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**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

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**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  the quarterly period ended June 30, 2008**                                                                                                                                                                                                                                                                                                                                |
|   |       |                                                                                                                                                                                                                                                                                                                                                                                  |
|   |       | **or**                                                                                                                                                                                                                                                                                                                                                                                |
|   |       |                                                                                                                                                                                                                                                                                                                                                                                  |
| **o**  | ** ** | **TRANSITION REPORT PURSUANT TO  SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**                                                                                                                                                                                                                                                                               |
|   |       |                                                                                                                                                                                                                                                                                                                                                                                  |
|   | ** ** | **For  the transition period from                            to                            ** |

 

**Commissionfile number: 001-33457**

 

**Pinnacle Gas Resources, Inc.**

(Exact name 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 telephone number, including area code)

 

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Indicate by check mark whether the registrant (1) has filed allreports required to be filed by Section 13 or 15(d) of the SecuritiesExchange Act of 1934 during the preceding 12 months (or for such shorter periodthat the registrant was required to file such reports), and (2) has beensubject to such filing requirements for the past 90 days. Yes x No £

 

Indicate by check mark whether the registrant is a large acceleratedfiler, an accelerated filer, a non-accelerated filer or a smaller reportingcompany. See the definitions of “large accelerated filer,” “accelerated filer”and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Checkone):
| Large  accelerated filer £ |   | Accelerated  filer £ |   | Non-accelerated filer x                        |   | Smaller  reporting company £ |
|---------------------------------|--------|---------------------------|--------|------------------------------------------------|--------|-----------------------------------|
|                            |   |                      |   | (Do not check if  a smaller reporting company) |

 

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

 

29,085,551 shares of the registrant’s Common Stock were outstanding asof August 11, 2008.

 

 

 

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**PINNACLEGAS RESOURCES, INC.**

 

**Indexto Form 10-Q**

 
| ** **                                                                                          | ** ** | **Page** |
|-----------------------------------------------------------------------------------------------------|------------|----------|
| **Cautionary  Statement Concerning Forward-Looking Statements**                                     |       | 1        |
| **Part I.  FINANCIAL INFORMATION**                                                             |       | 3        |
| Item 1.  Financial Statements                                                                       |       | 3        |
| Balance Sheets                                                                                      |       | 3        |
| Statement  of Operations                                                                            |       | 4        |
| Statement of  Cash Flows                                                                            |       | 5        |
| Statement  of Stockholders’ Equity                                                             |       | 6        |
| Notes  to Financial Statements                                                                      |       | 7        |
| Item 2. Management’s Discussion and Analysis of  Financial Condition and Results of Operations |       | 17       |
| Overview                                                                                            |       | 17       |
| Critical Accounting Policies                                                                        |       | 17       |
| Trends Affecting Our Business                                                                       |       | 22       |
| Results  of Operations                                                                              |       | 22       |
| Liquidity and Capital Resources                                                                     |       | 26       |
| Item 3. Quantitative and Qualitative Disclosures About  Market Risk                                 |       | 29       |
| Commodity Price Risk                                                                                |       | 29       |
| Interest Rate Risk                                                                                  |       | 30       |
| Item 4T. Controls and Procedures                                                                    |       | 30       |
| Disclosure Controls and Procedures                                                                  |       | 30       |
| Changes in Internal Control Over Financial Reporting                                                |       | 30       |
| **Part II.  OTHER INFORMATION**                                                                |       | 30       |
| Item  1. Legal Proceedings                                                                          |       | 30       |
| Item  1A. Risk Factors                                                                              |       | 30       |
| 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                                        |       | 32       |
| Item  5. Other Information                                                                          |       | 32       |
| Item 6.  Exhibits                                                                                   |       | 32       |

 

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**CAUTIONARY STATEMENT CONCERNINGFORWARD-LOOKING STATEMENTS**

 

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

 

·**               **projections and estimates concerning the timing andsuccess of specific projects;

 

·**               **our financial position or operating results;

 

·**               **our business strategy;

 

·**               **our budgets;

 

·**               **the amount, nature and timing of capital expenditures;

 

·**               **the drilling of wells;

 

·**               **the development of recently acquired natural gas andoil properties;

 

·**               **the timing and amount of future production of naturalgas and oil;

 

·**               **our operating costs and other expenses;

 

·**               **our estimated future net revenues from natural gas andoil 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 othersimilar expressions, the statements which include those words are usuallyforward looking statements. When we describe strategy that involves risks oruncertainties, we are making forward looking statements. The forward lookingstatements in this quarterly report on Form 10-Q speak only as of the dateof this report. We disclaim any obligation to update these statements unlessrequired by securities law, and we caution you not to rely on them unduly. Wehave based these forward looking statements on our current expectations andassumptions about future events. While our management considers theseexpectations and assumptions to be reasonable, they are inherently subject tosignificant business, economic, competitive, regulatory and other risks,contingencies and uncertainties, most of which are difficult to predict andmany of which are beyond our control. These risks, contingencies anduncertainties relate to, among other matters, the following:

 

·**               **our ability to implement our business strategy;

 

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

 

·**               **fluctuations in the commodity prices for natural gasand crude oil;

 

·**               **engineering, mechanical or technological difficultieswith operational equipment, in well completions and workovers, and in drillingnew wells;

 

·**               **the effects of government regulation and permittingand other legal requirements;

 

·**               **labor problems;

 

·**               **environmental related problems;

 

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·**               **the uncertainty inherent in estimating future naturalgas and oil production or reserves;

 

·**               **production variances from expectations;

 

·**               **the substantial capital expenditures required forconstruction of pipelines and the drilling of wells and the related need tofund such capital requirements through commercial banks and/or publicsecurities markets;

 

·**               **disruptions of, capacity constraints in or otherlimitations on our or others’ pipeline systems;

 

·**               **our ability to effectively market our production;

 

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

 

·**               **our ability to develop and replace reserves;

 

·**               **our dependence upon key personnel;

 

·**               **the lack of liquidity of our equity securities;

 

·**               **operating hazards attendant to the natural gas and oilbusiness, including down-hole drilling and completion risks that are generallynot recoverable from third parties or insurance;

 

·**               **potential mechanical failure or under performance ofsignificant wells;

 

·**               **climatic conditions or natural disasters;

 

·**               **acts of terrorism;

 

·**               **the availability and cost of materials and equipment;

 

·**               **delays in anticipated start-up dates;

 

·**               **our ability to find and retain skilled personnel;

 

·**               **the availability of capital;

 

·**               **competition from, and the strength and financialresources of, our competitors;

 

·**               **general economic conditions; and

 

·**               **regional price differentials.

 

When you consider these forward-looking statements, you should keep inmind these factors and the other factors discussed in the “Risk Factors”section of our annual report on Form 10-K for the year ended December 31,2007 and this quarterly report on Form 10-Q.

 

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**PART I. FINANCIAL INFORMATION**

 

**ITEM 1. FINANCIAL STATEMENTS**

 

**PINNACLE GAS RESOURCES, INC.**

**BalanceSheets**

 
| ** **                                                                                                                                                                         | ** ** | **June 30,  2008**                                                        | ** ** | **December 31,  2007** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                                                                                                                         | ** ** | **(unaudited)**                                                                | ** ** | ** **                  | ** ** |
| ** **                                                                                                                                                                         | ** ** | **(in thousands, except  share and  per share data)** | ** ** |
| **Assets**                                                                                                                                                                         |       |                                                                           |       |                        |       |
| Current assets                                                                                                                                                                     |       |                                                                           |       |                        |       |
| Cash and cash equivalents                                                                                                                                                          |       | $                                                                              | 1,172      |                        | $          | 8,151 |   |
| Deposits                                                                                                                                                                           |       | 643                                                                            |       | —                      |       |
| Receivables                                                                                                                                                                        |       |                                                                           |       |                        |       |
| Accrued gas sales                                                                                                                                                                  |       | 4,497                                                                          |       | 3,062                       |       |
| Joint interest receivables, net of $100 allowance  for doubtful accounts                                                                                                           |       | 8,580                                                                          |       | 6,040                       |       |
| Derivative instruments                                                                                                                                                             |       | —                                                                         |       | 556                         |       |
| Inventory of material for drilling and completion                                                                                                                                  |       | 134                                                                            |       | 174                         |       |
| Prepaid expenses                                                                                                                                                                   |       | 178                                                                            |       | 1,322                       |       |
| Total current assets                                                                                                                                                               |       | 15,204                                                                         |       | 19,305                      |       |
| Property and equipment, at cost, net of accumulated  depreciation                                                                                                                  |       | 2,095                                                                          |       | 2,226                       |       |
| Oil and gas properties, using full cost accounting,  net of accumulated depletion and impairment                                                                                   |       |                                                                           |       |                        |       |
| Proved                                                                                                                                                                             |       | 43,846                                                                         |       | 33,965                      |       |
| Unproved                                                                                                                                                                           |       | 92,701                                                                         |       | 88,820                      |       |
| Inventory held for exploration and development                                                                                                                                     |       | 390                                                                            |       | 505                         |       |
| Deposits, non-current                                                                                                                                                              |       | —                                                                         |       | 20                          |       |
| Restricted certificates of deposit, non-current                                                                                                                                    |       | 2,718                                                                          |       | 1,752                       |       |
| Total assets                                                                                                                                                                       |       | $                                                                              | 156,954    |                        | $          | 146,593 |   |
| **Liabilities and Stockholders’ Equity**                                                                                                                                      |       |                                                                           |       |                        |       |
| Current liabilities                                                                                                                                                                |       |                                                                           |       |                        |       |
| Long-term debt, current portion                                                                                                                                                    |       | $                                                                              | 24         |                        | $          | 23 |   |
| Derivative instruments, current                                                                                                                                                    |       | 5,035                                                                          |       | —                      |       |
| Trade accounts payable                                                                                                                                                             |       | 13,103                                                                         |       | 7,767                       |       |
| Revenue distribution payable                                                                                                                                                       |       | 8,348                                                                          |       | 6,534                       |       |
| Drilling prepayments from joint interest owners                                                                                                                                    |       | 9                                                                              |       | 28                          |       |
| Asset retirement obligations, current                                                                                                                                              |       | 380                                                                            |       | 363                         |       |
| Accrued liabilities                                                                                                                                                                |       | 2,511                                                                          |       | 2,241                       |       |
| Total current liabilities                                                                                                                                                          |       | 29,410                                                                         |       | 16,956                      |       |
| Asset retirement obligations,  non-current                                                                                                                                         |       | 2,774                                                                          |       | 2,404                       |       |
| Derivative instruments, non-current                                                                                                                                                |       | 875                                                                            |       | —                      |       |
| Production taxes, non-current                                                                                                                                                      |       | 1,401                                                                          |       | 633                         |       |
| Long-term debt, non-current                                                                                                                                                        |       | 5,751                                                                          |       | 763                         |       |
| Total liabilities                                                                                                                                                                  |       | 40,211                                                                         |       | 20,756                      |       |
| Contingencies                                                                                                                                                                      |       |                                                                           |       |                        |       |
| Series A Redeemable Preferred stock, $0.01 par  value; 25,000,000 authorized, 0 shares issued and outstanding at  June 30, 2008 and December 31, 2007, respectively |       | —                                                                         |       | —                      |       |
| Stockholders’ equity                                                                                                                                                          |       |                                                                           |       |                        |       |
| Common stock, $0.01 par value; 100,000,000  authorized and 29,000,101 and 29,019,751 shares issued and outstanding at  June 30, 2008 and December 31, 2007, respectively |       | 289                                                                            |       | 289                         |       |
| Additional paid-in capital                                                                                                                                                         |       | 150,128                                                                        |       | 149,701                     |       |
| Accumulated deficit                                                                                                                                                                |       | (33,674                                                                        | )          | (24,153                     | )          |
| Total stockholders’ equity                                                                                                                                                    |       | 116,743                                                                        |       | 125,837                     |       |
| Total liabilities and stockholders’ equity                                                                                                                                    |       | $                                                                              | 156,954    |                        | $          | 146,593 |   |

 

See Notes toFinancial Statements (unaudited)

 

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**Statements of Operations**

**(unaudited)**

 
| ** **                                                    | ** ** | **Three Months Ended  June 30,**                                    | ** ** | **Six Months Ended  June 30,** | ** ** |
|---------------------------------------------------------------|------------|------------------------------------------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                                    | ** ** | **2008**                                                                           | ** ** | **2007**                                      | ** ** | **2008** | ** ** | **2007** | ** ** |
| ** **                                                    | ** ** | **(in thousands, except share and  per share data)** | ** ** | ** **                                    | ** ** | ** ** | ** ** |
| Revenues                                                      |       |                                                                               |       |                                          |       |   |   |   |   |
| Gas sales                                                     |       | $                                                                                  | 7,573      |                                          | $          | 3,436 |   | $ | 13,234 |   | $ | 7,090 |   |
| Total revenues                                                |       | 7,573                                                                              |       | 3,436                                         |       | 13,234 |   | 7,090 |   |
| Cost of revenues and expenses                                 |       |                                                                               |       |                                          |       |   |   |   |   |
| Lease operating expenses                                      |       | 1,348                                                                              |       | 1,219                                         |       | 3,398 |   | 2,136 |   |
| Production taxes                                              |       | 860                                                                                |       | 357                                           |       | 1,519 |   | 759 |   |
| Marketing and transportation                                  |       | 1,210                                                                              |       | 898                                           |       | 2,287 |   | 1,683 |   |
| General and administrative, net                               |       | 3,217                                                                              |       | 1,220                                         |       | 4,591 |   | 2,327 |   |
| Depreciation, depletion, amortization and accretion           |       | 2,284                                                                              |       | 1,612                                         |       | 4,013 |   | 3,096 |   |
| Impairment of oil and gas properties                          |       | —                                                                             |       | 1,151                                         |       | — |   | 18,155 |   |
| Total cost of revenues and expenses                           |       | 8,919                                                                              |       | 6,457                                         |       | 15,808 |   | 28,156 |   |
| Operating loss                                                |       | (1,346                                                                             | )          | (3,021                                        | )          | (2,574 | ) | (21,066 | ) |
| Other income (expense)                                        |       |                                                                               |       |                                          |       |   |   |   |   |
| Gain (loss) on derivatives                                    |       | (2,664                                                                             | )          | 664                                           |       | (7,235 | ) | 465 |   |
| Interest income                                               |       | 34                                                                                 |       | 251                                           |       | 99 |   | 298 |   |
| Other income                                                  |       | 122                                                                                |       | 113                                           |       | 223 |   | 224 |   |
| Interest expense                                              |       | (20                                                                                | )          | (78                                           | )          | (35 | ) | (142 | ) |
| Total other income (expense)                                  |       | (2,528                                                                             | )          | 950                                           |       | (6,948 | ) | 845 |   |
| Net loss before income taxes                                  |       | (3,874                                                                             | )          | (2,071                                        | )          | (9,522 | ) | (20,221 | ) |
| Income taxes                                                  |       | —                                                                             |       | —                                        |       | — |   | — |   |
| Net loss attributable to common stockholders                  |       | $                                                                                  | (3,874     | )                                             | $          | (2,071 | ) | $ | (9,522 | ) | $ | (20,221 | ) |
| Basic and diluted net loss per share                          |       | $                                                                                  | (0.13      | )                                             | $          | (0.08 | ) | $ | (0.33 | ) | $ | (0.79 | ) |
| Weighted average shares outstanding — basic and  diluted |       | 29,000,101                                                                         |       | 27,115,114                                    |       | 29,008,000 |   | 25,517,025 |   |

