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

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.

(Exact 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

(303) 794-8445

Securities registered pursuant to Section 12(b) of the Act: 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405), is not contained herein, and will not be contained 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 (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 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 o		Small reporting company þ
				(Do not check if a small reporting company)

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 in the 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, 2010, was $45,880,306 (directors, officers and 10% shareholders are considered affiliates).

The number of shares of the registrant’s common stock outstanding as of March 1, 2011 was 11,178,459.

Portions of the registrant’s definitive proxy statement for the 2011 annual meeting of stockholders, which will be filed within 120 days after December 31, 2010, are incorporated by reference in Part III of this Form 10-K.

 

 

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

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

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 factors:

•

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

•

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

•

Our ability to increase our natural gas and oil reserves;

•

Our ability to market and find reliable and economic transportation for our gas;

•

The changing political environment in which we operate;

•

Our ability and the ability of our partners to continue to develop the Atlantic Rim project;

•

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

•

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

•

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

•

Incorrect estimates of required capital expenditures;

•

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

•

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

•

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

•

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

•

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

•

The credit worthiness of third parties with which we enter into hedging and business agreements with;

•

Weather, climate change and other natural phenomena;

•

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

•

The volatility of our stock price;

•

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

•

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

•

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

•

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

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.

The terms “Double Eagle”, the “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, 2010 (the “Form 10-K”). 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. We were incorporated in Wyoming in 1972 and reincorporated in Maryland in 2001. From 1995 to 2006, our common stock was publicly traded on the NASDAQ Capital Market under the symbol “DBLE”. In December 2006 our common stock began trading on the NASDAQ Global Select Market under the same symbol. Our Series A Cumulative Preferred Stock (“Preferred Stock”) was issued on the NASDAQ Capital Market under the symbol “DBLEP” in July 2007 and began trading on the NASDAQ Global Select Market in September 2007. Our corporate offices are located at 1675 Broadway, Suite 2200, Denver, Colorado 80202, telephone number (303) 794-8445. Our website is www.dble.com.

Overview and Strategy

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 in the Green River Basin in Wyoming. During 2010, we allocated a portion of our capital resources to acquiring acreage with mineral rights in the Niobrara formation in anticipation of beginning an exploration project in 2011. At December 31, 2010, we had over 70,000 net acres in an area that we believe has Niobrara formation exposure, located primarily in Wyoming and Western Nebraska.

Our objective is to increase shareholder value by profitably growing our reserves, production, revenues, and cash flow by focusing primarily on: (i) new coal bed methane gas development drilling; (ii) enhancement of existing production wells and field facilities on operated and non-operated properties in the Atlantic Rim; (iii) continued participation in the development of tight sands gas wells at the Mesa Fields on the Pinedale Anticline; (iv) expansion of our midstream business; v) pursuit of high quality exploration and strategic development projects with potential for providing long-term drilling inventories that generate high returns, including the Niobrara formation in the Atlantic Rim and other properties in which we have interest and (vi) selectively pursuing strategic acquisitions.

Substantially all of our revenues are generated through the sale of natural gas and oil production at market prices and the settlement of commodity hedges. Approximately 98% of our 2010 production volume was natural gas.

As of December 31, 2010, we had estimated proved reserves of 112.8 Bcf of natural gas and 381 MBbl of oil, or a total of 115.1 Bcfe. This represents a net increase in reserve quantities of 25% from the prior year, after adjustments for extensions and discoveries, current year production and revision of estimates. The increase in estimated proved reserves as compared to the prior year is attributable to the following:

	•		15.3 Bcfe of reserve additions attributed to the purchase of additional working interest in the Atlantic Rim properties, completed in July 2010.
	•		Extensions and discoveries totaling 17.0 Bcfe of reserves as the result of organic growth from development drilling in the Pinedale Anticline. Improved pricing allowed us to add new proved undeveloped reserves from wells in this area that had previously been uneconomic.

The proved oil and gas reserves at December 31, 2010 had a PV-10 value of approximately $143.7 million, an increase of 58% from 2009 primarily due to improved pricing. The average price used in calculating the December 31, 2010 reserves increased by $0.91, or 30%, to $3.95 per MMBtu from the December 31, 2009 price of $3.04 MMBtu. We also experienced an increase due to extensions and discoveries and our purchase of additional Atlantic Rim working interest, as noted above. (See the reconciliation of the PV-10 non-GAAP financial measure to the standardized measure under Reserves on page 9). Of these proved reserves, 65% were proved developed and 98% were natural gas.

During 2010, we invested $21.5 million in capital expenditures related to the development of our existing properties, as compared to $21.1 million in 2009. The focus of the capital expenditures was primarily on non-operated drilling on the Pinedale Anticline, where we have historically had a high rate of return, and on our acquisition of additional working interests in the Atlantic Rim at a total cost of $8.4 million. See Other Significant Developments since December 31, 2009 on page 15 for additional information related to this purchase. We also used a portion of our 2010 capital budget on well enhancement projects within the Catalina Unit and at the non-operated Sun Dog and Doty Mountain units. Finally, we allocated a portion of our capital expenditure to acquiring acreage with mineral rights in the Niobrara formation in anticipation of beginning an exploration project in 2011.

We continually assess projects that are currently in progress and those proposed for future development to determine the best use for our available capital. This assessment includes analyzing the risk and estimated rate of return for each proposed project, including our non-operated assets (primarily the Pinedale Anticline and the Doty Mountain and Sun Dog Units in the Atlantic Rim). Our estimated capital budget for 2011 is approximately $20 to $30 million, primarily for our development and exploration programs in the Atlantic Rim and Pinedale Anticline. We intend to recommence development drilling in the Atlantic Rim in the second half of 2011, with up to 20 coal bed methane (“CBM”) production wells within the Catalina Unit. We also plan to participate in any drilling by the operator within the Sun Dog and Doty Mountain Units and approximately 12 to 16 new wells at the Mesa Units. We also have allocated capital in our 2011 capital budget for one or more exploratory wells into the Niobrara formation in the Atlantic Rim.

We 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, enter into strategic partnerships or form joint ventures related to our assets that are not currently considered in our expected 2011 capital expenditures.

Operations

As of December 31, 2010, we owned interests in over 1,200 producing wells and had an acreage position of 405,906 gross acres (157,002 net), of which 264,631 gross acres (143,147 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 92% of our proved reserves as of December 31, 2010, and 94% of our 2010 production.

As of December 31, 2010, our estimated acreage holdings by basin are:

Basin		Gross Acres				Net Acres
Washakie Basin			140,064				57,112
Wind River Basin			51,026				3,043
Powder River Basin			48,051				18,074
Utah Overthrust			46,440				21,146
Greater Green River Basin			38,530				3,264
Huntington Basin			36,045				30,264
Other			45,750				24,099
Total			405,906				157,002

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 99,512 gross acres (46,716 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.

In May 2007, a Record of Decision on the Atlantic Rim Environmental Impact Statement (“EIS”), was issued. 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.

During 2010, we recognized net sales volumes from the coal bed natural gas projects in the Atlantic Rim of 6.7 Bcfe, which represented 73% of our total 2010 natural gas equivalent sales volume. The wells have historically been economic, and we intend to continue to focus our efforts on the drilling of up to 20 CBM wells in the Catalina Unit in 2011. We also plan to participate in any wells drilled by Anadarko Petroleum Corporation (“Anadarko”), the operator of the Doty Mountain and Sun Dog Units, within these units.

Catalina Unit

The Catalina Unit consists of 21,725 total acres (9,134 net acres) that the Company operates. Our development of the Catalina Unit began in 2007 with the 14 original producing wells in the Cow Creek Field and has expanded to 70 production wells as of December 31, 2010.

In September 2009, we began a well-enhancement program within the Catalina Unit that continued throughout 2010. As part of this program, we performed workovers on approximately 30 existing wells that had experienced production declines over the past year. The workovers have resulted in the stabilization of production and better overall operation of the wells.

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 24 new wells in 2008, our working interest in the Catalina Unit decreased to 69.31%. We acquired additional working interest in the Catalina Unit in 2010 from a third party, which increased our working interest to 72.40% (refer to page 15 for additional information on this working interest purchase). The Company anticipates that our working interest will decrease to approximately 60% upon completion of the 2011 drilling program. As we continue to expand the Catalina Unit, our working interest will continue to change. We anticipate our working interest will be approximately 51% upon the planned development of the existing acreage.

