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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2010

or

o  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission file number: 001-33457

Pinnacle Gas Resources, Inc.

(Exact name of registrant as specified in its charter)

(307) 673-9710

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

30,303,427 shares of the registrant’s Common Stock were outstanding as of August 16, 2010.

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PINNACLE GAS RESOURCES, INC.

Index to Form 10-Q

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

We are including the following discussion to inform you of some of the risks and uncertainties that can affect our company and to take advantage of the “safe harbor” protection for forward-looking statements that applicable federal securities law affords. Various statements in this prospectus, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward looking statements. These include statements relating to such matters as:

· our financial position or operating results;

· projections and estimates concerning the timing and success of specific projects;

· our business strategy;

· our budget;

· the amount, nature and timing of capital expenditures;

· the drilling of wells;

· the development of natural gas and oil properties and commercial potential of these properties;

· the timing and amount of future production of natural gas and oil;

· our operating costs and other expenses;

· our estimated future net revenues from natural gas and oil reserves and the present value thereof;

· our cash flow and anticipated liquidity; and

· our other plans and objectives for future operations

When we use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” their negatives, or other similar expressions, the statements which include those words are usually forward looking statements. When we describe strategy that involves risks or uncertainties, we are making forward looking statements. The forward looking statements in this quarterly report on Form 10-Q speak only as of the date of this report. We disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

· the availability of capital;

· fluctuations in the commodity prices for natural gas and crude oil and their related effects, including on cash flows and potential impairments of oil and gas properties;

· regional price differentials;

· the extent of our success in discovering, developing and producing reserves, including the risks inherent in exploration and development drilling, well completion and other development activities;

· the lack of liquidity of our equity securities;

· the substantial capital expenditures required for construction of pipelines and the drilling of wells and the related need to fund such capital requirements through commercial banks and/or public securities markets;

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· engineering, mechanical or technological difficulties with operational equipment, in well completions and workovers, and in drilling new wells;

· the effects of government regulation and permitting and other legal requirements;

· the uncertainty inherent in estimating future natural gas and oil production or reserves;

· production variances from expectations;

· our ability to develop and replace reserves;

· operating hazards attendant to the natural gas and oil business, including down-hole drilling and completion risks that are generally not recoverable from third parties or insurance;

· potential mechanical failure or under-performance of significant wells;

· environmental-related problems;

· the availability and cost of materials and equipment;

· our dependence upon key personnel;

· our ability to find and retain skilled personnel;

· delays in anticipated start-up dates;

· disruptions of, capacity constraints in or other limitations on our or others’ pipeline systems;

· land issues and the costs associated with perfecting title for natural gas rights in some of our properties;

· our ability to effectively market our production;

· competition from, and the strength and financial resources of, our competitors; and

· general economic conditions.

When you consider these forward-looking statements, you should keep in mind these factors and the other factors discussed in the “Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2009 and this quarterly report on
Form 10-Q.

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Part I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PINNACLE GAS RESOURCES, INC.

Balance Sheets

See Notes to Financial Statements (unaudited)

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PINNACLE GAS RESOURCES, INC.

Statements of Operations

(unaudited)

See Notes to Financial Statements (unaudited)

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PINNACLE GAS RESOURCES, INC.

Statements of Cash Flows

(in thousands)

(unaudited)

See Notes to Financial Statements (unaudited)

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PINNACLE GAS RESOURCES, INC.

Statement of Stockholders’ Equity

(in thousands, except for share data)

See Notes to Financial Statements (unaudited)

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Notes to Financial Statements

(Unaudited)

Note 1 — Organization and Nature of Operations

Pinnacle Gas Resources, Inc. (the “Company”) was formed as a Delaware corporation in June 2003 through a contribution of cash by funds affiliated with DLJ Merchant Banking and oil and gas reserves and leasehold interests by subsidiaries of Carrizo Oil & Gas, Inc. and U.S. Energy Corporation.

The Company’s primary business is the exploration for, and the acquisition, development and production of, coalbed methane natural gas in the United States. The Company is also engaged in gas property operations and the construction of low pressure gas collection systems which provide transportation for the Company’s coalbed methane production.

On February 23, 2010, the Company entered into an Agreement and Plan of Merger with Powder Holdings, LLC, a Delaware limited liability company and Powder Acquisition Co., a direct, wholly owned subsidiary of Powder Holdings (“Merger Agreement”).  Powder Holdings is controlled by an investor group led by Scotia Waterous (USA) Inc. and includes certain members of the Company’s management team. On April 2, 2010, the Company filed a preliminary proxy statement relating to the merger and on June 29, 2010, the Company filed a definitive proxy statement relating to the merger, with the U.S. Securities and Exchange Commission.  At the special meeting of the shareholders on August 9, 2010, the shareholders of the Company voted to approve a proposal to adopt the Merger Agreement. The Company anticipates that the closing will occur during the third quarter, subject to the satisfaction of customary closing conditions and the receipt of waivers from the Company’s lender, The Royal Bank of Scotland plc.

Although the Company anticipates closing will occur in the third quarter, the Company continues to communicate with key vendors to manage its obligations and payables. The Company has entered into agreements with various vendors to make minimum monthly payments ranging from $1,000 to $45,000 at interest rates between 2% and 12% for the remainder of 2010. The Company has also implemented various cost cutting measures, including reducing general and administrative costs through staff reductions, wage and benefit cuts and a hiring freeze. The Company has reduced lease operating expenses by renegotiating water disposal contracts, reducing service costs and temporarily shutting-in marginal wells.  Management believes that appropriate steps, including cost-cutting measures, are being taken to make operations sustainable in the future. Although the Company is pursuing various alternatives to provide additional liquidity, including its shareholder approved merger with Powder, there is no assurance of the likelihood or timing of any of these transactions.

In addition the Company has executed hedges of its gas to secure certain operating cash flow levels during the remainder of 2010. From January through April 2010, the Company had 5,500 MMbtu per day hedged through fixed price swaps at a weighted average CIG Rocky Mountain Index price of $4.19 per MMbtu.  From May through December 2010, the Company has 5,500 MMbtu per day hedged through fixed price swaps at a weighted average CIG Rocky Mountain Index price of $5.08 per MMbtu.

Note 2 — Basis of Presentation

The accompanying unaudited financial statements include the Company’s proportionate share of assets, liabilities, income and expenses from the properties in which the Company has a participating interest.  The Company has no subsidiaries or affiliates with which intercompany transactions are recorded.

The accompanying financial statements are unaudited, and in the opinion of management, reflect all adjustments that are necessary for a fair presentation of the financial position and results of operations for the periods presented.  All such adjustments are of a normal and recurring nature. The following Notes describe only the material changes in accounting policies, account details, or financial statement Notes during the first six months of 2010.  The results for the three and six months ending June 30, 2010 are not necessarily indicative of the results expected for the entire year.  These financial statements should be read in conjunction with the audited financial statements and the summary of significant accounting policies for prior years contained in the reports the Company files with the Securities and Exchange Commission, which can be found on the Company’s website at www.pinnaclegas.com or on the Securities and Exchange Commission website at www.sec.gov.

Use of Estimates

The preparation of the Company’s financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. Significant estimates with regard to the Company’s financial statements include the estimated carrying value of unproved properties, the estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows, the ceiling test applied to capitalized oil and gas

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properties, the estimate of the timing and cost of the Company’s future drilling activity, the estimated cost and timing related to asset retirement obligations, the estimated fair value of derivative assets and liabilities, the realizability of deferred tax assets, the estimates of expenses and timing of exercise of stock options, accrual of operating costs and capital expenditures and revenue.

Oil and Gas Properties

The Company utilizes 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. The Company’s oil and gas properties are all located within the United States, which constitutes a single cost center. The Company capitalizes 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 (“DD&A”) 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. The Company invests 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. Abandonment of unproved properties is accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized. No impairment was recorded for unevaluated properties for the three and six months ended June 30, 2010.

Substantially all of the remaining unproved properties are expected to be developed and included in the amortization base over the next three to five years, based on projected cash flow from operations combined with raising additional capital. Salvage value is taken into account in determining depletion rates and is based on the Company’s estimate of the value of equipment and supplies at the time the well is abandoned. As of June 30, 2010 and December 31, 2009, the estimated value was approximately $6.8 million.