 

See Notes toFinancial Statements (unaudited)

 

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**Statements of Cash Flows**

**(inthousands)**

**(unaudited)**

 
| ** **                                                                                  | ** ** | **For the Six Months  Ended  June 30,** | ** ** |
|---------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|
| ** **                                                                                  | ** ** | **2008**                                                    | ** ** | **2007** | ** ** |
| Cash flows from operating activities                                                        |       |                                                        |       |   |   |
| Net loss                                                                                    |       | $                                                           | (9,522     | ) | $ | (20,221 | ) |
| Adjustments to reconcile net loss to net cash  provided by (used in) / operating activities |       |                                                        |       |   |   |
| Impairment of oil and gas properties                                                        |       | —                                                      |       | 18,155 |   |
| Depreciation, depletion, amortization and accretion                                         |       | 4,013                                                       |       | 3,096 |   |
| (Gain) Loss on derivatives                                                                  |       | 7,235                                                       |       | (465 | ) |
| Stock-based compensation                                                                    |       | 433                                                         |       | 362 |   |
| Changes in assets and liabilities                                                           |       |                                                        |       |   |   |
| (Increase) decrease in receivables                                                          |       | (3,975                                                      | )          | 4,023 |   |
| Decrease in inventory of material for drilling and  completion                              |       | 40                                                          |       | 32 |   |
| Decrease in prepaid expenses                                                                |       | 1,144                                                       |       | 30 |   |
| Increase (decrease) in trade accounts payable and  accrued liabilities and production taxes |       | 3,853                                                       |       | (10,283 | ) |
| Increase (decrease) in revenue distribution payable                                         |       | 1,814                                                       |       | (60 | ) |
| Decrease in drilling prepayments                                                            |       | (19                                                         | )          | (135 | ) |
| Net cash provided by (used in) operating activities                                         |       | 5,016                                                       |       | (5,466 | ) |
| Cash flows from investing activities                                                        |       |                                                        |       |   |   |
| Capital expenditures — exploration and production                                      |       | (14,377                                                     | )          | (11,491 | ) |
| Capital expenditures — property and equipment                                          |       | (358                                                        | )          | (421 | ) |
| Purchase of restricted certificate of deposit                                               |       | (966                                                        | )          | (5 | ) |
| (Increase) decrease in inventory held for  exploration and development                      |       | 115                                                         |       | (158 | ) |
| Deposits                                                                                    |       | (623                                                        | )          | (501 | ) |
| Realized gain (loss) on derivatives                                                         |       | (769                                                        | )          | 1,676 |   |
| Net cash used in investing activities                                                       |       | (16,978                                                     | )          | (10,900 | ) |
| Cash flows from financing activities                                                        |       |                                                        |       |   |   |
| Principal payments on note payable                                                          |       | (11                                                         | )          | (11 | ) |
| Proceeds from long-term debt                                                                |       | 5,000                                                       |       | — |   |
| Proceeds from the issuance of common stock                                                  |       | —                                                      |       | 33,750 |   |
| Issuance costs related to common stock                                                      |       | (6                                                          | )          | (4,010 | ) |
| Net cash provided by financing activities                                                   |       | 4,983                                                       |       | 29,729 |   |
| Net increase (decrease) in cash and cash equivalents                                        |       | (6,979                                                      | )          | 13,363 |   |
| Cash and cash equivalents at beginning of the year                                          |       | 8,151                                                       |       | 4,762 |   |
| Cash and cash equivalents at June 30, 2008 and  2007, respectively                     |       | $                                                           | 1,172      |   | $ | 18,125 |   |
| Non-cash investing and financing activities                                                 |       |                                                        |       |   |   |
| Capital expenditures included in trade accounts  payable                                    |       | $                                                           | 8,352      |   | $ | 1,368 |   |
| Asset retirement obligation included in oil and gas  properties                             |       | 268                                                         |       | 69 |   |
| Accrued offering costs                                                                      |       | —                                                      |       | 419 |   |
| Inventory used in oil and gas properties                                                    |       | —                                                      |       | 116 |   |
| Supplemental cash flow information                                                          |       |                                                        |       |   |   |
| Cash payments for interest, net of amount  capitalized                                      |       | $                                                           | 35         |   | $ | 64 |   |

 

See Notes toFinancial Statements (unaudited)

 

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**Statement of Stockholders’ Equity**

**(inthousands, except for share data)**

 
| ** **                                                          | ** ** | ** **            | ** ** | ** **        | ** ** | ** **              | ** ** | **Stockholders’ Equity** | ** ** | ** **  | ** ** |
|---------------------------------------------------------------------|------------|-----------------------|------------|-------------------|------------|-------------------------|------------|------------------------------------|------------|-------------|------------|
| ** **                                                          | ** ** | **Common Stock** | ** ** | **Warrants  and** | ** ** | **Additional  Paid-In** | ** ** | **Accumulated**                    | ** ** | ** **  | ** ** |
| ** **                                                          | ** ** | **Shares**            | ** ** | **Amount**        | ** ** | **Options**             | ** ** | **Capital**                        | ** ** | **Deficit** | ** ** | **Total** | ** ** |
|                                                                |       |                  |       |              |       |                    |       |                               |       |        |       |   |   |
| Balance at December 31, 2007                                   |       | 29,019,751            |       | $                 | 289        |                    | —     |                               | $          | 149,701     |       | $ | (24,152 | ) | $ | 125,838 |   |
| Forfeiture of restricted shares (unaudited)                         |       | (19,650               | )          | —            |       | —                  |       | —                             |       | —      |       | — |   |
| Offering costs related to the issuance of common  stock (unaudited) |       | —                |       | —            |       | —                  |       | (6                                 | )          | —      |       | (6 | ) |
| Stock-based compensation (unaudited)                                |       | —                |       | —            |       | —                  |       | 433                                |       | —      |       | 433 |   |
| Net loss (unaudited)                                                |       | —                |       | —            |       | —                  |       | —                             |       | (9,522      | )          | (9,522 | ) |
| Balance at June 30, 2008 (unaudited)                           |       | 29,000,101            |       | $                 | 289        |                    | —     |                               | $          | 150,128     |       | $ | (33,674 | ) | $ | 116,743 |   |

 

See Notes toFinancial Statements (unaudited)

 

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**Notes to Financial Statements**

**(Unaudited)**

 

**Note1 — Organization and Nature of Operations**

 

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

 

Pinnacle’s primary business is the exploration for, and theacquisition, development and production of, coalbed methane natural gas in theUnited States. The Company is also engaged in gas property operations and theconstruction of low pressure gas collection systems which providetransportation for the Company’s coalbed methane production.

 

**Note2 — Basis of Presentation**

 

The accompanying unaudited financial statements include the Company’sproportionate share of assets, liabilities, income and expenses from theproperties in which the Company has a participating interest. The Company hasno subsidiaries or affiliates with which intercompany transactions arerecorded.

 

The accompanying financial statements are unaudited, and in the opinionof management, reflect all adjustments that are necessary for a fair presentationof the financial position and results of operations for the periods presented.All such adjustments are of a normal and recurring nature. The following notesdescribe only the material changes in accounting policies, account details, orfinancial statement notes during the first six months of 2008. The results forthe three and six months ended June 30, 2008 are not necessarilyindicative of the results expected for the entire year. These financialstatements should be read in conjunction with the audited financial statementsand the summary of significant accounting policies for prior years contained onthe Company’s website *www.pinnaclegas.com*.

 

*Useof Estimates*

 

The preparation of the Company’s financial statements in conformitywith accounting principles generally accepted in the United States of Americarequires management to make estimates and assumptions that affect the reportedamount of assets and liabilities, disclosure of contingent assets andliabilities at the date of the financial statements and the reported amounts ofrevenues and expenses during the reporting period. Actual results could differfrom these estimates. Significant estimates with regard to the Company’sfinancial statements include the estimated carrying value of unproved properties,the estimate of proved oil and gas reserve volumes and the related presentvalue of estimated future net cash flows and the ceiling test applied tocapitalized oil and gas properties, the estimate of the timing and cost of theCompany’s future drilling activity, the estimated cost and timing related toasset retirement obligations, the estimated fair value of derivative assets andliabilities, the realizability of deferred tax assets, the estimates ofexpenses and timing of exercise of stock options, accrual of operating costsand capital expenditures and revenue.

 

*Oiland Gas Properties*

 

The Company utilizes the full cost method of accounting for oil and gasproducing activities. Under this method, all costs associated with propertyacquisition, exploration and development, including costs of unsuccessfulexploration, costs of surrendered and abandoned leaseholds, delay lease rentalsand the fair value of estimated future costs of site restoration, dismantlementand abandonment activities are capitalized within a cost center. The Company’soil and gas properties are all located within the United States, whichconstitutes a single cost center. The Company has not capitalized any overheadcosts. No gain or loss is recognized upon the sale or abandonment ofundeveloped or producing oil and gas properties unless the sale represents asignificant portion of gas properties and the gain significantly alters therelationship between capitalized costs and proved gas reserves of the costcenter. Expenditures for maintenance and repairs are charged to lease operatingexpense in the period incurred.

 

Depreciation, depletion and amortization of oil and gas properties (“DD&A”)is computed on the unit-of-production method based on proved reserves.Amortizable costs include estimates of future development costs of provedundeveloped reserves and asset retirement obligations. The Company invests inunevaluated oil and gas properties for the purpose of exploration for provedreserves. The costs of such assets, including exploration costs on propertieswhere a determination of whether proved oil and gas reserves will beestablished is still under evaluation, and any capitalized interest, areincluded in unproved oil and gas properties at the lower of cost or estimated fairmarket value and are not subject to amortization. On a quarterly basis, suchcosts are evaluated for inclusion in the 

 

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costs to be amortizedresulting from the determination of proved reserves, impairments, or reductionsin value. To the extent that the evaluation indicates these properties areimpaired, the amount of the impairment is added to the capitalized costs to beamortized. Abandonment of unproved properties is accounted for as an adjustmentto capitalized costs related to proved oil and gas properties, with no lossesrecognized. No impairment was recorded for unevaluated properties for the threeand six months ended June 30, 2008. Substantially all of the remainingunproved property costs are expected to be developed and included in theamortization base over the next three to five years. Salvage value is takeninto account in determining depletion rates and is based on the Company’sestimate of the value of equipment and supplies at the time the well isabandoned. As of June 30, 2008 and December 31, 2007, the estimatedsalvage value was approximately $7.1 million and $6.4 million, respectively.

 

Under full cost method of accounting rules, capitalized costs lessaccumulated depletion and related deferred income taxes may not exceed a “ceiling”value which is the sum of (1) the present value discounted at 10% ofestimated future net revenue using current prices and costs, including theeffects of derivative instruments designated as cash flow hedges but excludingthe future cash outflows associated with settling asset retirement obligationsthat have been accrued on the balance sheet, less any related income taxeffects; plus (2) the cost of properties not being amortized, if any; plus(3) the lower of costs or estimated fair value of unproved properties;less (4) the income tax effects related to differences in the book to taxbasis of oil and gas properties. This is referred to as the “full cost ceilinglimitation.” If capitalized costs exceed the limit, the excess must be chargedto expense. The expense may not be reversed in future periods. At the end ofeach quarter, the Company calculates the full cost ceiling limitation. At June 30,2008, the full cost ceiling limitation exceeded the capitalized cost of oil andgas by approximately $35.0 million based upon a natural gas price of $8.73 perMcf (based on the Colorado Interstate Gas Rocky Mountain Index) in effect atthat date. As a result, the Company was not required to record an impairmentfor the six months ended June 30, 2008. An impairment of approximately$18.2 million was recorded for the six months ended June 30, 2007. Theimpairment of the Company’s oil and gas properties resulted from low commodityprices throughout 2007, specifically at the end of the first, second and thirdquarters of 2007. A decline in gas prices or an increase in operating costssubsequent to the measurement date or reductions in economically recoverablereserve quantities could result in the recognition of additional impairments ofthe Company’s oil and gas properties in future periods.

