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

• Weather and other natural phenomena;

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

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

• General economic and political conditions, including the current financial market volatility, tax rates or policies and inflation rates;

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

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

• Our ability to continue to develop our coal bed methane projects in the Atlantic Rim;

• Revisions to estimates of required capital expenditures;

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

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

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

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

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

• Unexpected changes in credit worthiness of third-parties that we enter into business agreements with;

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

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

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

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

• The volatility of our stock price; and

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

We may also make material acquisitions or divestitures or enter into financing transactions. None of these events can be predicted with certainty and the possibility of their occurring is not taken into consideration in the forward-looking statements.
New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward -looking statements, whether as a result of new information, future events, or otherwise. Business Overview and Strategy
We are an independent energy company engaged in the exploration, development, production and sale of natural gas and crude oil, primarily in Rocky Mountain Basins of the western United States. Double Eagle was incorporated in the State of Wyoming in January 1972 and reincorporated in the State of Maryland in February 2001. From 1995 to 2006, our common shares were publicly traded on the NASDAQ Capital Market under the symbol "DBLE". On December 15, 2006, our common shares began trading on the NASDAQ Global Select Market. Our Series A Cumulative Preferred Stock ("Preferred Stock") was issued and began trading on the NASDAQ Capital Market, under the symbol "DBLEP" on July 3, 2007 and began trading, under the symbol "DBLEP" on the NASDAQ Global Select Market on September 30, 2007. Our executive offices are located at 1675 Broadway, Suite 2200, Denver, Colorado 80202, and the telephone number there is (303)794-8445. Our operations offices are located at 777 Overland Trail, Casper, Wyoming 82601, and the telephone number there is (307) 237-9330.
Our objectives are to increase stockholder value, provide a positive and rewarding work environment for employees, and profitably operate and expand our assets. We plan to achieve these objectives by economically expanding our reserves, increasing and enhancing production of our existing properties, selectively pursuing strategic acquisitions, expanding our midstream business, and leveraging the experience of our employees. Our operations are currently focused on two core properties located in southwestern Wyoming where we have coal bed methane reserves and production in the Atlantic Rim area of the Eastern Washakie Basin, and tight sands gas reserves and production in the Pinedale Anticline. The operations in the Pinedale Anticline and Atlantic Rim operate under federal exploratory unit agreements between the working interest partners. 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") that surround the producing wells as a percentage of the entire acreage of the PA. This PA, and the associated working interest, will change as more wells and acreage are added to the PA. Effective December 21, 2007, as a result of the expansion of our operated acreage in the Atlantic Rim, the Catalina Unit PA was formed. During 2007, we drilled 33 producing wells in the Catalina Unit, all of which were completed and in production at September 30, 2008. The PA includes our original 14 Cow Creek Unit wells and the 33 new wells drilled. With the formation of the Catalina Unit PA, the Company's working interest was reduced from 100% to 73.84%. This working interest is applied to the production revenue, operating costs as well as the capital costs incurred. The Company recovered costs from the other working interest owners participating in the PA, in proportion to their working interests, which were originally recorded by the Company at our then 100% working interest.
Following are summary comments of our performance in several key areas during the three and nine months ended September 30, 2008 (Amounts in thousands of dollars, except amounts per unit of production):
• Average Daily Production

During the three months ended September 30, 2008, our total average daily net production increased 149% to 20,769 Mcfe as compared to average daily production of 8,329 Mcfe during the same prior year period. Total average daily production during the nine months ended September 30, 2008 increased 88% to 15,707 Mcfe as compared to average daily production of 8,368 Mcfe during the same prior year period. The fluctuations in production by major operating area are discussed below.
Atlantic Rim. During the three months ended September 30, 2008, average daily net production at the Atlantic Rim increased 202% to 14,929 Mcfe, as compared to 4,948 Mcfe during the same prior year period. This increase is the result of the production from 33 new wells which came on-line at our Catalina Unit properties during the first nine months of 2008. Average daily net production at our Catalina Unit increased 226% to 13,863 Mcfe, as compared to 4,248 Mcfe during the same prior year period. Average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 52% to 1,066 Mcfe, as compared to average daily production of 700 Mcfe during the same prior year period. The increase was due to production from 58 new Sun Dog Unit wells which were drilled as part of the 2007 drilling program. The operator at the Sun Dog Unit has informed us that it plans to bring one additional well on-line drilled during the 2007 drilling program in the fourth quarter of 2008. The operator has also informed us that it is in process of drilling up to 62 wells as part of its 2008 drilling program.

