We intend to increase our reserves, production, revenues, and cash flow by focusing primarily on: (i) new coal bed methane gas development and enhancement of field facilities on operated and non-operated properties in the Atlantic Rim;
(ii) continued participation in the development of the Mesa Fields on the Pinedale Anticline and (iii) expansion of our midstream business. We also may pursue selective high potential, low to medium risk, exploration projects where we have accumulated detailed geological knowledge and strategic acquisitions that may expand or complement our existing operations. Developments since December 31, 2007:
The Company's focus in 2008 was the continuing development of production and reserve growth at our operated and non-operated properties in the Atlantic Rim and our continued participation in the development of the Pinedale Anticline. We participated in an active oil and gas development program within our core areas in 2008, including the following:
• At our Company-operated Catalina Unit, located within the Atlantic Rim, we completed and brought on-line a total of 32 new producing wells. Twenty-seven of the new wells were drilled as part of the 2007 drilling program, and were completed and brought on-line for production during the first six months of 2008. In the third and fourth quarter of 2008, we also drilled 24 additional potential producing wells as part of our 2008 drilling season, of which five were completed and producing by December 31, 2008. One of the 24 potential producing wells drilled was determined to be a developmental dry hole and was plugged and abandoned. This well encountered a major structural fault, resulting in the absence of mesaverde coals at that location. Knowing the location of this fault of the fault will assist us in locating future well positions. Wells beyond this fault are believed to be productive. We expect to have the remaining wells completed and available for production by the end of the first quarter 2009. Upon reaching the total drilled depth of the 24 wells spud in the 2008 drilling program, our working interest in the Catalina Unit decreased from 73.84% to 68.35%. Our working interest will continue to adjust upon expansion of the unit.

• At the Sun Dog Unit, in which the Company currently has a working interest of 9.75%, 64 wells were brought on-line for production during 2008. We also participated in the drilling of 45 additional producing wells within the Sun Dog Unit. Drilling is complete on these new wells, and the operator expects the wells to be completed and producing by the end of the second quarter of 2009. At the Doty Mountain Unit, in which Double Eagle has 18.00% working interest, the operator drilled 18 new producing wells during 2008. In addition, the operator began a test pilot program for fracture stimulation of existing wells. We are currently awaiting results of this study.

• In the Mesa "B" Unit at the Pinedale Anticline, 22 new wells were brought on-line during the second and third quarters of 2008. We are also participating in the drilling of 20 additional wells. These wells were spud in the fall of 2008, and are expected to be completed in 2009 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.

• In the Wind River Basin, we completed the Waltman 34-24 well in June, 2008. This well is a 40-acre offset to the Chevron Waltman 96 well that has been producing since early 2007. However, due to unfavorable hole conditions, we were unable to install casing to the well's total depth. The well was completed at a depth of 4,349-4,374 and we intend to produce the upper gas zone in the second quarter of 2009. In August 2008, we began drilling the Waltman 24-24 well. We expect to complete the well at a depth of between 8,500 and 9,100 feet, and to begin producing in both the upper and lower gas zones in the second quarter of 2009.

• On the Moxa Arch, we participated in the drilling of 47 development wells in 2008, with working interests ranging from 0.14% to 6.02% in 2008.

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 agreement, $5 million of the $45 million borrowing base represents a term loan, which if drawn upon, has to be repaid on or before July 31, 2009 and the remaining $40 million of available

