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**UNITEDSTATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

 

##### **Form 10-Q**

 

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

** **

**For thequarterly period ended March 31, 2009**

** **

**or**

** **

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

 

**For thetransition period from                      to**

 

**Commissionfile number: 001-33457**

 

**PinnacleGas Resources, Inc.**

(Exactname of registrant as specified in its charter)

 

| **Delaware**                                                    | ** ** | **30-0182582**                        |
|-----------------------------------------------------------------|------------|---------------------------------------|
| (State or other  jurisdiction of incorporation or organization) |       | (I.R.S. Employer  Identification No.) |
|                                                            |       |                                  |
| **1 E.  Alger Street**                                          | ** ** | ** **                            |
| **Sheridan,  WY**                                               | ** ** | **82801**                             |
| (Address of  principal executive offices)                       |       | (Zip code)                            |

 

**(307)673-9710**

(Registrant’s telephonenumber, including area code)

 

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

 

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

 

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

 

| Large Accelerated Filer o |   | Accelerated Filer o     |
|--------------------------------|--------|------------------------------|
|                           |   |                         |
| Non-Accelerated  Filer o  |   | Smaller reporting  company x |

 

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

 

29,188,009 shares of the registrant’s Common Stockwere outstanding as of May 13, 2009.

 

 

 

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**PINNACLEGAS RESOURCES, INC.**

Index to Form 10-Q

 
|                                                                                                     | **Page** |
|-----------------------------------------------------------------------------------------------------|----------|
| Cautionary Statement Concerning Forward-Looking  Statements                                         | 2        |
| Part I. FINANCIAL INFORMATION                                                                  | 4        |
| Item 1. Financial Statements                                                                        | 4        |
| Balance  Sheets as of December 31, 2008 and March 31, 2009 (unaudited)                    | 4        |
| Statements  of Operations for the three months ended March 31, 2009 and 2008  (unaudited)      | 5        |
| Statements  of Cash Flows for the three months ended March 31, 2009 and 2008  (unaudited)      | 6        |
| Statements of Stockholders’ Equity at March 31,  2009 (unaudited)                         | 7        |
| Notes to Financial Statements (unaudited)                                                           | 8        |
| Item 2. Management’s Discussion and Analysis of  Financial Condition and Results of Operations | 19       |
| Overview                                                                                            | 19       |
| Economic and Natural Gas Pricing Environment                                                        | 19       |
| Credit Facility and Liquidity                                                                       | 20       |
| Critical Accounting Policies                                                                        | 20       |
| Trends Affecting Our Business                                                                       | 24       |
| Results  of Operations                                                                              | 25       |
| Liquidity and Capital Resources                                                                     | 27       |
| Item 3. Quantitative and Qualitative Disclosures About  Market Risk                                 | 30       |
| Item 4T. Controls and Procedures                                                                    | 31       |
| Part II.  OTHER INFORMATION                                                                    | 32       |
| Item  1. Legal Proceedings                                                                          | 32       |
| Item 1A. Risk Factors                                                                               | 32       |
| Item 2. Unregistered Sales of Equity Securities and  Use of Proceeds                                | 32       |
| Item 3. Defaults Upon Senior Securities                                                             | 32       |
| Item 4. Submission of Matters to a Vote of Security  Holders                                        | 33       |
| Item  5. Other Information                                                                          | 33       |
| Item 6. Exhibits                                                                                    | 34       |

 

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**CAUTIONARY STATEMENT CONCERNINGFORWARD-LOOKING STATEMENTS**

 

We are including thefollowing discussion to inform you of some of the risks and uncertainties thatcan affect our company and to take advantage of the “safe harbor” protectionfor forward-looking statements that applicable federal securities law affords.Various statements in this quarterly report on Form 10-Q, including thosethat express a belief, expectation, or intention, as well as those that are notstatements of historical fact, are forward-looking statements. These includestatements relating to such matters as:

 

· our financial position or operatingresults;

 

· projections and estimates concerning thetiming and success of specific projects;

 

· our business strategy;

 

· our budget;

 

· the amount, nature and timing of capitalexpenditures;

 

· the drilling of wells;

 

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

 

· the timing and amount of futureproduction of natural gas and oil;

 

· our operating costs and other expenses;

 

· our estimated future net revenues from naturalgas 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, thestatements which include those words are usually forward-looking statements.When we describe strategy that involves risks or uncertainties, we are makingforward-looking statements. The forward-looking statements in this quarterlyreport on Form 10-Q speak only as of the date of this report. We disclaimany obligation to update these statements unless required by securities law,and we caution you not to rely on them unduly. We have based theseforward-looking statements on our current expectations and assumptions aboutfuture events. While our management considers these expectations andassumptions to be reasonable, they are inherently subject to significant business,economic, competitive, regulatory and other risks, contingencies anduncertainties, most of which are difficult to predict and many of which arebeyond 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 andcrude oil and their related effects, including on cash flows and potentialimpairments of oil and gas properties;

 

· regional price differentials;

 

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

 

· the lack of liquidity of our equity securities;

 

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· the substantial capital expendituresrequired for construction of pipelines and the drilling of wells and therelated need to fund such capital requirements through commercial banks and/or publicsecurities markets;

 

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

 

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

 

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

 

· production variances from expectations;

 

· our ability to develop and replacereserves;

 

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

 

· potential mechanical failure orunder-performance of significant wells;

 

· environmental-related problems;

 

· the availability and cost of materialsand equipment;

 

· our dependence upon key personnel;

 

· our ability to find and retain skilledpersonnel;

 

· delays in anticipated start-up dates;

 

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

 

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

 

· our ability to effectively market ourproduction;

 

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

 

· general economicconditions.

 

When you consider theseforward-looking statements, you should keep in mind these factors and the otherfactors discussed under the “Risk Factors” sections of our annual report on Form 10-Kfor the year ended December 31, 2008 and this quarterly report on Form 10-Q.

 

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**PART I. FINANCIAL INFORMATION**

 

**ITEM 1. FINANCIAL STATEMENTS**

 

**PINNACLEGAS RESOURCES, INC.**

**BalanceSheets**

 
| ** **                                                                                                                                                                           | ** ** | **March 31,  2009**                                                       | ** ** | **December 31,  2008** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                                                                                                                           | ** ** | **(unaudited)**                                                                | ** ** | **(audited)**               | ** ** |
| ** **                                                                                                                                                                           | ** ** | **(in thousands, except  share and  per share data)** | ** ** |
| **Assets**                                                                                                                                                                           |       |                                                                           |       |                        |       |
| Current assets                                                                                                                                                                       |       |                                                                           |       |                        |       |
| Cash and cash  equivalents                                                                                                                                                           |       | $                                                                              | 111        |                        | $          | 346 |   |
| Receivables                                                                                                                                                                          |       |                                                                           |       |                        |       |
| Accrued gas  sales                                                                                                                                                                   |       | 804                                                                            |       | 2,091                       |       |
| Joint interest  receivables, net of $100 allowance for doubtful accounts                                                                                                             |       | 4,854                                                                          |       | 4,824                       |       |
| Derivative  instruments                                                                                                                                                              |       | 4,993                                                                          |       | 4,345                       |       |
| Inventory of  material for drilling and completion                                                                                                                                   |       | 84                                                                             |       | 83                          |       |
| Prepaid expenses                                                                                                                                                                     |       | 110                                                                            |       | 196                         |       |
| Total current  assets                                                                                                                                                                |       | 10,956                                                                         |       | 11,885                      |       |
| Property and  equipment, at cost, net of accumulated depreciation                                                                                                                    |       | 1,677                                                                          |       | 1,798                       |       |
| Oil and gas  properties, using full cost accounting, net of accumulated depletion and  impairment                                                                                    |       |                                                                           |       |                        |       |
| Proved                                                                                                                                                                               |       | 17,691                                                                         |       | 34,522                      |       |
| Unproved                                                                                                                                                                             |       | 85,806                                                                         |       | 86,827                      |       |
| Inventory of  material held for exploration and development                                                                                                                          |       | 388                                                                            |       | 384                         |       |
| Deposits                                                                                                                                                                             |       | 203                                                                            |       | 199                         |       |
| Restricted  certificates of deposit                                                                                                                                                  |       | 2,726                                                                          |       | 2,725                       |       |
| Total assets                                                                                                                                                                         |       | $                                                                              | 119,447    |                        | $          | 138,340 |   |
| **Liabilities and Stockholders’ Equity**                                                                                                                                        |       |                                                                           |       |                        |       |
| Current  liabilities                                                                                                                                                                 |       |                                                                           |       |                        |       |
| Long term  debt-current portion                                                                                                                                                      |       | $                                                                              | 10,530     |                        | $          | 11,530 |   |
| Trade accounts  payable                                                                                                                                                              |       | 10,416                                                                         |       | 10,112                      |       |
| Revenue  distribution payable                                                                                                                                                        |       | 3,332                                                                          |       | 4,625                       |       |
| Asset retirement  obligation, current                                                                                                                                                |       | 341                                                                            |       | 341                         |       |
| Accrued  liabilities                                                                                                                                                                 |       | 1,552                                                                          |       | 1,539                       |       |
| Total current  liabilities                                                                                                                                                           |       | 26,171                                                                         |       | 28,147                      |       |
| Asset retirement  obligations — non-current                                                                                                                                     |       | 3,081                                                                          |       | 3,025                       |       |
| Derivative  Instruments, non-current                                                                                                                                                 |       | 77                                                                             |       | —                      |       |
| Production  taxes, non-current                                                                                                                                                       |       | 1,424                                                                          |       | 1,156                       |       |
| Long term debt -  net of current portion                                                                                                                                             |       | 726                                                                            |       | 733                         |       |
| Total  liabilities                                                                                                                                                                   |       | 31,479                                                                         |       | 33,061                      |       |
| Commitments and  contingencies                                                                                                                                                       |       |                                                                           |       |                        |       |
| Stockholders’  equity                                                                                                                                                           |       |                                                                           |       |                        |       |
| Common stock,  $0.01 par value; 100,000,000 authorized and 29,188,009 and 29,193,573 shares  issued and outstanding at March 31, 2009 and December 31, 2008,  respectively |       | 289                                                                            |       | 289                         |       |
| Additional  paid-in capital                                                                                                                                                          |       | 151,078                                                                        |       | 150,879                     |       |
| Accumulated  deficit                                                                                                                                                                 |       | (63,399                                                                        | )          | (45,889                     | )          |
| Total  stockholders’ equity                                                                                                                                                     |       | 87,968                                                                         |       | 105,279                     |       |
| Total  liabilities and stockholders’ equity                                                                                                                                     |       | $                                                                              | 119,447    |                        | $          | 138,340 |   |

 

See Notes to Financial Statements (unaudited)

 

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**PINNACLEGAS RESOURCES, INC.**

**Statements of Operations**

**(unaudited)**

 
| ** **                                                    | ** ** | **Three Months Ended   March 31,**                             | ** ** |
|---------------------------------------------------------------|------------|------------------------------------------------------------------------------------|------------|
| ** **                                                    | ** ** | **2009**                                                                           | ** ** | **2008** | ** ** |
| ** **                                                    | ** ** | **(in thousands, except share and  per share data)** | ** ** |
| Revenues                                                      |       |                                                                               |       |   |   |
| Gas sales                                                     |       | $                                                                                  | 2,766      |   | $ | 5,661 |   |
| Total revenues                                                |       | 2,766                                                                              |       | 5,661 |   |
| Cost of revenues  and expenses                                |       |                                                                               |       |   |   |
| Lease operating  expenses                                     |       | 1,185                                                                              |       | 2,050 |   |
| Production taxes                                              |       | 279                                                                                |       | 660 |   |
| Marketing and  transportation                                 |       | 1,250                                                                              |       | 1,077 |   |
| General and  administrative, net                              |       | 1,031                                                                              |       | 1,373 |   |
| Depreciation,  depletion, amortization and accretion          |       | 1,828                                                                              |       | 1,728 |   |
| Impairment of  oil and gas properties                         |       | 16,819                                                                             |       | — |   |
| Total cost of  revenues and expenses                          |       | 22,392                                                                             |       | 6,888 |   |
| Operating loss                                                |       | (19,626                                                                            | )          | (1,227 | ) |
| Other income  (expense)                                       |       |                                                                               |       |   |   |
| Gain/(loss) on  derivatives                                   |       | 2,028                                                                              |       | (4,572 | ) |
| Interest income                                               |       | 8                                                                                  |       | 65 |   |
| Other income                                                  |       | 105                                                                                |       | 101 |   |
| Interest expense                                              |       | (25                                                                                | )          | (15 | ) |
| Total other  income/(loss)                                    |       | 2,116                                                                              |       | (4,421 | ) |
| Net loss before  income taxes                                 |       | (17,510                                                                            | )          | (5,648 | ) |
| Income taxes                                                  |       | —                                                                             |       | — |   |
| Net loss  attributable to common stockholders                 |       | (17,510                                                                            | )          | $ | (5,648 | ) |
| Basic and diluted  net loss per share                         |       | $                                                                                  | (0.60      | ) | $ | (0.19 | ) |
| Weighted average  shares outstanding — basic and diluted |       | 29,191,684                                                                         |       | 29,015,899 |   |

 

See Notes to Financial Statements (unaudited)

 

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**PINNACLE GAS RESOURCES, INC.Statements of Cash Flows**

 

