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**UNITEDSTATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

 

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

 

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

 

**For thetransition period from                    to                     **

 

**Commissionfile number: 001-33457**

 

**PinnacleGas Resources, Inc.**

(Exactname of registrant as specified in its charter)

 

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

 

**(307)673-9710**

(Registrant’s telephonenumber, including area code)

 

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

 

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

 

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

 

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

 

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

 

29,722,111 sharesof the registrant’s Common Stock were outstanding as of August 18, 2009.

 

 

 

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**PINNACLEGAS RESOURCES, INC.**

 

**Indexto Form 10-Q**

 
| ** **                                                                                           | **Page** |
|------------------------------------------------------------------------------------------------------|----------|
| Cautionary  Statement Concerning Forward-Looking Statements                                          | 1        |
| Part I.  FINANCIAL INFORMATION                                                                  | 3        |
| Item 1.  Financial Statements                                                                        | 3        |
| Balance Sheets as of December 31, 2008 and  June 30, 2009 (unaudited)                      | 3        |
| Statements of Operations for the three and six months  ended June 30, 2009 and 2008 (unaudited) | 4        |
| Statements  of Cash Flows for the six months ended June 30, 2009 and 2008  (unaudited)          | 5        |
| Statements of Stockholders’ Equity at June 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                                                                         | 21       |
| Trends Affecting Our Business                                                                        | 25       |
| Results  of Operations                                                                               | 26       |
| Liquidity and Capital Resources                                                                      | 30       |
| Item 3. Quantitative and Qualitative Disclosures About  Market Risk                                  | 33       |
| Item 4T. Controls and Procedures                                                                     | 34       |
| Part II.  OTHER INFORMATION                                                                     | 34       |
| Item  1. Legal Proceedings                                                                           | 34       |
| Item  1A. Risk Factors                                                                               | 34       |
| Item 2. Unregistered Sales of Equity Securities and  Use of Proceeds                                 | 35       |
| Item 3. Defaults Upon Senior Securities                                                              | 35       |
| Item 4. Submission of Matters to a Vote of Security  Holders                                         | 35       |
| Item  5. Other Information                                                                           | 36       |
| Item 6.  Exhibits                                                                                    | 36       |

 

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**CAUTIONARY STATEMENT CONCERNINGFORWARD-LOOKING STATEMENTS**

 

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

 

· our financial position or operating results;

 

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

 

· our business strategy;

 

· our budget;

 

· the amount, nature and timing of capital expenditures;

 

· the drilling of wells;

 

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

 

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

 

· our operating costs and other expenses;

 

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

 

· our cash flow and anticipated liquidity; and

 

· our other plans and objectives for future operations

 

When we use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,”“could,” “estimate,” “plan,” “predict,” “project,” their negatives, or 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;

 

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

 

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

 

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

 

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

 

· production variances from expectations;

 

· our ability to develop and replace reserves;

 

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

 

· potential mechanical failure or under-performance ofsignificant wells;

 

· 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 otherlimitations on our or others’ pipeline systems;

 

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

 

· our ability to effectively market our production;

 

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

 

· general economic 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.

 

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**Part I. FINANCIAL INFORMATION**

 

**ITEM 1. FINANCIAL STATEMENTS**

 

**PINNACLEGAS RESOURCES, INC.**

**Balance Sheets**

 
| ** **                                                                                                                                                                         | ** ** | **June 30,********2009** | ** ** | **December 31,********2008** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------|------------|-----------------------------------|------------|
| ** **                                                                                                                                                                         | ** ** | **(unaudited)**               | ** ** | **(audited)**                     | ** ** |
| ** **                                                                                                                                                                         | ** ** | **(in  thousands, except**    | ** ** |
| ** **                                                                                                                                                                         | ** ** | **share  and**                | ** ** |
| ** **                                                                                                                                                                         | ** ** | **per  share data)**          | ** ** |
| **Assets**                                                                                                                                                                         |       |                          |       |                              |       |
| Current assets                                                                                                                                                                     |       |                          |       |                              |       |
| Cash and cash equivalents                                                                                                                                                          |       | $                             | 47         |                              | $          | 346 |   |
| Receivables                                                                                                                                                                        |       |                          |       |                              |       |
| Accrued gas sales                                                                                                                                                                  |       | 747                           |       | 2,091                             |       |
| Joint interest receivables, net of $100 allowance  for doubtful accounts                                                                                                           |       | 1,453                         |       | 4,824                             |       |
| Derivative instruments                                                                                                                                                             |       | 2,541                         |       | 4,345                             |       |
| Inventory of material for drilling and completion                                                                                                                                  |       | 57                            |       | 83                                |       |
| Prepaid expenses                                                                                                                                                                   |       | 96                            |       | 196                               |       |
| Total current assets                                                                                                                                                               |       | 4,941                         |       | 11,885                            |       |
| Property and equipment, at cost, net of accumulated  depreciation                                                                                                                  |       | 1,526                         |       | 1,798                             |       |
| Oil and gas properties, using full cost accounting,  net of accumulated depletion and impairment                                                                                   |       |                          |       |                              |       |
| Proved                                                                                                                                                                             |       | 10,840                        |       | 34,522                            |       |
| Unproved                                                                                                                                                                           |       | 86,483                        |       | 86,827                            |       |
| Inventory of material held for exploration and  development                                                                                                                        |       | 404                           |       | 384                               |       |
| Deposits                                                                                                                                                                           |       | 64                            |       | 199                               |       |
| Restricted certificates of deposit                                                                                                                                                 |       | 2,740                         |       | 2,725                             |       |
| Total assets                                                                                                                                                                       |       | $                             | 106,998    |                              | $          | 138,340 |   |
| **Liabilities and Stockholders’  Equity**                                                                                                                                     |       |                          |       |                              |       |
| Current liabilities                                                                                                                                                                |       |                          |       |                              |       |
| Long term debt-current portion                                                                                                                                                     |       | $                             | 8,077      |                              | $          | 11,530 |   |
| Trade accounts payable                                                                                                                                                             |       | 9,334                         |       | 10,112                            |       |
| Revenue distribution payable                                                                                                                                                       |       | 2,911                         |       | 4,625                             |       |
| Drilling prepayments from joint interest owners                                                                                                                                    |       | 56                            |       | —                            |       |
| Asset retirement obligations, current                                                                                                                                              |       | 319                           |       | 341                               |       |
| Accrued liabilities                                                                                                                                                                |       | 2,846                         |       | 1,539                             |       |
| Total current liabilities                                                                                                                                                          |       | 23,543                        |       | 28,147                            |       |
| Asset retirement  obligations, non-current                                                                                                                                         |       | 3,138                         |       | 3,025                             |       |
| Derivative Instruments, non-current                                                                                                                                                |       | 328                           |       | —                            |       |
| Production taxes, non-current                                                                                                                                                      |       | 409                           |       | 1,156                             |       |
| Long term debt – net of current portion                                                                                                                                       |       | 762                           |       | 733                               |       |
| Total liabilities                                                                                                                                                                  |       | 28,180                        |       | 33,061                            |       |
| Commitments and contingencies                                                                                                                                                      |       |                          |       |                              |       |
| Stockholders’ equity                                                                                                                                                          |       |                          |       |                              |       |
| Common stock, $0.01 par value; 100,000,000  authorized and 29,722,111 and 29,193,573 shares issued and outstanding at  June 30, 2009 and December 31, 2008, respectively |       | 289                           |       | 289                               |       |
| Additional paid-in capital                                                                                                                                                         |       | 151,387                       |       | 150,879                           |       |
| Accumulated deficit                                                                                                                                                                |       | (72,858                       | )          | (45,889                           | )          |
| Total stockholders’ equity                                                                                                                                                    |       | 78,818                        |       | 105,279                           |       |
| Total liabilities and stockholders’ equity                                                                                                                                    |       | $                             | 106,998    |                              | $          | 138,340 |   |

 

See Notes toFinancial Statements (unaudited)

 

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**PINNACLEGAS RESOURCES, INC.**

**Statements of Operations**

**(unaudited)**

 
| ** **                                                    | ** ** | **Three  Months Ended**             | ** ** | **Six  Months Ended** | ** ** |
|---------------------------------------------------------------|------------|-------------------------------------|------------|-----------------------|------------|
| ** **                                                    | ** ** | **June 30,**                   | ** ** | **June 30,**     | ** ** |
| ** **                                                    | ** ** | **2009**                            | ** ** | **2008**              | ** ** | **2009** | ** ** | **2008** | ** ** |
|                                                          |       | **(in thousands, except share and** |       |
| ** **                                                    | ** ** | **per share data)**                 | ** ** |
| Revenues                                                      |       |                                |       |                  |       |   |   |   |   |
| Gas sales                                                     |       | $                                   | 1,605      |                  | $          | 7,573 |   | $ | 4,370 |   | $ | 13,234 |   |
| Total revenues                                                |       | 1,605                               |       | 7,573                 |       | 4,370 |   | 13,234 |   |
| Cost of revenues and expenses                                 |       |                                |       |                  |       |   |   |   |   |
| Lease operating expenses                                      |       | 939                                 |       | 1,348                 |       | 2,124 |   | 3,398 |   |
| Production taxes                                              |       | 140                                 |       | 860                   |       | 418 |   | 1,519 |   |
| Marketing and transportation                                  |       | 895                                 |       | 1,210                 |       | 2,145 |   | 2,287 |   |
| General and administrative, net                               |       | 1,183                               |       | 3,217                 |       | 2,214 |   | 4,591 |   |
| Depreciation, depletion, amortization and accretion           |       | 916                                 |       | 2,284                 |       | 2,744 |   | 4,013 |   |
| Impairment of oil and gas properties                          |       | 6,431                               |       | —                |       | 23,250 |   | — |   |
| Total cost of revenues and expenses                           |       | 10,504                              |       | 8,919                 |       | 32,895 |   | 15,808 |   |
| Operating loss                                                |       | (8,899                              | )          | (1,346                | )          | (28,525 | ) | (2,574 | ) |
| Other income (expense)                                        |       |                                |       |                  |       |   |   |   |   |
| Gain (loss) on derivatives                                    |       | (651                                | )          | (2,664                | )          | 1,377 |   | (7,235 | ) |
| Interest income                                               |       | 26                                  |       | 34                    |       | 34 |   | 99 |   |
| Other income                                                  |       | 95                                  |       | 122                   |       | 200 |   | 223 |   |
| Interest expense                                              |       | (30                                 | )          | (20                   | )          | (55 | ) | (35 | ) |
| Total other income (expense)                                  |       | (560                                | )          | (2,528                | )          | 1,556 |   | (6,948 | ) |
| Net loss before income taxes                                  |       | (9,459                              | )          | (3,874                | )          | (26,969 | ) | (9,522 | ) |
| Income taxes                                                  |       | —                              |       | —                |       | — |   | — |   |
| Net loss attributable to common stockholders                  |       | $                                   | (9,459     | )                     | $          | (3,874 | ) | $ | (26,969 | ) | $ | (9,522 | ) |
| Basic and diluted net loss per share                          |       | $                                   | (0.32      | )                     | $          | (0.13 | ) | $ | (0.92 | ) | $ | (0.33 | ) |
| Weighted average shares outstanding — basic and  diluted |       | 29,364,087                          |       | 29,000,101            |       | 29,277,885 |   | 29,008,000 |   |

 

See Notes to FinancialStatements (unaudited)

 

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**PINNACLEGAS RESOURCES, INC.**

