The terms "Double Eagle", "Company", "we", "our", and "us" refer to Double Eagle Petroleum Co. and its subsidiaries, as a consolidated entity, unless the context suggests otherwise.
FORWARD-LOOKING STATEMENTS This Quarterly Report on Form 10-Q 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-Q 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 our Annual Report on Form 10-K for the year ended December 31, 2008, including the following:
• 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;

• The changing political environment in which we operate

• 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;

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

• 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;

• 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;

• 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 three and six months ended June 30, 2009 (Amounts in thousands of dollars, except amounts per unit of production):
• Average Daily Production

During the three months ended June 30, 2009, our total average daily net production increased 60% to 26,209 Mcfe as compared to average daily production of 16,419 Mcfe during the same prior-year period. Total average daily net production increased 96% to 25,777 in the first six months of 2009, as compared to 13,148 Mcfe in the first half of 2008. The changes in production by major operating area are discussed below.

Atlantic Rim. During the three months ended June 30, 2009, average daily net production at the Atlantic Rim increased 78% to 19,724 Mcfe, as compared to 11,109 Mcfe during the three months ended June 30, 2008. This increase was primarily the result of the production from a total of 30 new wells at the Catalina Unit; 10 of which were drilled in 2007 and came on-line for production in the third quarter 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. During the three months ended June 30, 2009, average daily net production at our Catalina Unit increased 73% to 17,283 Mcfe, as compared to 10,002 Mcfe during the same prior-year period. The increase in production from the new wells in the Catalina Unit was partially offset by reduced production from certain existing wells due to workovers performed in the second quarter. Average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 121% to 2,441 Mcfe, as compared to average daily production of 1,107 Mcfe in the same period of 2008. The increase was due primarily to production from approximately 50 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.

Average daily net production at the Atlantic Rim increased 130% to 18,766 Mcfe in the six months ended June 30, 2009, as compared to 8,165 Mcfe during the same prior-year period. The increase was 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 quarter 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. During the six months ended June 30, 2009, average daily net production at our Catalina Unit increased 130% to 16,935 Mcfe, as compared to 7,359 Mcfe during the same prior-year period. Average daily production at the Sun Dog and Doty Mountain units increased 127% to 1,831 Mcfe as compared to 806 Mcfe in the six months ended June 30, 2008.

Pinedale Anticline. Average daily production at the Pinedale Anticline increased 30% to 5,153 Mcfe for the three months ended June 30, 2009, as compared to 3,961 Mcfe in the same 2008 period. The increase in production is due to volume added from 12 new wells in the third quarter of 2008 and eight new wells in the second quarter of 2009. The operator expects to bring an additional eight wells on-line for production in the third and fourth quarters of 2009.

During the six months ended June 30, 2009, average daily production at the Pinedale Anticline increased 54% to 5,648 Mcfe as compared to 3,661 Mcfe in the six months ended June 30, 2008, due to the added production from the wells brought on-line in the third quarter of 2008 and second quarter of 2009 as discussed above.

Madden Deep Unit. During the three and six months ended June 30, 2009, our average daily net production at the Madden Deep Unit was 513 Mcfe and 451 Mcfe, respectively, as compared to 455 Mcfe and 328 Mcfe in the three and six months ended June 30, 2008, respectively. 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 half of 2009.

• Oil and Gas Sales

During the three months ended June 30, 2009, oil and gas sales decreased 9% to $10,492, as compared to $11,526 during the same 2008 period. Although net production volumes increased at all significant properties, as discussed above, oil and gas sales was negatively impacted by lower realized average gas prices. During the three months ended June 30, 2009, the average CIG price decreased 70% as compared to the same prior-year period. In comparison, our average gas price received decreased 42%, to $4.34 from $7.54 for the same period. The overall average decrease in the gas 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.