**(unaudited)**

 
| ** **                                                                                | ** ** | **Three  Months Ended  March 31,** | ** ** |
|-------------------------------------------------------------------------------------------|------------|----------------------------------------------|------------|
| ** **                                                                                | ** ** | **2009**                                     | ** ** | **2008** | ** ** |
| Cash flows from  operating activities                                                     |       |                                         |       |   |   |
| Net loss                                                                                  |       | $                                            | (17,510    | ) | $ | (5,648 | ) |
| Adjustments to  reconcile net loss to net cash (used in)/provided by operating activities |       |                                         |       |   |   |
| Impairment of  oil and gas properties                                                     |       | 16,819                                       |       | — |   |
| Depreciation,  depletion, amortization and accretion                                      |       | 1,828                                        |       | 1,728 |   |
| Gain (loss) on  derivatives                                                               |       | (2,028                                       | )          | 4,572 |   |
| Stock-based  compensation                                                                 |       | 199                                          |       | 205 |   |
| Changes in  assets and liabilities                                                        |       |                                         |       |   |   |
| Decrease  (increase) in receivables                                                       |       | 1,257                                        |       | (2,477 | ) |
| Decrease  (increase) in inventory of material for drilling and completion                 |       | (1                                           | )          | 51 |   |
| Decrease  (increase) in prepaid expenses                                                  |       | 86                                           |       | (555 | ) |
| Increase in  trade accounts payable, accrued liabilities and production taxes             |       | 1,366                                        |       | 1,385 |   |
| Increase  (decrease) in revenue distribution payable                                      |       | (1,293                                       | )          | 1,543 |   |
| Net cash (used  in)/provided by operating activities                                      |       | 723                                          |       | 804 |   |
| Cash flows from  investing activities                                                     |       |                                         |       |   |   |
| Capital  expenditures — exploration and production                                   |       | (1,398                                       | )          | (5,026 | ) |
| Capital  expenditures — property and equipment                                       |       | (1                                           | )          | (205 | ) |
| Decrease  (increase) in purchase of restricted certificates of deposit and deposits       |       | (5                                           | )          | — |   |
| Decrease  (increase) in inventory held for exploration and development                    |       | (4                                           | )          | 153 |   |
| Realized gain  (loss) on derivatives                                                      |       | 1,457                                        |       | (93 | ) |
| Net cash  provided by/(used in) investing activities                                      |       | 49                                           |       | (5,171 | ) |
| Cash flows from  financing activities                                                     |       |                                         |       |   |   |
| Issuance costs  related to common stock                                                   |       | —                                       |       | (4 | ) |
| Principal  payments on long term debt                                                     |       | (1,007                                       | )          | (6 | ) |
| Net cash used in  financing activities                                                    |       | (1,007                                       | )          | (10 | ) |
| Net decrease in  cash and cash equivalents                                                |       | (235                                         | )          | (4,377 | ) |
| Cash and cash  equivalents at beginning of quarter                                        |       | 346                                          |       | 8,151 |   |
| Cash and cash  equivalents at end of quarter                                              |       | $                                            | 111        |   | $ | 3,774 |   |
| Noncash  investing and financing activities                                               |       |                                         |       |   |   |
| Capital  expenditures included in trade accounts payable                                  |       | $                                            | 6,951      |   | $ | 9,145 |   |
| Asset retirement  obligation included in oil and gas properties                           |       | —                                       |       | 101 |   |
| Supplemental  cash flow information                                                       |       |                                         |       |   |   |
| Cash payments  for interest, net of amount capitalized                                    |       | $                                            | 25         |   | $ | 15 |   |

 

See Notes to Financial Statements (unaudited)

 

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**Statements of Stockholders’ Equity**

 
| ** **                                  | ** ** | ** **            | ** ** | ** **  | ** ** | **Additional**  | ** ** | ** **  | ** ** | ** ** | ** ** |
|---------------------------------------------|------------|-----------------------|------------|-------------|------------|-----------------|------------|-------------|------------|------------|------------|
| ** **                                  | ** ** | **Common Stock** | ** ** | **Paid-In** | ** ** | **Accumulated** | ** ** | ** **  | ** ** |
| ** **                                  | ** ** | **Shares**            | ** ** | **Amount**  | ** ** | **Capital**     | ** ** | **Deficit** | ** ** | **Total**  | ** ** |
| ** **                                  | ** ** | ** **            | ** ** | ** **  | ** ** | ** **      | ** ** | ** **  | ** ** | ** ** | ** ** |
| Balance at  December 31, 2008          |       | 29,193,573            |       | $           | 289        |            | $          | 150,879     |       | $          | (45,889    | ) | $ | 105,279 |   |
| Forfeiture of  restricted shares            |       | (5,564                | )          |        |       |            |       |        |       |       |       |
| Stock-based  compensation                   |       |                  |       | —      |       | 199             |       | —      |       | 199        |       |
| Net loss                                    |       | —                |       | —      |       | —          |       | (17,510     | )          | (17,510    | )          |
|                                        |       |                  |       |        |       |            |       |        |       |       |       |   |   |   |   |
| Balance at  March 31, 2009 (unaudited) |       | 29,188,009            |       | $           | 289        |            | $          | 151,078     |       | $          | (63,399    | ) | $ | 87,968 |   |

 

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**Notes to Financial Statements**

**Unaudited**

 

**Note 1 —Organization and Nature of Operations**

 

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

 

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

 

Due to the current economic and pricing environment,the Company is actively marketing certain assets to raise additional capitaland is also reviewing alternatives for raising additional capital throughequity and debt financing, capital restructuring and possible mergers. TheCompany sold its high pressure gas gathering system in the Cabin Creek projectarea in Wyoming, and its remaining interest in the Arvada project area inWyoming in April 2009. The Company received approximately $3.2 million innet proceeds from these sales, and used part of such proceeds to repay aportion of its indebtedness outstanding under the credit facility and used theremainder for general operating purposes. The Company has also executedadditional hedges of its gas to secure certain operating cash flow levelsduring the remainder of 2009. From January through April 2009, theCompany had 4,500 MMbtu per day hedged through a combination of a fixed priceswap and a costless collar at a weighted average floor price of $6.87 per MMbtuand a ceiling price of $7.32 per MMbtu. From May through December 2009, the Company has 7,000 MMbtuper day hedged through a combination of a fixed price swap and a costlesscollar at a weighted average floor price of $5.65 per MMbtu and a ceiling priceof $5.93 per MMbtu. The Company has also implemented various cost cuttingmeasures, including reducing general and administrative costs through staffreductions, wage and benefit cuts and a hiring freeze. The Company has reducedlease operating expenses by renegotiating water disposal contracts, reducingservice costs and temporarily shutting-in marginal wells.

 

The Company continues to communicate with key vendorsto manage its obligations and payables. Management believes that appropriatesteps, including cost-cutting measures, are being taken to make operationssustainable in the future. Although the Company is pursuing variousalternatives to provide additional liquidity, there is no assurance of thelikelihood or timing of any of these transactions.

 

**Note 2 — Basis of Presentation**

 

The accompanyingunaudited financial statements include the Company’s proportionate share ofassets, liabilities, income and expenses from the properties in which theCompany has a participating interest. The Company has no subsidiaries or affiliates with which intercompanytransactions are recorded.

 

The accompanyingfinancial statements are unaudited, and in the opinion of management, reflectall adjustments that are necessary for a fair presentation of the financialposition and results of operations for the periods presented.  All such adjustments are of a normal andrecurring nature. The following Notes describe only the material changes inaccounting policies, account details, or financial statement Notes during thefirst three months of 2009.  The resultsfor the three months ending March 31, 2009 are not necessarily indicativeof the results expected for the entire year. These financial statements should be read in conjunction with theaudited financial statements and the summary of significant accounting policiesfor prior years contained in the reports the Company files with the Securitiesand Exchange Commission, which can be found on the Company’s website at *www.pinnaclegas.com*.

 

*Use of Estimates*

 

The preparation ofthe Company’s financial statements in conformity with accounting principlesgenerally accepted in the United States of America requires management to makeestimates and assumptions that affect the reported amount of assets andliabilities, disclosure of contingent assets and liabilities at the date of thefinancial statements and the reported amounts of revenues and expenses duringthe reporting period. Actual results could differ from these estimates.Significant estimates with regard to the Company’s financial statements includethe estimated carrying value of unproved properties, the estimate of proved oiland gas reserve volumes and the related present value of estimated future netcash flows, the ceiling test applied to capitalized oil and gas properties, theestimate of the timing and cost of the Company’s future drilling activity, theestimated cost and timing related to asset retirement obligations, theestimated fair value of derivative assets and liabilities, the realizability ofdeferred tax assets, the estimates of expenses and timing of exercise of stockoptions, accrual of operating costs and capital expenditures and revenue.

 

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*Oil and Gas Properties*

 

The Company utilizes the full cost method ofaccounting for oil and gas producing activities. Under this method, all costsassociated with property acquisition, exploration and development, includingcosts of unsuccessful exploration, costs of surrendered and abandonedleaseholds, delay lease rentals and the fair value of estimated future costs ofsite restoration, dismantlement and abandonment activities are capitalizedwithin a cost center. The Company’s oil and gas properties are all locatedwithin the United States, which constitutes a single cost center. The Companycapitalizes lease operating expenses associated with exploration and developmentof unevaluated oil and gas properties. No gain or loss is recognized upon thesale or abandonment of undeveloped or producing oil and gas properties unlessthe sale represents a significant portion of gas properties and the gainsignificantly alters the relationship between capitalized costs and proved gasreserves of the cost center. Expenditures for maintenance and repairs arecharged to lease operating expense in the period incurred.

 

Depreciation, depletion and amortization of oil andgas properties (“DD&A”) is computed on the unit-of-production method basedon proved reserves. Amortizable costs include estimates of future developmentcosts of proved undeveloped reserves and asset retirement obligations. TheCompany invests in unevaluated oil and gas properties for the purpose ofexploration for proved reserves. The costs of such assets, includingexploration costs on properties where a determination of whether proved oil andgas reserves will be established is still under evaluation, and any capitalizedinterest and lease operating expenses are included in unproved oil and gasproperties at the lower of cost or estimated fair market value and are notsubject to amortization. On a quarterly basis, such costs are evaluated forinclusion in the costs to be amortized resulting from the determination ofproved reserves, impairments, or reductions in value. To the extent that theevaluation indicates these properties are impaired, the amount of theimpairment is added to the capitalized costs to be amortized. Abandonment ofunproved properties is accounted for as an adjustment to capitalized costsrelated to proved oil and gas properties, with no losses recognized. TheCompany recorded an impairment of unevaluated properties of $0 million and $5.6million for the three months ended March 31, 2009 and year ended December 31,2008 respectively. Abandonment of unproved properties is also accounted for asan adjustment to capitalized costs related to proved oil and gas properties. Ifthe adjustment to capitalized costs related to proved oil and gas propertiesresults in the capitalized costs exceeding the full cost ceiling limitations,the excess must be charged to expense.

 

Substantially all of the remaining unproved propertiesare expected to be developed and included in the amortization base over thenext three to five years, based on projected cash flow from operations combinedwith the raising of additional capital. Salvage value is taken into account indetermining depletion rates and is based on the Company’s estimate of the valueof equipment and supplies at the time the well is abandoned. The estimatedsalvage value of equipment included in determining the depletion rate was $7.2million, and $6.7 million as of March 31, 2009, and 2008, respectively.

 

Under the full cost method of accounting rules,capitalized costs less accumulated depletion and related deferred income taxesmay not exceed a ‘‘ceiling’’ value which is the sum of (1) the presentvalue discounted at 10% of estimated future net revenue using current costs andprices, including the effects of derivative instruments designated as cash flowhedges but excluding the future cash outflows associated with settling assetretirement obligations that have been accrued on the balance sheet, less anyrelated income tax effects; plus (2) the cost of properties not beingamortized, if any; plus (3) the lower of costs or estimated fair value ofunproved properties; less (4) the income tax effects related todifferences in the book to tax basis of oil and gas properties. This isreferred to as the ‘‘full cost ceiling limitation.’’ If capitalized costsexceed the limit, the excess must be charged to expense. The expense may not bereversed in future periods. At the end of each quarter, the Company calculatesthe full cost ceiling limitation. At March 31, 2009, the capitalized costof the Company’s oil and gas properties exceeded the full cost ceilinglimitation by approximately $23.6 million based upon a natural gas price ofapproximately $2.52 per Mcf in effect at that date. Based on the subsequentprice increase to $3.31 per Mcf on May 12, 2009, the capitalized costexceeded the full cost ceiling limitation by $16.8 million. Therefore, animpairment of approximately $16.8 million was taken for the quarter ended March 31,2009.  This impairment of the Company’soil and gas properties resulted from low commodity prices in the first quarterof 2009.  No impairment was taken for thequarter ended March 31, 2008 based on a natural gas price of $8.01 perMcf.

 

*Per Share Information*

 

Basic earnings (loss) per share is computed bydividing net income (loss) from continuing operations attributable to commonstock by the weighted average number of shares of common stock outstandingduring each period. Diluted earnings per share is computed by adjusting theaverage number of shares of common stock outstanding for the dilutive effect,if any, of common stock equivalents such as stock options and warrants. Dilutednet loss per share is the same as basic net loss per share for all periodspresented because potential common stock equivalents were anti-dilutive. Forall periods in which there was a net loss attributable to stockholders, all ofthe Company’s stock options and warrants were anti-dilutive. Common

 

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stock equivalents of 645,000, and 750,000 at March 31,2009, and 2008, respectively, were excluded because they were anti-dilutive dueto the net loss attributable to stockholders incurred in such periods.

 

*Income Taxes*

 

The Company uses the asset and liability method ofaccounting for income taxes, in accordance with Statement of FinancialAccounting Standards (SFAS) No. 109, ‘‘Accounting for Income Taxes.’’Deferred tax assets and liabilities are recognized for the expected future taxconsequences of temporary differences between the financial statements and taxbasis of assets and liabilities. If appropriate, deferred tax assets are reducedby a valuation allowance which reflects expectations of the extent to whichsuch assets will be realized. As of March 31, 2009 and December 31,2008, the Company had recorded a full valuation allowance for its net deferredtax asset.