**Statements of Cash Flows**

**(inthousands)**

**(unaudited)**

 
| ** **                                                                         | ** ** | **For  the Six Months********Ended********June 30,** | ** ** |
|------------------------------------------------------------------------------------|------------|-----------------------------------------------------------|------------|
| ** **                                                                         | ** ** | **2009**                                                  | ** ** | **2008** | ** ** |
| Cash flows from operating activities                                               |       |                                                      |       |   |   |
| Net loss                                                                           |       | $                                                         | (26,969    | ) | $ | (9,522 | ) |
| Adjustments to reconcile net loss to net cash  provided by operating activities    |       |                                                      |       |   |   |
| Impairment of oil and gas properties                                               |       | 23,250                                                    |       | — |   |
| Depreciation, depletion, amortization and accretion                                |       | 2,723                                                     |       | 4,013 |   |
| (Gain) loss on derivatives                                                         |       | (1,377                                                    | )          | 7,235 |   |
| Stock-based compensation                                                           |       | 508                                                       |       | 433 |   |
| Changes in assets and liabilities                                                  |       |                                                      |       |   |   |
| Decrease (increase) in receivables                                                 |       | 1,515                                                     |       | (3,975 | ) |
| Decrease in inventory of material for drilling and  completion                     |       | 26                                                        |       | 40 |   |
| Decrease in prepaid expenses                                                       |       | 100                                                       |       | 1,144 |   |
| Increase in trade accounts payable and accrued  liabilities and production taxes   |       | 820                                                       |       | 3,853 |   |
| (Decrease) increase in revenue distribution payable                                |       | (1,714                                                    | )          | 1,814 |   |
| Decrease (increase) in drilling prepayments from  joint interest owners            |       | 56                                                        |       | (19 | ) |
| Net cash provided by (used in) operating activities                                |       | (1,062                                                    | )          | 5,016 |   |
| Cash flows from investing activities                                               |       |                                                      |       |   |   |
| Capital expenditures — exploration and production                             |       | (2,488                                                    | )          | (14,377 | ) |
| Capital expenditures — property and equipment                                 |       | (88                                                       | )          | (358 | ) |
| Proceeds received from sale of oil and gas  properties                             |       | 3,200                                                     |       | — |   |
| Decrease (increase) in purchase of restricted  certificate of deposit and deposits |       | 120                                                       |       | (1,589 | ) |
| (Increase) decrease in inventory held for  exploration and development             |       | (20                                                       | )          | 115 |   |
| Realized gain (loss) on derivatives                                                |       | 3,510                                                     |       | (769 | ) |
| Net cash provided by (used in) investing activities                                |       | 4,234                                                     |       | (16,978 | ) |
| Cash flows from financing activities                                               |       |                                                      |       |   |   |
| Principal payments on note payable                                                 |       | (3,471                                                    | )          | (11 | ) |
| Proceeds from long-term debt                                                       |       | —                                                    |       | 5,000 |   |
| Issuance costs related to common stock                                             |       | —                                                    |       | (6 | ) |
| Net cash (used in) provided by financing activities                                |       | (3,471                                                    | )          | 4,983 |   |
| Net decrease in cash and cash equivalents                                          |       | (299                                                      | )          | (6,979 | ) |
| Cash and cash equivalents at beginning of the year                                 |       | 346                                                       |       | 8,151 |   |
| Cash and cash equivalents at June 30, 2009 and  2008, respectively            |       | $                                                         | 47         |   | $ | 1,172 |   |
| Noncash investing and financing activities                                         |       |                                                      |       |   |   |
| Capital expenditures included in trade accounts  payable                           |       | $                                                         | 6,740      |   | $ | 8,352 |   |
| Asset retirement obligation included in oil and gas  properties                    |       | —                                                    |       | 268 |   |
| Supplemental cash flow information                                                 |       |                                                      |       |   |   |
| Cash payments for interest, net of amount  capitalized                             |       | $                                                         | 55         |   | $ | 35 |   |

 

See Notes toFinancial Statements (unaudited)

 

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**PINNACLEGAS RESOURCES, INC.**

**Statement of Stockholders’ Equity**

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

 
| ** **                                   | ** ** | ** **       | ** ** | ** **              | ** ** | **Stockholders’  Equity** | ** ** |
|----------------------------------------------|------------|------------------|------------|-------------------------|------------|--------------------------------|------------|
| ** **                                   | ** ** | **Common Stock** | ** ** | **Warrants********and** | ** ** | **Additional********Paid-In**  | ** ** | **Accumulated** | ** ** | ** ** | ** ** |
| ** **                                   | ** ** | **Shares**       | ** ** | **Amount**              | ** ** | **Options**                    | ** ** | **Capital** | ** ** | **Deficit** | ** ** | **Total** | ** ** |
|                                         |       |             |       |                    |       |                           |       |   |   |   |   |   |   |
| Balance at  December 31, 2008           |       | 29,193,573       |       | $                       | 289        |                           | —     |   | $ | 150,879 |   | $ | (45,889 | ) | $ | 105,279 |   |
| Issuance of restricted  shares (unaudited)   |       | 534,102          |       | —                  |       | —                         |       | 289 |   | — |   | 289 |   |
| Forfeiture of restricted  shares (unaudited) |       | (5,564           | )          | —                  |       | —                         |       | — |   | — |   | — |   |
| Stock-based compensation  (unaudited)        |       | —           |       | —                  |       | —                         |       | 219 |   | — |   | 219 |   |
| Net loss (unaudited)                         |       | —           |       | —                  |       | —                         |       | — |   | (26,969 | ) | (26,969 | ) |
| Balance at June 30,  2009 (unaudited)   |       | 29,722,111       |       | $                       | 289        |                           | —     |   | $ | 151,387 |   | $ | (72,858 | ) | $ | (78,818 | ) |

 

See Notes toFinancial Statements (unaudited)

 

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**Notes to Financial Statements**

**(Unaudited)**

 

**Note1 — Organization and Nature of Operations**

 

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

 

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

 

Due to the currenteconomic and pricing environment, the Company is actively marketing certainassets to raise additional capital and is also reviewing alternatives forraising 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 swap 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 swap and a costlesscollar at a weighted average floor price of $5.44 per MMbtu and a ceiling priceof $5.69 per MMbtu. The hedges were executed based on the Colorado InterstateGas price. The Company has also implemented various cost cutting measures,including reducing general and administrative costs through staff reductions,wage and benefit cuts and a hiring freeze. The Company has reduced leaseoperating expenses by renegotiating water disposal contracts, reducing servicecosts 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, are being taken to make operations sustainable in the future.Although the Company is pursuing various alternatives to provide additionalliquidity, there is no assurance of the likelihood or timing of any of thesetransactions.

 

**Note2 — 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 six months of 2009.  The results for the three and six monthsending June 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 ExchangeCommission, which can be found on the Company’s website at *www.pinnaclegas.com*.

 

*Use of Estimates*

 

The preparation of the Company’s financial statementsin conformity with accounting principles generally accepted in the UnitedStates of America requires management to make estimates and assumptions thataffect the reported amount of assets and liabilities, disclosure of contingentassets and liabilities at the date of the financial statements and the reportedamounts of revenues and expenses during the reporting period. Actual resultscould differ from these estimates. Significant estimates with regard to theCompany’s financial statements include the estimated carrying value of unprovedproperties, the estimate of proved oil and gas reserve volumes and the relatedpresent value of estimated future net cash flows, the ceiling test applied tocapitalized oil and gas 

 

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properties, the estimate of the timing and cost of the Company’s futuredrilling activity, the estimated cost and timing related to asset retirementobligations, the estimated fair value of derivative assets and liabilities, therealizability of deferred tax assets, the estimates of expenses and timing ofexercise of stock options, accrual of operating costs and capital expendituresand revenue.

 

*Oiland 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 anddevelopment, including costs of unsuccessful exploration, costs of surrendered andabandoned leaseholds, delay lease rentals and the fair value of estimatedfuture costs of site restoration, dismantlement and abandonment activities arecapitalized within a cost center. The Company’s oil and gas properties are alllocated within the United States, which constitutes a single cost center. TheCompany capitalizes 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 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 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 isaccounted for as an adjustment to capitalized costs related to proved oil andgas properties, with no losses recognized. No impairment was recorded forunevaluated properties for the three and six months ended June 30,2009.  Substantially all of the remainingunproved property costs are expected to be developed and included in theamortization base over the next three to five years.  Salvage value is taken into account indetermining depletion rates and is based on the Company’s estimate of the valueof equipment and supplies at the time the well is abandoned.  As of June 30, 2009 and December 31,2008, the estimated salvage value was approximately $7.2 million and $7.1million, 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 June 30,2009, the capitalized cost of the Company’s oil and gas properties exceeded thefull cost ceiling limitation by approximately $9.0 million based upon a naturalgas price of approximately $2.69 per Mcf in effect at that date.  Based on the subsequent price increase to $3.09per Mcf on August 12, 2009, the capitalized cost exceeded the full cost ceilinglimitation by $6.4 million. Therefore, an impairment of approximately $6.4million was taken for the quarter ended June 30, 2009.  This impairment of the Company’s oil and gasproperties resulted from low commodity prices in the second quarter of 2009.  No impairment was taken for the quarter endedJune 30, 2008 based on a natural gas price of $8.73 per Mcf.

 

*PerShare Information*

 

Basic loss per share is computed by dividing net loss from continuingoperations attributable to common stock by the weighted average number ofshares of common stock outstanding during each period. Diluted earnings pershare is computed by adjusting the average number of shares of common stockoutstanding for the dilutive effect, if any, of common stock equivalents such asstock options and warrants. Diluted net loss per share is the same as basic netloss per share for all periods presented because potential common stockequivalents were anti-dilutive. For all periods in which there was a net lossattributable to stockholders, all of the Company’s stock options and warrantswere anti-dilutive. Common stock equivalents of 842,280, and 750,000 at June 30,2009, 

 

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and 2008,respectively, were excluded because they were anti-dilutive due to the net lossattributable to stockholders incurred in such periods.

 

*IncomeTaxes*

 

The Company usesthe asset and liability method of accounting for income taxes, in accordancewith Statement of Financial Accounting Standards (SFAS) No. 109, ‘‘Accountingfor Income Taxes.’’ Deferred tax assets and liabilities are recognized for theexpected future tax consequences of temporary differences between the financialstatements and tax basis of assets and liabilities. If appropriate, deferredtax assets are reduced by a valuation allowance which reflects expectations ofthe extent to which such assets will be realized. As of June 30, 2009 and December 31,2008, the Company had recorded a full valuation allowance for its net deferredtax asset.

 

On January 1,2007, the Company adopted Financial Accounting Standards Board (FASB)Interpretation No. 48, ‘‘Accounting for Uncertainty in Income Taxes—aninterpretation of FASB Statement No. 109’’ (FIN 48). FIN 48 prescribes ameasurement process for recording in the financial statements uncertain taxpositions taken or expected to be taken in a tax return. FIN 48 requires thatthe Company recognize in its consolidated financial statements only those taxpositions that are ‘‘more-likely-than-not’’ of being sustained as of theadoption date, based on the technical merits of the position. As a result ofthe implementation of FIN 48, the Company performed a comprehensive review ofits material tax positions in accordance with recognition and measurementstandards established by FIN 48. As a result of this review, the Company didnot identify any material deferred tax assets that required adjustment. As of June 30,2009 and 2008 the Company had not recorded any material uncertain tax benefits.

 

The Company’spolicy is to recognize interest and penalties related to uncertain tax benefitsin income tax expense. As of June 30, 2009 and 2008, the Company had notrecognized 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.

