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:
• The changing political environment in which we operate

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

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

• Our ability to 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;

• Our ability to successfully integrate and profitably operate any current and 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;

• The ability of third-party operators in projects in which we own an interest, to continue to develop these projects;

• 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.com.
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 nine months ended September 30, 2009 (Amounts in thousands of dollars, except amounts per unit of production):
• Average Daily Production

During the three months ended September 30, 2009, our total average daily net production increased 21% to 25,052 Mcfe as compared to average daily production of 20,769 Mcfe during the same prior-year period. Total average daily net production increased 63% to 25,533 in the first nine months of 2009, as compared to 15,707 Mcfe in the first nine months of 2008. The changes in production by major operating area are discussed below.
Atlantic Rim. During the three months ended September 30, 2009, average daily net production at the Atlantic Rim increased 18% to 17,585 Mcfe, as compared to 14,929 Mcfe during the three months ended September 30, 2008. This increase was primarily the result of the production from 20 new wells at the Catalina Unit from the 2008 drilling program. During the three months ended September 30, 2009, average daily net production at our Catalina Unit increased 11% to 15,391 Mcfe, as compared to 13,863 Mcfe during the same prior-year period. The Company continued to perform well workovers on certain existing wells in the Catalina Unit during the third quarter of 2009, which caused these wells to be off-line for periods of time and offset production from the new wells. Average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 106% to 2,194 Mcfe, as compared to average daily production of 1,066 Mcfe in the same period of 2008. The increase was due primarily to production from over 40 Sun Dog Unit wells which were drilled as part of the 2007 and 2008 drilling program, and increased production from the existing wells at the Doty Mountain Unit due to production enhancement projects.
Average daily net production at the Atlantic Rim increased 76% to 18,368 Mcfe in the nine months ended September 30, 2009, as compared to 10,436 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 nine months ended September 30, 2009, average daily net production at our Catalina Unit increased 72% to 16,415 Mcfe, as compared to 9,543 Mcfe during the same prior-year period. Average daily production at the Sun Dog and Doty Mountain units increased 119% to 1,953 Mcfe as compared to 893 Mcfe in the nine months ended September 30, 2008.

Pinedale Anticline. Average daily production net at the Pinedale Anticline increased 29% to 5,384 Mcfe for the three months ended September 30, 2009, as compared to 4,164 Mcfe in the same 2008 period. The increase in production is due to volume added from 16 new wells that were brought on-line in the first nine months of 2009. The operator expects to bring on one additional well for production in the fourth quarter of 2009. During the nine months ended September 30, 2009, average daily net production at the Pinedale Anticline increased 45% to 5,559 Mcfe as compared to 3,830 Mcfe in the nine months ended September 30, 2008.
Madden Deep Unit. During the three and nine months ended September 30, 2009, our average daily net production at the Madden Deep Unit was 597 Mcfe and 500 Mcfe, respectively, as compared to 423 Mcfe and 360 Mcfe in the three and nine months ended September 30, 2008, respectively. The sour gas plant experienced operational issues during the first quarter of 2008, which resulted in lower production for the nine months ended September 30, 2008. The sour gas plant was fully operational during the first nine months 2009.
• Oil and Gas Sales

During the three months ended September 30, 2009, oil and gas sales decreased 17% to $9,669, as compared to $11,662 during the same 2008 period. Although net production volumes increased at all significant properties, as discussed above, oil and gas sales were negatively impacted by lower realized average gas prices. During the three months ended September 30, 2009, the average CIG price decreased 52% as compared to the same prior-year period. In comparison, our average gas price received decreased 32%, to $4.27 from $6.27 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 4% to $30,661 for the nine months ended September 30, 2009, as compared to $29,439 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 63% over the nine months ended September 30, 2008, our total oil and gas sales were negatively impacted by lower realized average gas prices. During the nine months ended September 30, 2009, the average CIG gas price decreased 62% as compared to the same 2008 period. In comparison, the average gas price we received decreased 29%, to $4.83 from $6.80 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.
• Acquisition of Petrosearch Energy Corporation

On August 6, 2009, we completed our acquisition of Petrosearch Energy Corporation ("Petrosearch") in exchange for 1.8 million shares of Double Eagle common stock and cash consideration of $873. Upon closing of the acquisition, Petrosearch became a wholly-owned subsidiary of the Company. Through the acquisition, we obtained approximately $8.6 million of cash, as well as oil and gas properties valued at approximately $350. We believe the acquisition has enhanced our financial position and will provide financing for our current operations and future development projects, thereby providing the potential to increase reserves.
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
At September 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. Any outstanding balance on the revolving line of credit matures on July 31, 2010, as has been classified as a current liability on the consolidated balance sheet. 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 September 30, 2009, the outstanding balance on our credit facility was $34 million. The interest rate, calculated in accordance with the agreement, was 4.5%. This compared to an interest rate of 3.875% at September 30, 2008. 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. The Company was in compliance with all financial covenants at September 30, 2009. If the covenants are violated, and the Company is unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.
We recognized interest expense related to the credit facility of $216 and $0, for the three months ended September 30, 2009 and 2008, respectively, and $500 and $0 for the nine months ended September 30, 2009 and 2008, respectively. The Company capitalized interest costs of $260 and $222 for the three months ended September 30, 2009 and 2008, respectively, and $903 and $515 for the nine months ended September 30, 2009 and 2008, respectively We are actively negotiating an extension of our credit facility with our current lending group. Management believes the discussions have been positive and that it is highly likely an agreement will be reached in the fourth quarter of 2009 to extend our agreement out until at least 2012. 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):