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 first day of the month twelve month average CIG 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, the Company calculates the full cost ceiling limitation. At June 30, 2010, the full cost ceiling limitation exceeded the capitalized cost of the Company’s oil and gas properties by approximately $5.2 million based on the first day of the month, twelve month average CIG price of approximately $3.76 per Mcf. Therefore, no impairment was taken for the quarter ended June 30, 2010. An impairment of $6.4 million was taken for the quarter ended June 30, 2009 based on a natural gas price of $3.09 per Mcf.

Per Share Information

Basic loss per share is computed by dividing net loss from continuing operations attributable to common stock by the weighted average number of shares of common stock outstanding during each period. Diluted earnings per share are computed by adjusting the average number of shares of common stock outstanding for the dilutive effect, if any, of common stock equivalents such as stock options and warrants. For the six months ended June 30, 2010, basic and diluted net loss per share was $0.02.  During the six months ended June 30, 2010, 835,446 options and stock appreciation rights were excluded because they were anti-dilutive.

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Income Taxes

The Company uses the asset and liability method of 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 June 30, 2010 and December 31, 2009, the Company had recorded a full valuation allowance for its net deferred tax asset.

New Accounting Pronouncements

The Company adopted FASB ASC Update 2010-06, “Fair Value Measurements and Disclosures” which amends ASC Update 2010-06 to require additional disclosures concerning transfers between Levels 1 and 2, inputs and valuation techniques used to value Level 2 and 3 measurements, and push down of previously prescribed fair value disclosures to each class of asset and liability for Levels 1, 2, and 3.  These disclosures were effective for the Company for the quarter ended June 30, 2010.  The adoption of this pronouncement did not have a material impact on the Company’s consolidated financial statements.

In addition, ASC Update 2010-06 requires that purchases, sales, issuances, and settlements for Level 3 measurements be disclosed.  This portion of the new authoritative guidance is effective for interim and annual reporting periods beginning after December 15, 2010.  As such, the Company will apply this new authoritative guidance in the Company’s March 31, 2011, Quarterly Report on Form 10-Q.  The adoption of ASC Update 2010-06 will not have a material impact on the Company’s financial statements.

The Company adopted FASB ASC Update 2010-09, “Amendments to Certain Recognition and Disclosure Requirements,” which eliminates the requirement for SEC filers to disclose the date through which an entity has evaluated subsequent events.  ASU No. 2010-09 was effective upon issuance and its adoption had no impact on the Company’s financial position, results of operations or cash flows.

Note 3 — Asset Retirement Obligations

The Company follows certain accounting provisions that apply 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. These provisions require the Company to recognize an estimated liability for costs associated with the abandonment of its 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. The Company’s liability is discounted using its best estimate of its 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.

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The following is a summary of the Company’s asset retirement obligation activity for the three and six months ended June 30, 2010 and June 30, 2009 (unaudited).

Note 4 — Restricted Assets (Certificates of Deposit), Surety Bonds and Deposits

Certificates of deposit.

The Company holds a certificate of deposit (“CD”), which expires in July 2011, totalling approximately $160,000. The CD is collateral for bonding required by the State of Wyoming, the State of Montana and the Federal Bureau of Land Management. Because the Company intends to renew the CD in order to maintain its bonding requirements, the Company has included the CD in other non-current assets as of June 30, 2010. The issuer of the bond has commenced litigation against the Company to increase its collateral position, although this litigation was tolled through June 15, 2010 (see Note 9).

On January 1, 2010 the Company held two CDs for $604,000 and $964,000. These CDs collateralized letters of credit in favor of Powder River Energy Corporation (“PRECorp”) in order to secure power lines in the Recluse, Kirby, Deer Creek and Cabin Creek areas. These CDs were to be renewed annually as the amount of the CDs would decrease over time as the Company paid down the capital cost recovery amounts on its monthly billing. On February 14, 2010, the $604,000 CD was lowered to $513,000 and renewed on February 19, 2010. The $964,000 CD was set to expire on May 27, 2010. However, the Company was presented with an opportunity to pay the capital cost recovery work orders in full which would result in a savings of approximately $282,000 in interest costs.  On May 18, 2010, the Company cashed the $513,000 CD and received approximately $506,000 in proceeds and on May 21, 2010, the Company cashed the second CD and received approximately $966,000 in proceeds. On May 20, 2010 the Company wired $500,000 to PRECorp and on May 28, 2010 the Company wired approximately $690,000 to PRECorp which fulfilled its obligation to PRECorp. In March 2010 the Company posted a cash security deposit to Powder River Energy Corp. of approximately $225,000 to collateralize electrical usage in its Recluse, Kirby, Deer Creek and Cabin Creek areas. In April 2007, the Company issued a $1,000,000 letter of credit (“LOC”), which was collateralized by a CD in favor of Bitter Creek Pipelines, LLC to secure the construction of a high pressure pipeline and related compression facilities to the Company’s Deer Creek and Kirby areas. Bitter Creek Pipelines, LLC drew approximately $858,000 on this LOC for compression services provided to the Company in 2009. In January of 2010, Bitter Creek Pipelines, LLC drew the remaining balance of the CD collateralizing this LOC.

Surety Bonds.

From June 2009 through June 30, 2010, the Company posted idle well surety for approximately $64,000 to the Wyoming Oil and Gas Conservation Commission. The Commission has requested the Company make 18 monthly installments of $12,777 for surety on wells that will need to be plugged by the Company. The surety amount may be adjusted downward by the Commission if the Company successfully plugs the proposed wells in question. In addition, the Company has included a $50,000 payment for bonding requirements in the Company’s Kirby Montana area.

Deposits.

The Company has included approximately $57,000 related to royalty payments in deposits. These amounts are included in Deposits in the accompanying balance sheet at June 30, 2010.

Note 5 — Derivatives

The Company has elected not to designate its derivatives as cash flow hedges under authoritative guidance prescribed by the FASB. These derivative instruments are marked to market at the end of each reporting period and changes in the fair value are recorded in the accompanying statements of operations. The aggregate fair values of these contracts were estimated to be an asset

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totaling $903,000 and an asset of $2,213,000 at June 30, 2010 and 2009, respectively. The Company realized a hedging gain of $590,000 and a hedging gain of $2,053,000 for the quarters ended June 30, 2010 and 2009, respectively. As a result of the change in the fair value of the commodity derivatives, the Company had an unrealized loss of $610,000 for the quarter ended June 30, 2010 and unrealized loss of $2,704,000 for the quarter ended June 30, 2009. For the six months ended June 30, 2010, the Company realized a hedging gain of $124,000 compared to a hedging gain of $3,510,000 for the six months ended June 30, 2009. For the six months ended June 30, 2010, the Company had an unrealized gain of $2,278,000 compared to an unrealized loss of $2,133,000 for the six months ended June 30, 2009. The aggregate of these contracts resulted in a gain on derivatives of $2,403,000 and $1,377,000 for the six months ended June 30, 2010 and 2009, respectively. Unrealized gains and losses are included in gains or losses on derivatives in the statement of operations. Realized gains and losses are included in revenues in the statements of operations.  As of June 30, 2010 and 2009, the Company had natural gas hedges in place as follows:

As of June 30, 2010 and 2009, the Company had natural gas hedges in place as follows:

The Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance.

Note 6 — Stock Based Compensation

Options under Stock Incentive Plan

The Company has adopted a stock incentive plan authorizing the grant of both incentive and non-statutory stock options. All options allow for the purchase of common stock at prices not less than the fair market value of such stock at the date of grant. If the option holder owns more than 10% of the total combined voting power of all classes of the Company’s stock, the exercise price cannot be less than 110% of the fair market value of such stock at the date of grant.

Options granted under the plan become vested as directed by the Company’s Board of Directors and generally expire seven or ten years after the date of grant, unless the option holder owns more than 10% of the total combined voting power of all classes of the Company’s stock, in which case the non-statutory stock options must be exercised within five years of the date of grant. At June 30, 2010, there were options to purchase 640,000 shares granted under the plan.

The options granted since formation in June 2003 vest in general as follows:

During the three months ended June 30, 2010, the Company did not grant any options to purchase common stock.  During the three and six months ended June 30, 2010 the Company recognized an expense of approximately $6,000 and $25,000, respectively, based on the fair value of the vested options.

