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**UNITEDSTATES****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 September 30, 2008**                                                                                                                                                                                                                                                                                                                            |
|       |       |                                                                                                                                                                                                                                                                                                                                                                                   |
|       |       | **or**                                                                                                                                                                                                                                                                                                                                                                                 |
|       |       |                                                                                                                                                                                                                                                                                                                                                                                   |
| ** ̈** | ** ** | **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**

 

**PinnacleGas 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 markwhether the registrant (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding 12months (or for such shorter period that the registrant was required to filesuch reports), and (2) has been subject to such filing requirements forthe past 90 days. Yes xNo  ̈

 

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer or a smaller reporting company. See the definitions of “largeaccelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2of the Exchange Act. (Check one):

 
| Large  accelerated filer  ̈ |   | Accelerated  filer  ̈                      |   | Non-accelerated  filer x |   | Smaller  reporting company  ̈ |
|---------------------------------|--------|------------------------------------------------|--------|--------------------------|--------|-----------------------------------|
|                            |   | (Do not check if  a smaller reporting company) |
|                                 |        |                                                |        |                          |        |                                   |  |  |

 

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

 

29,220,238 shares of theregistrant’s Common Stock were outstanding as of November 13, 2008.

 

 

 

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**PINNACLEGAS RESOURCES, INC.**

Index to Form 10-Q

 
| ** **                                                                                                  | Page |
|-------------------------------------------------------------------------------------------------------------|------|
| Cautionary Statement Concerning Forward-Looking  Statements                                                 | 1    |
| Part I. FINANCIAL INFORMATION                                                                          | 3    |
| Item 1. Financial Statements                                                                                | 3    |
| Balance Sheets as of  December 31, 2007 and September 30, 2008                                    | 3    |
| Statements of  Operations (unaudited) for the three and nine months ended September 30,  2007 and 2008 | 4    |
| Statements  of Cash Flows (unaudited) for the nine months ended September 30, 2007  and 2008           | 5    |
| Statements  of Stockholders’ Equity at September 30, 2008                                         | 6    |
| Notes  to Financial Statements (unaudited)                                                                  | 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                                                                              | 21   |
| Results  of Operations                                                                                      | 22   |
| Liquidity and Capital Resources                                                                             | 26   |
| Item 3. Quantitative and Qualitative Disclosures About  Market Risk                                         | 29   |
| Item 4T. Controls and Procedures                                                                            | 30   |
| Part II.  OTHER INFORMATION                                                                            | 31   |
| Item  1. Legal Proceedings                                                                                  | 31   |
| Item 1A. Risk Factors                                                                                       | 31   |
| Item 2. Unregistered Sales of Equity Securities and  Use of Proceeds                                        | 33   |
| Item 3. Defaults Upon Senior Securities                                                                     | 33   |
| Item 4. Submission of Matters to a Vote of Security  Holders                                                | 33   |
| Item  5. Other Information                                                                                  | 33   |
| Item 6. Exhibits                                                                                            | 34   |

 

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**CAUTIONARY STATEMENT CONCERNINGFORWARD-LOOKING STATEMENTS**

 

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

 

·                  Projections and estimatesconcerning the timing and success of specific projects;

 

·                  Our financial position or operating results;

 

·                  Our business strategy;

 

·                  Our budgets;

 

·                  The amount, nature and timing of capitalexpenditures;

 

·                  The drilling of wells;

 

·                  The development of recently acquired natural gas andoil properties;

 

·                  The timing and amount of future production ofnatural gas and oil;

 

·                  Our operating costs and other expenses;

 

·                  Our estimated future net revenues from natural gasand oil reserves and the present value thereof;

 

·                  Our cash flow and anticipated liquidity; and

 

·                  Our other plans andobjectives for future operations.

 

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

 

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

 

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

 

·                  Fluctuations in the commodity prices for natural gasand crude oil;

 

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

 

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·                  The effects of government regulation and permittingand other legal requirements;

 

·                  Labor problems;

 

·                  Environmental-related problems;

 

·                  The uncertainty inherent in estimating futurenatural gas 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 andoil business, including down-hole drilling and completion risks that aregenerally not 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 andequipment;

 

·                  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 economicconditions; and

 

·                  Regional price differentials.

 

When you consider theseforward-looking statements, you should keep in mind these factors and the otherfactors discussed in the “Risk Factors” sections of our annual report on Form 10-Kfor 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**

 

**PINNACLEGAS RESOURCES, INC.**

**BalanceSheets**

 
| ** **                                                                                                                                                                               | ** ** | **September 30,  2008**                                                   | ** ** | **December 31,  2007** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                                                                                                                               | ** ** | **(unaudited)**                                                                | ** ** | ** **                  | ** ** |
| ** **                                                                                                                                                                               | ** ** | **(in thousands, except  share and  per share data)** | ** ** |
| **Assets**                                                                                                                                                                               |       |                                                                           |       |                        |       |
| Current assets                                                                                                                                                                           |       |                                                                           |       |                        |       |
| Cash and cash  equivalents                                                                                                                                                               |       | $                                                                              | 179        |                        | $          | 8,151 |   |
| Deposits                                                                                                                                                                                 |       | 203                                                                            |       | —                      |       |
| Receivables                                                                                                                                                                              |       |                                                                           |       |                        |       |
| Accrued gas  sales                                                                                                                                                                       |       | 997                                                                            |       | 3,062                       |       |
| Joint interest  receivables, net of $100 allowance for doubtful accounts                                                                                                                 |       | 6,856                                                                          |       | 6,040                       |       |
| Derivative  instruments                                                                                                                                                                  |       | 3,400                                                                          |       | 556                         |       |
| Inventory of  material for drilling and completion                                                                                                                                       |       | 236                                                                            |       | 174                         |       |
| Prepaid expenses                                                                                                                                                                         |       | 275                                                                            |       | 1,322                       |       |
| Total current  assets                                                                                                                                                                    |       | 12,146                                                                         |       | 19,305                      |       |
| Property and  equipment, at cost, net of accumulated depreciation                                                                                                                        |       | 2,037                                                                          |       | 2,226                       |       |
| Oil and gas  properties, using full cost accounting, net of accumulated depletion and  impairment                                                                                        |       |                                                                           |       |                        |       |
| Proved                                                                                                                                                                                   |       | 51,073                                                                         |       | 33,965                      |       |
| Unproved                                                                                                                                                                                 |       | 92,087                                                                         |       | 88,820                      |       |
| Inventory held  for exploration and development                                                                                                                                          |       | 438                                                                            |       | 505                         |       |
| Derivative  instruments                                                                                                                                                                  |       | 642                                                                            |       | —                      |       |
| Deposits                                                                                                                                                                                 |       | —                                                                         |       | 20                          |       |
| Restricted  certificates of deposit                                                                                                                                                      |       | 2,726                                                                          |       | 1,752                       |       |
| Total assets                                                                                                                                                                             |       | $                                                                              | 161,149    |                        | $          | 146,593 |   |
| **Liabilities and Stockholders’ Equity**                                                                                                                                            |       |                                                                           |       |                        |       |
| Current  liabilities                                                                                                                                                                     |       |                                                                           |       |                        |       |
| Long-term debt,  current portion                                                                                                                                                         |       | $                                                                              | 24         |                        | $          | 23 |   |
| Trade accounts  payable                                                                                                                                                                  |       | 13,130                                                                         |       | 7,795                       |       |
| Revenue  distribution payable                                                                                                                                                            |       | 6,154                                                                          |       | 6,534                       |       |
| Asset retirement  obligation, current                                                                                                                                                    |       | 341                                                                            |       | 363                         |       |
| Accrued  liabilities                                                                                                                                                                     |       | 2,300                                                                          |       | 2,241                       |       |
| Total current  liabilities                                                                                                                                                               |       | 21,949                                                                         |       | 16,956                      |       |
| Asset retirement  obligations, non-current                                                                                                                                               |       | 2,973                                                                          |       | 2,404                       |       |
| Production  taxes, non-current                                                                                                                                                           |       | 1,961                                                                          |       | 633                         |       |
| Long-term debt,  non-current                                                                                                                                                             |       | 8,245                                                                          |       | 763                         |       |
| Total  liabilities                                                                                                                                                                       |       | 35,128                                                                         |       | 20,756                      |       |
| Contingencies                                                                                                                                                                            |       |                                                                           |       |                        |       |
| Series A  Redeemable Preferred stock, $0.01 par value. 25,000,000 authorized, 0 shares  issued and outstanding at September 30, 2008 and December 31, 2007,  respectively |       | —                                                                         |       | —                      |       |
| Stockholders’  equity                                                                                                                                                               |       |                                                                           |       |                        |       |
| Common stock,  $0.01 par value, 100,000,000 authorized and 29,231,271 and 29,019,751 shares  issued and outstanding at September 30, 2008 and December 31, 2007,  respectively |       | 289                                                                            |       | 289                         |       |
| Additional  paid-in capital                                                                                                                                                              |       | 150,467                                                                        |       | 149,701                     |       |
| Accumulated  deficit                                                                                                                                                                     |       | (24,735                                                                        | )          | (24,153                     | )          |
| Total  stockholders’ equity                                                                                                                                                         |       | 126,021                                                                        |       | 125,837                     |       |
| Total  liabilities and stockholders’ equity                                                                                                                                         |       | $                                                                              | 161,149    |                        | $          | 146,593 |   |

 

See Notes to FinancialStatements (unaudited)

 

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**PINNACLE GAS RESOURCES, INC.**

**Statements of Operations**

**(unaudited)**

 
| ** **                                             | ** ** | **Three Months Ended  September 30,**                                   | ** ** | **Nine Months Ended  September 30,** | ** ** |
|--------------------------------------------------------|------------|----------------------------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                             | ** ** | **2008**                                                                               | ** ** | **2007**                                            | ** ** | **2008** | ** ** | **2007** | ** ** |
| ** **                                             | ** ** | **(in thousands, except share and per share data)** | ** ** |
| Revenues                                               |       |                                                                                   |       |                                                |       |   |   |   |   |
| Gas sales                                              |       | $                                                                                      | 5,684      |                                                | $          | 2,722 |   | $ | 18,918 |   | $ | 9,812 |   |
| Total revenues                                         |       | 5,684                                                                                  |       | 2,722                                               |       | 18,918 |   | 9,812 |   |
| Cost of revenues  and expenses                         |       |                                                                                   |       |                                                |       |   |   |   |   |
| Lease operating  expenses                              |       | 1,793                                                                                  |       | 1,322                                               |       | 5,191 |   | 3,458 |   |
| Production taxes                                       |       | 645                                                                                    |       | 278                                                 |       | 2,164 |   | 1,037 |   |
| Marketing and  transportation                          |       | 1,165                                                                                  |       | 911                                                 |       | 3,452 |   | 2,594 |   |
| General and  administrative, net                       |       | 1,334                                                                                  |       | 1,488                                               |       | 5,925 |   | 3,816 |   |
| Depreciation,  depletion, amortization and accretion   |       | 2,664                                                                                  |       | 1,704                                               |       | 6,677 |   | 4,800 |   |
| Impairment of  oil and gas properties                  |       | —                                                                                 |       | 70                                                  |       | — |   | 18,225 |   |
| Total cost of  revenues and expenses                   |       | 7,601                                                                                  |       | 5,773                                               |       | 23,409 |   | 33,930 |   |
| Operating loss                                         |       | (1,917                                                                                 | )          | (3,051                                              | )          | (4,491 | ) | (24,118 | ) |
| Other income  (expense)                                |       |                                                                                   |       |                                                |       |   |   |   |   |
| Gain on  derivatives                                   |       | 10,676                                                                                 |       | 1,604                                               |       | 3,441 |   | 2,069 |   |
| Interest income                                        |       | 40                                                                                     |       | 234                                                 |       | 139 |   | 532 |   |
| Other income                                           |       | 201                                                                                    |       | 88                                                  |       | 424 |   | 312 |   |
| Interest expense                                       |       | (61                                                                                    | )          | (26                                                 | )          | (96 | ) | (168 | ) |
| Total other  income                                    |       | 10,856                                                                                 |       | 1,900                                               |       | 3,908 |   | 2,745 |   |
| Net  (loss)/income before income taxes                 |       | 8,939                                                                                  |       | (1,151                                              | )          | (583 | ) | (21,373 | ) |
| Income taxes                                           |       | —                                                                                 |       | —                                              |       | — |   | — |   |
| Net  (loss)/income attributable to common stockholders |       | 8,939                                                                                  |       | $                                                   | (1,151     | ) | (583 | ) | $ | (21,373 | ) |
| Basic net  (loss)/income per share                     |       | $                                                                                      | 0.31       |                                                | $          | (0.04 | ) | $ | (0.02 | ) | $ | (0.80 | ) |
| Diluted net  (loss)/income per share                   |       | $                                                                                      | 0.30       |                                                | $          | (0.04 | ) | $ | (0.02 | ) | $ | (0.80 | ) |
| Weighted average  shares outstanding – basic      |       | 29,146,543                                                                             |       | 29,014,299                                          |       | 29,054,181 |   | 26,695,765 |   |
| Weighted average  shares outstanding – diluted    |       | 29,887,521                                                                             |       | 29,014,299                                          |       | 29,054,181 |   | 26,695,765 |   |