borrowing base will be a revolving line of credit. Any remaining outstanding balances on the line of credit mature on July 31, 2010. Under this credit facility, we are subject to both financial and non-financial covenants. The financial covenants include maintaining a current ratio, as defined, of 1.0:1.0, as well as a ratio of earnings before interest, taxes, depreciation, depletion, and amortization ("EBITDA") to interest plus dividends of 1.5:1.0. The interest rate on the new credit facility will vary based upon the prevailing market rates, with a floor rate of 4.5%. The Company paid approximately $100 in one-time financing fees and related expenses in renegotiating this new facility in 2009.
The Company implemented a market awareness program during 2008 in order to increase the Company's visibility to sophisticated investors and grow the institutional shareholder base. As part of this program, the Company's Chief Executive Officer, Chief Financial Officer, and Senior Vice-President of Exploration and New Ventures conducted a road show in six different cities across the country, and presented at four investor conferences. The Company expects to continue this effort into 2009.
In June, 2008, the Company joined the Russell 2000® and 3000® indices when Russell performed its annual reconstitution of the Russell US Indexes. Membership in the indices will remain in place for one year. Our Industry:
The exploration for, and the acquisition, development, production, and sale of, natural gas and crude oil is highly competitive and capital intensive. As in any commodity business, the market price of the commodity produced and the costs associated with finding, acquiring, extracting, and financing the operation are critical to profitability and long-term value creation for stockholders. Generating reserve and production growth while containing costs represents an ongoing focus for management, and is made particularly important in our business by the natural production and reserve decline associated with oil and gas properties. In addition to developing new reserves, we compete to acquire additional reserves, which involve judgments regarding recoverable reserves, future oil and gas prices, operating costs and potential environmental and other liabilities, title issues and other factors. During periods of historically high oil and gas prices, third party contractor and material cost increases are more prevalent due to increased competition for goods and services. Other challenges we face include attracting and retaining qualified personnel, gaining access to equipment and supplies and maintaining access to capital on sufficiently favorable terms.
We have taken the following steps to mitigate the challenges we face:
• We attempt to reduce our overall exposure to commodity price fluctuations through the use of various fixed delivery contracts and other economic hedging instruments for some of our production. The duration of our various hedging instruments depends on our view of market conditions, available contract prices and our operating strategy. Use of such hedging instruments may limit the risk of fluctuating cash flows. As of December 31, 2008, we had sales delivery contracts in effect for approximately 61% of our current daily net production.

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

Development Outlook for 2009:
We expect to have $10-$20 million of capital available for development programs in 2009. The drilling activity provided for in the 2009 capital budget is primarily allocated to the projects below.
Atlantic Rim. We intend to initiate and participate in well production enhancement projects in the Catalina, Sun Dog and Doty Mountain Units during 2009. In 2008, Anadarko fracture stimulated several pilot wells within the Doty Mountain Unit. The operator intends to continue to fracture stimulate additional wells within the Doty Mountain Unit during 2009. We do not intend to drill any new production wells within the Catalina Unit in 2009, but we do expect to incur some costs as we complete and hook up 18 wells drilled during 2008, which were not producing at December 31, 2008.
Pinedale Anticline. At the Pinedale Anticline, the operator has informed us of its intentions to complete and hook up the 20 wells spud in the fall of 2008 at a rate of four wells in May, four in August, four in September, two in October, and six in November. We believe the operator will drill four additional wells in 2009.

Other. Management intends to complete the Waltman 24-24 well, and bring on production along with the Waltman 24-34 by the second quarter of 2009. We also are evaluating the opportunity to begin drilling at least one additional well in the South Waltman field during 2009.
We believe that we have the necessary capital, personnel and available drilling equipment to successfully execute this development program.

                                                As of and for the year ended December 31,                    Percent change between years
                                              2008                   2007                2006            2007 to 2008           2006 to 2007
Total proved reserves
Oil (MBbl)                                          420                    413                360                    2 %                   15 %
Gas (MMcf)                                       86,331                 71,254             48,497                   21 %                   47 %
MMcfe                                            88,852                 73,731             50,657                   21 %                   46 %

Net production volumes
Oil (Bbl)                                        25,668                 13,963             12,729                   84 %                   10 %
Gas (Mcf)                                     6,559,662              2,928,335          3,140,653                  124 %                   -7 %
Mcfe                                          6,713,670              3,012,113          3,217,027                  123 %                   -6 %

