**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

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**FORM 10-Q**

 

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| **x**                                                                                                                                                                                                                                            | ** ** | **QUARTERLY REPORT PURSUANT TO  SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**  |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------|
|                                                                                                                                                                                                                                             |       |                                                                                                    |
| **For the quarterly period ended  September 30, 2009**                                                                                                                                                                                      |
|                                                                                                                                                                                                                                             |
| **or**                                                                                                                                                                                                                                           |
|                                                                                                                                                                                                                                             |       |                                                                                                    |
| **o**                                                                                                                                                                                                                                            | ** ** | **TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE  SECURITIES EXCHANGE ACT OF 1934** |
|                                                                                                                                                                                                                                             |       |                                                                                                    |
| **For the transition period from                 to                 ** |

 

**Commission file number: 001-33457**

 

**Pinnacle Gas Resources, Inc.**

(Exact name of registrantas specified in its charter)

 

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

 

**(307) 673-9710**

(Registrant’s telephonenumber, including area code)

 

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

 

Indicate by check mark whether the registrant has submittedelectronically and posted on its corporate Web site, if any, every InteractiveData File required to be submitted and posted pursuant to Rule 405 ofRegulation S-T (§232.405 of this chapter) during the preceding 12 months (orfor such shorter period that the registrant was required to submit and postsuch files). Yes o Noo

 

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

 

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

 

Indicate by check mark whether the registrant is a shell company (asdefined in Rule 12b-2 of the Exchange Act). Yes £ Nox

 

29,911,697 shares of the registrant’s Common Stock were outstanding asof November 23, 2009.

 

 

 

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**PINNACLE GAS 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, 2008  and September 30, 2009 (unaudited)                       | 3        |
| Statements of Operations for the three and  nine months ended September 30, 2009 and 2008 (unaudited) | 4        |
| Statements of Cash Flows for the nine  months ended September 30, 2009 and 2008 (unaudited)           | 5        |
| Statement of Stockholders’ Equity at  September 30, 2009 (unaudited)                             | 6        |
| Notes to Financial Statements (unaudited)                                                                  | 7        |
| Item 2. Management’s Discussion and Analysis of Financial Condition  and Results of Operations        | 20       |
| Overview                                                                                                   | 20       |
| Economic and Natural Gas Pricing  Environment                                                              | 20       |
| Credit Facility and Liquidity                                                                              | 21       |
| Critical Accounting Policies                                                                               | 22       |
| Trends Affecting Our Business                                                                              | 27       |
| Results of Operations                                                                                      | 28       |
| Liquidity and Capital Resources                                                                            | 31       |
| Item 3. Quantitative and Qualitative Disclosures About Market Risk                                         | 35       |
| Item 4T. Controls and Procedures                                                                           | 36       |
| Part II. OTHER INFORMATION                                                                            | 36       |
| Item 1. Legal Proceedings                                                                                  | 36       |
| Item 1A. Risk Factors                                                                                      | 36       |
| Item 2. Unregistered Sales of Equity Securities and Use of Proceeds                                        | 37       |
| Item 3. Defaults Upon Senior Securities                                                                    | 37       |
| Item 4. Submission of Matters to a Vote of Security Holders                                                | 37       |
| Item 5. Other Information                                                                                  | 37       |
| Item 6. Exhibits                                                                                           | 38       |

 

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**CAUTIONARYSTATEMENT CONCERNING FORWARD-LOOKING STATEMENTS**

 

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

 

·**               **ourfinancial position or operating results;

 

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

 

·**               **ourbusiness strategy;

 

·**               **ourbudgets;

 

·**               **theamount, nature and timing of capital expenditures;

 

·**               **thedrilling of wells;

 

·**               **thedevelopment of recently acquired natural gas and oil properties;

 

·**               **thetiming and amount of future production of natural gas and oil;

 

·**               **ouroperating costs and other expenses;

 

·**               **ourestimated future net revenues from natural gas and oil reserves and the presentvalue thereof;

 

·**               **ourcash flow and anticipated liquidity; and

 

·**               **ourother plans and objectives for future operations.

 

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

 

· the availabilityof capital;

 

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

 

· regional pricedifferentials;

 

· the extent ofour success in discovering, developing and producing reserves, including therisks inherent in exploration and development drilling, well completion andother development activities;

 

· the lack ofliquidity of our equity securities;

 

· thesubstantial capital expenditures required for construction of pipelines and thedrilling of wells and the related need to fund such capital requirementsthrough commercial banks and/or public securities markets;

 

1

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

 

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

 

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

 

·production variances from expectations;

 

·our ability to develop and replace reserves;

 

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

 

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

 

·environmental-related problems;

 

·the availability and cost of materials and equipment;

 

·our dependence upon key personnel;

 

·our ability to find and retain skilled personnel;

 

·delays in anticipated start-up dates;

 

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

 

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

 

·our ability to effectively market our production;

 

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

 

· generaleconomic conditions.

 

When you consider these forward-looking statements, you should keep inmind these factors and the other factors discussed in the “Risk Factors”section of our annual report on Form 10-K for the year ended December 31,2008 and this quarterly report on Form 10-Q.

 

2

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**PART I. FINANCIAL INFORMATION**

 

**ITEM 1. FINANCIAL STATEMENTS**

 

**PINNACLE GAS RESOURCES, INC.**

**BalanceSheets**

 
| ** **                                                                                                                                                                              | ** ** | **September 30,********2009** | ** ** | **December 31,********2008** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------|------------|-----------------------------------|------------|
| ** **                                                                                                                                                                              | ** ** | **(unaudited)**                    | ** ** | **(audited)**                     | ** ** |
| ** **                                                                                                                                                                              | ** ** | **(in thousands)**                 | ** ** |
| **Assets**                                                                                                                                                                              |       |                               |       |                              |       |
| Current assets                                                                                                                                                                          |       |                               |       |                              |       |
| Cash and cash equivalents                                                                                                                                                               |       | $                                  | 7          |                              | $          | 346 |   |
| Receivables                                                                                                                                                                             |       |                               |       |                              |       |
| Accrued gas sales                                                                                                                                                                       |       | 526                                |       | 2,091                             |       |
| Joint interest receivables, net of $100  allowance for doubtful accounts                                                                                                                |       | 1,256                              |       | 4,824                             |       |
| Derivative instruments                                                                                                                                                                  |       | —                             |       | 4,345                             |       |
| Inventory of material for drilling and  completion                                                                                                                                      |       | 57                                 |       | 83                                |       |
| Restricted certificates of deposits                                                                                                                                                     |       | 300                                |       | —                            |       |
| Prepaid expenses                                                                                                                                                                        |       | 191                                |       | 196                               |       |
| Total current assets                                                                                                                                                                    |       | 2,337                              |       | 11,885                            |       |
| Property and equipment, at cost, net of  accumulated depreciation                                                                                                                       |       | 1,289                              |       | 1,798                             |       |
| Oil and gas properties, using full cost  accounting, net of accumulated depletion and impairment                                                                                        |       |                               |       |                              |       |
| Proved                                                                                                                                                                                  |       | 11,469                             |       | 34,522                            |       |
| Unproved                                                                                                                                                                                |       | 49,915                             |       | 86,827                            |       |
| Inventory of material held for exploration  and development                                                                                                                             |       | 402                                |       | 384                               |       |
| Deposits                                                                                                                                                                                |       | 75                                 |       | 199                               |       |
| Restricted certificates of deposit                                                                                                                                                      |       | 1,829                              |       | 2,725                             |       |
| Total assets                                                                                                                                                                            |       | $                                  | 67,316     |                              | $          | 138,340 |   |
| **Liabilities and Stockholders’ Equity**                                                                                                                                           |       |                               |       |                              |       |
| Current liabilities                                                                                                                                                                     |       |                               |       |                              |       |
| Long term debt-current portion                                                                                                                                                          |       | $                                  | 6,554      |                              | $          | 11,530 |   |
| Derivative instruments                                                                                                                                                                  |       | 291                                |       | —                            |       |
| Trade accounts payable                                                                                                                                                                  |       | 9,087                              |       | 10,112                            |       |
| Revenue distribution payable                                                                                                                                                            |       | 3,019                              |       | 4,625                             |       |
| Drilling prepayments from joint interest  owners                                                                                                                                        |       | 48                                 |       | —                            |       |
| Asset retirement obligations, current                                                                                                                                                   |       | 669                                |       | 341                               |       |
| Accrued liabilities                                                                                                                                                                     |       | 2,995                              |       | 1,539                             |       |
| Total current liabilities                                                                                                                                                               |       | 22,663                             |       | 28,147                            |       |
| Asset retirement  obligations, non-current                                                                                                                                              |       | 2,740                              |       | 3,025                             |       |
| Derivative instruments                                                                                                                                                                  |       | 571                                |       | —                            |       |
| Production taxes, non-current                                                                                                                                                           |       | 557                                |       | 1,156                             |       |
| Long term debt – net of current portion                                                                                                                                            |       | 754                                |       | 733                               |       |
| Total liabilities                                                                                                                                                                       |       | 27,285                             |       | 33,061                            |       |
| Commitments and contingencies                                                                                                                                                           |       |                               |       |                              |       |
| Stockholders’ equity                                                                                                                                                               |       |                               |       |                              |       |
| Common stock, $0.01 par value; 100,000,000  authorized and 29,911,697 and 29,193,573 shares issued and outstanding at  September 30, 2009 and December 31, 2008, respectively |       | 289                                |       | 289                               |       |
| Additional paid-in capital                                                                                                                                                              |       | 151,562                            |       | 150,879                           |       |
| Accumulated deficit                                                                                                                                                                     |       | (111,820                           | )          | (45,889                           | )          |
| Total stockholders’ equity                                                                                                                                                         |       | 40,031                             |       | 105,279                           |       |
| Total liabilities and stockholders’ equity                                                                                                                                         |       | $                                  | 67,316     |                              | $          | 138,340 |   |

 

See Notes to Financial Statements (unaudited)

 

3

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**PINNACLE GAS RESOURCES, INC.**

**Statementsof Operations**

**(unaudited)**

 
| ** **                                             | ** ** | **Three Months Ended**                               | ** ** | **Nine Months Ended**  | ** ** |
|--------------------------------------------------------|------------|------------------------------------------------------|------------|------------------------|------------|
| ** **                                             | ** ** | **September 30,**                               | ** ** | **September 30,** | ** ** |
| ** **                                             | ** ** | **2009**                                             | ** ** | **2008**               | ** ** | **2009** | ** ** | **2008** | ** ** |
| ** **                                             | ** ** | **(in thousands, except share and  per share data)** | ** ** |
| Revenues                                               |       |                                                 |       |                   |       |   |   |   |   |
| Gas sales                                              |       | $                                                    | 1,687      |                   | $          | 5,684 |   | $ | 6,057 |   | $ | 18,918 |   |
| Realized gain/(loss) on derivatives                    |       | 2,038                                                |       | 725                    |       | 5,548 |   | (45 | ) |
| Total revenues                                         |       | 3,725                                                |       | 6,409                  |       | 11,605 |   | 18,873 |   |
| Cost of revenues and expenses                          |       |                                                 |       |                   |       |   |   |   |   |
| Lease operating expenses                               |       | 923                                                  |       | 1,793                  |       | 3,047 |   | 5,191 |   |
| Production taxes                                       |       | 167                                                  |       | 645                    |       | 585 |   | 2,164 |   |
| Marketing and transportation                           |       | 785                                                  |       | 1,165                  |       | 2,930 |   | 3,452 |   |
| General and administrative, net                        |       | 868                                                  |       | 1,334                  |       | 3,082 |   | 5,925 |   |
| Depreciation, depletion, amortization and  accretion   |       | 2,319                                                |       | 2,664                  |       | 5,063 |   | 6,677 |   |
| Impairment of oil and gas properties                   |       | 34,594                                               |       | —                 |       | 57,844 |   | — |   |
| Total cost of revenues and expenses                    |       | 39,656                                               |       | 7,601                  |       | 72,551 |   | 23,409 |   |
| Operating loss                                         |       | (35,931                                              | )          | (1,192                 | )          | (60,946 | ) | (4,536 | ) |
| Other income/(expense)                                 |       |                                                 |       |                   |       |   |   |   |   |
| Unrealized gain/(loss) on derivatives                  |       | (3,074                                               | )          | 9,951                  |       | (5,207 | ) | 3,486 |   |
| Interest income                                        |       | 17                                                   |       | 40                     |       | 51 |   | 139 |   |
| Other income                                           |       | 102                                                  |       | 201                    |       | 302 |   | 424 |   |
| Interest expense                                       |       | (76                                                  | )          | (61                    | )          | (131 | ) | (96 | ) |
| Total other income/(expense)                           |       | (3,031                                               | )          | 10,131                 |       | (4,985 | ) | 3,953 |   |
| Net income/(loss) before income taxes                  |       | (38,962                                              | )          | 8,939                  |       | (65,931 | ) | (583 | ) |
| Net income/(loss) attributable to common  stockholders |       | $                                                    | (38,962    | )                      | $          | 8,939 |   | $ | (65,931 | ) | $ | (583 | ) |
| Basic net income/(loss) per share                      |       | $                                                    | (1.31      | )                      | $          | 0.31 |   | $ | (2.24 | ) | $ | (0.02 | ) |
| Diluted net income/(loss) per share                    |       | (1.31                                                | )          | 0.30                   |       | (2.24 | ) | (0.02 | ) |
| Weighted average shares outstanding — basic       |       | 29,783,933                                           |       | 29,146,543             |       | 29,446,568 |   | 29,054,181 |   |
| Weighted average shares outstanding —  diluted    |       | 29,783,933                                           |       | 29,887,521             |       | 29,446,568 |   | 29,054,181 |   |

 

See Notes to Financial Statements (unaudited)

 

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**PINNACLE GAS RESOURCES, INC.**

**Statementsof Cash Flows**

**(in thousands)**

** (unaudited)**

 
| ** **                                                                         | ** ** | **For the Nine Months********Ended********September 30,** | ** ** |
|------------------------------------------------------------------------------------|------------|----------------------------------------------------------------|------------|
| ** **                                                                         | ** ** | **2009**                                                       | ** ** | **2008** | ** ** |
| Cash flows from operating activities                                               |       |                                                           |       |   |   |
| Net loss                                                                           |       | $                                                              | (65,931    | ) | $ | (583 | ) |
| Adjustments to reconcile net loss to net  cash provided by operating activities    |       |                                                           |       |   |   |
| Impairment of oil and gas properties                                               |       | 57,844                                                         |       | — |   |
| Depreciation, depletion, amortization and  accretion                               |       | 5,063                                                          |       | 6,677 |   |
| Gain on derivatives                                                                |       | (341                                                           | )          | (3,441 | ) |
| Stock-based compensation                                                           |       | 683                                                            |       | 772 |   |
| Changes in assets and liabilities                                                  |       |                                                           |       |   |   |
| Decrease in receivables                                                            |       | 1,933                                                          |       | 1,249 |   |
| Decrease (increase) in inventory of  material for drilling and completion          |       | 26                                                             |       | (62 | ) |
| Asset retirement obligations settled this  period                                  |       | (129                                                           | )          | (48 | ) |
| Decrease in prepaid expenses                                                       |       | 5                                                              |       | 1,047 |   |
| Increase in trade accounts payable and  accrued liabilities and production taxes   |       | 718                                                            |       | 5,141 |   |
| Decrease in revenue distribution payable                                           |       | (1,606                                                         | )          | (380 | ) |
| (Decrease) increase in drilling prepayments  from joint interest owners            |       | 48                                                             |       | (20 | ) |
| Net cash (used in) provided by operating  activities                               |       | (1,687                                                         | )          | 10,352 |   |
| Cash flows from investing activities                                               |       |                                                           |       |   |   |
| Capital expenditures — exploration and  production                            |       | (3,026                                                         | )          | (24,106 | ) |
| Capital expenditures — property and  equipment                                |       | (99                                                            | )          | (561 | ) |
| Proceeds received from sale of oil and gas  properties                             |       | 3,200                                                          |       | — |   |
| Decrease (increase) in purchase of  restricted certificate of deposit and deposits |       | 720                                                            |       | (1,157 | ) |
| (Increase) decrease in inventory held for  exploration and development             |       | (18                                                            | )          | 67 |   |
| Realized gain (loss) on derivatives                                                |       | 5,548                                                          |       | (44 | ) |
| Net cash provided by (used in) investing  activities                               |       | 6,325                                                          |       | (25,801 | ) |
| Cash flows from financing activities                                               |       |                                                           |       |   |   |
| Principal payments on note payable                                                 |       | (4,977                                                         | )          | (17 | ) |
| Proceeds from long-term debt                                                       |       | —                                                         |       | 7,500 |   |
| Issuance costs related to common stock                                             |       | —                                                         |       | (6 | ) |
| Net cash (used in) provided by financing  activities                               |       | (4,977                                                         | )          | 7,477 |   |
| Net decrease in cash and cash equivalents                                          |       | (339                                                           | )          | (7,972 | ) |
| Cash and cash equivalents at beginning of  the year                                |       | 346                                                            |       | 8,151 |   |
| Cash and cash equivalents at  September 30, 2009 and 2008, respectively       |       | $                                                              | 7          |   | $ | 179 |   |
| Noncash investing and financing activities                                         |       |                                                           |       |   |   |
| Capital expenditures included in trade  accounts payable                           |       | $                                                              | 6,869      |   | $ | 7,481 |   |
| Asset retirement obligation included in oil  and gas properties                    |       | —                                                         |       | 410 |   |
| Supplemental cash flow information                                                 |       |                                                           |       |   |   |
| Cash payments for interest, net of amount  capitalized                             |       | $                                                              | 131        |   | $ | 95 |   |

