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

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

• Our ability to maintain adequate liquidity;

• Incorrect estimates of required capital expenditures;

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

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

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

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

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

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

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

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

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

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

• General economic conditions, including the current financial crisis, 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;

• Weather and other natural phenomena;

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

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

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

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

• The volatility of our stock price; and

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

We also may 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 July 30, 2007 on the NASDAQ Capital Market, under the symbol "DBLEP". On September 30, 2007, our Preferred Stock began trading on the NASDAQ Global Select Market. 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 website is www.dble.us.
Our objective is to increase long-term stockholder value by implementing our corporate strategy of economically growing our reserves and production through the development of our existing core properties, partnering on selective exploration projects, and pursuing strategic acquisitions that expand or complement our existing operations. Our operations 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.
Following are summary comments of our performance in several key areas during the quarter ended March 31, 2009 (Amounts in thousands of dollars, except amounts per unit of production):
• Average Daily Production

During the quarter ended March 31, 2009, our total average daily net production increased 157% to 25,340 Mcfe as compared to average daily production of 9,877 Mcfe during the same prior-year period. The changes in production by major operating area are discussed below.
Atlantic Rim. During the quarter ended March 31, 2009, average daily net production at the Atlantic Rim increased 241% to 17,797 Mcfe, as compared to 5,220 Mcfe during the first quarter of 2008. This increase is primarily the result of the production from a total of 43 new wells at the Catalina Unit; 23 of which were drilled in 2007 and came on-line for production in the second and third quarters of 2008, and the remaining 20 wells were drilled in 2008 and were brought on-line during the fourth quarter of 2008 and the first quarter of 2009. Average daily net production at our Catalina Unit increased 252% to 16,583 Mcfe, as compared to 4,715 Mcfe during the same prior-year period. Average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 140% to 1,214 Mcfe, as compared to average daily production of 505 Mcfe during the first quarter of 2008. The increase was due to production from 109 new Sun Dog Unit wells which were drilled as part of the 2007 and 2008 drilling programs, and nine new wells drilled at the Doty Mountain Unit during the 2008 drilling program.

Pinedale Anticline. Average daily production at the Pinedale Anticline increased 83% to 6,148 Mcfe for the quarter ended March 31, 2009, as compared to 3,361 Mcfe in the first quarter of 2008. The increase was primarily due to the addition of 22 new Mesa wells that were brought on-line in the second and third quarters of 2008. The operator at the Mesa Units has informed us that it is in the process of drilling up to 20 new wells, which are expected to come on-line at a rate of four new wells in May, four in August, four in September, two in October, and six in November 2009.
Madden Deep Unit. During the quarter ended March 31, 2009, our average daily net production at the Madden Deep Unit increased 93% to 388 Mcfe, as compared to 201 Mcfe in the quarter ending March 31, 2008. The sour gas plant experienced operational issues during the first quarter of 2008, which resulted in lower production. The sour gas plant was fully operational during the first quarter of 2009.
• Oil and Gas Sales

During the quarter ended March 31, 2009, net oil and gas sales increased 68% to $10,500, as compared to $6,251 during the first quarter of 2008. Total revenue increased due to the higher production volumes discussed above, but was negatively impacted by lower realized average gas prices. During the quarter ended March 31, 2009, the average CIG price decreased 60% as compared to the same prior-year period. In comparison, our average gas price received decreased 12%, to $5.90 from $6.69 for the same period. The overall average decrease in price that we experienced was less than the average CIG price decrease due primarily to the hedging instruments we had in place during the period. See additional comments in "Contracted Volumes" below.
• Cash Flow from Operations

During the quarter ended March 31, 2009, we generated cash flow from operations of $6,935, as compared to cash flow of $2,463 in the quarter ended March 31, 2008. The increase was primarily the result of increased production.
OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY
Liquidity and Capital Resources
We believe that we have sufficient liquidity and capital resources to continue our long-term strategic plan, including our 2009 capital program (see Capital Requirements below). We intend to use capital resources made available from future operating cash flow and through our $75 million credit facility ($45 million borrowing base, including a $5 million term loan) to fund this activity. We also may 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 what the terms of any additional financing would be.
Information about our financial position is presented in the following table (amounts in thousands, except ratios):

                                                 March 31,       December 31,
                                                   2009              2008
       Financial Position Summary
       Cash and cash equivalents                $     2,171     $            -
       Working capital                          $     3,591     $       (6,314 )
       Balance outstanding on credit facility   $    42,500     $       24,639
       Stockholders' equity                     $    54,687     $       54,903
       Ratios
       Debt to total capital ratio                     31.4 %             21.0 %
       Total debt to equity ratio                      77.7 %             44.9 %

During the quarter ended March 31, 2009, our working capital increased to $3,591 compared to negative working capital of $(6,314) at December 31, 2008. The increased working capital is primarily the result of a $27,712 decrease in accounts payable due to payments we made to vendors in the first quarter of 2009 related to drilling costs incurred in the fourth quarter of 2009. This was partially offset by an $11,949 decrease in our accounts receivable balance and a $3,123 decrease in current price risk management assets since December 31, 2008. The decrease in the accounts receivable balance was due to cash receipts from our joint interest partners at the Catalina Unit for their respective working interest percentage of costs incurred as part of the 2008 drilling program.