 

See Notes to Financial Statements (unaudited)

 

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

**(unaudited)**

 
| ** **                                                                                | ** ** | **For the Nine  Months Ended  September 30,** | ** ** |
|-------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------|------------|
| ** **                                                                                | ** ** | **2008**                                                          | ** ** | **2007** | ** ** |
| Cash flows from  operating activities                                                     |       |                                                              |       |   |   |
| Net loss                                                                                  |       | $                                                                 | (583       | ) | $ | (21,373 | ) |
| Adjustments to  reconcile net loss to net cash (used in)/provided by operating activities |       |                                                              |       |   |   |
| Impairment of  oil and gas properties                                                     |       | —                                                            |       | 18,225 |   |
| Depreciation,  depletion, amortization and accretion                                      |       | 6,677                                                             |       | 4,800 |   |
| Gain on  derivatives                                                                      |       | (3,441                                                            | )          | (2,069 | ) |
| Stock-based  compensation                                                                 |       | 772                                                               |       | 619 |   |
| Changes in  assets and liabilities                                                        |       |                                                              |       |   |   |
| Decrease in  receivables                                                                  |       | 1,249                                                             |       | 3,797 |   |
| Increase in  inventory of material for drilling and completion                            |       | (62                                                               | )          | (43 | ) |
| Asset retirement  obligations settled this period                                         |       | (48                                                               | )          | — |   |
| Decrease in  prepaid expenses                                                             |       | 1,047                                                             |       | 117 |   |
| (Decrease)/increase  in accounts payable and accrued liabilities                          |       | 5,121                                                             |       | (12,911 | ) |
| Decrease in  revenue distribution payable                                                 |       | (380                                                              | )          | (1,561 | ) |
| Net cash (used  in)/provided by operating activities                                      |       | 10,352                                                            |       | (10,399 | ) |
| Cash flows from  investing activities                                                     |       |                                                              |       |   |   |
| Capital  expenditures — exploration and production                                   |       | (24,106                                                           | )          | (14,940 | ) |
| Capital  expenditures — property and equipment                                       |       | (561                                                              | )          | (840 | ) |
| Decrease  (increase) in restricted certificates of deposit                                |       | (974                                                              | )          | 43 |   |
| Decrease in  inventory held for exploration and development                               |       | 67                                                                |       | 117 |   |
| Decrease  (increase) in deposits                                                          |       | (183                                                              | )          | 500 |   |
| Realized gain  (loss) on derivatives                                                      |       | (44                                                               | )          | 3,299 |   |
| Net cash used in  investing activities                                                    |       | (25,801                                                           | )          | (11,821 | ) |
| Cash flows from  financing activities                                                     |       |                                                              |       |   |   |
| Proceeds from  the issuance of common stock                                               |       | —                                                            |       | 33,750 |   |
| Offering costs  related to common stock                                                   |       | (6                                                                | )          | (4,130 | ) |
| Proceeds from  long-term debt                                                             |       | 7,500                                                             |       | — |   |
| Principal  payments on long-term debt                                                     |       | (17                                                               | )          | (15 | ) |
| Net cash  provided by financing activities                                                |       | 7,477                                                             |       | 29,605 |   |
| Net increase  (decrease) in cash and cash equivalents                                     |       | (7,972                                                            | )          | 7,385 |   |
| Cash and cash  equivalents at beginning of year                                           |       | 8,151                                                             |       | 4,762 |   |
| Cash and cash  equivalents at end of period                                               |       | $                                                                 | 179        |   | $ | 12,147 |   |
| Non-cash  investing and financing activities                                              |       |                                                              |       |   |   |
| Capital  expenditures included in trade accounts payable                                  |       | $                                                                 | 7,481      |   | $ | 3,452 |   |
| Asset retirement  obligation included in oil and gas properties                           |       | 410                                                               |       | 182 |   |
| Supplemental  cash flow information                                                       |       |                                                              |       |   |   |
| Cash payments  for interest, net of amount capitalized                                    |       | $                                                                 | 95         |   | $ | 168 |   |

 

See Notes to Financial Statements (unaudited)

 

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**PINNACLE GAS RESOURCES, INC.Statement of Stockholders’ Equity**

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

 
| ** **                                                          | ** ** | **Stockholders’ Equity** | ** ** |
|---------------------------------------------------------------------|------------|------------------------------------|------------|
| ** **                                                          | ** ** | **Common Stock**              | ** ** | **Additional  Paid-In** | ** ** | **Accumulated** | ** ** | ** ** | ** ** |
| ** **                                                          | ** ** | **Shares**                         | ** ** | **Amount** | ** ** | **Capital** | ** ** | **Deficit** | ** ** | **Total** | ** ** |
| Balance at December 31,  2007                                  |       | 29,019,751                         |       | $ | 289 |   | 149,701 |   | $ | (24,152 | ) | $ | 125,838 |   |
| Forfeiture of  restricted shares (unaudited)                        |       | (33,130                            | )          | — |   | — |   | — |   | — |   |
| Issuance of  restricted shares (unaudited)                          |       | 244,650                            |       | — |   | — |   | — |   | — |   |
| Offering costs  related to the issuance of common stock (unaudited) |       | —                             |       | — |   | (6 | ) | — |   | (6 | ) |
| Stock-based  compensation (unaudited)                               |       | —                             |       | — |   | 772 |   | — |   | 772 |   |
| Net loss  (unaudited)                                               |       | —                             |       | — |   | — |   | (583 | ) | (583 | ) |
| Balance at  September 30, 2008 (unaudited)                     |       | $                                  | 29,231,271 |   | $ | 289 |   | $ | 150,467 |   | $ | (24,735 | ) | $ | 126,021 |   |
|                                                                     |            |                                    |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

See Notes toFinancial Statements (unaudited)

 

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**Notes to Financial Statements**

**Unaudited**

 

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

 

Pinnacle GasResources, Inc. (“Pinnacle” or the “Company”) was formed as a Delawarecorporation in June 2003 through a contribution of cash by fundsaffiliated with DLJ Merchant Banking and oil and gas reserves and leaseholdinterests by subsidiaries of Carrizo Oil & Gas, Inc. and U.S.Energy Corporation.

 

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

 

***Note 2 — Basis of Presentation***

 

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

 

The accompanyingfinancial statements are unaudited, and in the opinion of management, reflectall adjustments that are necessary for a fair presentation of the financialposition and results of operations for the periods presented.  All such adjustments are of a normal andrecurring nature. The following notes describe only the material changes inaccounting policies, account details, or financial statement notes during thefirst nine months of 2008.  The resultsfor the three and nine months ended September 30, 2008 are not necessarilyindicative of the results expected for the entire year.  These financial statements should be read inconjunction with the audited financial statements and the summary ofsignificant accounting policies for prior years contained in the reports theCompany files with the Securities and Exchange Commission, which can be foundon the Company’s website at www.pinnaclegas.com.

 

*Use of Estimates*

 

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

 

*Oil and Gas Properties*

 

The Company utilizes the full cost method ofaccounting for oil and gas producing activities. Under this method, all costsassociated with property acquisition, exploration and development, includingcosts of unsuccessful exploration, costs of surrendered and abandonedleaseholds, delay lease rentals and the fair value of estimated future costs ofsite restoration, dismantlement and abandonment activities are capitalizedwithin a cost center. The Company’s oil and gas properties are all locatedwithin the United States, which constitutes a single cost center. The Companyhas not capitalized any overhead costs. No gain or loss is recognized upon thesale or abandonment of undeveloped or producing oil and gas properties unlessthe sale represents a significant portion of gas properties and the gainsignificantly alters the relationship between capitalized costs and proved gasreserves of the cost center. Expenditures for maintenance and repairs arecharged to lease operating expense in the period incurred.

 

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Depreciation,depletion and amortization of oil and gas properties (“DD&A”) is computedon the unit-of-production method based on proved reserves. Amortizable costsinclude estimates of future development costs of proved undeveloped reservesand asset retirement obligations. The Company invests in unevaluated oil andgas properties for the purpose of exploration for proved reserves. The costs ofsuch assets, including exploration costs on properties where a determination ofwhether proved oil and gas reserves will be established is still underevaluation, and any capitalized interest are included in unproved oil and gasproperties at the lower of cost or estimated fair market value and are notsubject to amortization. On a quarterly basis, such costs are evaluated forinclusion in the costs to be amortized resulting from the determination ofproved reserves, impairments, or reductions in value. To the extent that theevaluation indicates these properties are impaired, the amount of theimpairment is added to the capitalized costs to be amortized. Abandonment ofunproved properties is accounted for as an adjustment to capitalized costsrelated to proved oil and gas properties, with no losses recognized. TheCompany recorded an impairment of unevaluated properties of $1.6 million duringeach of the three and nine months ended September 30, 2008. Substantiallyall of the remaining unproved property costs are expected to be developed andincluded in the amortization base over the next three to five years. Salvagevalue is taken into account in determining depletion rates and is based on theCompany’s estimate of the value of equipment and supplies at the time the wellis abandoned. As of September 30, 2008 and December 31, 2007, theestimated salvage value was $7.3 million and $6.4 million, respectively.

 

Under full costmethod of accounting rules, capitalized costs less accumulated depletion andrelated deferred income taxes may not exceed a “ceiling” value which is the sumof (1) the present value discounted at 10% of estimated future net revenueusing current prices and costs, including the effects of derivative instrumentsdesignated as cash flow hedges but excluding the future cash outflowsassociated with settling asset retirement obligations that have been accrued onthe balance sheet, less any related income tax effects, plus (2) the costof properties not being amortized, if any, plus (3) the lower of costs orestimated fair value of unproved properties, less (4) the income taxeffects related to differences in the book to tax basis of oil and gasproperties. This is referred to as the “full cost ceiling limitation.” Ifcapitalized costs exceed the limit, the excess must be charged to expense. Theexpense may not be reversed in future periods. At the end of each quarter, theCompany calculates the full cost ceiling limitation.

 

At September 30,2008, the full cost ceiling limitation exceeded the capitalized cost of oil andgas by approximately $21.4 million based upon a natural gas price of $3.62 perMcf (based on the Colorado Interstate Gas Rocky Mountain Index) in effect atthat date. Based on the subsequent price increase to approximately $4.95 perMcf on November 11, 2008, the full cost ceiling limitation exceeded thecapitalized cost of the Company’s oil and gas properties by approximately $2.6million.   Therefore, the Company did notrecord an impairment for the three and nine months ended September 30,2008.  An impairment of approximately$18.2 million was recorded for the nine months ended September 30, 2007.This impairment of the Company’s oil and gas properties resulted from lowcommodity prices throughout 2007, specifically at the end of the first, secondand third quarters of 2007. A decline in gas prices or an increase in operatingcosts subsequent to the measurement date or reductions in economicallyrecoverable reserve quantities could result in the recognition of additionalimpairments of the Company’s oil and gas properties in future periods.

 

*Per Share Information*

 

The Company follows theprovisions of SFAS No. 128, “Accounting for Earnings per Share.” Under SFAS No. 128,basic earnings (loss) per share is computed by dividing net income (loss) fromcontinuing operations attributable to common stock by the weighted averagenumber of shares of common stock outstanding during each period. Dilutedearnings per share is computed by adjusting the average number of shares ofcommon stock outstanding for the dilutive effect, if any, of common stockequivalents such as stock options and warrants. For the three months ended September 30,2008, diluted net income per share was $0.30, while basic net income per sharewas $0.31. Certain options to purchase shares of Pinnacle’s common stock wereexcluded from the dilution calculations because the shares wereanti-dilutive.  During the nine monthsended September 30, 2008, 717,500 options were excluded because they wereanti-dilutive.  During the nine monthsended September 30, 2007, 907,000 options were excluded because they wereanti-dilutive.

 

*Income Taxes*

 

The Company usesthe asset and liability method of accounting for income taxes, in accordancewith Statement of Financial Accounting Standards (SFAS) No. 109, “Accountingfor Income Taxes.” Deferred tax assets and liabilities are recognized for theexpected future tax consequences of temporary differences between the financialstatements and tax basis of assets and liabilities. If appropriate, deferredtax assets are reduced by a valuation allowance which reflects expectations ofthe extent to which such assets will be realized. As of September 30, 2008and December 31, 2007, the Company had recorded a full valuation allowancefor its net deferred tax asset.

 

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On January 1,2007, the Company adopted Financial Accounting Standards Board (FASB)Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — aninterpretation of FASB Statement No. 109” (FIN 48).  FIN 48 prescribes a measurement process forrecording in the financial statements uncertain tax positions taken or expectedto be taken in a tax return. Additionally, FIN 48 provides guidance regarding uncertain tax positionsrelating to derecognition, classification, interest and penalties, accountingin interim periods, disclosure and transition. At September 30, 2008, the Company had no material uncertain taxpositions or penalties or interest recorded.