 

*NewAccounting Pronouncements*

 

EffectiveJanuary 1, 2008, the Company adopted the fair value measurement anddisclosure provisions of SFAS No. 157, “Fair Value Measurements,” which establishes specific criteriafor the fair value measurements of financial and nonfinancial assets andliabilities that are already subject to fair value measurements under currentaccounting rules. SFAS No. 157 also requires expanded disclosures relatedto fair value measurements. In February 2008, the FASB approved FASB StaffPosition (FSP) SFAS No. 157-2, “Effective Date of FASB Statement No. 157,”which allows companies to elect a one-year delay in applying SFAS No. 157to certain fair value measurements, primarily related to nonfinancialinstruments. The Company elected the delayed adoption date for the portions ofSFAS No. 157 impacted by FSP SFAS No. 157-2. The partial adoption ofSFAS No. 157 was prospective and did not have a significant effect on theCompany’s financial statements.  On January 1,2009, the Company adopted the provisions for nonfinancial assets andnonfinancial liabilities that are not required or permitted to be measured atfair value on a recurring basis, which include, among others, those nonfinanciallong-lived assets measured at fair value for impairment assessment and assetretirement obligations initially measured at fair value. Fair value used in theinitial recognition of asset retirement obligations is determined based on thepresent value of expected future dismantlement costs incorporating our estimateof inputs 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 October 2008,the FASB issued FSP SFAS No. 157-3, “Determining the Fair Value of aFinancial Asset When the Market for That Asset is Not Active.” FSP SFAS No. 157-3clarifies the application of SFAS No. 157, which the Company adopted as ofJanuary 1, 2008, in situations where the market is not active. The Companyhas considered the guidance provided by FSP SFAS No. 157-3 in itsdetermination of estimated fair values as of June 30, 2009.

 

In April 2009,the Financial Accounting Standards Board issued FASB Staff Position(FSP) FAS 107-1 and APB 28-1 “Interim Disclosures about Fair Value ofFinancial Instruments,” which requires disclosures about fair value offinancial instruments in interim reporting periods. The FSP is effective forinterim and annual periods ending after June 15, 2009, with early adoptionpermitted for periods ending after March 15, 2009. Adoption of this FSPdid not have a material impact on the Company’s financial statements.

 

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In April 2009, the FASB issued FSP No. 157-4, “Determining Fair Value When the Volume andLevel of Activity for the Asset or Liability Have Significantly Decreased andIdentifying Transactions That Are Not Orderly” (“FSP FAS 157-4”), whichprovides additional guidance for estimating fair value in accordance with SFAS No. 157,“Fair Value Measurements” (“SFASNo. 157”).  FSP FAS 157-4 is effectivefor the quarter ending June 30, 2009.  Adoption of this FSP didnot have a material impact on the Company’s financial statements.

 

In December 2007,the FASB issued SFAS No. 141(R), ‘‘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. SFAS No. 141(R) also establishes guidance for the measurement of the acquirer sharesissued in consideration for a business combination, the recognition ofcontingent consideration, the accounting treatment pre-acquisition gain andloss contingencies, the treatment of acquisition related transaction costs, andthe recognition of changes in the acquirer’s income tax valuation allowance anddeferred taxes. SFAS No. 141(R) is effective for fiscal yearsbeginning after December 15, 2008 and is to be applied prospectively as ofthe beginning of the fiscal year in which the statement is applied. Earlyadoption is not permitted. SFAS No. 141(R) is effective for theCompany beginning with the 2009 fiscal year. The impact of the adoption of SFASNo. 141(R) on Company’s financial statements will largely bedependent on the size and nature of the business combinations completed afterthe adoption of this statement.

 

In March 2008,the FASB issued SFAS No. 161, “Disclosures about Derivative Instrumentsand Hedging Activities.” SFAS No. 161 is intended to improve financialreporting by requiring transparency about the location and amounts ofderivative instruments in an entity’s financial statements, how derivativeinstruments and related hedged items are accounted for under SFAS No. 133,“Accounting for Derivative Instruments and Hedging Activities,” and howderivative instruments and related hedged items affect its financial position,financial performance and cash flows. SFAS No. 161 is effective forfinancial statements issued for fiscal years and interim periods beginningafter November 15, 2008. The adoption of this pronouncement has not had animpact on the Company’s financial statements, but it has required the Companyto expand its disclosures about derivative instruments.

 

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 petroleum resources that wasdeveloped by several industry organizations. Key revisions include changes tothe pricing used to estimate reserves, the ability to include nontraditionalresources in reserves, the use of new technology for determining reserves, andpermitting disclosure of probable and possible reserves. The SEC will requirecompanies to comply with the amended disclosure requirements for registrationstatements filed after January 1, 2010 and for annual reports for fiscalyears ending on or after December 15, 2009. Early adoption is notpermitted. The Company is currently assessing the impact that the adoption willhave on the Company’s disclosures, operating results, financial position, andcash flows.

 

On April 1, 2009, the Company adopted SFAS No. 165 whichestablished general standards of accounting for and disclosures of events thatoccur after the balance sheet date but before financial statements are issuedor are available to be issued.  SFAS No. 165requires companies to disclose the date through which the company evaluatedsubsequent events, the basis for that date, and whether that date representsthe date the financial statements were issued. In accordance with SFAS 165, the Company’s management has evaluatedevents subsequent to June 30, 2009 through August 18, 2009 which isthe issuance date of this report.  There has been no material event notedin this period which would either impact the results reflected in this reportor the Company’s results going forward.

 

In June 2009, the FASB issued SFAS No. 168, “The FASBAccounting Standards Codification and the Hierarchy of Generally AcceptedAccounting Principles, a replacement of FASB Statement No. 162” (“SFAS No. 168”). SFAS No. 168 establishes the FASBAccounting Standards Codification as the source of authoritative U.S. generallyaccepted accounting principles (“GAAP”) recognized by the FASB to be applied torules and interpretive releases of the SEC, under federal securities laws,as authoritative GAAP for SEC registrants. SFAS No. 168 is effective for interim and annual periods ending onor after September 15, 2009.

 

**Note3 — Asset Retirement Obligations**

 

The Companyfollows the provisions of Statement of Financial Accounting Standards (SFAS) No. 143,‘‘Accounting for Asset Retirement Obligations.’’ SFAS No. 143 generallyapplies to legal obligations associated with the retirement of long-livedassets that result from the acquisition, construction, development and/or normaloperation of a long-lived asset. SFAS No. 143 requires the Company torecognize an estimated liability for costs associated with the abandonment ofits oil and gas properties.

 

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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 June 30,2009 and December 31, 2008 was the prime rate plus 7% or 10.25%. Revisionsto the liability could occur due to changes in estimated abandonment costs,changes in well economic lives or if federal or state regulators enact newrequirements regarding the abandonment of wells. For the quarter ended June 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 six months ended June 30, 2009 and June 30,2008 (unaudited).

 
| ** **                                     | ** ** | **For  the Three********Months Ended********June 30,** | ** ** | **For  the Six********Months Ended********June 30,** | ** ** | **For  the Three********Months Ended********June 30,** | ** ** | **For  the Six********Months Ended********June 30,** | ** ** |
|------------------------------------------------|------------|-------------------------------------------------------------|------------|-----------------------------------------------------------|------------|-------------------------------------------------------------|------------|-----------------------------------------------------------|------------|
| ** **                                     | ** ** | **2009**                                                    | ** ** | **2008**                                                  | ** ** |
| Beginning balance asset retirement obligations |       | $                                                           | 3,422      |                                                      | $          | 3,366                                                       |       | $                                                         | 2,926      |   | $ | 2,767 |   |
| Additional obligation added during the period  |       | —                                                      |       | —                                                    |       | 167                                                         |       | 268                                                       |       |
| Obligations settled during the period          |       | (23                                                         | )          | (23                                                       | )          | —                                                      |       | —                                                    |       |
| Accretion expense                              |       | 58                                                          |       | 114                                                       |       | 61                                                          |       | 119                                                       |       |
| Ending balance of asset retirement obligations |       | $                                                           | 3,457      |                                                      | $          | 3,457                                                       |       | $                                                         | 3,154      |   | $ | 3,154 |   |

 

**Note4 —****Restricted Assets (Certificates of Deposit), SuretyBonds and Deposits**

 

*Certificatesof deposit.*

 

The Company holds a certificate of deposit (“CD”), which expires in July 2010,totaling $159,000. The CD is collateral on 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 ofJune 30, 2009. The issuer of the bonds has commenced litigation againstthe 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 June 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 that expires in April 2010 in favor of BitterCreek Pipelines, LLC to secure the construction of a high pressure pipeline andrelated compression facilities to the Company’s Deer Creek and Kirby areas. TheCompany has included this amount in non-current assets as of June 30, 2009because the pipeline and compression facilities are not expected to becompleted and fully utilized until the end of 2010.

 

*SuretyBonds.*

 

In June, 2009, the Company posted additional idle well surety forapproximately $13,000 to the Wyoming Oil & Gas ConservationCommission. This was the first monthly installment of 18 that the Commissionhas requested for surety on wells that will need to be plugged by Pinnacle. Thesurety amount may be adjusted downward by the Commission if the Company aggressivelyand successfully plugs the proposed wells in question. These amounts areincluded in restricted certificates of deposits in the accompanying balancesheet at June 30, 2009.

 

*Deposits.*

 

The Company hasincluded approximately $75,000 related to royalty payments in depositspartially offset by a timing difference of $11,000 for water disposal chargesbilled to joint interest owners. These amounts are included in Deposits in theaccompanying balance sheet at June 30, 2009.

 

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**Note5 — Derivatives**

 

The Company has elected not to designate its derivatives as cash flowhedges under provisions of SFAS No. 133. These derivative instruments aremarked to market at the end of each reporting period and changes in the fairvalue are recorded in the accompanying statements of operations. The aggregatefair values of these contracts were estimated to be assets totaling $2,213,000and a liability of $5,910,000 at June 30, 2009 and 2008, respectively. TheCompany realized a hedging gain of $2,053,000 and a hedging loss of $676,000for the quarters ended June 30, 2009 and 2008, respectively. As a resultof the change in the fair value of the commodity derivatives, the Company hadan unrealized loss of $2,704,000 and $1,988,000 for the quarters ended June 30,2009 and June 30, 2008 respectively. The aggregate of these contractsresulted in the loss on derivatives of $651,000 and $2,664,000 for the threemonths ended June 30, 2009 and 2008, respectively. For the six monthsended June 30, 2009, the Company realized a hedging gain of $3,510,000compared to a hedging loss of $769,000 for the six months ended June 30,2008. The Company had an unrealized loss of $2,133,000 and $6,466,000 for thesix months ended June 30, 2009 and 2008, respectively. The aggregate ofthese contracts resulted in a gain on derivatives of $1,377,000 and a loss onderivatives of $7,235,000 for the six months ended June 30, 2009 and 2008,respectively. Unrealized and realized gains and losses are included in thegains or losses on derivatives in the statement of operations. Because theCompany’s derivative contracts were not accounted for as cash flow hedges, theCompany classifies the realized gains and losses in the investment activitiesin the accompanying statement of cash flows.