Production in the Catalina Unit resulted in net sales volumes to us of 5.4 Bcf in 2010 (compared to 5.9 Bcf in 2009 and 4.0 Bcf in 2008), which represented 59% of our total sales volumes for 2010. Our daily net production at the Catalina Unit was 14,705 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. This water can be injected back into the ground through injection wells. In 2008, we were granted a permit by the Bureau of Land Management (“BLM”) to treat water removed from the wells, for release on the surface. We are currently the only company in the Atlantic Rim area with such a permit. We engaged EMIT Technologies Inc (“EMIT”) to construct a pilot waste water treatment facility within the Catalina Unit. The EMIT plant has capacity to treat and release up to 10,000 barrels of water per day. We would pay EMIT a fee per barrel of water processed. However, due to the current water production volumes and the cost of water treatment, all of the water produced by our CBM wells is currently reinjected into the ground.

Eastern Washakie Midstream Pipeline LLC

Through a wholly-owned subsidiary, Eastern Washakie Midstream Pipeline LLC (“EWM”), we own 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 us and other operators in the Atlantic Rim. EWM also owns survey and right of way permits for a potential line extension to the Wyoming Interstate Company (“WIC”) pipeline system.

Subsequent to December 31, 2010, the Company entered into an agreement with a third party to transport gas through its pipeline. Based on the current production volumes within this field, the Company expects to begin transporting the third party gas in the second half 2012 or 2013.

Sun Dog Unit

The Sun Dog Unit is adjacent to and east of the Catalina Unit. Anadarko operates this 21,929 acre unit in which we own 11,420 gross and 5,147 net acres of working interest. The Sun Dog Unit was established in 2005 and as of December 31, 2010, we owned a 21.46% working interest of the PA in the Unit. As of December 31, 2010, there were 114 production wells within the Unit. During 2010, the operator performed well workovers, including fracture stimulation on approximately 15 existing wells within the Sun Dog Unit. This PA and the associated working interest, including ours, will change as more wells and acreage are added to the PA. We are currently awaiting additional water injection capacity in the Sun Dog Unit. We do not believe we have realized the full benefit of the fracture stimulation in the Sun Dog Unit due to insufficient water capacity. The operator has indicated that it may drill additional wells in the Sun Dog and Doty Mountain Units in 2011, including an additional injection well in the Sun Dog Unit. During 2010, we recognized a total net production from the Sun Dog Unit of 726 MMcf, or an average daily net production of 1,990 Mcf per day (compared to total net production of 483 MMcf in 2009 and 297 MMcf in 2008).

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 20,336 acre unit in which we own 2,000 gross and 2,000 net acres of leasehold working interest. As of December 31, 2010, we owned an 18.00% working interest in the PA of 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. During 2010, the operator performed well workovers, including fracture stimulation on approximately 20 existing wells and added additional compression capacity at the field, which resulted in a production increase. We recognized a total net production from the Doty Mountain Unit of 635 MMcf in 2010, or an average of 1,741 Mcf (net) per day (compared to total net production of 298 MMcf in 2009 and 194 MMcf in 2008).

Other Acreage

Outside these three units, we own interests in additional acres 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. QEP Resources, Inc. (QEP) 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 approximately 146 non-operated wells producing 20% of our total production for 2010. Our net production from the Mesa Unit in 2010 was 1.9 Bcfe, or 5,075 Mcfe per day, net to our interest (compared to total net production of 2.1 Bcfe in 2009 and 1.6 Bcfe in 2008).

As of December 31, 2010, in the Mesa “A” PA, there were 22 producing wells, in which we hold a 0.312% overriding royalty interest. Our net acreage position is at least 1.875 net acres under a gross of 600 acres in the “A” PA.

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 90 producing wells that produced 1,286 MMcfe in 2010, 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” PA, and 100 net acres under a gross of 800 acres in the deep producing formations. Sixteen of the 90 wells came on-line for production during the second, third and fourth quarters of 2010. We are also currently participating in the drilling of 17 additional wells, which are estimated to be completed during 2011 with current expectations of three in April, four in June, four in September and six in December. We believe the operator will drill an additional 12 to 16 wells in the Mesa “B” PA in second half of 2011.

In the Mesa “C” PA, where we have a working interest of 6.4%, 34 wells produced 566 MMcfe in 2010, net to our interest (as compared to 756 MMcfe in 2009 and 501 MMcfe in 2008). 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.

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 this basin, including two very large natural gas accumulations, the Madden Anticline and the Cave Gulch/Waltman Fields. We have interests in 51,026 gross acres, (3,043 net acres), of leases in the Wind River 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 PA produced 220 MMcf net to our interest of gas in 2010 from eight wells. These are long-lived wells with large producing rates.

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. We purchased interests in this leasehold in 1996. We operate this property and own 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 the fourth quarter of 2010, management concluded that the non-producing Waltman 34-24 well is not capable of economically producing reserves, and we wrote-off the carrying costs of this well, which resulted in a $1.1 million impairment charge to the 2010 consolidated statement of operations. We will continue to produce the Waltman 24-24 well. We have the option on offsetting acreage to drill additional wells in the future.

The Moxa Arch and Other Areas in Southwest Wyoming

We continue to participate in development 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 and 2010. We have interest in a total of over 350 wells in this area. In 2011, natural gas prices will dictate further participation in drilling proposals in this area.

Exploration Projects

During 2010, we did not have any significant active exploration projects. The following discussion details our exploration projects.

Proposed Exploration of Niobrara Shale Formation

The Niobrara Shale Formation (“Niobrara”) is an emerging oil play in the Rocky Mountain region of the United States. Niobrara is a thick and continuous Cretaceous source rock that ranges from 150 feet to 1,500 feet thick. At December 31, 2010, we had over 94,000 gross acres (73,000 net), primarily located in Wyoming and western Nebraska, that we believe has Niobrara formation exposure. The acreage consists of leases in the followings areas:

Area		Gross Acres				Net Acres
Atlantic Rim			60,390				39,376
DJ Basin — Wyoming			4,954				4,954
DJ Basin — Nebraska			4,198				4,198
Power River Basin			15,643				15,643
Laramie/Hanna Basin			8,669				8,669
Wind River Basin			640				640
Total Niobrara Acreage			94,494				73,480

We currently plan to drill one or more exploratory Niobrara wells in the Atlantic Rim in 2011 to test this formation.

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 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 BLM 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. We are currently in discussions 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 to the Madison formation at 22,000-24,000 feet.

Nevada

We have leased 36,045 gross acres, 30,264 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. The results of drilling by other parties in the Huntington Valley have not been encouraging and in 2008, we concluded that we do not plan to renew any of the Nevada leases upon their expiration. Therefore, the related capitalized undeveloped leasehold costs of $741 were written off at December 31, 2008.

Reserves

Effective December 31, 2009, we adopted the SEC’s final rules on the Modernization of Oil and Gas Reporting. The new rules were designed to modernize the disclosures and to better align them with current practices and technology. The most noteworthy changes were as follows:

	•		The new SEC standards require us to calculate the quantity and PV-10 value of oil and gas reserves that are economically producible using a simple 12-month average price, using the first-day-of-the-month applicable commodity price within the 12-month period prior to the reporting period end. Prior to this rule change, oil and gas reserves were calculated using the price as of the last day of the reporting period, which was December 31 for us.
	•		The new definition allows for proved undeveloped reserves to be established for reserves in drilling units beyond those immediately adjacent to the drilling unit containing a producing well if we can establish with reasonable certainty that these reserves are economically producible. In prior years, we were not permitted to establish proved undeveloped reserves beyond those immediately adjacent to the drilling unit containing a producing well.

These rule changes are included in our reserve estimates as of December 31, 2010 and 2009.

We engaged the independent petroleum engineering firm, Netherland, Sewell & Associates, Inc. (“NSAI”) to prepare our reserve estimates at December 31, 2010, 2009 and 2008. 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 included herein are David Miller and 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 29 years of practical experience in petroleum engineering, with over 13 years of 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 30 years of practical experience in petroleum geosciences, with over 19 years of 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 our 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 our reserves, as shown in the table below, are located within the continental United States.

