The discussion and analysis that follows should be read together with the accompanying financial statements and notes related thereto that are included elsewhere in this quarterly report on Form 10-Q. It includes forward-looking statements that may reflect our estimates, beliefs, plans and expected performance. The forward-looking statements are based upon events, risks and uncertainties that may be outside our control. Our actual results could differ significantly from those discussed in these forward-looking statements. Factors that could cause or contribute to these differences include, but are not limited to, market prices for natural gas and oil, regulatory changes, estimates of proved reserves, economic conditions, competitive conditions, development success rates, capital expenditures and other uncertainties, as well as those factors discussed below and elsewhere in this quarterly report on Form 10-Q and in our annual report on Form 10-K for the year ended December 31, 2008, including in "Risk Factors" and "Cautionary Statement Concerning Forward-Looking Statements," all of which are difficult to predict. As a result of these assumptions, risks and uncertainties, the forward-looking matters discussed may not occur.

Overview

We are an independent energy company engaged in the acquisition, exploration and development of domestic onshore natural gas reserves. We primarily focus our efforts on the development of coalbed methane ("CBM") properties located in the Powder River Basin in northeastern Wyoming and southern Montana. In addition, in April 2006, we acquired properties located in the Green River Basin in southern Wyoming. As of March 31, 2009, we owned natural gas and oil leasehold interests in approximately 480,000 gross (334,000 net) acres, approximately 90% of which were undeveloped. As of December 31, 2008, we had estimated net proved reserves of approximately 27.7 Bcf based on the CIG index price of $4.61 per Mcf. For the first quarter of 2009 and the remainder of 2009, we have operated and expect to continue to operate with a reduced capital expenditure plan. Under our reduced capital expenditure plan, we will generally make only such expenditures as are necessary to secure drilling permits in strategic areas, drill wells that secure leasehold positions and construct the necessary infrastructure to complete and hook-up wells that have already been drilled. We had total capital expenditures of $0.6 million for the quarter ended March 31, 2009. Our capital expenditure budget for 2009 will be dependent upon CIG index prices, our cash flows and the availability of additional capital resources.

We were formed as a Delaware corporation in June 2003 through a contribution of proved producing properties and undeveloped leaseholds by subsidiaries of Carrizo Oil & Gas, Inc. and U.S. Energy Corporation and a cash contribution from funds affiliated with DLJ Merchant Banking.

In April 2006, we completed a private placement, exempt from registration under the Securities Act of 1933, of 12,835,230 shares of our common stock to qualified institutional buyers, non-U.S. persons and accredited investors. In May 2007, we completed our initial public offering of 3,750,000 shares of common stock.

Effective February 12, 2007, we entered into a credit facility which permits borrowings up to the borrowing base as designated by the administrative agent. As of March 31, 2009 and December 31, 2008, we had $10.5 million and $11.5 million, respectively, of debt outstanding under the facility.

Economic and Natural Gas Pricing Environment

During 2008, the global economy experienced a significant downturn. The downturn, which began over concerns related to the U.S. financial markets, spread to other industries, including the energy industry. The initial effects of the downturn restricted the capital and credit markets to a degree that has not been seen in a number of decades in the United States. We have been able to partially mitigate the constraints imposed by the current economic climate through utilization of our credit facility and cash flows from operations.

The fear of global recession led to an immediate drop in demand for natural gas, primarily by industrial users, which in turn led to a significant reduction in natural gas prices. The natural gas index price in the Rocky Mountain region averaged $7.84 per Mcf for the first eight months of 2008 but only $3.15 per Mcf for the last four months of 2008. For the first quarter of 2009, the price averaged $3.28 per Mcf. This decrease in price has caused us to reevaluate our 2009 business plan. We have curtailed drilling, except for wells that will hold significant blocks of acreage, and have also reduced administrative, operating and transportation costs. Even with cost reductions and a flexible capital spending budget, the current natural gas pricing and economic environment remains challenging. We are exploring strategic alternatives to increase our capital resources.