 

*RecentAccounting Pronouncements*

 

          In February 2007, the FASB issued SFAS No. 159, “TheFair Value 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 the Company. SFAS No. 159offers various options in electing to apply its provisions. The Company decidednot to elect fair value accounting for any of its eligible items other thanderivatives (See Note 5) which were being accounted for under a fair value methodprior to the adoption of SFAS No. 159.

 

          In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities.” SFAS No. 161is intended to improve financial reporting by requiring transparency about thelocation and amounts of derivative instruments in an entity’s financialstatements, how derivative instruments and related hedged items are accountedfor under SFAS No. 133, 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.

 

***Note 3**— Asset RetirementObligations***

 

The Companyfollows the provisions of SFAS No. 143, “Accounting for Asset RetirementObligations.” SFAS No. 143 generally applies to legal obligationsassociated with the retirement of long-lived assets that result from theacquisition, construction, development and/or normal operation of a long-livedasset. SFAS No. 143 requires the Company to recognize an estimatedliability for costs associated with the abandonment of its oil and gas properties.A liability for the fair value of an asset retirement obligation with acorresponding increase to the carrying value of the related long-lived asset isrecorded at the time a well is completed or acquired. The increased carryingvalue is depleted using the units-of-production method, and the discountedliability is increased through accretion over the remaining economic life ofthe respective oil and gas properties.

 

The estimatedliability is based on historical gas industry experience in abandoning wells,including estimated economic lives, external estimates as to the cost toabandon the wells in the future and federal and state regulatory requirements.The Company’s liability is discounted using the Company’s best estimate of itscredit-adjusted risk free rate. Revisions to the liability could occur due tochanges in estimated abandonment costs or changes in well economic lives or iffederal or state regulators enact new requirements regarding the abandonment ofwells.

 

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The following is asummary of the Company’s asset retirement obligation activity for the three andnine months ended September 30, 2008 and 2007 (in thousands):

 
| ** **                                      | ** ** | **Three  Months Ended  September 30,** | ** ** | **Nine  Months Ended  September 30,** | ** ** | **Three  Months Ended  September 30,** | ** ** | **Nine  Months Ended  September 30,** | ** ** |
|-------------------------------------------------|------------|--------------------------------------------------|------------|-------------------------------------------------|------------|--------------------------------------------------|------------|-------------------------------------------------|------------|
| ** **                                      | ** ** | **2008**                                         | ** ** | **2007**                                        | ** ** |
| ** **                                      | ** ** | **(unaudited)**                                  | ** ** | **(unaudited)**                                 | ** ** |
| Beginning  balance asset retirement obligations |       | $                                                | 3,154      |                                            | 2,767      |                                             | $          | 2,533                                           |       | $ | 2,321 |   |
| Additional  obligations added during the period |       | 142                                              |       | 410                                             |       | 69                                               |       | 182                                             |       |
| Obligations  settled during the period          |       | (48                                              | )          | (48                                             | )          | —                                           |       | —                                          |       |
| Accretion  expense                              |       | 66                                               |       | 185                                             |       | 53                                               |       | 152                                             |       |
| Ending balance  of asset retirement obligations |       | 3,314                                            |       | 3,314                                           |       | $                                                | 2,655      |                                            | $          | 2,655 |   |
|                                                 |            |                                                  |            |                                                 |            |                                                  |            |                                                 |            |  |  |  |

 

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

 

*Certificates of Deposit*

 

The Company holds acertificate of deposit (“CD”), which expires in July 2009, totaling$158,000. The CD is collateral on bonding required by the State of Wyoming, theState of Montana and the Federal Bureau of Land Management. Because the Companyintends to renew the CD in order to maintain its bonding requirements, theCompany has included the CD in other non-current assets as of September 30,2008. Additionally, the Company holds two CDs for $604,000 and $964,000 whichwere issued in February 2006 and May 2008 and will expire in February 2009and May 2009, respectively. These CDs collateralize letters of credit infavor of Powder River Energy Corporation, a local rural electric association,in order to secure power lines to the Kirby, Deer Creek and Cabin Creek areas.The Company has included these amounts in non-current assets as of September 30,2008 because the Company also intends to renew these CDs in order to maintain apower supply on a long-term basis. In April 2007, the Company issued a$1,000,000 letter of credit that expires in April 2009 in favor of BitterCreek Pipelines, LLC to secure the construction of a high pressure pipeline andrelated compression facilities to the Company’s Deer Creek and Kirby areas. TheCompany has included this amount in non-current assets as of September 30,2008  because the  pipeline and compression facilities are notexpected to be completed and fully utilized until the end of 2009.

 

*Deposits*

 

The Company has included approximately $187,000related to royalty payments in deposits. These amounts are included in depositsin the accompanying balance sheet at September 30, 2008.

 

***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.

 

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As of September 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** | ** **  |
|-------------------------------------------------------------------|------------|-------------------------|------------|--------------------------------------------------------|-------------|------------------|-------------|
| September 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 |   |
| September 30,  2007 (unaudited)                              |       |                    |       |                                                   |        |             |        |
| Natural  Gas—Collar                                          |       | 1,000                   |       | $                                                      | 6.50-$10.50 |             | 9/06-12/07  |   |
| Natural  Gas—Collar                                          |       | 3,000                   |       | $                                                      | 7.00-$9.05  |             | 1/07-12/07  |   |
| Natural  Gas—Collar                                          |       | 3,000                   |       | $                                                      | 6.50-$8.20  |             | 1/08-12/08  |   |

 

The Company realized hedging gains of $725,000 and$1,623,000 during the three months ended September 30, 2008 and 2007,respectively. As a result of the change in the fair value of the commodityderivatives, the Company had an unrealized gain of $9,951,000 for the threemonths ended September 30, 2008 and an unrealized loss of $19,000 for thethree months ended September 30, 2007.  The aggregate of these contracts resulted in a gain on derivatives of$10,676,000 and $1,604,000 for the three months ended September 30, 2008and 2007, respectively. For the nine months ended September 30, 2008, theCompany realized a hedging loss of $44,000 as compared to a hedging gain of$3,299,000 for the nine months ended September 30, 2007. The Company hadan unrealized gain of $3,485,000 for the nine months ended September 30,2008 and an unrealized loss of $1,230,000 for the nine months ended September 30,2007. The aggregate of these contracts resulted in a gain on derivatives of$3,441,000 and $2,069,000 for the nine months ended September 30, 2008 and2007, respectively. Unrealized and realized gains and losses are included ingains or losses on derivatives in the accompanying statements of operations.Because the Company’s derivative contracts were not accounted for as cash flowhedges, the Company classifies the realized gains and losses in investingactivities 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***

 

*Options under Employee Option Plans*

 

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

 

Options 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 theoption holder owns more than 10% of the total combined voting power of allclasses of the Company’s stock, in which case the non-statutory stock optionsmust be exercised within five years of the date of grant. At September 30,2008, there were options to purchase 717,500 shares 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 | % |

 

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*Stock-Based Compensation*

 

At September 30,2008, the Company had unvested options to purchase 197,500 shares with aweighted average grant date fair value of $528,000. During the three and ninemonths ended September 30, 2008, the Company did not grant any options topurchase common stock. The Company will recognize compensation expense relatingto nonvested options granted after January 1, 2007 ratably over the nextthree years. The Company recognized an expense of approximately $183,000 and$438,000 for the three and nine months ended September 30, 2008,respectively, based on the fair value of the vested options.

 

The followingtable summarizes stock option activity for the nine months ended September 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                |       | (153,500                   | )          | 8.14                                                           |       |                                                    |       |                                |       |
|                                  |       |                       |       |                                                           |       |                                                    |       |                                |       |
| Outstanding,  September 30, 2008 |       | 717,500                    |       | $                                                              | 6.22       |                                                    | 3.69       |                                | $          | — |   |
|                                  |       |                       |       |                                                           |       |                                                    |       |                                |       |
| Exercisable,  September 30, 2008 |       | 520,000                    |       | $                                                              | 5.81       |                                                    | 3.39       |                                | $          | — |   |

 

The following table summarizes information about stockoptions outstanding at September 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    |                                                    | 2.0 years  |                    | 137,500    |   | $ | 4.00 |   | Black-Scholes |   |
|                     |       |                                    |       |                                                    |       |                    |       |   |   | (minimum value) |   |
| $                        | 4.80       |                                    | 282,500    |                                                    | 3.5 years  |                    | 222,500    |   | $ | 4.80 |   | Black-Scholes |   |
|                     |       |                                    |       |                                                    |       |                    |       |   |   | (minimum value) |   |
| $                        | 5.20       |                                    | 112,500    |                                                    | 4.3 years  |                    | 56,250     |   | $ | 5.20 |   | Black-Scholes |   |
| $                        | 8.40       |                                    | 25,000     |                                                    | 5.7 years  |                    | 12,500     |   | $ | 8.40 |   | Black-Scholes |   |
| $                        | 11.00      |                                    | 160,000    |                                                    | 4.7 years  |                    | 91,250     |   | $ | 11.00 |   | Black-Scholes |   |
|                     |       | 717,500                                 |       |                                                    |       | 520,000                 |       |   |   |   |   |

 

*RestrictedStock*

 

The Company has a stockincentive plan whereby grants of restricted stock have been awarded to membersof the Board of Directors and certain employees. Restrictions and vestingperiods for the awards are determined at the discretion of the Board ofDirectors and are set forth in the award agreements.

 

During the three and ninemonths ended September 30, 2008, the Company recognized compensationexpense of approximately $156,000 and $334,000, respectively, based on the fairvalue of the vested shares.

 

A summary of the status and activity of the restrictedstock for the nine months ended September 30, 2008 is presented below.

 
| ** **                           | ** ** | **Shares** | ** ** | **Weighted-Average  Grant-Date  Fair Value** | ** ** |
|--------------------------------------|------------|------------|------------|---------------------------------------------------|------------|
| Unvested at  December 31, 2007  |       | 147,540    |       | $                                                 | 8.57       |   |
| Granted                              |       | 244,650    |       | $                                                 | 2.77       |   |
| Forfeited                            |       | (24,040    | )          | $                                                 | 7.38       |   |
| Vested                               |       | (39,375    | )          | $                                                 | 8.31       |   |
| Unvested at  September 30, 2008 |       | 328,775    |       | $                                                 | 4.24       |   |

 

As of September 30,2008, the Company had approximately $1,166,000 of unrecognized share-basedcompensation expense related to unvested stock awards, which is expected to beamortized over the remaining vesting periods of 3 to 5 years.

 

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***Note7*— *Long-Term Debt***

 

*CreditFacility*

 

Effective February 12,2007, the Company entered into a credit facility (the “Credit Agreement”) withThe Royal Bank of Scotland (“RBS”), which permits borrowings up to theborrowing base as designated by the administrative agent. As of September 30,2008, the borrowing base under the Credit Agreement was $16.8 million, and theCompany had $7.5 million of debt outstanding under the Credit Agreement.  Please see Note 10 — Subsequent Events.

 

The borrowing base isdetermined on a semi-annual basis and at such other times, up to twice yearly,as may be requested by the borrower or administrative agent.  Effective October 1, 2008, the administrativeagent established a new borrowing base under the Credit Agreement of $14.5million.  The new borrowing base will beautomatically reduced by approximately $666,667 per month for six months,beginning on November 1, 2008.

 

Prior to September 30,2008, borrowings under the Credit Agreement bore interest either: (i) at adomestic bank rate plus an applicable margin of 0.25% to 1.25% per annum basedon utilization or (ii) on a sliding scale from the one, two, three, or sixmonth LIBOR plus an applicable margin of 1.25% to 2.25% per annum based onutilization. Please see Note 10 — Subsequent Events. The Credit Agreementmatures February 12, 2011. The Credit Agreement with RBS is collateralizedby substantially all of the Company’s producing assets.

 

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

 

·                Incur liens;

 

·                Incur debt;

 

·                Make investmentsin other persons;

 

·                Declare dividendsor redeem or repurchase stock;

 

·                Engage in mergers,acquisitions, consolidations and asset sales or amend the Company’sorganizational documents;

 

·                Enter into certainhedging arrangements;

 

·                Amend materialcontracts; and

 

·                Enter into relatedparty transactions.

 

With regard to hedgingarrangements, the Credit Agreement provides that acceptable commodity hedgingarrangements cannot be greater than 80 to 85%, depending on the measurementdate, of the Company’s monthly production from its hydrocarbon properties thatare used in the borrowing base determination and that the fixed or floor priceof the Company’s hedging arrangements must be equal to or greater than the gasprice used by the lenders in determining the borrowing base.

 

The Credit Agreement, asamended, also requires that the Company satisfy certain affirmative covenants,meet certain financial tests, maintain certain financial ratios and makecertain customary indemnifications to lenders and the administrative agent. Thefinancial covenants include requirements to maintain: (i) a ratio ofearnings before income taxes, depreciation, depletion, amortization andaccretions (“EBITDA”) to cash interest expense of not less than 3.00 to 1.00, (ii) aratio of current assets to current liabilities of not less than 1.00 to 1.00, (iii) atotal debt to annualized EBITDA ratio of not more than 3.0 to 1.0, (iv) aquarterly total senior debt to annualized EBITDA ratio equal to or less than3.00 to 1.0, and (v) a total proved PV-10 value of reserves to total debtratio of at least 1.50 to 1.00.