                                                September 30,       December 31,
                                                    2009                2008
    Financial Position Summary
    Cash and cash equivalents                  $         3,075     $            -
    Working capital                            $       (36,145 )   $       (6,314 )
    Balance outstanding on credit facility     $        34,000     $       24,639
    Stockholders' equity and preferred stock   $        87,578     $       92,875

    Ratios
    Debt to total capital ratio                           28.0 %             21.0 %
    Total debt to equity ratio                            38.8 %             26.5 %

During the nine months ended September 30, 2009, our negative working capital balance decreased to $(36,145), as the $34,000 balance on our line of credit has been classified as current due to its maturity on July 31, 2010. Also during the nine month period, our accounts receivable balance decreased by $14,051 and the current price risk management assets decreased by $12,116. 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. These changes were offset somewhat by a $31,995 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.

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

                                          Nine Months Ended September 30,
                                            2009                   2008
        Cash provided by (used in):
        Operating Activities          $         19,474       $         15,100
        Investing Activities                   (22,560 )              (26,549 )
        Financing Activities                     6,161                 12,008

        Net change in cash            $          3,075       $            559

Net cash provided by operating activities was $19,474 for the nine months ended September 30, 2009, compared to $15,100 in the same prior-year period. During the nine months ended September 30, 2009, the primary sources of cash were $1,181 of net income, which was net of non-cash charges of $13,855 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 $7,018 and non-cash stock-based compensation expense of $1,071. In addition, we had a decrease in accounts receivable from operations of $15,219 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 $18,561 in accounts payable and accrued expenses related to operations.
During the nine months ended September 30, 2009, net cash used in investing activities totaled $22,560, as compared to $26,549 in the same prior-year period. During the first nine months 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. During the third quarter of 2009, we acquired Petrosearch in exchange for 1.8 million shares of Double Eagle common stock and cash consideration of $873. We assumed 100% of the assets and liabilities of Petrosearch, including cash and cash equivalents totaling $8,606. The net cash to the Company from this acquisition was $7,733. We also had cash outflows of $513 for transaction costs related to the acquisition. Refer to Note 3 in the Notes to the Consolidated Financial Statements for additional details regarding the Petrosearch acquisition. During the nine months ended September 30, 2009, net cash provided by financing activities decreased to $6,161, as compared to $12,008 in the same prior-year period. Borrowings on our line of credit decreased to $9,361 during the nine months ended September 30, 2009 from $14,521 in same 2008 period, as we used the net cash received from the Petrosearch acquisition to repay a portion of the outstanding balance on our line of credit during the third quarter of 2009. The borrowings during the period were primarily used to fund the 2008 drilling activity incurred in the fourth quarter of 2008. The borrowings were partially offset in both 2009 and 2008 by dividend payments on our Series A Preferred Stock in each of the first three quarters, 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 the projects in 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 did not include the impact of the Petrosearch merger, nor does it include the impact of any potential future exploration projects or other potential acquisitions. We believe that the amounts available under our 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 September 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 5
                              Total         or less          Years          Years            Years
Credit facility (a)         $  34,000      $   34,000      $       -      $       -      $            -
Interest on credit
facility (b)                    1,292           1,292              -              -                   -
Capital lease
commitments                     1,694             753            941              -                   -
Operating lease
commitments                     6,256           1,568          3,137          1,551                   -

Total contractual cash
commitments                 $  43,242      $   37,613      $   4,078      $   1,551      $            -

(a) Under the amended agreement, any balance outstanding on our revolving line of credit at July 31, 2010, will be due at that time. The Company is currently negotiating an extension of this maturity date.

(b) Assumes the interest rate on our revolving line of credit is consistent with that of September 30, 2009.

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

                                              Three Months Ended September 30,                          Percent        Percent
                                         2009                                  2008                     Volume          Price
                             Volume          Average Price         Volume          Average Price        Change         Change
Product:
Gas (Mcf)                    2,261,180      $          4.27        1,876,642      $          6.27             20 %          -32 %
Oil (Bbls)                       7,271      $         59.88            5,685      $         98.42             28 %          -39 %
Mcfe                         2,304,806      $          4.38        1,910,752      $          6.45             21 %          -32 %

Our average gas price realized for the three months ended September 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 $422 and $658, for the three months ended September 30, 2009 and 2008, respectively. This amount is divided by the total Mcfe volume for the period. For the three months ended September 30, 2009, total net production increased 21% to 2,305 MMcfe, as compared to the three months ended September 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 lost production from workover 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 69.31%. Our interest will continue to change as the Unit expands further.

During the three months ended September 30, 2009, average daily net production . . .