		As of December 31,
		2010 (1)								2009 (1)								2008
		Oil				Natural Gas				Oil				Natural Gas				Oil				Natural Gas
		(Bbls)				(Mcf)				(Bbls)				(Mcf)				(Bbls)				(Mcf)
PROVED
Developed			235,808				73,049,048				312,963				64,296,948				295,698				63,007,126
Undeveloped			145,443				39,719,466				106,250				25,479,722				124,491				23,323,694
Total proved reserves			381,251				112,768,514				419,213				89,776,670				420,189				86,330,820

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.”

We did not convert any proved undeveloped reserves into proved developed reserves during the year ended December 31, 2010, due to both the location of the wells drilled in the Pinedale Anticline in 2010 and due to the decision by us and the other operators in the Atlantic Rim to suspend drilling because of the low natural gas prices. We do not have any material concentrations of reserves that have remained undeveloped for a period of five years or more.

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,
		2010 (1)				2009 (1)				2008
Present value of estimated future net cash flows before income taxes, discounted at 10% (2)		$	143,694			$	91,133			$	155,766
Reconciliation of non-GAAP financial measure:
PV-10		$	143,694			$	91,133			$	155,766
Less: Undiscounted income taxes			(50,732	)			(14,279	)			(58,313	)
Plus: 10% discount factor			21,982				5,853				24,602
Discounted income taxes			(28,750	)			(8,426	)			33,711
Standardized measure of discounted future net cash flows		$	114,944			$	82,707			$	122,055

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 us. 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, 2010, 2009 and 2008.

		For the Year Ended December 31,
		2010								2009								2008
		Oil (Bbls)				Gas (MMcf)				Oil (Bbls)				Gas (MMcf)				Oil (Bbls)				Gas (MMcf)
Production:
Atlantic Rim			—				6,729				—				6,677				—				4,473
Pinedale Anticline			15,413				1,760				16,741				1,961				14,674				1,547
Other			10,611				514				12,186				524				10,994				540
Company total			26,024				9,003				28,927				9,162				25,668				6,560
Average sales price ($/Bbl or $/Mcf)
Atlantic Rim (1)			N/A			$	4.08				N/A			$	5.42				N/A			$	5.86
Pinedale Anticline		$	66.80			$	4.21			$	47.40			$	3.39			$	77.10			$	6.62
Other		$	75.51			$	4.36			$	57.49			$	3.09			$	77.42			$	6.39
Company average		$	70.35			$	4.12			$	51.65			$	4.85			$	77.24			$	6.08
Average production cost ($/mcfe)
Atlantic Rim (2)				$1.10								$0.85								$1.17
Pinedale Anticline				$0.68								$0.53								$0.51
Other				$1.88								$1.67								$1.49
Company average				$1.06								$0.83								$1.04

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. Our outstanding derivative instruments as of December 31, 2010 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

2,920,000

8,000

01/11-12/11

$7.07

CIG

Costless Collar

1,060,000

5,000

08/09-07/11

$4.50 floor

NYMEX

$7.90 ceiling

Costless Collar

1,670,000

5,000

12/09-11/11

$4.50 floor

NYMEX

$9.00 ceiling

Total

5,650,000

Subsequent to December 31, 2010, we entered into the following additional contracts:

		Daily								Price
Type of Contract		Production				Term		Price		Index
Fixed Price Swap			10,000			01/12-12/12		$5.05		NYMEX
Fixed Price Swap			6,000			01/13-12/13		$5.16		NYMEX
Costless Collar			6,000			01/13-12/13		$5.00 floor		NYMEX
								$5.35 ceiling

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, 2010. 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, three wells in Texas and one in Oklahoma, which are included in the table below.

		Oil								Gas
State		Gross				Net				Gross				Net
Wyoming			93				6.0353				1,074				101.5472
Other			39				4.4946				5				0.0855
Total			132				10.5299				1,079				101.6327

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,
		2010								2009								2008
		Gross				Net				Gross				Net				Gross				Net
Development
Oil			13				0.04				—				—				1				0.05
Gas			26				2.08				42				3.12				178				27.59
Dry Holes			—				—				—				—				1				0.69
Water Injection			—				—				—				—				14				5.42
Water Supply			—				—				1				1.00				—				—
Other			—				—				—				—				5				2.67
Total			39				2.12				43				4.12				199				36.42

We did not participate in any exploratory wells during these periods.

Finding and Development Costs

Our reserve replacement ratio represents the amount of proved reserves added to our reserve base during the year, as compared to the amount of oil and gas we produced. For the year ended December 31, 2010, we had extensions and discoveries of 17.0 Bcfe and we purchased reserves totaling 15.3 Bcfe, as compared to our 2010 annual production of 9.2 MMcfe, providing for a reserve replacement ratio of 351%.

During the same period, we invested $20.5 million in development and exploration capital expenditures. This consisted of $8.9 million recorded in conjunction with the working interest purchased and the related asset retirement obligation in the Atlantic Rim and $11.6 million of finding and development costs, defined as costs incurred by the Company in 2010 related to successful exploratory wells and successful and dry development wells. This activity resulted in a one-year finding and development cost in 2010 of $0.68 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, 2010, 2009 and 2008, total proved reserve additions consisted of (expressed in Mcfe):

		As of December 31
		2010				2009				2008
Proved Developed (MMcfe)			3,021				10,543				17,196
Proved Undeveloped (MMcfe)			13,941				11,761				9,441
Total Proved Reserves Added (Mmcfe)			16,962				22,304				26,637
One year finding and development costs per Mcfe		$	0.68			$	0.91			$	1.47

Proved reserves were added in each of 2010, 2009 and 2008 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 costs 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 were 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 we had working interests and royalty interests as of December 31, 2010. 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				10,936				140,820				84,710				262,361				95,646
Nevada			—				—				36,045				30,264				36,045				30,264
Utah			637				16				46,440				21,146				47,077				21,162
Other			5,544				2,678				7,930				4,997				13,474				7,675
Total			127,722				13,630				231,235				141,117				358,957				154,747

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

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, production has been obtained from the acreage subject to the lease prior to that date, or a suspension of a lease is granted. The following table sets forth the gross and net acres subject to leases summarized in the preceding table that will expire during the years indicated:

		Expiring Acreage
Year		Gross				Net
2011			18,244				6,282
2012			12,837				7,399
2013 and thereafter			374,825				143,321
Total			405,906				157,002

Other Significant Developments since December 31, 2009

In July 2010, we completed a purchase of additional working interests in the Atlantic Rim for a total cost of $8.4 million. The transaction was effective January 1, 2010 and we paid cash of approximately $7.9 million, net of revenue, expense and capital costs incurred from the effective date through the closing date. The purchase increased our working interest in the existing development units as follows:

						Working Interest After
Unit		Working Interest Acquired				Purchase (1)
Catalina			3.08	%			72.40	%
Sun Dog			12.57	%			21.46	%
Doty Mountain			1.15	%			18.00	%

In the third quarter of 2010, we reached a settlement with many of the defendants in the lawsuit we brought to recover either monetary damages or our respective share of the natural gas produced from the Madden Deep Unit over at least the period February 1, 2002 through June 30, 2007. As part of the settlement, we received cash proceeds of $4,061. Prior to the settlement, we had not recognized any amount of sales proceeds for the period February 1, 2002 through October 30, 2006. For the period from November 1, 2006 through June 30, 2007, we had recognized the sales and expenses and had recorded a related account receivable of $292, net of allowance for uncollectible amounts. We recorded $3,841 of net proceeds from Madden Deep Unit settlement on the consolidated statements of operations for 2010.

Effective March 7, 2011, we amended our credit agreement to increase the borrowing availability on the credit facility from $55 million to $60 million. Borrowings under the revolving line of credit will bear interest at a daily rate equal to either 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. The credit facility will no longer have a 4.5% floor. Any balance outstanding on the facility matures on January 31, 2013.

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, 2010, 2009 and 2008, we sold 77%, 85% and 80%, respectively, of our total oil and gas sales volumes to Summit Energy, LLC. No other companies 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 likely have a material adverse effect on our business because 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.

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 than we do. 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 it is not at this time, anticipated to have any material negative impact on our ability to deploy our capital drilling budget in 2011.