 

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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 not in compliance with the current ratio covenantunder the Credit Agreement as of September 30, 2008. However, RBS granted a waiver of the requirement that the Company complywith the current ratio covenant as of September 30, 2008.  Please see Note 10 — Subsequent Events.

 

Effective August 4,2008, the Company and RBS entered into the Second Amendment to the CreditAgreement (the “Second Amendment”).  TheSecond Amendment provided, among other things, for (i) the increase in thetotal quarterly senior debt to annualized EBITDA ratio from 2.0 to 1.0, to 3.0to 1.0, (ii) an increase in interest at each utilization level for LIBORborrowings, (iii) the amendment of the utilization calculation to bedetermined as the greater of (x) the percentage of credit exposure overthe borrowing base or (y) the percentage of credit exposure over threetimes EBITDA minus permitted subordinated debt, and (iv) the payment of anamendment fee.

 

*Office Building Loan*

 

On November 15,2005, the Company entered into a mortgage loan secured by its office buildingin Sheridan, Wyoming in the aggregate principal amount of $829,000. Thepromissory note provides for monthly payments of principal and interest in theinitial amount of $6,400, and unpaid principal 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 a principaland interest payment of $615,400 will become due. As of September 30,2008, the Company had $769,000 outstanding in principal and interest on thismortgage.

 

***Note 8 — FairValue Measurements***

 

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

 

·**               **Level 1 —Quoted prices in active markets 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 assets and liabilities required to be measured at fairvalue on a recurring basis and where they are classified within the hierarchyas of September 30, 2008 (in thousands):

 
| ** **                          | ** ** | **Level 1** | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** ** |
|-------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|-----------|------------|
| Assets                              |       |             |       |             |       |             |       |      |       |
| Oil and gas  derivative instruments |       | $                | —     |             | $          | 4,042            |       | $         | —     |   | $ | 4,042 |   |
| Total                               |       | $                | —     |             | $          | 4,042            |       | $         | —     |   | $ | 4,042 |   |

 

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

 

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

 

***Note 9 —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 and hazardouswaste management activities. As a result, it is extremely difficult toreasonably quantify future environmental and regulatory related expenditures.

 

The following are legalactions in which Pinnacle is involved. No assurance can be given that these legalactions will be resolved in Pinnacle’s favor. However, management believes,based on its experiences to date, that these matters will not have a materialadverse impact on Pinnacle’s business, financial position or results ofoperations.

 

Pinnacle, together withthe 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 plan ofdevelopment. The plaintiff is a surface owner with properties located in BigHorn County and Rosebud County, Montana where Pinnacle serves as operator andowns a working interest in the minerals under lease. The plaintiff seeks topermanently enjoin the State of Montana and its administrative bodies fromissuing licenses or permits, or authorizing the removal of ground water fromunder the plaintiff’s ranch. In addition, the plaintiff further seeks topreliminarily and permanently enjoin Pinnacle on the basis that Pinnacle’soperations lack adequate safeguards required under the Montana stateconstitution. On August 25, 2005, the District Court issued an orderdenying without prejudice the application for temporary restraining order andpreliminary injunction requested by the plaintiff. The case was appealed by theplaintiff to the Montana Supreme Court. On November 16, 2005, the MontanaSupreme Court issued an order that denied enjoining the Coal Creek POD, andsubsequently, the Montana Supreme Court remanded the case back to the District Courtfor a decision on the merits.

 

On July 14, 2008,the District Court issued a summary judgment order in this case, and the orderwas subsequently entered as a judgment on August 15, 2008.  Pinnacle believes the order and judgmentallow for the continued development of coal bed methane in the State ofMontana.  In summary, the District Courtheld that:  “Both the coal bed methaneand the water resulting from CBM production represent value to the people,industry, and wildlife in Montana.  Theproduction and management of each must be balanced against the other so thatMontana benefits to the greatest extent possible from both vital resources.”  In Pinnacle’s view, the District Courtessentially charged the Montana Board of Oil and Gas Conservation and theMontana Department of Natural Resource Conservation to cooperate in carryingout their responsibilities to manage the produced coal bed methane groundwaterin beneficial ways for the people of the state. The District Court’s ruling does not require Pinnacle (or any coal bedmethane operator) to improve the quality of the produced coal bed methanegroundwater to make it suitable for beneficial use.

 

Approximately 59% and 61%of Pinnacle’s gross acreage in Montana and Wyoming, respectively, is on U.S.federal land. Federal leases in Montana and Wyoming must be developed pursuantto the U.S. Bureau of Land Management’s Resource Management Plans. Federalleases are also subject to the National Environmental Policy Act and FederalLand Policy Management Act. The National Environmental Policy Act processimposes obligations on the federal government that may result in legalchallenges and potentially lengthy delays in obtaining project permits orapprovals. The Montana and Wyoming Bureaus of Land Management have been subjectto several lawsuits from various environmental and tribal groups challengingResource Management Plan amendments and supporting Environmental ImpactStatements addressing coal bed methane development in Montana and Wyoming. In2003, the Montana Bureau of Land Management and Wyoming Bureau of LandManagement each amended their Resource Management Plans based in part onEnvironmental Impact Statements prepared pursuant to the National EnvironmentalPolicy Act. Shortly after the issuance of the Environmental Impact Statementsand amended Resource Management Plans, various plaintiffs brought legal actionschallenging the Montana and 

 

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Wyoming EnvironmentalImpact Statements and Resource Management Plans. There have been at least fivefederal district court challenges to the Montana Environmental ImpactStatements. There are also at least three federal district court challenges tothe Wyoming Environmental Impact Statements currently pending before the UnitedStates District Court for the District of Wyoming. Pinnacle has intervened inseveral of these cases to protect its interests in these proceedings. Theoutcome and timing of these cases could affect the ability of the Montana andWyoming Bureaus of Land Management to approve plans of development and issuedrilling permits and thus could affect Pinnacle’s ability to further developits federal leases in Montana and Wyoming. In particular, the Ninth Circuitpreviously granted a motion for a blanket injunction prohibiting the MontanaBureau of Land Management from approving any coal bed methane productionprojects on federal lands in the Powder River Basin of Montana pendingdisposition of two of three appeals pending before that court. While a panel ofthe Ninth Circuit issued a favorable decision affirming an earlier order by theMontana District Court that allows phased coal bed methane development tocontinue pending completion of a Supplemental Environmental Impact Statement,Pinnacle cannot predict how or when the courts will ultimately resolve thesematters, including the dissolution of the injunction, nor can it foresee futurechallenges which may arise. Pinnacle believes it will ultimately be successfulin developing its leases as planned, but cannot give any assurances as to whenor how these suits will be resolved or when Pinnacle will be able to developits federal leases in the Powder River Basin of Montana.

 

The Montana Bureau ofLand Management has prepared the Final Supplement to the Montana Statewide Oiland Gas Environmental Impact Statement and Proposed Amendment of the PowderRiver and Billings Resource Management Plans (FSEIS). This proposed planamendment is a result of U.S. District Court orders issued on February 25,2005 and April 5, 2005, requiring the Bureau of Land Management to preparea Supplemental Environmental Impact Statement to evaluate a phased developmentalternative for coal bed methane gas production. The FSEIS was released to thepublic the week of November 3, 2008.

 

***Note 10 —Subsequent Events***

 

Effective October 1, 2008, RBS established a newborrowing base under the Credit Agreement of $14.5 million.  The new borrowing base will be automaticallyreduced by approximately $666,667 per month for six months, beginning on November 1,2008.  As of November 13, 2008, theCompany had $11.5 million of debt outstanding under the Credit Agreement.

 

On November 13, 2008 but effective September 30,2008, the Company and RBS, as the administrative agent and lender, entered intothe Third Amendment to the Credit Agreement (the “Third Amendment”).  The Third Amendment, among other things,waived the requirement that the Company comply with the current ratio covenantas of September 30, 2008.  However,it requires that immediately prior to any additional borrowings under theCredit Agreement, the Company’s ratio of current assets to current liabilitiesbe not less than 1.00 to 1.00.  As aresult of this new condition to additional borrowings, the Company is currentlyunable to borrow additional amounts under the Credit Agreement.  In addition, the Third Amendment increasedthe interest rate payable under the Credit Agreement to either (i) thegreater of the one month LIBOR plus 1.00% or a domestic bank rate, plus ineither case an applicable margin of 0.75% to 1.75% based on utilization, or (ii) asliding scale from the one, two, three or six month LIBOR, plus an applicablemargin of  2.00% to 3.00% based onutilization, and provided for the payment of an amendment fee.

 

***

 

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**ITEM 2. MANAGEMENT’SDISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS****OF OPERATIONS**

 

*Thediscussion and analysis that follows should be read together with theaccompanying financial statements and notes related thereto that are includedelsewhere in this quarterly report on Form 10-Q. It includesforward-looking statements that may reflect our estimates, beliefs, plans andexpected performance. The forward-looking statements are based upon events,risks and uncertainties that may be outside our control. Our actual resultscould differ significantly from those discussed in these forward-lookingstatements. Factors that could cause or contribute to these differencesinclude, but are not limited to, market prices for natural gas and oil,regulatory changes, estimates of proved reserves, economic conditions,competitive conditions, development success rates, capital expenditures andother uncertainties, as well as those factors discussed below and elsewhere inthis quarterly report on Form 10-Q and in our annual report on Form 10-Kfor the year ended December 31, 2007, including in “Risk Factors” and “CautionaryStatement Concerning Forward-Looking Statements,” all of which are difficult topredict. As a result of these assumptions, risks and uncertainties, theforward-looking matters discussed may not occur.*

 

**Overview**

 

We are an independentenergy company engaged in the acquisition, exploration and development ofdomestic onshore natural gas reserves. We primarily focus our efforts on thedevelopment of coal bed methane (or CBM) properties located in the Powder RiverBasin in northeastern Wyoming and southern Montana. In addition, in April 2006,we acquired properties located in the Green River Basin in southern Wyoming. Asof September 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 had a total capitalexpenditure budget of $30.1 million for 2008 and expected to drill 146 gross (110net) wells during that period. However, due to low CIG index prices and limitedcapital resources, we have reduced our capital expenditure budget from $30.1million to $26.6 million. We have curtailed substantially all new drilling forthe remainder of 2008 and have shut in a number of wells that are not economicat current natural gas price levels, and if natural gas prices remain low, wemay continue to operate with a reduced drilling plan through the first half of2009.  We incurred capital expendituresof approximately $26.1 million during the nine months ended September 30,2008, primarily related to our drilling, completion and infrastructure costs onour Cabin Creek acreage, and drilled 115 gross (81 net) wells and completed 102gross (70 net) wells during the nine months ended September 30, 2008. Weoperated 97% of those wells.  During thefourth quarter of 2008, we expect to drill only 1 gross (0.9 net) well.

 

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

 

In April 2006, wecompleted 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.  Shares of our common stock are traded on theNASDAQ Global Market under the symbol “PINN.”

 

**CriticalAccounting Policies**

 

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

 

·                  Reserve evaluation anddetermination;

 

·                  Estimates of the timingand cost of our future drilling activity;

 

·                  Estimates of the fairvaluation of hedges in place;

 

·                  Estimates of timing andcost of asset retirement obligations;

 

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·                  Estimates of the expenseand timing of exercise of stock options;

 

·                  Accruals of operatingcosts, capital expenditures and revenue; and

 

·                  Estimates for litigation.

 

***Oil and Gas Properties***

 

We use the full costmethod of accounting for oil and gas producing activities. Under this method,all costs associated with property acquisition, exploration and development,including costs of unsuccessful exploration, costs of surrendered and abandonedleaseholds, delay lease rentals and the fair value of estimated future costs ofsite restoration, dismantlement and abandonment activities, are capitalizedwithin a cost center. Our oil and gas properties are all located within theUnited States, which constitutes a single cost center. We have not capitalizedany overhead costs. No gain or loss is recognized upon the sale or abandonmentof undeveloped 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, depletionand amortization of oil and gas properties is computed on theunit-of-production method based on proved reserves. Amortizable costs includeestimates of future development costs of proved undeveloped reserves and assetretirement obligations. We invest in unevaluated oil and gas properties for thepurpose of exploration for proved reserves. The costs of such assets, includingexploration costs on properties where a determination of whether proved oil andgas reserves will be established is still under evaluation, and any capitalizedinterest, 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 $1.6 million during each of the three and nine months ended September 30,2008. Abandonment of unproved properties is accounted for as an adjustment tocapitalized costs related to proved oil and gas properties, with no lossesrecognized.

 

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. As of September 30, 2008 and December 31, 2007, theestimated salvage value was $7.3 million and $6.4 million, respectively.