 

As of June 30, 2009 and 2008, the Company had natural gas hedgesin place as follows:

 
| **Product and Type of Hedging Contract** | ** ** | **MMbtu  Per********Day** | ** ** | **Fixed  Price********Range********CIG Index Price** | ** ** | **Time********Period** | ** ** |
|------------------------------------------|------------|---------------------------|------------|------------------------------------------------------|------------|------------------------|------------|
| June 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                    |       | 1,000                     |       | $5.50                                                |       | 01/10-12/10            |       |
| June 30, 2008 (unaudited)           |       |                      |       |                                                 |       |                   |       |
| Natural Gas—Swap                    |       | 2,500                     |       | $6.63                                                |       | 02/08-12/08            |       |
| Natural Gas—Collar                  |       | 2,000                     |       | $6.50–$7.50                                     |       | 01/09-12/09            |       |
| Natural Gas—Swap                    |       | 1,500                     |       | $7.44                                                |       | 03/08-12/08            |       |
| Natural Gas—Swap                    |       | 2,500                     |       | $7.17                                                |       | 01/09-12/09            |       |
| Natural Gas—Collar                  |       | 3,000                     |       | $6.50–$8.20                                     |       | 01/08-12/08            |       |

 

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.

 

**Note6 — Stock Based Compensation**

 

*Optionsunder 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 June 30,2009, there were options to purchase 640,000 shares granted under the plan.

 

The options granted since formation in June 2003 vest in generalas follows:

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

 

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At June 30, 2009, the Company had unvested options to purchase25,000 shares with a weighted average grant date fair value of $91,000. Duringthe three months ended June 30, 2009, the Company did not grant anyoptions to purchase common stock. The Company will recognize compensationexpense relating to nonvested options granted after January 1, 2006ratably over the next two years. During the three and six months ended June 30,2009 the Company recognized an expense of approximately $96,000 and $217,000,respectively, based on the fair value of the vested options.

 

The following table summarizes stock option activity for the six monthsended June 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, June 30, 2009 (unaudited) |       | 640,000                      |       | $                                                            | 5.81       |                                                                 | 2.83       |                                 | $          | — |   |
| Exercisable, June 30, 2009 (unaudited) |       | 615,000                      |       | $                                                            | 5.65       |                                                                 | 2.76       |                                 | $          | — |   |

 

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

 
| ** **          | ** ** | **Options  Outstanding**                        | ** ** | **Options  Exercisable**                                             | ** ** | ** **                    | ** ** |
|---------------------|------------|-------------------------------------------------|------------|----------------------------------------------------------------------|------------|-------------------------------|------------|
| **Exercise Prices** | ** ** | **Number  of********shares********Outstanding** | ** ** | **Weighted********Average********Remaining********Contractual Life** | ** ** | **Number********Exercisable** | ** ** | **Weighted********Average********Exercise Price** | ** ** | **Fair  Value********Determination** | ** ** |
| $4.00               |       | 137,500                                         |       | 1.3 years                                                            |       | 137,500                       |       | $ | 4.00 |   | Black-Scholes  (minimum value) |   |
| $4.80               |       | 265,000                                         |       | 2.7 years                                                            |       | 265,000                       |       | $ | 4.80 |   | Black-Scholes  (minimum value) |   |
| $5.20               |       | 112,500                                         |       | 3.5 years                                                            |       | 112,500                       |       | $ | 5.20 |   | Black-Scholes |   |
| $8.40               |       | 25,000                                          |       | 4.9 years                                                            |       | 12,500                        |       | $ | 8.40 |   | Black-Scholes |   |
| $11.00              |       | 100,000                                         |       | 4.0 years                                                            |       | 87,500                        |       | $ | 11.00 |   | Black-Scholes |   |
| Total               |       | 640,000                                         |       |                                                                 |       | 615,000                       |       |   |   |   |   |

 

*StockAppreciation 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 paid in cash or common stock or acombination thereof to the participant. On June 1, 2009, 202,280 SARs weregranted and outstanding as of June 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 | % |

 

At June 30, 2009 the Company had unvested options to purchase202,280 shares with a weighted average grant date fair market value of $74,000.

 

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The following table summarizes stock appreciation activity for the sixmonths ended June 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 June 30, 2009 (unaudited) |       | 202,280    |       | $                                                                | 0.41       |                                                | 6.92       |   |

 

During the three and six months ended June 30, 2009, the Companyrecognized compensation expense of approximately $2,000, based on the fairvalue of the vested shares using a Black-Scholes model.

 

*RestrictedStock under the Stock Incentive Plan*

 

The Company has a stock incentive plan whereby grants of restrictedstock have been awarded to members of the Board of Directors and certainexecutives and employees. Restrictions and vesting periods for the awards aredetermined at the discretion of the Board of Directors and are set forth in theaward agreements. During the three and six months ended June 30, 2009, theCompany recognized compensation expense of approximately $78,000 and $289,000,respectively, based on the fair value of the vested shares.

 

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

 
| ** **                                   | ** ** | **Shares** | ** ** | **Weighted-********Average********Grant-Date********Fair Value** | ** ** |
|----------------------------------------------|------------|------------|------------|------------------------------------------------------------------|------------|
| Non-vested at December 31, 2008         |       | 203,577    |       | $                                                                | 4.78       |   |
| Granted                                      |       | 534,102    |       | $                                                                | .41        |   |
| Forfeited                                    |       | (5,564     | )          | $                                                                | 6.05       |   |
| Vested                                       |       | (340,897   | )          | $                                                                | .72        |   |
| Non-vested at June 30, 2009 (unaudited) |       | 391,218    |       | $                                                                | 2.37       |   |

 

As of June 30, 2009, the Company had approximately $0.7 million ofunrecognized share-based compensation expense related to non-vested stockawards, which is expected to be amortized over the remaining vesting periods ofthree to five years.

 

**Note 7 —Long-Term Debt**

 

*CreditFacility*

 

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 June 30, 2009 and December 31, 2008, theCompany had $8.0 million and $11.5 million, respectively, of debt outstandingunder the facility. As described below, the Company is currently unable toborrow additional amounts under the credit facility due to covenant andborrowing base limitations and may be further limited in the future based onborrowing 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 of approximately $666,667 per month until it reached $10.5million on April 1, 2009. As of April 14, 2009, the Company’sborrowing base was further reduced to $9.0 million, subject to automaticreductions of $500,000 per month until it reaches $6.5 million on October 1,2009, where it will remain until the next borrowing base redetermination. Ifnatural gas prices do not improve, the Company expects that its borrowing basecould be further reduced in the future. At August 13, 2009, the Company’s debt outstanding under the creditfacility was $7.5 million.

 

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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 specific borrowingbase 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:

 

·**               **incur liens;

 

·**               **incur debt;

 

·**               **make investments in other persons;

 

·**               **declare dividends or redeem or repurchase stock;

 

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

 

·**               **enter into certain hedging arrangements;

 

·**               **amend material contracts; and

 

·**               **enter into related party transactions.

 

With regard to 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 

 

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representationsand warranties, loss of material permits and licenses and a change in control.The credit agreement requires any wholly-owned subsidiaries to guarantee theobligations under the credit agreement.

 

After an event ofdefault, 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.  TheCompany and the lenders are negotiating the terms of a fifth amendment to theCredit Agreement which would provide for an additional 60-day waiver of thecurrent ratio financial covenant and certain other restrictive covenants.  The Company anticipates, although there is noassurance, that the fifth amendment will be executed on or before August 26,2009.

 

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 thatsuch waivers will be obtained on acceptable terms. If the Company is unable toobtain future waivers and/or comply with the restrictive covenants and aretherefore in default, the lenders could avail themselves of the remedies underthe credit agreement, including acceleration and foreclosure.

 

*Office Building Loan*

 

On November 15,2005, the Company entered into a mortgage loan secured by its office buildingin Sheridan, Wyoming in the aggregate principal amount of $829,000. Thepromissory note provides for monthly payments of principal and interest in theinitial amount of $6,400, and unpaid principal that bore interest at 6.875%during the first three years, currently bears interest at a variable base rateplus 0.5% and will bear interest at 18% upon a default. The variable base rateis based on the lender’s base rate. The maturity date of this mortgage is November 15,2015, at which time a principal and interest payment of $531,300 will becomedue. As of June 30, 2009, the Company had $748,000 outstanding inprincipal and interest on this mortgage. On November 15, 2008, the interest rate on the Company’s mortgageloan changed from a fixed rate of 6.875% to a variable rate. As of June 30,2009, the variable rate was 4.75%.

 

**Note8 — Fair Value Measurements**

 

Effective January 1, 2008, the Company adopted SFAS No. 157, “FairValue Measurements” for all financial assets and liabilities measured at fairvalue on a recurring basis. The statement establishes a framework for measuringfair value and requires enhanced disclosures about fair value measurements.SFAS No. 157 defines fair value as the price that would be received tosell an asset or paid to transfer a liability (an exit price) in an orderlytransaction between market participants at the measurement date. The statementestablishes market or observable inputs as the preferred sources of values,followed by assumptions based on hypothetical transactions in the absence ofmarket inputs. The statement establishes a hierarchy for grouping these assetsand liabilities, based on the significance level of the following inputs:

 

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

 

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

 

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

 

Thefollowing is a listing of the Company’s assets and liabilities required to bemeasured at fair value on a recurring basis and where they are classifiedwithin the hierarchy as of June 30, 2009 (in thousands):

 

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| ** **                         | ** ** | **Level 1** | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** ** |
|------------------------------------|------------|-------------|------------|-------------|------------|-------------|------------|-----------|------------|
| Assets                             |       |        |       |        |       |        |       |      |       |
| Oil and gas derivative instruments |       | $           | —     |        | $          | 2,541       |       | $         | —     |   | $ | 2,541 |   |
| Liabilities                        |       |        |       |        |       |        |       |      |       |
| Oil and gas derivative instruments |       | $           | —     |        | $          | (328        | )          | $         | —     |   | $ | (328 | ) |
| Total                              |       | $           | —     |        | $          | 2,213       |       | $         | —     |   | $ | 2,213 |   |

 

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.

 

**Note9 — Commitments and Contingencies**

 

*Operating Lease*

 

Upon purchase of its building in August 2005, the Company wasassigned the lease agreements for existing tenants in the building. The leasesexpire from January 2010 to December 2013. Future minimum leaseincome under noncancelable operating leases is as follows:

 
| **Year Ending December 31:** | ** ** | ** ** | ** ** |
|-----------------------------------|------------|------------|------------|
| 2009                              |       | $          | 50,000     |   |
| 2010                              |       | 63,000     |       |
| 2011                              |       | 60,000     |       |
| 2012                              |       | 60,000     |       |
| 2013                              |       | 60,000     |       |
| Total minimum lease payments      |       | $          | 293,000    |   |

 

*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 by theCompany 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 

 

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severancebenefits which will include a lump sum payment equal to 1.5 times his annualbase salary and the payment of a pro-rated bonus. In each case, any and allstock options, restricted stock awards and other equity compensation awardsheld by the executive will immediately vest and become exercisable. In theevent that either executive’s employment is terminated within six monthspreceding or following a change of control due to a non-renewal of hisemployment agreement by us, the executive will be entitled to the same changeof control severance benefit 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 relating to the Coal Creek POD. The plaintiff is a surfaceowner with properties located in Big Horn County and Rosebud County, Montanawhere the Company has a lease for approximately 10,300 acres, serves asoperator and owns a working interest in the minerals under lease. The plaintiffsought to permanently enjoin the State of Montana and its administrative bodiesfrom issuing licenses or permits, or authorizing the removal of ground waterfrom under 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, werealso 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 June 2005, the U.S. Bureau ofLand Management in Miles City, Montana issued suspensions of operations for themajority of our federal leases in Montana. The suspensions were issued basedupon a court order issued on April 5, 2005 by the U.S. District Court ofMontana that required the BLM to complete a Supplemental Environmental ImpactStatement (SEIS) to address phased development of coal bed natural gas. TheU.S. Ninth Circuit Court of Appeals also issued an order on May 31, 2005which enjoined the BLM from approving coal bed natural gas production projectsin the Powder River Basin of Montana. Both of these actions placed limitationson 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 in litigationbrought by RLI Insurance Company (Civil Cause No. 09-CV-157-J) filed inUnited States District Court for the District of Wyoming on July 6,2009.  The complaint alleges that theCompany failed to provide $1,439,360 in additional collateral requested byplaintiff to secure certain bonds issued by plaintiff on behalf of theCompany.  Plaintiff seeks the additionalbond collateral plus attorney’s fees and costs. This litigation is in the preliminary stages and the Company intends tovigorously defend the allegations in the complaint.