Oil and gas sales increased 18% to $20,992 for the six months ended June 30, 2009, as compared to $17,777 during the same prior year period. The increase in oil and gas sales was attributed to higher production volumes at each of our significant properties, as discussed above. Although production volumes increased 60% over the first half of 2008, our total oil and gas sales was negatively impacted by lower realized average gas prices. During the six months ended June 30, 2009, the average CIG gas price decreased 65% as compared to the same 2008 period. In comparison, the average gas price we received decreased 29%, to $5.10 from $7.23 as compared to the same prior-year 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.

OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY
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. We believe that the liquidity available from these sources will meet the anticipated short and long-term requirements of the Company, including the capital requirements and contractual obligations noted below. However, we can give no assurances that these historical sources of liquidity and capital resources will be available for future development projects, and we may be required to seek additional or alternative financing sources.
Credit Facility
As of June 30, 2009, the Company had a $75 million credit facility in place, with a $45 million borrowing base, collateralized by its oil and gas producing properties and other assets. Under this facility, $5 million of the $45 million borrowing base represented a term loan, which if drawn upon, was to be repaid by July 31, 2009, and the remaining $40 million of available borrowing base was a revolving line of credit. Any outstanding balance on the revolving line of credit matures on July 31, 2010. The interest rate on this credit facility varies based on prevailing market rates and our level of outstanding borrowings, with a minimum floor rate of 4.5%.

As of June 30, 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 4.5% on the revolving line of credit and 6.75% on the term loan. This compared to an interest rate of 3.875% at June 30, 2008.
Effective July 22, 2009, the Company amended its credit facility to terminate the $5 million term loan and to increase the revolving line of credit from $40 million to $45 million. As a result of the amendment, the $3.75 million outstanding under the term loan was rolled into the revolving line of credit and is no longer due July 31, 2009. Any balance outstanding on the revolving line of credit matures July 31, 2010. No changes were made to the interest rate as part of this amendment.
Under our credit facility, we are subject to certain financial and non-financial covenants. The financial covenants include maintaining a current ratio, as defined, of 1.0 to 1.0, as well as a ratio of earnings before interest, taxes, depreciation, depletion, and amortization ("EBITDA") to interest plus dividends, of 1.5 to 1.0. As of June 30, 2009, our current ratio was .99 to 1.0 and as a result, we were not in compliance with the current ratio covenant. The lenders waived the current ratio covenant until September 30, 2009. Management believes it is probable that we will be in compliance with all covenants at all assessment dates through June 30, 2010. If we had been unable to negotiate a waiver or amendment thereof, the lenders 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 six months ended June 30, 2009 and 2008, we recognized interest expense of $284 and $0, respectively, related to the credit facility. The Company capitalized interest costs of $343 and $188 for the three months ended June 30, 2009 and 2008, respectively, and $643 and $293 for the six months ended June 30, 2009 and 2008, respectively We are actively engaged in negotiations with our current lending group to bring in additional lenders, and to extend the maturity date of our credit facility past July 31, 2010. Although we expect to finalize a new agreement by the end of 2009, we can provide no assurance that we will be able to do so or what the terms of the financing will be. We also may consider additional offerings of securities.
Information about our financial position is presented in the following table (amounts in thousands, except ratios):

                                                  June 30,       December 31,
                                                    2009             2008
       Financial Position Summary
       Cash and cash equivalents                  $   3,898     $            -
       Working capital                            $  (1,524 )   $       (6,314 )
       Balance outstanding on credit facility     $  42,500     $       24,639
       Stockholders' equity and preferred stock   $  85,258     $       92,875
       Ratios
       Debt to total capital ratio                     33.3 %             21.0 %
       Total debt to equity ratio                      49.8 %             26.5 %

During the six months ended June 30, 2009, our negative working capital balance decreased to $(1,524) compared to negative working capital of $(6,314) at December 31, 2008. The increased working capital balance is primarily the result of a $28,140 decrease in accounts payable and accrued expenses due to payments we made to vendors in the first quarter of 2009 related to drilling costs incurred in the fourth quarter of 2008. This was partially offset by a $12,885 decrease in our accounts receivable balance and an $8,308 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. The decrease in current price risk management assets is due primarily to the settlement of derivative contracts we had in place at December 31, 2008.

