluate all tax positions taken, and recognize a liability for any positions that are not more likely than not to be sustained by the tax authorities. The Company has not recorded any liabilities, or interest and penalties, as of December 31, 2009 related to uncertain tax positions.

		The Company files income tax returns in the U.S. and various state jurisdictions. There are currently no federal or state income tax examinations underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue Service for tax years before 2005 and for state and local tax authorities for years before 2004. The Company’s tax years of 2004 and forward are subject to examination by federal and state taxing authorities.

5.		Commitments and Contingencies

		Derivative Instruments

		To partially mitigate the Company’s exposure to adverse fluctuations in the prices of natural gas, the Company has entered into various derivative contracts. The terms of the Company’s hedging instruments are summarized as follows (volume and daily production are expressed in Mcf):

Contractual

Daily

Price

Type of Contract

Volume

Production

Term

Price

Index (1)

Fixed Price Swap

4,380,000

12,000

1/10-12/10

4.30

CIG

Costless Collar

2,885,000

5,000

8/09-7/11

$4.50 floor

NYMEX

$7.90 ceiling

Costless Collar

3,495,000

5,000

12/09-11/11

$4.50 floor

NYMEX

$9.00 ceiling

Fixed Price Swap

2,920,000

8,000

1/11-12/11

7.07

CIG

Total

13,680,000


(1)		NYMEX refers to quoted prices on the New York Mercantile Exchange. CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month.

Refer to Note 6 for additional information related to the accounting treatment of the Company’s derivative contracts.

Capital Lease Commitments

The Company leases certain compressor equipment in the Catalina Unit under a noncancelable, 36 month term lease agreement that is accounted for as a capital lease. The effective interest rate on the capital leases is 2.125%. The property under capital lease at both December 31, 2009 and 2008, totaled $1,600, and is included in the developed properties line on the balance sheet. Related accumulated depreciation was approximately $533 and $0 at December 31, 2009 and 2008, respectively. The amortization of the capital lease balance is recorded within DD&A expense on the Consolidated Statement of Operations.

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Future minimum lease payments under noncancelable capital leases at December 31, 2009 are as follows (in thousands):


	Lease
Year ending December 31,	Commitments
2010	$	753
2011		753

Total minimum lease payments	$	1,506

Less: Executory costs		400
Less: Amounts representing interest		40

Present value of minimum lease payments	$	1,066

		Operating Lease Commitments

		The Company has entered into an operating lease through August 2013 for approximately 3,900 square feet of office space in Denver, Colorado. In addition, the Company assumed two office leases as part of the Petrosearch acquisition, both of which expire in 2010. The Company also maintains operating leases on certain compressor equipment in the Catalina Unit and various pieces of office equipment in both the Casper and Denver offices. The total annual minimum lease payments for the next five years and thereafter are:


	Lease
Year ending December 31,	Commitments
2010		2,019
2011		1,972
2012		1,967
2013		1,401
2014 and thereafter		—

Total	$	7,359

Total expense from operating leases totaled $2,575, $419, and $62 in 2009, 2008 and 2007, respectively.

Litigation and Contingencies

From time to time, the Company is subject to litigation, claims and governmental and regulatory proceedings, including the matter discussed below. It is the opinion of the Company’s management that current claims and litigation involving the Company are not likely to have a material adverse effect on its consolidated financial position, cash flows or results of operations.

Through unitization, the Company acquired an interest in the Madden Sour Gas Participating Area in the Madden Deep Unit and the Lost Cabin Gas Processing Plant in late 2006, at a cost of approximately $2.5 million. The Madden Sour Gas Participating Area produced 10 Mcf net to our interest of gas in December 2007 from seven wells. These are long-lived wells with large producing rates and reserves. Double Eagle has a 0.349% working interest in the deep participating area.

The Company has not been paid any of the proceeds generated by the sale of gas produced from the Madden Deep Unit over the period beginning the effective date of the Unit through June 30, 2007. Double Eagle began receiving payments for its share of the sales on July 1, 2007. The Company, along with other plaintiffs, filed a lawsuit on August 24, 2007, in the District Court of Fremont County, Wyoming, against Conoco/Phillips and other defendants who own working interests in the Madden Deep Unit. The Company and the other plaintiffs in the case are asserting that, under the gas balancing agreement, they are entitled to receive either monetary damages or their respective shares of the gas produced from the Madden Deep Unit over at least the period February 1, 2002 through June 30, 2007. Sulfur sales are not subject to a gas balancing agreement, and, accordingly, the Company received the proceeds for its share of sulfur sales dating back to February 2002 and continues to receive its respective share on an on-going basis. The Company has recognized the sales and has recorded a related account receivable of $292, net of allowance for uncollectible amounts of $292, for the period November 1, 2006 through June 30, 2007. The ultimate outcome of this lawsuit cannot be determined at this time and, as a result, the Company has not recognized any amount of sales proceeds for the period February 1, 2002 through October 30, 2006.