During the nine months ended September 30, 2008, average daily net production at the Atlantic Rim increased 121% to 10,436 Mcfe, as compared to 4,714 Mcfe during the nine months ended September 30, 2007. The increase was primarily the result of the production from 33 new wells which came on-line at our Catalina Unit properties during the first nine months of 2008. Average daily net production at our Catalina Unit increased 133% to 9,543 Mcfe, as compared to 4,099 Mcfe during the same prior year period. Average daily production at the Sun Dog and Doty Mountain units increased 45% to 893 Mcfe from 615 Mcfe in the nine months ended September 30, 2007.
Pinedale Anticline. Average daily production at the Pinedale Anticline increased 115% to 4,164 Mcfe for the quarter ended September 30, 2008, as compared to 1,933 Mcfe in the third quarter of 2007. The increase was primarily due to the addition of 22 new Mesa wells that were brought on-line in the first nine months of 2008. The operator at the Mesa Units has informed us that it is in the process of drilling up to 12 wells as part of the 2008 drilling program. During the nine months ended September 30, 2008, average daily production at the Pinedale Anticline increased 70% to 3,830 Mcfe as compared to 2,248 Mcfe in the nine months ended September 30, 2007, due to the added production from the wells brought on-line in the first nine months of 2008 as noted above.
Madden Deep Unit. During the three and nine months ended September 30, 2008, our average daily net production at the Madden Deep Unit was 423 Mcfe and 360 Mcfe, respectively compared to 290 Mcfe and 538 Mcfe in three and nine months ended September 30, 2007, respectively. The Madden Deep Unit experienced significant workovers in the third quarter of 2007, which resulted in decreased production. Such issues did not occur in the third quarter of 2008, resulting in an increase in average daily production of 46%. The decrease in the average daily production in the nine months ended September 30, 2008 was due largely to operational issues at the sour gas plant in the first half of 2008.
• Oil and Gas Sales

During the quarter ended September 30, 2008, net oil and gas sales increased 209% to $11,662, as compared to $3,779 during the same prior year period. Total revenue was impacted both by realized higher average gas prices and increased production volumes as discussed above. During the quarter ended September 30, 2008, the average CIG price increased 123% as compared to the same prior year period. In comparison, our average gas price received increased 31%, to $6.27 from $4.79, for the same period. The overall average increase in price that we experienced was less than the average CIG price increase due primarily to the fixed price contracts we have in place. See additional comments in "Contracted Volumes" below.
During the nine months ended September 30, 2008, net oil and gas sales increased 149% to $29,439, as compared to $11,812 during the same prior year period. Total revenue was impacted both by higher average gas prices and increased production volumes as discussed above. During the nine months ended September 30, 2008, the average CIG gas price increased 84% as compared to the same prior year period. The average gas price we received increased 35%, to $6.80 from $5.05 as compared to the same prior year period. The overall average increase in price that we experienced was less than the average CIG price increase due primarily to the fixed price contracts we have in place.
• Cash Flow from Operations

During the nine months ended September 30, 2008, we generated cash from operations of $15,100, as compared to cash flow of $544 in the nine months ended September 30, 2007. The increase was primarily the result of increased production and a higher realized gas price during the nine months ended September 30, 2008.

OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY
Liquidity and Capital Resources
We believe that we have sufficient liquidity and capital resources to continue our strategic plan, including continued development of our major natural gas projects in the Atlantic Rim and the Pinedale Anticline, as well as pursuit of exploration/development projects (see Capital Requirements below). We intend to use capital resources made available from future operating cash flow and through our $50 million bank line of credit ($35 million borrowing base) to fund this activity. We may also consider additional offerings of securities. Although we believe that we would be able to secure additional financing if required, we can provide no assurance that we will be able to do so or as to the terms of any additional financing. We also believe that cash provided by operating activities and amounts available under the revolving credit facility will be sufficient to meet our Series A Preferred Stock dividend requirements during the remainder of 2008 of approximately $931.
Information about our financial position is presented in the following table (amounts in thousands, except ratios):

                                               September 30,       December 31,
                                                   2008                2007
      Financial Position Summary
      Cash and cash equivalents               $           684     $          125
      Working capital                         $        (3,781 )   $       (7,012 )
      Line of credit outstanding              $        17,966     $        3,445
      Stockholders' equity                    $        45,541     $       28,624
      Ratios
      Long-term debt to total capital ratio              28.3 %             10.7 %
      Total debt to equity ratio                         39.5 %             12.0 %