 

On January 1, 2007, the Company adopted FinancialAccounting Standards Board (FASB) Interpretation No. 48, ‘‘Accounting forUncertainty in Income Taxes—an interpretation of FASB Statement No. 109’’(FIN 48). FIN 48 prescribes a measurement process for recording in the financialstatements uncertain tax positions taken or expected to be taken in a taxreturn. FIN 48 requires that the Company recognize in its consolidatedfinancial statements only those tax positions that are ‘‘more-likely-than-not’’of being sustained as of the adoption date, based on the technical merits ofthe position. As a result of the implementation of FIN 48, the Companyperformed a comprehensive review of its material tax positions in accordancewith recognition and measurement standards established by FIN 48.

 

As a result of this review, the Company did notidentify any material deferred tax assets that required adjustment. As of March 31,2009 and 2008 the Company had not recorded any material uncertain tax benefits.

 

The Company’s policy is to recognize interest andpenalties related to uncertain tax benefits in income tax expense. As of March 31,2009, the Company had not recognized any interest or penalties in its statementof operations or statement of financial position.

 

The Company is subject to the following materialtaxing jurisdictions: U.S. federal. The Company also has material operations inthe 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 RevenueService are years 2005 through 2008. Due to the Company’s net operating losscarry forwards, the Internal Revenue Service may also adjust the amount of lossrealizable under examination back to 2003.

 

*New Accounting Pronouncements*

 

Effective January 1, 2008, the Company adoptedthe fair value measurement and disclosure provisions of SFAS No. 157, “Fair Value Measurements,” whichestablishes specific criteria for the fair value measurements of financial andnonfinancial assets and liabilities that are already subject to fair valuemeasurements under current accounting rules. SFAS No. 157 also requiresexpanded disclosures related to fair value measurements. In February 2008,the FASB approved FASB Staff Position (FSP) SFAS No. 157-2, “EffectiveDate of FASB Statement No. 157,” which allows companies to elect aone-year delay in applying SFAS No. 157 to certain fair valuemeasurements, primarily related to nonfinancial instruments. The Companyelected the delayed adoption date for the portions of SFAS No. 157impacted by FSP SFAS No. 157-2. The partial adoption of SFAS No. 157was prospective and did not have a significant effect on the Company’sfinancial statements. The Company does not expect that the application of thedeferred portion of SFAS No. 157 to the nonrecurring fair valuemeasurements of its nonfinancial assets and liabilities will have a materialimpact on the Company’s financial statements. In accordance with FSP SFAS No. 157-2,the fair value measurements for nonfinancial assets and liabilities was adoptedeffective for fiscal years beginning after November 15, 2008.

 

In October 2008, the FASB issued FSP SFAS No. 157-3,“Determining the Fair Value of a Financial Asset When the Market for That Assetis Not Active.” FSP SFAS No. 157-3 clarifies the application of SFAS No. 157,which the Company adopted as of January 1, 2008, in situations where themarket is not active. The Company has considered the guidance provided by FSPSFAS No. 157-3 in its determination of estimated fair values as of March 31,2009.

 

In April 2009, the Financial Accounting StandardsBoard issued FASB Staff Position (FSP) FAS 107-1 and APB 28-1 “InterimDisclosures about Fair Value of Financial Instruments,” which requiresdisclosures about fair value of financial instruments in interim reportingperiods. The FSP is effective for interim and annual periods ending after June 15,2009, with early adoption permitted for periods ending after March 15,2009. Adoption of this FSP is not expected to have a material impact on theCompany’s financial statements.

 

In April 2009, theFASB issued FSP No. 157-4, “DeterminingFair Value When the Volume and Level of Activity for the Asset or LiabilityHave Significantly Decreased and Identifying Transactions That Are Not Orderly”(“FSP FAS 157-4”),

 

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which provides additionalguidance for estimating fair value in accordance with SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”).  FSPFAS 157-4 is effective for the quarter ending June 30,2009.  The Company is currently evaluating this pronouncement and hasnot determined the impact, if any, that adoption will have on its financialstatements.

 

In December 2007, the FASB issued SFAS No. 141(R),‘‘Business Combinations,’’ which requires the acquiring entity in a businesscombination to recognize and measure all assets and liabilities assumed in thetransaction and any non-controlling interest in the acquiree at fair value asof the acquisition date. SFAS No. 141 (R) also establishes guidancefor the measurement of the acquirer shares issued in consideration for abusiness combination, the recognition of contingent consideration, theaccounting treatment pre-acquisition gain and loss contingencies, the treatmentof acquisition related transaction costs, and the recognition of changes in theacquirer’s income tax valuation allowance and deferred taxes. SFAS No. 141(R) iseffective for fiscal years beginning after December 15, 2008 and is to beapplied prospectively as of the beginning of the fiscal year in which thestatement is applied. Early adoption is not permitted. SFAS No. 141(R) iseffective for the Company beginning with the 2009 fiscal year. The impact ofthe adoption of SFAS No. 141(R) on Company’s financial statementswill largely be dependent on the size and nature of the business combinationscompleted after the adoption of this statement.

 

In March 2008, the FASB issued SFAS No. 161,“Disclosures about Derivative Instruments and Hedging Activities.” SFAS No. 161is intended to improve financial reporting by requiring transparency about thelocation and amounts of derivative instruments in an entity’s financialstatements, how derivative instruments and related hedged items are accountedfor under SFAS No. 133, “Accounting for Derivative Instruments and HedgingActivities,” and how derivative instruments and related hedged items affect itsfinancial position, financial performance and cash flows. SFAS No. 161 iseffective for financial statements issued for fiscal years and interim periodsbeginning after November 15, 2008. The adoption of this pronouncement hasnot had an impact on the Company’s financial statements, but it has requiredthe Company to expand its disclosures about derivative instruments.

 

On December 31, 2008, the Securities and ExchangeCommission (‘‘SEC’’) published the final rules and interpretationsupdating its oil and gas reporting requirements. Many of the revisions are updatesto definitions in the existing oil and gas rules to make them consistentwith the petroleum resource management system, which is a widely acceptedstandard for the management of petroleum resources that was developed byseveral industry organizations. Key revisions include changes to the pricingused to estimate reserves, the ability to include nontraditional resources inreserves, the use of new technology for determining reserves, and permittingdisclosure of probable and possible reserves. The SEC will require companies tocomply with the amended disclosure requirements for registration statementsfiled after January 1, 2010 and for annual reports for fiscal years endingon or after December 15, 2009. Early adoption is not permitted. TheCompany is currently assessing the impact that the adoption will have on theCompany’s disclosures, operating results, financial position, and cash flows.

 

**Note 3****— Asset Retirement Obligations**

 

The Company follows the provisions of Statement ofFinancial Accounting Standards (SFAS) No. 143, ‘‘Accounting for AssetRetirement Obligations.’’ SFAS No. 143 generally applies to legalobligations associated with the retirement of long-lived assets that resultfrom the acquisition, construction, development and/or normal operation of along-lived asset. SFAS No. 143 requires the Company  to recognize an estimated liability for costsassociated with the abandonment of its oil and gas properties.

 

A liability for the fair value of an asset retirementobligation with a corresponding increase to the carrying value of the relatedlong-lived asset is recorded at the time a well is completed or acquired. Theincreased carrying value is depleted using the units-of-production method, andthe discounted liability is increased through accretion over the remaining lifeof the respective oil and gas properties.

 

The estimatedliability is based on historical gas industry experience in abandoning wells,including estimated economic lives, external estimates as to the cost toabandon the wells in the future and federal and state regulatory requirements.The Company’s liability is discounted using the Company’s best estimate of itscredit-adjusted risk-free rate. The credit adjusted risk free rate is based onthe Company’s borrowing under its credit facility or, if borrowings are notavailable under the credit facility because of borrowing base or covenantlimitations, the rate is based on the interest rate available from its banksfor senior secured debt or mezzanine debt. Based on the Company’s currentinability to borrow under its credit facility, the Company’s credit adjustedrisk free rate at December 31, 2008 was the prime rate plus 7% or 10.25%.Revisions to the liability could occur due to changes in estimated abandonmentcosts, changes in well economic lives or if federal or state regulators enactnew requirements regarding the abandonment of wells. For the quarter ended March 31,2009, no wells were drilled, completed or acquired.

 

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The following is asummary of the Company’s asset retirement obligation activity for the threemonths ended March 31, 2009 and 2008 (in thousands):

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

 

**Note 4****— Restricted Assets (Certificates of Deposit) and Deposits**

 

*Certificates of Deposit.*

 

The Company holds acertificate of deposit (“CD”), which expires in July 2009, totaling$158,000. The CD is collateral on bonding required by the State of Wyoming, theState of Montana and the Federal Bureau of Land Management. Because the Companyintends to renew the CD in order to maintain its bonding requirements, theCompany has included the CD in other non-current assets as of March 31,2009. Additionally, the Company holds two CDs for $604,000 and $964,000 whichwere issued in February 2006 and expire in February 2010 and May 2009,respectively. These CDs collateralize letters of credit in favor of PowderRiver Energy Corporation, a local rural electric association, in order tosecure power lines to the Kirby, Deer Creek and Cabin Creek areas. The Companyhas included these amounts in non-current assets as of March 31, 2009because the Company also intends to renew the CDs in order to maintain powersupply on a long-term basis. In April 2007, the Company issued a$1,000,000 letter of credit that expires in April 2010 in favor of BitterCreek Pipelines, LLC to secure the construction of a high pressure pipeline andrelated compression facilities to the Company’s Deer Creek and Kirby areas. TheCompany has included this amount in non-current assets as of March 31,2009  because the pipeline andcompression facilities are not expected to be completed and fully utilizeduntil the end of 2010.

 

*Deposits.*

 

The Company has included approximately $193,000related to royalty payments in deposits. These amounts are included in Depositsin the accompanying balance sheet at March 31, 2009.

 

**Note 5 — Derivatives**

 

The Company haselected not to designate its derivatives as cash flow hedges under provisionsof SFAS No. 133. These derivative instruments are marked to market at theend of each reporting period and changes in the fair value are recorded in theaccompanying statements of operations. The aggregate fair values of thesecontracts were estimated to be assets totaling $4,916,000 and a liability of$3,923,000 at March 31, 2009 and 2008, respectively. The Company realizeda hedging gain of $1,457,000 and a hedging loss of $93,000 for the quartersended March 31, 2009 and 2008, respectively.  As a result of the change in the fair valueof the commodity derivatives, the Company had an unrealized gain of $571,000for the quarter ended March 31, 2009 and unrealized loss of $4,479,000 forthe quarter ended March 31, 2008. Unrealized and realized gains and lossesare included in gains or losses on derivatives in the statement of operations.As of March 31, 2009 and 2008, the Company had natural gas hedges in placeas follows:

 
| **Product and Type of Hedging Contract** | ** ** | **MMbtu Per  Day** | ** ** | **Fixed Price  Range  CIG Index Price** | ** ** | **Time  Period** | ** **  |
|-------------------------------------------------------------------|------------|-------------------------|------------|--------------------------------------------------------|------------|------------------|-------------|
| March 31,  2009 (unaudited)                                  |       |                    |       |                                                   |       |             |        |
| Natural  Gas—Collar                                          |       | 2,000                   |       | $                                                      | 6.50-$7.50 |             | 01/09-12/09 |   |
| Natural Gas—Swap                                             |       | 2,500                   |       | $                                                      | 7.17       |             | 01/09-12/09 |   |
| Natural Gas—Swap                                             |       | 2,500                   |       | $                                                      | 3.45       |             | 05/09-04/10 |   |
| Natural Gas—Swap                                             |       | 2,000                   |       | $                                                      | 4.48       |             | 01/10-12/10 |   |
| March 31,  2008 (unaudited)                                  |       |                    |       |                                                   |       |             |        |
| Natural Gas—Swap                                             |       | 2,500                   |       | $                                                      | 6.63       |             | 02/08-12/08 |   |
| Natural  Gas—Collar                                          |       | 2,000                   |       | $                                                      | 6.50-$7.50 |             | 01/09-12/09 |   |
| Natural Gas—Swap                                             |       | 1,500                   |       | $                                                      | 7.44       |             | 03/08-12/08 |   |
| Natural Gas—Swap                                             |       | 2,500                   |       | $                                                      | 7.17       |             | 01/09-12/09 |   |
| Natural  Gas—Collar                                          |       | 3,000                   |       | $                                                      | 6.50-$8.20 |             | 01/08-12/08 |   |

 

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The Company isexposed to credit risk to the extent of nonperformance by the counterparties inthe derivative contracts discussed above; however, the Company does notanticipate such nonperformance.

 

**Note 6 — Stock Based Compensation**

 

*Options under Employee Option Plans*

 

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

 

Options granted under the plan become vested asdirected by the Company’s Board of Directors and generally expire seven or tenyears after the date of grant, unless the option holder owns more than 10% ofthe total combined voting power of all classes of the Company’s stock, in whichcase the non-statutory stock options must be exercised within five years of thedate of grant. At March 31, 2009, there were options to purchase 645,000shares granted under the plan.

 

The options granted sinceformation in June 2003 vest as follows:

 
| Year 1 |   | 20  | % |
|--------|--------|-----|---|
| Year 2 |   | 30  | % |
| Year 3 |   | 50  | % |
|   |   | 100 | % |

 

At March 31, 2009,the Company had unvested options to purchase 70,000 shares with a weightedaverage grant date fair value of $189,000. During the three months ended March 31,2009, the Company did not grant any options to purchase common stock. The Companywill recognize compensation expense relating to nonvested options granted afterJanuary 1, 2007 ratably over the next three years. The Company recognizedan expense of approximately $121,000 for the three months ended March 31,2009, based on the fair value of the vested options.