 

*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 

 

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the Company’soperations. In December 2007, the U.S. Bureau of Land Management imposed apermitting application fee of $4,000 per well drilled on federal lands.

 

*Environmental*

 

The Company produces significant amounts of water fromits wells. If future wells produce water of a lesser quality than allowed understate 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.

 

**Note10 — Recent Developments**

 

On August 19, 2009, the lenders waived compliance with the currentratio financial covenant under the Credit Agreement for the period ending August 26,2009 and the quarter ending June 30, 2009. The Company and the lenders are negotiating the terms of a fifth amendmentto the Credit Agreement which would provide for an additional 60-day waiver ofthe current ratio financial covenant and certain other restrictivecovenants.  The Company anticipates,although there is no assurance, that the fifth amendment will be executed on orbefore August 26, 2009.

********

 

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

 

*The discussion and analysis thatfollows should be read together with the**accompanyingfinancial statements and notes related thereto that are included**elsewhere in this quarterly report on Form 10-Q.It includes forward looking**statementsthat may reflect our estimates, beliefs, plans and expected**performance. The forward looking statements are basedupon events, risks and**uncertaintiesthat may be outside our control. Our actual results could differ**significantly from those discussed in these forwardlooking statements. Factors**thatcould cause or contribute to these differences include, but are not**limited to, market prices for natural gas and oil,regulatory changes,**estimates ofproved reserves, economic conditions, competitive conditions,**development success rates, capital expenditures andother uncertainties, as**well asthose factors discussed below and elsewhere in this quarterly report on**Form 10-Q and in our annual report on Form 10-Kfor the year ended December 31, 2008, including in “Risk Factors” and “CautionaryStatement Concerning Forward**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 June 30, 2009, we owned natural gas and oilleasehold interests in approximately 477,000 gross (332,000 net) acres,approximately 90% of which were undeveloped. As of June 30, 2009, we hadestimated net proved reserves of approximately 11.4 Bcf based on the CIG indexprice of $2.69 per Mcf. For the first half of 2009 and the remainder of 2009,we have operated and expect to continue to operate with a reduced capitalexpenditure plan. Under our reduced capital expenditure plan, we will generallymake only such expenditures as are necessary to secure drilling permits instrategic areas, drill wells that secure leasehold positions and construct thenecessary infrastructure to complete and hook-up wells that have already beendrilled. We had total capital expenditures of $2.5 million for the six monthsended June 30, 2009.  Our capitalexpenditure budget for 2009 will be dependent upon CIG index prices, our cashflows and the availability of additional capital resources.

 

We were formed asa Delaware corporation in June 2003 through a contribution of provedproducing properties and undeveloped leaseholds by subsidiaries of Carrizo Oil &Gas, Inc. and U.S. Energy Corporation and a cash contribution from fundsaffiliated 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 June 30,2009 and December 31, 2008, we had $8.0 million and $11.5 million,respectively, of debt outstanding under the facility.

 

**Economicand Natural Gas Pricing 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 partiallymitigate the constraints imposed by the current economic climate throughutilization of our credit facility and cash flows from operations.

 

The fear of globalrecession led to an immediate drop in demand for natural gas, primarily byindustrial users, which in turn led to a significant reduction in natural gasprices. The natural gas index price in the Rocky Mountain region averaged $7.84per Mcf for the first eight months of 2008 but only $3.15 per Mcf for the lastfour months of 2008. For the first six months of 2009, the price averaged $2.82per Mcf. This decrease in price has caused us to reevaluate our 2009 businessplan. We have curtailed drilling, except for wells that will hold significantblocks of acreage, and have also reduced administrative, operating andtransportation costs. Even with cost reductions and a flexible capital spendingbudget, the current natural gas pricing and economic environment remainschallenging. We are exploring strategic alternatives to increase our capitalresources.

 

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**CreditFacility and Liquidity**

 

On April 14, 2009, we andthe lenders entered into the fourth amendment to the credit facility whichwaived compliance with the current ratio financial covenant as of December 31,2008 and March 31, 2009 and with the restrictive covenants related to accountspayable, permitted liens and permitted debt until the next borrowing baseredetermination expected in the fall of 2009, subject to certain financialcaps.  In connection with the waiver ofthe restrictive covenants, the lenders reduced our borrowing base to $9.0million as of April 14, 2009, with further monthly reductions until theborrowing base reaches $6.5 million on October 1, 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.  We are negotiating the terms of a fifthamendment to the Credit Agreement which would provide for an additional 60-daywaiver of the current ratio financial covenant and certain other restrictivecovenants.  We anticipate, although thereis no assurance, that the fifth amendment will be executed on or before August26, 2009.  We believe that we may not bein compliance with the current ratio financial covenant and certain othercovenants throughout 2009, but management anticipates receiving waivers in thefuture based on prior dealings with the lender and continued compliance withthe borrowing base limitations. There can be no assurance that we will be ableto obtain such waivers or that such waivers will be obtained on acceptableterms.  If we are unable to obtain futurewaivers and/or to comply with the covenants, the lenders could accelerate ourindebtedness under the credit facility or foreclose on properties held byliens.  We have remained in compliancewith the payment of principal and interest pertaining to the credit facilityincluding ensuring that our outstanding borrowings remain within thelimitations of the borrowing base.  Dueto borrowing base limitations and waiver stipulations, we are currently unableto incur additional indebtedness under the credit facility and may be furtherlimited in the future. Please see “—Liquidity and Capital Resources—CreditFacility” for further information regarding our credit facility, borrowing baseand the covenant limitations.

 

In accordance with accounting guidance, we haveclassified all of the outstanding debt under the credit facility totalling$8.0 million as of June 30, 2009 as a current payable because it isunlikely that we will have cured the noncompliance of certain restrictivecovenants during 2009. We have further reduced our outstanding indebtednessunder the credit facility to $7.5 million as of August 18, 2009 inorder to be in compliance with the borrowing base limitation.

 

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 inWyoming and 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 priceswap and a costless collar at a weighted average floor price of $5.65 per Mmbtuand 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 swapand 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, are being taken to make operationssustainable in the future. Although we are pursuing various alternatives toprovide additional liquidity, there is no assurance of the likelihood or timingof any of these transactions.

 

**Critical Accounting Policies**

 

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

 

·**               **Reserve evaluation and determination;

 

·**               **Estimates of the timing and cost of our futuredrilling activity;

 

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

 

·**               **Estimates of timing and cost of asset retirementobligations;

 

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·**               **Estimates of the expense and timing of exercise ofstock options;

 

·**               **Accruals of operating costs, capital expenditures andrevenue;

 

·**               **Estimates for 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 properties areall located within the United States, which constitutes a single cost center.We capitalize certain 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 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 iscomputed on the unit-of-production method based on proved reserves. Amortizablecosts include estimates of future development costs of proved undevelopedreserves and asset retirement obligations. We invest in unevaluated oil and gasproperties for the purpose of exploration for proved reserves. The costs ofsuch assets, including exploration costs on properties where a determination ofwhether proved oil and gas reserves will be established is still underevaluation, and any capitalized interest and lease operating expenses, areincluded in unproved oil and gas properties at the lower of cost or estimatedfair market value and are not subject to amortization. On a quarterly basis,such costs are evaluated for inclusion in the costs to be amortized resultingfrom the determination of proved reserves, impairments, or reductions in value.To the extent that the evaluation indicates these properties are impaired, theamount of the impairment is added to the capitalized costs to be amortized. Noimpairment was recorded for unevaluated properties for the three and six monthsended June 30, 2009.  Substantiallyall of the remaining unproved property costs are expected to be developed andincluded in the amortization base over the next three to five years.  Salvage value is taken into account indetermining depletion rates and is based on the Company’s estimate of the valueof equipment and supplies at the time the well is abandoned.  As of June 30, 2009 and December 31,2008, the estimated salvage value was approximately $7.2 million and $7.1million, 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 June 30, 2009, the capitalized costof our oil and gas properties exceeded the full cost ceiling limitation byapproximately $9.0 million based upon a natural gas price of approximately$2.69 per Mcf in effect at that date. Based on the subsequent price increase to $3.09 on August 12, 2009,the capitalized cost exceeded the full cost ceiling limitation by $6.4 million.Therefore, an impairment of approximately $6.4 million was taken for the quarterended June 30, 2009.  Thisimpairment of our oil and gas properties resulted from low commodity prices inthe second quarter of 2009. No impairment was taken for the quarter ended June 30,2008 based on a natural gas price of $8.73 per Mcf. A decline in gasprices or an increase in operating costs or reductions in economicallyrecoverable quantities could result in the recognition of additionalimpairments of our oil and 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 June 30, 2009 and December 31,2008, there was no such liability recorded.

 

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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 June 30, 2009, and December 31, 2008 were based onthe actual volume statements from our purchasers and distribution process. Ifaccruals were to change by 10% at June 30, 2009 and at December 31,2008, the impact would have been a change of $75,000 and $209,000,respectively.

 

***Asset RetirementObligations***

 

We follow the provisions of Statement of Financial Accounting Standards(SFAS) No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143generally applies to legal obligations associated with the retirement oflong-lived assets that result from the acquisition, construction, developmentand/or the normal operation of a long-lived asset. SFAS No. 143 requiresus to recognize an estimated liability for costs associated with theabandonment of our 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 havehad a $346,000 effect on our asset retirement obligation liability at June 30,2009.

 

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

 
| ** **                                        | ** ** | **Three********Months Ended********June 30,** | ** ** | **Six********Months Ended June 30,** | ** ** | **Three********Months Ended********June 30,** | ** ** | **Six********Months Ended********June 30,** | ** ** |
|---------------------------------------------------|------------|----------------------------------------------------|------------|-------------------------------------------|------------|----------------------------------------------------|------------|--------------------------------------------------|------------|
| ** **                                        | ** ** | **2009**                                           | ** ** | **2008**                                  | ** ** |
| Beginning balance of asset retirement obligations |       | $                                                  | 3,422      |                                      | $          | 3,366                                              |       | $                                                | 2,926      |   | $ | 2,767 |   |
| Additional obligation added during the period     |       | —                                             |       | —                                    |       | $                                                  | 167        |                                             | $          | 268 |   |
| Obligations to be settled                         |       | (23                                                | )          | (23                                       | )          | —                                             |       | —                                           |       |
| Accretion expense                                 |       | 58                                                 |       | 114                                       |       | 61                                                 |       | 119                                              |       |
| Ending balance of asset retirement obligations    |       | 3,457                                              |       | 3,457                                     |       | 3,154                                              |       | 3,154                                            |       |
|                                                   |            |                                                    |            |                                           |            |                                                    |            |                                                  |            |  |  |  |  |

 

***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 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 June 30, 2009. The market price of steel isevaluated each quarter using prices quoted by authorized vendors in the area.

 

***Property andEquipment***

 

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—30 years, computer hardware and software—3 to 5 years,machinery, equipment and vehicles—5 years, and office furniture andequipment—3 to 5 years.

 

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***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 recorded an impairment. No impairments wererecorded during the six months ended June 30, 2009 and the year ended December 31,2008.