Cash flow activities
The table below summarizes our cash flows for the six months ended June 30, 2009 and 2008, respectively:

                                             Six Months Ended June 30,
                                               2009               2008
             Cash provided by (used in):
             Operating Activities          $      16,826       $   10,470
             Investing Activities                (28,650 )        (24,484 )
             Financing Activities                 15,722           14,154

             Net change in cash            $       3,898       $      140

Net cash provided by operating activities was $16,826 for the six months ended June 30, 2009, compared to $10,470 in the same prior-year period. During the six months ended June 30, 2009, the primary sources of cash were $765 of net income, which was net of non-cash charges of $9,147 related to depreciation, depletion, and amortization expenses ("DD&A") and accretion expense, an unrealized non-cash loss on the change in fair value of our derivatives of $6,218 and non-cash stock-based compensation expense of $770. In addition, we had a decrease in accounts receivable from operations of $14,137 primarily related to the collection of receivables from our joint interest partners for capital expenditures at the Catalina Unit. These changes were offset partially by a decrease of $14,376 in accounts payable and accrued expenses related to operations.
During the six months ended June 30, 2009, net cash used in investing activities was $28,650, as compared to $24,484 in the same prior-year period. During the first half 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 $320 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 six months ended June 30, 2009, net cash provided by financing activities increased to $15,722, as compared to $14,154 in the same prior-year period. Borrowings on our line of credit increased to $17,861 during the six months ended June 30, 2009 from $15,739 in same 2008 period, and were primarily used to fund the 2008 drilling activity incurred in the fourth quarter of 2008. Borrowings were partially offset in both 2009 and 2008 by the first and second quarter dividend payments totaling $1,862. Dividends are expected to be paid on a quarterly basis on the Series A Preferred Stock in the future at a rate of approximately $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 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 newly amended credit facility, 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.

Contractual Obligations
The expected impact that our contractual obligations as of June 30, 2009 will
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 credit
facility (b)                    1,940           1,790            150              -                  -
Capital lease
commitments                     1,882             753          1,129              -                  -
Operating lease
commitments                     6,647           1,567          3,137          1,943                  -

Total contractual cash
commitments                 $  52,969      $    7,860      $  43,166      $   1,943      $           -

(a) Effective July 22, 2009, we amended our credit facility to terminate the $5 million term loan and to increase the revolving line of credit from $40 million to $45 million. As a result of the amendment, the $3.75 million outstanding under the term loan was rolled into the revolving line of credit and is not longer due July 31, 2009. Under the amended agreement, 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 revolving line of credit is consistent with that of June 30, 2009.

RESULTS OF OPERATIONS
Three months ended June 30, 2009 compared to the three months ended June 30,
2008
Oil and gas sales volume and price comparisons

                                                Three Months Ended June 30,                             Percent        Percent
                                         2009                                  2008                     Volume          Price
                             Volume          Average Price         Volume          Average Price        Change         Change
Product:
Gas (Mcf)                    2,342,787      $          4.34        1,472,469      $          7.54             59 %          -42 %
Oil (Bbls)                       7,039      $         46.03            3,613      $        116.15             95 %          -60 %
Mcfe                         2,385,021      $          4.40        1,494,147      $          7.71             60 %          -43 %

Our average gas price realized for the three months ended June 30, 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 operations, 2) settlement of our cash flow hedges included within oil and gas sales on the consolidated statement of operations and 3) realized gain/loss on our economic hedges, which is included in our price risk management activities line on the consolidated statement of operations, totaling $0 and $0, for the three months ended June 30, 2009 and 2008, respectively. This amount is divided by the total Mcfe volume for the period. For the three months ended June 30, 2009, total net production increased 60% to 2,385 MMcfe, as compared to the three months ended June 30, 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 and work-over activity 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 three months ended June 30, 2009, average daily net production at the Atlantic Rim increased 78% to 19,724 Mcfe, as compared to 11,109 Mcfe during the . . .