 

The followingtable summarizes stock option activity for the three months ended March 31,2009:

 
| ** **                                    | ** ** | **Number of  Shares** | ** ** | **Weighted Average  Exercise Price  Per Share** | ** ** | **Weighted  Average  Remaining  Contractual Life** | ** ** | **Aggregate  Intrinsic value** | ** ** |
|-----------------------------------------------|------------|----------------------------|------------|----------------------------------------------------------------|------------|---------------------------------------------------------|------------|-------------------------------------|------------|
| Outstanding,  December 31, 2008          |       | 676,250                    |       | $                                                              | 5.93       |                                                    |       |                                |       |   |
| Canceled or  forfeited                        |       | (31,250                    | )          | 8.52                                                           |       |                                                    |       |                                |       |
|                                          |       |                       |       |                                                           |       |                                                    |       |                                |       |
| Outstanding,  March 31, 2009 (unaudited) |       | 645,000                    |       | $                                                              | 5.80       |                                                    | 3.08       |                                | $          | — |   |
|                                          |       |                       |       |                                                           |       |                                                    |       |                                |       |
| Exercisable,  March 31, 2009 (unaudited) |       | 575,000                    |       | $                                                              | 5.26       |                                                    | 2.91       |                                | $          | — |   |

 

The following table summarizes information about stockoptions outstanding at March 31, 2009:

 
| ** **               | ** ** | **Options Outstanding**            | ** ** | **Options Exercisable**                            | ** ** | ** **              | ** ** |
|--------------------------|------------|-----------------------------------------|------------|---------------------------------------------------------|------------|-------------------------|------------|
| **Exercise Prices** | ** ** | **Number of  Shares  Outstanding** | ** ** | **Weighted  Average  Remaining  Contractual Life** | ** ** | **Number  Exercisable** | ** ** | **Weighted  Average  Exercise Price** | ** ** | **Fair Value  Determination** | ** ** |
| $4.00                    |       | 137,500                                 |       | 1.5 years                                               |       | 137,500                 |       | $ | 4.00 |   | Black-Scholes |   |
|                     |       |                                    |       |                                                    |       |                    |       |   |   | (minimum value) |   |
| $4.80                    |       | 270,000                                 |       | 3.0 years                                               |       | 270,000                 |       | $ | 4.80 |   | Black-Scholes |   |
|                     |       |                                    |       |                                                    |       |                    |       |   |   | (minimum value) |   |
| $5.20                    |       | 112,500                                 |       | 3.8 years                                               |       | 112,500                 |       | $ | 5.20 |   | Black-Scholes |   |
| $8.40                    |       | 25,000                                  |       | 5.2 years                                               |       | 5,000                   |       | $ | 8.40 |   | Black-Scholes |   |
| $11.00                   |       | 100,000                                 |       | 4.2 years                                               |       | 50,000                  |       | $ | 11.00 |   | Black-Scholes |   |
|                     |       | 645,000                                 |       |                                                    |       | 575,000                 |       |   |   |   |   |

 

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*RestrictedStock*

 

The Company has an incentive program whereby grants ofrestricted stock have been awarded to members of the Board of Directors andcertain employees. Restrictions and vesting periods for the awards aredetermined at the discretion of the Board of Directors and are set forth in theaward agreements.

 

The Company recognized acompensation expense of approximately $78,000 for the quarter ended March 31,2009 based on the fair value of the vested shares during that period.

 

A summary of the status and activity of the restrictedstock for the three months ended March 31, 2009 is presented   below.

 
| ** **                          | ** ** | **Shares** | ** ** | **Weighted Average  Grant Date  Fair Value** | ** ** |
|-------------------------------------|------------|------------|------------|---------------------------------------------------|------------|
| Unvested at December 31,  2008 |       | 203,577    |       | $                                                 | 4.78       |   |
| Forfeited                           |       | (5,564     | )          | $                                                 | 6.05       |   |
| Vested                              |       | (1,500     | )          | $                                                 | 11.00      |   |
| Unvested at  March 31, 2009    |       | 196,513    |       | $                                                 | 4.70       |   |

 

As of March 31,2009, the Company had approximately $0.8 million of unrecognized share-basedcompensation expense related to unvested stock awards, which is expected to beamortized over the remaining vesting periods of three to four years.

 

**Note 7 —Line of Credit and Long Term Debt**

 

*CreditFacility*

 

Effective February 12,2007, the Company entered into a credit facility which permits borrowings up tothe borrowing base as designated by the administrative agent. As of March 31,2009 and December 31, 2008, the Company had $11.5 million and $10.5million, respectively, of debt outstanding under the facility. As described below,the Company is currently unable to borrow additional amounts under the creditfacility due to covenant and borrowing base limitations and may be furtherlimited in the future based on borrowing base limitations.

 

As of December 31,2008, the borrowing base under the credit facility was approximately $13.2million. The borrowing base was subject to automatic reductions ofapproximately $666,667 per month until it reached $10.5 million on April 1,2009. As of April 14, 2009, the Company’s borrowing base was reduced to$9.0 million, subject to automatic reductions of $500,000 per month until itreaches $6.5 million on October 1, 2009, where it will remain until thenext borrowing base redetermination. If natural gas prices do not improve, theCompany expects that its borrowing base could be further reduced in thefuture.  At May 15, 2009, theCompany’s debt outstanding under the credit facility was $9.0 million.

 

The borrowing base isdetermined on a semi-annual basis and at such other additional times, up totwice yearly, as may be requested by either the Company or the administrativeagent. The borrowing base is determined by the administrative agent inaccordance with customary practices and standards for loans of a similarnature, although such determination is at the administrative agent’s discretionas the credit agreement does not provide a specific borrowing base formula.

 

Borrowings under thiscredit facility may be used solely to acquire, explore or develop oil and gasproperties and for general corporate purposes. The credit facility matures February 12,2011.

 

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

 

Borrowings under theCompany’s credit facility, as amended, bear interest either: (i) at thegreater of the one month London Interbank Offered Rate, or LIBOR, plus 1.00% ora domestic bank rate, plus in either case an applicable margin of 0.75% to1.75% 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 onutilization.  The credit agreementprovides for various fees, including a quarterly commitment fee of 0.5% perannum and engineering fees to the administrative agent in connection with theborrowing base determination.  Inaddition, the credit facility provided for an up front fee of $27,000, whichwas paid on the closing date of the credit facility, and an additionalarrangement fee of 1% based on utilization. Borrowings under this credit facility may be prepaid without premium orpenalty, except on Eurodollar advances.

 

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The credit agreement, asamended contains covenants that, among other things, restrict the Company’sability, (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 andasset 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 hedgingarrangements, the credit agreement provides that acceptable commodity hedgingarrangements cannot be greater than 80 to 85%, depending on the measurementdate, of the Company’s monthly production from its hydrocarbon properties thatare used in the borrowing base determination and that the fixed or floor priceof the Company’s hedging arrangements must be equal to or greater than the gasprice used by the lenders in determining the borrowing base.

 

The credit agreement, asamended, also requires that the Company satisfy certain affirmative covenants,meet certain financial tests, maintain certain financial ratios and makecertain customary indemnifications to lenders and the administrative agent. Thefinancial covenants include requirements to maintain: (i) a ratio ofEBITDA to cash interest expense of not less than 3.00 to 1.00, (ii) aratio of current assets to current liabilities of not less than 1.00 to 1.00, (iii) atotal debt to annualized EBITDA ratio of not more than 3.0 to 1.0, (iv) aquarterly total senior debt to annualized EBITDA ratio equal to or less than3.0 to 1.0, and (v) a total proved PV-10 value to total debt ratio of atleast 1.50 to 1.00.

 

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

 

After an event of default, the outstanding debt bearsinterest at the default rate under the terms of the credit agreement. Thedefault rate is (i) with respect to principal, 2% over the otherwiseapplicable 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 payableon demand. Failure to pay the default interest when the administrative agentdemands would be another default. The lenders’ remedies for defaults under thecredit agreement are to terminate further borrowings, accelerate the repaymentof indebtedness and/or ultimately foreclose on the collateral property.

 

On April 14, 2009, the Company and theadministrative agent entered into the fourth amendment to the credit agreementwhich reduced the borrowing base as described above and waived compliance withthe current ratio financial covenant as of December 31, 2008 and March 31,2009 and with the restrictive covenants related to accounts payable, permittedliens and permitted debt until the next borrowing base redetermination, subjectto certain financial caps. The Company believes that it may not be incompliance with the current ratio financial covenant and certain other covenantsthroughout 2009, but management anticipates receiving waivers in the futurebased on prior dealings with the lender and continued compliance with theborrowing base limitations. There can be no assurance that the Company will beable to obtain such waivers or that such waivers will be obtained on acceptableterms. If the Company is unable to obtain future waivers and/or comply with therestrictive covenants and are therefore in default, the lenders could availthemselves of the remedies under the credit agreement, including accelerationand foreclosure.

 

*Office Building Loan*

 

On November 15,2005, the Company entered into a mortgage loan secured by its office buildingin Sheridan, Wyoming in the aggregate principal amount of $829,000. Thepromissory note provides for monthly payments of principal and interest in theinitial amount of $6,400, and unpaid principal that bore interest at 6.875%during the first three years, currently bears interest at a variable base rateplus 0.5%  and will bear interest at 18%upon a default. The variable base rate is based on

 

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the lender’s base rate.The maturity date of this mortgage is November 15, 2015, at which time aprincipal and interest payment of $531,300 will become due. As of March 31,2009, the Company had $756,000 outstanding in principal and interest on thismortgage.  On November 15, 2008, theinterest rate on the Company’s mortgage loan changed from a fixed rate of6.875% to a variable rate. As of March 31, 2009, the variable rate was4.75%.

 

**Note 8 —Fair Value Measurements**

 

          Effective January 1, 2008, the Company adopted SFAS No. 157,“Fair Value Measurements” for all financial assets and liabilities measured atfair value on a recurring basis. The statement establishes a framework formeasuring fair value and requires enhanced disclosures about fair valuemeasurements. SFAS No. 157 defines fair value as the price that would bereceived to sell an asset or paid to transfer a liability (an exit price) in anorderly transaction between market participants at the measurement date. Thestatement establishes market or observable inputs as the preferred sources ofvalues, followed by assumptions based on hypothetical transactions in theabsence of market inputs. The statement establishes a hierarchy for groupingthese assets and liabilities, based on the significance level of the followinginputs:

 

·**               **Level 1 — Quoted prices in active markets foridentical assets or liabilities;

 

·**               **Level 2 —Quoted prices in active markets for similarassets and liabilities, quoted prices for identical or similar instruments inmarkets that are not active, and model-derived valuations whose inputs areobservable or whose significant value drivers are observable;

 

·**    **Level3 —Significant inputs to the valuation model are unobservable.

 

The following is alisting of the Company’s assets and liabilities required to be measured at fairvalue on a recurring basis and where they are classified within the hierarchyas of March 31, 2009 (in thousands):

 
| ** **                          | ** ** | **Level 1** | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** ** |
|-------------------------------------|------------|-------------|------------|-------------|------------|-------------|------------|-----------|------------|
| Assets                              |       |        |       |        |       |        |       |      |       |
| Oil and gas  derivative instruments |       | $           | —     |        | $          | 4,993       |       | $         | —     |   | $ | 4,993 |   |
| Liabilities                         |       |        |       |        |       |        |       |      |       |
| Oil and gas  derivative instruments |       | $           | —     |        | $          | (77         | )          | $         | —     |   | $ | (77 | ) |
| Total                               |       | $           | —     |        | $          | 4,916       |       | $         | —     |   | $ | 4,916 |   |

 

A financial asset orliability is categorized within the hierarchy based upon the lowest level ofinput that is significant to the fair value measurement. The Company’svaluation methodologies for oil and gas derivative instruments, which aremeasured at fair value and are included in the accompanying balance sheet, arelisted below.

 

The Company uses Level 2inputs to measure the fair value of oil and gas derivative instruments. Thefair value is based on interpolated data. The Company uses an industry standardmodel that considers various inputs including; (a) quoted forward pricesfor the specific commodity and area which was hedged, (b) volatilityfactors with consistent time data that correlates to the remaining life of thederivative instruments and (c) time value. The Company believes that thisapproach provides a reasonable, non-biased and consistent methodology forvaluing oil and gas derivative instruments. In addition, the Company alsoevaluates company credit risk and counterparty credit risk to determine fairvalue of the asset or liability and further action as needed.

 

**Note 9 —Commitments and Contingencies**

 

*OperatingLease*

 

Upon purchase of itsbuilding in August 2005, the Company was assigned the lease agreements forexisting tenants in the building. The leases expire from January 2010 to December 2013.Future minimum lease income under noncancelable operating leases is as follows:

 
| **Year  Ending December 31:** | ** ** | ** ** | ** ** |
|------------------------------------|------------|------------|------------|
| 2009                               |       | $          | 108,000    |   |
| 2010                               |       | 60,000     |       |
| 2011                               |       | 60,000     |       |
| 2012                               |       | 60,000     |       |
| 2013                               |       | 60,000     |       |
| Total minimum  lease payments      |       | $          | 348,000    |   |

 

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*Gas Gathering Contracts*

 

The Company has enteredinto gas gathering and compression agreements with service providers in orderto compress and transport its gas to the point of sale. Compression agreementsand gathering agreements are based on a fee per Mcf either compressed orgathered. The Company accounts for these fees as a marketing and transportationexpense. The Company does not pay or charge marketing fees associated with themovement and sale of natural gas.

 

*Employment Agreements*

 

The Company entered intonew employment agreements with the Chief Executive Officer (Mr. Schoonmaker)and Chief Financial Officer (Mr. Barnes) on July 20, 2007, effective January 1,2007. The initial term of these agreements is one year and the agreements willautomatically renew for additional one-year terms unless either party gives 60days prior written notice. Under Mr. Schoonmaker’s employment agreement,he is entitled to an initial base salary of $250,000, subject to annual adjustment,and an annual bonus of up to 1.0 times his then current base salary, payable incash or in stock. Under Mr. Barnes’ employment agreement, he is entitledto an initial base salary of $200,000, subject to annual adjustment, and anannual bonus of up to 0.75 times his then current base salary, payable in cashor in stock.