 

***General andAdministrative Expenses***

 

General and administrative expenses are reported net of amounts allocatedand billed to working interest owners of gas properties operated by us. Theadministrative expenses billed to working interest owners may change inaccordance with the terms of the joint operating agreements. Administrativeexpenses are charged to working interest owners based on productive wellcounts.  A 10% change in well counts forthe six months ended June 30, 2009 would have increased or decreased ourexpenses billed to working interest owners by approximately $34,000. As weoperate and drill additional wells in the future, additional administrativeexpenses will be charged to the working interest owners when the wells becomeproductive.

 

***Income Taxes***

 

We use the asset and liability method of accounting for income taxes,in accordance with SFAS No. 109, “Accounting for Income Taxes.” Deferredtax 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 June 30, 2009 and December 31,2008, we recorded a full valuation allowance for our net deferred tax asset.

 

On January 1, 2007, we adopted the provisions of FIN 48, “Accounting for Uncertainty in Income Taxes.” FIN 48prescribes 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. FIN 48 requires that we recognize in our consolidatedfinancial statements only those tax positions that are “more-likely-than-not”of being sustained as of the adoption date, based on the technical merits ofthe position. As a result of the implementation of FIN 48, we performed acomprehensive review of our material tax positions in accordance withrecognition and measurement standards established by FIN 48. As a result ofthis review, we did not identify any material deferred tax assets that requiredadjustment. As of June 30, 2009 and 2008, we had not recorded any materialuncertain tax positions.

 

Our policy is to recognize interest and penalties related to uncertaintax benefits in income tax expense. As of June 30, 2009 and 2008, we hadnot 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 the provisionsof SFAS No. 133, “Accounting for Derivative Instruments and HedgingActivities.” SFAS No. 133 requires us to record derivative instruments attheir 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 included in the accompanying unaudited Notes toFinancial Statements for additional discussions 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 

 

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exposure tocommodity price risk. Our management decided not to use hedge accounting forthese agreements. Therefore, in accordance with the provisions of SFAS No. 133,the changes in fair market value are recognized in earnings.

 

***Stock-Based Compensation***

 

Effective January 1, 2006, we adopted SFAS No. 123(R), “Share-BasedPayments,” which requires companies to recognize compensation expense forshare-based payments based on the estimated fair value of the awards. Werecognized an expense of approximately $217,000 for the six months ended June 30,2009, based on the fair value of vested options.  We recognized an expense of approximately$289,000 for the six months ended June 30, 2009, based on the fair valueof restricted stock that vested during the quarter.  We recognized an expense of approximately$2,000 for the six months ending June 30, 2009, based on the fair marketvalue of stock appreciation rights. SFAS No. 123(R) also requiresthat the benefits of tax deductions in excess of compensation cost recognizedfor stock awards and options (“excess tax benefits”) be presented as financingcash inflows in the Statement of Cash Flows.

 

***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 at each of June 30, 2009 and December 31, 2008.

 

***TransportationCosts***

 

We account for transportation costs under Emerging Issues Task ForceIssues 00-10, “Accounting for Shipping and Handling Fees and Costs,” wherebyamounts paid for transportation 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 SFASNo. 5, “Accounting forContingencies,” which states that a loss contingency be recorded if itis probable that a liability has been incurred and it is reasonablyestimatable. At June 30, 2009 and December 31, 2008, we recorded noliability for legal proceedings.

 

***Per Share Information***

 

Basic loss per share is computed by dividing net loss from continuingoperations attributable to common stock by the weighted average number ofcommon shares outstanding during each period. Diluted earnings per share iscomputed by adjusting the average number of common shares outstanding for thedilutive effect, if any, of common stock equivalents such as stock options andwarrants. Diluted net loss per share was the same as basic net loss per sharefor the three months ended June 30, 2009 because potential common stockequivalents were anti-dilutive. Certain option to purchase shares of our commonstock were excluded from the dilution calculations because the shares wereanti-dilutive. At June 30, 2009 and 2008, 842,280 and 750,000 options,respectively, were excluded because they were anti-dilutive due to the net lossattributable to stockholders incurred in such periods.

 

***New Accounting Pronouncements***

 

For information concerning new accounting pronouncements, please seeNote 2 — Basis of Presentation of the notes to the unaudited financialstatements appearing 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 with a reduced capitalexpenditure plan for 2009. 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.

 

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Historically, natural gas prices have been extremely volatile, and weexpect that volatility to continue. For example, during the three months ended June 30,2009, the NYMEX natural gas index price ranged from a high of $4.45 per MMBtuto a low of $3.25 per MMBtu, while the CIG natural gas index price ranged froma high of $3.47 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 months ended June 30, 2009, estimated future gas prices had animpact on both our revenues and the costs attributable to our futureoperations. We expect that changing natural gas prices will continue to impactour operations and financial results in the future.

 

Transportation ofnatural gas and access to throughput capacity have a direct impact on naturalgas prices in the Rocky Mountain region, where our operations are concentrated.As drilling activity increases throughout the Rocky Mountain region, additionalproduction may come on line, which could cause bottlenecks or capacityconstraints. Generally speaking, a surplus of natural gas production relativeto available transportation capacity has a negative impact on prices.Conversely, as capacity increases, and bottlenecks are eliminated, pricesgenerally increase. Although there is currently adequate transportationcapacity out of the Powder River Basin, a surplus of natural gas arriving atkey marketing hubs from the Powder River Basin and elsewhere relative toavailable takeaway capacity from these hubs has caused Rocky Mountain gas togenerally trade at a discount to the NYMEX natural gas index price. For example,from January 1, 2009 through June 30, 2009, Rocky Mountain gas tradedat a differential to the NYMEX natural gas index price that ranged from adiscount of $0.73 to $2.30 per MMBtu, with an average differential of adiscount of $1.45 per MMBtu. The Rockies Express Pipeline which was completedand placed into service in early 2008, has increased takeaway capacity byapproximately 1.5 Bcf per day from these hubs. We expect that the completion ofadditional proposed pipelines will help reduce the differential between gasproduced in the Rocky Mountain region and the NYMEX natural gas index price.Additional proposed pipelines are scheduled to be completed in late 2010 and2011. General economic conditions and the future demand for natural gas maychange the development schedule of proposed pipelines.

 

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 regulations and permittingrequirements could lead to significant operational delays and increasedoperating costs as well as encumbering field enhancements through fracturing.

 

**Results of Operations**

 

Net loss attributable to stockholders for the quarter ended June 30,2009 was $9.5 million, or $0.32 per diluted share, on total revenues of $1.6million. Other income for the quarter ended June 30, 2009 included a $2.7million unrealized loss associated with the change in the fair valuation of ournatural gas hedges in place in accordance with the provisions of SFAS No. 133.Absent such change in the valuation of hedges, we would have shown a loss of $6.8million. In addition, we recorded an impairment of $6.4 million for the quarterended June 30, 2009.  Absent theimpairment and unrealized loss on derivatives, we would have shown a loss of $0.4million. This compares to a net loss attributable to stockholders of $3.9million for the quarter ended June 30, 2008 on total revenue of $7.6million. Adjusted for an unrealized loss in the fair valuation of our naturalgas hedges in place of $2.0 million shown in other income, our results for thequarter ended June 30, 2008 would have been a net loss attributable tocommon stockholders of $1.9 million. We did not record an impairment for thequarter ended June 30, 2008.

 

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In order to provide a measure of stability to the cash flow in anenvironment of volatile oil and gas prices and to manage the exposure tocommodity price risk, we chose to periodically hedge a portion of our oil andgas production using swap and collar agreements. We account for our derivativeinstruments under the provisions of SFAS No. 133. SFAS No. 133requires us to record derivative instruments at their fair value. Managementhas chosen not to use hedge accounting for these arrangements. Therefore, inaccordance with SFAS No. 133, changes in the fair market value arerecognized in earnings.

 

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

 

*Gassales volume.*

 

Gas sales volume decreased 30%, from 1,001 MMcf in the three monthsended June 30, 2008 to 702 MMcf in the three months ended June 30,2009. Daily sales volume was 7.7 MMcf for the three months ended June 30,2009 as compared to 10.9 MMcf for the three months ended June 30, 2008, a3.2 MMcf per day decrease. The decrease resulted primarily from shutting inwells due to low natural gas prices.

 

*Gassales revenue.*

 

Revenue from gas sales decreased approximately $6.0 million during thethree months ended June 30, 2009, to approximately $1.6 million, a 79%decrease compared to the three months ended June 30, 2008. This decreasewas primarily due to a decrease in the average realized price per Mcf alongwith a reduction in gas sales volume. The average realized price per Mcfdecreased approximately 70%, from $7.57 per Mcf in the three months ended June 30,2008 to $2.29 per Mcf in the three months ended June 30, 2009.

 

*Derivatives.*

 

For the three months ended June 30, 2009, we had an unrealizedloss of $2.7 million compared to an unrealized loss of $2.0 million for thethree months ended June 30, 2008. The unrealized losses are non-cashexpenses based primarily on the Black-Scholes model for valuing future cash flowsutilizing price volatility with a normal discount rate. Hedges settled duringthe three months ended June 30, 2009 resulted in a realized gain of $2.1million compared to a realized hedge loss of $0.7 million during the threemonths ended June 30, 2008. The realized hedge gain for the three monthsended June 30, 2009 was primarily due to the fact that gas prices werelower than the weighted average floor price of our hedges in place.

 

*Lease operating expenses.*

 

Lease operating expenses decreased $0.4 million in the three monthsended June 30, 2009 to $0.9 million, a 30% decrease compared to the threemonths ended June 30, 2008. This decrease resulted primarily from areduction in contract services, fuel, workover, and water management relatedcosts during the three months ended June 30, 2009. On a Mcf basis, leaseoperating expenses decreased 1% from $1.35 per Mcf in the three months ended June 30,2008 to $1.34 per Mcf in the three months ended June 30, 2009.

 

*Production taxes.*

 

Production taxes decreased $0.7 million in the three months ended June 30,2009 to $0.1 million, a 84% decrease from the three months ended June 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 June 30, 2009 was primarily due todecreased revenues associated with decreased volume and realized pricing. On anMcf basis, production taxes were $0.20 per Mcf for the three months ended June 30,2009 and $0.86 per Mcf for the three months ended June 30, 2008, a 77%decrease, which correlates to the decrease in the price per Mcf received in thethree months ended June 30, 2009 from the three months ended June 30,2008.

 

*Marketing and transportation.*

 

Marketing and transportation expenses decreased approximately $0.3million in the three months ended June 30, 2009 to approximately $0.9million, a 26% decrease from the three months ended June 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 5% to $1.27 per Mcf in the three months ended June 30,2009 from $1.21 per Mcf in the three months ended June 30, 2008.

 

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*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 $0.3million and $0.5 million for the three months ended June 30, 2009 and June 30,2008, respectively, a 36% decrease. General and administrative expenses, net,decreased $2.0 million in the three months ended June 30, 2009 to $1.2million. On an Mcf basis, general and administrative expenses, net decreased47%, from $3.21 per Mcf in the three months ended June 30, 2008 to $1.69per Mcf in the three months ended June 30, 2009. The decrease in generaland administrative expenses was primarily a result of staff and pay reductions.In addition, during the three months ended June 30, 2008, general andadministrative expenses included a $2.1 million charge related to the failedQuest merger.