 

Under full costmethod of accounting rules, capitalized costs less accumulated depletion andrelated deferred income taxes may not exceed a “ceiling” value which is the sumof (1) the present value discounted at 10% of estimated future net revenueusing current prices and costs, including the effects of derivative instrumentsdesignated as cash flow hedges but excluding the future cash outflowsassociated with settling asset retirement obligations that have been accrued onthe balance sheet, less any related income tax effects, plus (2) the costof properties not being amortized, if any, plus (3) the lower of costs orestimated fair value of unproved properties, less (4) the income taxeffects related to differences in the book to tax basis of oil and gasproperties. This is referred to as the “full cost ceiling limitation.” Ifcapitalized costs exceed the limit, the excess must be charged to expense. Theexpense may not be reversed in future periods. At the end of each quarter, we calculatethe full cost ceiling limitation.  At September 30,2008, the capitalized cost of our oil and gas properties exceeded the full costceiling limitation by approximately $21.4 million based upon a natural gasprice of $3.62 per Mcf (based on the Colorado Interstate Gas Rocky MountainIndex) in effect at that date. Based on the subsequent price increase toapproximately $4.95 per Mcf at the measurement date of November 11, 2008,the full cost ceiling limitation exceeded the capitalized cost of our oil andgas properties by approximately $2.6 million. Therefore, the Company did notrecord an impairment for the three and nine months ended September 30,2008.  An impairment of approximately$18.2 million was recorded for the nine months ended September 30, 2007.The impairment 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 recoverablereserve quantities could result in the recognition of additional impairments ofour oil and gas properties in future periods.

 

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***Gas Sales***

 

We use the sales methodfor recording natural gas sales. Sales of gas applicable to our interest inproducing natural gas and oil leases are recorded as revenues when the gas ismetered and title transferred pursuant to the gas sales contracts covering ourinterest in gas reserves. During such times as our sales of gas exceed our prorata ownership in a well, such sales are recorded as revenues unless totalsales from the well have exceeded our share of estimated total gas reservesunderlying the property at which time such excess is recorded as a gasimbalance liability. At September 30, 2008 and December 31, 2007,there was no such liability recorded. Although there was no such liabilityrecorded for prior periods, gas reserves are an estimate and are updated on anannual and interim basis. Gas pricing, expenses and production may impactfuture gas reserves remaining which, in turn, could impact the recording ofliabilities in the future. Gas sales accruals at September 30, 2008 and December 31,2007 were based on the actual volume statements from our purchasers anddistribution process. If accruals were to change by 10% at September 30,2008 and at December 31, 2007, the impact would have been $100,000 and$306,000, respectively.

 

***Asset Retirement Obligations***

 

We follow the provisionsof Statement of Financial Accounting Standards (SFAS) No. 143, “Accountingfor the Asset Retirement Obligations.” SFAS No. 143 generally applies tolegal obligations associated with the retirement of long-lived assets thatresult from the acquisition, construction, development and/or the normaloperation of a long-lived asset. SFAS No. 143 requires us to recognize anestimated liability for costs associated with the abandonment of our oil andgas properties.

 

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

 

The estimated liabilityis based on historical gas industry experience in abandoning wells, includingestimated economic lives, external estimates as to the cost to abandon thewells in the future and federal and state regulatory requirements. Ourliability is discounted using our best estimate of our credit-adjustedrisk-free rate. Revisions to the liability could occur due to changes inestimated abandonment costs, changes in well economic lives or if federal orstate regulators enact new requirements regarding the abandonment of wells. Forexample, a 10% change in our estimated retirement costs would have a $331,000effect on our asset retirement obligation liability at September 30, 2008.

 

The following is asummary of our asset retirement obligation activity for the three and ninemonths ended September 30, 2008 and 2007 (in thousands):

 
| ** **                                      | ** ** | **Three  Months Ended  September 30,** | ** ** | **Nine  Months Ended  September 30,** | ** ** | **Three  Months Ended  September 30,** | ** ** | **Nine  Months Ended  September 30,** | ** ** |
|-------------------------------------------------|------------|--------------------------------------------------|------------|-------------------------------------------------|------------|--------------------------------------------------|------------|-------------------------------------------------|------------|
| ** **                                      | ** ** | **2008**                                         | ** ** | **2007**                                        | ** ** |
| ** **                                      | ** ** | **(unaudited)**                                  | ** ** | **(unaudited)**                                 | ** ** |
| Beginning  balance asset retirement obligations |       | $                                                | 3,154      |                                            | $          | 2,767                                            |       | $                                               | 2,533      |   | $ | 2,321 |   |
| Additional  obligations added during the period |       | 142                                              |       | 410                                             |       | 69                                               |       | 182                                             |       |
| Obligations  settled during the period          |       | (48                                              | )          | (48                                             | )          | —                                           |       | —                                          |       |
| Accretion  expense                              |       | 66                                               |       | 185                                             |       | 53                                               |       | 152                                             |       |
| Ending balance of  asset retirement obligations |       | $                                                | 3,314      |                                            | $          | 3,314                                            |       | $                                               | 2,655      |   | $ | 2,655 |   |

 

***Inventory***

 

We acquired inventory ofoil and gas equipment, primarily tubulars, in 2007 and 2008 to take advantageof quantity pricing and to secure a readily available supply. Inventory isvalued at the lower of average cost or market. Inventory is used in thedevelopment of gas properties and to the extent it is estimated that it will bebilled to other working interest owners during the next year, it is included incurrent assets. Otherwise, it is recorded in non-current assets. The price ofsteel is a primary factor in valuing our inventory. Under the valuation methodof lower of average cost or market, a 10% reduction in the price of steel wouldcause a $67,000 reduction in our inventory valuation as of September 30,2008. The market price of steel is evaluated each quarter using prices quotedby authorized vendors in the area.

 

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***Property and Equipment***

 

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

 

***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 three and nine months ended September 30, 2008 would haveincreased or decreased our expenses billed to working interest owners byapproximately $54,000 and $145,000, respectively. As we operate and drilladditional 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 nine months ended September 30,2008 also include $2.1 million of merger related costs attributable to thefailed merger with Quest Resource Corporation.

 

***Income Taxes***

 

We use the asset andliability method of accounting for income taxes, in accordance with SFAS No. 109,“Accounting for Income Taxes.” Deferred tax assets and liabilities arerecognized for the expected future tax consequences of temporary differencesbetween the financial statement and tax bases of assets and liabilities. Ifappropriate, deferred tax assets are reduced by a valuation allowance whichreflects expectations of the extent to which such assets will be realized. Asof September 30, 2008 and December 31, 2007, we had recorded a fullvaluation allowance for our net deferred tax asset.

 

On January 1, 2007,we adopted the Financial Accounting Standards Board Interpretation No. 48,“Accounting for Uncertainty in Income Taxes – an interpretation of FASBStatement No. 109” (FIN 48). FIN 48 prescribes a measurement process forrecording in the financial statements uncertain tax positions taken or expectedto be taken in a tax return. Additionally, FIN 48 provides guidance regarding uncertain tax positionsrelating to derecognition, classification, interest and penalties, accountingin interim periods, disclosure and transition. At September 30, 2008, we had no material uncertain tax positionsor penalties or interest recorded.

 

***Derivatives***

 

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

 

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

 

***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) also requiresthat the benefits of tax deductions in excess of compensation cost recognizedfor stock awards and options (“excess tax benefits”) be presented as financingcash inflows in the Statement of Cash Flows.

 

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***Accounts Receivable***

 

Our revenue producingactivities are conducted primarily in Wyoming. We grant credit to qualifiedcustomers, which potentially subjects us to credit risk resulting from, amongother factors, adverse changes in the industry in which we operate and thefinancial condition of our customers. We continuously monitor collections andpayments from our customers and, if necessary, record an allowance for doubtfulaccounts based upon historical experience and any specific customer collectionissues identified. We recorded an allowance of $100,000 at each of September 30,2008 and December 31, 2007.

 

***Transportation Costs***

 

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

 

***Legal Estimates***

 

From time to time, we aresubject to legal proceedings and claims that arise in the ordinary course ofbusiness. We account for these costs under SFAS No. 5, “Accounting for Contingencies,”**which states that a loss contingency be recorded if it isprobable that a liability has been incurred and it is reasonably estimatable.At each of September 30, 2008 and December 31, 2007, we recorded noliability for legal proceedings.

 

***Per Share Information***

 

Basic earnings (loss) pershare is computed by dividing net income (loss) from continuing operationsattributable to common stock by the weighted average number of shares of commonstock outstanding during each period. Diluted earnings per share is computed byadjusting the average number of shares of common stock outstanding for thedilutive effect, if any, of common stock equivalents such as stock options andwarrants. For the three months ended September 30, 2008, diluted netincome per share was $0.30, while basic net income per share was $0.31.  Certain options to purchase shares of our commonstock were excluded from the dilution calculations because the shares wereanti-dilutive.  During the nine monthsended September 30, 2008, 717,500 options were excluded because they wereanti-dilutive.  During the nine monthsended September 30, 2007, 907,000 options were excluded because they wereanti-dilutive.

 

***Recent Accounting Pronouncements***

 

For information concerning recent accountingpronouncements, please see Note 2 of the notes to the unaudited financialstatements appearing elsewhere in this quarterly report.

 

**Trends Affecting Our Business**

 

We have experiencedincreasing costs since our inception in 2003 due to increased demand foroilfield products and services. The cyclical nature of the natural gas industrycauses fluctuations in demand for goods and services from oilfield companies,suppliers and others associated with the industry, which in turn affects theprices for those goods and services. Typically, as prices for natural gasincrease, so do all the costs associated with natural gas production.  Recently, we have seen increases in the costof tubulars, drilling rigs and cement in particular. We expect that increaseddemand for the goods and services we use in our business will continue to put pressureon prices in the near to medium term.

 

Historically, natural gasprices have been extremely volatile, and we expect that volatility to continue.For example, during each of the three and nine months ended September 30,2008, the NYMEX natural gas index price ranged from a high of $13.58 per MMBtuto a low of $7.22 per MMBtu, while the CIG natural gas index price ranged froma high of $10.26 per MMBtu to a low of $1.00 per MMBtu.  During the year ended December 31, 2007,the NYMEX natural gas index price ranged from a high of $8.64 per MMBtu toa low of $5.38 per MMBtu, while the CIG natural gas index price rangedfrom a high of $7.11 per MMBtu to a low of $0.06 per MMBtu. Changes in naturalgas pricing have impacted our revenue streams, production taxes, prices used inreserve calculations, borrowing base calculations and the valuation ofpotential property acquisitions. During the three and nine months ended September 30,2008, estimated future gas prices had an impact on both our revenues and thecosts attributable to our future operations. We expect that changing naturalgas prices will continue to impact our operations and financial results in thefuture.

 

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Transportation of naturalgas and access to throughput capacity have a direct impact on natural gasprices in the Rocky Mountain region, where our operations areconcentrated.  As drilling activityincreases throughout the Rocky Mountain region, additional production may comeon line, which could cause bottlenecks or capacity constraints. Generallyspeaking, a surplus of natural gas production relative to availabletransportation capacity has a negative impact on prices. Conversely, as capacityincreases, and bottlenecks are eliminated, prices generally increase. Althoughthere is currently adequate transportation capacity out of the Powder RiverBasin, a surplus of natural gas arriving at key marketing hubs from the PowderRiver Basin and elsewhere relative to available takeaway capacity from thesehubs has caused Rocky Mountain gas to generally trade at a discount to theNYMEX natural gas index price.  TheRockies Express Pipeline, which was completed to Audrain County, Missouri inearly 2008, has increased takeaway capacity by approximately 2 Bcf per day fromthese hubs.  We expect that thecompletion of additional proposed pipelines will help reduce the differentialbetween gas produced in the Rocky Mountain region and the NYMEX natural gas indexprice.

 

**Resultsof Operations**

 

Net income attributableto stockholders for the three months ended September 30, 2008 was$8.9 million, or $0.30 per diluted share, on total revenues of$5.7 million. Net income attributable to stockholders for the three monthsended September 30, 2008 included a $10.0 million unrealized gainassociated with the change in the fair valuation of our natural gas hedges inplace in accordance with the provisions of SFAS No. 133. Absent such achange in the valuation, we would have shown a net loss attributable tostockholders of $1.1 million. This compares to a net loss attributable tostockholders of $1.2 million for the three months ended September 30, 2007on total revenues of $2.7 million. Adjusted for an unrealized loss in thefair valuation of our natural gas hedges in place of $0.02 million, our resultsfor the three months ended September 30, 2007 would have been a net lossattributable to stockholders of $1.2 million.