 

*PerShare Information*

 

Basic loss per share is computed by dividing net loss from continuingoperations attributable to common stock by the weighted average number ofshares of common stock outstanding during each period. Diluted earnings pershare is computed by adjusting the average number of shares of common stockoutstanding for the dilutive effect, if any, of common stock equivalents suchas stock options and warrants. Diluted net loss per share was the same as basicloss per share for the three and six months ended June 30, 2007 and 2008because potential common stock equivalents were anti-dilutive.

 

Certain options to purchase shares of Pinnacle’s common stock wereexcluded from the dilution calculations because the shares were anti-dilutive.At June 30, 2008, 750,000 options were excluded because they wereanti-dilutive. At June 30, 2007, 990,000 options were excluded becausethey were anti-dilutive.

 

*General and Administrative Expenses*

 

General and administrative expenses are reported net of amountsallocated and billed to working interest owners of gas properties operated by theCompany. The administrative expenses billed to working interest owners maychange in accordance with the terms of the joint operating agreements.Administrative expenses are charged to working interest owners based onproductive well counts. A 10% change in well counts for the six months ended June 30,2008 would have increased or decreased the Company’s expenses billed to workinginterest owners by approximately $91,000. As the Company operates and drillsadditional wells in the future, additional administrative expenses will becharged to the working interest owners when the wells become productive.General and administrative expenses for the six months ended June 30, 2008also include $2.1 million of merger related costs attributable to the failedmerger with Quest Resource Corporation. Any future costs associated with any merger, acquisition or divestiturewill be expensed in the period of the transaction outcome.

 

*IncomeTaxes*

 

The Company uses the asset and liability method of accounting forincome taxes, in accordance with Statement of Financial Accounting Standards (“SFAS”)No. 109, “Accounting for Income Taxes.” Deferred tax assets andliabilities are recognized for the expected future tax consequences oftemporary differences between the financial statements and tax basis of assetsand liabilities. If appropriate, deferred tax assets are reduced by a valuationallowance which reflects expectations of the extent to which such assets willbe realized. As of June 30, 2008 and December 31, 2007, the Companyhad recorded a full valuation allowance for its net deferred tax asset.

 

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On January 1, 2007, the Company adopted the provisions of FIN 48, “Accountingfor Uncertainty in Income Taxes.” FIN 48 prescribes a recognition threshold andmeasurement attribute for the financial statement recognition and measurementof a tax position taken or expected to be taken in a tax return. FIN 48requires that the Company recognize in its consolidated financial statementsonly those tax positions that are “more-likely-than-not” of being sustained asof the adoption date, based on the technical merits of the position. As aresult of the implementation of FIN 48, the Company performed a comprehensivereview of its material tax positions in accordance with recognition andmeasurement standards established by FIN 48.

 

As a result of this review, the Company did not identify any materialtax positions that required adjustment. As of January 1, 2007, the date ofadoption of FIN 48, and as of June 30, 2008, the Company had not accruedany interest or penalties related to any material uncertain tax positions.

 

The Company is subject to the following material taxing jurisdictions:U.S. federal. The Company also has material operations in the state of Wyoming;however, Wyoming does not impose a corporate income tax. The tax years thatremain open to examination by the U.S. Internal Revenue Service are years 2004through 2007. Due to the Company’s net operating loss carry forwards, theInternal Revenue Service may also adjust the amount of loss realizable underexamination back to 2003.

 

*RecentAccounting Pronouncements*

 

In September 2006, the Financial Accounting Standards Board (“FASB”)issued SFAS No. 157, “Fair Value Measurements,” which defines fair value,establishes a framework for measuring fair value in generally acceptedaccounting principles, and expands disclosures about fair value measurements.SFAS No. 157 applies under other accounting pronouncements that require orpermit fair value measurements. Accordingly, SFAS No. 157 does not requireany new fair value measurements. However, for some entities, the application ofSFAS No. 157 will change current practice. SFAS No. 157 was effectiveas of January 1, 2008. However, FASB Financial Staff Position No. FAS157-2 deferred implementation for other non-financial assets and liabilities untilJanuary 1, 2009. The adoption of SFAS No. 157 did not have a materialimpact on the Company’s financial position but caused additional disclosure.Please see Note 8 — Fair Value Measurements.

 

In February 2007, the FASB issued SFAS No. 159, “The FairValue Option for Financial Assets and Financial Liabilities.” SFAS No. 159permits entities to choose to measure eligible financial instruments andcertain other items at fair value. The objective is to improve financialreporting by providing entities with the opportunity to mitigate volatility inreported earnings caused by measuring related assets and liabilitiesdifferently without having to apply complex hedge accounting provisions. SFAS No. 159was effective as of January 1, 2008 for us. SFAS No. 159 offersvarious options in electing to apply the provisions of SFAS No. 159. TheCompany decided not to elect fair value accounting for any of its eligibleitems other than derivatives (See Note 7) which were being accounted for undera fair value method prior to the adoption of SFAS No. 159.

 

In December 2007, the FASB issued SFAS No. 141(R), “BusinessCombinations,” which requires the acquiring entity in a business combination torecognize and measure all assets and liabilities assumed in the transaction andany non-controlling interest in the acquiree at fair value as of theacquisition date. SFAS No. 141 (R) also establishes guidance for themeasurement of the acquirer shares issued in consideration for a businesscombination, the recognition of contingent consideration, the accountingtreatment pre-acquisition gain and loss contingencies, the treatment ofacquisition 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) willbe effective for the Company beginning with the 2009 fiscal year. The Companyis evaluating the potential impact of SFAS No. 141(R), if any, on itsfinancial statements.

 

In December 2007, the FASB issued SFAS No. 160, “NoncontrollingInterest in Consolidated Financial Statements — an amendment of ARB 51,” whichestablishes accounting and reporting standards that require noncontrollinginterests to be reported as a component of equity. SFAS No. 160 alsorequires that changes in a parent’s ownership interest while the parent retainsits controlling interest be accounted for as equity transactions and that anyretained noncontrolling equity investment upon the deconsolidation of asubsidiary be initially measured at fair value. SFAS No. 160 is effectivefor fiscal years beginning after December 15, 2008 and is to be appliedprospectively as of the beginning of the fiscal year in which the statement isapplied. SFAS No. 160 will be effective for the Company beginning with the2009 fiscal year. The Company is evaluating the potential impact of SFAS No. 160,if any, on the Company’s financial statements.

 

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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 FAS No. 133, and how derivative instruments and related hedgeditems affect its financial position, financial performance and cash flows. SFASNo. 161 is effective for financial statements issued for fiscal years andinterim periods beginning after November 15, 2008. The Company does notbelieve the adoption of SFAS No. 161 will have a significant effect on itsfinancial statements.

 

**Note3 — Asset Retirement Obligations**

 

The Company follows the provisions of 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 normal operation of along-lived asset. SFAS No. 143 requires the Company to recognize anestimated liability for costs associated with the abandonment of its oil andgas 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 remainingeconomic life of the respective oil and gas properties.

 

The estimated liability is based on historical gas industry experiencein abandoning wells, including estimated economic lives, external estimates asto the cost to abandon the wells in the future and federal and state regulatoryrequirements. The Company’s liability is discounted using the Company’s bestestimate of its credit-adjusted risk free rate. Revisions to the liabilitycould occur due to changes in estimated abandonment costs or changes in welleconomic lives or if federal or state regulators enact new requirementsregarding the abandonment of wells.

 

The following is a summary of the Company’s asset retirement obligationactivity for the three and six months ended June 30, 2008 and June 30,2007 (unaudited).

 
| ** **                                     | ** ** | **For the Three  Months Ended  June 30,** | ** ** | **For the Six  Months Ended  June 30,** | ** ** | **For the Three  Months Ended  June 30,** | ** ** | **For the Six  Months Ended  June 30,** | ** ** |
|------------------------------------------------|------------|---------------------------------------------------------------|------------|-------------------------------------------------------------|------------|---------------------------------------------------------------|------------|-------------------------------------------------------------|------------|
| ** **                                     | ** ** | **2008**                                                      | ** ** | **2007**                                                    | ** ** |
| Beginning balance asset retirement obligations |       | $                                                             | 2,926      |                                                        | $          | 2,767                                                         |       | $                                                           | 2,438      |   | $ | 2,321 |   |
| Additional obligation added during the period  |       | 167                                                           |       | 268                                                         |       | 45                                                            |       | 113                                                         |       |
| Accretion expense                              |       | 61                                                            |       | 119                                                         |       | 50                                                            |       | 99                                                          |       |
| Ending balance of asset retirement obligations |       | $                                                             | 3,154      |                                                        | $          | 3,154                                                         |       | $                                                           | 2,533      |   | $ | 2,533 |   |

 

**Note4 — Restricted Certificates of Deposit and Deposits**

 

*Restricted Certificates of Deposit.*The Company holds a certificate ofdeposit (“CD”), which expires in July 2009, totaling $150,000. The CD iscollateral on bonding required by the State of Wyoming, the State of Montanaand the Federal Bureau of Land Management. Because the Company intends to renewthe CD in order to maintain its bonding requirements, the Company has includedthe CD in non-current assets as of June 30, 2008. Additionally, theCompany holds two CDs for $604,000 and $964,000 which were issued in February 2006and May 2008 and which expire in February 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 this amount in non-current assets as of June 30, 2008 becausethe Company also intends to renew these CDs in order to maintain a power supplyon a long-term basis. In April 2006, the Company issued a $1,000,000letter of credit that expires in April 2009 in favor of Bitter CreekPipelines, 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 June 30, 2008because the Company anticipates that the construction of the pipeline andcompression facility will not be completed and fully utilized until the end of2009.

 

*Deposits.*The Company included approximately$153,000 related to royalty payments in deposits. These amounts are included indeposits in the balance sheet at June 30, 2008.  The Company has also included $490,000 indeposits for pipe to be purchased in the third quarter of 2008.

 

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**Note 5 — Derivatives**

 

The Companyaccounts for derivative instruments or hedging activities under the provisionsof SFAS No. 133, “Accounting for Derivative Instruments and HedgingActivities.” SFAS No. 133 requires the Company to record derivativeinstruments at their fair value. If the derivative is designated as a fairvalue hedge, the changes in the fair value of the derivative and of the hedgeditem attributable to the hedged risk are recognized in earnings. If thederivative is designated as a cash flow hedge, the effective portions ofchanges in the fair value of the derivative are recorded in other comprehensiveincome (loss) and are recognized in the statement of operations when the hedgeditem affects earnings. Ineffective portions of changes in the fair value ofcash flow hedges, if any, are recognized in earnings. Changes in the fair valueof derivatives that do not qualify for hedge treatment are recognized inearnings.

 

The Companyperiodically hedges a portion of its oil and gas production through swap andcollar agreements. The purpose of the hedges is to provide a measure ofstability to the Company’s cash flows in an environment of volatile oil and gasprices and to manage the exposure to commodity price risk. Management of theCompany decided not to use hedge accounting for these agreements. Therefore, inaccordance with the provisions of SFAS No. 133, the changes in fair marketvalue are recognized in earnings.

 

As of June 30,2008 and 2007, the Company had natural gas hedges in place as follows:

 
| **Product and Type of Hedging Contract** | ** ** | **MMbtu Per  Day** | ** ** | **Fixed Price  Range  CIG Index Price** | ** ** | **Time  Period** | ** ** |
|-------------------------------------------------------------------|------------|-------------------------|------------|--------------------------------------------------------|------------|------------------|------------|
| June 30, 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      |       |
| June 30, 2007 (unaudited)                                    |       |                    |       |                                                   |       |             |       |
| Natural Gas—Collar                                           |       | 1,000                   |       | $5.00–$5.20                                       |       | 10/04-09/07      |       |
| Natural Gas—Collar                                           |       | 1,000                   |       | $6.50–$10.50                                      |       | 09/06-12/07      |       |
| Natural Gas—Collar                                           |       | 3,000                   |       | $7.00–$9.05                                       |       | 01/07-12/07      |       |
| Natural Gas—Collar                                           |       | 3,000                   |       | $6.50–$8.20                                       |       | 01/08-12/08      |       |

 

The Companyrealized a hedging loss of $676,000 and realized a hedging gain of $1,240,000for the three months ended June 30, 2008 and 2007, respectively.  As a result of the change in the fair valueof the commodity derivatives, the Company had an unrealized loss of $1,988,000for the three months ended June 30, 2008 and an unrealized loss of$576,000 for the three months ended June 30, 2007.  The aggregate of these contracts resulted inthe loss on derivatives of $2,664,000 and a gain on derivatives of $664,000 forthe three months ended June 30, 2008 and 2007, respectively.  For the six months ended June 30, 2008,the Company realized a hedging loss of $769,000 compared to a hedging gain of$1,676,000 for the six months ended June 30, 2007.  The Company had an unrealized loss of$6,466,000 and $1,211,000 for the six months ended June 30, 2008 and 2007,respectively.  The aggregate of thesecontracts resulted in a loss of derivatives of $7,235,000 and a gain of$465,000 for the six months ended June 30, 2008 and 2007,respectively.  Unrealized and realizedgains and losses are included in gains or losses on derivatives in theaccompanying statements of operations. Because the Company’s derivative contracts were not accounted for ascash flow hedges, the Company classifies the realized gains and losses in theinvestment activities in the accompanying statements of cash flows.

 

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**

 

*Optionsunder Employee Option Plans*

 

The Company hasadopted a stock incentive plan containing both incentive and non-statutorystock options. All options allow for the purchase of common stock at prices notless than the fair market value of such stock at the date of grant. If theoption holder owns more than 10% of the total combined voting power of allclasses of the Company’s stock, the exercise price cannot be less than 110% ofthe fair market value of such stock at the date of grant.

 

Options grantedunder the plan become vested as directed by the Company’s Board of Directorsand generally expire seven or ten years after the date of grant, unless the optionholder owns more than 10% of the total combined voting power of all classes ofthe 

 

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Company’s stock, in whichcase the non-statutory stock options must be exercised within five years of thedate of grant. At June 30, 2008, there were options to purchase 750,000shares granted under the plan.