Cash flow activities
The table below summarizes our cash flows for the quarters ended March 31, 2009 and 2008, respectively:

                                              Quarter ended March 31,
                                                2009             2008
              Cash provided by (used in):
              Operating Activities          $      6,935       $   2,463
              Investing Activities               (21,546 )       (11,003 )
              Financing Activities                16,782           8,592

              Net change in cash            $      2,171       $      52

During the quarter ended March 31, 2009, net cash provided by operating activities was $6,935 compared to $2,463 in the same prior-year period. During the quarter ended March 31, 2009, the primary sources of cash were $1,007 of net income, which was net of non-cash charges of $4,406 related to depreciation, depletion, and amortization expenses ("DD&A") and accretion expense, a non-cash loss on the change in fair value of our derivatives of $4,066 and non-cash stock-based compensation expense of $468. In addition, we had a decrease in accounts receivable from operations of $11,949. These changes were offset partially by a decrease of $15,089 in accounts payable and accrued expenses related to operations and an increase of $631 in deferred taxes.
During the quarter ended March 31, 2009, net cash used in investing activities was $21,546, as compared to $11,003 in the same prior-year period. During the first quarter of 2009, our capital expenditures were primarily related to the completion of the 2008 drilling program at our operated properties in the Catalina Unit as well as our share of costs for non-operated development wells in the Atlantic Rim and Pinedale Anticline. We also had cash outflows of $102 related to the proposed merger of Petrosearch Energy Corp ("Petrosearch"). The Company entered into a definitive agreement to merge with Petrosearch on March 30, 2009. The proposed merger is structured as an all-stock transaction, subject to closing adjustments, and requires approval by the stockholders of Petrosearch. Refer to Note 13 in the Notes to the Consolidated Financial Statements for additional details regarding the potential Petrosearch merger. During the quarter ended March 31, 2009, net cash provided by financing activities increased to $16,782, as compared to $8,592 in the same prior-year period. The net cash provided by financing activities was higher in the first quarter of 2009, as compared to the first quarter of 2008, due to higher draws on our credit facility to fund the 2008 drilling activity incurred in the fourth quarter of 2008. This was partially offset by the first quarter dividend payment totaling $931. Dividends are expected 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.
Line of Credit
Effective February 26, 2009, the Company renegotiated its $50 million revolving line of credit into a $75 million credit facility collateralized by its oil and gas producing properties and other assets, and the borrowing base increased to $45 million from $35 million. Under the modified agreement, $5 million of the $45 million borrowing base represents a term loan, which if drawn upon, becomes due July 31, 2009, and the remaining $40 million of available borrowing base will be a revolving line of credit. Any outstanding balance on the revolving line of credit matures on July 31, 2010. The interest rate on the new credit facility will vary based on prevailing market rates and our level of outstanding borrowings, with a minimum floor rate of 4.5%.

As of March 31, 2009, the outstanding balance on our credit facility was $42.5 million ($38.75 million on the revolving line of credit and $3.75 million on the term loan). The interest rate, calculated in accordance with the agreement, was 6.0% on the revolving line of credit and 6.75% on the term loan. This compared to an interest rate of 4.125% at March 31, 2008.
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 beginning June 30, 2009, and a ratio of earnings before interest, taxes, depreciation, depletion, and amortization ("EBITDA"), to interest, plus dividends of 1.5 to 1.0. As of March 31, 2008, we were in compliance with all such covenants. Management also believes that it is probable that we will be able to meet the current ratio covenant at June 30, 2009. 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 quarters ended March 31, 2009 and 2008, we recognized interest expense of $0 and $0, respectively, on the credit facility. We capitalized interest costs of $300 and $106 for the quarters ended March 31, 2009 and 2008, respectively.
Capital Requirements
Our net capital expenditures for 2009 are expected to be approximately $10-$20 million for production enhancement projects in the Catalina, Sun Dog and Doty Mountain Units and continued participation in the development drilling at the Pinedale Anticline. The 2009 budget does not include the impact of any potential future exploration projects, or ongoing exploration or development activities, or potential acquisitions, including Petrosearch. We believe that the amounts available under our $75 million credit facility ($40 million borrowing base, plus $5 term loan), and net cash provided by operating activities, will provide us with sufficient funds to meet future financial covenants, develop new reserves, maintain our current facilities, and complete our 2009 capital expenditure program. We also may consider offerings of securities to raise additional capital.
Contractual Obligations
The impact that our contractual obligations as of March 31, 2009 are expected to have on our liquidity and cash flows in future periods is:

                                                      Payments due by period
                                            One year         2 - 3          4 - 5          More than
                              Total         or less          Years          Years           5 Years
Credit facility (a)         $  42,500      $    3,750      $  38,750      $       -      $           -
Interest on line of
credit (b)                      3,209           2,421            788              -                  -
Capital lease
commitments                     2,070             753          1,317              -                  -
Operating lease
commitments                     7,029           1,557          3,138          2,334                  -

Total contractual cash
commitments                 $  54,808      $    8,481      $  43,993      $   2,334      $           -

(a) The amount listed reflects the balance outstanding as of March 31, 2009. Any balance outstanding on our revolving line of credit at July 31, 2010, will be due at that time.