During the nine months ended September 30, 2008, our negative working capital decreased to $(3,781) compared to negative working capital of $(7,012) at December 31, 2007. The increased working capital is primarily the result of a $14,279 increase in accounts receivable, primarily associated with amounts due from our joint interest partners at the Catalina Unit for their respective working interest percentage of current costs incurred as part of our 2008 drilling program. Also, an increase in our assets from price risk management of $7,568 contributed to the higher working capital balance. This increase resulted from the increased fair value of the new economic hedges we have entered into since the prior year-end. This was offset by a $19,042 increase in our accounts payable and accrued liabilities primarily related to capital expenditures from the 2008 drilling program. We often maintain a working capital deficit due to an agreement with our bank which allows us to apply any available cash balances to the outstanding line of credit on a daily basis, thereby minimizing our interest expense. We believe that approach is more beneficial than maintaining a positive working capital balance.
Cash flow activities
The table below summarizes our cash flows for the nine months ended September 30, 2008:

                                          Nine Months Ended September 30,
                                            2008                   2007
        Cash provided by (used in):
        Operating Activities          $         15,100       $            544
        Investing Activities                   (26,549 )              (23,208 )
        Financing Activities                    12,008                 33,884

        Net change in cash            $            559       $         11,220

During the nine months ended September 30, 2008, net cash provided by operating activities was $15,100 compared to $544 in the same prior year period. During the nine months ended September 30, 2008, the primary sources of cash were $8,042 of net income, which was net of non-cash charges of $7,998 related to depreciation, depletion, and amortization expenses ("DD&A") and accretion expense, and stock-based compensation expense of $554. In addition, we had an increase of $7,439 in accounts payable and accrued expenses related to operations and an increase of $4,554 in deferred taxes. These increases were partially offset by the increase in accounts receivable from operations of $11,832 and the non-cash gain on derivative contracts of $2,384 During the nine months ended September 30, 2008, net cash used in investing activities was $(26,549), as compared to $(23,208) in the same prior year period. During the first nine months of 2008 we invested in drilling and completion costs and power and compression infrastructure at our operated properties in the Catalina Unit as well as our share of costs for non-operated development wells in the Atlantic Rim and Pinedale Anticline from the 2007 drilling program.

During the nine months ended September 30, 2008, net cash provided by financing activities decreased to $12,008, as compared to $33,884 in the same prior year period. The net cash provided by financing activities was lower in the nine months ended September 30, 2008 due to the receipt of approximately $38 million in net proceeds from a public offering of Series A Preferred Stock in July 2007, combined with higher draws on our revolving line of credit to fund expenditures related to the 2007 and 2008 drilling programs. This was partially offset by three quarterly dividend payments totaling $2,792. Dividends will continue to be paid on a quarterly basis on the Series A Preferred Stock in the future at a rate of $931 per quarter.
Off-Balance Sheet Arrangements
We do not participate in transactions that generate relationships with unconsolidated entities or financial partnerships. Such entities are often referred to as structured finance or special purpose entities ("SPEs") or variable interest entities ("VIEs"). SPEs and VIEs can be established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. We were not involved in any unconsolidated SPEs or VIEs at any time during any of the periods presented in this Form 10-Q. From time to time, we enter into contracts that might be construed as off-balance sheet obligations but are normal in the day-to-day course of business in the oil and gas industry. Those contracts are the forward sales contracts discussed in "Contracted Volumes" below. We do not believe we will be affected by these contracts materially differently than other similar companies in the energy industry.
Capital Requirements
Our net capital expenditures for 2008 are expected to be approximately $40-$60 million for new coal bed gas development drilling in the Atlantic Rim and new development drilling the Pinedale Anticline, depending on project participation, timing and resource availability. In addition to development of our reserves in our core areas, we believe in engaging in exploratory efforts that may lead to new core areas in the future. The 2008 budget does not include the impact of any potential future exploration projects, or ongoing exploration or development activities, including the Table Top Unit #1 project. We continually evaluate our opportunities, and if a potential opportunity is identified that complements our identified areas of expertise, it may be pursued. We believe that the amounts available under our $50 million bank line of credit ($35 million borrowing base), and net cash provided by operating activities, will provide us with sufficient funds to maintain our current facilities and complete our 2008 capital expenditure program. We may also consider offerings of securities to raise additional capital. Line of Credit
The Company has a $50 million revolving line of credit collateralized by oil and gas producing properties. The borrowing base increased to $35 million from $25 million, pursuant to the debt modification agreement dated July 1, 2007, and all outstanding balances on the line of credit mature on July 31, 2010. As of September 30, 2008, the outstanding balance on the line of credit was $17,966 and the interest rate, calculated in accordance with the agreement at 1.125% below the posted Wall Street Journal Prime Rate, was 3.875% compared to 6.625% at September 30, 2007.
We are subject to certain financial and non-financial covenants with respect to the above credit facility, including a requirement to maintain a current ratio, plus the line of credit availability, of at least 1.0 to 1.0. As of September 30, 2008, we were in compliance with all such covenants. Should any of the covenants with respect to this credit facility be violated, and if we were 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.
For the three and nine months ended September 30, 2008, we recognized no interest expense with respect to the above credit lines, and capitalized interest totaled $222 and $515, respectively.