 

If eitherexecutive’s employment is terminated by the Company without cause or by eitherexecutive for good reason, the executive will be entitled to severance benefitswhich will include a lump sum payment equal to the sum of (i) 1.0 timeshis annual base salary plus (ii) 18.0 times the monthly health savingsaccount contribution last made by us for his benefit, and the payment of apro-rated bonus. Additionally, if either executive’s employment is terminatedby us without cause or by either executive for good reason or due toretirement, in each case within one year following a change of control of us,the executive will be entitled to severance benefits which will include a lumpsum payment equal to 1.5 times his annual base salary and the payment of apro-rated bonus. In each case, any and all stock options, restricted stockawards and other equity compensation awards held by the executive willimmediately vest and become exercisable. In the event that either executive’semployment is terminated within six months preceding or following a change ofcontrol due to a non-renewal of his employment agreement by us, the executivewill be entitled to the same change of control severance benefit describedabove.

 

*Litigation*

 

From time to time,the Company is subject to legal proceedings and claims that arise in theordinary course of its business. In addition, like other natural gas and oilproducers and marketers, the Company’s operations are subject to extensive andrapidly changing federal and state environmental, health and safety and otherlaws and regulations governing air emissions, wastewater discharges, and solidand hazardous waste management activities. As a result, it is extremelydifficult to reasonably quantify future environmental and regulatory relatedexpenditures.

 

The followingrepresent legal actions in which the Company is involved. No assurance can begiven 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’sbusiness, financial position or results of operations.

 

The Company,together with the State of Montana, the Montana Department of EnvironmentalQuality, the Montana Board of Oil and Gas Conservation and the Department ofNatural 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, BighornCounty by Diamond Cross Properties, LLC relating to the Coal Creek POD. Theplaintiff is a surface owner with properties located in Big Horn County andRosebud County, Montana where the Company has a lease for approximately 10,300acres, serves as operator and owns a working interest in the minerals underlease. The plaintiff sought to permanently enjoin the State of Montana and itsadministrative bodies from issuing licenses or permits, or authorizing theremoval of ground water from under the plaintiff’s ranch. In addition, theplaintiff further sought to preliminarily and permanently enjoin the Company onthe basis that the Company’s operations lacked adequate safeguards requiredunder the Montana state constitution. On August 25, 2005, the districtjudge issued an order denying without prejudice the application for temporaryrestraining order and preliminary injunction requested by the plaintiff. Thecase 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 CoalCreek POD, and subsequently, the Montana Supreme Court remanded the case backto the district court for a decision on the merits.

 

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

 

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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 June 2005,the U.S. Bureau of Land Management in Miles City, Montana issued suspensions ofoperations for the majority of our federal leases in Montana. The suspensionswere 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 SupplementalEnvironmental Impact Statement (SEIS) to address phased development of coal bednatural 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 productionprojects in the Powder River Basin of Montana. Both of these actions placedlimitations on lease development until completion of the SEIS.

 

The 2005injunction 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 ofOperations and Production for the suspended leases was terminated effective February 1,2009. We have received letters from the BLM with amended lease terms of theaffected leases. Leases that were suspended will be placed back into an activelease status with the primary term increasing for approximately three to fiveyears based on the time period the leases were in suspension.

 

*Regulations*

 

The Company’s oil and gasoperations are subject to various federal, state and local laws andregulations. The Company could incur significant expense to comply with the newor existing laws and non-compliance could have a material adverse effect on theCompany’s operations. In December 2007, the U.S. Bureau of Land Managementimposed a permitting application fee of $4,000 per well drilled on federallands.

 

*Environmental*

 

The Companyproduces significant amounts of water from its wells. If future wells producewater of a lesser quality than allowed under state laws or if water is producedat rates greater than the Company can dispose of, the Company could incuradditional costs to dispose of the water.

 

**Note 10— Recent Developments**

 

The Company and theadministrative agent under its credit agreement entered into the fourthamendment to the credit agreement on April 14, 2009. The fourth amendmentreduced the borrowing base under the credit agreement and waived compliancewith the current ratio covenant as of December 31, 2008 and March 31,2009, and with certain other restrictive covenants related to overdue accountspayable, permitted liens and permitted debt until the next borrowing baseredetermination, which is expected in the fall of 2009, subject to certainfinancial caps.

 

In April 2009, theCompany sold its interest in approximately 800 net undeveloped acres in theArvada prospect in Wyoming to an unrelated third party and sold certain of itsgas gathering assets in the Cabin Creek area of Wyoming to Big Horn GasGathering, L.L.C., the field operator of the assets. The Company’s aggregatenet proceeds from these transactions were approximately $3.2 million. TheCompany used part of these proceeds to repay the Company’s outstandingindebtedness under its credit facility to $9.0 million as of April 14,2009.

 

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**ITEM2. MANAGEMENT’S DISCUSSION ANDANALYSIS OF FINANCIAL CONDITION AND RESULTS****OF OPERATIONS**

 

*Thediscussion and analysis that follows should be read together with theaccompanying financial statements and notes related thereto that are includedelsewhere in this quarterly report on Form 10-Q. It includesforward-looking statements that may reflect our estimates, beliefs, plans andexpected performance. The forward-looking statements are based upon events,risks and uncertainties that may be outside our control. Our actual resultscould differ significantly from those discussed in these forward-lookingstatements. Factors that could cause or contribute to these differencesinclude, 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 andother uncertainties, as well as those factors discussed below and elsewhere inthis quarterly report on Form 10-Q and in our annual report on Form 10-Kfor the year ended December 31, 2008, including in “Risk Factors” and “CautionaryStatement Concerning Forward-Looking Statements,” all of which are difficult topredict. As a result of these assumptions, risks and uncertainties, theforward-looking matters discussed may not occur.*

 

**Overview**

 

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

 

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

 

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

 

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

 

**Economic and Natural Gas Pricing Environment**

 

During 2008, the global economy experienced asignificant downturn. The downturn, which began over concerns related to theU.S. financial markets, spread to other industries, including the energyindustry. The initial effects of the downturn restricted the capital and creditmarkets to a degree that has not been seen in a number of decades in the UnitedStates. We have been able to partially mitigate the constraints imposed by thecurrent economic climate through utilization of our credit facility and cashflows from operations.

 

The fear of global recession led to an immediate dropin demand for natural gas, primarily by industrial users, which in turn led toa significant reduction in natural gas prices. The natural gas index price inthe Rocky Mountain region averaged $7.84 per Mcf for the first eight months of2008 but only $3.15 per Mcf for the last four months of 2008. For the first quarterof 2009, the price averaged $3.28 per Mcf. This decrease in price has caused usto reevaluate our 2009 business plan. We have curtailed drilling, except forwells that will hold significant blocks of acreage, and have also reducedadministrative, operating and transportation costs. Even with cost reductionsand a flexible capital spending budget, the current natural gas pricing andeconomic environment remains challenging. We are exploring strategicalternatives to increase our capital resources.

 

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**Credit Facility and Liquidity**

 

OnApril 14, 2009, we and the lenders entered into the fourth amendment tothe credit facility which waived compliance with the current ratio financialcovenant as of December 31, 2008 and March 31, 2009 and with therestrictive covenants related to accounts payable, permitted liens andpermitted debt until the next borrowing base redetermination expected in thefall of 2009, subject to certain financial caps.  In connection with the waiver of therestrictive covenants, the lenders reduced our borrowing base to$9.0 million as of April 14, 2009, with further monthly reductionsuntil the borrowing base reaches $6.5 million on October 1,2009.  We believe that we may not be incompliance with the current ratio financial covenant and certain othercovenants throughout 2009, but management anticipates receiving waivers in thefuture based on prior dealings with the lender and continued compliance withthe borrowing base limitations. There can be no assurance that we will be ableto obtain such waivers or that such waivers will be obtained on acceptableterms.  If we are unable to obtain futurewaivers and/or to comply with the covenants, the lenders could accelerate ourindebtedness under the credit facility or foreclose on properties held byliens.  We have remained in compliancewith the payment of principal and interest pertaining to the credit facilityincluding ensuring that our outstanding borrowings remain within thelimitations of the borrowing base.  Dueto borrowing base limitations and waiver stipulations, we are currently unableto incur additional indebtedness under the credit facility and may be furtherlimited in the future. Please see “—Liquidity and Capital Resources—CreditFacility” for further information regarding our credit facility, borrowing baseand the covenant limitations.

 

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

 

Due to the currenteconomic and pricing environment and our liquidity position, we are activelymarketing certain assets to raise additional capital and are also reviewingalternatives for raising additional capital through equity and debt financing,capital restructuring and possible mergers. We sold our high pressure gasgathering system in the Cabin Creek project area in Wyoming and our remaininginterest in the Arvada project area in Wyoming in April 2009. We receivedapproximately $3.2 million in net proceeds from these sales, and used part ofsuch proceeds to repay a portion of the indebtedness outstanding under ourcredit facility and for general operating purposes. We also put additionalhedges of our natural gas production in place to secure certain operating cashflow levels during the remainder of 2009. From January through April 2009,we had 4,500 MMbtu per day hedged through a combination of a fixed price swapand a costless collar at a weighted average floor price of $6.87 per MMbtu anda ceiling price of $7.32 per MMbtu. From May through December 2009,we have 7,000 MMbtu per day hedged through a combination of a fixed price swapand a costless collar at a weighted average floor price of $5.65 per MMbtu anda ceiling price of $5.93 per MMbtu.

 

We have also implementedvarious cost cutting measures, including reducing general and administrativecosts through staff reductions, wage and benefit cuts and a hiring freeze. Wehave reduced lease operating expenses by renegotiating water disposalcontracts, reducing service costs and temporarily shutting-in marginal wells.We continue to communicate with key vendors to manage our obligations andpayables. Management believes that appropriate steps, including cost-cuttingmeasures, 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.

 

**CriticalAccounting Policies**

 

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

 

·                  Reserve evaluation anddetermination;

 

·                  Estimates of the timing and cost ofour future drilling activity;

 

·                  Estimates of the fair valuation ofhedges in place;

 

·                  Estimates of timing and cost ofasset retirement obligations;

 

·                  Estimates of the expense and timingof exercise of stock options;

 

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

 

·                  Estimates forlitigation

 

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***Oil and Gas Properties***

 

We use the full costmethod 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 abandonedleaseholds, delay lease rentals and the fair value of estimated future costs ofsite restoration, dismantlement and abandonment activities, are capitalizedwithin a cost center. Our oil and gas properties are all located within theUnited States, which constitutes a single cost center. We capitalize certainlease operating expenses associated with exploration and development ofunevaluated oil and gas properties. No gain or loss is recognized upon the saleor abandonment of undeveloped or producing oil and gas properties unless thesale represents a significant portion of gas properties and the gainsignificantly alters the relationship between capitalized costs and proved gasreserves of the cost center. Expenditures for maintenance and repairs arecharged to lease operating expense in the period incurred.

 

Depreciation, depletionand amortization of oil and gas properties is computed on theunit-of-production method based on proved reserves. Amortizable costs includeestimates of future development costs of proved undeveloped reserves and assetretirement obligations. We invest in unevaluated oil and gas properties for thepurpose of exploration for proved reserves. The costs of such assets, includingexploration costs on properties where a determination of whether proved oil andgas reserves will be established is still under evaluation, and any capitalizedinterest and lease operating expenses, are included in unproved oil and gasproperties at the lower of cost or estimated fair market value and are notsubject to amortization. On a quarterly basis, such costs are evaluated forinclusion in the costs to be amortized resulting from the determination ofproved reserves, impairments, or reductions in value. To the extent that theevaluation indicates these properties are impaired, the amount of theimpairment is added to the capitalized costs to be amortized. We recorded animpairment of unevaluated properties of $0 million and $5.6 millionduring the three months ended March 31, 2009 and year ended December 31,2008, respectively. Abandonment of unproved properties is also accounted for asan adjustment to capitalized costs related to proved oil and gasproperties.  If the adjustment tocapitalized costs related to proved oil and gas properties results in thecapitalized costs exceeding the full cost ceiling limitations, the excess mustbe charged to expense.

 

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

 

Under the full costmethod of accounting rules, capitalized costs less accumulated depletion andrelated deferred income taxes may not exceed a “ceiling” value which is the sumof (1) the present value discounted at 10% of estimated future net revenueusing current costs and prices, including the effects of derivative instrumentsdesignated as cash flow hedges but excluding the future cash outflowsassociated with settling asset retirement obligations that have been accrued onthe balance sheet, less any related income tax effects; plus (2) the costof properties not being amortized, if any; plus (3) the lower of costs orestimated fair value of unproved properties; less (4) the income taxeffects related to differences in the book to tax basis of oil and gasproperties. This is referred to as the “full cost ceiling limitation.” Ifcapitalized costs exceed the limit, the excess must be charged to expense. Theexpense may not be reversed in future periods. At the end of each quarter, wecalculate the full cost ceiling limitation. At March 31, 2009, the capitalized cost of our oil and gasproperties exceeded the full cost ceiling limitation by approximately $23.6million based upon a natural gas price of approximately $2.52 per Mcf in effectat that date. Based on the subsequent price increase to $3.31 on May 12,2009, the capitalized cost exceeded the full cost ceiling limitation by $16.8million. Therefore, an impairment of approximately $16.8 million was taken forthe quarter ended March 31, 2009. This impairment of our oil and gas properties resulted from lowcommodity prices in the first quarter of 2009. No impairment was taken for thequarter ended March 31, 2008 based on a natural gas price of $8.01 perMcf. A decline in gas prices or an increase in operating costs orreductions in economically recoverable quantities could result in therecognition of additional impairments of our oil and gas properties in futureperiods.