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 (including hydraulic fracture stimulation reports), 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 BLM and the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) (formerly the Minerals Management Service), which under laws such as the Federal Land Policy and Management Act, Endangered Species Act, National Environmental Policy Act and Outer Continental Shelf Lands Act have certain authority over our operations on federal lands, particularly in the Rocky Mountains;
	•		the Environmental Protection Agency (“EPA”) and the Occupational Safety and Health Administration, which under laws such as the Comprehensive Environmental Response, Compensation and Liability Act, as amended, the Resource Conservation and Recovery Act, as amended, the Oil Pollution Act of 1990, the Clean Air Act, the Clean Water Act, the Occupational Safety and Health Act and the recent Final Mandatory Reporting of Greenhouse Gases Rule have certain authority over environmental, health and safety matters affecting our operations; and
	•		the Federal Energy Regulatory Commission, which under laws such as the Energy Policy Act of 2005 has certain authority over the marketing and transportation of crude oil and natural gas; and

On May 17, 2010, the BLM issued a revised oil and gas leasing policy that requires, 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. We do not expect this new legislation to impact our current development projects, but may impact our future leasing opportunities.

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, development 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 our 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, we do not believe that they do not appear to affect us to any greater or lesser extent than other companies in the industry.

Employees and Office Space

As of December 31, 2010, 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 lease 7,490 square feet of office space in Denver, Colorado, for our principal executive offices. We also own 6,765 square feet of office space in Casper, Wyoming that houses our land and geology departments.

Available Information

Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, and amendments to reports filed or furnished pursuant to Sections 13(a) and 15(d) of the Securities Exchange Act of 1934, as amended, are available on our website 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 stockholder 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.

Btu. 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.

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.

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.

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.

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 Form 10-K. Each of these risk factors, as well as other risks described elsewhere in this Form 10-K, 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. See “Cautionary Note about Forward-Looking Statements’’ for additional risks and information regarding forward- looking statements.

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. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and/or subject us to administrative, civil and criminal penalties. 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 and regulation, that, if adopted, could adversely affect our business, financial condition and results of operations, include the following:

	•		Climate Change. Climate-change legislation establishing a “cap-and-trade” plan for greenhouse gases (“GHGs”) was approved by the U.S. House of Representatives in 2010. It is not possible at this time to predict whether or when the U.S. Senate may act on climate-change legislation.
	•		The U.S. Environmental Protection Agency (“EPA”) has also taken recent action related to GHGs. The EPA now purports to have a basis to begin regulating emissions of GHGs under the federal Clean Air Act.
	•		Taxes. President Obama’s fiscal year 2011 budget proposal includes provisions that would, if enacted, make significant changes to United States tax laws. These changes include, but are not limited to, eliminating the immediate deduction for intangible drilling and development costs and eliminating the deduction from income for domestic production activities relating to oil and natural-gas exploration and development.
	•		Hydraulic Fracturing. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. We find that the use of hydraulic fracturing is necessary to produce commercial quantities of crude oil and natural gas from many reservoirs. Currently, regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. Concern around the exploration and development of shale gas using hydraulic fracturing has continued to grow, which may give rise to additional regulation in this area. The U.S. Congress continues to consider legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. This legislation, if adopted, could establish an additional level of regulation and permitting at the federal level. In addition, the State of Wyoming, where the Company conducts substantially all of its operations, approved new reporting requirements involving hydraulic fracturing in 2010.

•

Derivatives. The Dodd-Frank Act passed in July 2010 expanded federal regulation of financial derivative instruments, including credit default swaps, commodity derivatives and other over-the-counter derivatives. Although under the current definitions within the Dodd Frank Act we would meet the qualifications for exemption status with respect to the requirement to post cash collateral in all hedging transactions, it is not possible at this time to predict the final impact of any final regulations adopted.

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

Our revenues, profitability liquidity, future rate of growth and the carrying value of our oil and gas properties are heavily dependent upon prevailing prices for natural gas and oil, which have historically been highly volatile and in recent years have been depressed by excess total domestic and imported natural gas supplies. Natural gas prices in the Rocky Mountain region of the United States have been more adversely affected by the market volatility than other regions of the country, due to pipeline capacity and the resulting excess supply within the region. Historically, prices have also been affected by actions of federal, state and local agencies, the United States and foreign governments, foreign political conditions, 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 and our reserves. All of these factors are beyond our control. Because over 95% of our current production is natural gas, our revenue, margin, cash flow and results of operations are substantially more sensitive to changes in natural gas prices than to changes in oil prices.

We may be unable to find reliable and economic markets for our gas production.

All of our current natural gas production is produced in the Rocky Mountain Region. There is a limited amount of transportation volume availability for all Rocky Mountain producers. Although there are numerous transportation pipeline projects, there is uncertainty as to the amount of available take-away volumes in the future. We have contracts with marketing companies that provide for the availability of transportation for our natural gas but interruption of any transportation line out of the Rocky Mountains could have a material impact on our financial condition. In addition, the transportation providers have gas quality requirements as to Btu content and carbon dioxide make-up, etc. The gas we produce in the Catalina Unit is transported on the Southern Star Transportation line, which has various gas quality requirements, including that gas must have a carbon dioxide content below 1%. In the second half of 2010, we periodically had carbon dioxide levels that exceeded this limit. Southern Star has waived this requirement until March 31, 2011. While we are actively working to resolve this issue, we may not have a long-term solution in place when the waiver expires. We may incur additional costs in 2011 to process this gas, or we may experience a production interruption at certain wells, which could have a material adverse impact on our cash flow and results of operations.

We may be unable to develop our existing acreage due to the change in the political environment or environmental and social pressures around natural resource development.

Our anticipated growth and planned expenditures are based upon the assumption that existing leases and regulations will remain intact and allow for the future development of carbon based fuels. However, the United States federal government has not adopted a clear energy policy, and policy decisions continue to be complicated by the shift in the political balance in Washington D.C. and the recent Gulf of Mexico oil spill. 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.

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. Three separate coalitions of conservation groups appealed the approval of the EIS to the BLM all of which were subsequently dismissed. Although there are currently no outstanding appeals, the BLM allows public comment during the permitting process. Pressure from conservation and environmental groups could ultimately prevent drilling in this area.

Our operations require substantial capital and we may be unable to fund our planned capital expenditures.

The oil and gas industry is capital intensive. 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 capital 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;
	•		our proved reserves;
	•		our ability to acquire, locate and produce new reserves;
	•		oil and natural gas prices; and
	•		our market value and operating performance.

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 obtain the capital necessary to complete our capital expenditures program.

Indebtedness may limit our liquidity and financial flexibility.

As of December 31, 2010, we had $32 million drawn under our bank credit facility and had 1,610,000 shares of preferred stock outstanding (redeemable at our option), which require payment of cumulative cash dividends at a rate of 9.25% per year.

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

•

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

•

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

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 may 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.

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. In addition, as the economy recovers, there may be price inflation for rigs, equipment and supplies.

Regardless of the economic conditions, there may not be enough available qualified personnel in our industry. Our success depends significantly upon the efforts and abilities of our senior management and key employees. Several senior personnel are reaching retirement age, and there may not be enough younger workers with the training and experience to take their place. If we are unable to economically secure drilling equipment and supplies or to attract qualified personnel, our operations may be adversely affected.

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. 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. There are a variety of geological, operational, or market-related factors that may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. These include:

•

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.

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

This report on Form 10-K contains estimates of our proved oil and natural gas reserves. The estimates of reserves and future net revenues are not exact and are based on many variable and uncertain factors; therefore, the estimates may vary substantially from the actual amounts depending, in part, on the assumptions made and may be subject to adjustment either up or down in the future. The 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 many risks and uncertainties.

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 we will realize the expected benefits or synergies of the transaction.

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 also 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 us incurring additional debt, contingent liabilities and expenses, all of which could have a material adverse effect on our financial condition and operating results.

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

Certain 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 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.

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. In 2010, we sold approximately 77% of our crude oil and natural gas to one counterparty. 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 its ability to perform under the terms of the hedging contracts or other receivables. 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 and accounts receivables expose us to risk of financial loss if a counterparty fails to perform under a contract. We use master agreements that 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 or sustained low commodity prices, the value of 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.

We use commodity-price derivative arrangements to reduce, or hedge, exposure to volatile natural gas prices and to protect cash flow from downward commodity price movements. To the extent we hedge commodity price exposure, we lose the opportunity to take advantage of commodity price increases.

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. There are no assurances that we will be able to find, develop or acquire additional reserves to replace our current and future production at acceptable costs, or at all.

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. There is also growing pressure for companies to balance their oil to natural gas reserve ratios, as natural gas is considered to be a relatively clean fossil fuel and has potential to become the major fuel for multiple end uses. This may further increase competition, particularly in the emerging natural gas shale plays. 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.