 

The options granted sinceformation in June 2003 vest in general as follows:

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

 

*Stock-BasedCompensation*

 

At June 30,2008, the Company had unvested options to purchase 249,250 shares with aweighted average grant date fair value of $741,000. During the three months endedJune 30, 2008, the Company did not grant any options to purchase commonstock. The Company will recognize compensation expense relating to non-vestedoptions granted after January 1, 2006 ratably over the next threeyears.  During the three and six monthsended June 30, 2008, the Company recognized compensation expense ofapproximately $158,000 and $256,000, respectively, based on the fair value ofthe vested options.

 

The followingtable summarizes stock option activity for the six months ended June 30,2008:

 
| ** **                                  | ** ** | **Number of  Shares** | ** ** | **Weighted Average  Exercise Price  Per Share** | ** ** | **Weighted  Average  Remaining  Contractual Life** | ** ** | **Aggregate  Intrinsic value** | ** ** |
|---------------------------------------------|------------|----------------------------|------------|----------------------------------------------------------------|------------|---------------------------------------------------------|------------|-------------------------------------|------------|
| Outstanding, December 31, 2007         |       | 871,000                    |       | $                                                              | 6.56       |                                                    |       |                                |       |   |
| Canceled or forfeited                       |       | (121,000                   | )          | 7.37                                                           |       |                                                    |       |                                |       |
| Outstanding, June 30, 2008 (unaudited) |       | 750,000                    |       | $                                                              | 6.42       |                                                    | 3.90       |                                | $          | — |   |
| Exercisable, June 30, 2008 (unaudited) |       | 500,750                    |       | $                                                              | 5.72       |                                                    | 3.83       |                                | $          | — |   |

 

The followingtable summarizes information about stock options outstanding at June 30,2008:

 
| ** **               | ** ** | **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    |                                                    | 2.3 years  |                    | 137,500    |   | $ | 4.00 |   | Black-Scholes (minimum  value) |   |
| $                        | 4.80       |                                    | 282,500    |                                                    | 3.8 years  |                    | 216,250    |   | $ | 4.80 |   | Black-Scholes (minimum  value) |   |
| $                        | 5.20       |                                    | 112,500    |                                                    | 4.5 years  |                    | 56,250     |   | $ | 5.20 |   | Black-Scholes |   |
| $                        | 8.40       |                                    | 25,000     |                                                    | 5.9 years  |                    | 5,000      |   | $ | 8.40 |   | Black-Scholes |   |
| $                        | 11.00      |                                    | 192,500    |                                                    | 4.9 years  |                    | 85,750     |   | $ | 11.00 |   | Black-Scholes |   |
| Total                    |       | 750,000                                 |       |                                                    |       | 500,750                 |       |   |   |   |   |

 

*RestrictedStock*

 

The Company has astock incentive plan whereby grants of restricted stock have been awarded tomembers of the Board of Directors and certain executives and employees.Restrictions and vesting periods for the awards are determined at thediscretion of the Board of Directors and are set forth in the award agreements.

 

During the threeand six months ended June 30, 2008, the Company recognized compensationexpense of approximately $71,000 and $178,000, respectively, based on the fairvalue of the vested shares.

 

A summary of thestatus and activity of the restricted stock for the six months ended June 30,2008 is presented below.

 

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| ** **                                   | ** ** | **Shares** | ** ** | **Weighted-  Average  Grant-Date  Fair Value** | ** ** |
|----------------------------------------------|------------|------------|------------|-----------------------------------------------------|------------|
| Non-vested at December 31, 2007         |       | 147,540    |       | $                                                   | 8.57       |   |
| Forfeited                                    |       | (10,560    | )          | $                                                   | 7.45       |   |
| Vested                                       |       | (26,090    | )          | $                                                   | 11.00      |   |
| Non-vested at June 30, 2008 (unaudited) |       | 110,890    |       | $                                                   | 7.91       |   |

 

As of June 30,2008, the Company had approximately $706,000 of unrecognized share-basedcompensation expense related to non-vested stock awards, which is expected tobe amortized over the remaining vesting periods of three to five years.

 

**Note 7 —Long-Term Debt**

 

*CreditFacility*

 

Effective February 12,2007, the Company entered into a new $100 million credit facility (the “CreditAgreement”) with The Royal Bank of Scotland (“RBS”), with an initial commitmentof $27 million which permits borrowings up to the borrowing base as designatedby the administrative agent. As of June 30, 2008, the borrowing base underthe Credit Agreement was $17.8 million, although the Company’s actual borrowingavailability was approximately $6.6 million due to covenant limitations, ofwhich $5.0 million of debt was outstanding under the Credit Agreement.

 

The borrowing baseis determined on a semi-annual basis and at such other times as may berequested by the borrower or administrative agent. As part of the annualborrowing base redetermination, in April 2008, the Company entered into aletter agreement with the administrative agent whereby the borrowing base underthe credit facility will be automatically reduced on a monthly basis until aformal determination or redetermination of the borrowing base comes intoeffect. Under such agreement, the borrowing base may be reduced from $17.8million on June 30, 2008 to $16.5 million on October 1, 2008.However, we expect that a redetermination of our borrowing base will occur inSeptember 2008.

 

Borrowing underthe Credit Agreement bears interest either: (i) at a domestic bank rateplus an applicable margin between 0.25% and 1.25% per annum based onutilization or (ii) on a sliding scale from the one, two, three, or sixmonth LIBOR rate plus 1.25% to 2.25% per annum based on utilization. The CreditAgreement matures February 12, 2011, and replaced the Company’s previouscredit facility. The Credit Agreement with RBS is collateralized bysubstantially all of the Company’s producing assets.

 

The CreditAgreement contains covenants that, among other things, restrict the Company’sability, subject to certain exceptions, to do the following:

 

·**               **incur liens;

 

·**               **incur debt;

 

·**               **makeinvestments in other persons;

 

·**               **declaredividends or redeem or repurchase stock;

 

·**               **engage inmergers, acquisitions, consolidations and asset sales or amend the Company’sorganizational documents;

 

·**               **enter intocertain hedging arrangements;

 

·**               **amend materialcontracts; and

 

·**               **enter intorelated party transactions.

 

With regard tohedging arrangements, the Credit Agreement provides that acceptable commodityhedging arrangements cannot be greater than 80 to 85%, depending on themeasurement date, of the Company’s monthly production from its hydrocarbonproperties that are used in the borrowing base determination and that the fixedor floor price of the Company’s hedging arrangements must be equal to orgreater than the gas price used by the lenders in determining the borrowingbase.

 

The CreditAgreement 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 as of June 30, 2008 included requirements to maintain:(i) earnings before income taxes, depreciation, depletion, amortizationand accretions (“EBITDA”) to cash interest expense of not less than 3.00 to1.00, (ii) current ratio of not less than 1.00 to 1.00, (iii) totaldebt to annualized EBITDA of not more than 3.0 to 1.0, (iv) quarterlytotal senior debt to annualized EBITDA equal to or less than 2.00 to 1.0, and

 

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(v) total proved PV-10value of reserves to total debt of at least 1.50 to 1.00. The Credit Agreementcontains customary events of default, including, without limitation, paymentdefaults, covenant defaults, certain events of bankruptcy and insolvency,defaults in the payment of other material debt, judgment defaults, breaches ofrepresentations and warranties, loss of material permits and licenses and achange in control. The Company was in compliance with the covenants under theCredit Agreement as of June 30, 2008*.*

 

Effective August 4,2008, the parties to the Credit Agreement entered into the Second Amendment(the “Second Amendment”) to the Credit Agreement.  The Second Amendment provides, among otherthings, for (i) the 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.

 

*OfficeBuilding 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 bears interest at 6.875% duringthe first three years, at a variable base rate thereafter and 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 $615,400 will become due. As of June 30,2008, the Company had $775,000 outstanding in principal and interest on this mortgage.

 

**Note 8 —Fair Value Measurements**

 

Effective January 1,2008, the Company adopted SFAS No. 157, “Fair Value Measurements” for allfinancial assets and liabilities measured at fair value on a recurring basis.The statement establishes a framework for measuring fair value and requiresenhanced disclosures about fair value measurements. SFAS No. 157 definesfair value as the price that would be received to sell an asset or paid totransfer a liability (an exit price) in an orderly transaction between marketparticipants at the measurement date. The statement establishes market orobservable inputs as the preferred sources of values, followed by assumptionsbased on hypothetical transactions in the absence of market inputs. Thestatement establishes a hierarchy for grouping these assets and liabilities,based on the significance level of the following inputs:

 

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

 

·**               **Level 2—Quoted prices in active markets for similar assets and liabilities, quotedprices for identical or similar instruments in markets that are not active, andmodel-derived valuations whose inputs are observable or whose significant valuedrivers are observable.

 

·**               **Level 3 —Significant inputs to the valuation model are unobservable.

 

The following is alisting of the Company’s liabilities required to be measured at fair value on arecurring basis and where they are classified within the hierarchy as of June 30,2008 (in thousands):

 
| ** **                         | ** ** | **Level 1** | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** ** |
|------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|-----------|------------|
| Liabilities                        |       |             |       |             |       |             |       |      |       |
| Oil and Gas derivative instruments |       | $                | —     |             | $          | 5,910            |       | $         | —     |   | $ | 5,910 |   |
| Total                              |       | $                | —     |             | $          | 5,910            |       | $         | —     |   | $ | 5,910 |   |

 

A financial assetor liability 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 usesLevel 2 inputs to measure the fair value of oil and gas derivative instruments.The fair value is based on interpolated data. The Company uses an industrystandard model that considers various inputs including; (a) quoted forwardprices for the specific commodity and area which was hedged, (b) volatilityfactors with consistent time data that correlates to the remaining life 

 

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of the derivativeinstruments and (c) time value. The Company believes that this approachprovides a reasonable, non-biased and consistent methodology for valuing oiland gas derivative instruments. In addition, the Company also evaluates companycredit risk and counterparty credit risk to determine fair value of the assetor liability and further action as needed.

 

**Note 9 —Contingencies**

 

From time to time,Pinnacle is subject to legal proceedings and claims that arise in the ordinarycourse of its business. In addition, like other natural gas and oil producersand marketers, Pinnacle’s operations are subject to extensive and rapidlychanging federal and state environmental, health and safety laws andregulations governing air emissions, wastewater discharges, and solid andhazardous waste management activities. As a result, it is extremely difficultto reasonably quantify future environmental and regulatory relatedexpenditures.

 

The followingrepresent legal actions in which Pinnacle is involved. No assurance can begiven that these legal actions will be resolved in Pinnacle’s favor. However,management believes, based on its experiences to date, that these matters willnot have a material adverse impact on Pinnacle’s business, financial positionor results of operations.

 

Pinnacle, togetherwith the State of Montana, the Montana Department of Environmental Quality, theMontana Board of Oil and Gas Conservation and the Department of NaturalResources, have been 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 Pinnacle serves as operator and owns a workinginterest in the minerals under lease. The plaintiff seeks to permanently enjointhe State of Montana and its administrative bodies from issuing licenses orpermits, or authorizing the removal of ground water from under the plaintiff’sranch. In addition, the plaintiff further seeks to preliminarily and permanentlyenjoin Pinnacle on the basis that Pinnacle’s operations lack adequatesafeguards required under the Montana state constitution. On August 25,2005, the district judge issued an order denying without prejudice theapplication for temporary restraining order and preliminary injunctionrequested by the plaintiff. The case was appealed by the plaintiff to theMontana Supreme Court. On November 16, 2005, the Montana Supreme Courtissued an order that denied enjoining the Coal Creek POD, and subsequently, theMontana Supreme Court remanded the case back to the district court for adecision on the merits.

 

Approximately 59%and 61% of Pinnacle’s gross acreage in Montana and Wyoming, respectively, is onU.S. federal land. Federal leases in Montana and Wyoming must be developedpursuant to the U.S. BLM’s Resource Management Plans. Federal leases are alsosubject to the National Environmental Policy Act and Federal Land PolicyManagement Act. The National Environmental Policy Act process imposesobligations on the federal government that may result in legal challenges andpotentially lengthy delays in obtaining project permits or approvals. TheMontana and Wyoming BLMs have been subject to several lawsuits from variousenvironmental and tribal groups challenging Resource Management Plan amendmentsand supporting Environmental Impact Statements addressing CBM development inMontana and Wyoming. In 2003, the Montana BLM and Wyoming BLM each amendedtheir Resource Management Plans based in part on Environmental ImpactStatements prepared pursuant to the National Environmental Policy Act. Shortlyafter the issuance of the Environmental Impact Statements and amended ResourceManagement Plans, various plaintiffs brought legal actions challenging theMontana and Wyoming Environmental Impact Statements and Resource ManagementPlans. There have been at least five federal district court challenges to theMontana Environmental Impact Statements. There are also at least three federaldistrict court challenges to the Wyoming Environmental Impact Statementscurrently pending before the United States District Court for the District ofWyoming. Pinnacle has intervened in several of these cases to protect itsinterests in these proceedings. The outcome and timing of these cases couldaffect the Montana and Wyoming BLM’s ability to approve PODs and issue drillingpermits and thus could affect Pinnacle’s ability to further develop its federalleases in Montana and Wyoming. In particular, the Ninth Circuit previouslygranted a motion for a blanket injunction prohibiting the Montana BLM fromapproving any CBM production projects on federal lands in the Powder RiverBasin of Montana pending disposition of two of three appeals pending beforethat court. While a panel of the Ninth Circuit issued a favorable decisionaffirming an earlier order by the Montana District Court that allows phased CBMdevelopment to continue pending completion of a Supplemental EnvironmentalImpact Statement, or SEIS, Pinnacle cannot predict how or when the courts willultimately resolve these matters, including the dissolution of the injunction,nor can it foresee future challenges which may arise. Pinnacle believes it willultimately be successful in developing its leases as planned, but cannot giveany assurances as to when or how these suits will be resolved or when Pinnaclewill be able to develop its federal leases in the Powder River Basin ofMontana.