Credit Facility and Liquidity

On April 14, 2009, we and the lenders entered into the fourth amendment to the credit facility which waived compliance with the current ratio financial covenant as of December 31, 2008 and March 31, 2009 and with the restrictive covenants related to accounts payable, permitted liens and permitted debt until the next borrowing base redetermination expected in the fall of 2009, subject to certain financial caps. In connection with the waiver of the restrictive covenants, the lenders reduced our borrowing base to $9.0 million as of April 14, 2009, with further monthly reductions until the borrowing base reaches $6.5 million on October 1, 2009. We believe that we may not be in compliance with the current ratio financial covenant and certain other covenants throughout 2009, but management anticipates receiving waivers in the future based on prior dealings with the lender and continued compliance with the borrowing base limitations. There can be no assurance that we will be able to obtain such waivers or that such waivers will be obtained on acceptable terms. If we are unable to obtain future waivers and/or to comply with the covenants, the lenders could accelerate our indebtedness under the credit facility or foreclose on properties held by liens. We have remained in compliance with the payment of principal and interest pertaining to the credit facility including ensuring that our outstanding borrowings remain within the limitations of the borrowing base. Due to borrowing base limitations and waiver stipulations, we are currently unable to incur additional indebtedness under the credit facility and may be further limited in the future. Please see "-Liquidity and Capital Resources-Credit Facility" for further information regarding our credit facility, borrowing base and the covenant limitations.

In accordance with accounting guidance, we have classified all of the outstanding debt under the credit facility totaling $10.5 million as of March 31, 2009 as a current payable because it is unlikely that we will have cured the noncompliance of certain restrictive covenants during 2009. We have further reduced our outstanding indebtedness under the credit facility to $9.0 million as of April 14, 2009 in order to be in compliance with the borrowing base limitation.

Due to the current economic and pricing environment and our liquidity position, we are actively marketing certain assets to raise additional capital and are also reviewing alternatives for raising additional capital through equity and debt financing, capital restructuring and possible mergers. We sold our high pressure gas gathering system in the Cabin Creek project area in Wyoming and our remaining interest in the Arvada project area in Wyoming in April 2009. We received approximately $3.2 million in net proceeds from these sales, and used part of such proceeds to repay a portion of the indebtedness outstanding under our credit facility and for general operating purposes. We also put additional hedges of our natural gas production in place to secure certain operating cash flow levels during the remainder of 2009. From January through April 2009, we had 4,500 MMbtu per day hedged through a combination of a fixed price swap and a costless collar at a weighted average floor price of $6.87 per MMbtu and a ceiling price of $7.32 per MMbtu. From May through December 2009, we have 7,000 MMbtu per day hedged through a combination of a fixed price swap and a costless collar at a weighted average floor price of $5.65 per MMbtu and a ceiling price of $5.93 per MMbtu.

We have also implemented various cost cutting measures, including reducing general and administrative costs through staff reductions, wage and benefit cuts and a hiring freeze. We have reduced lease operating expenses by renegotiating water disposal contracts, reducing service costs and temporarily shutting-in marginal wells. We continue to communicate with key vendors to manage our obligations and payables. Management believes that appropriate steps, including cost-cutting measures, are being taken to make operations sustainable in the future. Although we are pursuing various alternatives to provide additional liquidity, there is no assurance of the likelihood or timing of any of these transactions.