 

See Notes to Financial Statements (unaudited)

 

5

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**PINNACLE GAS RESOURCES, INC.**

**Statementof Stockholders’ Equity**

**(in thousands, except for sharedata)**

 
| ** **                                      | ** ** | ** **       | ** ** | ** **              | ** ** | **Stockholders’ Equity** | ** ** |
|-------------------------------------------------|------------|------------------|------------|-------------------------|------------|-------------------------------|------------|
| ** **                                      | ** ** | **Common Stock** | ** ** | **Warrants********and** | ** ** | **Additional********Paid-In** | ** ** | **Accumulated** | ** ** | ** ** | ** ** |
| ** **                                      | ** ** | **Shares**       | ** ** | **Amount**              | ** ** | **Options**                   | ** ** | **Capital** | ** ** | **Deficit** | ** ** | **Total** | ** ** |
|                                            |       |             |       |                    |       |                          |       |   |   |   |   |   |   |
| Balance at December 31, 2008               |       | 29,193,573       |       | $                       | 289        |                          | —     |   | $ | 150,879 |   | $ | (45,889 | ) | $ | 105,279 |   |
| Issuance of restricted shares (unaudited)       |       | 723,688          |       | —                  |       | —                        |       | 422 |   | — |   | 422 |   |
| Forfeiture of restricted shares (unaudited)     |       | (5,564           | )          | —                  |       | —                        |       | — |   | — |   | — |   |
| Stock-based compensation (unaudited)            |       | —           |       | —                  |       | —                        |       | 261 |   | — |   | 261 |   |
| Net loss (unaudited)                            |       | —           |       | —                  |       | —                        |       | — |   | (65,931 | ) | (65,931 | ) |
| Balance at September 30, 2009  (unaudited) |       | 29,911,697       |       | $                       | 289        |                          | —     |   | $ | 151,562 |   | $ | (111,820 | ) | $ | 40,031 |   |

 

See Notes to Financial Statements (unaudited)

 

6

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**Notes toFinancial Statements**

**(Unaudited)**

 

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

 

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

 

The Company’s primary business is the explorationfor, and the acquisition, development and production of, coalbed methanenatural gas in the United States. The Company is also engaged in gas propertyoperations and the construction of low pressure gas collection systems whichprovide transportation for the Company’s coalbed methane production.

 

Due to thecurrent economic and pricing environment, the Company is actively marketingcertain assets to raise additional capital and is also reviewing alternativesfor raising additional capital through equity and debt financing, capitalrestructuring and possible mergers. The Company sold its high pressure gasgathering system in the Cabin Creek project area in Wyoming, and its remaininginterest in the Arvada project area in Wyoming in April 2009. The Companyreceived approximately $3.2 million in net proceeds from these sales, and usedpart of such proceeds to repay a portion of its indebtedness outstanding underthe credit facility and used the remainder for general operating purposes. TheCompany has also executed additional hedges of its gas production to securecertain operating cash flow levels during the remainder of 2009. From January throughApril 2009, the Company had 4,500 MMbtu per day hedged through acombination of a fixed price swap and a costless collar at a weighted averagefloor price of $6.87 per MMbtu and a ceiling price of $7.32 per MMbtu.  In May, the Company had 7,000 Mmbtu per dayhedged through a combination of fixed price swaps and a costless collar at aweighted average floor price of $5.65 per Mmbtu and a ceiling price of $5.94per Mmbtu. From June through December 2009, the Company has 8,000MMbtu per day hedged through a combination of a fixed price swaps and acostless collar at a weighted average floor price of $5.44 per MMbtu and aceiling price of $5.69 per MMbtu. The hedges were executed based on the ColoradoInterstate Gas price. The Company has also implemented various cost cuttingmeasures, including reducing general and administrative costs through staffreductions, wage and benefit cuts and a hiring freeze. The Company has reducedlease operating expenses by renegotiating water disposal contracts, reducingservice costs and temporarily shutting-in marginal wells.

 

The Companycontinues to communicate with key vendors to manage its obligations andpayables. Management believes that appropriate steps, including cost-cuttingmeasures, marketing of certain assets, possible equity offerings, andadditional or new debt financing are being taken to make operations sustainablein the future. Although the Company is pursuing various alternatives to provideadditional liquidity, there is no assurance of the likelihood or timing of anyof these transactions.

 

**Note 2 — Basis of Presentation**

 

The accompanying unaudited financial statementsinclude the Company’s proportionate share of assets, liabilities, income andexpenses from the properties in which the Company has a participatinginterest.  The Company has nosubsidiaries or affiliates with which intercompany transactions are recorded.

 

The accompanying financial statements are unaudited,and in the opinion of management, reflect all adjustments that are necessaryfor a fair presentation of the financial position and results of operations forthe periods presented.  All suchadjustments are of a normal and recurring nature. The following Notes describeonly the material changes in accounting policies, account details, or financialstatement Notes during the first nine months of 2009.  The results for the three and nine monthsending September 30, 2009 are not necessarily indicative of the resultsexpected for the entire year.  Thesefinancial statements should be read in conjunction with the audited financialstatements and the summary of significant accounting policies for prior yearscontained in the reports the Company files with the Securities and Exchange Commission,which can be found on the Company’s website at *www.pinnaclegas.com*.

 

*Use ofEstimates*

 

The preparation of the Company’s financialstatements in conformity with accounting principles generally accepted in theUnited States of America requires management to make estimates and assumptionsthat affect the reported amount of assets and liabilities, disclosure ofcontingent assets and liabilities at the date of the financial statements andthe reported amounts of revenues and expenses during the reporting period.Actual results could differ from these estimates. Significant estimates withregard to the Company’s financial statements include the estimated carryingvalue of unproved properties, the estimate of proved oil and gas reservevolumes and the related present value of estimated future net cash flows, theceiling test applied to capitalized oil and gas properties, the estimate of thetiming and cost of the Company’s future drilling activity, the estimated costand timing related to asset retirement obligations, the estimated fair value ofderivative assets and liabilities, the realizability of deferred tax assets,the estimates of expenses and timing of exercise of stock options, accrual ofoperating costs and capital expenditures and revenue.

 

7

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*Oil and Gas Properties*

 

The Company utilizes thefull cost method of accounting for oil and gas producing activities. Under thismethod, 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. The Company’s oil and gas properties are all locatedwithin the United States, which constitutes a single cost center. The Companycapitalizes lease operating expenses associated with exploration anddevelopment of unevaluated oil and gas properties. No gain or loss isrecognized upon the sale or abandonment of undeveloped or producing oil and gasproperties unless the sale represents a significant portion of gas propertiesand the gain significantly alters the relationship between capitalized costs andproved gas reserves of the cost center. Expenditures for maintenance andrepairs are charged to lease operating expense in the period incurred.

 

Depreciation, depletion and amortization of oil and gas properties (“DD&A”)is computed on the unit-of-production method based on proved reserves.Amortizable costs include estimates of future development costs of provedundeveloped reserves and asset retirement obligations. The Company invests inunevaluated oil and gas properties for the purpose of exploration for provedreserves. The costs of such assets, including exploration costs on propertieswhere a determination of whether proved oil and gas reserves will beestablished is still under evaluation, and any capitalized interest and leaseoperating expenses are included in unproved oil and gas properties at the lowerof cost or estimated fair market value and are not subject to amortization. Ona quarterly 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. Abandonment of unproved properties is accountedfor as an adjustment to capitalized costs related to proved oil and gasproperties, with no losses recognized. The Company recorded an impairment ofunevaluated properties of $26.0 million and $10.7 million on its Green Riverand Kirby properties respectively, for the three months ended September 30,2009. Substantially all of the remaining unproved property costs are expectedto be developed and included in the amortization base over the next three tofive years.  Salvage value is taken intoaccount in determining depletion rates and is based on the Company’s estimateof the value of equipment and supplies at the time the well is abandoned.  As of September 30, 2009 and December 31,2008, the estimated salvage value was approximately $7.2 million and $7.3million, respectively.

 

Under the full cost method of accounting rules, capitalized costs lessaccumulated depletion and related deferred income taxes may not exceed a ‘‘ceiling’’value which is the sum of (1) the present value discounted at 10% ofestimated future net revenue using current costs and prices, including theeffects of derivative instruments designated as cash flow hedges but excludingthe future cash outflows associated with settling asset retirement obligationsthat have been accrued on the balance sheet, less any related income taxeffects; plus (2) the cost of properties not being amortized, if any; plus(3) the lower of costs or estimated fair value of unproved properties;less (4) the income tax effects related to differences in the book to taxbasis of oil and gas properties. This is referred to as the ‘‘full cost ceilinglimitation.’’ If capitalized costs exceed the limit, the excess must be chargedto expense. The expense may not be reversed in future periods. At the end ofeach quarter, the Company calculates the full cost ceiling limitation. At September 30,2009, the capitalized cost of our oil and gas properties exceeded the full costceiling limitation by approximately $35.6 million based upon a natural gasprice of $3.09 per Mcf (based on the Colorado Interstate Gas Rocky MountainIndex) in effect at that date. Based on the subsequent price increase toapproximately $3.22 per Mcf on November 11, 2009, the capitalized cost ofour oil and gas properties exceeded the full cost ceiling limitation of theCompany’s oil and gas properties by approximately $34.6 million. Therefore, theCompany recorded an impairment for the three months ended September 30,2009 of $34.6 million. A total impairment of approximately $57.8 million has beenrecorded for the nine months ended September 30, 2009. This impairment ofthe Company’s oil and gas properties resulted from low commodity prices in thefirst three quarters of 2009. No impairment was recorded for the nine monthsended September 30, 2008. A decline in gas prices or an increase inoperating costs subsequent to the measurement date or reductions ineconomically recoverable reserve quantities could result in the recognition ofadditional impairments of the Company’s oil and gas properties in futureperiods.

 

*Per Share Information*

 

Basic earnings (loss) per share is computed by dividing net income(loss) from continuing operations attributable to common stock by the weightedaverage number of shares of common stock outstanding during each period.Diluted earnings per share are computed by adjusting the average number ofshares of common stock outstanding for the dilutive effect, if any, of commonstock equivalents such as stock options and warrants. For the three and ninemonths ended September 30, 2009, 640,000 options were excluded becausethey were anti-dilutive. During the nine months ended September 30, 2008,717,500 options were excluded because they were anti-dilutive.

 

8

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A summary ofthe net income/(loss) per share calculation is shown below (in thousands,except per share amounts):

 
| ** **                                                   | ** ** | **For the Three********Months Ended********September 30,** | ** ** | **For the Nine********Months Ended********September 30,** | ** ** |
|--------------------------------------------------------------|------------|-----------------------------------------------------------------|------------|----------------------------------------------------------------|------------|
| ** **                                                   | ** ** | **2009**                                                        | ** ** | **2008**                                                       | ** ** | **2009** | ** ** | **2008** | ** ** |
| Net income/(loss)                                            |       | $                                                               | (38,962    | )                                                              | $          | 8,939 |   | $ | (65,931 | ) | $ | (583 | ) |
| Common shares outstanding:                                   |       |                                                            |       |                                                           |       |   |   |   |   |
| Historical common shares outstanding at  beginning of period |       | 29,722                                                          |       | 29,000                                                         |       | 29,278 |   | 29,008 |   |
| Weighted average common shares issued                        |       | 62                                                              |       | 147                                                            |       | 169 |   | 46 |   |
| Weighted average common shares  outstanding-basic            |       | 29,784                                                          |       | 29,147                                                         |       | 29,447 |   | 29,054 |   |
| Effect of dilution – stock options                      |       | —                                                          |       | 741                                                            |       | — |   | — |   |
| Weighted average common shares  outstanding-diluted          |       | 29,784                                                          |       | 29,888                                                         |       | 29,447 |   | 29,054 |   |
| Net income/(loss) per share-basic                            |       | $                                                               | (1.31      | )                                                              | $          | 0.31 |   | $ | (2.24 | ) | $ | (0.02 | ) |
| Net income/(loss) per share-diluted                          |       | $                                                               | (1.31      | )                                                              | $          | 0.30 |   | $ | (2.24 | ) | $ | (0.02 | ) |

 

*Income Taxes*

 

The Company usesthe asset and liability method of accounting for income taxes. Deferred taxassets and liabilities are recognized for the expected future tax consequencesof temporary differences between the financial statements and tax basis ofassets and liabilities. If appropriate, deferred tax assets are reduced by avaluation allowance which reflects expectations of the extent to which suchassets will be realized. As of September 30, 2009 and December 31,2008, the Company had recorded a full valuation allowance for its net deferredtax asset.

 

                The Company has a measurementprocess for recording in the financial statements uncertain tax positions takenor expected to be taken in a tax return. The Company recognizes in its financial statements only those taxpositions that are ‘‘more-likely-than-not’’ of being sustained, based on thetechnical merits of the position. For the quarters ending September 30,2009 and 2008, the Company performed a comprehensive review of its material taxpositions in accordance with recognition and measurement standards establishedby Generally Accepted Accounting Principles (“GAAP”). As a result of thisreview, the Company did not identify any material deferred tax assets thatrequired adjustment. As of September 30, 2009 and 2008 the Company had notrecorded any material uncertain tax benefits.

 

The Company’spolicy is to recognize interest and penalties related to uncertain tax benefitsin income tax expense. As of September 30, 2009 and 2008, the Company hadnot recognized any interest or penalties in its statement of operations orstatement of financial position.

 

The Company is subject tothe following material taxing jurisdictions: U.S. federal. The Company also hasmaterial operations in the state of Wyoming; however, Wyoming does not impose acorporate income tax. The tax years that remain open to examination by the U.S.Internal Revenue Service are years 2005 through 2008. Due to the Company’s netoperating loss carry forwards, the Internal Revenue Service may also adjust theamount of loss realizable under examination back to 2003.

 

*New Accounting Pronouncements*

 

In June 2009,the Financial Accounting Standards Board (FASB) issued FASB ASC 105, GenerallyAccepted Accounting Principles, which established the FASB Accounting StandardsCodificationTM (ASC or Codification), officially released on July 1, 2009,as the sole source of authoritative generally accepted accounting principlesused by nongovernmental entities in the preparation of financial statements,except for rules and interpretive releases of the SEC under authority offederal securities laws, which are sources of authoritative accounting guidancefor SEC registrants.  The Codification ismeant to simplify user access to all authoritative accounting guidance byreorganizing US GAAP pronouncements into roughly 90 accounting topics within aconsistent structure. The Codification supersedes all existing non-SECaccounting and reporting standards and was effective for the Company beginning July 1,2009.  The FASB will not issue newstandards in the form of Statements, FASB Staff Positions, or Emerging IssuesTask Force Abstracts; instead, it will issue Accounting Standards Updates. TheFASB will not consider Accounting Standards Updates as authoritative in theirown right; these updates will serve only to update the Codification, providebackground information about the guidance, and provide the bases forconclusions on the change(s) in the Codification.  In the description of Accounting Standards 

 

9

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Updates thatfollows, references in “italics” relate to Codification Topics and Subtopics,and their descriptive titles, as appropriate. All references to US GAAP in these footnotes are to the FASB ASC.

 

In September 2006,the FASB issued accounting guidance related to fair value measurements andrelated disclosures. This new guidance defines fair value, establishes aframework for measuring fair value, and expands disclosures about fair valuemeasurements. The Company adopted this guidance on January 1, 2008, asrequired for its financial assets and financial liabilities. However, the FASBdeferred the effective date of this guidance for one year as it relates to fairvalue measurement requirements for nonfinancial assets and nonfinancialliabilities that are not recognized or disclosed at fair value on a recurringbasis, which include, among others, those nonfinancial long-lived assetsmeasured at fair value for impairment assessment and asset retirementobligations initially measured at fair value. Fair value used in the initialrecognition of asset retirement obligations is determined based on the presentvalue of expected future dismantlement costs incorporating our estimate ofinputs used by industry participants when valuing similar liabilities.Accordingly, the fair value is based on unobservable pricing inputs andtherefore, is considered a level 3 value input in the fair value hierarchy.