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Derivative Instruments

The Company’s primary market exposure is to adverse fluctuations in the prices of natural gas. The Company uses derivative instruments, primarily forward sales, costless collars and swaps, to manage the price risk associated with equity gas production, and the resulting impact on cash flow, net income, and earnings per share. The Company does not use derivative instruments for speculative purposes.

The extent of the Company’s risk management activities is controlled through policies and procedures that involve senior management and were approved by the Company’s Board of Directors. Senior management is responsible for proposing equity hedge recommendations, execution of the approved hedging plan, oversight of the risk management process including methodologies used for valuation and risk measurement and presenting policy changes to the Board. The Company’s Board of Directors is responsible for approving risk management policies and for establishing the Company’s overall risk tolerance levels. The duration of the various derivative instruments depends on senior management’s view of market conditions, available contract prices and the Company’s operating strategy. Under the Company’s credit agreement, the Company can hedge up to 90% of the projected proved developed producing reserves for the next 12 month period, and up to 80% of the projected proved producing reserves for the ensuing 24 month period.

The Company recognizes its derivative instruments as either assets or liabilities at fair value on our consolidated balance sheet, except for certain instruments which qualify for accounting treatment exception under “normal purchases and normal sales”. See additional discussion of these instruments below. The Company accounts for the commodity forward contracts that do not qualify for this exception as either cash flow hedges or mark to market derivative instruments. On the cash flow statement, the cash flows from these instruments are classified as operating activities.

Derivative instruments expose the Company to counterparty credit risk. The Company enters into these contracts with third parties and financial institutions that it considers to be credit worthy. In addition, the Company’s master netting agreements reduce credit risk by permitting the Company to net settle for transactions with the same counterparty.

As with most derivative instruments, the Company’s derivative contracts contain provisions which may allow for another party to require security from the counterparty to ensure performance under the contract. The security may be in the form of, but not limited to, a letter of credit, security interest or a performance bond. None of the Company’s counterparties have required any type of security to be posted as of December 31, 2009.

Cash flow hedges

Derivative instruments that are designated and qualify as cash flow hedges are recorded at fair value on the balance sheet and the effective portion of the change in fair value is reported as a component of accumulated other comprehensive income (“AOCI”) and is subsequently reclassified into the oil and gas sales line on the consolidated statement of operations as the contracts settle. In order to qualify as cash flow hedges, the instruments must be designated as such and the changes in fair value must be highly correlated with the changes in price of our equity production. The Company formally documents the relationship between the derivative instruments and the hedged production, as well as the Company’s risk management objective and strategy for the particular derivative contracts. This process includes linking all derivatives that are designated as cash flow hedges to the specific forecasted sale of gas at its physical location as well as routinely evaluating the effectiveness of the cash flow hedges. The Company seeks to minimize the ineffectiveness of the cash flow hedges by entering into contracts indexed to regional index prices associated with pipelines in proximity to the Company’s areas of production. As the Company’s cash flow hedges contain the same index as the Company’s sales contracts; this results in hedges that are highly correlated with the underlying hedged item

Mark to market hedging instruments

Unrealized gains and losses resulting from derivatives not designated as cash flow hedges are recorded at fair value on the balance sheet and changes in fair value are recognized in the price risk management activities line on the consolidated statement of operations currently. Realized gains and losses resulting from the contract settlement of derivatives not designated as cash flow hedges also are recorded in the price risk management activities line on the consolidated statement of operations.

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The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of December 31, 2009, presented gross of any master netting arrangements:


Derivatives designated as hedging
instruments under ASC 815	Balance Sheet Location	Fair Value
Assets
Commodity derivatives	Assets from price risk management — long term		3,566

Total		$	3,566


Derivatives not designated as
hedging instruments under ASC 815	Balance Sheet Location	Fair Value
Assets
Commodity derivatives	Liabilities from price risk management — current	$	105
Liabilities
Commodity derivatives	Liabilities from price risk management — current		(4,844	)
	Liabilities from price risk management — long term		(430	)

Total		$	(5,169	)

The before-tax effect of derivative instruments in cash flow hedging relationships on the consolidated statement of operations for the year ended December 31, 2009 was as follows:

Location of Gain

Gain (Loss)

Recognized in Income

Recognized in OCI¹

Gain Reclassified

(Ineffective Portion and

on Derivative

from Accumulated

Amount Excluded from

(effective portion)

Location

OCI¹into Income

Effectiveness testing)

Cash flow hedges:

Commodity contracts

2,616

Oil and gas sales

15,740

N/A


		¹ Other comprehensive income (“OCI”).