Critical Accounting Policies

The most subjective and complex judgments used in the preparation of our financial statements are:

† Reserve evaluation and determination;

† Estimates of the timing and cost of our future drilling activity;

† Estimates of the fair valuation of hedges in place;

† Estimates of timing and cost of asset retirement obligations;

† Estimates of the expense and timing of exercise of stock options;

† Accruals of operating costs, capital expenditures and revenue; and

† Estimates for litigation

Oil and Gas Properties

We use the full cost method of accounting for oil and gas producing activities. Under this method, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration, costs of surrendered and abandoned leaseholds, delay lease rentals and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities, are capitalized within a cost center. Our oil and gas properties are all located within the United States, which constitutes a single cost center. We capitalize certain lease operating expenses associated with exploration and development of unevaluated oil and gas properties. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of gas properties and the gain significantly alters the relationship between capitalized costs and proved gas reserves of the cost center. Expenditures for maintenance and repairs are charged to lease operating expense in the period incurred.

Depreciation, depletion and amortization of oil and gas properties is computed on the unit-of-production method based on proved reserves. Amortizable costs include estimates of future development costs of proved undeveloped reserves and asset retirement obligations. We invest in unevaluated oil and gas properties for the purpose of exploration for proved reserves. The costs of such assets, including exploration costs on properties where a determination of whether proved oil and gas reserves will be established is still under evaluation, and any capitalized interest and lease operating expenses, are included in unproved oil and gas properties at the lower of cost or estimated fair market value and are not subject to amortization. On a quarterly basis, such costs are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. We recorded an impairment of unevaluated properties of $0 million and $5.6 million during the three months ended March 31, 2009 and year ended December 31, 2008, respectively. Abandonment of unproved properties is also accounted for as an adjustment to capitalized costs related to proved oil and gas properties. If the adjustment to capitalized costs related to proved oil and gas properties results in the capitalized costs exceeding the full cost ceiling limitations, the excess must be charged to expense.

Substantially all remaining unproved property costs are expected to be developed and included in the amortization base ratably over the next three to five years, based on projected cash flow from operations combined with the raising of additional capital. Salvage value is taken into account in determining depletion rates and is based on our estimate of the value of equipment and supplies at the time the well is abandoned. As of March 31, 2009 and March 31, 2008, the estimated salvage value of equipment was $7.2 million and $6.7 million, respectively.

Under the full cost method of accounting rules, capitalized costs less accumulated depletion and related deferred income taxes may not exceed a "ceiling" value which is the sum of (1) the present value discounted at 10% of estimated future net revenue using current costs and prices, including the effects of derivative instruments designated as cash flow hedges but excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, less any related income tax effects; plus (2) the cost of properties not being amortized, if any; plus
(3) the lower of costs or estimated fair value of unproved properties; less
(4) the income tax effects related to differences in the book to tax basis of oil and gas properties. This is referred to as the "full cost ceiling limitation." If capitalized costs exceed the limit, the excess must be charged to expense. The expense may not be reversed in future periods. At the end of each quarter, we calculate the full cost ceiling limitation. At March 31, 2009, the capitalized cost of our oil and gas properties exceeded the full cost ceiling limitation by approximately $23.6 million based upon a natural gas price of approximately $2.52 per Mcf in effect at that date. Based on the subsequent price increase to $3.31 on May 12, 2009, the capitalized cost exceeded the full cost ceiling limitation by $16.8 million. Therefore, an impairment of approximately $16.8 million was taken for the quarter ended March 31, 2009. This impairment of our oil and gas properties resulted from low commodity prices in the first quarter of 2009. No impairment was taken for the quarter ended March 31, 2008 based on a natural gas price of $8.01 per Mcf. A decline in gas prices or an increase in operating costs or reductions in economically recoverable quantities could result in the recognition of additional impairments of our oil and gas properties in future periods.

Gas Sales

We use the sales method for recording natural gas sales. Sales of gas applicable to our interest in producing natural gas and oil leases are recorded as revenues when the gas is metered and title transferred pursuant to the gas sales contracts covering our interest in gas reserves. During such times as our sales of gas exceed our pro rata ownership in a well, such sales are recorded as revenues unless total sales from the well have exceeded our share of estimated total gas reserves underlying the property at which time such excess is recorded as a gas imbalance liability. At March 31, 2009 and December 31, 2008, there was no such liability recorded. Although there was no such liability recorded for prior periods, gas reserves are an estimate and are updated on an annual and interim basis. Gas pricing, expenses and production may impact future gas reserves remaining which, in turn, could impact the recording of liabilities in the future. Gas sales accruals at March 31, 2009, and December 31,

2008 were based on the actual volume statements from our purchasers and distribution process. If accruals were to change by 10% at March 31, 2009 and at December 31, 2008, the impact would have been a change of $80,000 and $209,000, respectively.