 

In December 2007,the FASB issued new guidance related to business combinations, which requiresthe acquiring entity in a business combination to recognize and measure allassets and liabilities assumed in the transaction and any non-controllinginterest in the acquiree at fair value as of the acquisition date. Guidance wasalso established for the measurement of the acquirer shares issued inconsideration for a business combination, the recognition of contingentconsideration, the accounting treatment pre-acquisition gain and losscontingencies, the treatment of acquisition related transaction costs, and therecognition of changes in the acquirer’s income tax valuation allowance anddeferred taxes. This guidance is effective for fiscal years beginning after December 15,2008 and is to be applied prospectively as of the beginning of the fiscal yearin which the statement is applied. Early adoption is not permitted.  The impact of the adoption of thisguidance on the Company’s financial statements will largely be dependenton the size and nature of the business combinations completed after theadoption of this statement.

 

In October 2008,the FASB issued accounting guidance relating to determining the fair value of afinancial asset when the market for that asset is not active.  The Company has considered this guidanceprovided in its determination of estimated fair values as of September 30,2009.

 

In March 2008,the FASB issued new accounting guidance related to disclosures about derivativeinstruments and hedging activities. This guidance amends and expands disclosurerequirements to provide a better understanding of how and why an entity usesderivative instruments, how derivative instruments and related hedged items areaccounted for, and their effect on an entity’s financial position, financialperformance, and cash flows. This guidance is effective for financialstatements issued for fiscal years and interim periods beginning after November 15,2008. The Company adopted this guidance January 1, 2009, which requiresadditional disclosures regarding the Company’s derivative instruments in thisQuarterly Report on Form10-Q and subsequent reports, but did not have an impacton the Company’s financial position or results of operations. See Note 2 “Derivatives”herein for the required disclosures.

 

In April 2009,the FASB issued new accounting guidance related to interim disclosures aboutthe fair values of financial instruments. This guidance requires disclosuresabout the fair value of financial instruments whenever a public company issuesfinancial information for interim reporting periods. This guidance is effectivefor interim reporting periods ending after June 15, 2009. The Companyadopted this guidance upon its issuance, which requires additional disclosuresregarding the fair value of financial instruments in this Quarterly Report onForm10-Q and subsequent reports, but had no material impact on the Company’sconsolidated financial statements.

 

In April 2009,the FASB issued accounting guidance relating to determining fair value when thevolume and level of activity for the asset or liability have significantlydecreased and identifying transactions that are not orderly, which providesadditional guidance for estimating fair value. The Company has considered this guidance provided in its determinationof estimated fair values as of September 30, 2009.

 

In April 2009,the FASB issued new accounting guidance related to the accounting anddisclosures of subsequent events. This guidance incorporates the subsequentevents guidance contained in the auditing standards literature intoauthoritative accounting literature. It also requires entities to disclose thedate through which they have evaluated subsequent events and whether the datecorresponds with the release of their financial statements. This guidance iseffective for all interim and annual periods ending after June 15, 2009.The Company adopted this guidance upon its issuance and it had no materialimpact on the Company’s consolidated financial statements. The Companyevaluates subsequent events up to immediately prior to the issuance of itsfinancial statements, and for purposes of the accompanying consolidatedfinancial statements, the Company has evaluated events subsequent to September 30,2009 through November 23, 2009, which is the issuance date of this report.

 

On December 31,2008, the Securities and Exchange Commission (‘‘SEC’’) published the final rules andinterpretations updating its oil and gas reporting requirements. Many of therevisions are updates to definitions in the existing oil and gas rules tomake them consistent with the petroleum resource management system, which is awidely accepted standard for the management of 

 

10

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petroleumresources that was developed by several industry organizations. Key revisionsinclude changes to the pricing used to estimate reserves, the ability toinclude nontraditional resources in reserves, the use of new technology fordetermining reserves, and permitting disclosure of probable and possiblereserves. The SEC will require companies to comply with the amended disclosurerequirements for registration statements filed after January 1, 2010 andfor annual reports for fiscal years ending on or after December 15, 2009.Early adoption is not permitted. The Company is currently assessing the impactthat the adoption will have on the Company’s disclosures, operating results,financial position, and cash flows.

 

In September 2009,the FASB issued its proposed updates to oil and gas accounting rules toalign the oil and gas reserve estimation and disclosure requirements ofExtractive Industries—Oil and Gas (Topic 932) with the requirements in the SEC’sfinal rule discussed above. The public comment period for the FASB’s proposedupdates ended October 15, 2009; however, no final guidance has been issuedby the FASB. The Company is evaluating the potential impact of any updates tothe oil and gas accounting rules and will comply with any new accountingand disclosure requirements once they become effective. The Company anticipatesthat the following rule changes could have a significant impact on itsresults of operations as follows:

 

·                  Theprice used in calculating reserves will change from a single-day closing pricemeasured on the last day of the company’s fiscal year to a 12-month averageprice, and will affect the Company’s depletion and ceiling test calculations.

·                  Severalreserve definitions have changed that could revise the types of reserves thatwill be included in the Company’s year-end reserve report.

 

Many of the Company’s financial reporting disclosures could change as aresult of the new rules.

 

**Note 3 — Asset Retirement Obligations**

 

The Company follows the FASB guidance related to asset retirementobligations. The guidance generally applies to legal obligations associatedwith the retirement of long-lived assets that result from the acquisition,construction, development and/or normal operations of a long-lived asset. Theguidance requires the Company to recognize an estimated liability for costsassociated with the abandonment of its oil and gas properties.

 

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

 

The estimated liability is based on historical gasindustry experience in abandoning wells, including estimated economic lives,external estimates as to the cost to abandon the wells in the future andfederal and state regulatory requirements. The Company’s liability isdiscounted using the Company’s best estimate of its credit-adjusted risk-freerate. The credit adjusted risk free rate is based on the Company’s borrowingunder its credit facility or, if borrowings are not available under the creditfacility because of borrowing base or covenant limitations, the rate is basedon the interest rate available from its banks for senior secured debt ormezzanine debt. Based on the Company’s current inability to borrow under itscredit facility, the Company’s credit adjusted risk free rate at September 30,2009 and December 31, 2008 was the prime rate plus 7%. Revisions to theliability could occur due to changes in estimated abandonment costs, changes inwell economic lives or if federal or state regulators enact new requirementsregarding the abandonment of wells. For the quarter and nine months ended September 30,2009, no wells were drilled, completed or acquired.

 

The following is a summary of the Company’s asset retirement obligationactivity for the three and nine months ended September 30, 2009 and 2008(in thousands).

 
| ** **                                      | ** ** | **For the Three********Months Ended********September 30,** | ** ** | **For the Nine********Months Ended********September 30,** | ** ** | **For the Three********Months Ended********September 30,** | ** ** | **For the nine********Months Ended********September 30,** | ** ** |
|-------------------------------------------------|------------|-----------------------------------------------------------------|------------|----------------------------------------------------------------|------------|-----------------------------------------------------------------|------------|----------------------------------------------------------------|------------|
| ** **                                      | ** ** | **2009**                                                        | ** ** | **2008**                                                       | ** ** |
| Beginning balance asset retirement  obligations |       | $                                                               | 3,457      |                                                           | $          | 3,366                                                           |       | $                                                              | 3,154      |   | $ | 2,767 |   |
| Additional obligation added during the  period  |       | —                                                          |       | —                                                         |       | 142                                                             |       | 410                                                            |       |
| Obligations settled during the period           |       | (106                                                            | )          | (129                                                           | )          | (48                                                             | )          | (48                                                            | )          |
| Accretion expense                               |       | 58                                                              |       | 172                                                            |       | 66                                                              |       | 185                                                            |       |
| Ending balance of asset retirement  obligations |       | $                                                               | 3,409      |                                                           | $          | 3,409                                                           |       | $                                                              | 3,314      |   | $ | 3,314 |   |

 

**Note 4 —****RestrictedAssets (Certificates of Deposit), Surety Bonds and Deposits**

 

*Certificates of deposit.*

 

11

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The Company holds a certificate of deposit (“CD”), which expires in July 2010,totaling $160,000. The CD is collateral for bonding required by the State ofWyoming, the State of Montana and the Federal Bureau of Land Management.Because the Company intends to renew the CD in order to maintain its bondingrequirements, the Company has included the CD in other non-current assets as ofSeptember 30, 2009. The issuer of the bonds has commenced litigationagainst the Company to increase their collateral position. See the litigationdiscussion in Note 9. Additionally, the Company holds two CDs for $604,000 and$964,000 which were issued in February 2006 and expire in February 2010and May 2010, 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 30,2009 because the Company also intends to renew the CDs in order to maintainpower supply on a long-term basis. In April 2007, the Company issued a$1,000,000 letter of credit (“LOC”), which is collateralized by a CD, thatexpires in April 2010 in favor of Bitter Creek Pipelines, LLC to securethe construction of a high pressure pipeline and related compression facilitiesto the Company’s Deer Creek and Kirby areas. Bitter Creek Pipelines, LLC hasdrawn approximately $700,000 on this LOC for compression services provided tothe Company in the third quarter of 2009. The remaining balance of this LOC is $300,000 and the Company hasincluded this amount in current assets as of September 30, 2009.

 

*SuretyBonds.*

 

From June 2009 through September 2009, the Company postedadditional idle well surety for approximately $51,000 to the Wyoming Oil &Gas Conservation Commission. A September payment of $12,777 was the fourthmonthly installment of 18 that the Commission has requested for surety on wellsthat will need to be plugged by Pinnacle. The surety amount may be adjusteddownward by the Commission if the Company aggressively and successfully plugsthe proposed wells in question. In addition, a $50,000 accrual was made as of September 30,2009, pertaining to bonding requirements in the Kirby Montana area. These amountsare included in restricted certificates of deposits in the accompanying balancesheet at September 30, 2009.

 

*Deposits.*

 

The Company hasincluded approximately $75,000 related to royalty payments in deposits. Theseamounts are included in Deposits in the accompanying balance sheet at September 30,2009.

 

**Note 5 — Derivatives**

 

The Company has elected not to designate its derivatives as cash flowhedges under authoritive guidance prescribed by FASB. These derivativeinstruments are marked to market at the end of each reporting period andchanges in the fair value are recorded in the accompanying statements ofoperations. The aggregate fair values of these contracts were estimated to beliabilities totaling $862,000 and assets of $4,042,000 at September 30, 2009and 2008, respectively. The Company realized hedging gains of $2,038,000 and$725,000 for the quarters ended September 30, 2009 and 2008, respectively.As a result of the change in the fair value of the commodity derivatives, theCompany had an unrealized loss of $3,074,000 and an unrealized gain of$9,951,000 for the three months ended September 30, 2009. For the ninemonths ended September 30, 2009, the Company realized a hedging gain of$5,548,000, compared to a hedging loss of $45,000 for the nine months ended September 30,2008. The Company had an unrealized loss of $5,207,000 and an unrealized gainof $3,486,000 for the nine months ended September 30, 2009 and 2008,respectively. The Company classifies realized gains and losses as revenue andunrealized gains and losses as other income/(expenses) in the accompanyingstatements of operations. Because the Company’s derivative contracts were notaccounted for as cash flow hedges, the Company classifies the realized gainsand losses in the investment activities in the accompanying statement of cashflows.

 

As of September 30, 2009 and 2008, the Company had natural gashedges in place as follows:

 
| **Product and Type of Hedging Contract** | ** ** | **MMbtu Per********Day** | ** ** | **Fixed Price********Range********CIG Index Price** | ** ** | **Time********Period** | ** ** |
|------------------------------------------|------------|--------------------------|------------|-----------------------------------------------------|------------|------------------------|------------|
| September 30, 2009 (unaudited)      |       |                     |       |                                                |       |                   |       |
| Natural Gas—Collar                  |       | 2,000                    |       | $6.50-$7.50                                         |       | 01/09-12/09            |       |
| Natural Gas—Swap                    |       | 2,500                    |       | $7.17                                               |       | 01/09-12/09            |       |
| Natural Gas—Swap                    |       | 1,000                    |       | $4.00                                               |       | 06/09-12/09            |       |
| Natural Gas—Swap                    |       | 2,500                    |       | $3.45                                               |       | 05/09-04/10            |       |
| Natural Gas—Swap                    |       | 2,000                    |       | $4.48                                               |       | 01/10-12/10            |       |
| Natural Gas—Swap                    |       | 2,500                    |       | $5.40                                               |       | 05/10-12/10            |       |
| Natural Gas—Swap                    |       | 1,000                    |       | $5.50                                               |       | 01/10-12/10            |       |
| 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            |       |

 

12

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| ** **                    | ** ** | **Location  on  Consolidated Balance  Sheets** | ** ** | **Fair  Value at  September 30, 2009** | ** ** |
|-------------------------------|------------|------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                    | ** ** | ** **                                     | ** ** | **(In thousands)**                          | ** ** |
| Derivative liabilities:       |       |                                           |       |                                        |       |
| Natural gas, commodity        |       | Current liabilities                            |       | $                                           |  291  |   |
| Natural gas, commodity        |       | Noncurrent liabilities                         |       | $                                           |  571  |   |
| Total derivative  liabilities |       |                                           |       | $                                           |  862  |   |

 

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

 

**Note 6 — Stock Based Compensation**

 

*Options under Stock Incentive Plan*

 

The Company has adopted a stock incentive planauthorizing the grant of both incentive and non-statutory stock options. Alloptions allow for the purchase of common stock at prices not less than the fairmarket value of such stock at the date of grant. If the option holder owns morethan 10% of the total combined voting power of all classes of the Company’sstock, the exercise price cannot be less than 110% of the fair market value ofsuch 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 30,2009, there were options to purchase 640,000 shares granted under the plan.

 

The options granted since formation in September 2003 vest ingeneral as follows:

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

 

At September 30, 2009, the Company had unvested options topurchase 12,500 shares with a weighted average grant date fair value of$55,000. During the three and nine months ended September 30, 2009, theCompany did not grant any options to purchase common stock. The Company willrecognize compensation expense relating to nonvested options granted after January 1,2006 ratably over the next two years. During the three and nine months ended September 30,2009 the Company recognized an expense of approximately $36,000 and $253,000,respectively, based on the fair value of the vested options.

 

The followingtable summarizes stock option activity for the nine months ended September 30,2009:

 
| ** **                                        | ** ** | **Number of********Shares** | ** ** | **Weighted Average********Exercise Price********Per Share** | ** ** | **Weighted********Average********Remaining********Contractual Life** | ** ** | **Aggregate********Intrinsic value** | ** ** |
|---------------------------------------------------|------------|-----------------------------|------------|-------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|--------------------------------------|------------|
| Outstanding, December 31, 2008               |       | 676,250                     |       | $                                                           | 5.93       |                                                                 |       |                                 |       |   |
| Canceled or forfeited                             |       | (36,250                     | )          | 8.01                                                        |       |                                                                 |       |                                 |       |
| Outstanding, September 30, 2009 (unaudited)  |       | 640,000                     |       | $                                                           | 5.81       |                                                                 | 2.58       |                                 | $          | — |   |
| Exercisable, September 30, 2009  (unaudited) |       | 627,500                     |       | $                                                           | 5.76       |                                                                 | 2.54       |                                 | $          | — |   |

 

The following table summarizes information about stock optionsoutstanding at September 30, 2009:

 

13

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| ** **          | ** ** | **Options Outstanding**                        | ** ** | **Options Exercisable**                                              | ** ** | ** **                    | ** ** |
|---------------------|------------|------------------------------------------------|------------|----------------------------------------------------------------------|------------|-------------------------------|------------|
| **Exercise Prices** | ** ** | **Number of********shares********Outstanding** | ** ** | **Weighted********Average********Remaining********Contractual Life** | ** ** | **Number********Exercisable** | ** ** | **Weighted********Average********Exercise Price** | ** ** | **Fair Value********Determination** | ** ** |
| $                   | 4.00       |                                           | 137,500    |                                                                 | 1.0 years  |                          | 137,500    |   | $ | 4.00 |   | Black–Scholes (minimum value) |   |
| $                   | 4.80       |                                           | 265,000    |                                                                 | 2.5 years  |                          | 265,000    |   | $ | 4.80 |   | Black–Scholes (minimum value) |   |
| $                   | 5.20       |                                           | 112,500    |                                                                 | 3.3 years  |                          | 112,500    |   | $ | 5.20 |   | Black–Scholes |   |
| $                   | 8.40       |                                           | 25,000     |                                                                 | 4.7 years  |                          | 12,500     |   | $ | 8.40 |   | Black–Scholes |   |
| $                   | 11.00      |                                           | 100,000    |                                                                 | 3.7 years  |                          | 100,000    |   | $ | 11.00 |   | Black–Scholes |   |
| Total               |       | 640,000                                        |       |                                                                 |       | 627,500                       |       |   |   |   |   |

 

*Stock Appreciation Rights under Stock Incentive Plan*

 

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

 

The SARs granted in June 2009 vest in general as follows:

 
| Year 1 |   | 33.33  | % |
|--------|--------|--------|---|
| Year 2 |   | 33.33  | % |
| Year 3 |   | 33.34  | % |
|   |   | 100.00 | % |

 

As of September 30, 2009, the Company had approximately $68,000 ofunrecognized compensation expense related to non-vested SAR awards.