 

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**Note 10— Recent Developments**

 

On July 1,2008, Pinnacle granted an aggregate of 86,650 shares of restricted common stockto employees who were employed as of December 31, 2007.  The restricted shares will vest 33.4%, 33.3%and 33.3% over three years on each anniversary date of the grant.

 

Effective August 4, 2008, the parties to the Company’s CreditAgreement entered into the Second Amendment (the “Second Amendment”) to theCredit Agreement.  The Second Amendmentprovides, among other things, for (i) the increase in the total quarterlysenior debt to annualized EBITDA ratio from 2.0 to 1.0, to 3.0 to 1.0, (ii) anincrease in 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.  For more information, see Note 7 — Long-TermDebt.

 

As of June 30, 2008, the borrowing base under the Credit Agreementwas $17.8 million, although the actual borrowing availability was $6.6 milliondue to covenant limitations, of which $5.0 million of debt was outstandingindebtedness under the Credit Agreement.

 

********

 

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

 

*Thediscussion and analysis that follows should be read together with the**accompanying financial statements and notesrelated thereto that are included**elsewherein this quarterly report on Form 10-Q. It includes forward looking**statements that may reflect our estimates,beliefs, plans and expected**performance.The forward looking statements are based upon events, risks and**uncertainties that may be outside our control. Ouractual results could differ**significantlyfrom those discussed in these forward looking statements. 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,**developmentsuccess rates, capital expenditures and other uncertainties, as**well as those factors discussed below and elsewherein this quarterly report on**Form 10-Qand in our annual report on Form 10-K for the year ended December 31,**2007, including in “Risk Factors” and “CautionaryStatement Concerning Forward**LookingStatements,” all of which are difficult to predict. As a result of**these assumptions, risks and uncertainties, theforward looking matters**discussedmay not occur.*

 

**Overview**

 

We are anindependent energy company engaged in the acquisition, exploration anddevelopment of domestic onshore natural gas reserves. We primarily focus ourefforts on the development of CBM properties located in the Powder River Basinin northeastern Wyoming and southern Montana. In addition, in April 2006,we acquired properties located in the Green River Basin in southern Wyoming. Asof June 30, 2008, we owned natural gas and oil leasehold interests inapproximately 494,000 gross (316,000 net) acres, approximately 93% of whichwere undeveloped. As of June 30, 2008, we had estimated net provedreserves of approximately 29.8 Bcf based on the CIG index price of $8.73 perMcf. We have a total capital expenditure budget of $30.1 million for 2008 andexpect to drill 146 gross (110 net) wells during that period. Depending on CIGindex prices and available capital resources, we may re-evaluate our 2008capital expenditure budget in the future. We incurred capital expenditures ofapproximately $17.2 million during the six months ended June 30, 2008,primarily related to our drilling, completion and infrastructure costs on ourCabin Creek acreage, and drilled 76 gross (54 net) wells and completed 49 gross(35 net) wells during the six months ended June 30, 2008. We operated 100%of those wells.

 

We were formed in June 2003as a Delaware corporation through a contribution of proved producing propertiesand undeveloped leaseholds by subsidiaries of Carrizo and U.S. Energy and acash contribution from DLJ Merchant Banking.

 

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

 

Effective February 12,2007, we entered into a new $100 million credit facility with an initialcommitment of $27 million which permits borrowings up to the borrowing base asdesignated by the administrative agent. As of June 30, 2008, the borrowingbase was $17.8 million, although our actual borrowing availability wasapproximately $6.6 million due to covenant limitations, of which$5.0 million of debt was outstanding. Effective August 4, 2008, weentered into an amendment to our credit facility.  Among other things, the amendment increasedthe total quarterly senior debt to annualized EBITDA ratio to 3.0 to 1.0.  Please see “Note 10 — Recent Developments” inthe notes to the financial statements for more information regarding theamendment to the credit facility and the information under the heading “—Liquidityand Capital Resources—Credit Facility” in this Item 2 and the risk factorsunder Part II, Item 1A for further information regarding our creditfacility and the covenant limitations.

 

**CriticalAccounting Policies**

 

The mostsubjective and complex judgments used in the preparation of our financialstatements are:

 

·**               **Reserveevaluation and determination.

 

·**               **Estimates ofthe timing and cost of our future drilling activity.

 

·**               **Estimates ofthe fair valuation of hedges in place.

 

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·**               **Estimates oftiming and cost of asset retirement obligations.

 

·**               **Estimates ofthe expense and timing of exercise of stock options.

 

·**               **Accruals ofoperating costs, capital expenditures and revenue.

 

·**               **Estimates forlitigation.

 

***Oil and Gas Properties***

 

We use the fullcost method of accounting for oil and gas producing activities. Under thismethod, all costs associated with property acquisition, exploration anddevelopment, including costs of unsuccessful exploration, costs of surrenderedand abandoned leaseholds, delay lease rentals and the fair value of estimatedfuture costs of site restoration, dismantlement and abandonment activities, arecapitalized within a cost center. Our oil and gas properties are all locatedwithin the United States, which constitutes a single cost center. We have notcapitalized any overhead costs. No gain or loss is recognized upon the sale orabandonment of undeveloped or producing oil and gas properties unless the salerepresents a significant portion of gas properties and the gain significantlyalters the relationship between capitalized costs and proved gas reserves ofthe cost center. Expenditures for maintenance and repairs are charged to leaseoperating expense in the period incurred.

 

Depreciation,depletion and 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, are included in unproved oil and gas properties at the lower of costor estimated fair market value and are not subject to amortization. On aquarterly basis, such costs are evaluated for inclusion in the costs to beamortized resulting from the determination of proved reserves, impairments, orreductions in value. To the extent that the evaluation indicates theseproperties are impaired, the amount of the impairment is added to thecapitalized costs to be amortized. We recorded an impairment of unevaluatedproperties of $0 and $740,000 as of June 30, 2008 and June 30, 2007,respectively. Abandonment of unproved properties are also accounted for as anadjustment to capitalized costs related to proved oil and gas properties, withno losses recognized.

 

Substantially allremaining unproved property costs are expected to be developed and included inthe amortization base ratably over the next three to five years. Salvage valueis taken into account in determining depletion rates and is based on ourestimate of the value of equipment and supplies at the time the well isabandoned. The estimated salvage value of equipment included in determining thedepletion rate was approximately $7.1 million and $6.4 million as of June 30,2008 and December 31, 2007, respectively.

 

Under the fullcost method of accounting rules, capitalized costs less accumulated depletionand related deferred income taxes may not exceed a “ceiling” value which is thesum of (1) the present value discounted at 10% of estimated future netrevenue using current costs and prices, including the effects of derivativeinstruments designated as cash flow hedges but excluding the future cashoutflows associated with settling asset retirement obligations that have beenaccrued on the balance sheet, less any related income tax effects; plus (2) thecost of properties not being amortized, if any; plus (3) the lower ofcosts or estimated fair value of unproved properties; less (4) the incometax effects related to differences in the book to tax basis of oil and gasproperties. If capitalized cost exceeds the limit, the excess must be chargedto expense. The expense may not be reversed in future periods. At the end ofeach quarter, we calculate the full cost ceiling limitation. At June 30,2008, the full cost ceiling of our oil and gas properties exceeded thecapitalized cost by approximately $35.0 million based upon a natural gas priceof approximately $8.73 per Mcf (based on the CIG Rocky Mountain Index) ineffect at that date. As a result, we were not required to record an impairmentfor the six months ended June 30, 2008. An impairment of approximately$18.2 million was recorded for the six months ended June 30, 2007. Theimpairment of our oil and gas properties resulted from low commodity pricesthroughout 2007, specifically at the end of the first, second and thirdquarters of 2007. A decline in gas prices or an increase in operating costssubsequent to the measurement date or reductions in economically recoverablequantities could result in the recognition of additional impairments of our oiland gas properties in future periods.

 

***Gas Sales***

 

We use the salesmethod for recording natural gas sales. Sales of gas applicable to our interestin producing natural gas and oil leases are recorded as revenues when the gasis metered and title transferred pursuant to the gas sales contracts coveringour interest in gas reserves. During such times as our sales of gas exceed ourpro rata ownership in a well, such sales are recorded as revenues unless 

 

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total sales from the wellhave exceeded our share of estimated total gas reserves underlying the propertyat which time such excess is recorded as a gas imbalance liability. At June 30,2008 and December 31, 2007, no liability was recorded. Although there wasno liability recorded for prior periods, gas reserves are an estimate and areupdated on an annual and interim basis. Gas pricing, expenses and productionmay impact future gas reserves remaining which in turn, could impact therecording of liabilities in the future. Gas sales accruals at June 30,2008 and December 31, 2007 were based on the actual volume statements fromour purchasers and distribution process. If accruals were to change by 10% at June 30,2008 and December 31, 2007, the impact would have been a $450,000 and$306,000 change, respectively.

 

***Asset Retirement Obligations***

 

We follow theprovisions of SFAS No. 143, “*Accountingfor the Asset Retirement Obligations*.” SFAS No. 143 generallyapplies to legal obligations associated with the retirement of long-livedassets that result from the acquisition, construction, development and/or thenormal operation of a long-lived asset. SFAS No. 143 requires us torecognize an estimated liability for costs associated with the abandonment ofour oil and gas properties.

 

A liability forthe fair value of an asset retirement obligation with a corresponding increaseto the carrying value of the related long-lived asset is recorded at the time awell is completed or acquired. The increased carrying value is depleted usingthe units of production method, and the discounted liability is increasedthrough accretion over the remaining life of the respective oil and gasproperties.

 

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.Our liability is discounted using our best estimate of our credit-adjustedrisk-free rate. Revisions to the liability could occur due to changes in estimatedabandonment costs, changes in well economic lives or if federal or stateregulators enact new requirements regarding the abandonment of wells. Forexample, a 10% change in our estimated retirement costs would have a $315,000effect on our asset retirement obligation liability at June 30, 2008.

 

The following is asummary of our asset retirement obligation activity for the three and sixmonths ended June 30, 2008 and June 30, 2007 (unaudited):

 
| ** **                                        | ** ** | **Three  Months Ended  June 30,** | ** ** | **Six  Months Ended  June 30,** | ** ** | **Three  Months Ended  June 30,** | ** ** | **Six  Months Ended  June 30,** | ** ** |
|---------------------------------------------------|------------|---------------------------------------------|------------|-------------------------------------------|------------|---------------------------------------------|------------|-------------------------------------------|------------|
| ** **                                        | ** ** | **2008**                                    | ** ** | **2007**                                  | ** ** |
| Beginning balance of asset retirement obligations |       | $                                           | 2,926      |                                      | $          | 2,767                                       |       | $                                         | 2,438      |   | $ | 2,321 |   |
| Additional obligation added during the period     |       | 167                                         |       | 268                                       |       | 45                                          |       | 113                                       |       |
| Accretion expense                                 |       | 61                                          |       | 119                                       |       | 50                                          |       | 99                                        |       |
| Ending balance of asset retirement obligations    |       | $                                           | 3,154      |                                      | $          | 3,154                                       |       | $                                         | 2,533      |   | $ | 2,533 |   |

 

***Inventory***

 

We acquireinventory of oil and gas equipment, primarily tubulars, to take advantage ofquantity pricing and to secure a readily available supply. Inventory is valuedat the lower of average cost or market. Inventory is used in the development ofgas properties and to the extent it is estimated that it will be billed toother working interest owners during the next year, it is included in currentassets. Otherwise, it is recorded in noncurrent assets. The price of steel is aprimary factor in valuing our inventory. Under the valuation method of lower ofaverage cost or market, a 10% reduction in the price of steel would have causeda $52,000 reduction in our inventory valuation as of June 30, 2008. Themarket price of steel is evaluated each quarter using prices quoted byauthorized vendors in the area.

 

***Property and Equipment***

 

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

 

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***Long-Lived Assets***

 

Long-lived assetsto be held and used in our business are reviewed for impairment whenever eventsor changes in circumstances indicate that the related carrying amount may notbe recoverable. When the carrying amounts of long-lived assets exceed the fairvalue, which is generally based on discounted expected future cash flows, werecord an impairment. No impairments on long-lived assets were recorded duringthe year ended December 31, 2007 and the six months ended June 30,2008.

 

***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 wellcounts for the six months ended June 30, 2008 would have increased ordecreased our expenses billed to working interest owners by approximately$91,000. As we operate and drill additional wells in the future, additionaladministrative expenses will be charged to the working interest owners when thewells become productive. General and administrative expenses for the six monthsended June 30, 2008 also include $2.1 million of merger related costsattributable to the failed merger with Quest Resource Corporation.  Any future costs associated with any merger,acquisition or divestiture will be expensed in the period of the transactionoutcome.

 

***Income Taxes***

 

We use the assetand liability method of accounting for income taxes, in accordance with SFAS No. 109,“*Accounting for Income Taxes*.”Deferred tax assets and liabilities are recognized for the expected future taxconsequences of temporary differences between the financial statement and taxbases of assets and liabilities. If appropriate, deferred tax assets arereduced by a valuation allowance which reflects expectations of the extent towhich such assets will be realized. As of December 31, 2007 and June 30,2008, we had recorded a full valuation allowance for our net deferred taxasset.

 

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 ofthis review, we did not identify any material deferred tax assets that requiredadjustment. As of January 1, 2007, the date of adoption of FIN 48, and asof June 30, 2008, we had not accrued any penalties or interest related toany material uncertain tax positions.

 

Our policy is torecognize interest and penalties related to uncertain tax benefits in incometax expense. As of June 30, 2008, we had not recognized any interest orpenalties in our statement of operations or statement of financial position.