Average daily production
Mcfe                                             18,343                  8,252              8,814                  122 %                   -6 %

Average price per unit production
Oil (Bbl)                                $        77.24         $        63.17        $     57.90                   22 %                    9 %
Gas (Mcf)                                $         6.08         $         5.18        $      5.57                   17 %                   -7 %
Mcfe                                     $         6.23         $         5.33        $      5.67                   17 %                   -6 %

Oil and gas production revenues
Oil revenues                             $        1,983         $          882        $       737                  125 %                   20 %
Gas revenues                                     37,166                 15,162             17,491                  145 %                  -13 %

Total                                    $       39,149         $       16,044        $    18,228                  144 %                  -12 %


Oil and gas production costs
Production costs                         $        7,601         $        5,696        $     3,560                   33 %                   60 %
Production taxes                                  4,701                  1,933              2,209                  143 %                  -12 %

Total                                    $       12,302         $        7,629        $     5,769                   61 %                   32 %


Data on a per Mcfe basis
Average price (1)                        $         6.23         $         5.33        $      5.67                   17 %                   -6 %

Production costs                                   1.13                   1.89               1.11                  -40 %                   70 %
Production taxes                                   0.70                   0.64               0.69                    9 %                   -7 %
Depletion and amortization                         1.65                   1.51               1.29                    9 %                   17 %

Total operating costs                              3.48                   4.04               3.09                  -14 %                   31 %

Gross margin                             $         2.75         $         1.29               2.58                  113 %                  -50 %

Gross margin percentage                              44 %                   24 %               46 %                 82 %                  -47 %

(1) Our average gas price per Mcfe realized for the years ended December 31, 2008, 2007 and 2006 is calculated by summing a) production revenue received from third parties for sale of our gas, included in the oil and gas sales line item on the Consolidated Statement of Operations,
b) settlement of our cash flow hedges included within oil and gas sales on the Consolidated Statement of Operations and c) realized gain/loss on our economic hedges, which due to accounting rules is included in our price risk management activities line on the Consolidated Statement of Operations, totaling $2,698, $0 and $0, for the years ended December 31, 2008, 2007 and 2006, respectively. This amount is divided by the total Mcfe volume for the period.

Year ended December 31, 2008 compared to the year ended December 31, 2007 Oil and gas sales volume and price comparisons During the year ended December 31, 2008, total net production increased 123% to 6,714 MMcfe as compared to the