 

Net loss attributable tostockholders for the nine months ended September 30, 2008 was $0.6million, or $0.02 per diluted share, on total revenues of $18.9 million. Netloss attributable to stockholders for the nine months ended September 30,2008 included a $3.5 million unrealized gain associated with the change in thefair valuation of our natural gas hedges in place in accordance with theprovisions of SFAS No. 133. Absent such a change in the valuation, wewould have shown a net loss attributable to stockholders of $4.1 million. Thiscompares to a reported net loss attributable to stockholders of $21.4 millionfor the nine months ended September 30, 2007 on total revenues of $9.8million. Adjusted for an unrealized loss in the fair valuation of our naturalgas hedges in place of $1.2 million, our results for the nine months ended September 30,2007 would have been a net loss attributable to stockholders of $20.2 million.

 

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

 

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

 

*Gassales volume*

 

Gas sales volumeincreased 16%, from 893 MMcf in the three months ended September 30, 2007to 1,036 MMcf in the three months ended September 30, 2008. Daily salesvolume was 11.3 MMcf for the three months ended September 30, 2008 ascompared to 9.7 MMcf for the three months ended September 30, 2007, a 1.6MMcf per day increase. The increase was primarily due to production comingonline in our Cabin Creek, Kirby and Deer Creek project areas.  The volumes for the three months ended September 30,2008 were reduced due to a water treatment interruption caused by a failure toobtain chemicals as a result of Hurricane Ike. In addition, during the same period the Rockies Express Pipeline wasshut-in for hydrostatic testing.

 

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*Gassales revenue*

 

Revenue from gas salesincreased approximately $3.0 million during the three months ended September 30,2008, to approximately $5.7 million, a 109% increase compared to the three months ended September 30, 2007.This increase was primarily due to an increase in gas sales volume coupled withan increase in the average realized price per Mcf. The average realized priceper Mcf increased approximately 80%, from $3.05 per Mcf before transportationin the three months ended September 30, 2007 to $5.49 per Mcf in the threemonths ended September 30, 2008.

 

*Derivatives*

 

For the three monthsended September 30, 2008, we had an unrealized gain on our hedges of $10.0million compared to an unrealized loss of $0.02 million for the three monthsended September 30, 2007. The unrealized gain for the three months endedSeptember 30, 2008 was non-cash income, while the unrealized loss for the threemonths ended September 30, 2007 was a non-cash expense, in each case basedprimarily on the Black-Scholes model for valuing future cash flows utilizingprice volatility with a normal discount rate. Hedges settled during the threemonths ended September 30, 2008 resulted in a realized gain of $0.7million compared to a realized hedge gain of $1.6 million during the threemonths ended September 30, 2007. The hedge gain for the three months endedSeptember 30, 2008 was primarily due to the fact that gas prices werelower than the weighted average floor price of our hedges in place.

 

*Leaseoperating expenses*

 

Lease operating expensesincreased $0.5 million in the three months ended September 30, 2008 to$1.8 million, a 36% increase compared to the three months ended September 30,2007. This increase resulted from an increase in the number of wells in theproductive cycle during the three months ended September 30, 2008, alongwith higher generator rental costs and additional expenses related to dieselfuel to run the generators and ongoing pump maintenance. On an Mcf basis, leaseoperating expenses increased 17% from $1.48 per Mcf in the three months ended September 30,2007 to $1.73 per Mcf in the three months ended September 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 $0.4 million in the three months ended September 30, 2008to $0.6 million, a 132% increase from the three months ended September 30,2007. Production taxes generally correlate to gross sales revenue becauseproduction taxes are based on a percentage of sales value. In Wyoming the percentageaverages 11% to 13%, depending on rates in effect for the respective year,while in Montana the percentage averages 9%. The increase in production taxesfor the three months ended September 30, 2008 was primarily due to anincrease in the average realized price per Mcf. On an Mcf basis, production taxes were $0.62 per Mcf for the threemonths ended September 30, 2008 and $0.31 per Mcf for the three monthsended September 30, 2007, a 100% increase, which correlates to theincrease in the price per Mcf received in the three months ended September 30,2008 from the three months ended September 30, 2007.

 

*Marketingand transportation*

 

Marketing andtransportation expenses increased $0.3 million in the three months ended September 30,2008 to $1.2 million, a 28% increase from the three months ended September 30,2007. The increase related primarily to the increased sales volume in the threemonths ended September 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 andtransportation expenses increased 10% to $1.12 per Mcf in the three monthsended September 30, 2008 from $1.02 per Mcf in the three months ended September 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 increased 31% inthe three months ended September 30, 2008, from $0.4 million in thethree months ended September 30, 2007 to $0.5 million, due toincreased productive wells which we operate and for which we charge an overheadfee. General and administrative expenses, net decreased $0.2 million inthe three months ended September 30, 2008 to $1.3 million.   On an Mcf basis, general and administrativeexpenses, net decreased 23% from $1.67 per Mcf in the three months ended September 30,2007 to $1.29 per Mcf in the three months ended September 30, 2008.

 

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*Depreciation,depletion, amortization and accretion*

 

Depreciation, depletion,amortization and accretion expense increased $1.0 million for the three monthsended September 30, 2008 to $2.7 million, a 56% increase compared to thethree months ended September 30, 2007. This increase was due to a 16%increase in gas sales volumes for the three months ended September 30,2008 along with additional capitalized costs in the full cost pool. On an Mcfbasis, the depreciation, depletion, amortization and accretion rate increased35% to $2.57 per Mcf in the three months ended September 30, 2008 from$1.91 per Mcf in the three months ended September 30, 2007.

 

*Impairment*

 

At September 30,2008, the capitalized cost of our oil and gas properties exceeded the full costceiling limitation by approximately $21.4 million based upon a natural gasprice of approximately $3.62 per Mcf (based on the CIG Rocky Mountain Index) ineffect at that date. Based on the subsequent price increase to approximately$4.95 per Mcf at the measurement date of November 11, 2008, the full costceiling limitation of our oil and gas properties exceeded the capitalized costby approximately $2.6 million. Therefore, the Company did not record an impairment for the three andnine months ended September 30, 2008. For further information regarding this impairment, please see Note2  in the notes to the unauditedfinancial statements appearing elsewhere in this quarterly report. A decline innatural 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.

 

***Nine Months Ended September 30,2008 Compared to Nine Months Ended September 30, 2007***

 

*Gassales volume*

 

Gas sales volumeincreased 15%, from 2,527 MMcf in the nine months ended September 30, 2007to 2,916 MMcf in the nine months ended September 30, 2008. Daily salesvolume was 10.6 MMcf for the nine months ended September 30, 2008 ascompared to 9.2 MMcf for the nine months ended September 30, 2007, a 1.4MMcf per day increase. The increase was primarily due to production comingonline in our Cabin Creek, Kirby and Deer Creek project areas.

 

*Gassales revenue*

 

Revenue from gas salesincreased approximately $9.1 million during the nine months ended September 30,2008, to approximately $18.9 million, a 93% increase compared to the ninemonths ended September 30, 2007. This increase was primarily due to anincrease in gas sales volume coupled with an increase in the average realizedprice per Mcf. The average realized price per Mcf increased approximately 67%,from $3.88 per Mcf before transportation in the nine months ended September 30,2007 to $6.49 per Mcf in the nine months ended September 30, 2008.

 

*Derivatives*

 

For the nine months ended September 30, 2008, wehad an unrealized gain on our hedges of $3.5 million compared to an unrealizedloss of $1.2 million for the nine months ended September 30, 2007. Theunrealized gain for the three months ended September 30, 2008 was non-cashincome, while the unrealized loss for the three months ended September 30, 2007was a non-cash expense, in each case based primarily on the Black-Scholes modelfor valuing future cash flows utilizing price volatility with a normal discountrate. Hedges settled during the nine months ended September 30, 2008resulted in a realized loss of $0.05 million compared to a realized hedge gainof $3.3 million during the nine months ended September 30, 2007. Therealized hedge loss for the nine months ended September 30, 2008 wasprimarily due to the fact that gas prices were slightly higher than theweighted average floor price of our hedges in place.

 

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* *

*Leaseoperating expenses*

 

Lease operating expensesincreased $1.7 million in the nine months ended September 30, 2008 to $5.2million, a 50% increase compared to the nine months ended September 30,2007. This increase resulted from an increase in the number of wells in theproductive cycle during the nine months ended September 30, 2008, alongwith a workover program which replaced or repaired pumps in over 170 wellswhich were underperforming and increased generator rental and diesel fuelcosts. On an Mcf basis, lease operating expenses increased 30% from $1.37 perMcf in the nine months ended September 30, 2007 to $1.78 per Mcf in thenine months ended September 30, 2008. The increase per Mcf was primarilydue to a number of wells being in the early stages of their productive lifecycle as production did not increase proportionately to the number of wellscoming online. Additionally, increases in generator rentals and associated fuelwhile waiting on permanent power contributed, along with increased watermanagement costs associated with water treatment.

 

*Productiontaxes*

 

Production taxesincreased $1.1 million in the nine months ended September 30, 2008 to $2.2million, a 109% increase from the nine months ended September 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,while in Montana the percentage averages 9%. The increase in production taxesfor the nine months ended September 30, 2008 was primarily due toincreased revenues associated with increased volume and realized pricing. On anMcf basis, production taxes were $0.74 per Mcf for the nine months ended September 30,2008 and $0.41 per Mcf for the nine months ended September 30, 2007, an81% increase, which correlates to the increase in the price per Mcf received inthe nine months ended September 30, 2008 from the nine months ended September 30,2007.

 

*Marketingand transportation*

 

Marketing andtransportation expenses increased approximately $0.9 million in the nine monthsended September 30, 2008 to approximately $3.5 million, a 33% increasefrom the nine months ended September 30, 2007. The increase relatedprimarily to increased sales volume in the nine months ended September 30,2008, together with a slight increase in transportation fees and compressiondue to inflationary adjustments in the contracts along with fees paid forcompression design capacity which was not used. On an Mcf basis, marketing andtransportation expenses increased 15% to $1.18 per Mcf in the nine months endedSeptember 30, 2008 from $1.03 per Mcf in the nine months ended September 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 $1.4 millionin the nine months ended September 30, 2008 compared to $1.2 million forthe nine months ended September 30, 2007, a 24% increase. General andadministrative expenses, net increased $2.1 million in the nine months ended September 30,2008 to $5.9 million from $3.8 million in the nine months ended September 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 34%, from$1.51 per Mcf in the nine months ended September 30, 2007 to $2.03 per Mcfin the nine months ended September 30, 2008.

 

*Depreciation,depletion, amortization and accretion*

 

Depreciation, depletion,amortization and accretion expense increased $1.9 million for the nine monthsended September 30, 2008 to $6.7 million, a 39% increase compared to thenine months ended September 30, 2007. This increase was due to a 15%increase in gas sales volumes for the nine months ended September 30, 2008along with additional capitalized costs in the full cost pool. On an Mcf basis,the depreciation, depletion, amortization and accretion rate increased 21% to$2.29 per Mcf in the nine months ended September 30, 2008 from $1.90 perMcf in the nine months ended September 30, 2007.

 

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*Impairment*

 

The Company did notrecord an impairment for the nine months ended September 30, 2008.

 

**Liquidity and Capital Resources**

 

Our primary source ofliquidity since our formation has been the private sale of our equity. Duringthe period from our formation in June 2003 through September 2005,DLJ Merchant Banking contributed $44.1 million cash in exchange for sharesof our 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 credit facility which permits borrowings up to theborrowing base as designated by the administrative agent. As of September 30,2008 and November 13, 2008, we had $7.5 million and $11.5 million,respectively, of debt outstanding under the facility.  As described below, we are currently unableto borrow additional amounts under the credit facility.

 

The borrowing base isdetermined on a semi-annual basis and at such other additional times, up totwice yearly, as may be requested by either the borrower or the administrativeagent and is determined by the administrative agent in accordance withcustomary practices and standards for loans of a similar nature, although suchdetermination is at the administrative agent’s discretion as the creditagreement does not provide a specific borrowing base formula.  As of September 30, 2008, the borrowing baseunder the credit facility was $16.8 million. Effective October 1, 2008, the administrative agent established anew borrowing base under the credit facility of $14.5 million.  The new borrowing base will be automaticallyreduced by approximately $666,667 per month for six months, beginning on November 1,2008.  If natural gas prices do notimprove, we expect that our borrowing base could be further reduced in thefuture.

 

Borrowings under thiscredit facility may be used solely to acquire, explore or develop oil and gasproperties and for general corporate purposes. The credit facility matures February 12,2011.  Our obligations under the creditfacility are secured by liens on (i) no less than 90% of the net presentvalue of the oil and gas to be produced from our oil and gas properties thatare included in the borrowing base determination, calculated using a discountrate of 10% per annum and reserve estimates, prices and production rates andcosts, (ii) options to lease, seismic options, permits, and recordsrelated to such properties, and (iii) seismic data.

 

Borrowings under ourcredit facility bear interest either (i) at the greater of the one monthLondon interbank offered rate, or LIBOR, plus 1.00% or a domestic bank rate,plus in either case an applicable margin of 0.75% to 1.75% based onutilization, or (ii) on a sliding scale from the one, two, three or sixmonth LIBOR, plus an applicable margin of 2.00% to 3.00% based on utilization.The credit agreement provides for various fees, including a quarterlycommitment fee of 0.5% per annum and engineering fees to the administrativeagent in connection with a borrowing 

 

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base determination. Inaddition, the credit facility provided for an up front fee of $27,000, whichwas paid on the closing date of the credit facility, and an additionalarrangement fee of up to 1% based on utilization. Borrowings under this creditfacility may be prepaid without premium or penalty, except on Eurodollaradvances. If an event of default exists, the default rate shall be equal to 2%plus the floating rate.