The before-tax effect of derivative instruments not designated as hedging instruments on the consolidated statement of operations for the year ended December 31, 2009 was as follows:


	Loss Recognized in
	Income on
Location	Derivative
Price risk management activites	$	(4,295	)

Normal purchases and normal sales

During the year ended December 31, 2009, the Company had fixed delivery contracts for production from Sun Dog and Doty Mountain at the Atlantic Rim and the Pinedale Anticline that qualified for accounting under the normal purchases and normal sales exception. Physical delivery contracts may meet the criteria for this accounting exception so long as it is probable both at inception and throughout the life of the contract that the contract will result in physical delivery and will not net settle. Under the normal purchases and normal sales accounting treatment, the Company records the revenue upon contract settlement in oil and

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gas sales on the consolidated statement of operations. All of the Company’s contracts that qualified for this treatment had settled prior to December 31, 2009.

Refer to Note 6 for additional information regarding the valuation of the Company’s derivative instruments, and Note 5 for the listing of the current contracts the Company had in place as of December 31, 2009.

7. Fair Value of Financial Instruments

The Company records certain of its assets and liabilities on the balance sheet at fair value. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). A three-level valuation hierarchy has been established to allow readers to understand the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:

	•		Level 1 — Quoted prices (unadjusted) for identical assets or liabilities in active markets.

	•		Level 2 — Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; and model-derived valuations whose inputs or significant value drivers are observable.

	•		Level 3 — Unobservable inputs that reflect the Company’s own assumptions.

The following describes the valuation methodologies the Company uses for its fair value measurements.

Cash and cash equivalents

Cash and cash equivalents include all cash balances and any highly liquid investments with an original maturity of 90 days or less. The carrying amount approximates fair value because of the short maturity of these instruments.

Derivative instruments

The Company considers several factors in determining its estimate of fair value, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit rating. The Company also performs an internal valuation to ensure the reasonableness of third-party quotes.

At December 31, 2009, the types of derivative instruments utilized by the Company included costless collars and swaps. The natural gas derivative markets are highly active. Although the Company’s cash flow and economic hedges are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

Credit facility

The recorded value of the Company’s credit facility approximates fair value as it bears interest at a floating rate.

Asset retirement obligations

The Company recognizes an estimated liability for future costs associated with the abandonment of our oil and gas properties. The Company’s asset retirement obligation is measured using primarily Level 3 inputs. The significant unobservable inputs include the cost of abandoning oil and gas wells, which is based on the Company’s historical experience for similar work, and estimates from

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independent third parties, the economic lives of our properties, the inflation rate, and the credit adjusted risk-free rate. The Company bases its estimate of the liability on its historical experience and current estimated costs.

The following table provides a summary of the fair values of assets and liabilities measured at fair value:


	Level 1		Level 2		Level 3		Total


Assets
Derivative instruments	$	—	$	3,566	$	—	$	3,566

Total assets at fair value	$	—	$	3,566	$	—	$	3,566


Liabilities
Derivative instruments	$	—	$	5,169	$	—	$	5,169
Asset retirement obligation	$	—				4,807	$	4,807

Total liabilities at fair value	$	—	$	5,169	$	4,807	$	9,976

Refer to Note 1 for the Level 3 rollforward of the asset retirement obligation.

Series A Cumulative Preferred Stock

In 2007, the shareholders of the Company amended the Company’s Articles of Incorporation to allow for the issuance of 10,000,000 shares of preferred stock, and subsequently completed a public offering of 1,610,000 shares of 9.25% Series A Cumulative Preferred Stock at a price to the public of $25.00 per share.

Holders of the Series A Preferred Stock are entitled to receive, when and as declared by the Board of Directors, dividends at a rate of 9.25% per annum ($2.3125 per annum per share). The Series A Preferred Stock does not have any stated maturity date and will not be subject to any sinking fund or mandatory redemption provisions, except, under some circumstances upon a Change of Ownership or Control. Except pursuant to the special redemption upon a Change of Ownership or Control, the Company may not redeem the Series A Preferred Stock prior to June 30, 2012. On or after June 30, 2012, the Company may redeem the Series A Preferred Stock for cash at our option, in whole or from time to time in part, at a redemption price of $25.00 per share, plus accrued and unpaid dividends (whether or not earned or declared) to the redemption date. The shares of Series A Preferred Stock are classified outside of permanent equity on the accompanying Consolidated Balance Sheets due to the following redemption provision. Following a Change of Ownership or Control of us by a person or entity, other than by a “Qualifying Public Company,” the Company will be required to redeem the Series A Preferred Stock within 90 days after the date on which the Change of Ownership or Control occurred for cash, at the following price per share, plus accrued and unpaid dividends.