 

We are subject tothe following material taxing jurisdictions: U.S. federal. We also havematerial operations 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 2004 through 2007. 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, “*Accounting for Derivative Instruments and Hedging**Activities*.” SFAS No. 133requires us to record derivative instruments at their fair value. If thederivative is designated as a fair value hedge, the changes in the fair valueof the derivative 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 

 

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“Note 5 — Derivatives” ofthe notes to the unaudited financial statements appearing elsewhere in thisquarterly report for additional discussion of derivatives.

 

We periodicallyhedge a portion of our oil and gas production through swap and collaragreements. The purpose of the hedges is to provide a measure of stability toour cash flows in an environment of volatile oil and gas prices and to managethe exposure to commodity price risk. Our management decided not to use hedgeaccounting for these agreements. Therefore, in accordance with the provisionsof SFAS No. 133, the changes in fair market value are recognized inearnings.

 

***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.

 

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. Prior to January 1,2006, we accounted for share-based payments under the recognition andmeasurement provisions of APB Opinion No. 25, “*Accounting**for StockIssued to Employees*,” and related interpretations, as permitted bySFAS No. 123, “*Accounting for Stock-BasedCompensation*.” In accordance with APB No. 25, no compensationcost was required to be recognized for options granted that had an exerciseprice equal to or greater than the market value of the underlying common stockon the date of the grant.

 

***Accounts Receivable***

 

Our revenueproducing activities are conducted primarily in Wyoming. We grant credit toqualified customers, which potentially subjects us to credit risk resultingfrom, among other factors, adverse changes in the industry in which we operateand the financial condition of our customers. We continuously monitorcollections and payments from our customers and, if necessary, record anallowance for doubtful accounts based upon historical experience and anyspecific customer collection issues identified. We recorded an allowance of$100,000 as of June 30, 2008 and December 31, 2007.

 

***Transportation Costs***

 

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

 

***Legal Estimates***

 

From time to time,we are subject to legal proceedings and claims that arise in the ordinarycourse of business. 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 June 30, 2008 and December 31,2007, we recorded $0, respectively, for legal proceedings.

 

***Per Share Information***

 

Basic loss pershare is computed by dividing net income loss from continuing operationsattributable to common stock by the weighted average number of common sharesoutstanding during each period. Diluted earnings per share is computed byadjusting the average number of common shares outstanding for the dilutiveeffect, if any, of common stock equivalents such as stock options and warrants.Diluted net loss per share was the same as basic net loss per share for thethree months ended June 30, 2008 because potential common stockequivalents were anti-dilutive. Certain option to purchase shares of our commonstock were excluded from the dilution calculations because the shares wereanti-dilutive. At June 30, 2008 and 2007, 750,000 and 990,000 options,respectively, were excluded because they were anti-dilutive due to the net lossattributable to stockholders incurred in such periods.

 

***New Accounting Pronouncements***

 

For informationconcerning new accounting pronouncements, please see “Note 2 — Basis ofPresentation” of the notes to the unaudited financial statements appearingelsewhere in this quarterly report.

 

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**TrendsAffecting Our Business**

 

We haveexperienced increasing costs since our inception in 2003 due to increaseddemand for oilfield products and services. The cyclical nature of the naturalgas industry causes fluctuations in demand for goods and services from oilfieldcompanies, suppliers and others associated with the industry, which in turnaffects the prices for those goods and services. Typically, as prices fornatural gas increase, so do all the costs associated with natural gas production.Recently, we have seen increases in the cost of tubulars, drilling rigs andcement in particular. We expect that increased demand for the goods andservices we use in our business will continue to put pressure on prices in thenear to medium term.

 

Historically,natural gas prices have been extremely volatile, and we expect that volatilityto continue. For example, during the six months ended June 30, 2008, theNYMEX natural gas index price ranged from a high of $13.21 per MMBtu to a lowof $7.38 per MMBtu, while the CIG natural gas index price ranged from a high of$9.43 per MMBtu to a low of $6.08 per MMBtu. During the year ended December 31,2007, the NYMEX natural gas index price ranged from a high of $8.64 per MMBtuto a low of $5.38 per MMBtu, while the CIG natural gas index price ranged froma high of $7.11per MMBtu to a low of $0.06 per MMBtu. Changes in natural gaspricing have impacted our revenue streams, production taxes, prices used inreserve calculations, borrowing base calculations and the carrying value of ourproperties and the valuation of potential property acquisitions. During thethree and six months ended June 30, 2008, estimated future gas prices hadan impact on our revenues and the costs attributable to our future operations.We expect that changing natural gas prices will continue to impact ouroperations and financial results in the future.

 

Transportation ofnatural gas and access to throughput capacity have a direct impact on naturalgas prices in the Rocky Mountain region, where our operations are concentrated.As drilling activity increases throughout the Rocky Mountain region, additionalproduction may come on line, which could cause bottlenecks or capacityconstraints. Generally speaking, a surplus of natural gas production relativeto available transportation capacity has a negative impact on prices.Conversely, as capacity increases and bottlenecks are eliminated, pricesgenerally increase. Although there is currently adequate transportationcapacity out of the Powder River Basin, a surplus of natural gas arriving atkey marketing hubs from the Powder River Basin and elsewhere relative toavailable takeaway capacity from these hubs has caused Rocky Mountain gas togenerally trade at a discount to the NYMEX natural gas index price. The RockiesExpress Pipeline, which was completed to Audrain County, Missouri in early2008, has increased takeaway capacity by approximately 2 Bcf per day from thesehubs. We expect that the completion of this pipeline along with additional proposedpipelines will help reduce the differential between gas produced in the RockyMountain region and the NYMEX natural gas index price.

 

**Resultsof Operations**

 

Net lossattributable to stockholders for the three months ended June 30, 2008 was$3.9 million, or $0.13 per diluted share, on total revenue of $7.6 million.Other income for the three months ended June 30, 2008 included a $2.0million unrealized loss associated with the change in the fair valuation of ournatural gas hedges in place in accordance with the provisions of SFAS No. 133.Absent such change in the valuation, we would have shown a loss of $1.9million. This compares to a reported net loss attributable to stockholders of$2.1 million for the three months ended June 30, 2007 on total revenue of$3.4 million. Adjusted for an unrealized loss in the fair valuation of ournatural gas hedges in place of $0.6 million shown in other income, our resultsfor the three months ended June 30, 2007 would have been a net lossattributable to stockholders of $1.5 million. In addition, for the three monthsended June 30, 2007, an impairment of the capitalized costs due to theceiling limitation was $1.2 million. Absent the impairment and unrealized loss,the net loss attributable to stockholders would have been $0.3 million.

 

Net lossattributable to stockholders for the six months ended June 30, 2008 was$9.5 million, or $0.33 per diluted share, on total revenue of $13.2 million.Other income for the six months ended June 30, 2008 included a $6.5million unrealized loss associated with the change in the fair valuation of ournatural gas hedges in place in accordance with the provisions of SFAS No. 133.Absent such change in the valuation, we would have shown a loss of $3.0million. This compares to a reported net loss attributable to stockholders of$20.2 million for the six months ended June 30, 2007 on total revenue of$7.1 million. Adjusted for an unrealized loss in the fair valuation of ournatural gas hedges in place of $1.2 million shown in other income, our resultsfor the six months ended June 30, 2007 would have been a net lossattributable to stockholders of $19.0 million. In addition, for the six monthsended June 30, 2007, an impairment of the capitalized costs due to theceiling limitation was $18.2 million. Absent the impairment and unrealizedloss, the net loss attributable to stockholders would have been $0.8 million.

 

In order toprovide a measure of stability to the cash flow in an environment of volatileoil and gas prices and to manage the exposure to commodity price risk, wechoose to periodically hedge a portion of our oil and gas production using swapand collar agreements. We account for our derivative instruments under theprovisions of SFAS No. 133. SFAS No. 133 requires us to record 

 

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derivative instruments attheir fair value. Management has chosen not to use hedge accounting for thesearrangements. Therefore, in accordance with SFAS No. 133, changes in thefair market value are recognized in earnings.

 

***Three Months Ended June 30, 2008 Compared to ThreeMonths Ended June 30, 2007***

 

*Gassales volume.*

 

Gas sales volumeincreased approximately 9%, from 917 MMcf in the three months ended June 30,2007 to 1,001 MMcf in the three months ended June 30, 2008. Daily salesvolume was 10.9 MMcf for the three months ended June 30, 2008 compared to10.0 MMcf for the three months ended June 30, 2007, a 0.9 MMcf per dayincrease.  The increase was primarily dueto production coming online in our Cabin Creek, Kirby and Deer Creek projectareas.

 

*Gassales revenue.*

 

Revenue from gassales increased approximately $4.1 million during the three months ended June 30,2008, to approximately $7.6 million, a 120% increase compared to the threemonths ended June 30, 2007. This increase was primarily due to an increasein gas sales volume coupled with an increase in the average realized price perMcf. The average realized price per Mcf increased approximately 102%, from$3.75 per Mcf before transportation in the three months ended June 30,2007 to $7.57 per Mcf in the three months ended June 30, 2008.

 

*Derivatives.*

 

For the threemonths ended June 30, 2008, we had an unrealized loss of $2.0 millioncompared to an unrealized loss of $0.6 million for the three months ended June 30,2007. The unrealized loss is a non-cash expense based primarily on theBlack-Scholes model for valuing future cash flows utilizing price volatilitywith a normal discount rate. Hedges settled during the three months ended June 30,2008 resulted in a realized loss of $0.7 million compared to a realized hedgegain of $1.2 million during the three months ended June 30, 2007. Thehedge loss for the three months ended June 30, 2008 was primarily due tothe fact that gas prices were higher than the weighted average floor price ofour hedges in place.

 

*Leaseoperating expenses.*

 

Lease operatingexpenses increased $0.1 million in the three months ended June 30, 2008 to$1.3 million, an 11% increase compared to the three months ended June 30,2007. This increase resulted from an increase in the number of wells in theproductive cycle during the three months ended June 30, 2008, along with aworkover program which replaced or repaired pumps in over 50 wells which wereunderperforming. We elected to expense the workover costs because such costswere $5,000 to $10,000 on a per well basis. On an Mcf basis, lease operatingexpenses increased 1% from $1.33 per Mcf in the three months ended June 30,2007 to $1.35 per Mcf in the three months ended June 30, 2008. Theincrease per Mcf was primarily due to a number of wells being in the earlystages of their productive life cycle as production did not increaseproportionately to the number of wells coming online. Additionally, increasesin generator rentals and associated fuel while waiting on permanent powercontributed to the increase along with increased water management costsassociated with water treatment.

 

*Productiontaxes.*

 

Production taxesincreased $0.5 million in the three months ended June 30, 2008 to $0.9million, a 141% increase from the three months ended June 30, 2007.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 alongwith a 9% average rate for production sold derived in Montana. The increase inproduction taxes for the three months ended June 30, 2008 was primarilydue to increased revenues associated with increased volume and realizedpricing. On an Mcf basis, production taxes were $0.86 per Mcf for the threemonths ended June 30, 2008 and $0.39 per Mcf for the three months ended June 30,2007, a 121% increase, which correlates to the increase in the price per Mcfreceived in the three months ended June 30, 2008 from the three monthsended June 30, 2007.

 

*Marketingand transportation.*

 

Marketing andtransportation expenses increased approximately $0.3 million in the threemonths ended June 30, 2008 to approximately $1.2 million, a 35% increasefrom the three months ended June 30, 2007. The increase related primarilyto increased 

 

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sales volume in the threemonths ended June 30, 2008, together with a slight increase intransportation fees and compression due to inflationary adjustments in thecontracts along with fees paid for compression design capacity which was notused. On an Mcf basis, marketing and transportation expenses increased 23% to$1.21 per Mcf in the three months ended June 30, 2008 from $0.98 per Mcfin the three months ended June 30, 2007.

 

*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 $0.5 millionand $0.4 million in the three months ended June 30, 2008 and June 30,2007, respectively. General and administrative expenses, net, increased $2.0million in the three months ended June 30, 2008 to $3.2 million from $1.2million in the three months ended June 30, 2007. This increase was dueprimarily to a $2.1 million charge related to merger costs attributable to thefailed Quest Resources Corporation merger. On an Mcf basis, general andadministrative expenses, net increased 142%, from $1.33 per Mcf in the threemonths ended June 30, 2007 to $3.21 per Mcf in the three months ended June 30,2008.

 

*Depreciation,depletion, amortization and accretion.*

 

Depreciation,depletion, amortization and accretion expense increased $0.7 million for thesix months ended June 30, 2008 to $2.3 million, a 42% increase compared tothe three months ended June 30, 2007. This increase was due to a 9%increase in gas sales volumes for the three months ended June 30, 2008along with additional capitalized costs in the full cost pool. On an Mcf basis,the depreciation, depletion, amortization and accretion rate increased 42% to$2.20 per Mcf in the three months ended June 30, 2008 from $1.61 per Mcfin the three months ended June 30, 2007.

 

*Impairment.*

 

At June 30,2008, the full cost ceiling of our oil and gas properties exceeded thecapitalized cost by approximately $35.0 million based upon a natural gas priceof approximately $8.73 per Mcf (based on the CIG Rocky Mountain Index) in effectat that date. As a result, we were not required to record an impairment for thethree months ended June 30, 2008. An impairment of approximately $18.2million was recorded for the year ended December 31, 2007. The impairmentof our oil and gas properties resulted from low commodity prices throughout theyear, specifically at the end of the first, second and third quarters of 2007.For further information regarding this impairment, please see “Note 2 —  Basis of Presentation” in the notes to theunaudited financial statements appearing elsewhere in this quarterly report. Adecline in gas prices or an increase in operating costs subsequent to themeasurement date or reductions in economically recoverable quantities couldresult in the recognition of additional impairments of our oil and gasproperties in future periods.