Provisions in our corporate documents and Maryland law could delay or prevent a change of control of Double Eagle, even if that change would be beneficial to our stockholders.

Our restated certificate of incorporation and by-laws contain provisions that may make a change of control of Double Eagle difficult, even if it may be beneficial to our stockholders, including the authorization given to our Board of Directors to issue and set the terms of preferred stock. In 2007, the Board of Directors of the Company adopted a Shareholder Rights Plan (“Rights Plan”). The Rights Plan provides us with the ability to issue rights that entitles stockholders to purchase a fractional share of the Company’s Series B Junior Participating Preferred Stock at an exercise price of $45. 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, the Company could issue the rights that would 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.

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

The exploration, development and operation of oil and gas properties 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 the United States Congress 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.

Weak economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions. The consequences of a 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:

•

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.

Failure of our common stock to trade at reasonable prices may limit our ability to fund future potential capital needs through issuances or sales of our stock.

ITEM 1B.		UNRESOLVED STAFF COMMENTS

None.

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.

On December 18, 2009, Tiberius Capital, LLC (“Plaintiff”), a stockholder of Petrosearch prior to the Company’s acquisition (the “Acquisition”) of Petrosearch pursuant to a merger between Petrosearch and a wholly-owned subsidiary of the Company, filed a claim in the U.S. District Court of New York against Petrosearch, the Company, and the individuals who were officers and directors of Petrosearch prior to the Acquisition. In general, the claims against the Company and Petrosearch are that Petrosearch inappropriately denied dissenters’ rights of appraisal under the Nevada Revised Statutes to its stockholders in connection with the Acquisition, that the defendants violated various sections of the Securities Act of 1933 and the Securities Exchange Act of 1934, and that the defendants caused other damages to the stockholders of Petrosearch. The Plaintiff is seeking monetary damages. The Company does not believe the case has merit, and is defending this case vigorously. There has been no judgment or decision to date on this litigation.

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”. From 1995 to December 2006 our Common Stock traded on the NASDAQ Capital Market.

The range of high and low sales prices for our Common Stock for each quarterly period from January 1, 2009 through December 31, 2010 as reported by the NASDAQ Stock Market, is set forth below:

Quarter Ended		High				Low
March 31, 2010		$	5.00				4.01
June 30, 2010			5.53				4.14
September 30, 2010			4.48				3.90
December 31, 2010		$	5.45			$	4.14
March 31, 2009			11.23				3.00
June 30, 2009			6.49				3.62
September 30, 2009			5.40				3.75
December 31, 2009		$	6.02			$	4.04

On February 25, 2011, the closing sales price for the Common Stock as reported by the NASDAQ Global Select Market was $11.21 per share.

Holders. On February 25, 2011, the number of holders of record of our common stock was 1,171.

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.

Our credit facility limits the aggregate value of dividends in any fiscal year to no more than 40% of consolidated net income, provided that we are not in default on our credit facility.

Issuer Purchases of Equity Securities.

The table below summarizes repurchases of our common stock in the fourth quarter of 2010:

										Total Number of Shares				Maximum Number of
										Purchased as Part of				Shares that May Yet Be
		Total Number of Shares				Average Price Paid per				Publically Announced				Purchased Under the
Period		Purchased				Share				Plans or Programs				Plans or Programs
October 2010			—				—				—				—
November 2010			—				—				—				—
December 2010			2,025	(1)		$	4.93				—				—

ITEM 6.		SELECTED FINANCIAL DATA

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

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

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

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

The following discussion and analysis should be read in conjunction with the “Selected Financial Data” and the accompanying consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. See “Cautionary Information About Forward-Looking Statements”.

BUSINESS OVERVIEW

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. During 2010, we allocated a portion of our capital resources to acquiring acreage with mineral rights in the Niobrara formation in anticipation of beginning an exploration project in 2011. At December 31, 2010, we had over 70,000 net acres in areas that we believe has Niobrara formation exposure, located primarily in Wyoming and Western Nebraska.

Our objective is to increase shareholder value by profitably growing our reserves, production, revenues, and cash flow by focusing primarily on: (i) new coal bed methane gas development drilling; (ii) enhancement of existing production wells and field facilities on operated and non-operated properties in the Atlantic Rim; (iii) continued participation in the development of tight sands gas wells at the Mesa Fields on the Pinedale Anticline; (iv) expansion of our midstream business; (v) pursuit of high quality exploration and strategic development projects with potential for providing long-term drilling inventories that generate high returns, including exploration of the Niobrara formation in the Atlantic Rim and other properties in which we have an interest and (vi) selectively pursuing strategic acquisitions. Substantially all of our revenues are generated through the sale of natural gas and oil production at market prices and the settlement of commodity hedges. Approximately 98% of our 2010 production volume was natural gas.

As of December 31, 2010, we had estimated proved reserves of 112.8 Bcf of natural gas and 381 MBbl of oil, or a total of 115.1 Bcfe. This represents a net increase in reserve quantities of 25% from 2009, after adjustments for extensions and discoveries, current year production and revision of estimates. The increase in estimated proved reserves as compared to the prior year is the result of 17.0 Bcfe of additional reserves added as a result of organic growth from drilling in the Pinedale Anticline and other development fields and 15.3 Bcfe of reserves attributed to our purchase of additional working interest in the Atlantic Rim completed in July 2010.

The estimated proved reserves have a PV-10 value of approximately $143,694 at December 31, 2010 as compared to $91,133 at December 31, 2009 (see reconciliation of the PV-10 non-GAAP financial measure to the standardized measure under Reserves within Part 1 and 2: Business and Properties section of this Form 10-K). The average price used in calculating the December 31, 2010 reserves increased by $0.91, or 30%, to $3.95 per MMBtu from the December 31, 2009 price of $3.04 per MMBtu. We also experienced an increase in our PV-10 value due to extensions and discoveries and our purchase of additional Atlantic Rim working interest, as noted above.

During 2010, we invested $21.5 million in capital expenditures related to the development of our existing properties, as compared to $21.1 million in 2009. The focus of the capital expenditures was primarily on non-operated drilling on the Pinedale Anticline, where we have historically had a high rate of return, and on our acquisition of additional working interest in the Atlantic Rim, for a purchase price of $8.4 million. Additional information related to this purchase can be found below. We also used capital on well enhancement projects within the Catalina Unit and at the non-operated Sun Dog and Doty Mountain units. Finally, we allocated a portion of our capital expenditures to acquiring acreage with mineral rights in the Niobrara formation in anticipation of beginning an exploration project in 2011.

Developments since December 31, 2009

In 2010, we continued to focus on strengthening our financial position, while pursuing 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 2010, including the following:

•

In July 2010, we completed a purchase of additional working interests in the Atlantic Rim for a total cost of $8.4 million. The transaction was effective January 1, 2010 and we paid cash of approximately $7.9 million, net of revenue, expense and capital costs incurred from the effective date through the closing date. The purchase increased our working interest in the existing development units as follows:

						Working Interest After
Unit		Working Interest Acquired				Purchase (1)
Catalina			3.08	%			72.40	%
Sun Dog			12.57	%			21.46	%
Doty Mountain			1.15	%			18.00	%

•

At our company-operated Catalina Unit, we continued to perform well workover and production enhancement projects on our existing wells. The production enhancement program focused on existing wells that had experienced production declines over the past two years.

•

At the Sun Dog Unit, the operator completed well workovers, including stimulation, of approximately 15 wells and is in process of adding additional water injection capacity. Management does not believe we have realized the full benefit of the fracture stimulation in the Sun Dog Unit due to the insufficient water injection capacity.

•

At the Doty Mountain Unit, the operator added additional compressor capacity in the first quarter of 2010, which has led to a monthly production increase as of December 31, 2010 of approximately 65% in the Unit. In addition, the operator completed well workovers, including fracture stimulation of 20 wells in 2010.

•

In the Mesa “B” Participating Area at the Pinedale Anticline, 16 new wells were brought on-line during 2010. We are also currently participating in the drilling of approximately 17 additional wells. These wells were drilled in the fall of 2010, and are expected to be completed in 2011.