 

*Depreciation, depletion,amortization and accretion.*

 

Depreciation, depletion, amortization and accretion expense decreased$1.4 million for the three months ended June 30, 2009 to $0.9 million, a60% decrease compared to the three months ended June 30, 2008. Thedecrease was primarily due to a decrease in the capitalized basis in our fullcost pool at June 30, 2009. On an Mcf basis, the depreciation, depletion,amortization and accretion rate decreased to $1.30 per Mcf in the three monthsended June 30, 2009 from $2.20 per Mcf in the three months ended June 30,2008.

 

*Impairment.*

 

At June 30, 2009, the capitalized cost of our oil and gasproperties exceeded the full cost ceiling limitation by approximately $9.0million based upon a natural gas price of approximately $2.69 per Mcf (based onthe CIG Rocky Mountain Index) in effect at that date. Based on the subsequentprice increase to $3.09 per Mcf on August 12, 2009, the capitalized costexceeded the full cost ceiling limitation by $6.4 million. Therefore, animpairment of approximately $6.4 million was taken for the quarter ended June 30,2009. For further information regarding this impairment, please see Note 2 — “Basisof Presentation” in the Notes to the unaudited financial statements appearingelsewhere in this quarterly report. A decline in natural gas prices or anincrease in operating costs in economically recoverable quantities could resultin the recognition of additional impairments of our oil and gas properties infuture periods.

 

***Six Months Ended June 30, 2009 Compared to Six MonthsEnded June 30, 2008***

 

*Gassales volume.*

 

Gas sales volume decreased 19%, from 1,880 MMcf in the six months endedJune 30, 2008 to 1,516 MMcf in the six months ended June 30, 2009.Daily sales volume was 8.4 MMcf for the six months ended June 30, 2009 ascompared to 10.3 MMcf for the six months ended June 30, 2008, a 1.9 MMcfper day decrease. The decrease resulted primarily from shutting in wells due tolow natural gas prices, reductions in volumes due to compression maintenanceand repairs, and weather related downtime.

 

*Gassales revenue.*

 

Revenue from gas sales decreased approximately $8.9 million during thesix months ended June 30, 2009, to approximately $4.4 million, a 67%decrease compared to the six months ended June 30, 2008. This decrease wasprimarily due to a decrease in the average realized price and a decrease in gassales volume per Mcf. The average realized price per Mcf decreasedapproximately 59%, from $7.04 per Mcf in the six months ended June 30,2008 to $2.88 per Mcf in the six months ended June 30, 2009.

 

*Derivatives.*

 

For the six months ended June 30, 2009, we had an unrealized lossof $2.1 million compared to an unrealized loss of $6.5 million for the sixmonths ended June 30, 2008. The unrealized losses are non-cash expensesbased primarily on the Black-Scholes model for valuing future cash flowsutilizing price volatility with a normal discount rate. Hedges settled duringthe six months ended June 30, 2009 resulted in a realized gain of $3.5million compared to a realized hedge loss of $0.8 million during the six monthsended June 30, 2008. The realized hedge gain for the six months ended June 30,2009 was primarily due to the fact that gas prices were lower than the weightedaverage floor price of our hedges in place.

 

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*Lease operating expenses.*

 

Lease operating expenses decreased $1.3 million in the six months endedJune 30, 2009 to $2.1 million, a 38% decrease compared to the six monthsended June 30, 2008. This decrease resulted primarily from a reduction incontract services, fuel, workover and water management related costs offsetpartially by an increase in surface use expenses in the productive cycle duringthe six months ended June 30, 2009. On a Mcf basis, lease operatingexpenses decreased 23% from $1.81 per Mcf in the six months ended June 30,2008 to $1.40 per Mcf in the six months ended June 30, 2009.

 

*Production taxes.*

 

Production taxes decreased $1.1 million in the six months ended June 30,2009 to $0.4 million, a 72% decrease from the six months ended June 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 six months ended June 30, 2009 was primarily due todecreased revenues associated with decreased volume and realized pricing. On anMcf basis, production taxes were $0.28 per Mcf for the six months ended June 30,2009 and $0.81 per Mcf for the six months ended June 30, 2008, a 65%decrease, which correlates to the decrease in the price per Mcf received in thesix months ended June 30, 2009 from the six months ended June 30,2008.

 

*Marketing and transportation.*

 

Marketing and transportation expenses decreased approximately $0.1million in the six months ended June 30, 2009 to approximately $2.1million, a 6% decrease from the six months ended June 30, 2008. Thedecrease related primarily to a slight decrease in transportation fees andcompression due to lower production volumes. On an Mcf basis, marketing andtransportation expenses increased 16% to $1.41 per Mcf in the six months ended June 30,2009 from $1.22 per Mcf in the six months ended June 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$0.7 million in the six months ended June 30, 2009 compared to $0.9million for the six months ended June 30, 2008, a 27% decrease. Generaland administrative expenses, net, decreased $2.4 million in the six monthsended June 30, 2009 to $2.2 million. On an Mcf basis, general andadministrative expenses, net decreased 40%, from $2.44 per Mcf in the sixmonths ended June 30, 2008 to $1.46 per Mcf in the six months ended June 30,2009. The decrease in general and administrative expenses was primarily aresult of staff and pay reductions. In addition, during the six months ended June 30,2008, general and administrative expenses included a $2.1 million chargerelated to the failed Quest merger.

 

*Depreciation, depletion,amortization and accretion.*

 

Depreciation, depletion, amortization and accretion expense decreased$1.3 million for the six months ended June 30, 2009 to $2.7 million, a 32%decrease compared to the six months ended June 30, 2008. The decrease wasprimarily due to a decrease in the capitalized basis in our full cost pool. Onan Mcf basis, the depreciation, depletion, amortization and accretion ratedecreased to $1.81 per Mcf in the six months ended June 30, 2009 from$2.13 per Mcf in the six months ended June 30, 2008.

 

*Impairment.*

 

In the six months ending June 30, 2009, our oil and gas propertiesexceeded the full cost ceiling limitation by approximately $23.2 million.  Consequently, in the quarter ending March 31,2009, we recorded an impairment to our oil and gas properties of approximately$16.8 million based upon a natural gas price of $3.31 per Mcf (the CIG RockyMountain Index price) in effect at May 12, 2009. At June 30, 2009, thecapitalized cost of our oil and gas properties exceeded the full cost ceilinglimitation by approximately $9.0 million based upon a natural gas price ofapproximately $2.69 per Mcf in effect at that date. Based on the subsequentprice increase to $3.09 per Mcf on August 12, 2009, the capitalized costexceeded the full cost ceiling limitation by $6.4 million. Therefore, animpairment of approximately $6.4 million was taken for the quarter ended June 30,2009. For further information regarding this impairment, please see Note 2 — “Basisof Presentation” in the Notes to the unaudited financial statements appearingelsewhere in this quarterly report. A decline in natural gas prices or anincrease in operating costs in economically recoverable quantities could resultin the recognition of additional impairments of our oil and gas properties infuture periods.

 

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**Liquidity and Capital Resources**

 

In the past, ourprimary sources of liquidity have been private and public sales of our equitysecurities, cash provided by operating activities, and debt financing. All ofthese sources have been negatively impacted by the current economic climate,its impact on our industry, and by significant fluctuations in oil and gasprices, 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 activities and could reduce the borrowing base of ourcredit facility as well as the value of assets we might consider selling.Historically, decreases in market prices have limited our industry’s access tothe capital markets. During these challenging times, we have reduced ouradministrative, operating and transportation costs. We are also activelymarketing asset sales and exploring other strategic alternatives and capitalrestructuring options.

 

*CreditFacility.*

 

Effective February 12, 2007, we entered into a credit facilitywhich permits borrowings up to the borrowing base as designated by theadministrative agent. As of June 30, 2009 and December 31, 2008, wehad $8.0 million and $11.5 million, respectively, of debt outstanding under thefacility. 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 of approximately $666,667 per month until it reached $10.5million on April 1, 2009. As of August 13, 2009, our borrowing basewas reduced to $7.5 million, subject to automatic reductions of $500,000 permonth until it reaches $6.5 million on October 1, 2009, where it willremain until the next borrowing base redetermination. If natural gas prices donot improve, we expect that our borrowing base could be further reduced in thefuture.

 

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 June 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 a borrowingbase determination. In addition, the credit facility provided for an up frontfee of $27,000, which was paid on the closing date of the credit facility, andan additional arrangement fee of 1% based on utilization. Borrowings under thiscredit facility may be prepaid without premium or penalty, except on Eurodollaradvances.

 

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

 

·**               **incur liens;

 

·**               **incur debt;

 

·**               **make investments in other persons;

 

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·**               **declare dividends or redeem or repurchase stock;

 

·**               **engage in mergers, acquisitions, consolidations andasset sales or amend our organizational documents;

 

·**               **enter into certain hedging arrangements;

 

·**               **amend material contracts; and

 

·**               **enter into related party transactions.

 

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

 

The 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 event ofdefault, 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 covenant underthe Credit Agreement for the period ending August 26, 2009 and the quarterending June 30, 2009.  We are negotiatingthe terms of a fifth amendment to the Credit Agreement which would provide foran additional 60-day waiver of the current ratio financial covenant and certainother restrictive covenants.  Weanticipate, although there is no assurance, that the fifth amendment will beexecuted on or before August 26, 2009. We believe that we may not be incompliance with the current ratio financial covenant and certain othercovenants throughout 2009, but management anticipates receiving waivers in thefuture based on prior dealings with the lender and continued compliance withthe borrowing base limitations. There can be no assurance that we will be ableto obtain such waivers or that such waivers will be obtained on acceptableterms. If we 

 

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are unable toobtain future waivers and/or comply with the restrictive covenants and aretherefore in default, the lenders could avail themselves of the remedies underthe credit agreement, including acceleration and foreclosure.

 

*OfficeBuilding Loan.*

 

On November 15,2005, we entered into a mortgage loan secured by our office building inSheridan, Wyoming in the aggregate principal amount of $829,000. The promissorynote provides for monthly payments of principal and interest in the initialamount of $6,400, and unpaid principal 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 June 30,2009, we had $748,000 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 June 30, 2009, the variable rate was4.75%.

 

*CapitalExpenditure Budget*.

 

We had totalcapital expenditures of $2.5 million for the six months ended June 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. 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 inoperating activities was $1.1 million for the six months ended June 30,2009, compared to net cash provided by operating activities of $5.0 million forthe six months ended June 30, 2008. The change was primarily due to adecrease in our revenue distribution payable balance offset partially by adecrease in our accounts receivable balance.

 

***Cash Flow from Investing Activities***

 

Net cash provided by investing activities was $4.2 million for the sixmonths ended June 30, 2009, compared to net cash used in investingactivities of $17.0 million for the six months ended June 30, 2008.  The increase in net cash provided byinvesting activities in the six months ended June 30, 2009 was primarilydue to a sale of certain oil and gas properties and a realized gain onderivatives coupled with reduced capital expenditures as compared to thequarter ended June 30, 2008.

 

***CashFlow from Financing Activities***

 

Net cash used in financing activities was $3.5 million for the sixmonths ended June 30, 2009, compared with net cash provided by financingactivities of $5.0 million for the six months ended June 30, 2008. Thechange was primarily due to a reduction in the balance owed on the line ofcredit for the six ended June 30, 2009, compared to additional borrowingsfor the six months ended June 30, 2008.