 

***Gas Sales***

 

We use the sales methodfor recording natural gas sales. Sales of gas applicable to our interest inproducing natural gas and oil leases are recorded as revenues when the gas ismetered and title transferred pursuant to the gas sales contracts covering ourinterest in gas reserves. During such times as our sales of gas exceed our prorata ownership in a well, such sales are recorded as revenues unless totalsales from the well have exceeded our share of estimated total gas reservesunderlying the property at which time such excess is recorded as a gasimbalance liability. At March 31, 2009 and December 31, 2008, therewas no such liability recorded. Although there was no such liability recordedfor prior periods, gas reserves are an estimate and are updated on an annualand interim basis. Gas pricing, expenses and production may impact future gasreserves remaining which, in turn, could impact the recording of liabilities inthe future. Gas sales accruals at March 31, 2009, and December 31, 

 

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

 

***Asset Retirement Obligations***

 

We follow the provisionsof Statement of Financial Accounting Standards (SFAS) No. 143, “Accountingfor Asset Retirement Obligations.” SFAS No. 143 generally applies to legalobligations associated with the retirement of long-lived assets that resultfrom the acquisition, construction, development and/or the normal operation ofa long-lived asset. SFAS No. 143 requires us to recognize an estimatedliability for costs associated with the abandonment of our oil and gasproperties.

 

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

 

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

 

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

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

 

***Inventory***

 

We acquired inventory ofoil and gas equipment, primarily tubulars, in 2007 and 2008, to take advantageof quantity pricing and to secure a readily available supply. Inventory isvalued at the lower of average cost or market. Inventory is used in thedevelopment of gas properties and to the extent it is estimated that it will bebilled to other working interest owners during the next year, it is included incurrent assets. Otherwise, it is recorded in non-current assets. The price ofsteel is a primary factor in valuing our inventory. Under the valuation methodof lower of average cost or market, a 10% reduction in the price of steel wouldhave caused a $47,000 reduction in our inventory valuation as of March 31,2009. The market price of steel is evaluated each quarter using prices quotedby authorized vendors in the area.

 

***Property and Equipment***

 

Property and equipment iscomprised primarily of a building, computer hardware and software, vehicles andequipment, and is recorded at cost. Renewals and betterments that substantiallyextend the useful lives of the assets are capitalized. Maintenance and repairsare expensed when incurred. Depreciation and amortization are provided usingthe straight-line method over the estimated useful lives of the assets, rangingas follows: buildings—30 years, computer hardware and software—3 to5 years, machinery, equipment and vehicles—5 years, and officefurniture and equipment—3 to 5 years.

 

***Long-Lived Assets***

 

Long-lived assets to beheld and used in our business are reviewed for impairment whenever events orchanges in circumstances indicate that the related carrying amount may not berecoverable. When the carrying amounts of long-lived assets exceed the fairvalue, which is generally based on discounted expected future cash flows, werecorded an impairment. No impairments were recorded during the three monthsended March 31, 2009 and the year ended December 31, 2008 .

 

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***General and Administrative Expenses***

 

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

 

***Income Taxes***

 

We use the asset andliability method of accounting for income taxes, in accordance with SFAS No. 109,“Accounting for Income Taxes.” Deferred tax assets and liabilities arerecognized for the expected future tax consequences of temporary differencesbetween the financial statement and tax bases of assets and liabilities. Ifappropriate, deferred tax assets are reduced by a valuation allowance whichreflects expectations of the extent to which such assets will be realized. Asof March 31, 2009 and December 31, 2008, we recorded a full valuationallowance for our net deferred tax asset.

 

On January 1, 2007,we adopted the provisions of FIN 48, “Accountingfor Uncertainty in Income Taxes.”FIN 48 prescribes a recognition threshold and measurement attribute for thefinancial statement recognition and measurement of a tax position taken orexpected to be taken in a tax return. FIN 48 requires that we recognize in ourconsolidated 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 ofthe position. As a result of the implementation of FIN 48, we performed acomprehensive review of our material tax positions in accordance withrecognition and measurement standards established by FIN 48.

 

As a result of thisreview, we did not identify any material deferred tax assets that requiredadjustment. As of March 31, 2009, we had not recorded any materialuncertain tax positions.

 

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

 

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

 

***Derivatives***

 

We use derivativeinstruments to manage our exposure to fluctuating natural gas prices throughthe use of natural gas swap and option contracts. We account for derivativeinstruments or hedging activities under the provisions of SFAS No. 133, “Accountingfor Derivative Instruments and Hedging Activities.” SFAS No. 133 requiresus to record derivative instruments at their fair value. If the derivative isdesignated as a fair value hedge, the changes in the fair value of thederivative and of the hedged item attributable to the hedged risk arerecognized in earnings. If the derivative is designated as a cash flow hedge,the effective portions of changes in the fair value of the derivative arerecorded in other comprehensive income (loss) and are recognized in thestatement of operations when the hedged item affects earnings. Ineffectiveportions of changes in the fair value of cash flow hedges, if any, arerecognized in earnings. Changes in the fair value of derivatives that do notqualify for hedge treatment are recognized in earnings. Please see Note 5included in the accompanying unaudited Notes to Financial Statements foradditional discussions of derivatives.

 

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

 

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***Stock-Based Compensation***

 

Effective January 1,2006, we adopted SFAS No. 123(R), “Share-Based Payments,” which requirescompanies to recognize compensation expense for share-based payments based onthe estimated fair value of the awards. We recognized an expense ofapproximately $121,000 for the three months ended March 31, 2009, based onthe fair value of vested options.  Werecognized an expense of approximately $78,000 for the three months ended March 31,2009, based on the fair value of restricted stock that vested during thequarter.  SFAS No. 123(R) alsorequires that the benefits of tax deductions in excess of compensation costrecognized for stock awards and options (“excess tax benefits”) be presented asfinancing cash inflows in the Statement of Cash Flows.

 

***Accounts Receivable***

 

Our revenue producingactivities are conducted primarily in Wyoming. We grant credit to qualifiedcustomers, which potentially subjects us to credit risk resulting from, amongother factors, adverse changes in the industry in which we operate and thefinancial condition of our customers. We continuously monitor collections andpayments from our customers and, if necessary, record an allowance for doubtfulaccounts based upon historical experience and any specific customer collectionissues identified. We recorded an allowance of $100,000 at each of March 31,2009 and December 31, 2008.

 

***Transportation Costs***

 

We account fortransportation costs under Emerging Issues Task Force Issues 00-10, “Accountingfor Shipping and Handling Fees and Costs,” whereby amounts paid fortransportation are classified as operating expenses.

 

***Legal Estimates***

 

From time to time, we aresubject to legal proceedings and claims that arise in the ordinary course ofbusiness. We account for these costs under SFAS No. 5, “Accounting for Contingencies,” whichstates that a loss contingency be recorded if it is probable that a liabilityhas been incurred and it is reasonably estimatable. At March 31, 2009 and December 31,2008, we recorded no liability for legal proceedings.

 

***Per Share Information***

 

Basic earnings (loss) pershare is computed by dividing net income (loss) from continuing operationsattributable to common stock by the weighted average number of shares of commonstock outstanding during each period. Diluted earnings per share is computed byadjusting the average number of shares of common stock outstanding for thedilutive effect, if any, of common stock equivalents such as stock options andwarrants. Diluted net loss per share was $0.60, the same as basic net loss pershare, for the three months ended March 31, 2009.  Diluted net loss per share was $0.19, thesame as basic net loss per share, for the three months ended March 31,2008.  Certain options to purchase sharesof Pinnacle’s common stock were excluded from the dilution calculations becausethe shares were anti-dilutive.  Duringthe three months ended March 31, 2009, 645,000 options were excludedbecause they were anti-dilutive.  Duringthe three months ended March 31, 2008, 750,000 options were excludedbecause they were anti-dilutive.

 

***New Accounting Pronouncements***

 

Forinformation concerning new accounting pronouncements, please see Note 2 of theNotes to the unaudited financial statements appearing elsewhere in the quarterlyreport.

 

**TrendsAffecting Our Business**

 

The continued creditcrisis and related turmoil in the global financial system have had an adverseimpact on our business and financial condition. In addition, the prices of oiland natural gas declined significantly in 2008 and have remained low in2009.  As a result of low CIG indexprices, the economic climate and our limited capital resources, we expect tocontinue operating during 2009 with a reduced capital expenditure plan for2009. Under our plan, we will generally make expenditures only as are necessaryto secure drilling permits in strategic areas, drill wells that secureleasehold positions and construct the necessary infrastructure to complete andhook-up wells that have already been drilled.

 

Historically, natural gasprices have been extremely volatile, and we expect that volatility to continue.For example, during the three months ended March 31, 2009, the NYMEXnatural gas index price ranged from a high of $6.07 per MMBtu to a low of $3.63per MMBtu, while the CIG natural gas index price ranged from a high of $4.59per MMBtu to a low of $2.27 per MMBtu. During the year ended December 31,2008, the NYMEX natural gas index price ranged from a high of $13.58 per MMBtuto a low of $5.29 per MMBtu, while the CIG natural gas index price ranged froma high of $10.26 per 

 

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MMBtu to a low of $1.00per MMBtu. Changes in natural gas pricing have impacted our revenue streams,production taxes, prices used in reserve calculations, borrowing basecalculations and the carrying value of our properties and the valuation ofpotential property acquisitions. During the three months ended March 31,2009, estimated future gas prices had an impact on both our revenues and thecosts attributable to our future operations. We expect that changing naturalgas prices will continue to impact our operations and financial results in thefuture.

 

Transportation of natural gas and access to throughputcapacity have a direct impact on natural gas prices in the Rocky Mountainregion, where our operations are concentrated. As drilling activity increasesthroughout the Rocky Mountain region, additional production may come on line,which could cause bottlenecks or capacity constraints. Generally speaking, asurplus of natural gas production relative to available transportation capacityhas a negative impact on prices. Conversely, as capacity increases, andbottlenecks are eliminated, prices generally increase. Although there iscurrently adequate transportation capacity out of the Powder River Basin, asurplus of natural gas arriving at key marketing hubs from the Powder RiverBasin and elsewhere relative to available takeaway capacity from these hubs hascaused Rocky Mountain gas to generally trade at a discount to the NYMEX naturalgas index price. For example, from January 1, 2009 through March 31,2009, Rocky Mountain gas traded at a differential to the NYMEX natural gasindex price that ranged from a discount of $1.36 per MMBtu to a discount of$1.49 per MMBtu, with an average differential of a discount of $1.46 per MMBtu.The Rockies Express Pipeline which was completed and placed into service in early2008, has increased takeaway capacity by approximately 1.5 Bcf per day fromthese hubs. We expect that the completion of additional proposed pipelines willhelp reduce the differential between gas produced in the Rocky Mountain regionand the NYMEX natural gas index price. Additional proposed pipelines arescheduled to be completed in late 2010 and 2011. General economic conditionsand the future demand for natural gas may change the development schedule ofproposed pipelines.

 

**Resultsof Operations**

 

Net loss attributable tostockholders for the quarter ended March 31, 2009 was $17.5 million, or$0.60 per diluted share, on total revenues of $2.8 million. Other income forthe quarter ended March 31, 2009 included a $0.6 million unrealized gainassociated with the change in the fair valuation of our natural gas hedges inplace in accordance with the provisions of SFAS No. 133. Absent suchchange in the valuation of hedges, we would have shown a loss of $18.1 million.In addition, we recorded an impairment of $16.8 million for the quarter ended March 31,2009.  Absent the impairment andunrealized gain on derivatives, we would have shown a loss of $1.2 million.This compares to a net loss attributable to stockholders of $5.6 million forthe quarter ended March 31, 2008 on total revenue of $5.7 million.Adjusted for an unrealized loss in the fair valuation of our natural gas hedgesin place of $4.5 million shown in other income, our results for the quarterended March 31, 2008 would have been a net loss attributable to commonstockholders of $1.1 million. We did not record an impairment for the quarterended March 31, 2008.

 

In order to provide ameasure of stability to the cash flow in an environment of volatile oil and gasprices and to manage the exposure to commodity price risk, we chose toperiodically hedge a portion of our oil and gas production using swap andcollar agreements. We account for our derivative instruments under theprovisions of SFAS No. 133. SFAS No. 133 requires us to recordderivative instruments at their fair value. Management has chosen not to usehedge accounting for these arrangements. Therefore, in accordance with SFAS No. 133,changes in the fair market value are recognized in earnings.

 

***Three Months Ended March 31,2009 Compared To Three Months Ended March 31, 2008***

 

*Gassales volume.*

 

Gas sales volumedecreased 7.5%, from 879 MMcf in the three months ended March 31, 2008 to813 MMcf in the three months ended March 31, 2009. Daily sales volume was9.0 MMcf for the three months ended March 31, 2009 as compared to 9.6 MMcffor the three months ended March 31, 2008, a 0.6 MMcf per day decrease.The decrease resulted primarily from shutting in wells due to low natural gasprices, reductions in volumes due to compression maintenance and repairs, andweather related downtime.

 

*Gassales revenue.*

 

Revenue from gas salesdecreased approximately $2.9 million during the three months ended March 31,2009, to approximately $2.8 million, a 51% decrease compared to the three monthsended March 31, 2008. This decrease was primarily due to a decrease in theaverage realized price per Mcf. The average realized price per Mcf decreasedapproximately 47%, from $6.44 per Mcf in the three months ended March 31,2008 to $3.40 per Mcf in the three months ended March 31, 2009.

 

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*Derivatives.*

 

For the three monthsended March 31, 2009, we had an unrealized gain of $0.6 million comparedto an unrealized loss of $4.5 million for the three months ended March 31,2008. The unrealized gain and loss are non-cash income and expense,respectively, based primarily on the Black-Scholes model for valuing futurecash flows utilizing price volatility with a normal discount rate. Hedgessettled during the three months ended March 31, 2009 resulted in arealized gain of $1.4 million compared to a realized hedge loss of $0.1 millionduring the three months ended March 31, 2008. The realized hedge gain forthe three months ended March 31, 2009 was primarily due to the fact thatgas prices were lower than the weighted average floor price of our hedges inplace.