In the third quarter of 2010, we reached a settlement with many of the defendants in a lawsuit brought by us to recover either monetary damages or our respective share of the natural gas produced from the Madden Deep Unit over at least the period February 1, 2002 through June 30, 2007. As part of the settlement, we received cash proceeds of $4,061. Prior to the settlement, we had not recognized any amount of sales proceeds for the period February 1, 2002 through October 30, 2006. For the period from November 1, 2006 through June 30, 2007, we had recognized the sales and expenses and had recorded a related account receivable of $292, net of allowance for uncollectible amounts. We recorded $3,841 of net proceeds from Madden Deep Unit settlement on the consolidated statements of operations for 2010.

Effective March 7, 2011, we amended our credit agreement to increase the borrowing availability on the credit facility from $55 million to $60 million. Borrowings under the revolving line of credit will bear interest at a daily rate equal to either (a) the Federal Funds rate, plus 0.5%, the Prime Rate or the Eurodollar Rate plus 1%, plus (b) a margin ranging between 1.25% and 2.0% depending on the level of funds borrowed. The credit facility will no longer have a 4.5% floor. Any balance outstanding on the facility matures on January 31, 2013.

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 is an ongoing focus for management, and is made particularly important in our business by the natural production and reserve declines associated with oil and gas properties. We attempt to overcome these declines by drilling to find additional reserves, acquisitions of additional reserves and exploiting new exploration opportunities. Our future growth will depend on our ability to continue to add reserves in excess of production.

Our ability to add reserves through drilling is dependent on our available capital resources but is also limited by many other factors, including our ability to timely obtain drilling permits, regulatory approvals and the ability to complete drilling operations with the stipulated timeframe. The permitting and approval process has become increasingly difficult over the past several years due to an increase in regulatory requirements and increased activism from environmental and other groups, which has extended the time it takes us to receive permits, and other necessary approvals. Historically, we have not encountered any significant delays in permit or drilling approvals. Because of our relatively small size and concentrated operated property base, we can be at a disadvantage to our competitors by delays in obtaining or failing to obtain drilling approvals compared to companies with larger or more dispersed property bases. As a result, we are less able to shift drilling activities to areas where permitting may be easier, and we have fewer properties over which to spread the costs related to complying with these regulations and the costs or foregone opportunities resulting from delays.

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

•

We attempt to reduce our overall exposure to commodity price fluctuations through the use of various hedging instruments for some of our production. Our strategic objective is to hedge at least 50% of our anticipated production on a forward 12 to 24 month basis. The duration of our various hedging instruments depends on our view of market conditions, available contract prices and our operating strategy. Use of such hedging instruments may limit the risk of fluctuating cash flows. Refer to Contracted Volumes on page 41 for the derivative instruments we had in place as of December 31, 2010.

•

We have acquired additional acreage in the Niobrara Shale formation in Wyoming and Nebraska to provide for future exploration potential.

•

We proactively work with state and federal regulatory agencies to facilitate communication and necessary approvals.

Development and Exploration Outlook for 2011:

We expect to expend $20 to $30 million of capital for development drilling and exploration programs in 2011. The drilling activity provided for in our 2011 capital budget is primarily allocated to the projects below:

Atlantic Rim. We intend to resume development drilling in the Atlantic Rim in the second half of 2011. We expect to drill up to 20 CBM production wells within the Catalina Unit during this period. Upon reaching total depth of these new wells, the participating area will expand, and our working interest in the Unit will decrease to approximately 60%. In addition, we plan to drill at least one Niobrara exploratory well located within our Atlantic Rim acreage. We also plan to participate in any drilling by the operator within the Sun Dog and Doty Mountain Units.

Pinedale Anticline. At the Pinedale Anticline, the operator is in the process of drilling 17 wells, which are expected to come on-line in 2011 at a rate of three wells in April, four in June, four in September and six in December. We believe the operator will drill 12 to 16 additional wells in the second half of 2011.

We also have allocated capital in our 2011 capital budget for one or more exploratory wells into the Niobrara formation in the Atlantic Rim.

We believe that we have the necessary capital, personnel and available drilling equipment to execute this development and exploration 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
		2010				2009				2008				2009 to 2010				2008 to 2009
Total proved reserves
Oil (MBbl)			381				419				420				-9	%			0	%
Gas (MMcf)			112,769				89,777				86,331				26	%			4	%
MMcfe			115,056				92,292				88,852				25	%			4	%
Net production volumes
Oil (Bbl)			26,024				28,927				25,668				-10	%			13	%
Gas (Mcf)			9,002,873				9,162,362				6,559,662				-2	%			40	%
Mcfe			9,159,017				9,335,924				6,713,670				-2	%			39	%
Average daily produciton
Mcfe			25,093				25,578				18,343				-2	%			39	%
Average price per unit production
Oil (Bbl)		$	70.35			$	51.65			$	77.24				36	%			-33	%
Gas (Mcf)		$	4.12			$	4.85			$	6.08				-15	%			-20	%
Mcfe		$	4.25			$	4.92			$	6.23				-14	%			-21	%
Oil and gas production revenues
Oil revenues		$	1,831			$	1,494			$	1,983				23	%			-25	%
Gas revenues			31,779				40,904				37,166				-22	%			10	%
Total		$	33,610			$	42,398			$	39,149				-21	%			8	%
Oil and gas production costs
Production costs		$	9,708			$	7,754			$	7,007				25	%			11	%
Production taxes			4,563				3,652				4,701				25	%			-22	%
Total		$	14,271			$	11,406			$	11,708				25	%			-3	%
Data on a per Mcfe basis
Average price (1)		$	4.25			$	4.92			$	6.23				-14	%			-21	%
Production costs (2)			1.06				0.83				1.04				28	%			-20	%
Production taxes			0.50				0.39				0.70				28	%			-44	%
Depletion and amortization			1.98				1.94				1.65				2	%			18	%
Total operating costs			3.54				3.16				3.39				12	%			-7	%
Gross margin		$	0.71			$	1.76			$	2.84				-60	%			-38	%
Gross margin percentage			17	%			36	%			46	%			-53	%			-22	%

Year ended December 31, 2010 compared to the year ended December 31, 2009

Oil and gas sales, production volume and price comparisons

For the year ended December 31, 2010, oil and gas sales decreased 21% to $33,610, as compared to the year ended December 31, 2009. We received substantially less revenue in 2010 from the settlement of our derivative instruments as compared to 2009, which led to the decrease in oil and gas sales. For the year ended December 31, 2009, $13,164 of oil and gas sales was cash received upon a derivative contract settlement, whereas in 2010, $0 of oil and gas sales was related to derivative settlements. The decrease was also due in part to an overall 2% decrease in production volumes, discussed in more detail below. See Price Risk Management on the following page for information on our other derivative settlements that are not recorded within oil and gas sales.

For the year ended December 31, 2010, our average realized natural gas price decreased 15%, to $4.12 per Mcf from $4.85 per Mcf for the year ended December 31, 2009. Our calculation of the average realized gas price includes both revenue generated from the physical sale of gas at market prices as well as the cash received from the settlement of derivative contracts. Although the average CIG index price was approximately 24% higher for the year ended December 31, 2010, our realized gas price was lower in 2010 due to the strength of our 2009 hedging program.

During the year ended December 31, 2010, total net production decreased 2% to 9,159 MMcfe as compared to the year ended December 31, 2009. The decrease is largely due to lower production volumes at the Catalina Unit and the Mesa Units. The Company’s purchase of additional working interest at the Sun Dog and Doty Mountain Units in the third quarter of 2010 increased our net production in these Units and somewhat offset the production decline at the Catalina and Mesa Units.

During the year-ended December 31, 2010, average daily net production at the Atlantic Rim increased 1% to 18,436 Mcfe, as compared to 18,294 Mcfe in 2009. The production from the Atlantic Rim comes from three operating units, the Catalina Unit, the Sun Dog Unit and the Doty Mountains Unit. The Catalina Unit is operated by the Company.

•

Average daily net production at the Catalina Unit decreased 9% to 14,705 Mcfe for the year ended December 31, 2010, as compared to 16,154 Mcfe during 2009. The decrease is largely the result of what management believes to be the normal production decline for wells within this field. In addition, the decrease is a result of the continuation of our well-enhancement program, which began in the third quarter of 2009 and continued throughout 2010. This program requires individual wells to be off-line for periods of time while the well is worked-over. Finally, the Catalina field also experienced several power outages during the second quarter of 2010 and the Southern Star pipeline was shut down for maintenance for several days in April 2010, both of which temporarily halted production. These decreases were partially offset by the increase in our working interest to 72.40% from 69.31%, which resulted from our working interest purchase from a third-party in July 2010.