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The following table summarizes stock option activity for the six months ended June 30, 2010:

The following table summarizes information about stock options outstanding at June 30, 2010:

Stock Appreciation Rights under Stock Incentive Plan

The Company has adopted a stock incentive plan authorizing the grant of Stock Appreciation Rights (“SARs”). A SAR confers on the participant a right to receive, upon exercise, the excess of the fair market value of a share of Common Stock on the date of the exercise over $1.00. Such excess shall be paid in cash or common stock or a combination thereof to the participant. On June 1, 2009, 202,280 SARs were granted and 195,446 were outstanding as of June 30, 2010.

The SARs granted in June 2010 vest in general as follows:

At June 30, 2010 the Company had unvested options to purchase 128,025 shares with a weighted average grant date fair market value of $47,000.

The following table summarizes stock appreciation activity for the six months ended June 30, 2010:

During the three and six months ended June 30, 2010, the Company recognized compensation expense of approximately $6,000 and $12,000 respectively, based on the fair value of the vested shares using a Black-Scholes model.

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Restricted Stock under the Stock Incentive Plan

The Company has an incentive program whereby grants of restricted stock have been awarded to members of the Board of Directors and certain employees. Restrictions and vesting periods for the awards are determined at the discretion of the Board of Directors and are set forth in the award agreements. During the three and six months ended June 30, 2010, the Company recognized compensation expense of approximately $58,000 and $187,000, respectively, based on the fair value of the vested shares.

A summary of the status and activity of the restricted stock for the six months ended June 30, 2010 is presented below:

As of June 30, 2010, the Company had approximately $0.4 million of unrecognized share-based compensation expense related to non-vested stock awards, which is expected to be amortized over the remaining vesting periods of three years.

Note 7 — Line of Credit and Long-Term Debt

Credit Facility

Effective February 12, 2007, the Company entered into a credit facility which permits borrowings up to the borrowing base as designated by the administrative agent. As of June 30, 2010 and December 31, 2009, the Company had $5.1 million and $6.1 million, respectively, of debt outstanding under the facility. As described below, the Company is currently unable to borrow additional amounts under the credit facility due to covenant and borrowing base limitations and may be further limited in the future based on borrowing base limitations.

As of December 31, 2008, the borrowing base under the credit facility was approximately $13.2 million. The borrowing base was subject to automatic reductions for approximately $666,667 per month until it reached $10.5 million on April 1, 2009. As of April 14, 2009, the borrowing base was further reduced to $9.0 million, subject to automatic reductions of $500,000 per month until it reached $6.5 million on October 1, 2009. As of October 20, 2009, the borrowing base was subject to automatic reductions of $200,000 per month until it reaches maturity or until a redetermination is received.

The borrowing base is determined on a semi-annual basis and at such other additional times, up to twice yearly, as may be requested by either the Company or the administrative agent and is determined by the administrative agent in accordance with customary practices and standards for loans of a similar nature, although such determination is at the administrative agent’s discretion as the credit agreement does not provide a specific borrowing base formula.

Borrowings under this credit facility may be used solely to acquire, explore or develop oil and gas properties and for general corporate purposes. The credit facility matured June 15, 2010.

The Company’s obligations under the credit facility are secured by liens on (i) no less than 90% of the net present value of the oil and gas to be produced from its oil and gas properties that are included in the borrowing base determination, calculated using a discount rate of 10% per annum and reserve estimates, prices and production rates and costs, (ii) options to lease, seismic options, permits, and records related to such properties, and (iii) seismic data.

Borrowings under the Company’s credit facility, as amended, bear interest either: (i) at the greater of the one month London Interbank Offered Rate, or LIBOR, plus 1.00% or a domestic bank rate, plus in either case an applicable margin of 0.75% to 1.75% based on utilization, or (ii) on a sliding scale from the one, two, three or six month LIBOR, plus an applicable margin of 2.00% to 3.00% based on utilization. The weighted average interest rate as of June 30, 2010 was 5.0%. The credit agreement provides for various fees, including a quarterly commitment fee of 0.5% per annum and engineering fees to the administrative agent in connection with a borrowing base determination. In addition, the credit facility provided for an up front fee of $27,000, which was paid on the closing date of the credit facility, and an additional arrangement fee of 1% based on utilization. Borrowings under this credit facility may be prepaid without premium or penalty, except on Eurodollar advances.

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The Credit Agreement contains covenants that, among other things, restrict the Company’s ability, subject to certain exceptions, to do the following:

·                incur liens;

·                incur debt;

·                make investments in other persons;

·                declare dividends or redeem or repurchase stock;

·                engage in mergers, acquisitions, consolidations and asset sales or amend the Company’s organizational documents;

·                enter into certain hedging arrangements;

·                amend material contracts; and

·                enter into related party transactions.

With regard to hedging arrangements, the credit agreement provides that acceptable commodity hedging arrangements cannot be greater than 80 to 85%, depending on the measurement date, of the Company’s monthly production from its hydrocarbon properties that are used in the borrowing base determination and that the fixed or floor price of the Company’s hedging arrangements must be equal to or greater than the gas price used by the lenders in determining the borrowing base.

The credit agreement, as amended, also requires that the Company satisfy certain affirmative covenants, meet certain financial tests, maintain certain financial ratios and make certain customary indemnifications to lenders and the administrative agent. The financial covenants include requirements to maintain: (i) a ratio of EBITDA to cash interest expense of not less than 3.00 to 1.00, (ii) a ratio of current assets to current liabilities of not less than 1.00 to 1.00, (iii) a total debt to annualized EBITDA ratio of not more than 3.0 to 1.0, (iv) a quarterly total senior debt to annualized EBITDA ratio equal to or less than 3.0 to 1.0, and (v) a total proved PV-10 value to total debt ratio of at least 1.50 to 1.00.

The credit agreement, as amended, contains customary events of default, including payment defaults, covenant defaults, certain events of bankruptcy and insolvency, defaults in the payment of other material debt, judgment defaults, breaches of representations and warranties, loss of material permits and licenses and a change in control. The credit agreement requires any wholly-owned subsidiaries to guarantee the obligations under the credit agreement.

After an event of default, the outstanding debt bears interest at the default rate under the terms of the credit agreement. The default rate is (i) with respect to principal, 2% over the otherwise applicable rate and (ii) with respect to interest, fees and other amounts, the Base Rate (as defined in the credit agreement), plus the Applicable Margin (as defined in the credit agreement), plus 2%. Any default interest is payable on demand. Failure to pay the default interest when the administrative agent demands would be another default. The lenders’ remedies for defaults under the credit agreement are to terminate further borrowings, accelerate the repayment of indebtedness and/or ultimately foreclose on the collateral property.

On April 14, 2009, the Company and the administrative agent entered into the fourth amendment to the credit agreement which reduced the borrowing base as described above and waived compliance with the current ratio financial covenant as of December 31, 2009 and March 31, 2009 and with the restrictive covenants related to accounts payable, permitted liens and permitted debt until the next borrowing base redetermination, subject to certain financial caps.  On August 19, 2009, the lenders waived compliance with the current ratio financial covenant under the Credit Agreement for the period ending August 26, 2009 and the quarter ending June 30, 2010.

On August 26, 2009, the Company entered into a fifth amendment to the credit agreement which provided a waiver of the current ratio covenant through October 26, 2009 and for the quarter ending June 30, 2009. The fifth amendment to the credit agreement also extended restrictive covenants related to accounts payable, permitted liens and permitted debt, until October 26, 2009, subject to certain financial caps.

On October 20, 2009, the Company and the Lenders executed the sixth amendment to the credit agreement. This amendment established the Borrowing Base for the following amounts in the following applicable periods:

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Each Calendar month thereafter commenced May 1, 2010; the Borrowing Base for the preceding calendar month reduced by $200,000.

On October 26, 2009, the lenders provided a waiver effectively extending the terms of the fifth amendment to the credit agreement through November 16, 2009. On November 16, 2009, the lenders provided an additional waiver effectively extending the terms of the fifth amendment to the credit agreement through November 23, 2009.

On November 23, 2009, the lenders provided an additional waiver extending the terms of the fifth amendment to the credit agreement through December 1, 2009 and for the quarter ended December 31, 2009.

On December 1, 2009 the lenders provided an additional waiver extending the terms of the fifth amendment to the credit agreement through January 5, 2010.

On January 5, 2010 the lenders provided an additional waiver extending the terms of the fifth amendment to the credit agreement through January 12, 2010.