Redemption Date on or Before	Redemption Price
June 30, 2010	$	25.50
June 30, 2011	$	25.25
June 30, 2012 or thereafter	$	25.00

In the event of liquidation, the holders of the Series A Preferred Stock will have the right to receive $25.00 per share, plus all accrued and unpaid dividends, before any payments are made to the holders or our common stock.

Holders of the Series A Preferred Stock will generally have no voting rights. However, if cash dividends on any outstanding Series A Preferred Stock are in arrears for any six consecutive or non-consecutive quarterly dividend periods, or if Double Eagle fails to maintain a national market listing, the holders of the Series A Preferred Stock, voting separately as a class, will have the right to elect two directors to serve on our board of directors in addition to those directors then serving on our board until such time as the national market listing is obtained or the dividend arrearage is eliminated.

Compensation Plans

Double Eagle has outstanding stock options issued to employees under various stock option plans, approved by the Company’s stockholders (collectively “the Plans”). The options have been granted with an exercise price equal to the market price of Double

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Eagle’s stock on the date of grant, vest annually over various periods from two to five years of continuous service, and expire over various periods up to ten years from the date of grant. As of December 31, 2009, there were 14,500 and 33,099 options available for grant under the 2002 and 2003 Stock Option Plans, respectively.

In 2007, the Company’s shareholders approved the 2007 Stock Incentive Plan (“2007 Plan”), which allows both stock options and stock awards to be granted to the Company’s employees, directors, consultants, and other persons designated by the Compensation Committee of the Board of Directors. In 2008, the Company began granting stock awards and stock options under this plan. These awards vest annually over various periods of three to five years of continuous service. As of December 31, 2009, there were 90,767 shares available for grant under the 2007 Plan.

The Company accounts for its stock compensation in accordance with the provisions of ASC 718, which requires the measurement and recognition of compensation expense for all share-based payment awards (including stock options and stock awards) made to employees and directors based on estimated fair value. During the years ended December 31, 2009, 2008 and 2007, total share-based compensation expense for equity-classified awards, was $1,484, $1,178 and $552, respectively, and is reflected in general and administrative expense in the Consolidated Statement of Operations.

Stock Options

The Company uses the Black-Scholes valuation model to determine the fair value of each option award. Expected volatilities are based on the historical volatility of Double Eagle’s stock over a period consistent with that of the expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in Double Eagle’s stock price and historical exercise behavior. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms.

Assumptions used in estimating fair value of share-based awards for the periods indicated:


	For the year ended December 31,
	2009			2008			2007
Weighted-average volatility		51	%		40 - 41	%		42	%
Expected dividends		0.00	%		0.00	%		0.00	%
Expected term (in years)		5			4.5			4.25
Risk-free rate		1.72	%		2.42% - 3	%		4.58	%
Expected forfeiture rate		7.00	%		5% - 7	%		7.00	%

Summary of option activity during the year ended December 31, 2009:


						Weighted-Average
						Remaining
				Weighted-Average		Contractual Term		Aggregate
Options:	Shares			Exercise Price		(in years)		Intrinsic Value
Outstanding at January 1, 2009		626,897		$	15.68		5.1
Granted		50,500		$	7.79
Exercised		—		$	—
Cancelled/expired		(29,500	)	$	15.83

Outstanding at December 31, 2009		647,897		$	15.06		4.7	$	—


Exerciseable at December 31, 2009		281,359		$	12.77		3.7	$	—

The weighted average grant date fair value price per share of options granted during the three years ended December 31, 2009, 2008, and 2007 was $7.79, $14.91, and $17.86, respectively. No options were exercised during 2009. During the years ended December

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31, 2008, and 2007, the total intrinsic value, or the difference between the exercise price and the market price on the date of exercise, of all options exercised was $276 and $150. As of December 31, 2009, 2008, and 2007, the fair value of options vested and exercisable was $0, $0, and $2,255.