•

Average daily net production at the Sun Dog and Doty Mountain Units increased 74% for the year ended December 31, 2010 to 3,731 Mcfe per day from 2,140 Mcfe per day in the prior year, largely due to our higher working interest in both units. We purchased additional working interests in the Sun Dog and Doty Mountain Units during the third quarter of 2010, increasing our working interest in the Sun Dog Unit to 21.46% from 8.89% prior to the purchase, and the Doty Mountain Unit to 18.00% from 16.5% prior to the purchase. Also, the operator added additional compressor capacity at the Doty Mountain Unit in the first quarter of 2010, which boosted production.

Average daily net production in the Pinedale Anticline decreased 10% for the year ended December 31, 2010, to 5,075 Mcfe, as compared to 5,648 Mcfe in the prior year. The operator of the Mesa Units brought an additional 16 wells on-line during 2010, although this did not result in an overall increase in production. Management believes that the production decline is due to the operator managing the production flow from the field due to the low gas prices in the Rocky Mountain region. In addition, the operator has indicated that it delays well completions during the winter months.

During the year ended December 31, 2010, average daily net production at the Madden Unit increased 25% to 603 Mcfe as compared to 484 Mcfe in the prior year. The increase was primarily due to a one-time gas balancing adjustment in the second quarter of 2010. The gas balancing adjustment was partially offset by processing down-time for a 15-day span due to a fire at the Lost Cabin gas plant.

Transportation and gathering revenue

During the year ended December 31, 2010, transportation and gathering revenue decreased 10% to $5,549 from $6,179. We receive fees 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 decrease in revenue is directly correlated to the decrease in production 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 gain on our derivative contracts of $11,512 for the year ended December 31, 2010, as compared to a net loss of $4,295 for the year ended December 31, 2009. The net gain consisted of an unrealized non-cash gain of $6,196, which represents the change in the fair value on our economic hedges at December 31, 2010, based on the future expected prices of the related commodities, and a net realized gain of $5,316 related to the cash settlement of some of our economic hedges.

Proceeds from Madden Deep settlement

During the third quarter of 2010, we reached a settlement with many of the defendants in a lawsuit brought by us through which we sought to recover either monetary damages or our respective share of natural gas produced by our interest in the Madden Deep Unit during the period February 1, 2002 through June 30, 2007. As part of the settlement, we received cash proceeds of $4,061. Prior to the litigation settlement, we had not recognized any amount of sales proceeds related to natural gas from the Madden Deep Unit for the period February 1, 2002 through October 30, 2006. For the period from November 1, 2006 through June 30, 2007, we had recognized the sales and expenses and had recorded a related account receivable of $292, net of allowance for uncollectible amounts. We recorded income of $3,841 upon the settlement within proceeds from Madden Deep settlement on the consolidated statements of operations during 2010.

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

During the year ended December 31, 2010, well production costs increased 25% to $9,708, as compared to $7,754 during the prior year, and production costs in dollars per Mcfe increased 28%, or $0.23, to $1.06, as compared to the same prior-year period. The increase in total production costs and production costs on a per Mcfe basis was primarily driven by higher workover costs at the Catalina and Sun Dog Units related to the well enhancement and workover programs during the year. In addition, we incurred higher transportation expense at the Sun Dog and Doty Mountain Units resulting from an operator metering adjustment.

Production taxes for the year ended December 31, 2010 increased 25% to $4,563, as compared to $3,652 during 2009. Production taxes, on a dollars per Mcfe basis, increased 28%, or $0.11 to $0.50, as compared to the same prior-year period. We pay taxes as a percentage of the proceeds received upon the physical sale of our natural gas to counterparties. As the gas market prices rise, less of our revenue is related to cash received from the settlement of the financial derivative instruments we have in place; rather it is generated by the cash received for the physical sale of our gas in the open market. The increase in the CIG market price, which is the index on which most of our gas volumes are sold, resulted in an overall increase in production taxes, as well as an increase of production taxes expressed on a dollars per Mcfe basis.

Total depreciation, depletion and amortization expenses (“DD&A”) remained flat year over year, totaling $18,574 and $18,562 for the year ended December 31, 2010 and 2009, respectively, and depletion and amortization related to producing assets was $18,159, as compared to $18,136 in the 2009. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 2%, or $0.04, to $1.98, as compared to the prior year.

Pipeline operating costs

Pipeline operating costs increased 12% to $4,152 for the year ended December 31, 2010, as compared to the prior year. The increase is the result of consulting costs we incurred in the first half of 2010 related to reconfiguring our compressor units. In addition, the 2009 expenses were net of a vendor credit we received for compressor downtime, which lowered the pipeline operating costs for 2009.

Impairment and abandonment of equipment and properties

We continually evaluate our properties for potential impairment of value. During the fourth quarter of 2010, management concluded that the non-producing Waltman 34-24 well was not capable of economically producing gas. Accordingly, we incurred a $1,103 impairment charge on the consolidated statement of operations during 2010. We also incurred expense of $480 for the write-off of expiring undeveloped leaseholds.

General and administrative

General and administrative expenses decreased 11% to $5,976 as compared to $6,718 in the prior year. General and administrative expenses were lower during 2010 primarily due to the one-time transaction costs of $513 that related to the Petrosearch acquisition in 2009. In addition, share-based compensation expense decreased by $528 in the 2010 period primarily because of stock forfeitures related to two executive terminations in the second quarter of 2010. These decreases were partially offset by a $154 increase in bank fees related to the unused portion of our credit facility, a $98 increase in salary and salary-related expenses due to increased healthcare costs and an $80 increase due to the Petrosearch building leases assumed in the merger in August 2009.

Income taxes

During the year ended December 31, 2010, we recorded income tax expense of $3,224, as compared to income tax expense of $902 during the prior year. Our income tax expense reflects an effective book rate of 36.95% in 2010. The rate was lower in the 2010 period due to a reduction in permanent income tax differences related to stock option expense, higher net income and the impact of the Petrosearch acquisition, which increased the rate 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 significant required payments for current tax liabilities in the near future. We have net operating loss carry-forwards (“NOLs”) of $32.7 million at December 31, 2010. We have 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, 2010. In reaching this conclusion, management considered that we expect to generate income in excess of our NOLs by continuing to develop our core assets. In addition, we routinely consider 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 NOLs do not begin to expire for 10 years.

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 from 73.84% to 69.31% due to expansion of the Unit.

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 the 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 2008. 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, 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 was 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.

Average daily net production in the Pinedale Anticline increased 26% for the year ended December 31, 2009, to 5,648 Mcfe, as compared to 4,467 Mcfe in 2008. The increase was the result of the addition of 17 new wells in the Mesa “B” Unit during 2009. Although there was an increase in production due to the new wells in the Mesa Unit, the operator has indicated that it kept production volumes in this field relatively fixed due to the low gas prices in the Rocky Mountain region.

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 2008. 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.

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 2008, and production costs in dollars per Mcfe decreased 20%, or $0.21, to $0.83, as compared to 2008. The increase in production costs was attributable to higher lease operating expenses, primarily at the Sun Dog Unit due to an 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. 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 resulted 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 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 was 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 2008.

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 lease compressor equipment rather than own.

General and administrative

General and administrative expenses increased 20% to $6,718 for the year ended December 31, 2009, as compared to $5,604 in 2008. The increase was due largely to $513 of transaction costs related to the acquisition of Petrosearch, 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 reflected an effective book rate of 42.7% in 2009, as compared to 34.6% in 2008. 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.

LIQUIDITY AND CAPITAL RESOURCES

Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our credit 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, these sources of liquidity and capital have been sufficient to meet our needs and finance the growth of our business.

We believe that the amounts available under our 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 2011 capital expenditure program (see “Calendar 2011 Capital Spending Budget” below). Depending on the timing and amounts of future projects, we may be required to seek additional sources of capital. We can provide no assurance that we will be able to do so on favorable terms or at all. The Company currently has an effective Form S-3 shelf registration statement on file with the SEC, which has $150 million of securities available for issuance. The market price of our common stock has only recently recovered from the stock market crash in the fourth quarter of 2008, and therefore we have relied more heavily on other funding sources over the past two years. An increase in the market price of our common stock may create opportunities to raise additional funds through private placements or registered offerings of equity or debt.