On January 13, 2010, the Company entered into a seventh amendment and waiver to credit agreement (“waiver agreement”) with the lenders party thereto. The waiver agreement provided that the lenders would waive (i) its compliance with certain restrictions based on the current ratio in the credit agreement, (ii) certain requirements pertaining to the aging of certain accounts payable, and (iii) certain restrictions regarding the amount of liens the Company has. Default remedies available to the lenders under the credit agreement include acceleration of all principal and interest amounts due under the credit agreement. The waiver agreement extends the waiver period for these items until the earlier of June 15, 2010 and the date of any default arising out of a breach or non-compliance with the credit agreement not expressly waived in the waiver agreement or a breach of the waiver agreement.

In addition, the waiver agreement amends the definition of “Final Maturity Date” under the credit agreement to the earlier of (i) June 15, 2010 or (ii) the date that is thirty days following the earlier of (A) the date the merger is withdrawn or terminated in whole or in part or (B) the date that the lenders have been advised that the merger will not proceed.

On July 8, 2010, the Company was notified by its lender that it failed to make the principal and interest payments due on July 1, 2010 and that such missed payments constituted an Events of Default under the Credit Agreement. The Company remains obligated to pay all amounts outstanding under the credit agreement. The current amount outstanding under the credit facility is approximately $5,100,000 plus accrued interest.

The Company has requested additional waivers from its lender; however, there can be no assurance that it will be able to obtain such waivers or that such waivers will be obtained on acceptable terms. If the Company is unable to obtain future waivers and/or to comply with the restrictive covenants, the lender could foreclose on properties held by liens.  Due to borrowing base limitations and waiver stipulations, the Company is currently unable to incur additional indebtedness under the credit facility.

Office Building Loan

On November 15, 2005, the Company entered into a mortgage loan secured by its office building in Sheridan, Wyoming in the aggregate principal amount of $829,000. The promissory note provides for monthly payments of principal and interest in the initial amount of $6,400 and unpaid principal that bore interest at 6.875% until November 15, 2008, currently bears interest at a variable base rate plus 0.5% and will bear interest at 18% upon a default. The variable base rate is based on the lender’s base rate. The maturity date of this mortgage is November 15, 2015, at which time a principal and interest payment of $520,800 will become due. As of June 30, 2010, the Company had $717,000 outstanding in principal on this mortgage. On November 15, 2008, the interest rate on the mortgage loan changed from a fixed rate of 6.875% to a variable rate. As of June 30, 2010, the variable rate was 4.0%.

Note 8 — Fair Value Measurements

Effective January 1, 2008, the Company adopted the authoritative guidance that applies to all financial assets and liabilities required to be measured and reported on a fair value basis. Beginning January 1, 2009, the Company also applied the guidance to non-financial assets and liabilities measured at fair value on a nonrecurring basis, including proved oil and gas properties and other long-lived assets and asset retirement obligations initially measured at fair value. The guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the

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measurement date. The guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability based on the best information available in the circumstances. The financial and nonfinancial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

·                  Level 1—Quoted prices in active markets for identical assets or liabilities;

·                  Level 2—Quoted prices in active markets for similar assets and liabilities, that are observable for the asset or liability; or

·                  Level 3—Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

The following is a listing of the Company’s assets and liabilities required to be measured at fair value on a recurring basis and where they are classified within the hierarchy as of June 30, 2010 (in thousands):

The Company adopted FASB ASC Update 2010-06, “Fair Value Measurements and Disclosures” which amends ASC Update 2010-06 to require additional disclosures concerning transfers between Levels 1 and 2, inputs and valuation techniques used to value Level 2 and 3 measurements, and push down of previously prescribed fair value disclosures to each class of asset and liability for Levels 1, 2, and 3. The Company determines the fair value of these swap contracts under the income approach using a discounted cash flow model.  The valuation model requires a variety of inputs, including contractual terms, projected gas market prices, discount rate, and credit risk adjustments, as appropriate.  The Company has consistently applied this valuation technique in all periods presented and believes it has obtained the most accurate information available for the types of derivative instruments it holds. These disclosures were effective for the Company for the quarter ended June 30, 2010.  The adoption of this pronouncement did not have a material impact on the Company’s consolidated financial statements.

The Company’s estimate of the fair value of derivative financial instruments includes consideration of the counterparty’s credit worthiness, the Company’s credit worthiness, and the time value of money. The consideration of these factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view.

Note 9 — Commitments and Contingencies

Operating Lease

Upon purchase of its building in August 2005, the Company was assigned the lease agreements for existing tenants and executed lease agreements with new tenants in the building. The leases expire from January 2010 to January 2013. Future minimum lease income under noncancelable operating leases is as follows:

Gas Gathering Contracts

The Company has entered into gas gathering and compression agreements with service providers in order to compress and transport its gas to the point of sale. Compression agreements and gathering agreements are based on a fee per Mcf either compressed

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or gathered. The Company accounts for these fees as a marketing and transportation expense. The Company does not pay or charge marketing fees associated with the movement and sale of natural gas.

Litigation

From time to time, the Company is subject to legal proceedings and claims that arise in the ordinary course of its business. In addition, like other natural gas and oil producers and marketers, the Company’s operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. As a result, it is extremely difficult to reasonably quantify future environmental and regulatory related expenditures.

The following represent legal actions in which the Company is involved. No assurance can be given that these legal actions will be resolved in the Company’s favor. However, the Company’s management believes, based on its experiences to date, that these matters will not have a material adverse impact on the Company’s business, financial position or results of operations.

The Company, together with the State of Montana, the Montana Department of Environmental Quality, the Montana Board of Oil and Gas Conservation and the Department of Natural Resources, were named as defendants in a lawsuit (Civil Cause No. DV-05-27) filed on May 19, 2005 in the Montana 22nd Judicial District Court, Bighorn County by Diamond Cross Properties, LLC relating to the Coal Creek POD. The plaintiff is a surface owner with properties located in Big Horn County and Rosebud County, Montana where the Company has a lease for approximately 10,300 acres, serves as operator and owns a working interest in the minerals under lease. The plaintiff sought to permanently enjoin the State of Montana and its administrative bodies from issuing licenses or permits, or authorizing the removal of ground water from under the plaintiff’s ranch. In addition, the plaintiff further sought to preliminarily and permanently enjoin the Company on the basis that the Company’s operations lacked adequate safeguards required under the Montana state constitution. On August 25, 2005, the district judge issued an order denying without prejudice the application for temporary restraining order and preliminary injunction requested by the plaintiff. The case was appealed by the plaintiff to the Montana Supreme Court. On November 16, 2005, the Montana Supreme Court issued an order that denied enjoining the Coal Creek POD, and subsequently, the Montana Supreme Court remanded the case back to the district court for a decision on the merits.

The Company, together with the defendants above, was also named as defendants in a related lawsuit (Civil Cause No. DV-05-70) filed on September 21, 2005 in the Montana 22nd Judicial District Court, Bighorn County by Diamond Cross Properties, LLC relating to the Dietz POD. The plaintiff sought similar relief as in the Coal Creek POD suit. The two cases were combined.

On July 14, 2008, the district court issued a summary judgment order in the combined case, and the order was subsequently entered as a judgment on August 15, 2008. As a result, the Company has continued its operations in the two project areas. To date, there has been no appeal by the plaintiff.

In April and September 2005, the U.S. Bureau of Land Management in Miles City, Montana issued suspensions of operations for the majority of the Company’s federal leases in Montana. The suspensions were issued based upon a court order issued on April 5, 2005 by the U.S. District Court of Montana that required the BLM to complete a Supplemental Environmental Impact Statement (SEIS) to address phased development of coal bed natural gas. The U.S. Ninth Circuit Court of Appeals also issued an order on May 31, 2005 which enjoined the BLM from approving coal bed natural gas production projects in the Powder River Basin of Montana. Both of these actions placed limitations on lease development until completion of the SEIS.

The 2005 injunction was lifted by the Ninth Circuit Court of Appeals on October 29, 2007. The record of decision (ROD) for the SEIS was signed by the BLM on December 30, 2008 and went into effect on January 14, 2009. The Suspension of Operations and Production for the suspended leases was terminated effective February 1, 2009. The Company has received letters from the BLM with amended lease terms of the affected leases. Leases that were suspended have been placed back into an active lease status with the primary term increasing for approximately three to five years based on the time period the leases were in suspension.

On July 6, 2009, the Company filed suit (Cause No. DV09-35) against Big Sky Energy LLC and Quaneco L.L.C., in the Twenty-Second Judicial District Court, Big Horn County, Montana alleging claims for breach of contract, breach of implied covenant of good faith and fair dealing, tortuous interference with business, tortuous interference with contractual relations and slander of title. The Company is amending the complaint to add a foreclosure action against Big Sky Energy LLC’s and Quaneco L.L.C.’s collective interest in the developed properties in Montana for non payment of invoices in the amount of $298,689.