 

***Six Months Ended June 30, 2008 Compared to Six MonthsEnded June 30, 2007***

 

*Gassales volume.*

 

Gas sales volumeincreased approximately 15%, from 1,634 MMcf in the six months ended June 30,2007 to 1,880 MMcf in the six months ended June 30, 2008. Daily salesvolume was 10.3 MMcf for the six months ended June 30, 2008 compared to9.0 MMcf for the six months ended June 30, 2007, a 1.3 MMcf per dayincrease.  The increase was primarily dueto production coming online in our Cabin Creek, Kirby and Deer Creek projectareas.

 

*Gassales revenue.*

 

Revenue from gassales increased approximately $6.1 million during the six months ended June 30,2008, to approximately $13.2 million, an 87% increase compared to the sixmonths ended June 30, 2007. This increase was primarily due to an increasein gas sales volume coupled with an increase in the average realized price perMcf. The average realized price per Mcf increased approximately 62%, from $4.34per Mcf in the six months ended June 30, 2007 to $7.04 per Mcf in the sixmonths ended June 30, 2008.

 

*Derivatives.*

 

For the six monthsended June 30, 2008, we had an unrealized loss of $6.4 million compared toan unrealized loss of $1.2 million for the six months ended June 30, 2007.The unrealized loss is a non-cash expense based primarily on the Black-Scholesmodel for 

 

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valuing future cash flowsutilizing price volatility with a normal discount rate. Hedges settled duringthe six months ended June 30, 2008 resulted in a realized loss of $0.8million compared to a realized hedge gain of $1.7 million during the six monthsended June 30, 2007. The hedge loss for the six months ended June 30,2008 was primarily due to the fact that gas prices were higher than theweighted average floor price of our hedges in place.

 

*Leaseoperating expenses.*

 

Lease operatingexpenses increased $1.3 million in the six months ended June 30, 2008 to$3.4 million, a  59% increase compared tothe six months ended June 30, 2007. This increase resulted from anincrease in the number of wells in the productive cycle during the six monthsended June 30, 2008, along with a workover program which replaced orrepaired pumps in over 170 wells which were underperforming. We elected toexpense the workover costs because such costs were $5,000 to $10,000 on a perwell basis. On an Mcf basis, lease operating expenses increased 38% from $1.31per Mcf in the six months ended June 30, 2007 to $1.81 per Mcf in the sixmonths ended June 30, 2008. The increase per Mcf was primarily due to anumber of wells being in the early stages of their productive life cycle as productiondid not increase proportionately to the number of wells coming online.Additionally, increases in generator rentals and associated fuel while waitingon permanent power contributed, along with increased water management costsassociated with water treatment.

 

*Productiontaxes.*

 

Production taxesincreased $0.8 million in the six months ended June 30, 2008 to $1.5million, a 100% increase from the six months ended June 30, 2007.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 whilein Montana the percentage averages 9%. The increase in production taxes for thesix months ended June 30, 2008 was primarily due to increased revenuesassociated with increased volume and realized pricing. On an Mcf basis,production taxes were $0.81 per Mcf for the six months ended June 30, 2008and $0.46 per Mcf for the six months ended June 30, 2007, a 74% increase,which correlates to the increase in the price per Mcf received in the sixmonths ended June 30, 2008 from the six months ended June 30, 2007.

 

*Marketingand transportation.*

 

Marketing andtransportation expenses increased approximately $0.6 million in the six monthsended June 30, 2008 to approximately $2.3 million, a 36% increase from thesix months ended June 30, 2007. The increase related primarily toincreased sales volume in the six months ended June 30, 2008, togetherwith a slight increase in transportation fees and compression due toinflationary adjustments in the contracts along with fees paid for compressiondesign capacity which was not used. On an Mcf basis, marketing andtransportation expenses increased 18% to $1.22 per Mcf in the six months ended June 30,2008 from $1.03 per Mcf in the six months ended June 30, 2007.

 

*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 $0.9 millionin the six months ended June 30, 2008 compared to $0.8 million for the sixmonths ended June 30, 2007, a 13% increase. General and administrativeexpenses, net, increased $2.3 million in the six months ended June 30,2008 to $4.6 million from $2.3 million in the six months ended June 30,2007. This increase was due primarily to a $2.1 million charge related tomerger costs attributable to the failed Quest Resource Corporation merger. Onan Mcf basis, general and administrative expenses, net increased 71%, from$1.42 per Mcf in the six months ended June 30, 2007 to $2.44 per Mcf inthe six months ended June 30, 2008.

 

*Depreciation,depletion, amortization and accretion.*

 

Depreciation,depletion, amortization and accretion expense increased $0.9 million for thesix months ended June 30, 2008 to $4.0 million, a 30% increase compared tothe six months ended June 30, 2007. This increase was due to a 15%increase in gas sales volumes for the three months ended June 30, 2008along with additional capitalized costs in the full cost pool. On an Mcf basis,the depreciation, depletion, amortization and accretion rate increased 13% to$2.13 per Mcf in the six months ended June 30, 2008 from $1.89 per Mcf inthe six months ended June 30, 2007.

 

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*Impairment.*

 

At June 30,2008, the full cost ceiling of our oil and gas properties exceeded thecapitalized cost by approximately $35.0 million based upon a natural gas priceof approximately $8.73 per Mcf (based on the CIG Rocky Mountain Index) ineffect at that date. As a result, we were not required to record an impairmentfor the six months ended June 30, 2008. An impairment of approximately$18.2 million was recorded for the six months ended June 30, 2007. Theimpairment of our oil and gas properties resulted from low commodity pricesthroughout the year, specifically at the end of the first, second and thirdquarters of 2007. For further information regarding this impairment, please see“Note 2 —  Basis of Presentation” in thenotes to the unaudited financial statements appearing elsewhere in thisquarterly report. A decline in gas prices or an increase in operating costssubsequent to the measurement date or reductions in economically recoverablequantities could result in the recognition of additional impairments of our oiland gas properties in future periods.

 

**Liquidityand Capital Resources**

 

Our primary sourceof liquidity since our formation has been the private sale of our equity.During the period from our formation in June 2003 through September 2005,DLJ Merchant Banking contributed $44.1 million cash in exchange for shares ofour common stock, shares of our Series A Redeemable Preferred Stock anddetachable warrants to purchase additional shares of common stock. The proceedswere used to fund our acquisitions and capital expenditures. In April 2006,we completed a private placement of an aggregate of 12,835,230 shares of ourcommon stock at a price per share of $11.00, or $10.23 net of the initialpurchaser’s discount and placement fee. In May 2007, we completed aninitial public offering of an aggregate of 3,750,000 shares of our common stockat a price per share of $9.00, or $8.37 net of the underwriters’ discounts andcommissions.

 

*CreditFacility*.

 

Effective February 12,2007, we entered into a $100 million credit facility with an initial commitmentof $27 million which permits borrowings up to the borrowing base as designatedby the administrative agent. As of June 30, 2008, the borrowing base was$17.8 million, although our actual borrowing availability wasapproximately $6.6 million due to covenant limitations, of which $5.0 millionof debt was outstanding under the credit facility. Please see the informationunder the heading “Recent Developments” in the notes to the financialstatements.  Please see risk factorsunder Part II, Item 1A for more information regarding the covenantlimitations under our credit facility.

 

The borrowing baseis determined on a semi-annual basis and at such other additional times, up totwice yearly, as may be requested by either the borrower or the administrativeagent and is determined by the collateral agent, although the determination isat the administrative agent’s discretion as the credit agreement does notprovide a specific borrowing base formula. Based on future reserve reports,fluctuations in CIG index prices, covenant limitations and possible titledefects on certain of our properties, our borrowing base and borrowingavailability could be further reduced. As part of the annual borrowing baseredetermination, in April 2008 we entered into a letter agreement with theadministrative agent whereby the borrowing base under our credit facility willbe automatically reduced on a monthly basis until a formal determination orredetermination of the borrowing base comes into effect. Under such agreement,the borrowing base may be reduced from $18.5 million on April 1, 2008 to$16.5 million on October 1, 2008. However, we expect that aredetermination of our borrowing base will occur in September 2008.

 

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

 

Our obligationsunder the credit facility are secured by liens on (i) no less than 90% ofthe net present value of the oil and gas to be produced from our 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 underour credit facility bear interest either: (i) at a domestic bank rate plusan applicable margin between 0.25% and 1.25% per annum based on utilization, or(ii) at the London interbank offered rate, or LIBOR, plus an applicablemargin between 1.25% and 2.25% per annum based on utilization. The creditagreement provides for various fees, including a quarterly commitment fee of1/2 of 1.00% per annum and engineering fees to the administrative agent inconnection with a borrowing base determination. In addition, the creditfacility provided for an up front fee of $27,000, which was paid on the closingdate of the credit facility, and an additional arrangement fee of 1% based onutilization. Borrowings under this credit facility may be prepaid withoutpremium or penalty, except on Eurodollar advances. If an event of defaultexists, the default rate will be equal to 2% plus the floating rate.

 

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

 

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·**               **incur liens;

 

·**               **incur debt;

 

·**               **makeinvestments in other persons;

 

·**               **declaredividends or redeem or repurchase stock;

 

·**               **engage inmergers, acquisitions, consolidations and asset sales or amend ourorganizational documents;

 

·**               **enter intocertain hedging arrangements;

 

·**               **amend materialcontracts; and

 

·**               **enter intorelated party transactions.

 

With regard tohedging arrangements, the credit facility provides that acceptable commodityhedging arrangements cannot be greater than 80 to 85%, depending on the measurementdate of our monthly production from our hydrocarbon properties that are used inthe borrowing base determination, and that the fixed or floor price of ourhedging arrangements must be equal to or greater than the gas price used by thelenders in determining the borrowing base.

 

The creditagreement also requires that we satisfy certain affirmative covenants, meetcertain financial tests, maintain certain financial ratios and make certaincustomary indemnifications to lenders and the administrative agent. Thefinancial covenants as of June 30, 2008 included requirements to maintain:(i) EBITDA to cash interest expense of not less than 3.00 to 1.00, (ii) currentratio of not less than 1.00 to 1.00, (iii) total debt to annualized EBITDAof not more than 3.0 to 1.0, (iv) quarterly total senior debt toannualized EBITDA equal to or less than 2.00 to 1.0, and (v) total provedPV-10 value to total debt of at least 1.50 to 1.00.

 

The creditagreement 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.We were in compliance with the covenants under our credit agreement as of June 30,2008.

 

The creditagreement requires any wholly-owned subsidiaries to guarantee the obligationsunder the credit agreement.

 

Effective August 4,2008, the parties to the Credit Agreement entered into the Second Amendment(the “Second Amendment”) to the Credit Agreement.  The Second Amendment provides, among otherthings, for (i) the 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.

 

*OfficeBuilding Loan*.

 

On November 15,2005, we entered into a mortgage loan secured by our office building inSheridan, Wyoming in the aggregate principal amount of $829,000. The promissorynote provides for monthly payments of principal and interest in the initialamount of $6,400, and unpaid principal bears interest at 6.875% during thefirst three years, at a variable base rate thereafter and 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 $615,400 will become due. As of June 30,2008, we had $775,000 outstanding in principal on this mortgage.

 

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*CapitalExpenditure Budget*.

 

During 2007, wereduced our total capital expenditure budget for 2007 from approximately $52.6million to approximately $30.0 million. Consequently, we also reduced ourdrilling and completion targets for 2007 from approximately 260 gross (207 net)wells to approximately 140 gross (102 net) wells. During the year ended December 31,2007, we incurred capital expenditures of $21.2 million and drilled 87 gross(61 net) wells.

 

We have a totalcapital expenditure budget of $30.1 million for 2008 and expect to drill 146gross (110 net) wells during that period. During the six months ended June 30,2008, we incurred capital expenditures of $17.2 million, drilled 76 gross (54net) wells and completed 49 gross (35 net) wells. Our capital expenditures wereused to drill and complete wells, to construct related gas and waterinfrastructure, to fund plans of development costs for future wells, to fundundeveloped leasehold acquisition costs carried over from 2007, to recompletecertain wells, and to fund infrastructure and completion costs related to wellsdrilled in 2007. While we believe we will have adequate resources from cashflows from operations to implement a majority of our drilling plan for theremainder of 2008, our ability to complete our 2008 drilling plan and developfuture projects will depend on access to additional sources of capital,including our credit facility. The CIG index price was extremely volatileduring 2007 and at times reached unusually low levels. If prices decrease, ourcash flows from operations could decrease and the borrowing base and borrowingavailability under our credit facility could be further reduced. If we do nothave sufficient cash flows and could not obtain capital through our creditfacility or otherwise, our ability to execute our development and acquisitionplans, replace our reserves and maintain production levels could be greatlylimited. Depending on CIG index prices and available capital resources, we mayre-evaluate our capital expenditure budget in the future.

 

***Cash Flow from Operating Activities***

 

Net cash providedby operating activities was approximately $5.0 million for the six months endedJune 30, 2008, compared to net cash used in operating activities ofapproximately $5.5 million for the six months ended June 30, 2007. Thechange was primarily due to an increase in our accounts payable balance offsetpartially by an increase in our accounts receivable balance.

 

While we believethat cash flows from operations will be sufficient to meet a majority of ourcapital expenditures and other cash needs during the remaining six months of2008, the CIG Rocky Mountain index price was extremely volatile during 2007 andat times reached unusually low levels. If natural gas prices trend downward,our cash flows from operations could decrease and the borrowing base and borrowingavailability under our credit facility could be reduced.

 

***Cash Flow from Investing Activities***

 

Net cash used ininvesting activities was approximately $17.0 million for the six months ended June 30,2008, compared to net cash used in investing activities of approximately $10.9million for the six months ended June 30, 2007. The increase was primarilydue to an increase in capital spending on development drilling andinfrastructure along with a realized loss recognized on gas derivatives.