 

The following table summarizes stock appreciation activity for the ninemonths ended September 30, 2009:

 
| ** **                                          | ** ** | **Shares** | ** ** | **Weighted-********Average********Grant-Date********Fair Value** | ** ** | **Weighted  Average  Remaining  Contractual  Life** | ** ** |
|-----------------------------------------------------|------------|------------|------------|------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| Outstanding at December 31, 2008               |       | —     |       | —                                                           |       |                                                |       |
| Granted on June 1, 2009                        |       | 202,280    |       | $                                                                | 0.41       |                                                |       |   |
| Canceled or forfeited                               |       | —     |       | —                                                           |       | —                                              |       |
| Outstanding at September 30, 2009  (unaudited) |       | 202,280    |       | $                                                                | 0.41       |                                                | 6.67       |   |

 

During the three and nine months ended September 30, 2009, theCompany recognized compensation expense of approximately $6,000, and $8,000respectively, based on the fair value of the vested shares using aBlack-Scholes model.

 

*Restricted Stock under the Stock Incentive Plan*

 

The Company hasa stock incentive plan whereby grants of restricted stock have been awarded tomembers of the Board of Directors and certain executives and employees.Restrictions and vesting periods for the awards are determined at thediscretion of the Board of Directors and are set forth in the award agreements.During the three and nine months ended September 30, 2009, the Companyrecognized compensation expense of approximately $132,000 and $422,000,respectively, based on the fair value of the vested shares.

 

A summary of the status and activity of the restricted stock for thenine months ended September 30, 2009 is presented below:

 
| ** **                                         | ** ** | **Shares** | ** ** | **Weighted-********Average********Grant-Date********Fair Value** | ** ** |
|----------------------------------------------------|------------|------------|------------|------------------------------------------------------------------|------------|
| Non-vested at December 31, 2008               |       | 203,577    |       | $                                                                | 4.78       |   |
| Granted                                            |       | 723,688    |       | $                                                                | .38        |   |
| Forfeited                                          |       | (5,564     | )          | $                                                                | 6.05       |   |
| Vested                                             |       | (578,708   | )          | $                                                                | .82        |   |
| Non-vested at September 30, 2009  (unaudited) |       | 342,993    |       | $                                                                | 2.18       |   |

 

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As of September 30, 2009, the Company had approximately $0.6million of unrecognized share-based compensation expense related to non-vestedstock awards, which is expected to be amortized over the remaining vestingperiods of three to five years.

 

**Note 7 — Long-Term Debt**

 

*Credit Facility*

 

Effective February 12, 2007, the Company entered into a creditfacility which permits borrowings up to the borrowing base as designated by theadministrative agent. As of September 30, 2009 and December 31, 2008,the Company had $6.5 million and $11.5 million, respectively, of debtoutstanding under the facility. As described below, the Company is currentlyunable to borrow additional amounts under the credit facility due to covenantand borrowing base limitations and may be further limited in the future basedon borrowing base limitations.

 

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

 

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

 

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

 

The obligations under the credit facility are secured by liens on (i) noless than 90% of the net present value of the oil and gas to be produced fromthe Company’s oil and gas properties that are included in the borrowing basedetermination, calculated using a discount rate of 10% per annum and reserveestimates, prices and production rates, and costs, (ii) options to lease,seismic options, permits, and records related to such properties, and (iii) seismicdata.

 

Borrowings under the Company’s credit facility, as amended, bearinterest either: (i) at the greater of the one month London InterbankOffered Rate, or LIBOR, plus 1.00% or a domestic bank rate, plus in either casean applicable margin of 0.75% to 1.75% based on utilization, or (ii) on asliding scale from the one, two, three, or six month LIBOR, plus an applicablemargin 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 the borrowing base determination.  In addition, the credit facility provided foran up front fee of $27,000, which was paid on the closing date of the creditfacility, and an additional arrangement fee of 1% based on utilization.  Borrowings under this credit facility may beprepaid without premium or penalty, except on Eurodollar advances.

 

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

 

·**               **incurliens;

 

·**               **incurdebt;

 

·**               **makeinvestments in other persons;

 

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

 

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

 

·**               **enterinto certain hedging arrangements;

 

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·**               **amendmaterial contracts; and

 

·**               **enterinto related party transactions.

 

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

 

The credit agreement, as amended, also requires that the Companysatisfy certain affirmative covenants, meet certain financial tests, maintaincertain financial ratios and make certain customary indemnifications to lendersand the administrative agent. The financial covenants include requirements tomaintain: (i) a ratio of EBITDA to cash interest expense of not less than3.00 to 1.00, (ii) a ratio of current assets to current liabilities of notless than 1.00 to 1.00, (iii) a total debt to annualized EBITDA ratio ofnot more than 3.0 to 1.0, (iv) a quarterly total senior debt to annualizedEBITDA ratio equal to or less than 3.0 to 1.0, and (v) a total provedPV-10 value to total debt ratio of at least 1.50 to 1.00.

 

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

 

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

 

On April 14, 2009, the Company and the administrative agententered into the fourth amendment to the credit agreement which reduced theborrowing base as described above and waived compliance with the current ratiofinancial covenant as of December 31, 2008 and March 31, 2009 andwith the restrictive covenants related to accounts payable, permitted liens andpermitted debt until the next borrowing base redetermination, subject tocertain financial caps.  On August 19,2009, the lenders waived compliance with the current ratio financial covenantunder the Credit Agreement for the period ending August 26, 2009 and thequarter ending June 30, 2009.

 

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

 

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

 
| December 1, 2009 through  December 31, 2009 |   | $ | 6,300,000 |   |
|-------------------------------------------------------|--------|---|-----------|--------|
| January 1, 2010 through  January 31, 2010   |   | $ | 6,100,000 |   |
| February 1, 2010 through  February 28, 2010 |   | $ | 5,900,000 |   |
| March 1, 2010 through March 31,  2010       |   | $ | 5,700,000 |   |
| April 1, 2010 through April 30,  2010       |   | $ | 5,500,000 |   |

 

Each Calendar month thereafter commencing May 1, 2010; theBorrowing Base for the preceding calendar month will be reduced by $200,000.

 

On October 26, 2009, the lenders provided a waiver effectivelyextending the terms of the fifth amendment to the Credit Agreement through November 16,2009.  On November 16, 2009, thelenders provided an additional waiver effectively extending the terms of thefifth amendment to the Credit Agreement through November 23, 2009.

 

On November 23,2009, the lenders provided an additional waiver extending the terms of thefifth amendment to the Credit Agreement through December 1, 2009 and for thequarter ended September 30, 2009.

 

The Companybelieves that it may not be in compliance with the current ratio financialcovenant and certain other covenants throughout 2009, but managementanticipates receiving waivers in the future based on prior dealings with thelender and continued compliance with the borrowing base limitations. There canbe no assurance that the Company will be able to obtain such waivers or

 

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that such waivers will beobtained on acceptable terms. If the Company is unable to obtain future waiversand/or comply with the restrictive covenants and are therefore in default, thelenders could avail themselves of the remedies under the credit agreement,including acceleration and foreclosure.

 

*Office Building Loan*

 

On November 15, 2005, the Company entered intoa mortgage loan secured by its office building in Sheridan, Wyoming in theaggregate principal amount of $829,000. The promissory note provides formonthly payments of principal and interest in the initial amount of $6,400, andunpaid principal that bore interest at 6.875% during the first three years,currently bears interest at a variable base rate plus 0.5% and will bearinterest at 18% upon a default. The variable base rate is based on the lender’sbase rate. The maturity date of this mortgage is November 15, 2015, atwhich time a principal and interest payment of $531,300 will become due. As of September 30,2009, the Company had $741,000 outstanding in principal and interest on thismortgage.  On November 15, 2008, theinterest rate on the Company’s mortgage loan changed from a fixed rate of6.875% to a variable rate. As of September 30, 2009, the variable rate was4.75%.

 

**Note 8 — Fair Value Measurements**

 

Effective January 1, 2008, the Company adopted FASB’s guidancerelated to fair value measurements for all financial assets and liabilitiesmeasured at fair value on a recurring basis. This criteria establishes aframework for measuring fair value and requires enhanced disclosures about fairvalue measurements. The guidance 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 criteria establishes a hierarchy for groupingthese assets and liabilities, based on the significance level of the followinginputs:

 

·**               **Level1 — Quoted prices in active markets for identical assets or liabilities;

 

·**               **Level2 —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 a listing of the Company’s assets and liabilitiesrequired to be measured at fair value on a recurring basis and where they areclassified within the hierarchy as of September 30, 2009 (in thousands):

 
| ** **                         | ** ** | **Level 1** | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** ** |
|------------------------------------|------------|-------------|------------|-------------|------------|-------------|------------|-----------|------------|
| Liabilities                        |       |        |       |        |       |        |       |      |       |
| Oil and gas derivative instruments |       | $           | —     |        | $          | 862         |       | $         | —     |   | $ | 862 |   |
| Total                              |       | $           | —     |        | $          | 862         |       | $         | —     |   | $ | 862 |   |

 

A financial asset or liability is categorized within the hierarchybased upon the lowest level of input that is significant to the fair valuemeasurement. The Company’s valuation methodologies for oil and gas derivativeinstruments, which are measured at fair value and are included in theaccompanying balance sheet, are listed below.

 

The Company uses Level 2 inputs to measure the fair value of oil andgas derivative instruments. The fair value is based on interpolated data. TheCompany uses an industry standard model that considers various inputsincluding; (a) quoted forward prices for the specific commodity and areawhich was hedged, (b) volatility factors with consistent time data thatcorrelates to the remaining life of the derivative instruments and (c) timevalue. The Company believes that this approach provides a reasonable,non-biased and consistent methodology for valuing oil and gas derivativeinstruments. In addition, the Company also evaluates company credit risk andcounterparty credit risk to determine fair value of the asset or liability andfurther action as needed.

 

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**Note 9 — Commitments and Contingencies**

 

*Operating Lease*

 

Upon purchase ofits building in August 2005, the Company was assigned the lease agreementsfor existing tenants in the building. The leases expire from January 2010to December 2013. Future minimum lease income under noncancelableoperating leases is as follows:

 
| **Year Ending December 31:** | ** ** | ** ** | ** ** |
|-----------------------------------|------------|------------|------------|
| 2009                              |       | $          | 25,000     |   |
| 2010                              |       | 63,000     |       |
| 2011                              |       | 60,000     |       |
| 2012                              |       | 60,000     |       |
| 2013                              |       | 60,000     |       |
| Total minimum lease payments      |       | $          | 268,000    |   |

 

*GasGathering Contracts*

 

The Company has entered into gas gathering and compression agreementswith service providers in order to compress and transport its gas to the pointof sale. Compression agreements and gathering agreements are based on a fee perMcf either compressed or gathered. The Company accounts for these fees as amarketing and transportation expense. The Company does not pay or chargemarketing fees associated with the movement and sale of natural gas.

 

*EmploymentAgreements*

 

The Company entered into new employment agreements with the ChiefExecutive Officer (Mr. Schoonmaker) and Chief Financial Officer (Mr. Barnes)on July 20, 2007, effective January 1, 2007. The initial term ofthese agreements is one year and the agreements will automatically renew foradditional one-year terms unless either party gives 60 days prior writtennotice. Under Mr. Schoonmaker’s employment agreement, he is entitled to aninitial base salary of $250,000, subject to annual adjustment, and an annualbonus of up to 1.0 times his then current base salary, payable in cash or instock. Under Mr. Barnes’ employment agreement, he is entitled to aninitial base salary of $200,000, subject to annual adjustment, and an annualbonus of up to 0.75 times his then current base salary, payable in cash or instock.

 

If either executive’s employment is terminated bythe Company without cause or by either executive for good reason, the executivewill be entitled to severance benefits which will include a lump sum paymentequal to the sum of (i) 1.0 times his annual base salary plus (ii) 18.0times the monthly health savings account contribution last made by us for hisbenefit, and the payment of a pro-rated bonus. Additionally, if eitherexecutive’s employment is terminated by us without cause or by either executivefor good reason or due to retirement, in each case within one year following achange of control of us, the executive will be entitled to severance benefitswhich will include a lump sum payment equal to 1.5 times his annual base salaryand the payment of a pro-rated bonus. In each case, any and all stock options,restricted stock awards and other equity compensation awards held by theexecutive will immediately vest and become exercisable. In the event thateither executive’s employment is terminated within six months preceding orfollowing a change of control due to a non-renewal of his employment agreementby us, the executive will be entitled to the same change of control severancebenefit described above.

 

*Litigation*

 

From time to time, the Company is subject to legalproceedings and claims that arise in the ordinary course of its business. Inaddition, like other natural gas and oil producers and marketers, the Company’soperations are subject to extensive and rapidly changing federal and stateenvironmental, health and safety and other laws and regulations governing airemissions, wastewater discharges, and solid and hazardous waste managementactivities. As a result, it is extremely difficult to reasonably quantifyfuture environmental and regulatory related expenditures.

 

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

 

The Company, together with the State of Montana, theMontana Department of Environmental Quality, the Montana Board of Oil and GasConservation and the Department of Natural Resources, were named as defendantsin a lawsuit (Civil Cause No. DV-05-27) filed on May 19, 2005 in theMontana 22nd Judicial District Court, Bighorn County by Diamond CrossProperties, LLC 

 

18

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relating to the Coal Creek POD. The plaintiff is a surface owner withproperties located in Big Horn County and Rosebud County, Montana where theCompany has a lease for approximately 10,300 acres, serves as operator and ownsa working interest in the minerals under lease. The plaintiff sought 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 sought topreliminarily and permanently enjoin the Company on the basis that the Company’soperations lacked adequate safeguards required under the Montana stateconstitution. On August 25, 2005, the district judge 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 districtcourt for a decision on the merits.

 

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

 

On July 14, 2008, the district court issued asummary judgment order in the combined case, and the order was subsequentlyentered as a judgment on August 15, 2008. As a result, the Company hascontinued its operations in the two project areas. To date, there has been noappeal by the plaintiff.

 

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

 

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

 

The Company was named as a defendant inlitigation brought by RLI Insurance Company (Civil Cause No. 09-CV-157-J)filed in United States District Court for the District of Wyoming on July 6,2009. The complaint alleges that the Company failed to provide $1,439,360 inadditional collateral requested by plaintiff to secure certain bonds issued byplaintiff on behalf of the Company. Plaintiff seeks the additional bondcollateral plus attorney’s fees and costs.  The Company has asserted acounterclaim against RLI Insurance Company for breach of the covenant of goodfaith and fair dealing. Trial is set for April 26-29, 2010. The Companyintends to vigorously defend against RLI Insurance Company’s claim andvigorously pursue its counterclaim.

 

*Regulations*

 

The Company’s oil and gas operations are subject to various federal,state and local laws and regulations. The Company could incur significantexpense to comply with the new or existing laws and non-compliance could have amaterial adverse effect on the Company’s operations. In December 2007, theU.S. Bureau of Land Management imposed a permitting application fee of $4,000per well drilled on federal lands.

 

*Environmental*

 

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

 

**Note 10 — Recent Developments**

 

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

 
| December 1, 2009 through  December 31, 2009 |   | $ | 6,300,000 |   |
|-------------------------------------------------------|--------|---|-----------|--------|
| January 1, 2010 through  January 31, 2010   |   | $ | 6,100,000 |   |
| February 1, 2010 through  February 28, 2010 |   | $ | 5,900,000 |   |
| March 1, 2010 through March 31,  2010       |   | $ | 5,700,000 |   |
| April 1, 2010 through April 30,  2010       |   | $ | 5,500,000 |   |

 

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

 

On October 26, 2009, the lenders provided a waiver effectivelyextending the terms of the fifth amendment to the Credit Agreement through November 16,2009.  On November 16, 2009, thelenders provided an additional waiver effectively extending the terms of thefifth amendment to the Credit Agreement through November 23, 2009.

 

On November 23,2009, the lenders provided an additional waiver extending the terms of thefifth amendment to the Credit Agreement through December 1, 2009 and for thequarter ended September 30, 2009.