 

*Leaseoperating expenses.*

 

Lease operating expensesdecreased $0.9 million in the three months ended March 31, 2009 to $1.2million, a 42% decrease compared to the three months ended March 31, 2008.This decrease resulted primarily from a reduction in contract services, fueland workover related costs offset partially by an increase in surface useexpenses in the productive cycle during the three months ended March 31,2009. On a Mcf basis, lease operating expenses decreased 37% from $2.33 per Mcfin the three months ended March 31, 2008 to $1.46 per Mcf in the threemonths ended March 31, 2009. The decrease per Mcf was primarily due to anumber of non-productive wells being shut in due to low natural gas prices.

 

*Production taxes.*

 

Production taxesdecreased $0.4 million in the three months ended March 31, 2009 to $0.3million, a 58% decrease from the three months ended March 31, 2008.Production taxes generally correlate to gross sales revenue because productiontaxes are based on a percentage of sales value. In Wyoming, the percentageaverages 11% to 13%, depending on rates in effect for the respective year,while in Montana the percentage averages 9%. The decrease in production taxesfor the three months ended March 31, 2009 was primarily due to decreasedrevenues associated with decreased volume and realized pricing. On an Mcfbasis, production taxes were $0.34 per Mcf for the three months ended March 31,2009 and $0.75 per Mcf for the three months ended March 31, 2008, a 55%decrease, which correlates to the decrease in the price per Mcf received in thethree months ended March 31, 2009 from the three months ended March 31,2008.

 

*Marketingand transportation.*

 

Marketing andtransportation expenses increased approximately $0.2 million in the threemonths ended March 31, 2009 to approximately $1.3 million, a 16% increasefrom the three months ended March 31, 2008. The increase related primarilyto a slight increase in transportation fees and compression due to inflationaryadjustments in the contracts along with fees paid for compression designcapacity which was not used. On an Mcf basis, marketing and transportationexpenses increased 25% to $1.54 per Mcf in the three months ended March 31,2009 from $1.23 per Mcf in the three months ended March 31, 2008.

 

*Generaland administrative expenses, net.*

 

General andadministrative expenses are offset by operating income from drilling andproduction activities for which we can charge an overhead fee to nonoperatingworking interest owners. These well operating overhead fees were $0.3 millionin the three months ended March 31, 2009 compared to $0.4 million for thethree months ended March 31, 2008, a 15% decrease. General andadministrative expenses, net, decreased $0.3 million in the three months ended March 31,2009 to $1.0 million. On an Mcf basis, general and administrative expenses, netdecreased 19%, from $1.56 per Mcf in the three months ended March 31, 2008to $1.27 per Mcf in the three months ended March 31, 2009. The decrease ingeneral and administrative expenses was primarily a result of staff and payreductions.

 

*Depreciation,depletion, amortization and accretion.*

 

Depreciation, depletion,amortization and accretion expense increased $0.1 million for the three monthsended March 31, 2009 to $1.8 million, an 6% increase compared to the threemonths ended March 31, 2008. The increase was primarily due to a decreasein the net proved reserves at March 31, 2009 resulting from a CIG indexprice of $2.52 per Mcf. On an Mcf basis, the depreciation, depletion,amortization and accretion rate increased to $2.25 per Mcf in the three monthsended March 31, 2009 from $1.97 per Mcf in the three months ended March 31,2008.

 

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*Impairment.*

 

At March 31, 2009,the capitalized cost of our oil and gas properties exceeded the full costceiling limitation by approximately $23.6 million based upon a natural gasprice of approximately $2.52 per Mcf (based on the CIG Rocky Mountain Index) ineffect at that date. Based on the subsequent price increase to $3.31 per Mcf onMay 12, 2009, the capitalized cost exceeded the full cost ceilinglimitation by $16.8 million. Therefore, an impairment of approximately $16.8million was taken for the quarter ended March 31, 2009. For furtherinformation regarding this impairment, please see Note 2 — “Basis ofPresentation” in the Notes to the unaudited financial statements appearingelsewhere in this quarterly report. A decline in natural gas prices or anincrease in operating costs in economically recoverable quantities could resultin the recognition of additional impairments of our oil and gas properties infuture periods.

 

**Liquidityand Capital Resources**

 

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

 

*Credit Facility.*

 

Effective February 12,2007, we entered into a credit facility which permits borrowings up to theborrowing base as designated by the administrative agent. As of March 31,2009 and December 31, 2008, we had $10.5 million and $11.5 million,respectively, of debt outstanding under the facility. As described below, weare currently unable to borrow additional amounts under the credit facility dueto covenant limitations and may be further limited in the future based onborrowing base limitations.

 

As of December 31,2008, the borrowing base under the credit facility was approximately $13.2million. The borrowing base was subject to automatic reductions ofapproximately $666,667 per month until it reached $10.5 million on April 1,2009. As of April 14, 2009, our borrowing base was reduced to $9.0million, subject to automatic reductions of $500,000 per month until it reaches$6.5 million on October 1, 2009, where it will remain until the nextborrowing base redetermination. If natural gas prices do not improve, we expectthat our borrowing base could be further reduced in the future.

 

The borrowing base isdetermined on a semi-annual basis and at such other additional times, up totwice yearly, as may be requested by either us or the administrative agent andis determined by the administrative agent in accordance with customarypractices and standards for loans of a similar nature, although suchdetermination is at the administrative agent’s discretion as the creditagreement does not provide a specific borrowing base formula.

 

Borrowings under thiscredit facility may be used solely to acquire, explore or develop oil and gasproperties and for general corporate purposes. The credit facility matures February 12,2011.

 

Our obligations under thecredit facility are secured by liens on (i) no less than 90% of the netpresent value of the oil and gas to be produced from our oil and gas propertiesthat are included in the borrowing base determination, calculated using adiscount rate of 10% per annum and reserve estimates, prices and productionrates and costs, (ii) options to lease, seismic options, permits, andrecords related to such properties, and (iii) seismic data.

 

Borrowings under ourcredit facility, as amended, bear interest either: (i) at the greater ofthe one month London Interbank Offered Rate, or LIBOR, plus 1.00% or a domesticbank rate, plus in either case an applicable margin of 0.75% to 1.75% based onutilization, or (ii) on a sliding scale from the one, two, three or sixmonth LIBOR, plus an applicable margin of 2.00% to 3.00% based on utilization.The weighted average interest rate as of March 31, 2009 was 5.0%.  The credit agreement provides for variousfees, including a quarterly commitment fee of 0.5% per annum and engineeringfees to the administrative agent in connection with a borrowing basedetermination. 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 anadditional arrangement fee of 1% based on utilization. Borrowings under thiscredit facility may be prepaid without premium or penalty, except on Eurodollaradvances.

 

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The credit agreement, asamended, contains covenants that among other things restrict our 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 andasset 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 creditagreement provides that acceptable commodity hedging arrangements cannot covergreater than 80 to 85%, depending on the measurement date, of our monthlyproduction from our hydrocarbon properties that are used in the borrowing basedetermination, and that the fixed or floor price of our hedging arrangementsmust be equal to or greater than the gas price used by the lenders indetermining the borrowing base.

 

The credit agreement, as amended, also requires thatwe satisfy certain affirmative covenants, meet certain financial tests,maintain certain financial ratios and make certain customary indemnificationsto lenders and the administrative agent. The financial covenants includerequirements to maintain: (i) a ratio of EBITDA to cash interest expenseof not less than 3.00 to 1.00, (ii) a ratio of current assets to currentliabilities of not less than 1.00 to 1.00, (iii) a total debt toannualized EBITDA ratio of not more than 3.0 to 1.0, (iv) a quarterlytotal 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 to1.00.

 

The credit agreement, as amended, contains customaryevents of default, including payment defaults, covenant defaults, certainevents of bankruptcy and insolvency, defaults in the payment of other materialdebt, judgment defaults, breaches of representations and warranties, loss ofmaterial permits and licenses and a change in control. The credit agreementrequires any wholly-owned subsidiaries to guarantee the obligations under thecredit agreement.

 

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

 

Effective August 4, 2008, we and theadministrative agent and lender entered into the second amendment to the creditagreement (the “second amendment”). The second amendment provided, among otherthings, for (i) an increase in the total quarterly senior debt toannualized EBITDA ratio from 2.0 to 1.0, to 3.0 to 1.0, (ii) an increasein interest at each utilization level for LIBOR borrowings, (iii) theamendment of the utilization calculation to be determined as the greater of (x) thepercentage of credit exposure over the borrowing base or (y) thepercentage of credit exposure over three times EBITDA minus permittedsubordinated debt, and (iv) the payment of an amendment fee.

 

Effective September 30, 2008, we and theadministrative agent and lender entered into the third amendment to the creditagreement (the “third amendment”). In addition to waiving compliance with thecurrent ratio covenant as of September 30, 2008, the third amendment,among other things, required that immediately prior to any additionalborrowings under the credit agreement, our ratio of current assets to currentliabilities be not less than 1.00 to 1.00. As a result of this new condition toadditional borrowings, we are currently unable to borrow additional amountsunder the credit agreement. The third amendment also increased the interestrate payable under the credit agreement to either (i) the greater of theone month LIBOR plus 1.00% or a domestic bank rate, plus in either case anapplicable margin of 0.75% to 1.75% based on utilization, or (ii) asliding scale from the one, two, three or six month LIBOR, plus an applicablemargin of 2.00% to 3.00% based on utilization, and provided for the payment ofan amendment fee.

 

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On April 14, 2009,we and the administrative agent entered into the fourth amendment to the creditagreement which reduced the borrowing base as described above and waivedcompliance with the current ratio financial covenant as of December 31,2008 and March 31, 2009 and with the restrictive covenants related toaccounts payable, permitted liens and permitted debt until the current ratiofinancial covenant and next borrowing base redetermination, subject to certainfinancial caps. We believe that we may not be in compliance with the currentratio financial covenant and certain other covenants throughout 2009, but managementanticipates receiving waivers in the future based on prior dealings with thelender and continued compliance with the borrowing base limitations. There canbe no assurance that we will be able to obtain such waivers or that suchwaivers will be obtained on acceptable terms. If we are unable to obtain futurewaivers and/or comply with the restrictive covenants and are therefore indefault, the lenders could avail themselves of the remedies under the creditagreement, including acceleration and foreclosure.

* *

*OfficeBuilding Loan.*

 

On November 15, 2005, we entered into a mortgageloan secured by our office building in Sheridan, Wyoming in the aggregateprincipal amount of $829,000. The promissory note provides for monthly paymentsof principal and interest in the initial amount of $6,400, and unpaid principalthat bore interest at 6.875% until November 15, 2008, currently bearsinterest at a variable base rate plus 0.5% and will bear interest at 18% upon adefault. The variable base rate is based on the lender’s base rate. Thematurity date of this mortgage is November 15, 2015, at which time aprincipal and interest payment of $531,300 will become due. As of March 31,2009, we had $756,000 outstanding in principal on this mortgage. On November 15,2008, the interest rate on our mortgage loan changed from a fixed rate of6.875% to a variable rate. As of March 31, 2009, the variable rate was4.75%.

 

*CapitalExpenditure Budget*.

 

We had total capital expenditures of $0.6 million forthe quarter ended March 31, 2009. Due to low CIG index prices, theeconomic climate and limited capital resources, we expect to continue tooperate with a reduced capital expenditure plan through 2009. Under our reducedcapital expenditure plan, we will generally only make such expenditures as arenecessary to secure drilling permits in strategic areas, drill wells thatsecure leasehold positions and construct the necessary infrastructure tocomplete and hook-up wells that have already been drilled.

 

***Cash Flow from Operating Activities***

*** ***

Net cash provided by operating activities was $0.7million for the three months ended March 31, 2009, compared to net cashprovided by operating activities of $0.8 million for the three months ended March 31,2008. The change was primarily due to a decrease in our revenue distributionpayable balance offset partially by a decrease in our accounts receivablebalance.

 

***Cash Flow from Investing Activities***

*** ***

Net cash provided byinvesting activities was $49,000 for the three months ended March 31,2009, compared to net cash used in investing activities of $5.2 million for thethree months ended March 31, 2008. The increase in net cash provided by investing activities in the threemonths ended March 31, 2009 was primarily due to a realized gain onderivatives coupled with reduced capital expenditures as compared to thequarter ended March 31, 2008.

 

***CashFlow from Financing Activities***

*** ***

Net cash used infinancing activities was $1.0 million for the three months ended March 31,2009, compared with net cash used in financing activities of $10,000 for thethree months ended March 31, 2008. The change was primarily due to areduction in the balance owed on the line of credit for the three months ended March 31,2009.

 

***Contractual Obligations***

* *

Please see Notes 3 and 7of the Notes to the unaudited financial statements appearing elsewhere in thisquarterly report for information regarding our credit facility and otherindebtedness.

 

The following tablesummarizes by period our contractual obligations as of March 31, 2009:

 
| ** **                                     | ** ** | **Total**               | ** ** | **2009** | ** ** | **2010-2011** | ** ** | **2012-2013** | ** ** | **Thereafter** | ** ** |
|------------------------------------------------|------------|-------------------------|------------|----------|------------|---------------|------------|---------------|------------|----------------|------------|
| ** **                                     | ** ** | **(In thousands)** | ** ** |
| Notes payable in  connection with the mortgage |       | $                       | 756        |     | $          | 22            |       | $             | 64         |           | $          | 70 |   | $ | 600 |   |
| Asset retirement  obligations                  |       | 3,422                   |       | 341      |       | 856           |       | 1,050         |       | 1,175          |       |
| Production and  property taxes                 |       | $                       | 2,580      |     | $          | 1,157         |       | $             | 1,423      |           | —     |   | — |   |
| Total                                          |       | $                       | 6,758      |     | $          | 1,519         |       | $             | 2,344      |           | $          | 1,120 |   | $ | 1,775 |   |

 

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**ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK**

 

The primary objective ofthe following information is to provide forward-looking quantitative andqualitative information about our potential exposure to market risk. The term “marketrisk” refers to the risk of loss arising from adverse changes in natural gasprices or interest rates. This forward-looking information provides indicatorsof how we view and manage our ongoing market risk exposure. All of our marketrisk sensitive instruments were entered into for purposes other thanspeculative trading.