The Company will continue to vigorously pursue payment of the amounts owed including interest and attorney’s fees along with foreclosure proceedings and any other rights and remedies available to us pursuant to the Joint Operating Agreement dated June 23, 2003, as amended.

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The Company was named as a defendant in litigation brought by RLI Insurance Company (Civil Cause No. 09-CV-157-J) filed in United States District Court for the District of Wyoming on July 6, 2009.  The complaint alleged that the Company failed to provide $1,439,360 in additional collateral requested by plaintiff to secure certain bonds issued by plaintiff on behalf of the Company.  Plaintiff sought the additional bond collateral plus attorney’s fees and costs.  On March 18, 2010, Pinnacle Gas Resources, Inc. and RLI Insurance Company entered into a Tolling Agreement.  The agreement stipulated that the parties dismiss all claims and counterclaims in the litigation captioned RLI Insurance Company v. Pinnacle Gas Resources, Inc., Case No. 09-CV-157-J (D. Wyo.), without prejudice.  The agreement further stipulated that each party will extend the period within which either party may institute a claim, counterclaim, action or proceeding up to and including June 16, 2010.  The agreement also obligated The Company to continue to solicit market quotes for the purpose of replacing all bonds or bonding relationships which exist between the Company and RLI Insurance Company.  The Tolling Agreement has lapsed and, to the Company’s knowledge on the date hereof, RLI Insurance Company has not re-filed its claims against the Company.

The Company is a party to two stockholder class action lawsuit filed in the Delaware Court of Chancery.  On March 24, 2010, the Delaware Court of Chancery entered an order consolidating the two actions under the caption In re Pinnacle Gas Resources Shareholder Litigation, C.A. No. 5313-CC (Del. Ch.) and appointing co-lead counsel.

The consolidated complaint generally alleges that our directors breached their fiduciary duties by, among other things, entering into the merger agreement with Powder and Powder Holdings, taking actions designed to deter higher offers from other potential acquirers and failing to maximize the value of Pinnacle to its stockholders. In addition, the lawsuit alleges that DLJ, as a controlling stockholder of Pinnacle, violated fiduciary duties to Pinnacle stock holders and that Powder and Merger Sub aided and abetted the alleged breaches of fiduciary duties by the other defendants.  The lawsuit seeks, among other relief, injunctive relief prohibiting the Merger, and costs of the action including reasonable attorneys’ fees.

On May 24, 2010, the Company and its directors entered into a Memorandum of Understanding in anticipation of settling the shareholder lawsuit. Under the terms of the Memorandum of Understanding, the Company agreed to make additional proxy disclosures regarding the interests of our executive officers in the surviving entity and furnish additional information regarding FBR’s analysis and fairness opinion. In return the shareholders will provide a release of their claims against the Company, its directors, Powder and DLJ.  The Company and its directors, Powder and DLJ do not admit any wrongdoing and entered into the Memorandum of Understanding to avoid the distraction, burden and expense of further litigation. The settlement is subject to confirmatory discovery, negotiation of a definitive settlement agreement, and approval by the Delaware Chancery Court. Powder and DLJ have agreed to the terms of the Memorandum of Understanding.

Regulations

The Company’s oil and gas operations are subject to various federal, state and local laws and regulations. The Company could incur significant expense to comply with the new or existing laws and non-compliance could have a material adverse effect on the Company’s operations.

Environmental

The Company produces significant amounts of water from its wells. If future wells produce water of a lesser quality than allowed under state laws or if water is produced at rates greater than the Company can dispose of, the Company could incur additional costs to dispose of the water.

Note 10 — NASDAQ Delisting

On March 16, 2010, The NASDAQ Stock Market notified the Company of its failure to comply with Listing Rule 5450(a)(1). This rule subjects a company’s stock to delisting on the NASDAQ exchange if its stock price closes below $1 over the previous 30 consecutive business days and then, after notification, fails to regain compliance within the subsequent 180 days. Accordingly, unless the Company appealed this determination, the trading of the Company’s stock would have been suspended on March 25, 2010. The Company filed an appeal, pursuant to NASDAQ listing rule series 5800 on March 22, 2010.

On April 29, 2010, the Company met with representatives of NASDAQ to formally request a 180 day extension to allow implementation of certain strategies to regain compliance.

On May 10, 2010, the Company received a determination letter from the NASDAQ hearings panel granting the Company’s request for continued listing subject to a proxy being filed which included a proposal for a reverse stock split and a closing bid price of $1.00 or more for a minimum of ten consecutive trading days prior to September 13, 2010.

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Note 11 — Recent Developments

At the special meeting of the shareholders on August 9, 2010, the our shareholders voted to approve a proposal to adopt the Agreement and Plan of Merger dated February 23, 2010 (“Merger Agreement”) by and amongst us, Powder Holdings, LLC, a Delaware LLC, and Powder Acquisition Co. (“Powder”), A Delaware Corporation and wholly-owned subsidiary of Powder. We anticipate that the closing will occur during the third quarter, subject to the satisfaction of customary closing conditions and the receipt of waivers from our lender, The Royal Bank of Scotland plc.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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, 2009, 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 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 June 30, 2010, we owned natural gas and oil leasehold interests in approximately 406,000 gross (297,000 net) acres, approximately 90% of which were undeveloped. As of December 31, 2009, we had estimated net proved reserves of approximately 15.0 Bcf based on the first day of the month, twelve month average CIG index price of approximately $3.04 per Mcf.

The continued credit crisis and related turmoil in the global financial system have had an adverse impact on our business and financial condition. In addition, the prices of oil and natural gas declined significantly in 2008 and have remained low in 2009 and during the first six months of 2010. Therefore, total capital expenditures were limited to $4.2 million in 2009. As a result of low CIG index prices, the economic climate and our limited capital resources, we expect to continue operating during 2010 with a reduced capital expenditure plan. Under our plan, we will generally make expenditures only as 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. Our capital expenditure budget for 2010 will be dependent upon CIG index prices, our cash flows and the availability of additional capital resources.  We had total capital expenditures of $1.9 million for the six months ended June 30, 2010.

On February 23, 2010, we entered into an Agreement and Plan of Merger with Powder Holdings, LLC, and Powder Acquisition Co., a direct, wholly owned subsidiary of Powder Holdings. Powder Holdings is controlled by an investor group led by Scotia Waterous (USA) Inc. and includes certain members of our management team. On April 2, 2010, we filed a preliminary proxy statement relating to the merger, with the U.S. Securities and Exchange Commission (SEC). On June 29, 2010, we filed a definitive proxy statement relating to the merger with the SEC. At the special meeting of the shareholders on August 9, 2010, our shareholders voted to approve a proposal to adopt the Agreement and Plan of Merger dated February 23, 2010 (“Merger Agreement”) by and amongst us, Powder Holdings, LLC, and Powder Acquisition Co. (“Powder”), a wholly-owned subsidiary of Powder. We anticipate that the closing will occur during the third quarter, subject to the satisfaction of customary closing conditions and the receipt of waivers from our lender, The Royal Bank of Scotland plc.

Shares of our common stock are traded on the NASDAQ Global Market under the symbol “PINN.”

Economic and Natural Gas Pricing Environment

During 2009, 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 cash flows from operations.

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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 $6.24 per Mcf for the twelve months ended December 31, 2008 but only $3.07 per Mcf for the twelve months ended December 31, 2009. For the first six months of 2010, the price averaged $4.38.  This volatility in price has caused us to reevaluate our 2010 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

In the past, our primary sources of liquidity have been private and public sales of our equity securities, cash provided by operating activities, and debt financing. All of these sources have been negatively impacted by the current economic climate, its impact on our industry, and by significant fluctuations in oil and gas prices, operating costs, and volumes produced. We have no control over the market prices for oil and natural gas, although we are able to influence the amount of our net realized revenues related to gas sales through the use of derivative contracts. A decrease in market prices would reduce expected cash flow from operating activities and could reduce the borrowing base of our credit facility as well as the value of assets we might consider selling. Historically, decreases in the market prices have limited our industry’s access to the capital markets. During these challenging times, we have reduced our administrative, operating and transportation costs. We are also actively marketing asset sales and exploring other strategic alternatives and capital restructuring options.