 

********

 

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

 

*The discussion and analysis that follows should beread together with the**accompanying financial statements and notes related thereto that areincluded**elsewhere in thisquarterly report on Form 10-Q. It includes forward looking**statements that may reflect our estimates, beliefs,plans and expected**performance.The forward looking statements are based upon events, risks and**uncertainties that may be outside our control. Ouractual results could differ**significantlyfrom those discussed in these forward looking statements. Factors**that could cause or contribute to these differencesinclude, but are not**limited to,market prices for natural gas and oil, regulatory changes,**estimates of proved reserves, economic conditions,competitive conditions,**developmentsuccess rates, capital expenditures and other uncertainties, as**well as those factors discussed below and elsewherein this quarterly report on**Form 10-Qand in our annual report on Form 10-K for the year ended December 31,**2008, including in “Risk Factors” and “CautionaryStatement Concerning Forward**LookingStatements,” all of which are difficult to predict. As a result of**these assumptions, risks and uncertainties, theforward looking matters**discussedmay not occur.*

 

**Overview**

 

We are anindependent energy company engaged in the acquisition, exploration anddevelopment of domestic onshore natural gas reserves. We primarily focus ourefforts on the development of coalbed methane (“CBM”) properties located in thePowder River Basin in northeastern Wyoming and southern Montana. In addition,in April 2006, we acquired properties located in the Green River Basin insouthern Wyoming. As of September 30, 2009, we owned natural gas and oilleasehold interests in approximately 462,000 gross (319,000 net) acres,approximately 90% of which were undeveloped. As of September 30, 2009, wehad estimated net proved reserves of approximately 13.0 Bcf based on the CIGindex price of $3.09 per Mcf. For the first three quarters of 2009 and theremainder of 2009, we have operated and expect to continue to operate with areduced capital expenditure plan. Under our reduced capital expenditure plan, wewill generally make only such expenditures as are necessary to secure drillingpermits in strategic areas, drill wells that secure leasehold positions andconstruct the necessary infrastructure to complete and hook-up wells that havealready been drilled. We had total capital expenditures of $3.0 million for thenine months ended September 30, 2009. Our capital expenditure budget for 2009 and 2010 will be dependent uponCIG index prices, our cash flows and the availability of additional capitalresources.

 

We were formedas a Delaware corporation in September 2003 through a contribution ofproved producing properties and undeveloped leaseholds by subsidiaries ofCarrizo Oil & Gas, Inc. and U.S. Energy Corporation and a cashcontribution from funds affiliated with DLJ Merchant Banking.

 

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

 

Effective February 12,2007, we entered into a credit facility which permits borrowings up to theborrowing base as designated by the administrative agent. As of September 30,2009 and December 31, 2008, we had $6.5 million and $11.5 million,respectively, of debt outstanding under the facility.

 

**Economic and Natural GasPricing Environment**

 

During 2008, theglobal economy experienced a significant downturn. The downturn, which beganover concerns related to the U.S. financial markets, spread to otherindustries, including the energy industry. The initial effects of the downturnrestricted the capital and credit markets to a degree that has not been seen ina number of decades in the United States. We have been able to 

 

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partially mitigate theconstraints imposed by the current economic climate through utilization of ourcredit facility and cash flows from operations.

 

The fear ofglobal recession led to an immediate drop in demand for natural gas, primarilyby industrial users, which in turn led to a significant reduction in naturalgas prices. The natural gas index price in the Rocky Mountain region averaged$7.84 per Mcf for the first eight months of 2008 but only $3.15 per Mcf for thelast four months of 2008. For the first nine months of 2009, the price averaged$2.77 per Mcf. This decrease in price has caused us to reevaluate our 2009business plan. We have curtailed drilling, except for wells that will holdsignificant blocks of acreage, and have also reduced administrative, operatingand transportation costs. Even with cost reductions and a flexible capitalspending budget, the current natural gas pricing and economic environmentremains challenging. We are exploring strategic alternatives to increase ourcapital resources.

 

**Credit Facility andLiquidity**

 

As of September 30, 2009, we were not in compliance with thecurrent ratio financial covenant and certain other covenants related toaccounts payable, permitted liens, and permitted debt under our creditfacility.  On April 14, 2009, thelenders waived compliance with the current ratio as of March 31, 2009, andwith such other restrictive covenants, subject to certain financial caps, untilthe next borrowing base redetermination on October 20, 2009.  On August 19, 2009, the lenders waivedcompliance with the current ratio financial covenant under the Credit Agreementfor the period ending August 26, 2009 and the quarter ending June 30,2009.  On August 26, 2009, weobtained a fifth amendment to the Credit Agreement which provides for anadditional 60-day waiver of the current ratio financial covenant and certainother restrictive covenants through October 26, 2009.  On October 20, 2009 we obtained a sixthamendment to the Credit Agreement whereby our borrowing base became subject tomonthly reductions of $200,000 until maturity or until a new redetermination isreceived. On October 26, 2009, the lenders provided a waiver effectivelyextending the terms of the fifth amendment to the Credit Agreement through November 16,2009.  On November 16, 2009, thelenders provided an additional waiver effectively extending the terms of thefifth amendment to the Credit Agreement through November 23, 2009. OnNovember 23, 2009, the lenders provided an additional waiver extending theterms of the fifth amendment to the Credit Agreement through December 1, 2009and for the quarter ended September 30, 2009.

 

We have not beenin compliance with certain financial covenants for the last five quarters buthave obtained waivers and/or amendments in each instance.  As a result of such non-compliance, we arecurrently unable to borrow additional funds under our credit agreement.  We believe that we may not be in compliancewith certain financial and other covenants throughout the remainder of 2009,but will seek additional waivers.  Therecan be no assurance that we will be able to obtain such waivers or that suchwaivers will be obtained on acceptable terms. If we are unable to obtain future waivers and/or to comply with thecovenants, the lenders could accelerate our indebtedness or foreclose onproperties held by liens. Please see “—Liquidity and Capital Resources—CreditFacility” for further information regarding our credit facility, borrowing baseand the covenant limitations.

 

Inaccordance with accounting guidance, we have classified all of the outstandingdebt under the credit facility totalling $6.5 million as of September 30,2009 as a current payable because it is unlikely that we will have cured thenoncompliance of certain restrictive covenants during 2009.

 

Due to the current economic and pricing environment and our liquidityposition, we are actively marketing certain assets to raise additional capitaland are also reviewing alternatives for raising additional capital throughequity and debt financing, capital restructuring and possible mergers. We soldour high pressure gas gathering system in the Cabin Creek project area in Wyomingand our remaining interest in the Arvada project area in Wyoming in April 2009.We received approximately $3.2 million in net proceeds from these sales, andused part of such proceeds to repay a portion of the indebtedness outstandingunder our credit facility and for general operating purposes. We have alsoexecuted additional hedges of its gas to secure certain operating cash flowlevels during the remainder of 2009. From January through April 2009,we had 4,500 MMbtu per day hedged through a combination of a fixed price swapand a costless collar at a weighted average floor price of $6.87 per MMbtu anda ceiling price of $7.32 per MMbtu.  InMay, we had 7,000 Mmbtu per day hedged through a combination of fixed priceswaps and a costless collar at a weighted average floor price of $5.65 perMmbtu and a ceiling price of $5.94 per Mmbtu. From June through December 2009,we have 8,000 MMbtu per day hedged through a combination of a fixed price swapsand a costless collar at a weighted average floor price of $5.44 per MMbtu anda ceiling price of $5.69 per MMbtu. The hedges were executed based on theColorado Interstate Gas price.

 

We have also implemented various cost cutting measures, includingreducing general and administrative costs through staff reductions, wage andbenefit cuts and a hiring freeze. We have reduced lease operating expenses byrenegotiating water disposal contracts, reducing service costs and temporarilyshutting-in marginal wells. We continue to communicate with key vendors tomanage our obligations and payables. Management believes that appropriatesteps, including cost-cutting measures, marketing of certain assets, possibleequity offerings, and additional or new debt financing are being taken to makeoperations sustainable in the future. Although we are pursuing variousalternatives to provide additional liquidity, there is no assurance of thelikelihood or timing of any of these transactions

 

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**Critical Accounting Policies**

 

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

 

·**               **Reserveevaluation and determination;

 

·**               **Estimatesof the timing and cost of our future drilling activity;

 

·**               **Estimatesof the fair valuation of hedges in place;

 

·**               **Estimatesof timing and cost of asset retirement obligations;

 

·**               **Estimatesof the expense and timing of exercise of stock options; and

 

·**               **Accrualsof operating costs, capital expenditures and revenue.

 

·**               **Estimatesfor litigation.

 

***Oil and Gas Properties***

 

We use the full cost method of accounting for oil and gas producingactivities. Under this method, all costs associated with property acquisition,exploration and development, including costs of unsuccessful exploration, costsof surrendered and abandoned leaseholds, delay lease rentals and the fair valueof estimated future costs of site restoration, dismantlement and abandonmentactivities, are capitalized within a cost center. Our oil and gas propertiesare all located within the United States, which constitutes a single costcenter. We have not capitalized any overhead costs. No gain or loss isrecognized upon the sale or abandonment of undeveloped or producing oil and gasproperties unless the sale represents a significant portion of gas propertiesand the gain significantly alters the relationship between capitalized costsand proved gas reserves of the cost center. Expenditures for maintenance andrepairs are charged to lease operating expense in the period incurred.

 

Depreciation, depletion and amortization of oil and gas properties (“DD&A”)is computed on the unit-of-production method based on proved reserves.Amortizable costs include estimates of future development costs of provedundeveloped reserves and asset retirement obligations. The Company invests inunevaluated oil and gas properties for the purpose of exploration for proved reserves.The costs of such assets, including exploration costs on properties where adetermination of whether proved oil and gas reserves will be established isstill under evaluation, and any capitalized interest and lease operatingexpenses 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. Abandonment of unproved properties isaccounted for as an adjustment to capitalized costs related to proved oil andgas properties, with no losses recognized. The Company recorded an impairmentof unevaluated properties of $26.0 million and $10.7 million on its Green Riverand Kirby properties respectively, for the three and nine months ended September 30,2009. Substantially all of the remaining unproved property costs are expectedto be developed and included in the amortization base over the next three tofive years.  Salvage value is taken intoaccount in determining depletion rates and is based on the Company’s estimateof the value of equipment and supplies at the time the well is abandoned.  As of September 30, 2009 and December 31,2008, the estimated salvage value was approximately $7.2 million and $7.3 million,respectively.

 

Under the full cost method of accounting rules, capitalized costs lessaccumulated depletion and related deferred income taxes may not exceed a “ceiling”value which is the sum of (1) the present value discounted at 10% ofestimated future net revenue using current costs and prices, including theeffects of derivative instruments designated as cash flow hedges but excludingthe future cash outflows associated with settling asset retirement obligationsthat have been accrued on the balance sheet, less any related income taxeffects; plus (2) the cost of properties not being amortized, if any; plus(3) the lower of costs or estimated fair value of unproved properties;less (4) the income tax effects related to differences in the book to taxbasis of oil and gas properties. This is referred to as the “full cost ceilinglimitation.” If capitalized costs exceed the limit, the excess must be chargedto expense. The expense may not be reversed in future periods. At the end ofeach quarter, we calculate the full cost ceiling limitation.  At September 30, 2009, the capitalizedcost of our oil and gas properties exceeded the full cost ceiling limitation byapproximately $35.6 million based upon a natural gas price of $3.09 per Mcf(based on the Colorado Interstate Gas Rocky Mountain Index) in effect at thatdate. Based on the subsequent price increase to approximately $3.22 per Mcf on November 11,2009, the capitalized cost of our oil and gas properties exceeded the full costceiling limitation by approximately $34.6 million. Therefore, we recorded animpairment for the three months ended September 30, 2009 of $34.6 million.A total impairment of approximately $57.8 million was recorded for the ninemonths ended September 30, 2009. This impairment of our oil and gasproperties resulted from low commodity prices in the first three 

 

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quarters of 2009. No impairment was recorded for the nine months ended September 30,2008. A decline in gas prices or an increase in operating costs subsequent tothe measurement date or reductions in economically recoverable reservequantities could result in the recognition of additional impairments of our oiland gas properties in future periods.

 

***Gas Sales***

 

We use the sales method for recording natural gas sales. Sales of gasapplicable to our interest in producing natural gas and oil leases are recordedas revenues when the gas is metered and title transferred pursuant to the gassales contracts covering our interest in gas reserves. During such times as oursales of gas exceed our pro rata ownership in a well, such sales are recordedas revenues unless total sales from the well have exceeded our share ofestimated total gas reserves underlying the property at which time such excessis recorded as a gas imbalance liability. At September 30, 2009 and December 31,2008, there was no such liability recorded.

 

Although there was no such liability recorded for prior periods, gasreserves are an estimate and are updated on an annual and interim basis. Gaspricing, expenses and production may impact future gas reserves remainingwhich, in turn, could impact the recording of liabilities in the future. Gassales accruals at September 30, 2009, and December 31, 2008 werebased on the actual volume statements from our purchasers and distributionprocess. If accruals were to change by 10% at September 30, 2009 and at December 31,2008, the impact would have been a change of $53,000 and $209,000,respectively.

 

***Asset Retirement Obligations***

 

We follow the FASB guidance related to asset retirement obligations.The guidance generally applies to legal obligations associated with theretirement of long-lived assets that result from the acquisition, construction,development and/or normal operations of a long-lived asset. The guidancerequires us to recognize an estimated liability for costs associated with theabandonment 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 life of therespective oil and gas properties.

 

The estimated liability is based on historical gas industry experiencein abandoning wells, including estimated economic lives, external estimates asto the cost to abandon the wells in the future and federal and state regulatoryrequirements. Our liability is discounted using our best estimate of ourcredit-adjusted risk-free rate. Revisions to the liability could occur due tochanges in estimated abandonment costs, changes in well economic lives or iffederal or state regulators enact new requirements regarding the abandonment ofwells. For example, a 10% change in our estimated retirement costs would have a$341,000 effect on our asset retirement obligation liability at September 30,2009.

 

The following is a summary of our asset retirement obligation activityfor the three and nine months ended September 30, 2009 and September 30,2008 (unaudited):

 
| ** **                                      | ** ** | **For the Three Months Ended  September 30,** | ** ** | **For the Nine  Months Ended  September 30,** | ** ** | **For the Three  Months Ended  September 30,** | ** ** | **For the nine  Months Ended  September 30,** | ** ** |
|-------------------------------------------------|------------|----------------------------------------------------|------------|----------------------------------------------------|------------|-----------------------------------------------------|------------|----------------------------------------------------|------------|
| ** **                                      | ** ** | **2009**                                           | ** ** | **2008**                                           | ** ** |
| Beginning balance asset retirement  obligations |       | $                                                  | 3,457      |                                               | $          | 3,366                                               |       | $                                                  | 3,154      |   | $ | 2,767 |   |
| Additional obligation added during the  period  |       | —                                             |       | —                                             |       | 142                                                 |       | 410                                                |       |
| Obligations settled during the period           |       | (106                                               | )          | (129                                               | )          | (48                                                 | )          | (48                                                | )          |
| Accretion expense                               |       | 58                                                 |       | 172                                                |       | 66                                                  |       | 185                                                |       |
| Ending balance of asset retirement  obligations |       | $                                                  | 3,409      |                                               | $          | 3,409                                               |       | $                                                  | 3,314      |   | $ | 3,314 |   |

 

***Inventory***

 

We acquired inventory of oil and gas equipment, primarily tubulars, in2007 and 2008, to take advantage of quantity pricing and to secure a readilyavailable supply. Inventory is valued at the lower of average cost or market.Inventory is used in the development of gas properties and to the extent it isestimated that it will be billed to other working interest owners during thenext 

 

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year, it is included in current assets. Otherwise, it is recorded innon-current assets. The price of steel is a primary factor in valuing ourinventory. Under the valuation method of lower of average cost or market, a 10%reduction in the price of steel would have caused a $46,000 reduction in ourinventory valuation as of September 30, 2009. The market price of steel isevaluated each quarter using prices quoted by authorized vendors in the area.

 

***Property and Equipment***

 

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

 

***Long-Lived Assets***

 

Long-lived assets to be held and used in our business are reviewed forimpairment whenever events or changes in circumstances indicate that therelated carrying amount may not be recoverable. When the carrying amounts oflong-lived assets exceed the fair value, which is generally based on discountedexpected future cash flows, we record an impairment. No impairments onlong-lived assets were recorded during the year ended December 31, 2008and the nine months ended September 30, 2009.

 

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***General and Administrative Expenses***

 

General andadministrative expenses are reported net of amounts allocated and billed toworking interest owners of gas properties operated by us. The administrativeexpenses billed to working interest owners may change in accordance with theterms of the joint operating agreements. Administrative expenses are charged toworking interest owners based on productive well counts.  A 10% change in well counts for the three andnine months ended September 30, 2009 would have increased or decreased ourexpenses billed to working interest owners by approximately $29,000 and$95,000, respectively. As we operate and drill additional wells in the future,additional administrative expenses will be charged to the working interestowners when the wells become productive.

 

***Income Taxes***

 

We use the asset and liability method of accounting for income taxes.Deferred tax assets and liabilities are recognized for the expected future taxconsequences of temporary differences between the financial statement and taxbases of assets and liabilities. If appropriate, deferred tax assets arereduced by a valuation allowance which reflects expectations of the extent towhich such assets will be realized. As of September 30, 2009 and December 31,2008, we recorded a full valuation allowance for our net deferred tax asset.