Stock options outstanding and currently exercisable at December 31, 2009 are:


			Options				Options Exercisable
			Outstanding
			Weighted Average		Weighted				Weighted
	Number of		Remaining		Average		Number of		Average
Range of Exercise	Options		Contractual Life		Exercise Price		Options		Exercise Price
Prices per Share	Outstanding		(in years)		per Share		Exercisable		per Share
$6.78 - $7.79		65,500		6.8	$	7.60		3,000	$	6.94
$14.00 - $16.21		420,897		5.3	$	14.70		191,359	$	10.34
$17.86 - $19.55		134,000		2.4	$	18.55		70,500	$	17.61
$20.21 - $23.61		27,500		2.5	$	21.30		16,500	$	21.30

		647,897		4.7	$	15.06		281,359	$	12.77

As of December 31, 2009, there was $1,637 of total unrecognized stock-based compensation expense related to stock options to be recognized over a weighted-average period of 2.89 years.

Stock awards

The Company measures the fair value of the stock awards based upon the fair market value of its common stock on the date of grant and recognize the resulting compensation expense ratably over the associated service period, which is generally the vesting term of the stock awards. The Company recognizes these compensation costs net of a forfeiture rate, if applicable, and recognize the compensation costs for only those shares expected to vest. The forfeiture rates are based on historical experience, while also considering the duration of the vesting term of the award.

Nonvested stock awards as of December 31, 2009 and changes for the year ended December 31, 2009 were as follows:


				Weighted-
				Average Grant
Stock Awards:	Shares			Date Fair Value
Outstanding at January 1, 2009		94,762		$	14.70
Granted		105,837		$	4.22
Vested		(113,151	)	$	6.69
Forfeitures		—		$	—

Nonvested at December 31, 2009		87,448		$	12.38

As of December 31, 2009, there was $1,017 of unrecognized stock-based compensation expense related to nonvested stock awards. This cost is expected to be recognized over a weighted-average period of 3.7 years.

As part of the acquisition of Petrosearch, the Company assumed all outstanding warrants to purchase common stock that had been issued by Petrosearch prior to the merger. At December 31, 2009, the Company had three tranches of warrants outstanding; 14,691 warrants with an exercise price of $46.19 that expire in February 2010; 10,310 warrants with an exercise price of $34.64 that expire November 2010; and 8,660 warrants with an exercise price of $21.25 that expire December 2011. The warrants had no intrinsic value at December 31, 2009.

F-23

10.		Subsequent Events

		Effective February 5, 2010, the Company entered into an amended and restated credit agreement with its lenders, primarily to extend the maturity date of the facility from July 31, 2010 to January 31, 2013. No other material changes were made to the agreement. In accordance with ASC 470, the Company reclassified its credit facility balance from a current liability to a long-term liability on the Consolidated Balance Sheet as of December 31, 2009.

		The Company has noted no additional events, other than noted above, that require recognition or disclosure at December 31, 2009.

11.		Supplemental Information on Oil and Gas Producing 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, 2009, 2008 and 2007 are:


	As of December 31,
	2009			2008			2007

Developed properties	$	165,279		$	133,516		$	61,394
Wells in progress		7,544			18,518			29,768
Undeveloped properties		2,502			2,907			3,147

		175,325			154,941			94,309
Accumulated depletion and amortization		(52,041	)		(33,905	)		(22,218	)

Net capitalized costs	$	123,284		$	121,036		$	72,091

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

		Costs incurred in property acquisitions, exploration, and development activities for the years ended December 31, 2009, 2008 and 2007 were:


	For the year ended December 31,
	2009		2008		2007

Property acquisitions — unproved	$	16	$	30	$	316
Exploration		59		536		3,600
Development		21,466		64,462		41,337

Total	$	21,541	$	65,028	$	45,253

F-24

		Results of Operations from Oil and Gas Producing Activities

		The table below shows the results of operations for the Company’s oil and gas producing activities for the years ended December 31, 2009, 2008 and 2007. All production is from within the continental United States.


	For the year ended December 31,
	2009		2008		2007

Operating revenues (1)	$	45,901	$	41,847	$	16,044
Costs and expenses:
Production		11,406		11,708		7,629
Exploration		103		911		15,399
Depletion, amortization and impairment		18,136		11,078		6,691

Total costs and expenses		29,645		23,697		29,719

Income (loss) before income taxes		16,256		18,150		(13,675	)
Income tax expense		5,693		6,356		(4,789	)

Results of operations	$	10,563	$	11,794	$	(8,886	)


(1)		Operating revenues are comprised of the oil and gas sales from the Consolidated Statement of Operations, plus settlements on the Company’s financial hedges during the period. For the years ended December 31, 2009, 2008 and 2007, the settlements on derivatives totaled $3,503, $2,698, and $0, respectively.