On January 13, 2010, we entered into a seventh amendment and waiver to credit agreement (“waiver agreement”) with the lenders party thereto. The waiver agreement provided that the lenders would waive (i) our compliance with certain restrictions based on the current ratio in the credit agreement, (ii) certain requirements pertaining to the aging of certain accounts payable, and (iii) certain restrictions regarding the amount of liens we have. Default remedies available to the lenders under the credit agreement include acceleration of all principal and interest amounts due under the credit agreement. The waiver agreement extends the waiver period for these items until the earlier of June 15, 2010 and the date of any default arising out of a breach or non-compliance with the credit agreement not expressly waived in the waiver agreement or a breach of the waiver agreement.

In addition, the waiver agreement amends the definition of “Final Maturity Date” under the credit agreement to the earlier of (i) June 15, 2010 or (ii) the date that is thirty days following the earlier of (A) the date the merger (please see Note 10 in the notes to the financial statements) is withdrawn or terminated in whole or in part or (B) the date that the lenders have been advised that the merger will not proceed.

On July 8, 2010, we were notified by our lender that we failed to make the principal and interest payments due on July 1, 2010 and that such missed payments constituted an Events of Default under the Credit Agreement. We remain obligated to pay all amounts outstanding under the credit agreement.  The current amount outstanding under the credit facility is approximately $5,100,000.

We have requested additional waivers from our lender; however, 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 restrictive covenants, the lender could foreclose on properties held by liens.  Due to borrowing base limitations and waiver stipulations, we are currently unable to incur additional indebtedness under the credit facility.

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. We also put additional hedges of our natural gas production in place to secure certain operating cash flow levels during 2010. From January through April 2010, we had 5,500 MMbtu per day hedged through fixed price swaps at a weighted average price of $4.19 per MMbtu. From May through December 2010, we have 5,500 MMbtu hedged through fixed price swaps at a weighted average price of $5.08 per MMbtu. 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;

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·                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;

·                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 are 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. No impairment was recorded on unevaluated properties for the three and six months ended June 30, 2010 and the year ended December 31, 2009, respectively. Abandonment of unproved properties is also accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized.

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. 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 June 30, 2010 and December 31, 2009, the estimated salvage value of equipment was $6.8 million.

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 the first day of the month, twelve month average CIG price, 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 June 30, 2010, the full cost ceiling limitation exceeded the capitalized cost of the Company’s oil and gas properties by approximately $5.2 million based on the first day of the month, twelve month average CIG price of approximately $3.76 per Mcf. Therefore, no impairment was taken for the quarter ended June 30, 2010. An impairment of $6.4 million was taken for the quarter ended June 30, 2009 based on a natural gas price of $3.09 per Mcf. A decline in gas prices or an increase in operating costs subsequent to the measurement date 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

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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 June 30, 2010 and December 31, 2009, 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 June 30, 2010, and December 31, 2009 were based on the actual volume statements from our purchasers and distribution process. If accruals were to change by 10% at June 30, 2010 and at December 31, 2009, the impact would have been a change of $87,000 and $124,000, respectively.

Asset Retirement Obligations

We follow certain accounting provisions that apply 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. These provisions 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 $300,000 effect on our asset retirement obligation liability at June 30, 2010.

The following is a summary of our asset retirement obligation activity for the three and six months ended June 30, 2010 and June 30, 2009 (unaudited):

Inventory

We have acquired inventory of oil and gas equipment, primarily tubulars, 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 $45,000 reduction in our inventory valuation as of June 30, 2010. 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.

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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 impairment. No impairments were recorded during the six months ended June 30, 2010 and the year ended December 31, 2009.

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 six months ended June 30, 2010 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. Deferred tax assets and liabilities are recognized for the expected future tax consequences of temporary differences between the financial statement and tax basis 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 June 30, 2010 and December 31, 2009, we recorded a full valuation allowance for our net deferred tax asset.

On January 1, 2007, we adopted accounting provisions that prescribe 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. This provision 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 the provision, we performed a comprehensive review of our material tax positions in accordance with these recognition and measurement standards. As a result of this review, we did not identify any material deferred tax assets that required adjustment. As of June 30, 2010 and December 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 June 30, 2010 and 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 2009. 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

On July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was enacted into law.  This financial reform legislation includes provisions that require over-the-counter derivative transactions to be executed through an exchange or centrally cleared.  In addition, the legislation provides an exemption from mandatory clearing requirements based on regulations to be developed by the Commodity Futures Trading Commission (CFTC) and the Securities and Exchange Commission  for transactions by non-financial institutions to hedge or mitigate commercial risk.  At the same time, the legislation includes provisions under which the CFTC may impose collateral requirements for transactions, including those that are used to hedge commercial risk.  However, during drafting of the legislation, members of Congress adopted report language and issued a public letter stating that it was not their intention to impose margin and collateral requirements on counterparties that utilize transactions to hedge commercial risk.  Final rules on major provisions in the legislation will be established through rulemakings and will not take effect until 12 months after the date of enactment.   Although we cannot predict the ultimate outcome of these rulemakings, new regulations in this area may result in increased costs and cash collateral requirements for the types of oil and gas derivative instruments we use to hedge and otherwise manage our financial risks related to volatility in oil and gas commodity prices.

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 authoritive guidance prescribed by FASB that 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.

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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 certain accounting provisions, the changes in fair market value are recognized in earnings.

Stock-Based Compensation

Effective January 1, 2006, we adopted accounting provisions, which require companies to recognize compensation expense for share-based payments based on the estimated fair value of the awards. We recognized an expense of approximately $25,000 for the six months ended June 30, 2010, based on the fair value of vested options.  We recognized an expense of approximately $187,000 for six months ended June 30, 2010, based on the fair value of restricted stock that vested during the quarter.  We recognized an expense of approximately $12,000 for the six months ending June 30, 2010, based on the fair market value of stock appreciation rights. This accounting provision 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 approximately $14,000 and $100,000 at each of June 30, 2010 and December 31, 2009 respectively.

Transportation Costs

We account for transportation costs under authoritative guidance prescribed by the FASB related to the 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 an accounting provision, which states that a loss contingency be recorded if it is probable that a liability has been incurred and it is reasonably estimatable. At June 30, 2010 and 2009, we recorded no expenses for legal proceedings.

Per Share Information

Basic earnings (loss) per share is computed by dividing net income (loss) from continuing operations attributable to common stock by the weighted average number of shares of common stock outstanding during each period. Diluted earnings per share are computed by adjusting the average number of shares of common stock outstanding for the dilutive effect, if any, of common stock equivalents such as stock options and warrants. For the six months ended June 30, 2010, basic and diluted net loss per share was $0.02. During the six months ended June 30, 2010, 835,446 options and stock appreciation rights were excluded because they were anti-dilutive.

Recent Accounting Pronouncements

For information concerning recent accounting pronouncements, please see Note 2 in the notes to the audited financial statements appearing elsewhere in this report.

Trends Affecting Our Business

The continued credit crisis and related turmoil in the global financial system have had an adverse impact on our business and financial condition. In addition, the prices of oil and natural gas declined significantly in 2008 and have remained low in 2009 and the first and second quarters of 2010. As a result of low CIG index prices, the economic climate and our limited capital resources, we expect to continue operating during 2010 with a reduced capital expenditure plan for 2010. Under our plan, we will generally make expenditures only 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.

Historically, natural gas prices have been extremely volatile, and we expect that volatility to continue. For example, during the six months ended June 30, 2010, the NYMEX natural gas index price ranged from a high of $6.00 per MMBtu to a low of $3.84

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per MMBtu, while the CIG natural gas index price ranged from a high of $6.08 per MMBtu to a low of $3.35 per MMBtu. During the year ended December 31, 2009, the NYMEX natural gas index price ranged from a high of $4.45 per MMBtu to a low of $3.25 per MMBtu, while the CIG natural gas index price ranged from a high of $3.47 per MMBtu to a low of $1.33 per MMBtu. Changes in natural gas pricing have impacted our revenue streams, production taxes, prices used in reserve calculations, borrowing base calculations and the carrying value of our properties and the valuation of potential property acquisitions. During the six months ended June 30, 2010, estimated future gas prices had an impact on both our revenues and the costs attributable to our future operations. We expect that changing natural gas prices will continue to impact our operations and financial results in the future.