 

On January 1, 2007, we adopted accounting provisions thatprescribe a recognition threshold and measurement attribute for the financialstatement recognition and measurement of a tax position taken or expected to betaken in a tax return. This provision requires that we recognize in ourconsolidated financial statements only those tax positions that are “more-likely-than-not”of being sustained as of the adoption date, based on the technical merits ofthe position. As a result of the implementation of the provision, we performeda comprehensive review of our material tax positions in accordance with theserecognition and measurement standards. As a result of this review, we did notidentify any material deferred tax assets that required adjustment. As of September 30,2009 and 2008, we had not recorded any material uncertain tax positions.

 

Our policy is to recognize interest and penalties related to uncertaintax benefits in income tax expense. As of September 30, 2009 and 2008, wehad not recognized any interest or penalties in our statement of operations orstatement of financial position.

 

We are subject to the following material taxing jurisdictions: U.S.federal. We also have material operations in the state of Wyoming; however,Wyoming does not impose a corporate income tax. The tax years that remain opento examination by the U.S. Internal Revenue Service are years 2005 through2008. Due to our net operating loss carry forwards, the Internal RevenueService may also adjust the amount of loss realizable under examination back to2003.

 

***Derivatives***

 

We use derivative instruments to manage our exposure to fluctuatingnatural gas prices through the use of natural gas swap and option contracts. Weaccount for derivative instruments or hedging activities under authoritiveguidance prescribed by FASB that requires us to record derivative instrumentsat their fair value. If the derivative is designated as a fair value hedge, thechanges in the fair value of the derivative and of the hedged item attributableto the hedged risk are recognized in earnings. If the derivative is designatedas a cash flow hedge, the effective portions of changes in the fair value ofthe derivative are recorded in other comprehensive income (loss) and arerecognized in the statement of operations when the hedged item affectsearnings. Ineffective portions of changes in the fair value of cash flowhedges, if any, are recognized in earnings. Changes in the fair value ofderivatives that do not qualify for hedge treatment are recognized in earnings.Please see “Note 5 — Derivatives” of the notes to the unaudited financialstatements appearing elsewhere in this quarterly report for additionaldiscussion of derivatives.

 

We periodically hedge a portion of our oil and gas production throughswap and collar agreements. The purpose of the hedges is to provide a measureof stability to our cash flows in an environment of volatile oil and gas pricesand to manage the exposure to commodity price risk. Our management decided notto use hedge accounting for these agreements. Therefore, in accordance withcertain accounting provisions, the changes in fair market value are recognizedin earnings.

 

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***Stock-Based Compensation***

 

Effective January 1, 2006, we adopted accounting provisions, whichrequire companies to recognize compensation expense for share-based paymentsbased on the estimated fair value of the awards. We recognized an expense ofapproximately $253,000 for the nine months ended September 30, 2009, basedon the fair value of vested options.  Werecognized an expense of approximately $422,000 for the nine months ended September 30,2009, based on the fair value of restricted stock that vested during thequarter.  We recognized an expense ofapproximately $8,000 for the nine months ending September 30, 2009, basedon the fair market value of stock appreciation rights. This accountingprovision also requires that the benefits of tax deductions in excess ofcompensation cost recognized for stock awards and options (“excess tax benefits”)be presented as financing cash inflows in the Statement of Cash Flows.

 

***Accounts Receivable***

 

Our revenue producing activities are conducted primarily in Wyoming. Wegrant credit to qualified customers, which potentially subjects us to creditrisk resulting from, among other factors, adverse changes in the industry inwhich we operate and the financial condition of our customers. We continuouslymonitor collections and payments from our customers and, if necessary, recordan allowance for doubtful accounts based upon historical experience and anyspecific customer collection issues identified. We recorded an allowance of$100,000 as of September 30, 2009 and December 31, 2008.

 

***Transportation Costs***

 

We account for transportation costs under authoritative guidanceprescribed by FASB related to the accountingfor shipping and handling fees and costs, whereby amounts paid fortransportation are classified as operating expenses.

 

***Legal Estimates***

 

From time to time, we are subject to legal proceedings and claims thatarise in the ordinary course of business. We account for these costs under anaccounting provision, 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, 2009 and December 31, 2008, we accrued noexpenses for legal proceedings.

 

***Per Share Information***

 

Basic loss per share is computed by dividing net income loss fromcontinuing operations attributable to common stock by the weighted averagenumber of common shares outstanding during each period. Diluted earnings pershare is computed by adjusting the average number of common shares outstandingfor the dilutive effect, if any, of common stock equivalents such as stockoptions and warrants. Diluted net loss per share was the same as basic net lossper share for the nine months ended September 30, 2009 because potentialcommon stock equivalents were anti-dilutive. Certain option to purchase sharesof our common stock were excluded from the dilution calculations because theshares were anti-dilutive. At September 30, 2009 and 2008, 640,000 and717,500 options, respectively, were excluded because they were anti-dilutivedue to the net loss attributable to stockholders incurred in such periods.

 

A summary ofthe net income/(loss) per share calculation is shown below (in thousands,except per share amounts):

 
| ** **                                                   | ** ** | **For the Three  Months Ended  September 30,** | ** ** | **For the Nine  Months Ended  September 30,** | ** ** |
|--------------------------------------------------------------|------------|-----------------------------------------------------|------------|----------------------------------------------------|------------|
| ** **                                                   | ** ** | **2009**                                            | ** ** | **2008**                                           | ** ** | **2009** | ** ** | **2008** | ** ** |
| Net income/(loss)                                            |       | $                                                   | (38,962    | )                                                  | $          | 8,939 |   | $ | (65,931 | ) | $ | (583 | ) |
| Common shares outstanding:                                   |       |                                                |       |                                               |       |   |   |   |   |
| Historical common shares outstanding at  beginning of period |       | 29,722                                              |       | 29,000                                             |       | 29,278 |   | 29,008 |   |
| Weighted average common shares issued                        |       | 62                                                  |       | 147                                                |       | 169 |   | 46 |   |
| Weighted average common shares  outstanding-basic            |       | 29,784                                              |       | 29,147                                             |       | 29,447 |   | 29,054 |   |
| Effect of dilution – stock options                      |       | —                                              |       | 741                                                |       | — |   | — |   |
| Weighted average common shares  outstanding-diluted          |       | 29,784                                              |       | 29,888                                             |       | 29,447 |   | 29,054 |   |
| Net income/(loss) per share-basic                            |       | $                                                   | (1.31      | )                                                  | $          | 0.31 |   | $ | (2.24 | ) | $ | (0.02 | ) |
| Net income/(loss) per share-diluted                          |       | $                                                   | (1.31      | )                                                  | $          | 0.30 |   | $ | (2.24 | ) | $ | (0.02 | ) |

 

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***New Accounting Pronouncements***

 

For information concerning new accounting pronouncements, please see “Note2 — Basis of Presentation” of the notes to the unaudited financial statementsappearing elsewhere in this quarterly report.

 

**Trends Affecting Our Business**

 

The continued credit crisis and related turmoil in the global financialsystem have had an adverse impact on our business and financial condition. Inaddition, the prices of oil and natural gas declined significantly in 2008 andhave remained low in 2009.  As a resultof low CIG index prices, the economic climate and our limited capitalresources, we expect to continue operating during 2009 and 2010 with a reducedcapital expenditure plan. Under our plan, we will generally make expendituresonly as are necessary to secure drilling permits in strategic areas, drillwells that secure leasehold positions and construct the necessaryinfrastructure to complete and hook-up wells that have already been drilled.

 

Historically, natural gas prices have been extremely volatile, and weexpect that volatility to continue. For example, during the nine months ended September 30,2009, the NYMEX natural gas index price ranged from a high of $6.07 per MMBtuto a low of $2.51 per MMBtu, while the CIG natural gas index price ranged froma high of $4.59 per MMBtu to a low of $1.33 per MMBtu. During the year ended December 31,2008, the NYMEX natural gas index price ranged from a high of $13.58 per MMBtuto a low of $5.29 per MMBtu, while the CIG natural gas index price ranged froma high of $10.26 per MMBtu to a low of $1.00 per MMBtu. Changes in natural gaspricing have impacted our revenue streams, production taxes, prices used inreserve calculations, borrowing base calculations and the carrying value of ourproperties and the valuation of potential property acquisitions. During thethree and nine months ended September 30, 2009, estimated future gasprices had an impact on both our revenues and the costs attributable to ourfuture operations. We expect that changing natural gas prices will continue toimpact our operations and financial results in the future.

 

Transportationof natural gas and access to throughput capacity have a direct impact onnatural gas prices in the Rocky Mountain region, where our operations are concentrated.As drilling activity increases throughout the Rocky Mountain region, additionalproduction may come on line, which could cause bottlenecks or capacityconstraints. Generally speaking, a surplus of natural gas production relativeto available transportation capacity has a negative impact on prices.Conversely, as capacity increases, and bottlenecks are eliminated, pricesgenerally increase. Although there is currently adequate transportationcapacity out of the Powder River Basin, a surplus of natural gas arriving atkey marketing hubs from the Powder River Basin and elsewhere relative toavailable takeaway capacity from these hubs has caused Rocky Mountain gas togenerally trade at a discount to the NYMEX natural gas index price. Forexample, from January 1, 2009 through September 30, 2009, RockyMountain gas traded at a differential to the NYMEX natural gas index price thatranged from a discount of $0.06 to $2.30 per MMBtu, with an averagedifferential of a discount of $1.12 per MMBtu. The Rockies Express Pipelinewhich was completed and placed into service in early 2008, has increasedtakeaway capacity by approximately 1.5 Bcf per day from these hubs. We expectthat the completion of additional proposed pipelines will help reduce thedifferential between gas produced in the Rocky Mountain region and the NYMEXnatural gas index price. Additional proposed pipelines are scheduled to becompleted in late 2010 and 2011. General economic conditions and the futuredemand for natural gas may change the development schedule of proposedpipelines.

 

The U.S. House of Representatives recently passed the American CleanEnergy and Security Act of 2009 which, if passed into law, will establish afederal cap-and-trade system. Under this system, major producers of greenhousegas emissions would be required to acquire emission allowances, either throughpurchases at auctions or through trades with other allowance holders, and thensurrender the allowances to the government. If a regulated party could not acquire sufficient allowances or reduceits emissions to the level of the allowances that it did acquire, the partywould face regulatory penalties.  Thislegislation would initially cover electrical generation facilities and wouldphase in coverage of other industrial sources of emissions and natural gas andfossil fuel distribution.  If this orsimilar legislation is enacted into law, it could have a material adverseeffect on our operations through significant increases in operating costs anddecreases in the demand for natural gas.

 

The U.S. Congress is currently considering legislation that would amendthe Safe Drinking Water Act to eliminate an existing exemption from federalregulation of hydraulic fracturing activities. Hydraulic fracturing is a common process in our industry of creatingartificial cracks or fractures in deep underground formations through thepressurized injection of water or other materials.  The resulting fractures allow natural gas andoil to flow more freely to a producing well. This process is often necessary to produce economically viablequantities of oil and natural gas from many reservoirs.  Currently, regulation of hydraulic fracturingis primarily conducted at the state level through permitting and othercompliance requirements.  If adopted, theproposed amendment to the Safe Drinking Water Act could result in additionalregulations and permitting requirements at the federal level.  These additional 

 

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regulations and permitting requirements could lead to significantoperational delays and increased operating costs as well as encumbering fieldenhancements through fracturing.

 

**Results of Operations**

 

Net loss attributable to stockholders for the quarter ended September 30,2009 was $39.0 million, or $1.31 per diluted share, on total revenues of $3.7million. Other income for the quarter ended September 30, 2009 included a$3.1 million unrealized loss associated with the change in the fair valuationof our natural gas hedges in place in accordance with certain accountingprovisions. Absent such change in the valuation of hedges, we would have showna loss of $35.9 million. In addition, we recorded an impairment of $34.6million for the quarter ended September 30, 2009.  Absent the impairment and unrealized loss onderivatives, we would have shown a loss of $1.3 million for the quarter ended September 30,2009. This compares to net income attributable to stockholders of $8.9 millionfor the three months ended September 30, 2008 on total revenue of $6.4million. Adjusted for an unrealized gain in the fair valuation of our naturalgas hedges in place of $10.0 million shown in other income, our results for thequarter ended September 30, 2008 would have been a net loss attributableto common stockholders of $1.1 million. We did not record an impairment for thequarter ended September 30, 2008.

 

In order to provide ameasure of stability to the cash flow in an environment of volatile oil and gasprices and to manage the exposure to commodity price risk, we chose toperiodically hedge a portion of our oil and gas production using swap andcollar agreements. We account for our derivative instruments under certainaccounting provisions which require us to record derivative instruments attheir fair value. Management has chosen not to use hedge accounting for thesearrangements. Therefore, in accordance with these provisions, changes in thefair market value are recognized in earnings.

 

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***Three Months Ended September 30, 2009 Compared to ThreeMonths Ended September 30, 2008***

 

*Gas salesvolume.*

 

Gas sales volume decreased35%, from 1,036 MMcf in the three months ended September 30, 2008 to 674MMcf in the three months ended September 30, 2009. Daily sales volume was7.3 MMcf for the three months ended September 30, 2009 as compared to 11.3MMcf for the three months ended September 30, 2008, a 4.0 MMcf per daydecrease. The decrease resulted primarily from shutting in wells due to lownatural gas prices.

 

*Gas salesrevenue.*

 

          Revenue from gas sales decreased approximately $4.0 millionduring the three months ended September 30, 2009, to approximately $1.7million, a 70% decrease compared to the three months ended September 30,2008. This decrease was primarily due to a decrease in gas sales volume coupledwith a decrease in the average realized price per Mcf. The average realizedprice per Mcf decreased approximately 54%, from $5.49 per Mcf beforetransportation in the three months ended September 30, 2008 to $2.50 perMcf in the three months ended September 30, 2009.

 

*Derivatives.*

 

          For the three months ended September 30, 2009, we hadan unrealized loss of $3.1 million compared to an unrealized gain of $10.0million for the three months ended September 30, 2008. The unrealized lossis a non-cash expense based primarily on the Black-Scholes model for valuingfuture cash flows utilizing price volatility with a normal discount rate.Hedges settled during the three months ended September 30, 2009 and 2008resulted in a realized gain of $2.0 million and $0.7 million, respectively. Therealized hedge gain for the three months ended September 30, 2009 wasprimarily due to the fact that gas prices were lower than the weighted averagefloor price of our hedges in place.

 

*Lease operating expenses.*

 

Lease operating expenses decreased $0.9 million in the three monthsended September 30, 2009 to $0.9 million, a 49% decrease compared to thethree months ended September 30, 2008. This decrease resulted primarilyfrom a reduction in contract services, fuel, workover, and water managementrelated costs during the three months ended September 30, 2009. On a Mcfbasis, lease operating expenses decreased 21% from $1.73 per Mcf in the threemonths ended September 30, 2008 to $1.37 per Mcf in the three months endedSeptember 30, 2009.

 

*Production taxes.*

 

Production taxes decreased $0.5 million in the three months ended September 30,2009 to $0.2 million, a 74% decrease from the three months ended September 30,2008. Production taxes generally correlate to gross sales revenue becauseproduction taxes are based on a percentage of sales value. In Wyoming, thepercentage averages 11% to 13%, depending on rates in effect for the respectiveyear, while in Montana the percentage averages 9%. The decrease in productiontaxes for the three months ended September 30, 2009 was primarily due todecreased revenues associated with decreased volume and realized pricing. On anMcf basis, production taxes were $0.25 per Mcf for the three months ended September 30,2009 and $0.62 per Mcf for the three months ended September 30, 2008, a60% decrease, which correlates to the decrease in the price per Mcf received inthe three months ended September 30, 2009 from the three months ended September 30,2008.

 

*Marketing and transportation.*

 

Marketing and transportation expenses decreased approximately $0.4million in the three months ended September 30, 2009 to approximately $0.8million, a 33% decrease from the three months ended September 30, 2008.The decrease related primarily to a decrease in transportation fees andcompression due to lower production volumes. On an Mcf basis, marketing andtransportation expenses increased 4% to $1.16 per Mcf in the three months endedSeptember 30, 2009 from $1.12 per Mcf in the three months ended September 30,2008.

 

*General and administrative expenses, net.*

 

General and administrative expenses are offset by operating income fromdrilling and production activities for which we can charge an overhead fee tononoperating working interest owners. These well operating overhead fees were$0.3 million and $0.5 million for the three months ended September 30,2009 and September 30, 2008, respectively, a 47% decrease. General and 

 

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administrative expenses, net, decreased $0.5 million in the threemonths ended September 30, 2009 to $0.9 million. On an Mcf basis, generaland administrative expenses, remained unchanged, at $1.29 per Mcf in the threemonths ended September 30, 2008 and September 30, 2009. The decreasein general and administrative expenses was primarily a result of staff and payreductions

 

*Depreciation, depletion, amortization and accretion.*

 

Depreciation, depletion, amortization and accretion expense decreased$0.3 million for the three months ended September 30, 2009 to $2.3million, a 13% decrease compared to the three months ended September 30,2008. The decrease was primarily due to a decrease in the capitalized basis inour full cost pool at September 30, 2009. On an Mcf basis, thedepreciation, depletion, amortization and accretion rate increased to $3.44 perMcf in the three months ended September 30, 2009 from $2.57 per Mcf in thethree months ended September 30, 2008.