 

***ContractualObligations***

 

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 June 30, 2009:

 
| ** **                                    | ** ** | **Total**           | ** ** | **2009** | ** ** | **2010-2011** | ** ** | **2012-2013** | ** ** | **Thereafter** | ** ** |
|-----------------------------------------------|------------|---------------------|------------|----------|------------|---------------|------------|---------------|------------|----------------|------------|
| ** **                                    | ** ** | **(In  thousands)** | ** ** |
| Notes payable in connection with the mortgage |       | 748                 |       | 15       |       | 63            |       | 70            |       | 600            |       |
| Asset retirement obligations                  |       | 3,457               |       | 319      |       | 875           |       | 1,069         |       | 1,194          |       |
| Production and property taxes                 |       | 2,721               |       | 1,156    |       | 1,565         |       | —        |       | —         |       |
| Total                                         |       | $                   | 6,926      |     | $          | 1,490         |       | $             | 2,503      |           | $          | 1,139 |   | $ | 1,794 |   |
|                                               |            |                     |            |          |            |               |            |               |            |                |            |  |  |  |  |  |

 

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**ITEM 3. QUANTITATIVE AND QUALITATIVEDISCLOSURES 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. This forward-lookinginformation provides indicators of how we view and manage our ongoing marketrisk exposure. All of our market risk sensitive instruments were entered intofor purposes other than speculative trading.

 

**CommodityPrice Risk**

 

Our major marketrisk exposure is in the pricing applicable to our natural gas production. Theprices we receive for our production depend on many factors beyond our control.We seek to reduce our exposure to unfavorable changes in natural gas prices,which are subject to significant and often volatile fluctuation, through theuse of fixed-price contracts. 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 ourhydrocarbon properties that are used in the borrowing base determination, andthat the fixed or floor price of our hedging arrangements must be equal to orgreater than the gas price used by the lenders in determining the borrowing base.

 

The followingtable summarizes the estimated volumes, fixed prices, fixed price sales andfair value attributable to the fixed price contracts as of June 30, 2009.At June 30, 2009, we had hedged volumes through December 2010. Pleasesee Note 5 of the Notes to the unaudited financial statements appearingelsewhere in this quarterly report for further information regarding ourderivatives.

 
| ** **                                      | ** ** | **Year  Ending********December 31, 2009** | ** ** | **Year  Ending********December 31, 2010** | ** ** |
|-------------------------------------------------|------------|------------------------------------------------|------------|------------------------------------------------|------------|
| ** **                                      | ** ** | **(Unaudited)**                                | ** ** | **(Unaudited)**                                | ** ** |
| **Natural Gas Collars:**                        |       |                                           |       |                                           |       |
| Contract volumes (MMBtu)                        |       |                                           |       |                                           |       |
| Floor                                           |       | 368,000                                        |       | —                                         |       |
| Ceiling                                         |       | 368,000                                        |       | —                                         |       |
| Weighted-average fixed price per MMBtu(1)       |       |                                           |       |                                           |       |
| Floor                                           |       | $                                              | 6.50       |                                           | $          | — |   |
| Ceiling                                         |       | $                                              | 7.50       |                                           | $          | — |   |
| Fixed-price sales(2)                            |       | $                                              | 7.50       |                                           | $          | — |   |
| Fair value, net (thousands)(3)                  |       | $                                              | 1,193      |                                           | $          | — |   |
| **Natural Gas Swaps:**                          |       |                                           |       |                                           |       |
| Contract volumes (MMBtu)                        |       | 1,104,000                                      |       | 1,395,000                                      |       |
| Weighted-average fixed price sales per MMBtu(1) |       | $                                              | 5.09       |                                           | $          | 4.52 |   |
| Fair value, net (thousands)(3)                  |       | $                                              | 1,836      |                                           | $          | (816 | ) |
| **Total Natural Gas Contracts:**                |       |                                           |       |                                           |       |
| Contract volumes (MMBtu)                        |       | 1,472,000                                      |       | 1,395,000                                      |       |
| Fixed-price sales(2)                            |       | $                                              | 5.69       |                                           | $          | 4.52 |   |
| Fair value, net (thousands)(3)                  |       | $                                              | 3,029      |                                           | $          | (816 | ) |

 

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(1)      Volumes hedged using the CIG index price published inthe first issue of Inside FERC’s Gas Market Report for each calendar month ofthe derivative transaction.

 

(2)       Assumes ceiling prices for natural gascollar volumes.

 

(3)      Fair value based on CIG index price in effect for eachmonth as of June 30, 2009.

 

**InterestRate Risk**

 

Borrowings under our credit facility bear interest at fluctuating market-basedrates.  Accordingly, our interestexpenses are sensitive to market changes, which expose us to interest rate riskon current and future borrowings under our credit facility.

 

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As of June 30, 2009, we had $8.0 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 was 4.75% forthe six months ended June 30, 2009 and 3.0% for the six months ended June 30,2008. A hypothetical change of 1% in either the domestic bank rate or the LIBORinterest rates would increase or decrease gross interest expense approximately$80,000 per year.

 

**ITEM 4T. CONTROLS AND PROCEDURES**

 

**DisclosureControls 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.

 

**Changesin Internal Control over Financial Reporting**

 

During the most recent fiscal quarter, there has been no change in ourinternal control over financial reporting that has materially affected, or isreasonably 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 has been no material developments during the quarter ended June 30,2009 regarding our currently pending legal proceedings. For a discussion ofcertain of our current legal proceedings, please see Note 9 — “Commitments andContingencies” of the Notes to the unaudited financial statements appearingelsewhere in this quarterly 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.

 

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

 

Our revenues, profitability and future growth and the carrying value 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 six months ended June 30,2009, the NYMEX natural gas index price ranged from a high of $6.07 per MMBtuto a low of $3.25 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.

 

***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.***

 

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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 June 30, 2009, we were not in compliancewith the current ratio financial covenant and certain other covenants relatedto accounts payable, permitted liens and permitted debt under our creditfacility. On April 14, 2009, the lenders waived compliance with thecurrent ratio as of March 31, 2009, and with such other restrictivecovenants, subject to certain financial caps, until the next borrowing baseredetermination expected in the fall of 2009. On August 19, 2009, the lenderswaived compliance with the current ratio financial covenant under the CreditAgreement for the period ending August 26, 2009 and the quarter ending June 30,2009.  We are negotiating the terms of a fifthamendment to the Credit Agreement which would provide for an additional 60-daywaiver of the current ratio financial covenant and certain other restrictivecovenants.  We anticipate, although thereis no assurance, that the fifth amendment will be executed on or before August26, 2009. We have also not been in compliance with certain financial covenantsfor the last four quarters, but obtained waivers and/or amendments in eachinstance. As a result of such non-compliance, we are currently unable to borrowadditional funds under our credit agreement. We believe that we may not be incompliance with certain financial and other covenants throughout the remainderof 2009, but will seek additional waivers. There can be no assurance that wewill be able to obtain such waivers or that such waivers will be obtained onacceptable terms. If we are unable to obtain future waivers and/or to complywith the covenants, the lenders could accelerate our indebtedness or forecloseon properties held by liens. In addition, due to borrowing base limitations, weare also unable to borrow additional funds under the credit facility. As of August 18,2009, our borrowing base was $7.5 million, with further monthly reductionsof $500,000 until the borrowing base reaches $6.5 million on October 1,2009.  If natural gas prices do notimprove, we expect that our borrowing base could be further reduced in thefuture.

 

***Proposedlegislation to eliminate or reduce certain federal income tax incentives anddeductions available to oil and gas exploration and production companies could,if enacted into law, have a material adverse effect on our results ofoperations 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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS**

 

At the Company’s 2009 Annual Meeting of Stockholders held on May 21,2009, the following matters were submitted to a vote of the Company’sstockholders:

 

1. *Election of Directors.*  F. GardnerParker and Susan C. Schnabel were re-elected as Class III directors of theCompany holding office until the end of such director’s term in 2012 and untilsuch director’s respective successor is duly elected andqualified.  For each director nominee, votes were cast as follows:

 
| **NOMINEE**        | ** ** | **FOR**    | ** ** | **ABSTAIN** | ** ** |
|--------------------|------------|------------|------------|-------------|------------|
| F.  Gardner Parker |       | 22,225,435 |       | 2,518,446   |       |
| Susan  C. Schnabel |       | 22,130,606 |       | 2,613,275   |       |

 

The following directors continuedin office after the meeting:

 

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**INCUMBENTDIRECTORS—CLASS ITerms Expiring in 2010**

 
| **Name**             | ** ** | **Age** | ** ** | **Position**                                     | ** ** | **Director  Since** | ** ** |
|----------------------|------------|---------|------------|--------------------------------------------------|------------|---------------------|------------|
| Jeffrey P. Gunst     |       | 32      |       | Director                                         |       | 2003                |       |
| Thomas G. McGonagle  |       | 49      |       | Director                                         |       | 2007                |       |
| Peter G. Schoonmaker |       | 50      |       | Chief Executive  Officer, President and Director |       | 2006                |       |

 

**INCUMBENTDIRECTORS—CLASS IITerms Expiring in 2011**

 
| **Name**                   | ** ** | **Age** | ** ** | **Position** | ** ** | **Director  Since** | ** ** |
|----------------------------|------------|---------|------------|--------------|------------|---------------------|------------|
| Robert  L. Cabes, Jr. |       | 39      |       | Director     |       | 2003                |       |
| Sylvester  P. Johnson, IV  |       | 53      |       | Director     |       | 2003                |       |

 

2.*Ratification of Appointment of IndependentRegistered Public Accounting Firm*.  At the meeting, theappointment of Ehrhardt Keefe Steiner & Hottman PC as the Company’sindependent registered public accounting firm for the year ending December 31,2009 was ratified by the Company’s stockholders.  The number of votes castfor and against the ratification of Ehrhardt Keefe Steiner & HottmanPC and the number of abstentions and broker non-votes were as follows:

 
| **FOR**    | ** ** | **AGAINST** | ** ** | **ABSTAIN** | ** ** | **BROKER********NON-VOTES** | ** ** |
|------------|------------|-------------|------------|-------------|------------|-----------------------------|------------|
| 23,539,445 |       | 973,180     |       | 231,256     |       | 0                           |       |

 

**ITEM5. OTHER INFORMATION**

 

Not applicable.

 

**ITEM6. EXHIBITS**

 
| **Exhibit****No.** | ** ** | ** **   | ** ** | **Description**                                                                                                                                                                                                                                                                                     |
|--------------------|------------|--------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.1                |       |  — |       | Second Amended and  Restated Certificate of Incorporation of Pinnacle Gas Resources, Inc.  (incorporated herein by reference to Exhibit 3.1 to the Registration  Statement on Form S-1 (File No. 333-133983) filed by Pinnacle Gas  Resources, Inc. on May 10, 2006). |

 

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| 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.                                                                                                                                                                                                                          |
|   |   |         |   |                                                                                                                                                                                                                                                                               |
| *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  |   |  — |   | CertificationofPresidentandChiefExecutiveOfficerofPinnacleGasResources,Inc.pursuantto18U.S.C.Section1350,asadoptedpursuanttoSection906oftheSarbanes-OxleyActof2002.                                                                                                                |
|   |   |         |   |                                                                                                                                                                                                                                                                               |
| *32.2  |   |  — |   | Certification of Senior  Vice President, Chief Financial Officer and Secretary of Pinnacle Gas  Resources, Inc. pursuant to 18 U.S.C. Section 1350, as adopted  pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                                          |

 

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*              Filed herewith

 

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**SIGNATURES**

 

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

 
|   | PINNACLE GAS  RESOURCES, INC. |
|--------|-------------------------------|
|   |                          |   |
|   | By:                           | /s/ Peter G.  Schoonmaker |
|   | Name:                         | Peter G.  Schoonmaker |
|   | Title:                        | *President,  Chief Executive Officer and Director* |
|   |                          | (Principal  Executive Officer) |
|   |                          |   |
|   | Date:                         | August 19,  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:                         | August 19,  2009 |
|        |                               |  |  |

 

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