 

***Cash Flow from Financing Activities***

 

Net cash providedby financing activities was approximately $5.0 million for the three monthsended June 30, 2008, compared to net cash provided by financing activitiesof approximately $29.7 million for the six months ended June 30, 2007. Thedecrease was primarily due to net proceeds from an initial public offering of$30.3 million in the second quarter of 2007 offset by $5.0 million drawn on ourcredit facility in the second quarter of 2008.

 

In May 2007,we completed an initial public offering of 3,750,000 shares of our common stockat a price of $9.00 per share, or $8.37 per share net of underwriters’discounts and commissions. Out of the approximately $30.3 million of netproceeds (after underwriters’ discounts and commissions and offering expenses)we received in our initial public offering, we used $7.0 million to pay downall of the outstanding indebtedness under our credit facility. We used theremainder of the net proceeds from our initial public offering for capital expenditures,infrastructure development and general corporate purposes.

 

*Contractual Obligations*

 

Please see Notes3, 5 and 7 of the notes to the unaudited financial statements appearingelsewhere in this quarterly report for information regarding our credit facilityand other indebtedness.

 

The followingtable summarizes by period our contractual obligations as of June 30,2008:

 

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| ** **                                    | ** ** | **Total**               | ** ** | **2008** | ** ** | **2009-2010** | ** ** | **2011-2012** | ** ** | **Thereafter** | ** ** |
|-----------------------------------------------|------------|-------------------------|------------|----------|------------|---------------|------------|---------------|------------|----------------|------------|
| ** **                                    | ** ** | **(In thousands)** | ** ** |
| Derivative instruments                        |       | $                       | 5,910      |     | $          | 2,673         |       | $             | 3,237      |           | —     |   | — |   |
| Notes payable in connection with the mortgage |       | 775                     |       | 12       |       | 51            |       | 58            |       | 654            |       |
| Asset retirement obligations                  |       | 3,154                   |       | 380      |       | 609           |       | 800           |       | 1,365          |       |
| Production and property taxes                 |       | 3,387                   |       | 1,354    |       | 2,033         |       | —        |       | —         |       |
| Total                                         |       | $                       | 13,226     |     | $          | 4,419         |       | $             | 5,930      |           | $          | 858 |   | $ | 2,019 |   |
|                                               |            |                         |            |          |            |               |            |               |            |                |            |  |  |  |  |  |

 

**ITEM3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK**

 

The primaryobjective of the following information is to provide forward-lookingquantitative and qualitative information about our potential exposure to marketrisk. The term “market risk” refers to the risk of loss arising from adversechanges in natural gas prices. This forward-looking information providesindicators of how we view and manage our ongoing market risk exposure. All ofour market risk sensitive instruments were entered into for purposes other thanspeculative trading.

 

**CommodityPrice Risk**

 

Our major marketrisk exposure is in the pricing applicable to our natural gas production. Theprices we receive for our production depend on many factors beyond our control.We seek to reduce our exposure to unfavorable changes in natural gas prices,which are subject to significant and often volatile fluctuation, through theuse of fixed-price contracts. The fixed-price contracts are comprised of energyswaps and collars. These contracts allow us to predict with greater certaintythe effective natural gas prices to be received for hedged production andbenefit operating cash flows and earnings when market prices are less than thefixed prices provided by the contracts. However, we will not benefit frommarket prices that are higher than the fixed prices in the contracts for hedgedproduction. Collar structures provide for participation in price increases anddecreases to the extent of the ceiling prices and floors provided in thosecontracts.

 

The followingtable summarizes the estimated volumes, fixed prices, fixed price sales andfair value attributable to the fixed price contracts as of June 30, 2008.At June 30, 2008, we had hedged volumes through December 2009. Pleasesee “Note 5 — Derivatives” of the notes to the unaudited financial statementsappearing elsewhere in this quarterly report for further information regardingour derivatives.

 
| ** **                                      | ** ** | **Year Ending  December 31, 2008** | ** ** | **Year Ending  December 31, 2009** | ** ** |
|-------------------------------------------------|------------|---------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                      | ** ** | **(Unaudited)**                                   | ** ** | **(Unaudited)**                                   | ** ** |
| **Natural Gas Collars:**                        |       |                                              |       |                                              |       |
| Contract volumes (MMBtu)                        |       |                                              |       |                                              |       |
| Floor                                           |       | 552,000                                           |       | 730,000                                           |       |
| Ceiling                                         |       | 552,000                                           |       | 730,000                                           |       |
| Weighted-average fixed price per MMBtu(1)       |       |                                              |       |                                              |       |
| Floor                                           |       | $                                                 | 6.50       |                                              | $          | 6.50 |   |
| Ceiling                                         |       | $                                                 | 8.20       |                                              | $          | 7.50 |   |
| Fixed-price sales(2)                            |       | $                                                 | 8.20       |                                              | $          | 7.50 |   |
| Fair value, net (thousands)(3)                  |       | $                                                 | (1,068     | )                                                 | $          | (1,695 | ) |
| **Natural Gas Swaps:**                          |       |                                              |       |                                              |       |
| Contract volumes (MMBtu)                        |       | 736,000                                           |       | 912,500                                           |       |
| Weighted-average fixed price sales per MMBtu(1) |       | $                                                 | 6.93       |                                              | $          | 7.17 |   |
| Fair value, net (thousands)(3)                  |       | $                                                 | (1,605     | )                                                 | $          | (1,542 | ) |
| **Total Natural Gas Contracts:**                |       |                                              |       |                                              |       |
| Contract volumes (MMBtu)                        |       | 1,288,000                                         |       | 1,642,500                                         |       |
| Fixed-price sales(2)                            |       | $                                                 | 7.48       |                                              | $          | 7.32 |   |
| Fair value, net (thousands)(3)                  |       | $                                                 | (2,673     | )                                                 | $          | (3,237 | ) |

 

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(1)       Volumeshedged using the CIG index price published in the first issue of Inside FERC’sGas Market Report for each calendar month of the derivative transaction.

 

(2)       Assumesceiling prices for natural gas collar volumes.

 

(3)       Fairvalue based on CIG index price in effect for each month as of June 30,2008.

 

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**Interest Rate Risk**

 

Borrowings underour credit 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 June 30,2008, we had $5.0 million in outstanding indebtedness under our creditfacility.  Borrowing under the creditfacility bears interest either: (i) at a domestic bank rate plus anapplicable margin between 0.25% and 1.25% per annum based on utilization or (ii) ona sliding scale from one, two, three, or six month LIBOR rate plus anapplicable margin between 1.50% and 2.50% per annum based on utilization.  The weighted average interest rate for borrowingsunder our credit facility was 3% for the six months ended June 30, 2008and 3% at June 30, 2008.

 

A hypotheticalchange of 1% in either the domestic bank rate or the LIBOR interest rates wouldincrease gross interest expense approximately $50,000 per year.  

 

**ITEM4T. CONTROLS AND PROCEDURES**

 

**DisclosureControls and Procedures**

 

Based on theirevaluation as of the end of the period covered by this report, our principalexecutive officer and principal financial officer have concluded that ourdisclosure controls and procedures (as defined in Rules 13a-15(e) and15d-15(e) under the Securities Exchange Act of 1934, as amended (the “ExchangeAct”)) are effective to ensure that information required to be disclosed inreports that we file or submit under the Exchange Act is recorded, processed,summarized and reported within the time periods specified in the SEC’s rules andforms.

 

**Changesin Internal Control Over Financial Reporting**

 

During the mostrecent fiscal quarter, there have been no changes in our internal control overfinancial reporting that have materially affected, or are reasonably likely tomaterially affect, our internal control over financial reporting.

 

**PART II. OTHER INFORMATION**

 

**ITEM1. LEGAL PROCEEDINGS**

 

From time to time,we are subject to legal proceedings and claims that arise in the ordinarycourse of our business. While the outcome of these proceedings cannot bepredicted with certainty, we do not currently expect them to have a materialadverse effect on the financial statements.

 

There have been nomaterial developments during the quarter ended June 30, 2008 regarding ourcurrently pending legal proceedings. For a discussion of certain of our currentlegal proceedings, please see “Note 9 — Contingencies” of the notes to theunaudited financial statements appearing elsewhere in this quarterly report.

 

**ITEM1A. RISK FACTORS**

 

The followingdiscussion supplements or updates the risk factors set forth under the heading “RiskFactors” in our annual report on Form 10-K for the year ended December 31,2007 and in our quarterly report on Form 10-Q for the three months ended March 31,2008.

 

***The volatility of natural gas and oil prices could have amaterial adverse******effect on 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, such as:

 

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·**               **the domesticand foreign supply of natural gas and oil;

 

·**               **the activitiesof the Organization of Petroleum Exporting Countries and state-owned oilcompanies relating to oil price and production controls;

 

·**               **overalldomestic and global economic and political conditions;

 

·**               **theconsumption pattern of industrial consumers, electricity generators andresidential users;

 

·**               **weatherconditions;

 

·**               **naturaldisasters;

 

·**               **acts ofterrorism;

 

·**               **politicalstability in the Middle East and elsewhere;

 

·**               **domestic andforeign governmental regulations;

 

·**               **the price andquantity of foreign imports; and

 

·**               **the price andavailability of alternative fuels.

 

In the past,natural gas prices have been extremely volatile, and we expect this volatilityto continue. For example, during the six months ended June 30, 2008, theNYMEX natural gas index price ranged from a high of $13.21 per MMBtu to a lowof $7.38 per MMBtu, while the CIG natural gas index price ranged from a high of$9.43 per MMBtu to a low of $6.08 per MMBtu. During the year ended December 31,2007, the NYMEX natural gas index price ranged from a high of $8.64 per MMBtuto a low of $5.38 per MMBtu, while the CIG natural gas index price ranged froma high of $7.11 per MMBtu to a low of $0.06 per MMBtu.

 

A sharp decline innatural gas prices would result in a commensurate reduction in our revenues,income and cash flows from the production of natural gas and could have amaterial adverse effect on our borrowing base and proved reserves. In the eventprices fall substantially, we may not be able to realize a profit from ourproduction and would operate at a loss, and even relatively modest drops inprices can significantly affect our financial results and impede our growth.Lower natural gas prices may not only decrease our revenues on a per unitbasis, but also may reduce the amount of natural gas that we can produceeconomically. This may result in our having to make substantial downwardadjustments to our estimated proved reserves. For example, if natural gasprices decline by $0.10 per Mcf, then the pre-tax PV-10 of our proved reservesas of June 30, 2008 would decrease from $87.9 million to $85.9 million.Accounting rules may also require us to write down, as a non-cash chargeto earnings, the carrying value of our properties for impairments. As such, wemay incur impairment charges in the future, which could have a material adverseeffect on our results of operations in the period such impairment charges aretaken. For example, we reported an impairment of our oil and gas properties ofapproximately $18.2 million for the year ended December 31, 2007 due tolow and volatile CIG index prices throughout the year. A decline in gas pricesor an increase in operating costs subsequent to the measurement date orreductions in the economically recoverable quantities could result in therecognition of additional ceiling write-downs of our gas properties in futureperiods.

 

***Our credit facility imposes restrictions on us that mayaffect our ability to******successfully operate our business.***

 

Our creditfacility imposes certain operational and financial restrictions on us. Theserestrictions, among other things, limit our ability to:

 

·**               **incurindebtedness;

 

·**               **create liens;

 

·**               **sell ourassets or consolidate or merge with or into other companies;

 

·**               **makeinvestments and other restricted payments, including dividends; and

 

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·**               **engage intransactions with affiliates.

 

These limitationsare subject to a number of important qualifications and expectations. Inaddition, our credit facility requires us to maintain certain financial ratiosand to satisfy certain financial conditions which may limit our borrowingavailability or require us to reduce our debt or to take some other action inorder to comply with them. These restrictions could also limit our ability toobtain future financing, make needed capital expenditures, withstand a downturnin our business or the economy in general, or otherwise conduct necessarycorporate activities. For example, as of June 30, 2008, our borrowing baseunder the credit facility was $17.8 million. However, due to covenantrestrictions, the actual borrowing availability under our credit facility wasapproximately $6.6****million, ofwhich $5.0 million was outstanding under the credit facility. Effective August 4,2008, we entered into an amendment to our credit facility.  Among other things, the amendment increasedthe total quarterly senior debt to annualized EBITDA ratio to 3.0 to 1.0.  Please see “Note 10 — Recent Developments” inthe notes to the financial statements for more information regarding theamendment to the credit facility. We also may be prevented from takingadvantage of business opportunities that arise because of the limitationsimposed on us by the restrictive covenants under our credit facility. Pleasesee Part I, Item 2, “Management’s Discussion and Analysis of FinancialCondition and Results of Operations — Liquidity and Capital Resources — CreditFacility” for further discussion of our credit facility and the covenantrestrictions.

 

**ITEM2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS**

 

Not applicable.

 

**ITEM3. DEFAULTS UPON SENIOR SECURITIES**

 

Not applicable.

 

**ITEM4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS**

 

Not applicable.

 

**ITEM5. OTHER INFORMATION**

 

Not applicable.

 

**ITEM6. 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).                                      |
|                 |       |       |       |                                                                                                                                                                                                                                                                                                |
| *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.                                                                                                               |

 

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| *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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*    Filed herewith

 

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**SIGNATURES**

 

Pursuant to therequirements of the Securities Exchange Act of 1934, the registrant has dulycaused this report to be signed on its behalf by the undersigned thereunto dulyauthorized.

 
|     |   | **PINNACLE  GAS RESOURCES, INC.** |
|----------|--------|-----------------------------------|
|     |   |                              |
|     |   | By:                               | /s/ Peter G.  Schoonmaker |
|     |   |                              | Name: | Peter G. Schoonmaker |
|     |   |                              | Title: | *President,  Chief Executive Officer and Director* |
|     |   |                              |   | (Principal Executive  Officer) |
|     |   |                              |
|     |   | Date: August 14,  2008       |
|     |   |                              |
|     |   | 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: August 14,  2008       |

 

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