Transportation of natural gas and access to throughput capacity has a direct impact on natural gas prices in the Rocky Mountain region, where our operations are concentrated. As drilling activity increases throughout the Rocky Mountain region, additional production may come on line, which could cause bottlenecks or capacity constraints. Generally speaking, a surplus of natural gas production relative to available transportation capacity has a negative impact on prices. Conversely, as capacity increases, and bottlenecks are eliminated, prices generally increase. Although there is currently adequate transportation capacity out of the Powder River Basin, a surplus of natural gas arriving at key marketing hubs from the Powder River Basin and elsewhere relative to available takeaway capacity from these hubs has caused Rocky Mountain gas to generally trade at a discount to the NYMEX natural gas index price. For example, from January 1, 2010 through June 30, 2010, Rocky Mountain gas traded at a differential to the NYMEX natural gas index price that ranged from a premium of $0.27 per Mcf to a discount of $1.00 per Mcf, with an average differential of a discount of $0.38 per Mcf. The Rockies Express Pipeline which was completed and placed into service in early 2008, has increased takeaway capacity by approximately 1.5 Bcf per day from these hubs. We expect that the completion of additional proposed pipelines will help reduce the differential between gas produced in the Rocky Mountain region and the NYMEX natural gas index price. Additional proposed pipelines are scheduled to be completed in late 2010 and 2011. General economic conditions and the future demand for natural gas may change the development schedule of proposed pipelines.

Results of Operations

Net loss attributable to stockholders for the quarter ended June 30, 2010 was $1.8 million, or $0.06 per diluted share, on total revenues of $2.5 million. Other income for the quarter ended June 30, 2010 included a $0.6 million unrealized loss associated with the change in the fair valuation of our natural gas hedges in place in accordance with certain accounting provisions. Absent such change in the valuation of hedges, we would have shown a loss of $1.2 million.  This compares to a net loss attributable to stockholders of $9.5 million for the quarter ended June 30, 2009 on total revenue of $3.7 million. Adjusted for an unrealized loss in the fair valuation of our natural gas hedges in place of $2.7 million shown in other income, our results for the quarter ended June 30, 2009 would have been a net loss attributable to common stockholders of $6.8 million.

In order to provide a measure of stability to the cash flow in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk, we chose to periodically hedge a portion of our oil and gas production using swap and collar agreements. We account for our derivative instruments under certain accounting provisions which require us to record derivative instruments at their fair value. Management has chosen not to use hedge accounting for these arrangements. Therefore, in accordance with these provisions, changes in the fair market value are recognized in earnings.

Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009

Gas sales volume.

Gas sales volume decreased 18%, from 702 MMcf in the three months ended June 30, 2009 to 575 MMcf in the three months ended June 30, 2010. Daily sales volume was 6.3 MMcf for the three months ended June 30, 2010 as compared to 7.7 MMcf for the three months ended June 30, 2009, a 1.4 MMcf per day decrease. The decrease resulted primarily from shutting in wells due to low natural gas prices, reductions in volumes due to compression maintenance and repairs, and weather related downtime.

Gas sales revenue.

Revenue from gas sales increased approximately $0.3 million during the three months ended June 30, 2010, to approximately $1.9 million, a 21% increase compared to the three months ended June 30, 2009. This increase was primarily due to an increase in the average realized price per Mcf along with a reduction in gas sales volume. The average realized price per Mcf increased approximately 47%, from $2.29 per Mcf in the three months ended June 30, 2009 to $3.37 per Mcf in the three months ended June 30, 2010.

Derivatives.

For the three months ended June 30, 2010, we had an unrealized loss of $610,000 compared to an unrealized loss of $2.7 million for the three months ended June 30, 2009. The unrealized losses are non-cash expenses based primarily on the Black-Scholes

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model for valuing future cash flows utilizing price volatility with a normal discount rate. Hedges settled during the three months ended June 30, 2010 resulted in a realized gain of $590,000 compared to a realized hedge gain of $2.1 million during the three months ended June 30, 2009. The realized hedge gain for the three months ended June 30, 2010 was primarily due to the fact that gas prices were lower than the weighted average floor price of our hedges in place.

Lease operating expenses.

Lease operating expenses decreased $0.2 million in the three months ended June 30, 2010 to $0.8 million, a 18% decrease compared to the three months ended June 30, 2009. This decrease resulted primarily from a reduction in contract services, fuel, and water management related costs offset partially by an increase in surface use expenses in the productive cycle during the three months ended June 30, 2010. On a Mcf basis, lease operating expenses were $1.34 an Mcf for the three months ended June 30, 2010 and June 30, 2009.

Production taxes.

Production taxes increased $68,000 in the three months ended June 30, 2010 to $0.2 million, a 49% increase from the three months ended June 30, 2009. Production taxes generally correlate to gross sales revenue because production taxes are based on a percentage of sales value. In Wyoming, the percentage averages 11% to 13%, depending on rates in effect for the respective year, while in Montana the percentage averages 9%. The decrease in production taxes for the three months ended June 30, 2010 was primarily due to decreased revenues associated with decreased volume and realized pricing. On a Mcf basis, production taxes were $0.36 per Mcf for the three months ended June 30, 2010 and $0.20 per Mcf for the three months ended June 30, 2009, a 81% increase, which correlates to the increase in the price per Mcf received in the three months ended June 30, 2010 from the three months ended June 30, 2009.

Marketing and transportation.

Marketing and transportation expenses decreased approximately $0.1 million in the three months ended June 30, 2010 to approximately $0.8 million, a 16% decrease from the three months ended June 30, 2009. The decrease related primarily to a decrease in transportation fees and compression due to lower production volumes. On an Mcf basis, marketing and transportation expenses increased 3% to $1.31 per Mcf in the three months ended June 30, 2010 from $1.27 per Mcf in the three months ended June 30, 2009.

General and administrative expenses, net.

General and administrative expenses are offset by operating income from drilling and production activities for which we can charge an overhead fee to nonoperating working interest owners. These well operating overhead fees were $332,000 in the three months ended June 30, 2010 compared to $335,000 for the three months ended June 30, 2009. General and administrative expenses net decreased $0.2 million in the three months ended June 30, 2010 to $1.0 million. On a Mcf basis, general and administrative expenses, net increased 5%, from $1.69 per Mcf in the three months ended June 30, 2009 to $1.77 per Mcf in the three months ended June 30, 2010. General and administrative expenses, for the quarter ended June 30, 2010, include $0.4 million for professional services expense incurred in connection with the merger agreement with Powder and Powder Holdings.

Depreciation, depletion, amortization and accretion.

Depreciation, depletion, amortization and accretion expense decreased $0.1 million for the three months ended June 30, 2010 to $0.8 million, an 8% decrease compared to the three months ended June 30, 2009. The decrease was primarily due to a decrease in the capitalized basis in our full cost pool at June 30, 2010. On an Mcf basis, the depreciation, depletion, amortization and accretion rate increased to $1.47 per Mcf in the three months ended June 30, 2010 from $1.30 per Mcf in the three months ended June 30, 2009.

Impairment.

At June 30, 2010, the full cost ceiling limitation of our oil and gas properties exceeded the capitalized cost by approximately $5.2 million based upon a natural gas price of approximately $3.76 per Mcf (based on the first day of the month, twelve month average per Mcf on the Colorado Interstate Gas Rocky Mountain Index) in effect at that date. Therefore, no impairment was taken for the three months ended June 30, 2010. An impairment of approximately $6.4 million was taken for the three months ended June 30, 2009.  For further information regarding this impairment, please see Note 2 — “Basis of Presentation” in the Notes to the unaudited financial statements appearing elsewhere in this quarterly report. A decline in natural gas prices or an increase in operating costs in economically recoverable quantities could result in the recognition of additional impairments of our oil and gas properties in future periods.

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Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Gas sales volume.

Gas sales volume decreased 23%, from 1,516 MMcf in the six months ended June 30, 2009 to 1,169 MMcf in the six months ended June 30, 2010. Daily sales volume was 6.5 MMcf for the six months ended June 30, 2010 as compared to 8.4 MMcf for the six months ended June 30, 2009, a 1.9 MMcf per day decrease. The decrease resulted primarily from shutting in wells due to low natural gas prices, reductions in volumes due to compression maintenance and repairs, and weather related downtime.

Gas sales revenue.