 

*Impairment.*

 

At September 30, 2009, the capitalized cost of our oil and gasproperties exceeded the full cost ceiling limitation by approximately $35.6million based upon a natural gas price of $3.09 per Mcf (based on the ColoradoInterstate Gas Rocky Mountain Index) in effect at that date. Based on thesubsequent price increase to approximately $3.22 per Mcf on November 11,2009, the capitalized cost of our oil and gas properties exceeded the full costceiling limitation by approximately $34.6 million. Therefore, we recorded animpairment of $34.6 million for the three months ended September 30, 2009.No impairment was taken for the three months ended September 30, 2008. Forfurther information regarding this impairment, please see Note 2 — “Basis ofPresentation” in the Notes to the unaudited financial statements appearingelsewhere in this quarterly report. A decline in natural gas prices or anincrease in operating costs in the economically recoverable quantities couldresult in the recognition of additional impairments of our oil and gas propertiesin future periods.

 

***Nine Months Ended September 30,2009 Compared to Nine Months Ended September 30, 2008***

 

*Gas sales volume.*

 

Gas sales volume decreased 25%, from 2,916 MMcf in the nine monthsended September 30, 2008 to 2,189 MMcf in the nine months ended September 30,2009. Daily sales volume was 8.0 MMcf for the nine months ended September 30,2009 as compared to 10.6 MMcf for the nine months ended September 30,2008, a 2.6 MMcf per day decrease. The decrease resulted primarily fromshutting in wells due to low natural gas prices, reductions in volumes due tocompression maintenance and repairs, and weather related downtime.

 

*Gas sales revenue.*

 

Revenue from gas sales decreased approximately $12.9 million during thenine months ended September 30, 2009, to approximately $6.1 million, a 68%decrease compared to the nine months ended September 30, 2008. Thisdecrease was primarily due to a decrease in the average realized price and adecrease in gas sales volume per Mcf. The average realized price per Mcfdecreased approximately 57%, from $6.49 per Mcf in the nine months ended September 30,2008 to $2.77 per Mcf in the nine months ended September 30, 2009.

 

*Derivatives.*

 

For the nine months ended September 30, 2009, we had an unrealizedloss of $5.2 million compared to an unrealized gain of $3.5 million for thenine months ended September 30, 2008. The unrealized gain and losses arenon-cash expenses based primarily on the Black-Scholes model for valuing futurecash flows utilizing price volatility with a normal discount rate. Hedgessettled during the nine months ended September 30, 2009 resulted in arealized gain of $5.5 million compared to a realized hedge loss of $0.05million during the nine months ended September 30, 2008. The realizedhedge gain for the nine months ended September 30, 2009 was primarily dueto the fact that gas prices were lower than the weighted average floor price ofour hedges in place.

 

*Lease operating expenses.*

 

Lease operating expenses decreased $2.1 million in the nine monthsended September 30, 2009 to $3.0 million, a 41% decrease compared to thenine months ended September 30, 2008. This decrease resulted primarilyfrom a reduction in contract services, fuel, workover and water managementrelated costs offset partially by an increase in surface use expenses in theproductive cycle during the nine months ended September 30, 2009. On a Mcfbasis, lease operating expenses decreased 22% from $1.78 per Mcf in the ninemonths ended September 30, 2008 to $1.39 per Mcf in the nine months ended September 30,2009.

 

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*Production taxes*

 

Production taxes decreased $1.6 million in the nine months ended September 30,2009 to $0.6 million, a 73% decrease from the nine months ended September 30,2008. Production taxes generally correlate to gross sales revenue becauseproduction taxes are based on a percentage of sales value. In Wyoming, thepercentage averages 11% to 13%, depending on rates in effect for the respectiveyear, while in Montana the percentage averages 9%. The decrease in productiontaxes for the nine months ended September 30, 2009 was primarily due todecreased revenues associated with decreased volume and realized pricing. On anMcf basis, production taxes were $0.27 per Mcf for the nine months ended September 30,2009 and $0.74 per Mcf for the nine months ended September 30, 2008, a 64%decrease, which correlates to the decrease in the price per Mcf received in thenine months ended September 30, 2009 from the nine months ended September 30,2008.

 

*Marketing and transportation.*

 

Marketing and transportation expenses decreased approximately $0.5million in the nine months ended September 30, 2009 to approximately $2.9million, a 15% decrease from the nine months ended September 30, 2008. Thedecrease related primarily to a decrease in transportation fees and compressiondue to lower production volumes. On an Mcf basis, marketing and transportationexpenses increased 14% to $1.34 per Mcf in the nine months ended September 30,2009 from $1.18 per Mcf in the nine months ended September 30, 2008.

 

*General and administrative expenses, net.*

 

General and administrative expenses are offset by operating income fromdrilling and production activities for which we can charge an overhead fee tononoperating working interest owners. These well operating overhead fees were$0.9 million and $1.4 million for the nine months ended September 30, 2009and September 30, 2008, respectively, a 35% decrease. General andadministrative expenses, net, decreased $2.8 million in the nine months ended September 30,2009 to $3.1 million. On an Mcf basis, general and administrative expenses, netdecreased 31%, from $2.03 per Mcf in the nine months ended September 30,2008 to $1.41 per Mcf in the nine months ended September 30, 2009. Thedecrease in general and administrative expenses was primarily a result of staffand pay reductions. In addition, during the nine months ended September 30,2008, general and administrative expenses included a $2.1 million charge relatedto the failed Quest merger.

 

*Depreciation, depletion, amortization and accretion.*

 

Depreciation, depletion, amortization and accretion expense decreased$1.6 million for the nine months ended September 30, 2009 to $5.1 million,a 24% decrease compared to the nine months ended September 30, 2008. Thedecrease was primarily due to a decrease in the capitalized basis in our fullcost pool at September 30, 2009. On an Mcf basis, the depreciation,depletion, amortization and accretion rate increased to $2.31 per Mcf in thenine months ended September 30, 2009 from $2.29 per Mcf in the nine monthsended September 30, 2008.

 

*Impairment.*

 

At September 30, 2009, the capitalizedcost of our oil and gas properties exceeded the full cost ceiling limitation byapproximately $35.6 million based upon a natural gas price of $3.09 per Mcf(based on the Colorado Interstate Gas Rocky Mountain Index) in effect at thatdate. Based on the subsequent price increase to approximately $3.22 per Mcf on November 11,2009, the capitalized cost of our oil and gas properties exceeded thecapitalized cost of the Company’s oil and gas properties by approximately $34.6million. Therefore, we recorded an impairment for the three months ended September 30,2009 of $34.6 million. An impairment of approximately $57.8 million wasrecorded for the nine months ended September 30, 2009. No impairment wastaken for the nine months ended September 30, 2008. For furtherinformation regarding this impairment, please see Note 2 — “Basis of Presentation”in the Notes to the unaudited financial statements appearing elsewhere in thisquarterly report. A decline in natural gas prices or an increase in operatingcosts in the economically recoverable quantities could result in therecognition of additional impairments of our oil and gas properties in futureperiods.

 

**Liquidity and Capital Resources**

 

In the past,our primary sources of liquidity have been private and public sales of ourequity securities, cash provided by operating activities, and debt financing.All of these sources have been negatively impacted by the current economicclimate, its impact on our industry, and by significant fluctuations in oil andgas prices, operating costs, and volumes produced. We have no control over themarket prices for oil and natural gas, although we are able to influence theamount of our net realized revenues related to gas sales through the use ofderivative contracts. A decrease in market prices would reduce expected cashflow from operating 

 

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activitiesand could reduce the borrowing base of our credit facility as well as the valueof assets we might consider selling. Historically, decreases in the marketprices have limited our industry’s access to the capital markets. During thesechallenging times, we have reduced our administrative, operating andtransportation costs. We are also actively marketing asset sales and exploringother strategic alternatives and capital restructuring options.

 

*Credit Facility*.

 

Effective February 12, 2007, we entered into a credit facilitywhich permits borrowings up to the borrowing base as designated by theadministrative agent. As of September 30, 2009 and December 31, 2008,we had $6.5 million and $11.5 million, respectively, of debt outstanding underthe facility. As described below, we are currently unable to borrow additionalamounts under the credit facility due to covenant limitations and may befurther limited in the future based on borrowing base limitations.

 

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

 

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

 

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

 

Our obligations under the credit facility are secured by liens on (i) noless than 90% of the net present value of the oil and gas to be produced fromour oil and gas properties that are included in the borrowing basedetermination, calculated using a discount rate of 10% per annum and reserveestimates, prices and production rates and costs, (ii) options to lease,seismic options, permits, and records related to such properties, and (iii) seismicdata.

 

Borrowings under our credit facility, as amended, bear interest either:(i) at the greater of the one month London Interbank Offered Rate, orLIBOR, plus 1.00% or a domestic bank rate, plus in either case an applicablemargin of 0.75% to 1.75% based on utilization, or (ii) on a sliding scalefrom the one, two, three or six month LIBOR, plus an applicable margin of 2.00%to 3.00% based on utilization. The weighted average interest rate as of September 30,2009 was 5.0%.  The credit agreementprovides for various fees, including a quarterly commitment fee of 0.5% perannum and engineering fees to the administrative agent in connection with aborrowing base determination. In addition, the credit facility provided for anup front fee of $27,000, which was paid on the closing date of the creditfacility, and an additional arrangement fee of 1% based on utilization.Borrowings under this credit facility may be prepaid without premium orpenalty, except on Eurodollar advances.

 

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

 

·**               **incurliens;

 

·**               **incurdebt;

 

·**               **makeinvestments in other persons;

 

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

 

·**               **engagein mergers, acquisitions, consolidations and asset sales or amend ourorganizational documents;

 

·**               **enterinto certain hedging arrangements;

 

·**               **amendmaterial contracts; and

 

·**               **enterinto related party transactions.

 

With regard tohedging arrangements, our credit agreement provides that acceptable commodityhedging arrangements cannot cover greater than 80 to 85%, depending on themeasurement date, of our monthly production from our hydrocarbon propertiesthat are used in the borrowing base determination, and that the fixed or floorprice of our hedging arrangements must be equal to or greater than the gasprice used by the lenders in determining the borrowing base.

 

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The creditagreement, as amended, also requires that we satisfy certain affirmativecovenants, meet certain financial tests, maintain certain financial ratios andmake certain customary indemnifications to lenders and the administrativeagent. The financial covenants include requirements to maintain: (i) aratio of 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 than3.0 to 1.0, and (v) a total proved PV-10 value to total debt ratio of atleast 1.50 to 1.00.

 

The creditagreement, as amended, contains customary events of default, including 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 credit agreement requires any wholly-owned subsidiariesto guarantee the obligations under the credit agreement.

 

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

 

Effective August 4,2008, we and the administrative agent and lender entered into the secondamendment to the credit agreement (the “second amendment”). The secondamendment provided, among other things, for (i) an increase in the totalquarterly senior debt to annualized EBITDA ratio from 2.0 to 1.0, to 3.0 to1.0, (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.

 

Effective September 30,2008, we and the administrative agent and lender entered into the thirdamendment to the credit agreement (the “third amendment”). In addition towaiving compliance with the current ratio covenant as of September 30,2008, the third amendment, among other things, required 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 ofthis new condition to additional borrowings, we are currently unable to borrowadditional amounts under the credit agreement. The third amendment alsoincreased the 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 on utilization, and provided for the payment ofan amendment fee.

 

On April 14, 2009, we and the administrative agent entered intothe fourth amendment to the credit agreement which reduced the borrowing baseas described above and waived compliance with the current ratio financialcovenant as of December 31, 2008 and March 31, 2009 and with therestrictive covenants related to accounts payable, permitted liens andpermitted debt until the current ratio financial covenant and next borrowingbase redetermination, subject to certain financial caps. On August 19,2009, the lenders waived compliance with the current ratio financial covenantunder the Credit Agreement for the period ending August 26, 2009 and thequarter ending June 30, 2009.

 

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

 

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

 
| December 1, 2009 through  December 31, 2009 |   | $ | 6,300,000 |   |
|-------------------------------------------------------|--------|---|-----------|--------|
| January 1, 2010 through  January 31, 2010   |   | $ | 6,100,000 |   |
| February 1, 2010 through  February 28, 2010 |   | $ | 5,900,000 |   |
| March 1, 2010 through March 31,  2010       |   | $ | 5,700,000 |   |
| April 1, 2010 through April 30,  2010       |   | $ | 5,500,000 |   |

 

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

 

On October 26, 2009, the lenders provided a waiver effectivelyextending the terms of the fifth amendment to the Credit Agreement through November 16,2009.  On November 16, 2009, thelenders provided an additional waiver effectively extending the terms of thefifth amendment to the Credit Agreement through November 23, 2009.

 

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On November 23,2009, the lenders provided an additional waiver extending the terms of thefifth amendment to the Credit Agreement through December 1, 2009 and for thequarter ended September 30, 2009.

 

We believe that we may not be in compliance with the current ratiofinancial covenant and certain other covenants throughout 2009, but managementanticipates receiving waivers in the future based on prior dealings with thelender and continued compliance with the borrowing base limitations. There canbe no assurance that we will be able to obtain such waivers or that such waiverswill be obtained on acceptable terms. If we are unable to obtain future waiversand/or comply with the restrictive covenants and are therefore in default, thelenders could avail themselves of the remedies under the credit agreement,including acceleration and foreclosure.

 

*Office Building 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 that bore interest at 6.875% until November 15,2008, currently bears interest at a variable base rate plus 0.5% and will bearinterest at 18% upon a default. The variable base rate is based on the lender’sbase rate. The maturity date of this mortgage is November 15, 2015, atwhich time a principal and interest payment of $531,300 will become due. As of September 30,2009, we had $741,000 outstanding in principal on this mortgage. On November 15,2008, the interest rate on our mortgage loan changed from a fixed rate of6.875% to a variable rate. As of September 30, 2009, the variable rate was4.75%.

 

*Capital Expenditure Budget*.

 

We had totalcapital expenditures of $3.0 million for the nine months ended September 30,2009. Due to low CIG index prices, the economic climate and limited capitalresources, we expect to continue to operate with a reduced capital expenditureplan through 2009 and 2010. Under our reduced capital expenditure plan, we willgenerally only make such expenditures as are necessary to secure drillingpermits in strategic areas, drill wells that secure leasehold positions andconstruct the necessary infrastructure to complete and hook-up wells that havealready been drilled.

 

***Cash Flow from Operating Activities***

 

Net cash used in operatingactivities was $1.7 million for the nine months ended September 30, 2009,compared to net cash provided by operating activities of $10.4 million for thenine months ended September 30, 2008. The change was primarily due to adecrease in AP, accrued liabilities and production taxes in addition to adecrease in revenue distribution payables.

 

***Cash Flow from Investing Activities***

 

Net cash provided by investing activities was $6.3 million for the ninemonths ended September 30, 2009, compared to net cash used in investingactivities of $25.8 million for the nine months ended September 30,2008.  The change in net cash provided byinvesting activities in the nine months ended September 30, 2009 wasprimarily due to a sale of certain oil and gas properties and a realized gainon derivatives coupled with reduced capital expenditures as compared to thequarter ended September 30, 2008.

 

***Cash Flow from Financing Activities***

 

Net cash used in financing activities was $5.0 million for the ninemonths ended September 30, 2009, compared with net cash provided byfinancing activities of $7.5 million for the nine months ended September 30,2008. The change was primarily due to a reduction in the balance owed on theline of credit for the nine ended September 30, 2009, compared toadditional borrowings for the nine months ended September 30, 2008.

 

*Contractual Obligations*

 

Please see Notes 3 and 7 of the Notes to the unaudited financialstatements appearing elsewhere in this quarterly report for informationregarding our credit facility and other indebtedness.

 

The following table summarizes by period our contractual obligations asof September 30, 2009:

 
| ** **                                     | ** ** | **Total**          | ** **  | **2009** | ** ** | **2010-2011** | ** ** | **2012-2013** | ** **  | **Thereafter** | ** ** |
|------------------------------------------------|------------|--------------------|-------------|----------|------------|---------------|------------|---------------|-------------|----------------|------------|
| ** **                                     | ** ** | **(In Thousands)** | ** **  |
| Notes payable in connection with the  mortgage |       | 741                |        | 8        |       | 63            |       | 70            |        | 600            |       |
| Asset retirement obligations                   |       | 3,409              |        | 213      |       | 895           |       | 1,088         |        | 1,213          |       |
| Production and property taxes                  |       | 2,868              |        | 1,156    |       | 1,712         |       | —        |        | —         |       |
| Total                                          |       | $                  |  7,018 |     | $          |  1,377   |       | $             |  2,670 |           | $          |  1,158 |   | $ |  1,813 |   |
|                                                |            |                    |             |          |            |               |            |               |             |                |            |  |  |  |  |  |

 

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**ITEM 3. QUANTITATIVE ANDQUALITATIVE DISCLOSURES ABOUT MARKET RISK**

 

The primary objective of the following information is to provideforward-looking quantitative and qualitative information about our potentialexposure to market risk. The term “market risk” refers to the risk of lossarising from adverse changes in natural gas prices and interest rates. Thisforward-looking information provides indicators of how we view and manage ourongoing market risk exposure. All of our market risk sensitive instruments wereentered into for purposes other than speculative trading.