 

**Commodity Price Risk**

 

Our major market risk exposure is in the pricingapplicable to our natural gas production. The prices we receive for ourproduction depend on many factors beyond our control. We seek to reduce ourexposure to unfavorable changes in natural gas prices, which are subject tosignificant and often volatile fluctuation, through the use of fixed-pricecontracts. Our fixed-price contracts are comprised of energy swaps and collars.Fixed price contracts allow us to predict with greater certainty the effectivenatural gas prices to be received for hedged production and benefit operatingcash flows and earnings when market prices are less than the fixed pricesprovided by the contracts. However, we will not benefit from market prices thatare higher than the fixed prices in the contracts for hedged production. Collarstructures provide for participation in price increases and decreases to theextent of the ceiling prices and floors provided in those contracts. Withregard to hedging arrangements, our credit facility provides that acceptablecommodity hedging arrangements cannot cover greater than 80 to 85%, dependingon the measurement date, of our monthly production from our hydrocarbonproperties that are used in the borrowing base determination, and that the fixedor floor price of our hedging arrangements must be equal to or greater than thegas price used by the lenders in determining the borrowing base.

 

The following table summarizes the estimated volumes,fixed prices, fixed price sales and fair value attributable to the fixed pricecontracts as of March 31, 2009. At March 31, 2009, we had hedgedvolumes through December 2010. Please see Note 5 of the Notes to theunaudited financial statements appearing elsewhere in this quarterly report forfurther information regarding our derivatives.

 
| ** **                                       | ** ** | **Year Ending  December 31, 2009** | ** ** | **Year Ending  December 31, 2010** | ** ** |
|--------------------------------------------------|------------|---------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                       | ** ** | **(Unaudited)**                                   | ** ** | **(Unaudited)**                                   | ** ** |
| **Natural  Gas Collars:**                        |       |                                              |       |                                              |       |
| Contract volumes  (MMBtu):                       |       |                                              |       |                                              |       |
| Floor                                            |       | 550,000                                           |       |                                              |       |
| Ceiling                                          |       | 550,000                                           |       |                                              |       |
| Weighted-average  fixed price per MMBtu(1):      |       |                                              |       |                                              |       |
| Floor                                            |       | $                                                 | 6.50       |                                              | $          |   |   |
| Ceiling                                          |       | $                                                 | 7.50       |                                              | $          |   |   |
| Fixed-price  sales(2)                            |       | $                                                 | 7.50       |                                              | $          |   |   |
| Fair value, net  (thousands)(3)                  |       | $                                                 | 2,027      |                                              | $          |   |   |
| **Natural  Gas Swaps:**                          |       |                                              |       |                                              |       |
| Contract volumes  (MMBtu)                        |       | 1,300,000                                         |       | 1,030,000                                         |       |
| Weighted-average  fixed price sales per MMBtu(1) |       | $                                                 | 5.41       |                                              | $          | 4.18 |   |
| Fair value, net  (thousands)(3)                  |       | $                                                 | 3,266      |                                              | $          | (377 | ) |
| **Total  Natural Gas Contracts:**                |       |                                              |       |                                              |       |
| Contract volumes  (MMBtu)                        |       | 1,850,000                                         |       | 1,030,000                                         |       |
| Fixed-price  sales(2)                            |       | $                                                 | 6.03       |                                              | $          | 4.18 |   |
| Fair value, net  (thousands)(3)                  |       | $                                                 | 5,293      |                                              | $          | (377 | ) |
|                                                  |            |                                                   |            |                                                   |            |  |  |  |

 

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(1)             Volumes hedged using the CIG index pricepublished in the first issue of Inside FERC’s Gas Market Report for each calendarmonth of the derivative transaction.

 

(2)             Assumes ceiling prices for natural gascollar volumes.

 

(3)             Fair value based on CIG index price ineffect for each month as of March 31, 2009.

 

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**Interest Rate Risk**

 

Borrowings under ourcredit facility bear interest at fluctuating market-based rates.  Accordingly, our interest expenses aresensitive to market changes, which expose us to interest rate risk on currentand future borrowings under our credit facility.

 

As of March 31,2009, we had $10.5 million in outstanding indebtedness under our creditfacility.  Borrowings under the creditfacility bear interest either: (i) at the greater of the one month LondonInterbank Offered Rate, or LIBOR, plus 1.00% or a domestic bank rate, plus ineither case an applicable margin of 0.75% to 1.75% based on utilization, or (ii) ona sliding scale from the one, two, three or six month LIBOR, plus an applicablemargin of 2.00% to 3.00% based on utilization. The weighted average interest rate for borrowings under our creditfacility was 5.0% for the three months ended March 31, 2009 and 5.3% forthe year ended December 31, 2008.

 

A hypothetical change of1% in either the domestic bank rate or the LIBOR interest rates would increaseor decrease gross interest expense approximately $105,000 per year.

** **

**ITEM 4T. CONTROLS AND PROCEDURES**

 

**Disclosure Controls and Procedures**

 

Our principal executive officer and principalfinancial officer are responsible for establishing and maintaining adequatedisclose controls and procedures.  Basedon their evaluation as of the end of the period covered by this quarterlyreport, our principal executive officer and principal financial officer haveconcluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and15d-15(e) under the Securities Exchange Act of 1934, as amended (theExchange Act)) are effective to ensure that information required to bedisclosed in reports that we file or submit under the Exchange Act arerecorded, processed, summarized and reported within the time periods specifiedin the SEC’s rules and forms.

 

**Changes in Internal Control OverFinancial Reporting**

 

During the most recent fiscal quarter, there has beenno change in our internal control over financial reporting that has materiallyaffected, or is reasonably likely to materially affect, our internal controlover financial reporting.

 

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**PART II. OTHER INFORMATION**

 

**ITEM1. LEGAL PROCEEDINGS**

 

From time to time, we aresubject to legal proceedings and claims that arise in the ordinary course ofour business. While the outcome of these proceedings cannot be predicted withcertainty, we do not currently expect them to have a material adverse effect onthe financial statements.

 

There have been nomaterial developments during the quarter ended March 31, 2009 regardingour currently pending legal proceedings. For a discussion of certain of ourcurrent legal proceedings, please see Note 9 — “Commitments and Contingencies”of the Notes to the unaudited financial statements appearing elsewhere in thisquarterly report.

 

**ITEM1A. RISK FACTORS**

 

The following discussionsupplements or updates the risk factors set forth under the heading “RiskFactors” in our annual report on Form 10-K for the year ended December 31,2008.

 

***We continue to experience volatility in natural gas and oilprices which could have a material adverse******effecton our business.***

 

Our revenues,profitability and future growth and the carrying value of our natural gas andoil properties depend to a large degree on prevailing natural gas and oilprices. Our ability to maintain or increase our borrowing capacity and toobtain additional capital on attractive terms also substantially depends uponnatural gas and oil prices. Prices for natural gas and oil are subject to largefluctuations in response to relatively minor changes in the supply and demandfor natural gas and oil, uncertainties within the market and a variety of otherfactors in large part beyond our control. During the three months ended March 31, 2009, the NYMEX natural gasindex price ranged from a high of $6.07 per MMBtu to a low of $3.63 per MMBtu,while the CIG natural gas index price ranged from a high of $4.59 per MMBtu toa low of $2.27 per MMBtu.  Please see “Thevolatility of natural gas and oil prices could have a material adverse effecton our business” under Risk Factors in our annual report on Form 10-K forthe year ended December 31, 2008 for further information related to pricevolatility.

 

***Ourcredit facility has substantial restrictions and financial covenants that mayaffect our ability to successfully operate our business. In addition, we mayhave difficulty returning to compliance with certain financial covenants.***

*** ***

Our credit facilityimposes certain operational and financial restrictions on us.  Please see “Our credit facility hassubstantial restrictions and financial covenants that may affect our ability tosuccessfully operate our business. In addition, we may have difficultyreturning to compliance with certain financial covenants” under Risk Factors inour annual report on Form 10-K for the year ended December 31, 2008for further information regarding restrictions under our credit facility.

 

As of March 31,2009, we were not in compliance with the current ratio financial covenant andcertain other covenants related to accounts payable, permitted liens andpermitted debt under our credit facility. On April 14, 2009, the lenders waivedcompliance with the current ratio as of March 31, 2009, and with suchother restrictive covenants, subject to certain financial caps, until the nextborrowing base redetermination expected in the fall of 2009. We have also notbeen in compliance with certain financial covenants for the last four quarters,but obtained waivers and/or amendments in each instance. As a result of suchnon-compliance, we are currently unable to borrow additional funds under ourcredit agreement. We believe that we may not be in compliance with certainfinancial and other covenants throughout the remainder of 2009, but will seekadditional waivers. There can be no assurance that we will be able to obtainsuch waivers or that such waivers will be obtained on acceptable terms. If weare unable to obtain future waivers and/or to comply with the covenants, thelenders could accelerate our indebtedness or foreclose on properties held byliens. In addition, due to borrowing base limitations, we are also unable toborrow additional funds under the credit facility. As of May 14, 2009, ourborrowing base was $9.0 million, with further monthly reductions of$500,000 until the borrowing base reaches $6.5 million on October 1,2009.  If natural gas prices do notimprove, we expect that our borrowing base could be further reduced in thefuture.

 

Please see “Management’sDiscussion and Analysis of Financial Condition and Results ofOperations—Liquidity and Capital Resources—Credit Facility,” for furtherdiscussion of our credit facility.

 

**ITEM 2. UNREGISTERED SHARES OF EQUITYSECURITIES AND USE OF PROCEEDS**

** **

Notapplicable.

 

**ITEM 3. DEFAULTS UPON SENIORSECURITIES**

 

Not applicable.

 

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**ITEM 4. SUBMISSION OF MATTERS TO AVOTE OF SECURITY HOLDERS**

 

Not applicable.

 

**ITEM 5. OTHER INFORMATION**

 

Not applicable.

 

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**ITEM 6. EXHIBITS**

 
| Exhibit No. | ** ** | **Description**                                                                                                                                                                                                                                                                                     |
|-------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.1         | —     | Second Amended and Restated Certificate of  Incorporation of Pinnacle Gas Resources, Inc. (incorporated herein by  reference to Exhibit 3.1 to the Registration Statement on Form S-1  (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on  May 10, 2006). |
|        |       |                                                                                                                                                                                                                                                                                                |
| 3.2         | —     | Amended and Restated Bylaws of Pinnacle Gas  Resources, Inc. (incorporated herein by reference to Exhibit 3.2 to  the Registration Statement on Form S-1 (File No. 333-133983) filed  by Pinnacle Gas Resources, Inc. on May 10, 2006).                               |
|        |       |                                                                                                                                                                                                                                                                                                |
| 4.1         | —     | Amended and Restated Securityholders Agreement,  dated February 16, 2006 (incorporated herein by reference to  Exhibit 4.1 to the Registration Statement on Form S-1 (File  No. 333-133983) filed by Pinnacle Gas Resources, Inc. on  May 10, 2006).                  |
|        |       |                                                                                                                                                                                                                                                                                                |
| 4.2         | —     | Registration Rights Agreement, dated April 11,  2006 (incorporated herein by reference to Exhibit 4.2 to the  Registration Statement on Form S-1 (File No. 333-133983) filed by  Pinnacle Gas Resources, Inc. on May 10, 2006).                                       |
|        |       |                                                                                                                                                                                                                                                                                                |
| 10.1        | —     | Fourth Amendment to Credit Agreement, dated as of  April 14, 2009 (incorporated herein by reference to Exhibit 10.21  to the Annual Report on Form 10-K (File No. 001-33457) filed by  Pinnacle Gas Resources, Inc. on April 15, 2009).                               |
|        |       |                                                                                                                                                                                                                                                                                                |
| *31.1       | —     | Certification of President and Chief Executive  Officer of Pinnacle Gas Resources, Inc. pursuant to Section 302 of  the Sarbanes-Oxley Act of 2002.                                                                                                                                       |
|        |       |                                                                                                                                                                                                                                                                                                |
| *31.2       | —     | Certification of Senior Vice President, Chief  Financial Officer and Secretary of Pinnacle Gas Resources, Inc. pursuant  to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                |
|        |       |                                                                                                                                                                                                                                                                                                |
| *32.1       | —     | Certification of President and Chief Executive  Officer of Pinnacle Gas Resources, Inc. pursuant to 18 U.S.C.  Section 1350, as adopted pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002.                                                                                  |
|        |       |                                                                                                                                                                                                                                                                                                |
| *32.2       | —     | Certification of Senior Vice President, Chief  Financial Officer and Secretary of Pinnacle Gas Resources, Inc. pursuant  to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of  the Sarbanes-Oxley Act of 2002.                                                           |

 

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*              Filedherewith

 

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**SIGNATURES**

 

Pursuant to the requirements of the SecuritiesExchange Act of 1934, the registrant has duly caused this report to be signedon its behalf by the undersigned thereunto duly authorized.

 
|        | PINNACLE GAS  RESOURCES, INC. |
|--------|-------------------------------|
|   |                          |   |
|   | By:                           | /s/ Peter G. Schoonmaker |
|   | Name:                         | Peter G. Schoonmaker |
|   | Title:                        | *President, Chief Executive Officer and Director* |
|   |                          | (Principal Executive Officer) |
|   |                          |   |
|   | Date:                         | May 15,  2009 |
|   |                          |   |
|   | By:                           | /s/ Ronald T.  Barnes |
|   | Name:                         | Ronald T. Barnes |
|   | Title:                        | *Senior  Vice President, Chief Financial Officer and Secretary* |
|   |                          | (Principal  Financial Officer and Principal Accounting Officer) |
|   |                          |   |
|   | Date:                         | May 15,  2009 |

 

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