Asset Retirement Obligations

We follow the provisions of Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 requires us to recognize an estimated liability for costs associated with the abandonment of our oil and gas properties.

A liability for the fair value of an asset retirement obligation with a corresponding increase to the carrying value of the related long-lived asset is recorded at the time a well is completed or acquired. The increased carrying value is depleted using the units-of-production method, and the discounted liability is increased through accretion over the remaining life of the respective oil and gas properties.

The estimated liability is based on historical gas industry experience in abandoning wells, including estimated economic lives, external estimates as to the cost to abandon the wells in the future and federal and state regulatory requirements. Our liability is discounted using our best estimate of our credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in estimated abandonment costs, changes in well economic lives or if federal or state regulators enact new requirements regarding the abandonment of wells. For example, a 10% change in our estimated retirement costs would have had a $342,000 effect on our asset retirement obligation liability at March 31, 2009.

The following is a summary of our asset retirement obligation activity for the three months ended March 31, 2009 and 2008 (in thousands):

                                                     Three           Three
                                                 Months Ended    Months Ended
                                                   March 31,       March 31,
                                                     2009            2008
                                                  (unaudited)     (unaudited)
Beginning balance asset retirement obligations   $       3,366   $       2,767
Additional obligation added during the period                -             101
Accretion expense                                           56              58
Ending balance of asset retirement obligations   $       3,422   $       2,926

Inventory

We acquired inventory of oil and gas equipment, primarily tubulars, in 2007 and 2008, to take advantage of quantity pricing and to secure a readily available supply. Inventory is valued at the lower of average cost or market. Inventory is used in the development of gas properties and to the extent it is estimated that it will be billed to other working interest owners during the next year, it is included in current assets. Otherwise, it is recorded in non-current assets. The price of steel is a primary factor in valuing our inventory. Under the valuation method of lower of average cost or market, a 10% reduction in the price of steel would have caused a $47,000 reduction in our inventory valuation as of March 31, 2009. The market price of steel is evaluated each quarter using prices quoted by authorized vendors in the area.

Property and Equipment

Property and equipment is comprised primarily of a building, computer hardware and software, vehicles and equipment, and is recorded at cost. Renewals and betterments that substantially extend the useful lives of the assets are capitalized. Maintenance and repairs are expensed when incurred. Depreciation and amortization are provided using the straight-line method over the estimated useful lives of the assets, ranging as follows: buildings-30 years, computer hardware and software-3 to 5 years, machinery, equipment and vehicles-5 years, and office furniture and equipment-3 to 5 years.

Long-Lived Assets

Long-lived assets to be held and used in our business are reviewed for impairment whenever events or changes in circumstances indicate that the related carrying amount may not be recoverable. When the carrying amounts of long-lived assets exceed the fair value, which is generally based on discounted expected future cash flows, we recorded an impairment. No impairments were recorded during the three months ended March 31, 2009 and the year ended December 31, 2008 .

General and Administrative Expenses

General and administrative expenses are reported net of amounts allocated and billed to working interest owners of gas properties operated by us. The administrative expenses billed to working interest owners may change in accordance with the terms of the joint operating agreements. Administrative expenses are charged to working interest owners based on productive well counts. A 10% change in well counts for the three months ended March 31, 2009 would have increased or decreased our expenses billed to working interest owners by approximately $33,000. As we operate and drill additional wells in the future, additional administrative expenses will be charged to the working interest owners when the wells become productive.