 

The credit agreementcontains covenants that, among other things, restrict our ability, subject tocertain exceptions, to do the following:

 

·                  Incur liens;

 

·                  Incur debt;

 

·                  Make investments in otherpersons;

 

·                  Declare dividends orredeem or repurchase stock;

 

·                  Engage in mergers,acquisitions, consolidations and asset sales or amend our organizationaldocuments;

 

·                  Enter into certain hedgingarrangements;

 

·                  Amend material contracts;and

 

·                  Enter into related partytransactions.

 

With regard to hedgingarrangements, the credit facility provides that acceptable commodity hedgingarrangements cannot be greater than 80 to 85%, depending on the measurementdate, of our monthly production from our hydrocarbon properties that are usedin the 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 credit agreement, asamended, 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 include requirements to maintain: (i) a ratio ofEBITDA to cash interest expense of not less than 3.00 to 1.00, (ii) aratio of current assets to current liabilities of not less than 1.00 to 1.00, (iii) atotal debt to annualized EBITDA ratio of not more than 3.0 to 1.0, (iv) aquarterly total senior debt to annualized EBITDA ratio equal to or less than3.0 to 1.0, and (v) a total proved PV-10 value to total debt ratio of atleast 1.50 to 1.00.

 

The credit 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. We were not in compliance with the current ratio covenantunder our credit agreement as of September 30, 2008. However, the administrativeagent and lender granted a waiver of the requirement that we comply with thecurrent ratio covenant as of September 30, 2008.

 

Effective August 4,2008, we and the administrative agent and lender entered into the secondamendment to the credit agreement (the “second amendment”).  The second amendment provided, 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.

 

Effective September 30, 2008, we and theadministrative agent and lender entered into the third amendment to the creditagreement (the “third amendment”).  Inaddition to waiving compliance with the current ratio covenant as describedabove, the third amendment, among other things, requires that immediately priorto any additional borrowings under the credit agreement, our ratio of currentassets to current liabilities be not less than 1.00 to 1.00.  As a result of this new condition toadditional borrowings, we are currently unable to borrow additional amounts underthe credit agreement.  The thirdamendment also increased the interest rate payable under the credit agreementto either (i) the greater of the one month LIBOR plus 1.00% or a domesticbank rate, plus in either case an applicable margin of 0.75% to 1.75% based onutilization, or (ii) a sliding scale from the one, two, three or six monthLIBOR, plus an applicable margin of 2.00% to 3.00% based on utilization, and provided for the payment of anamendment 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 a principaland interest payment of $615,400 will become due. As of September 30,2008, we had $769,000 outstanding in principal and interest on this mortgage.

 

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* *

*CapitalExpenditure Budget*

 

We had a total capitalexpenditure budget of $30.1 million for 2008 and expected to drill 146 gross(110 net) wells during that period. However, due to low CIG index prices and limited capital resources, wereduced our capital expenditure budget from $30.1 million to $26.6million.  We have curtailed substantiallyall new drilling for the remainder of 2008 and have shut in a number of wellsthat are not economic at current natural gas price levels, and if natural gasprices remain low, we expect to continue to operate with a reduced drillingplan through the first half of 2009. During the nine months ended September 30,2008, we incurred capital expenditures of approximately $26.1 million, drilled115 gross (81 net) wells and completed 102 gross (70 net) wells. Our capitalexpenditures were used to drill and complete wells, to construct related gasand water infrastructure, to fund plans of development costs for future wells,to fund undeveloped leasehold acquisition costs carried over from 2007, torecomplete certain wells, and to fund infrastructure and completion costsrelated to wells drilled in 2007.  Weexpect to drill only one gross (0.9 net) well in the fourth quarter of 2008. TheCIG index price has been extremely volatile during 2007 and 2008 and at timesreached unusually low levels. For instance, the CIG monthly index price per Mcfwas $1.78, $3.41 and $2.78 for delivery in September, October and November of2008, respectively.  If prices remainlow, our cash flows from operations will decrease and the borrowing base andborrowing availability under our credit facility could be further reduced. Ifwe do not have sufficient cash flows and cannot 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. If natural gas prices do not improve, we will consider alternatives toincrease liquidity, including asset sales and issuances of equity.

 

*Cash Flowfrom Operating Activities*

 

Net cash provided byoperating activities was approximately $10.4 million for the nine months ended September 30,2008, compared to net cash used in operating activities of approximately $10.4million for the nine months ended September 30, 2007. The change wasprimarily due to an increase in our accounts payable balance and in ouraccounts receivable balance.

 

As a result of lownatural gas prices, our cash flows from operations have not been sufficient tofund our cash requirements and we have been required to draw on our creditfacility. If natural gas prices continue to trend downward, our cash flows fromoperations will decrease and the borrowing base under our credit facility couldbe reduced.

 

*Cash Flow from Investing Activities*

 

Net cash used ininvesting activities was approximately $25.8 million for the nine months ended September 30,2008, compared to net cash used in investing activities of approximately $11.8million for the nine months ended September 30, 2007. The increase wasprimarily due to an increase in capital spending on development drilling andinfrastructure.

 

*Cash Flow from Financing Activities*

 

Net cash provided byfinancing activities was approximately $7.5 million for the nine months ended September 30,2008, compared to net cash provided by financing activities of approximately$29.6 million for the nine months ended September 30, 2007. The change wasprimarily due to net proceeds from an initial public offering of $29.6 millionduring the nine months ended September 30, 2007.

 

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* *

*ContractualObligations*

 

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

 

The following tablesummarizes by period our contractual obligations as of September 30, 2008:

 
| ** **                                     | ** ** | **Total**               | ** ** | **2008** | ** ** | **2009-2010** | ** ** | **2011-2012** | ** ** | **Thereafter** | ** ** |
|------------------------------------------------|------------|-------------------------|------------|----------|------------|---------------|------------|---------------|------------|----------------|------------|
| ** **                                     | ** ** | **(In thousands)** | ** ** |
| Notes payable in  connection with the mortgage |       | $                       | 769        |     | $          | 6             |       | $             | 51         |           | $          | 58 |   | $ | 654 |   |
| Asset retirement  obligations                  |       | 3,314                   |       | 341      |       | 623           |       | 815           |       | 1,535          |       |
| Production and  property taxes                 |       | 3,469                   |       | 976      |       | 2,493         |       | —        |       | —         |       |
| Total                                          |       | $                       | 7,552      |     | $          | 1,323         |       | $             | 3,167      |           | $          | 873 |   | $ | 2,189 |   |

 

**ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURESABOUT MARKET RISK**

 

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

 

**Commodity Price Risk**

 

Our major market riskexposure is in the pricing applicable to our natural gas production. The priceswe receive for our production depend on many factors beyond our control. Weseek to reduce our exposure to unfavorable changes in natural gas prices, whichare subject to significant and often volatile fluctuation, through the use offixed-price contracts. The fixed-price contracts are comprised of energy swapsand collars. These contracts allow us to predict with greater certainty theeffective natural gas prices to be received for hedged production and benefitoperating cash flows and earnings when market prices are less than the fixedprices provided by the contracts. However, we will not benefit from marketprices 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 following tablesummarizes the estimated volumes, fixed prices, fixed price sales and fairvalue attributable to the fixed price contracts as of September 30, 2008.At September 30, 2008, we had hedged volumes through December 2009.Please see Note 5 of the notes to the unaudited financial statements appearingelsewhere in this quarterly report for further information regarding ourderivatives.

 
|                                             | ** ** | **Year Ending  December 31, 2008** | **  ** | **Year Ending  December 31, 2009** | ** ** |
|---------------------------------------------|------------|---------------------------------------------------|------------------|---------------------------------------------------|------------|
| ** **                                  | ** ** | **(Unaudited)**                                   | ** **       | **(Unaudited)**                                   | ** ** |
| **Natural  Gas Collars:**                   |       |                                              |             |                                              |       |
| Contract volumes  (MMBtu)                   |       |                                              |             |                                              |       |
| Floor                                       |       | 276,000                                           |             | 730,000                                           |       |
| Ceiling                                     |       | 276,000                                           |             | 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)             |       | $                                                 | 657              |                                              | $          | 811 |   |
| **Natural  Gas Swaps:**                     |       |                                              |             |                                              |       |
| Contract volumes  (MMBtu)                   |       | 368,000                                           |             | 912,500                                           |       |
| Weighted-average  fixed price per MMBtu (1) |       | $                                                 | 6.93             |                                              | $          | 7.17 |   |
| Fair value, net  (thousands)(3)             |       | $                                                 | 960              |                                              | $          | 1,613 |   |
| **Total  Natural Gas Contracts:**           |       |                                              |             |                                              |       |
| Contract volumes  (MMBtu)                   |       | 644,000                                           |             | 1,642,500                                         |       |
| Fixed-price  sales(2)                       |       | $                                                 | 7.47             |                                              | $          | 7.32 |   |
| Fair value, net  (thousands)(3)             |       | $                                                 | 1,617            |                                              | $          | 2,424 |   |

 

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| (1)    | Volumes hedged using  the CIG index price published in the first issue of Inside FERC’s Gas Market  Report for each calendar month of the derivative transaction. |
|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                   |
| (2)    | Assumes ceiling prices  for natural gas collar volumes.                                                                                                                |
|   |                                                                                                                                                                   |
| (3)    | Fair value based on CIG  index price in effect for each month as of September 30, 2008.                                                                           |

 

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** **

**Interest Rate Risk**

 

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

 

As of September 30,2008 and November 13, 2008, we had $7.5 million and $11.5 million,respectively, in outstanding indebtedness under our credit facility.  Borrowings under the credit facility bearinterest either: (i) at the greater of the one month LIBOR plus 1.00% or adomestic bank rate, plus in either case an applicable margin of 0.75% to 1.75%based on utilization, or (ii) on a sliding scale from one, two, three, orsix month LIBOR, plus an applicable margin of 2.00% to 3.00% based onutilization.  The weighted averageinterest rate for borrowings under our credit facility was 5.0% for the threemonths ended September 30, 2008 and 4.0% for the nine months ended September 30,2008.

 

A hypothetical increaseof 1% in either the domestic bank rate or the LIBOR interest rates wouldincrease gross interest expense approximately $115,000 per year.

 

**ITEM 4T. CONTROLS AND PROCEDURES**

 

***Disclosure Controls andProcedures***

 

Based on their evaluation as of the end of the periodcovered by this report, our principal executive officer and principal financialofficer have concluded that our disclosure controls and procedures (as definedin Rules 13a-15(e) and 15d-15(e) under the Securities ExchangeAct of 1934, as amended (the Exchange Act)) are effective to ensure thatinformation required to be disclosed in reports that we file or submit underthe Exchange Act are recorded, processed, summarized and reported within thetime periods specified in the SEC’s rules and forms.

 

***Changes in Internal Control OverFinancial Reporting***

 

During the most recent fiscal quarter, there have beenno changes in our internal control over financial reporting that havematerially affected, or are reasonably likely to materially affect, ourinternal control over financial reporting.

 

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**PART II. OTHER INFORMATION**

 

**ITEM1. LEGAL PROCEEDINGS**

 

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

 

There has been nomaterial developments during the quarter ended September 30, 2008regarding our currently pending legal proceedings. For a discussion of certainof our current legal proceedings, please see Note 9 of the notes to theunaudited financial statements appearing elsewhere in this quarterly report.

 

**ITEM1A. RISK FACTORS**

 

The following discussionsupplements or updates the risk factors set forth under the heading “RiskFactors” in our annual report on Form 10-K for the year ended December 31,2007 and in our quarterly report on Form 10-Q for the six months ended June 30,2008.

 

***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 upon naturalgas 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:

 

·**               **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;

 

·**               **Overall domesticand 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; and

 

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

 

In the past, natural gas prices have been extremelyvolatile, and we expect this volatility to continue. For example, during thenine months ended September 30, 2008, the NYMEX natural gas index priceranged from a high of $13.58 per MMBtu to a low of $7.22 per MMBtu, while theCIG natural gas index price ranged from a high of $10.26 per MMBtu to a low of$1.00 per MMBtu. During the year ended December 31, 2007, the NYMEXnatural gas index price ranged from a high of $8.64 per MMBtu to a low of $5.38per MMBtu, while the CIG natural gas index price ranged from a high of $7.11per MMBtu to a low of $0.06 per MMBtu.

 

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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. Dueto a decline in the price of natural gas during the third quarter and thebeginning of the fourth quarter, we have curtailed substantially all newdrilling for the remainder of 2008 and have shut in a number of wells that arenot economic at current natural gas price levels.