		Oil and Gas Reserves (Unaudited)

		The reserves at December 31, 2009, 2008 and 2007 presented below were reviewed by the independent engineering firm, Netherland, Sewell & Associates, Inc. All reserves are located within the continental United States. The reserve estimates are developed using geological and engineering data and interests and burden information developed by the Company. Reserve estimates are inherently imprecise and are continually subject to revisions based on production history, results of additional exploration and development, prices of oil and gas, and other factors.

		Estimated net quantities of proved developed reserves of oil and gas for the years ended December 31, 2009, 2008, and 2007 are:


	For the year ended December 31,
	2009						2008						2007
	Oil			Gas			Oil			Gas			Oil			Gas
	(Bbl)			(Mcf)			(Bbl)			(Mcf)			(Bbl)			(Mcf)

Beginning of year		420,189			86,330,820			412,812			71,253,865			360,165			48,496,719
Revisions of estimates		(42,417	)		(9,323,380	)		(33,439	)		(4,637,562	)		(112,093	)		(18,449,972	)
Extensions and discoveries		61,932			21,931,592			65,429			26,244,840			178,208			44,135,456
Purchases of reserves		8,436			—			—			—			—			—
Production		(28,927	)	(9,162,362		)		(24,613	)		(6,530,323	)		(13,468	)		(2,928,338	)

End of year		419,213			89,776,670			420,189			86,330,820			412,812			71,253,865

Proved developed reserves		287,276			64,195,169			295,698			63,007,126			253,478			44,782,553

Percentage of proved developed reserves		69	%		72	%		70	%		73	%		61	%		63	%

As of December 31, 2009, the Company had estimated proved reserves of 89.8 Bcf of natural gas and 419 MBbl of oil, or a total of 92.3 Bcfe. The proved reserves were estimated in accordance with ASC 2010-3, which updated the guidance for reporting oil and gas reserves to align the oil and gas reserve estimation and disclosure requirements with the requirements in the SEC’s final rule, Modernization of the Oil and Gas Reporting Requirements. The new reserve guidance changed the pricing methodology used to estimate reserves to an average, first-day-of-the-month price based on the prior 12-month period. For the year ended December 31, 2008 and 2007, however, pricing was based upon the price on the last day of the fiscal year. Using this change in price determination, the average natural gas price used in calculating the December 31, 2009 reserves decreased to $3.04 per

F-25

MMBtu from the December 31, 2008 price of $4.61 MMBtu. The decrease in price shortened the economic life of certain existing wells and caused a downward revision in reserves. If the Company had used the prior-year pricing methodology for its calculation of its 2009 estimated proved reserves, the Company would have reported higher proved reserves of approximately 21.9 Bcfe. In addition, ASC 2010-3 allows for more than a one well offset from proved reserves in well-defined fields. This provided additional reserves in the Catalina Unit and Mesa Unit.

As of December 31, 2009, 76% of the proved developed gas reserves and 100% of the proved developed oil reserves were in producing status.


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

		The following information has been developed utilizing procedures prescribed by ASC 932 Extractive Activities — Oil and Gas, and is based on natural gas and crude oil reserves and production volumes estimated by the Company. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative or realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.

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

		Under the Standardized Measure, for the year ended December 31, 2009, future cash inflows were estimated by applying the new SEC 12-month average pricing of oil and gas relating to the Company’s proved reserves to the year-end quantities of those reserves. For the years ended December 31, 2008 and 2007, future cash inflows were computed by applying the former SEC end of year pricing of oil and gas relating to the Company’s proved reserves to the year-end quantities of those reserves. Future cash inflows were reduced by estimated future development and production costs based upon year-end costs in order to arrive at net cash flow before tax. Future income tax expense has been computed by applying year-end statutory rates to future pretax net cash flows and the utilization of net operating loss carry-forwards.

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


		Information with respect to the Company’s Standardized Measure:


	As of December 31,
	2009			2008			2007

Future cash inflows	$	276,374		$	406,017		$	462,655
Future production costs		(105,161	)		(118,299	)		(102,515	)
Future development costs		(16,777	)		(18,275	)		(23,651	)
Future income taxes		(14,279	)		(58,313	)		(96,370	)

Future net cash flows		140,157			211,130			240,119
10% annual discount		(57,450	)		(89,075	)		109,820

Standardized measure of discounted future net cash flows	$	82,707		$	122,055		$	130,299

F-26

Principal changes in the Standardized Measure for the years ended December 31, 2009, 2008 and 2007:


	2009			2008			2007

Standard measure, as of January 1,	$	122,055		$	130,299		$	50,033
Sales of oil and gas produced, net of production costs		(30,992	)		(26,846	)		(8,416	)
Extensions and discoveries		22,506			49,511			118,002
Net change in prices and production costs related to future production		(62,838	)		(63,682	)		41,821
Development costs incurred during the year		13,043			11,181			9,924
Changes in estimated future development costs		(3,516	)		(5,188	)		(24,107	)
Purchases of reserves in place		201			—			—
Revisions of quantity estimates		(10,460	)		(9,119	)		(50,750	)
Accretion of discount		13,257			15,919			6,764
Net change in income taxes		25,285			18,576			(18,064	)
Changes in timing and other		(5,834	)		1,404			5,092

Aggregate Change		(39,348	)		(8,244	)		80,266

Standardized measure, as of December 31,	$	82,707		$	122,055		$	130,299

12.		Quarterly Financial Data (Unaudited)

		Summary of the unaudited financial data for each quarter for the years ended December 31, 2009 and 2008 (in thousands except per share data):


	Fourth						Second			First
	Quarter			Third Quarter			Quarter			Quarter
Year ended December 31, 2009
Oil and gas sales	$	11,737		$	9,669		$	10,492		$	10,500
Income from operations	$	1,705		$	641		$	(352	)	$	1,890
Net income	$	28		$	416		$	(242	)	$	1,007
Net income (loss) attributable to common stock	$	(903	)	$	(514	)	$	(1,173	)	$	76
Basic net income per common share	$	(0.08	)	$	(0.05	)	$	(0.13	)	$	0.01
Diluted net income per common share	$	(0.08	)	$	(0.05	)	$	(0.13	)	$	0.01

Year ended December 31, 2008
Oil and gas sales (1)	$	9,710		$	11,662		$	10,981		$	6,796
Income from operations	$	3,287		$	4,464		$	5,189		$	3,009
Net income	$	2,338		$	2,907		$	3,273		$	1,863
Net income attributable to common stock	$	1,407		$	1,977		$	2,342		$	932
Basic net income per common share	$	0.15		$	0.22		$	0.26		$	0.10
Diluted net income per common share	$	0.15		$	0.22		$	0.26		$	0.10

F-27


		PAGE
	PART I
Items 1. and 2.	Business and Properties		3
	General		3
	Overview and Strategy		3
	Operations		4
	Reserves		9
	Production		12
	Derivative Instruments		12
	Productive Wells		13
	Drilling Activity		13
	Finding and Development Costs		14
	Acreage		15
	Other Significant Developments Since December 31, 2008		15
	Marketing and Major Customers		16
	Title to Properties		16
	Seasonality		16
	Competition		16
	Government Regulations		17
	Cautionary Information About Forward-looking Statements		18
	Employees and Office Space		19
	Available Information		19
	Glossary		20
Item 1A.	Risk Factors		21
Item 3.	Legal Proceedings		28
Item 4.	Reserved		28

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		29
Item 6.	Selected Financial Data		32
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		32
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		48
Item 8.	Financial Statements and Supplementary Data		49
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		49
Item 9A.	Controls and Procedures		49
Item 9B.	Other Information		52

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance		52
Item 11.	Executive Compensation		52
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		52
Item 13.	Certain Relationships and Related Transactions		52
Item 14.	Principal Accountant Fees and Services		52

	PART IV

Item 15.	Exhibits and Financial Statement Schedules		53
EX-21.1
EX-23.1
EX-23.2
EX-31.1
EX-31.2
EX-32
EX-99.1


Date: March 4, 2010		/s/ Richard Dole

		Richard Dole
		Chief Executive Officer

Date: March 4, 2010		/s/ Kurtis S. Hooley

		Kurtis S. Hooley
		Chief Financial Officer



Date:March 4, 2010		/s/ Richard Dole

		Principal Executive Officer
		Chief Executive Officer

Date:March 4, 2010		/s/ Kurtis S. Hooley

		Chief Financial Officer
		Principal Accounting Officer

Date: March 4, 2010		/s/ Sigmund Balaban

		Sigmund Balaban, Director

Date: March 4, 2010		/s/ Roy G. Cohee

		Roy G. Cohee, Director

Date: March 4, 2010		/s/ Brent Hathaway

		Brent Hathaway, Director


Name of Subsidiary		Relationship

1)	Eastern Washakie Midstream Pipeline LLC, a Wyoming LLC	Wholly owned subsidiary of Double Eagle Petroleum Co.

2)	Petrosearch Energy Corporation , a Nevada Corporation	Wholly owned subsidiary of Double Eagle Petroleum Co.

3)	Petrosearch Operating Company, LLC , a Texas LLC	Wholly owned subsidiary of Double Eagle Petroleum Co.