Income Taxes

We use the asset and liability method of accounting for income taxes, in accordance with SFAS No. 109, "Accounting for Income Taxes." Deferred tax assets and liabilities are recognized for the expected future tax consequences of temporary differences between the financial statement and tax bases of assets and liabilities. If appropriate, deferred tax assets are reduced by a valuation allowance which reflects expectations of the extent to which such assets will be realized. As of March 31, 2009 and December 31, 2008, we recorded a full valuation allowance for our net deferred tax asset.

On January 1, 2007, we adopted the provisions of FIN 48, "Accounting for Uncertainty in Income Taxes." FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 requires that we recognize in our consolidated financial statements only those tax positions that are "more-likely-than-not" of being sustained as of the adoption date, based on the technical merits of the position. As a result of the implementation of FIN 48, we performed a comprehensive review of our material tax positions in accordance with recognition and measurement standards established by FIN 48.

As a result of this review, we did not identify any material deferred tax assets that required adjustment. As of March 31, 2009, we had not recorded any material uncertain tax positions.

Our policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of March 31, 2009, we had not recognized any interest or penalties in our statement of operations or statement of financial position.

We are subject to the following material taxing jurisdictions: U.S. federal. We also have material operations in the state of Wyoming; however, Wyoming does not impose a corporate income tax. The tax years that remain open to examination by the U.S. Internal Revenue Service are years 2005 through 2008. Due to our net operating loss carry forwards, the Internal Revenue Service may also adjust the amount of loss realizable under examination back to 2003.

Derivatives

We use derivative instruments to manage our exposure to fluctuating natural gas prices through the use of natural gas swap and option contracts. We account for derivative instruments or hedging activities under the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 requires us to record derivative instruments at their fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income (loss) and are recognized in the statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges, if any, are recognized in earnings. Changes in the fair value of derivatives that do not qualify for hedge treatment are recognized in earnings. Please see Note 5 included in the accompanying unaudited Notes to Financial Statements for additional discussions of derivatives.

We periodically hedge a portion of our oil and gas production through swap and collar agreements. The purpose of the hedges is to provide a measure of stability to our cash flows in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk. Our management decided not to use hedge accounting for these agreements. Therefore, in accordance with the provisions of SFAS No. 133, the changes in fair market value are recognized in earnings.

Stock-Based Compensation

Effective January 1, 2006, we adopted SFAS No. 123(R), "Share-Based Payments," which requires companies to recognize compensation expense for share-based payments based on the estimated fair value of the awards. We recognized an expense of approximately $121,000 for the three months ended March 31, 2009, based on the fair value of vested options. We recognized an expense of approximately $78,000 for the three months ended March 31, 2009, based on the fair value of restricted stock that vested during the quarter. SFAS No. 123(R) also requires that the benefits of tax deductions in excess of compensation cost recognized for stock awards and options ("excess tax benefits") be presented as financing cash inflows in the Statement of Cash Flows.

Accounts Receivable

Our revenue producing activities are conducted primarily in Wyoming. We grant credit to qualified customers, which potentially subjects us to credit risk resulting from, among other factors, adverse changes in the industry in which we operate and the financial condition of our customers. We continuously monitor collections and payments from our customers and, if necessary, record an allowance for doubtful accounts based upon historical experience and any specific customer collection issues identified. We recorded an allowance of $100,000 at each of March 31, 2009 and December 31, 2008.

Transportation Costs

We account for transportation costs under Emerging Issues Task Force Issues 00-10, "Accounting for Shipping and Handling Fees and Costs," whereby amounts paid for transportation are classified as operating expenses.

Legal Estimates

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. We account for these costs under SFAS No. 5, "Accounting for Contingencies," which states that a loss contingency be recorded if it is probable that a liability has been incurred and it is reasonably estimatable. At March 31, 2009 and December 31, 2008, we recorded no liability for legal proceedings.

Per Share Information

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