 

**Commodity Price Risk**

 

Our major marketrisk exposure is in the pricing applicable to our natural gas production. Theprices we receive for our production depend on many factors beyond our control.We seek to reduce our exposure to unfavorable changes in natural gas prices,which are subject to significant and often volatile fluctuation, through theuse of fixed-price contracts. Our fixed-price contracts are comprised of energyswaps and collars. Fixed price contracts allow us to predict with greatercertainty the effective natural gas prices to be received for hedged productionand benefit operating cash flows and earnings when market prices are less thanthe fixed prices provided by the contracts. However, we will not benefit frommarket prices that are higher than the fixed prices in the contracts for hedgedproduction. Collar structures provide for participation in price increases anddecreases to the extent of the ceiling prices and floors provided in thosecontracts. With regard to hedging arrangements, our credit facility providesthat acceptable commodity hedging arrangements cannot cover greater than 80 to85%, depending on the measurement date, of our monthly production from our hydrocarbonproperties that are used in the borrowing base determination, and that thefixed or floor price of our hedging arrangements must be equal to or greaterthan the gas price used by the lenders in determining the borrowing base.

 

The following table summarizesthe estimated volumes, fixed prices, fixed price sales and fair valueattributable to the fixed price contracts as of September 30, 2009. At September 30,2009, we had hedged volumes through December 2010. Please see Note 5 ofthe Notes to the unaudited financial statements appearing elsewhere in thisquarterly report for further information regarding our derivatives.

 
| ** **                                       | ** ** | **Year Ending  December 31, 2009** | ** ** | **Year Ending  December 31, 2010** | ** ** |
|--------------------------------------------------|------------|---------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                       | ** ** | **(Unaudited)**                                   | ** ** | **(Unaudited)**                                   | ** ** |
| **Natural Gas Collars:**                         |       |                                              |       |                                              |       |
| Contract volumes (MMBtu)                         |       |                                              |       |                                              |       |
| Floor                                            |       | 184,000                                           |       | —                                            |       |
| Ceiling                                          |       | 184,000                                           |       | —                                            |       |
| Weighted-average fixed price per MMBtu(1)        |       |                                              |       |                                              |       |
| Floor                                            |       | $                                                 | 6.50       |                                              | $          | — |   |
| Ceiling                                          |       | $                                                 | 7.50       |                                              | $          | — |   |
| Fixed-price sales(2)                             |       | $                                                 | 7.50       |                                              | $          | — |   |
| Fair value, net (thousands)(3)                   |       | $                                                 | 410        |                                              | $          | — |   |
| **Natural Gas Swaps:**                           |       |                                              |       |                                              |       |
| Contract volumes (MMBtu)                         |       | 552,000                                           |       | 2,007,500                                         |       |
| Weighted-average fixed price sales per  MMBtu(1) |       | $                                                 | 5.09       |                                              | $          | 4.79 |   |
| Fair value, net (thousands)(3)                   |       | $                                                 | 395        |                                              | $          | (1,667 | ) |
| **Total Natural Gas  Contracts:**                |       |                                              |       |                                              |       |
| Contract volumes (MMBtu)                         |       | 736,000                                           |       | 2,007,500                                         |       |
| Fixed-price sales(2)                             |       | $                                                 | 5.69       |                                              | $          | 4.79 |   |
| Fair value, net (thousands)(3)                   |       | $                                                 | 805        |                                              | $          | (1,667 | ) |

 

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(1)       Volumes hedgedusing the CIG index price published in the first issue of Inside FERC’s GasMarket Report for each calendar month of the derivative transaction.

 

(2)       Assumes ceilingprices for natural gas collar volumes.

 

(3)       Fair value basedon CIG index price in effect for each month as of September 30, 2009.

 

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**Interest Rate Risk**

 

Borrowings under our credit facility bear interest at fluctuatingmarket-based rates.  Accordingly, ourinterest expenses are sensitive to market changes, which expose us to interestrate risk on current and future borrowings under our credit facility.

 

As of September 30, 2009, we had $6.5 million in outstandingindebtedness under our credit facility. Borrowings under the credit facility bear interest either: (i) atthe greater of the one month London Interbank Offered Rate, or LIBOR, plus1.00% or a domestic bank rate, plus in either case an applicable margin of0.75% to 1.75% based on utilization, or (ii) on a sliding scale from theone, two, three or six month LIBOR, plus an applicable margin of 2.00% to 3.00%based on utilization.  The weightedaverage interest rate for borrowings under our credit facility wasapproximately 4.75% for the nine months ended September 30, 2009 and 5.0%for the nine months ended September 30, 2008. A hypothetical change of 1%in either the domestic bank rate or the LIBOR interest rates would increase ordecrease gross interest expense approximately $65,000 per year.

 

**ITEM 4T. CONTROLS AND PROCEDURES**

 

**Disclosure Controls and Procedures**

 

Our principalexecutive officer and principal financial officer are responsible forestablishing and maintaining adequate disclosure controls and procedures.  Based on their evaluation as of the end ofthe period covered by this quarterly report, our principal executive officerand principal financial officer have concluded that our disclosure controls andprocedures (as defined in Rules 13a-15(e) and 15d-15(e) underthe Securities Exchange Act of 1934, as amended (the Exchange Act)) areeffective to ensure that information required to be disclosed in reports thatwe file or submit under the Exchange Act are recorded, processed, summarizedand reported within the time periods specified in the SEC’s rules andforms.

 

**Changes in Internal Control Over Financial Reporting**

 

During the most recent fiscal quarter, there have been no changes inour internal control over financial reporting that have materially affected, orare reasonably likely to materially affect, our internal control over financialreporting.

 

**PART II.OTHER INFORMATION**

 

**ITEM 1. LEGAL PROCEEDINGS**

 

From time to time, we are subject to legal proceedings and claims thatarise in the ordinary course of our business. While the outcome of theseproceedings cannot be predicted with certainty, we do not currently expect themto have a material adverse effect on the financial statements.

 

There have been no material developments during the quarter ended September 30,2009 regarding our currently pending legal proceedings. For a discussion ofcertain of our current legal proceedings, please see [“Note 9 — Contingencies”]of the notes to the unaudited financial statements appearing elsewhere in thisquarterly report.

 

**ITEM 1A. RISK FACTORS**

 

The following discussion supplements or updates the risk factors setforth under the heading “Risk Factors” in our annual report on Form 10-Kfor the year ended December 31, 2008 and in our quarterly report on Form 10-Qfor the nine months ended September 30, 2009.

 

***We continue to experience volatilityin natural gas and oil prices which could have a material adverse******effect on our business.***

 

Our revenues, profitability and future growth and the carrying value ofour natural gas and oil properties depend to a large degree on prevailingnatural gas and oil prices. Our ability to maintain or increase our borrowingcapacity and to obtain additional capital on attractive terms alsosubstantially depends upon natural gas and oil prices. Prices for natural gasand oil are subject to large fluctuations in response to relatively minorchanges in the supply and demand for natural gas and oil, uncertainties withinthe market and a variety of other factors in large part beyond ourcontrol.  During the nine months ended September 30,2009, the NYMEX natural gas index price ranged from a high of $6.07 per MMBtuto a low of $2.51 per MMBtu, while the CIG natural gas index price ranged froma high of $4.59 per MMBtu to a low of $1.33 per MMBtu.  Please see “The volatility of natural gas andoil prices could have a material adverse effect on our business” under RiskFactors in our annual report on Form 10-K for the year ended December 31,2008 for further information related to price volatility.

 

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***Our credit facility has substantial restrictionsand financial covenants that may affect our ability to successfully operate ourbusiness. In addition, we may have difficulty returning to compliance withcertain financial covenants.***

 

Our credit facility imposes certain operational and financialrestrictions on us.  Please see “Ourcredit facility has substantial restrictions and financial covenants that mayaffect our ability to successfully operate our business. In addition, we mayhave difficulty returning to compliance with certain financial covenants” underRisk Factors in our annual report on Form 10-K for the year ended December 31,2008 for further information regarding restrictions under our credit facility.

 

As of September 30, 2009, we were not in compliance with thecurrent ratio financial covenant and certain other covenants related toaccounts payable, permitted liens, and permitted debt under our creditfacility.  On April 14, 2009, thelenders waived compliance with the current ratio as of March 31, 2009, andwith such other restrictive covenants, subject to certain financial caps, untilthe next borrowing base redetermination on October 20, 2009.  On August 19, 2009, the lenders waivedcompliance with the current ratio financial covenant under the Credit Agreementfor the period ending August 26, 2009 and the quarter ending June 30,2009.  On August 26, 2009, weobtained a fifth amendment to the Credit Agreement which provides for anadditional 60-day waiver of the current ratio financial covenant and certainother restrictive covenants through October 26, 2009.  On October 20, 2009 we obtained a sixthamendment to the Credit Agreement whereby our borrowing base became subject tomonthly reductions of $200,000 until maturity or until a new redetermination isreceived.  On October 26, 2009, thelenders provided a waiver effectively extending the terms of the fifthamendment to the Credit Agreement through November 16, 2009.  On November 16, 2009, the lendersprovided an additional waiver effectively extending the terms of the fifthamendment to the Credit Agreement through the November 23, 2009.

 

On November 23, 2009, the lenders provided an additional waiver extendingthe terms of the fifth amendment to the Credit Agreement through December 1,2009 and for the quarter ended September 30, 2009.  We have not been in compliance with certainfinancial covenants for the last five quarters but have obtained waivers and/oramendments in each instance.  As a resultof such non-compliance, we are currently unable to borrow additional fundsunder our credit agreement.  We believethat we may not be in compliance with certain financial and other covenantsthroughout the remainder of 2009, but will seek additional waivers.  There can be no assurance that we will beable to obtain such waivers or that such waivers will be obtained on acceptableterms.  If we are unable to obtain futurewaivers and/or to comply with the covenants, the lenders could accelerate ourindebtedness or foreclose on properties held by liens.

 

***Proposed legislation to eliminate or reduce certainfederal income tax incentives and deductions available to oil and gasexploration and production companies could, if enacted into law, have amaterial adverse effect on our results of operations and cash flows.***

 

On April 23, 2009, the “Oil Industry Tax Break Repeal Act of 2009”was introduced in the U.S. Senate.  Thisbill proposes amendments to the Internal Revenue Code of 1986 to eliminate orreduce certain federal income tax incentives and deductions currently availableto oil and gas exploration and production companies.  The proposed amendments include theelimination or reduction of current deductions for intangible drilling anddevelopment costs, percentage depletion allowances, and the manufacturingdeduction for oil and gas properties.  Ifsome or all of these provisions are enacted into law, our effective tax rateand current income tax expense will increase, potentially significantly, whichwould reduce cash flows from operating activities and in turn reduce cashavailable for drilling and other exploration and development activities.

 

Please see “Management’s Discussion and Analysis of Financial Conditionand Results of Operations—Liquidity and Capital Resources—Credit Facility,” forfurther discussion of our credit facility.

 

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

 

Not applicable.

 

**ITEM3. DEFAULTS UPON SENIOR SECURITIES**

 

Not applicable.

 

**ITEM4. OTHER INFORMATION**

 

Not applicable.

 

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**ITEM 5. EXHIBITS**

 
| **Exhibit****No.** | ** ** | **Description**                                                                                                                                                                                                                                                                                     |
|--------------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.1                | —     | Second Amended and Restated Certificate of Incorporation of Pinnacle  Gas Resources, Inc. (incorporated herein by reference to  Exhibit 3.1 to the Registration Statement on Form S-1 (File  No. 333-133983) filed by Pinnacle Gas Resources, Inc. on  May 10, 2006). |
| 3.2                | —     | Amended and Restated Bylaws of Pinnacle Gas Resources, Inc.  (incorporated herein by reference to Exhibit 3.2 to the Registration  Statement on Form S-1 (File No. 333-133983) filed by Pinnacle Gas  Resources, Inc. on May 10, 2006).                               |
|               |       |                                                                                                                                                                                                                                                                                                |
| 4.1                | —     | Amended and Restated Securityholders Agreement, dated  February 16, 2006 (incorporated herein by reference to Exhibit 4.1  to the Registration Statement on Form S-1 (File No. 333-133983)  filed by Pinnacle Gas Resources, Inc. on May 10, 2006).                   |
|               |       |                                                                                                                                                                                                                                                                                                |
| 4.2                | —     | Registration Rights Agreement, dated April 11, 2006  (incorporated herein by reference to Exhibit 4.2 to the Registration  Statement on Form S-1 (File No. 333-133983) filed by Pinnacle Gas  Resources, Inc. on May 10, 2006).                                       |
|               |       |                                                                                                                                                                                                                                                                                                |
| 10.1               | —     | Fourth Amendment to Credit Agreement, dated as of April 14, 2009  (incorporated herein by reference to Exhibit 10.21 to the Annual Report  on Form 10-K (File No. 001-33457) filed by Pinnacle Gas  Resources, Inc. on April 15, 2009).                               |
|               |       |                                                                                                                                                                                                                                                                                                |
| 10.2               | —     | Waiver to Credit Agreement, dated as of August 19, 2009 (incorporated  herein by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q  filed by Pinnacle Gas Resources on August 19, 2009).                                                                                          |
|               |       |                                                                                                                                                                                                                                                                                                |
| 10.3               | —     | Fifth Amendment to the Credit Agreement, dated August 26, 2009 (incorporated  herein by reference to Exhibit 10.1 to the 8-K filed by Pinnacle Gas  Resources, Inc. on August 27, 2009).                                                                                                       |
|               |       |                                                                                                                                                                                                                                                                                                |
| 10.4               | —     | Sixth Amendment to the Credit Agreement, dated October 20, 2009 (incorporated  herein by reference to Exhibit 10.1 to the 8-K filed by Pinnacle Gas  Resources, Inc. on October 22, 2009).                                                                                                     |
|               |       |                                                                                                                                                                                                                                                                                                |
| 10.5               | —     | Waiver and Amendment, dated October 26, 2009 (incorporated herein  by reference to Exhibit 10.1 to the 8-K filed by Pinnacle Gas Resources, Inc.  on October 29, 2009)                                                                                                                         |
|               |       |                                                                                                                                                                                                                                                                                                |
| 10.6               | —     | Waiver and Amendment, dated November 16, 2009 (incorporated  herein by reference to Exhibit 10.1 to the 8-K filed by Pinnacle Gas  Resources, Inc. on November 19, 2009)                                                                                                                       |
|               |       |                                                                                                                                                                                                                                                                                                |
| 10.7               | —     | Waiver and Amendment, dated November 23, 2009 (incorporated herein by  reference to Exhibit 10.1 to the 8-K filed by Pinnacle Gas Resources, Inc. on  November 23, 2009)                                                                                                                            |
|               |       |                                                                                                                                                                                                                                                                                                |
| *31.1              | —     | Certification of President and Chief Executive Officer of Pinnacle  Gas Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley  Act of 2002.                                                                                                                                       |
|               |       |                                                                                                                                                                                                                                                                                                |
| *31.2              | —     | Certification of Senior Vice President, Chief Financial Officer and  Secretary of Pinnacle Gas Resources, Inc. pursuant to Section 302  of the Sarbanes-Oxley Act of 2002.                                                                                                                |
|               |       |                                                                                                                                                                                                                                                                                                |
| *32.1              | —     | Certification of President and Chief Executive Officer of Pinnacle  Gas Resources, Inc. pursuant to 18 U.S.C. Section 1350, as adopted  pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                   |
|               |       |                                                                                                                                                                                                                                                                                                |
| *32.2              | —     | Certification of Senior Vice President, Chief Financial Officer and  Secretary of Pinnacle Gas Resources, Inc. pursuant to 18 U.S.C.  Section 1350, as adopted pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002.                                                           |

 

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*    Filed herewith

 

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**SIGNATURES**

 

Pursuant to the requirements of the Securities Exchange Act of 1934,the registrant has duly caused this report to be signed on its behalf by theundersigned 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 23, 2009     |
|     |                             |   |   |
|     | By:                              | /s/ Ronald T. Barnes |
|     |                             | Name: | Ronald T. Barnes |
|     |                             | Title: | *Senior Vice President, Chief Financial Officer and* |
| * * |                             |   | *Secretary* |
|     |                             |   | (Principal Financial Officer and |
|     |                             |   | Principal Accounting Officer) |
|     |                             |   |   |
|     | Date: November 23, 2009     |

 

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