 

Lower natural gas pricesmay not only decrease our revenues on a per unit basis, but also may reduce theamount of natural gas that we can produce economically. This may result in ourhaving to make substantial downward adjustments to our estimated provedreserves. For example, if natural gas prices decline by $0.10 per Mcf, then thepre-tax PV-10 of our proved reserves as of June 30, 2008 would decreasefrom $87.9 million to $85.9 million. Accounting rules may also require usto write down, as a non-cash charge to earnings, the carrying value of ourproperties for impairments. As such, we may incur impairment charges in thefuture, which could have a material adverse effect on our results of operationsin the period such impairment charges are taken. For example, we reported animpairment of our oil and gas properties of approximately $18.2 million for theyear ended December 31, 2007 due to low and volatile CIG index pricesthroughout the year. A decline in gas prices or an increase in operating costssubsequent to the measurement date or reductions in the economicallyrecoverable quantities could result in the recognition of additional ceiling write-downsof our gas properties in future periods.

 

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

 

Our credit facilityimposes certain operational and financial restrictions on us. These restrictions,among other things, limit our ability to:

 

·**               **Incurindebtedness;

 

·**               **Create liens;

 

·**               **Sell ourassets or consolidate or merge with or into other companies; and

 

·**               **Engage intransactions with affiliates.

 

These limitations aresubject to a number of important qualifications and expectations. In addition,our credit facility requires us to maintain certain financial ratios and tosatisfy certain financial conditions which may limit our borrowing availabilityor require us to reduce our debt or to take some other action in order tocomply with them. Due to the limitations in our credit facility, we arecurrently unable to borrow additional amounts under the facility. Therestrictions in our credit facility could limit our ability to obtain futurefinancing, make needed capital expenditures, withstand a downturn in ourbusiness or the economy in general, or otherwise conduct necessary corporateactivities. We also may be prevented from taking advantage of businessopportunities that arise because of the limitations imposed on us by therestrictive covenants under our credit facility. Please see Part I, Item 2of this quarterly report, “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.

 

***Dueto the recent financial and credit crisis, we may not be able to obtainfunding, or obtain funding on acceptable terms, to meet our future capitalneeds, which could negatively affect our business, results of operations andfinancial condition.***

 

The recent credit crisis and the related turmoil inthe global financial system may have an adverse impact on our business andfinancial condition, and we may face challenges if conditions in the financialmarkets do not improve.  Currently, weare not able to borrow additional amounts under our credit facility.  As a result, we have curtailed substantiallyall new drilling for the remainder of 2008, and if our operating cash flow isnot sufficient to carry out our drilling plan for 2009, we will be required toreduce the number of wells we drill or seek alternative sources offinancing.  However, due to the financialcrisis, financing may not be available to us on acceptable terms or atall.  If additional funding is notavailable, or is available only on unfavorable terms, we may be unable toimplement our drilling plan, make capital expenditures, withstand a downturn inour business or the economy in general, or take advantage of businessopportunities that may arise.  Any furthercurtailment of our operations would have an additional adverse effect on ourrevenues and results of operations.  Inaddition, current economic conditions have led to reduced demand for, and lowerprices of, oil and natural gas, and a sustained decline the price of naturalgas would adversely affect our business, results of operations and financialcondition.  Please read “The volatilityof natural gas and oil prices could have a material adverse effect on ourbusiness” above.

 

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** **

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

 

Effective July 1,2008 and August 12, 2008, we granted and issued an aggregate of 86,650 and10,500 shares of restricted common stock, respectively, to certain of ouremployees pursuant to our stock incentive plan. These restricted shares will vest in thirds on the first, second andthird anniversaries of the date of grant. Effective August 25, 2008, we granted and issued 12,500 shares ofrestricted stock to each of our non-employee directors, or 87,500 shares ofrestricted stock in the aggregate.  Theserestricted shares will vest in full on December 31, 2008.  Also effective August 25, 2008, wegranted and issued 35,000 and 25,000 shares of restricted stock to ourpresident and chief executive officer and our senior vice president and chieffinancial officer, respectively.  Theserestricted shares will vest in thirds on the first, second and thirdanniversaries of the date of grant. These issuances of restricted stock were exempt from the registrationrequirements of the Securities Act pursuant to Rule 701.

 

**ITEM 3. DEFAULTS UPON SENIORSECURITIES**

 

Not applicable.

 

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

 

On August 12, 2008,we held our annual meeting of stockholders. Of the 29,000,101 shares of common stock of record as of the recorddate, holders of 15,967,989 shares were present in person or represented byproxy at the meeting.  At the meeting,the stockholders voted on the election of two Class II directors to serveuntil the end of their terms in 2011 and on the ratification of the appointmentof Ehrhardt Keefe Steiner & Hottman PC as the company’s independentregistered public accounting firm.  Thefollowing is a summary of the votes on these matters:

 
| ** **                                   | ** ** | **Votes For** | ** ** | **Votes Withheld** | ** ** | ** **      | ** ** |
|----------------------------------------------|------------|--------------------|------------|-------------------------|------------|-----------------|------------|
| **Election  of Directors:**                  |       |               |       |                    |       |            |       |
| Robert L.  Cabes, Jr.                   |       | 15,893,202         |       | 74,787                  |       |            |       |
| Sylvester P.  Johnson IV                     |       | 15,915,810         |       | 52,179                  |       |            |       |
|                                         |       |               |       |                    |       |            |       |
| ** **                                   | ** ** | **Votes For**      | ** ** | **Votes Against**       | ** ** | **Abstentions** | ** ** |
| **Ratification  of Appointment of Auditors** |       | 15,932,245         |       | 23,593                  |       | 12,151          |       |

 

**ITEM 5. OTHER INFORMATION**

 

On November 11, 2008, we adopted our SecondAmended and Restated Stock Incentive Plan. The plan was amended primarily to comply with final regulations issuedunder Section 409A of the Internal Revenue Code of 1986.  A copy of the amended and restated plan isfiled as Exhibit 10.1 to this quarterly report.

 

On November 13,2008, we and The Royal Bank of Scotland, plc, as administrative agent andlender, entered into the Third Amendment to our credit facility (the “ThirdAmendment”), effective September 30, 2008. For a description of the material terms of the Third Amendment, pleasesee Note 10 of the notes to the financial statements appearing elsewhere inthis quarterly report and “Management’s Discussion and Analysis of FinancialCondition and Results of Operations—Liquidity and Capital Resources—CreditFacility.”  A copy of the Third Amendmentis filed as Exhibit 10.3 to this quarterly report.

 

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**ITEM 6. EXHIBITS**

 
| Exhibit No. | ** ** | **Description**                                                                                                                                                                                                                                                                                           |
|-------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.1         |       | —Second Amended and Restated Certificate of  Incorporation of Pinnacle Gas Resources, Inc. (incorporated herein by  reference to Exhibit 3.1 to the Registration Statement on Form S-1  (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on  May 10, 2006). |
|        |       |                                                                                                                                                                                                                                                                                                      |
| 3.2         |       | —Amended and Restated Bylaws of Pinnacle Gas  Resources, Inc. (incorporated herein by reference to Exhibit 3.2 to  the Registration Statement on Form S-1 (File No. 333-133983) filed  by Pinnacle Gas Resources, Inc. on May 10, 2006).                               |
|        |       |                                                                                                                                                                                                                                                                                                      |
| 4.1         |       | —Amended and Restated Securityholders Agreement,  dated February 16, 2006 (incorporated herein by reference to  Exhibit 4.1 to the Registration Statement on Form S-1 (File  No. 333-133983) filed by Pinnacle Gas Resources, Inc. on  May 10, 2006).                  |
|        |       |                                                                                                                                                                                                                                                                                                      |
| 4.2         |       | —Registration Rights Agreement, dated April 11,  2006 (incorporated herein by reference to Exhibit 4.2 to the  Registration Statement on Form S-1 (File No. 333-133983) filed by  Pinnacle Gas Resources, Inc. on May 10, 2006).                                       |
|        |       |                                                                                                                                                                                                                                                                                                      |
| †*10.1 |       | —Second Amended and Restated Stock Incentive Plan,  effective November 11, 2008.                                                                                                                                                                                                                     |
|        |       |                                                                                                                                                                                                                                                                                                      |
| 10.2        |       | —Second Amendment to Credit Agreement, dated August  4, 2008 (incorporated herein by reference to Exhibit 10.1 to the Current  Report on Form 8-K filed by Pinnacle Gas Resources, Inc. on August 6, 2008).                                                                                          |
|        |       |                                                                                                                                                                                                                                                                                                      |
| *10.3       |       | —Third Amendment to Credit Agreement, dated September  30, 2008.                                                                                                                                                                                                                                     |
|        |       |                                                                                                                                                                                                                                                                                                      |
| *31.1       |       | —Certification of President and Chief Executive  Officer of Pinnacle Gas Resources, Inc. pursuant to Section 302 of  the Sarbanes-Oxley Act of 2002.                                                                                                                                       |
|        |       |                                                                                                                                                                                                                                                                                                      |
| *31.2       |       | —Certification of Senior Vice President, Chief  Financial Officer and Secretary of Pinnacle Gas Resources, Inc. pursuant  to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                |
|        |       |                                                                                                                                                                                                                                                                                                      |
| *32.1       |       | —Certification of President and Chief Executive  Officer of Pinnacle Gas Resources, Inc. pursuant to 18 U.S.C.  Section 1350, as adopted pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002.                                                                                  |
|        |       |                                                                                                                                                                                                                                                                                                      |
| *32.2       |       | —Certification of Senior Vice President, Chief  Financial Officer and Secretary of Pinnacle Gas Resources, Inc. pursuant  to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of  the Sarbanes-Oxley Act of 2002.                                                           |

 

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*              Filedherewith

 

†              Managementcontract or compensatory plan or arrangement

 

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**SIGNATURES**

 

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

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

 

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| Exhibit No. | ** ** | **Description**                                                                                                                                                                                                                                                                                           |
|-------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.1         |       | —Second Amended and Restated Certificate of  Incorporation of Pinnacle Gas Resources, Inc. (incorporated herein by  reference to Exhibit 3.1 to the Registration Statement on Form S-1  (File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on  May 10, 2006). |
|        |       |                                                                                                                                                                                                                                                                                                      |
| 3.2         |       | —Amended and Restated Bylaws of Pinnacle Gas Resources, Inc.  (incorporated herein by reference to Exhibit 3.2 to the Registration  Statement on Form S-1 (File No. 333-133983) filed by Pinnacle Gas  Resources, Inc. on May 10, 2006).                               |
|        |       |                                                                                                                                                                                                                                                                                                      |
| 4.1         |       | —Amended and Restated Securityholders Agreement,  dated February 16, 2006 (incorporated herein by reference to  Exhibit 4.1 to the Registration Statement on Form S-1 (File  No. 333-133983) filed by Pinnacle Gas Resources, Inc. on  May 10, 2006).                  |
|        |       |                                                                                                                                                                                                                                                                                                      |
| 4.2         |       | —Registration Rights Agreement, dated April 11,  2006 (incorporated herein by reference to Exhibit 4.2 to the  Registration Statement on Form S-1 (File No. 333-133983) filed by  Pinnacle Gas Resources, Inc. on May 10, 2006).                                       |
|        |       |                                                                                                                                                                                                                                                                                                      |
| †*10.1 |       | —Second Amended and Restated Stock Incentive Plan,  effective November 11, 2008.                                                                                                                                                                                                                     |
|        |       |                                                                                                                                                                                                                                                                                                      |
| 10.2        |       | —Second Amendment to Credit Agreement, dated August  4, 2008 (incorporated herein by reference to Exhibit 10.1 to the Current  Report on Form 8-K filed by Pinnacle Gas Resources, Inc. on August 6, 2008).                                                                                          |
|        |       |                                                                                                                                                                                                                                                                                                      |
| *10.3       |       | —Third Amendment to Credit Agreement, dated September  30, 2008.                                                                                                                                                                                                                                     |
|        |       |                                                                                                                                                                                                                                                                                                      |
| *31.1       |       | —Certification of President and Chief Executive  Officer of Pinnacle Gas Resources, Inc. pursuant to Section 302 of  the Sarbanes-Oxley Act of 2002.                                                                                                                                       |
|        |       |                                                                                                                                                                                                                                                                                                      |
| *31.2       |       | —Certification of Senior Vice President, Chief  Financial Officer and Secretary of Pinnacle Gas Resources, Inc. pursuant  to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                |
|        |       |                                                                                                                                                                                                                                                                                                      |
| *32.1       |       | —Certification of President and Chief Executive  Officer of Pinnacle Gas Resources, Inc. pursuant to 18 U.S.C.  Section 1350, as adopted pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002.                                                                                  |
|        |       |                                                                                                                                                                                                                                                                                                      |
| *32.2       |       | —Certification of Senior Vice President, Chief  Financial Officer and Secretary of Pinnacle Gas Resources, Inc. pursuant  to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of  the Sarbanes-Oxley Act of 2002.                                                           |

 

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*              Filedherewith

 

†              Managementcontract or compensatory plan or arrangement

 

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