Revenue from gas sales increased approximately $0.4 million during the six months ended June 30, 2010, to approximately $4.8 million, a 9% increase compared to the six months ended June 30, 2009. This increase was primarily due to a increase in the average realized price offset by a decrease in gas sales volume per Mcf. The average realized price per Mcf increased approximately 42%, from $2.88 per Mcf in the six months ended June 30, 2009 to $4.09 per Mcf in the six months ended June 30, 2010.

Derivatives.

For the six months ended June 30, 2010, we had an unrealized gain of $2.3 million compared to an unrealized loss of $2.1 million for the six months ended June 30, 2009. The unrealized losses are non-cash expenses based primarily on the Black-Scholes model for valuing future cash flows utilizing price volatility with a normal discount rate. Hedges settled during the six months ended June 30, 2010 resulted in a realized gain of $0.1 million compared to a realized hedge gain of $3.5 million during the six months ended June 30, 2009. The realized hedge gain for the six months ended June 30, 2010 was primarily due to the fact that gas prices were lower than the weighted average floor price of our hedges in place.

Lease operating expenses.

Lease operating expenses decreased $0.3 million in the six months ended June 30, 2010 to $1.8 million, a 16% decrease compared to the six months ended June 30, 2009. This decrease resulted primarily from a reduction in labor, fuel, workover and water management related costs offset partially by an increase in surface use expenses in the productive cycle during the six months ended June 30, 2010. On a Mcf basis, lease operating expenses increased 9% from $1.40 per Mcf in the six months ended June 30, 2009 to $1.53 per Mcf in the six months ended June 30, 2010.

Production taxes.

Production taxes increased $0.1 million in the six months ended June 30, 2010 to $0.5 million, a 26% increase from the six months ended June 30, 2009. Production taxes generally correlate to gross sales revenue because production taxes are based on a percentage of sales value. In Wyoming, the percentage averages 11% to 13%, depending on rates in effect for the respective year, while in Montana the percentage averages 9%. The decrease in production taxes for the six months ended June 30, 2010 was primarily due to decreased revenues associated with decreased volume and realized pricing. On an Mcf basis, production taxes were $0.45 per Mcf for the six months ended June 30, 2010 and $0.28 per Mcf for the six months ended June 30, 2009, a 63% increase, which correlates to the increase in the price per Mcf received in the six months ended June 30, 2010 from the six months ended June 30, 2009.

Marketing and transportation.

Marketing and transportation expenses decreased approximately $0.7 million in the six months ended June 30, 2010 to approximately $1.5 million, a 31% decrease from the six months ended June 30, 2009. The decrease related primarily to a slight decrease in transportation fees and compression due to lower production volumes. On an Mcf basis, marketing and transportation expenses decreased 11% to $1.26 per Mcf in the six months ended June 30, 2010 from $1.41 per Mcf in the six months ended June 30, 2009.

General and administrative expenses, net.

General and administrative expenses are offset by operating income from drilling and production activities for which we can charge an overhead fee to nonoperating working interest owners. These well operating overhead fees were $0.6 million in the six months ended June 30, 2010 compared to $0.7 million for the six months ended June 30, 2009, a 6% decrease. General and administrative expenses, net, increased $0.2 million in the six months ended June 30, 2010 to $2.4 million. On an Mcf basis, general and administrative expenses, net increased 42%, from $1.46 per Mcf in the six months ended June 30, 2009 to $2.07 per Mcf in the six months ended June 30, 2010. The increase in general and administrative expenses was primarily a result of professional services expense incurred in connection with the merger agreement with Powder and Powder Holdings.

Depreciation, depletion, amortization and accretion.

Depreciation, depletion, amortization and accretion expense decreased $1.2 million for the six months ended June 30, 2010 to $1.6 million, a 43% decrease compared to the six months ended June 30, 2009. The decrease was primarily due to a decrease in the

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capitalized basis in our full cost pool. On an Mcf basis, the depreciation, depletion, amortization and accretion rate decreased to $1.33 per Mcf in the six months ended June 30, 2010 from $1.81 per Mcf in the six months ended June 30, 2009.

Impairment.

In the six months ending June 30, 2010, the full cost ceiling limitation of our oil and gas properties exceeded the capitalized cost by approximately $5.2 million based upon a natural gas price of approximately $3.76 per Mcf (based on the first day of the month, twelve month average per Mcf on the Colorado Interstate Gas Rocky Mountain Index) in effect at that date. Therefore, no impairment was taken for the quarter ended June 30, 2010. An impairment of approximately $23.3 million was taken for the quarter ended June 30, 2009.  For further information regarding this impairment, please see Note 2 — “Basis of Presentation” in the Notes to the unaudited financial statements appearing elsewhere in this quarterly report. A decline in natural gas prices or an increase in operating costs in economically recoverable quantities could result in the recognition of additional impairments of our oil and gas properties in future periods.

Liquidity and Capital Resources

In the past, our primary sources of liquidity have been private and public sales of our equity securities, cash provided by operating activities, and debt financing. All of these sources have been negatively impacted by the current economic climate, its impact on our industry, and by significant fluctuations in oil and gas prices, operating costs, and volumes produced. We have no control over the market prices for oil and natural gas, although we are able to influence the amount of our net realized revenues related to gas sales through the use of derivative contracts. A decrease in market prices would reduce expected cash flow from operating activities and could reduce the borrowing base of our credit facility as well as the value of assets we might consider selling. Historically, decreases in market prices have limited our industry’s access to the capital markets. During these challenging times, we have reduced our administrative, operating and transportation costs. We are also actively marketing asset sales and exploring other strategic alternatives and capital restructuring options.

Credit Facility.

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 June 30, 2010 and December 31, 2009, we had $5.1 million and $11.5 million, respectively, of debt outstanding under the facility. As described below, we are currently unable to borrow additional amounts under the credit facility due to covenant limitations and may be further limited in the future based on borrowing base limitations.

As of December 31, 2009, the borrowing base under the credit facility was approximately $13.2 million. The borrowing base was subject to automatic reductions of approximately $666,667 per month until it reached $10.5 million on April 1, 2009. As of August 13, 2009, our borrowing base was reduced to $7.5 million, subject to automatic reductions of $500,000 per month until it reaches $6.5 million on October 1, 2009.  Further borrowing base redeterminations were made pursuant to a series of waivers and agreements described below.

The borrowing base is determined on a semi-annual basis and at such other additional times, up to twice yearly, as may be requested by either us or the administrative agent and is determined by the administrative agent in accordance with customary practices and standards for loans of a similar nature, although such determination is at the administrative agent’s discretion as the credit agreement does not provide a specific borrowing base formula.

Borrowings under this credit facility may be used solely to acquire, explore or develop oil and gas properties and for general corporate purposes.

Our obligations under the credit facility are secured by liens on (i) no less than 90% of the net present value of the oil and gas to be produced from our oil and gas properties that are included in the borrowing base determination, calculated using a discount rate of 10% per annum and reserve estimates, prices and production rates and costs, (ii) options to lease, seismic options, permits, and records related to such properties, and (iii) seismic data.

Borrowings under our credit facility, as amended, bear interest either: (i) at the greater of the one month London Interbank Offered Rate, or LIBOR, plus 1.00% or a domestic bank rate, plus in either case an applicable margin of 0.75% to 1.75% based on utilization, or (ii) on a sliding scale from the one, two, three or six month LIBOR, plus an applicable margin of 2.00% to 3.00% based on utilization. The weighted average interest rate as of June 30, 2010 was 5.0%.  The credit agreement provides for various fees, including a quarterly commitment fee of 0.5% per annum and engineering fees to the administrative agent in connection with a borrowing base determination. In addition, the credit facility provided for an up front fee of $27,000, which was paid on the closing date of the credit facility, and an additional arrangement fee of 1% based on utilization. Borrowings under this credit facility may be prepaid without premium or penalty, except on Eurodollar advances.

The credit agreement contains covenants that, among other things, restrict our ability, subject to certain exceptions, to do the following:

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·                incur liens;

·                incur debt;

·                make investments in other persons;

·                declare dividends or redeem or repurchase stock;

·                engage in mergers, acquisitions, consolidations and asset sales or amend our organizational documents;

·                enter into certain hedging arrangements;

·                amend material contracts; and

·                enter into related party transactions.

With regard to hedging arrangements, our credit agreement provides that acceptable commodity hedging arrangements cannot cover greater than 80 to 85%, depending on the measurement date, of our monthly production from our hydrocarbon properties that are used in the borrowing base determination, and that the fixed or floor price of our hedging arrangements must be equal to or greater than the gas price used by the lenders in determining the borrowing base.