4)	Wilcox Petrosearch, LLC a Texas LLC	Wholly owned subsidiary of Double Eagle Petroleum Co.

5)	Anadarko Petrosearch, LLC a Texas LLC	Wholly owned subsidiary of Double Eagle Petroleum Co.

6)	Barnett Petrosearch, LLC a Texas LLC	Wholly owned subsidiary of Double Eagle Petroleum Co.

7)	Beacon Petrosearch, LLC a Texas LLC	Wholly owned subsidiary of Double Eagle Petroleum Co.

8)	Guidance Petrosearch, LLC a Texas LLC	Wholly owned subsidiary of Double Eagle Petroleum Co.


	NETHERLAND, SEWELL & ASSOCIATES, INC.
	By:	/s/ C.H. (Scott) Rees III, P.E.
		C.H. (Scott) Rees III, P.E.
		Chairman and Chief Executive Officer

	1.		I have reviewed this annual report on Form 10-K of Double Eagle Petroleum Co.;

	2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

	3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

	4.		The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 11a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 11a-15(f) and 15d-15(f)) for the registrant and have:

	(a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	(b)		Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

	(c)		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	(d)		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	a)		All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


	Chairman & CEO	Executive Committee
	C.H. (Scott) Rees III	P. Scott Frost - Dallas
	President & COO	J. Carter Henson, Jr. - Houston
	Danny D. Simmons	dan Paul Smith - Dallas
WORLDWIDE PETROLEUM CONSULTANTS	Executive VP	Joseph J. Spellman - Dallas
ENGINEERING • GEOLOGY • GEOPHYSICS • PETROPHYSICS	G lance Binder	Thomas J. Tella II — Dallas


	Net Reserves				Future Net Revenue (M$)
Category	Oil (MBBL)		Gas (MMCF)		Total		Present Worth at 10%

Proved Developed Producing		287.3		48,965.9		90,250.1		62,759.4
Proved Developed Non-Producing		0.0		15,229.3		23,804.1		15,672.5
Proved Undeveloped		106.3		25,479.7		39,060.2		11,791.0

Total Proved		393.5		89,674.9		153,114.4		90,222.9



4500 Thanksgiving Tower • 1601 Elm Street • Dallas, Texas 75201-4754 • Ph: 214-969-5401 • Fax: 214-969-5411		nsai@nsai-petro.com
1221 Lamar Street, Suite 1200 • Houston, Texas 77010-3072 • Ph: 713-654-4950 • Fax: 713-654-4951		netherlandsewell.com


	Sincerely, NETHERLAND, SEWELL & ASSOCIATES, INC. Texas Registered Engineering Firm F-002699
	By:	/s/ C.H. (Scott) Rees III
		C.H. (Scott) Rees III, P.E.
		Chairman and Chief Executive Officer


By:	/s/ David T. Miller	By:	/s/ John G. Hattner

	David T. Miller, P.E. 96134		John G. Hattner, P.G. 559
	Vice President		Senior Vice President

	Date Signed: January 28, 2010		Date Signed: January 28, 2010

	(i)		Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

	(ii)		Same environment of deposition;

	(iii)		Similar geological structure; and

	(iv)		Same drive mechanism.

	(i)		Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

	(ii)		Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

	(i)		Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

	(ii)		Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

	(iii)		Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

	(iv)		Provide improved recovery systems.

	(i)		Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs.

	(ii)		Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

	(iii)		Dry hole contributions and bottom hole contributions.

	(iv)		Costs of drilling and equipping exploratory wells.

	(v)		Costs of drilling exploratory-type stratigraphic test wells.

	(A)		The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

	(B)		The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

	(C)		The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

	(1)		Lifting the oil and gas to the surface; and

	(2)		Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

	a.		The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

	b.		In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

	(A)		Transporting, refining, or marketing oil and gas;

	(B)		Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

	(C)		Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

	(D)		Production of geothermal steam.

	(i)		When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

	(ii)		Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

	(iii)		Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

	(iv)		The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

	(v)		Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

	(vi)		Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

	(ii)		Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

	(iii)		Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

	(iv)		See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

	(A)		Costs of labor to operate the wells and related equipment and facilities.

	(B)		Repairs and maintenance.

	(C)		Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

	(D)		Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

	(E)		Severance taxes.

	(A)		The area identified by drilling and limited by fluid contacts, if any, and

	(B)		Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

	(ii)		In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

	(iii)		Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

	(iv)		Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

			reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

	(B)		The project has been approved for development by all necessary parties and entities, including governmental entities.

	a.		Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

	b.		Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

	a.		Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

	b.		Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

	c.		Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves.

	d.		Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.