Our Credit Facility at December 31, 2010

At December 31, 2010, we had a $75 million credit facility in place, with $55 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 our oil and gas producing properties and other assets. At December 31, 2010, we had $32 million outstanding on the facility, which was used primarily to fund the Company-operated Catalina Unit expansion and other non-operated projects in the Atlantic Rim in 2008, projects in the Pinedale Anticline in 2008, 2009 and 2010, and our working interest purchase in the Atlantic Rim in July 2010.

Borrowings under the revolving line of credit bear interest at the greater of (i) 4.5% or (ii) a daily rate equal to the greater of (a) the Federal Funds rate, plus 0.5%, the Prime Rate or the Eurodollar Rate plus 1%, plus (b) a margin ranging between 1.25% and 2.0% depending on the level of funds borrowed. As of December 31, 2010, the interest rate on the outstanding balance under the line of credit, calculated in accordance with the agreement, was 4.5%. We are subject to a variety of financial and non-financial covenants under this facility. As of December 31, 2010, we were in compliance with all covenants under the facility. If any of the covenants are violated, and we are unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.

Our borrowing base is subject to redetermination each June 15 and December 15, beginning June 15, 2010. Our borrowing base is determined based on the financial institutions assessment of current and future commodity prices, primarily natural gas available us. An assessment of available borrowing base is done semi-annually. Should natural gas commodity prices significantly decrease for extended periods of time, our borrowing base could be reduced, thus limiting the future amounts of funds under the current facility. Our borrowing base is currently in excess of the bank commitment amount we have requested from the banks. This is due to management’s strategy to reduce the bank fees associated with the unused but committed funds, while providing sufficient borrowing availability to execute on our short-term strategies, including capital spending for organic growth as well as acquisitions.

Subsequent to December 31, 2010, the Company amended its credit agreement to increase the borrowing availability on the credit facility from $55 million to $60 million. Refer to page 30 for additional information.

Capital Expenditures

Our primary capital expenditures by type for the years ended December 31, 2010 and 2009 were:

		Year Ended December 31,
		2010				2009
Property acquisition costs		$	1,043			$	16
Exploration			73				59
Development			20,402				21,042
Total capital expenditures		$	21,518			$	21,117

Year Ended December 31, 2010

Our development projects in 2010 focused on our core properties in the Atlantic Rim and the Pinedale Anticline. In the Atlantic Rim, we completed a purchase of additional working interests from a third party in the Catalina, Sun Dog and Doty Mountain Units. The purchase gave us an immediate increase in production and reserve amounts in the units. The total purchase price of the additional working interests was $8,417. In addition, we invested $2,421, net to our working interest, to continue our well enhancement and production maximization project in the Catalina Unit. We also reconfigured certain compressor equipment in the Catalina Unit in the second quarter of 2010. Capital expenditures recorded for the Sun Dog and Doty Mountain Units in 2010 totaled $3,740, net to our interest. In 2010, the operator added additional compressor capacity in the Doty Mountain Unit and completed well workovers, including fracture stimulation, on approximately 35 wells at the Sun Dog and Doty Mountain Units.

We also incurred capital costs of $5,398, net to our interest, related to the Pinedale Anticline development, as we participated in the drilling and completion of 16 new wells in the Mesa Units in the Pinedale Anticline. We also are also participating in the drilling of 17 additional wells, which were drilled in the second half of 2010, and are expected to come on-line in 2011.

During 2010, we expended $1,043 to acquire additional acreage in the Niobrara formation in Wyoming and western Nebraska in anticipation of a future exploration project. We plan to drill at least one exploratory well in the Niobrara formation in 2011.

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.

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.

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 came on-line in 2010.

In July 2009, we incurred capital costs, net to our interest, of $919 to complete and hook-up the Waltman 24-24 well.

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

Calendar 2011 Capital Spending Budget

For 2011, we have budgeted approximately $20 to $30 million for our development and exploration programs in the Atlantic Rim and Pinedale Anticline. We intend to drill in the Atlantic Rim in the second half of 2011, with up to 20 coal bed methane (“CBM”) production wells within the Catalina Unit. We also may participate in additional wells within the Sun Dog and Doty Mountain Units and approximately 12 to 16 new wells at the Mesa Units. We also have allocated capital in our 2011 capital budget for one or more exploratory wells into the Niobrara formation in the Atlantic Rim. We expect to fund our 2011 capital expenditures with cash provided by operating activities and funds made available through our $75 million credit facility. Our 2011 capital budget does not include the impact of other potential future exploration projects or possible acquisitions, which we continually evaluate.

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

Net cash provided by operating activities

Operating activities provided cash of $25,044 in 2010, $22,062 in 2009, and $22,904 in 2008. The primary sources of cash during the year ended December 31, 2010 were $5,503 of net income, which was net of non-cash charges of $18,714 related to DD&A and accretion expense, impairment expenses of $1,103 and non-cash share-based compensation expense of $956. In addition, in 2010, we had an increase of $3,180 in the provision for deferred income taxes, which we do not expect to have to pay in the near future due to our NOL carryforwards. These increases were partially offset by the non-cash gain on derivative contracts of $6,196. Our net income in 2010 included proceeds of $3,841 related to our settlement with many of the defendants in a lawsuit for our share of natural gas from the Madden Deep Unit. This litigation had been outstanding since 2007, and is not a recurring source of operating cash flow. Excluding the impact of the Madden Deep Unit settlement proceeds, our operating cash flow was lower in 2010 as compared to 2009 due primarily to our lower realized natural gas price.

Product prices and volumes are expected to have a significant influence on our future net cash flow provided by operating activities. The natural gas market has been highly volatile over the past two years. During these periods, we rely heavily on cash received from our hedging program. As of December 31, 2010, we had 62% of our anticipated production hedged in 2011. See Contract Volumes for additional information about our outstanding derivative contracts.

The gas we produce in the Catalina Unit is transported on the Southern Star Transportation line, which has various gas quality requirements, including that gas must have a carbon dioxide content below 1%. In the second half of 2010, we periodically had carbon dioxide levels that exceeded this limit. Southern Star has waived this requirement until March 31, 2011. While we are actively working to resolve this issue, we may not have a long-term solution in place when the waiver expires. We may incur additional costs in 2011 to process this gas, or we may experience a production interruption at certain wells, which could have a material impact on our cash flow and results of operations in the second quarter of 2011.

Net cash used in investing activities

During 2010, net cash used in investing activities totaled $21,858, as compared to $21,461 and $40,778 in 2009 and 2008, respectively. Drilling activity slowed significantly in 2010 and 2009, and as a result, our cash outflow related to capital expenditures also decreased as compared to the prior year. The capital expenditures in 2010 primarily related to non-operated drilling in the Pinedale Anticline and well workovers in the Sun Dog and Doty Mountain Units, whereas in 2009, we had significant cash expenditures related to the 2008 drilling programs in the Atlantic Rim and Pinedale Anticline. In addition, during the third quarter of 2010, we completed a purchase of working interests in the Atlantic Rim for a total cost of approximately $8,417, subject to closing adjustments. The effective date of the transaction was January 1, 2010. We paid cash of approximately $7,868, which was net of revenue, expense and capital costs incurred from the effective date through the closing date. Refer to Note 3 in the Notes to the Consolidated Financial Statements for additional details regarding this purchase.

Net cash used in financing activities

Cash used in financing activities totaled $6,263 in 2010 as compared to cash provided by financing activities of $5,081 in 2009 and $17,749 in 2008. We relied heavily on our credit facility to fund our 2008 drilling program, and therefore we had significant draws on our credit facility in 2008 and the first quarter of 2009. In contrast, we repaid $2,000 on our credit facility in 2010 due to increased operating cash flow and slower drilling and workover activity. In all periods presented, we expended a total of $3,723 for our four quarterly dividend payments. We expect to continue to pay dividends on a quarterly basis on the Series A Preferred Stock at a rate of $931 per quarter. We may again draw upon our credit facility in 2011 to partially finance our 2011 drilling program in the Company-operated Catalina Unit and at our non-operated properties in the Atlantic Rim and Pinedale Anticline.

Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2010:

						Less than				1 - 3				3 - 5				More than
		Total				one year				Years				Years				5 Years
Credit facility (a)		$	32,000			$	—			$	32,000			$	—			$	—
Interest on credit facility (b)			3,044				1,460				1,584				—				—
Capital leases			752				752				—				—				—
Operating leases			6,631				2,192				4,217				222				—
Total contractual cash commitments		$	42,427			$	4,404			$	37,801			$	222			$	—