year ended December 31, 2007. The increase in production volumes was due largely to the addition of wells at our operated Catalina Unit and non-operated well additions in the Atlantic Rim and Pinedale Anticline, offset somewhat by the decrease of our working interest at the Catalina Unit due to unitization. Unitization is a type of sharing arrangement by which owners of operating and non-operating working interests pool their property interests in a producing area to form a single operating unit. Units are designed to improve efficiency and economics of developing and producing an area. The share that each interest owner receives is based upon the respective acreage contributed by each owner in the participating area ("PA") as a percentage of the entire acreage of the PA. 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 PA, which included the 14 wells in the original Cow Creek Unit, as well as the 33 wells from the 2007 drilling program, our working interest decreased to 73.84% in the Catalina Unit. In October, 2008, our working interest adjusted again from 73.84% to 68.35% upon reaching certain contractual thresholds in our 2008 drilling program. This PA, and our associated working interest will continue to change as more wells and acreage are added to the PA.
During the year-ended December 31, 2008, average daily net production at the Atlantic Rim increased 161% to 12,221 Mcfe, as compared to 4,678 Mcfe in 2007, largely resulting from the addition of 33 new wells at the Catalina Unit, which were drilled in 2007. These wells were partially brought on-line during the fourth quarter of 2007, with the remaining wells coming on during the first six months of 2008. Additionally, we drilled 24 potential producing wells during 2008, of which five were completed and producing at December 31, 2008. Average daily net production for the year ended December 31, 2008 at the Catalina Unit increased 167% to 10,881 Mcfe, as compared to 4,068 Mcfe during the same prior year period. Average daily net production, net to our interest, at the Doty Mountain and Sun Dog Units increased 120% to 1,340 Mcfe, as compared to 610 Mcfe during the same prior year period. The increase was due primarily to the addition of 64 wells from the Sun Dog Unit's 2007 drilling program. The operator has informed us that it intends to do fracture stimulations and well enhancement projects on the wells in the Sun Dog and Doty Mountain Unit in 2009. Average daily net production in the Pinedale Anticline increased 106% for the year ended December 31, 2008, to 4,467 Mcfe, as compared to 2,166 Mcfe in the prior year. The increase was the result of the addition of 22 new wells in the Mesa "B" Unit during the second and third quarters of 2008. This increase was offset slightly by the natural production decline typical of wells in the Mesa Unit. We are also participating in the drilling of 20 additional wells at the Pinedale Anticline. These wells were spud in the fall of 2008, and are expected to be completed in 2009. The operator has informed us that these wells are expected to be brought on for production 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.
During the year ended December 31, 2008, average daily net production at the Madden Unit decreased to 407 Mcfe as compared to 502 Mcfe in the prior year. The decrease in production was largely due to operational difficulties at the sour gas plant in the first half of 2008.
During the year ended December 31, 2008, oil and gas sales increased 144% to $39,149, as compared to the year ended December 31, 2007. This increase in oil and gas sales was driven by both the volume increase discussed above, as well as an increase in our average gas price realized. During 2008, our average gas price realized increased 17% to $6.23 from $5.33, as compared to an increase of 61% in the average CIG index price. Our price did not increase consistent with the CIG index prices due to the fixed price contracts and economic hedges we had in place throughout 2008.
Transportation and gathering revenue
Transportation and gathering revenue increased 426%, to $4,788 for the year ended December 31, 2008, as compared to $910 during the prior year. The Company receives a fee 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 growth in revenue is due to an increase in the fee charged to third parties and higher production volumes at the Catalina Unit. With additional compression, the pipeline is expected to have approximately 100 MMcf per day capacity, which is expected to be sufficient to handle the development of the Catalina Unit and also additional third party gas from other non-operated properties in the Atlantic Rim proximity.
Price risk management
We recorded a net gain on our derivative contracts of $5,329 for the year ended December 31, 2008. This amount consists of an unrealized gain of $2,631, which represents the change in the fair value on our economic hedges at