(b) Assumes the interest rate on our credit facility is consistent with that of March 31, 2009.

RESULTS OF OPERATIONS
Quarter ended March 31, 2009 compared to the quarter ended March 31, 2008
Oil and gas sales volume and price comparisons

                                                Quarter Ended March 31,                              Percent        Percent
                                        2009                                 2008                    Volume          Price
                            Volume          Average Price        Volume         Average Price        Change         Change
Product:
Gas (Mcf)                   2,234,415      $          5.90        865,988      $          6.69            158 %          -12 %
Oil (Bbls)                      7,696      $         30.68          5,464      $         83.34             41 %          -63 %
Mcfe                        2,280,591      $          5.89        898,772      $          6.96            154 %          -15 %

Our average gas price realized for the quarter ended March 31, 2009 is calculated by summing 1) production revenue received from third parties for sale of our gas, which is included in the oil and gas sales line item on the consolidated statement of income 2) settlement of our cash flow hedges included within oil and gas sales on the consolidated statement of income and 3) realized gain/loss on our economic hedges, which is included in our price risk management activities line on the consolidated statement of income, totaling $2,926 and $0, for the quarters ended March 31, 2009 and 2008, respectively. This amount is divided by the total Mcfe volume for the period.
For the quarter ended March 31, 2009, total net production increased 154% to 2,281 MMcfe, as compared to the quarter ended March 31, 2008. The increase in volumes was due largely to the addition of production wells at the Atlantic Rim and Pinedale Anticline, offset somewhat by the decrease of our working interest in the Catalina Unit. As a result of the 2008 drilling program, the Catalina Unit participating area expanded, and our working interest decreased from 73.84% to 68.35%. Our interest will continue to change as the Unit expands further. During the quarter ended March 31, 2009, average daily net production at the Atlantic Rim increased 241% to 17,797 Mcfe, as compared to 5,220 Mcfe during the same prior-year period, largely resulting from the addition of 43 new wells which were on-line at our Catalina Unit properties during the period. Twenty-three of the 43 wells were drilled during the 2007 drilling program and came on-line in the second quarter of 2008, and 20 wells that were drilled during the 2008 drilling program came on-line during the fourth quarter of 2008 and first quarter of 2009. Average daily net production at our Catalina Unit increased 252% to 16,583 Mcfe, as compared to 4,715 Mcfe during the first quarter of 2008. Average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 140% to 1,214 Mcfe, as compared to average daily production of 505 during the same prior-year period. The increase was due to the addition of 109 wells at the Sun Dog Unit's from the 2007 and 2008 drilling programs, and nine new wells at the Doty Mountain Unit from the 2008 drilling program.
Average daily production in the Pinedale Anticline increased 83% during the quarter ended March 31, 2009, to 6,148 Mcfe, as compared to 3,361 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 20 additional wells, which are expected to come on-line at a rate of four wells in May, four wells in August, four wells in September, two wells in October, and six wells in November 2009.
During the quarter ended March 31, 2009, the average daily production at the Madden Unit was 388 Mcfe compared to 201 Mcfe in the same prior-year period. The sour gas plant experienced significant operational issues during the first quarter of 2008, which limited the output of natural gas. The sour gas plant was fully operational during the first quarter of 2009.
For the quarter ended March 31, 2009, oil and gas revenue increased 68% to $10,500, as compared to the same prior-year period. This increase was primarily volume driven, due to increased production at each of our major fields, as discussed above. The increase in production volumes was partially offset by a decrease in our average gas price realized. During the quarter ended March 31, 2009, our average gas price realized decreased 12%, to $5.90 from $6.69, as compared to a decrease of 60% in the average CIG index price. Our realized average price did not decrease consistent with the CIG index prices due to the hedging instruments in place during the quarter. See additional comments under "Contracted Volumes" below.
Transportation and gathering revenue
During the quarter ended March 31, 2009, transportation and gathering revenue increased 336% to $1,587 from $364. The Company receives 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 increase in revenue is due to an increase in the fee charged to third parties and higher production volumes at the Catalina Unit discussed above.
Price risk management activities
We recorded a net loss on our derivative contracts that did not qualify for cash flow hedge accounting of $1,140 for the quarter ended March 31, 2009, as compared to a gain of $652 for the quarter ended March 31, 2008. This amount consists of an unrealized loss of $4,066, which represents a change in the fair value of our mark-to-market derivative instruments at March 31, 2009, and a net realized gain of $2,926 related to the settlements of some of our economic hedges.

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