RESULTS OF OPERATIONS
Three months ended September 30, 2008 compared to the three months ended
September 30, 2007
Oil and gas sales volume and price comparisons

                                            Three Months Ended September 30,                         Percent        Percent
                                        2008                                 2007                    Volume          Price
                            Volume          Average Price        Volume         Average Price        Change         Change
Product:
Gas (Mcf)                   1,876,642      $          6.27        749,497      $          4.79            150 %           31 %
Oil (Bbls)                      5,685      $         98.42          2,798      $         66.91            103 %           47 %
Mcfe                        1,910,752      $          6.45        766,285      $          4.93            149 %           31 %

Our average gas price realized for the three months ended September 30, 2008 is calculated by summing 1) cash received from third parties for sale of our gas, included in the oil and gas revenue line item on the statement of operations, 2) settlement of our cash flow hedges included within oil and gas revenue on the statement of operations and 3) realized gain/loss on our economic hedges, which due to accounting rules is included in our price risk management activities line on the statement of operations, totaling $658 and $0, for the three months ended September 30, 2008 and 2007, respectively. This amount is divided by the total gas volume for the period.
For the three months ended September 30, 2008, total net production increased 149% to 1,910,752 Mcfe as compared to the three months ended September 30, 2007. The increase in volumes was due largely to the addition of wells at the Atlantic Rim and Pinedale Anticline, offset somewhat by the decrease of our working interest in the Catalina Unit resulting from unitization.
Prior to December 21, 2007, we owned 100% of the working interest in the Cow Creek Unit. With the formation of the Catalina Unit and expansion of the participating area, which included the 14 wells in the original Cow Creek Unit as well as the new wells from the 2007 drilling program, our working interest decreased to 73.84% in the Catalina Unit. During the three months ended September 30, 2008, average daily net production at the Atlantic Rim increased 202% to 14,929 Mcfe, as compared to 4,948 Mcfe during the three months ended September 30, 2007, largely resulting from the addition of 33 new wells which were on-line at our Catalina Unit properties during the period. Average daily net production at our Catalina Unit increased 226% to 13,863 Mcfe, as compared to 4,248 Mcfe during the same prior year period. Average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 52% to 1,066 Mcfe, as compared to average daily production of 700 during the same prior year period. The increase was due to the addition of 58 wells from the Sun Dog Unit's 2007 drilling program. The operator at Sun Dog Unit has informed us it expects to bring on one additional well during the fourth quarter of 2008. The operator has also informed us that it is in process of drilling up to 62 wells in the Sun Dog and Doty Mountain units as part of its 2008 drilling program. During the three months ended September 30, 2008, average daily production in the Pinedale Anticline increased 115% to 4,164 Mcfe, as compared to 1,933 Mcfe in the same prior year period. Twenty two new wells were brought online during the first nine months of 2008, resulting in the increased production. The operator at the Mesa Units has informed us that it is in process of drilling up to 12 additional wells as part of the 2008 drilling program.
During the three months ended September 30, 2008, the average daily production at the Madden Unit was 423 Mcfe compared to 290 Mcfe in the same prior year period. Significant workovers occurred at the Madden Deep Unit during the three months ended September 30, 2007, which resulted in decreased production. Such issues were avoided in 2008, and thus the average daily production increased 46%.
For the three months ended September 30, 2008, oil and gas revenue increased 209% to $11,662, as compared to the same prior year period. This increase was due in part to the production increases discussed above, as well as an increase in our average gas price realized. During the three months ended September 30, 2008, our average gas price realized increased 31%, to $6.27 from $4.79, as compared to an increase of 123% in the average CIG index price. Our realized average price did not increase consistent with the CIG index prices due to the . . .