December 31, 2008, based on the future expected prices of the related commodities, and a net realized gain of $2,698 related to the settlement of some of our economic hedges. We had no derivative instruments accounted for under mark-to-market accounting at December 31, 2007.
Oil and gas production expenses, depreciation, depletion and amortization During the year ended December 31, 2008, well production costs increased 33% to $7,601, as compared to $5,696 during the prior year, and production costs in dollars per Mcfe decreased 40%, or $0.76, to $1.13, as compared to the same prior year period. The increase in production costs is due primarily to a $1,829 million increase in the lease operating expenses at the Catalina Unit, as 33 new wells were brought on-line during the fourth quarter of 2007 and the first six months of 2008. We also brought five additional wells on-line in December 2008. In addition, transportation costs increased by $585 at the Sun Dog and Doty Mountain Units. Offsetting these increases, was a decrease in well workover costs. The decrease in production costs on a per Mcfe basis, is largely attributed to operating efficiencies gained from the increased production at the Company-operated Catalina Unit and lower well workover costs, partially offset by increased transportation costs at our non-operated Sun Dog and Doty Mountain units.
During the year ended December 31, 2008, total depreciation, depletion and amortization expenses ("DD&A") increased 126% to $11,473, as compared to $5,068 in the prior year, and depletion and amortization related to producing assets increased 143% to $11,078, as compared to $4,550 in the prior year. The increase is due primarily to increased capital expenditures at the Catalina, Sun Dog, and Mesa units, increased production levels, and a decrease in the reserve estimates at the Doty Mountain Unit used in the calculation of DD&A. This increase was partially offset by an increase in the reserve estimates used in the calculation of DD&A at the Catalina and Mesa units, which caused a decrease in the expense recognized during the period. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 9%, or $0.14, to $1.65, as compared to the prior year.
Pipeline operating costs
Pipeline operating costs totaled $2,596 for the year ended December 31, 2008, which represented an increase over the prior year of 302%. The increase is due to the expansion of the Catalina Unit and related transportation assets, and compressor rental costs.
Dry hole and impairment
Dry hole and impairment expense decreased to $1,654 for the year ended December 31, 2008, as compared to $17,631 for the year ended December 31, 2007. The 2008 expense primarily relates to a $741 write-off of our Nevada leases, as the Company has determined that we will not develop these properties in the future, and we do not plan to renew the leases upon their expiration. We also made rental payments of $340 on other undeveloped leaseholds. In 2007, the Company wrote off the following exploratory costs that did not meet the requirements for continued capitalization; Cow Creek Unit Deep #2 ($4,395), the PH State 16-1 ($2,759), the Christmas Meadows Table Top Unit #1 ($5,773) and the Straight Flush 17-1 ($1,983).
General and administrative
General and administrative expenses increased 36% to $5,604 as compared to $4,133 in the prior year. The increase was due largely to higher non-cash stock-based compensation expense of $688 due to additional grants to employees, higher Board of Director related costs of $241, additional costs related to the implementation of our new accounting software of $174, additional salary and salary-related expenses due primarily to headcount additions of $289, and $61 related to the two reserve studies performed in 2008. These increases were offset partially by a $174 decrease in audit and tax related fees. Income taxes
During the year ended December 31, 2008, we recorded an income tax expense of $5,343, as compared to an income tax benefit of $6,143 during the prior year. Our income tax expense reflects an effective book rate of 34.0% in 2008. The lower than expected effective book rate reflects the tax effect of the permanent difference caused by the stock option expense in 2008. We expect to continue to generate losses for federal income tax reporting purposes, and anticipate net income from operations in future years, which has resulted in a deferred tax position reported under U.S. generally accepted accounting principles. We do not anticipate any required payments for current tax liabilities in the near future. We have a net operating loss carry-forward ("NOL's") of $30.3 million at December 31, 2008. The Company has

evaluated the need to provide a valuation allowance on the amount recorded as the net operating loss carry-forward, and management has concluded that no valuation allowance is required as of December 31, 2008. In reaching this conclusion, management considered that the Company generated positive net income in 2008, and by continuing to develop our core assets in the Catalina Unit, we expect to generate income in excess of our current NOL's. Our current NOL's do not begin to expire for 11 years. In addition, the Company routinely considers the sale of non-core assets, which is likely to generate a tax gain, as the tax cost per Mcfe of our assets is generally lower than the current market rates being paid in the open market for gas producing properties.
Year ended December 31, 2007 compared to the year ended December 31, 2006 Oil and gas sales volume and price comparisons During the year ended December 31, 2007, average daily net production at the Atlantic Rim decreased 12% to 4,678 Mcfe as compared to 5,289 Mcfe during the same prior year period due to decreases in all three Atlantic Rim Units. During the year ended December 31, 2007, average daily net production at the Catalina Unit decreased 8% to 4,068 Mcfe, as compared to 4,431 Mcfe during the same prior year period. The decrease in production at the Catalina Unit was due to operational issues caused by severe winter weather, which resulted in unscheduled workovers during the first half of 2007 and to electrical and compression problems experienced during the fourth quarter of 2007. We drilled 33 potential producing wells in the Catalina Unit in 2007 with six completed and . . .