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**UNITEDSTATES**

**SECURITIESAND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

**Form 10-Q**

 

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**x****      QUARTERLY REPORT PURSUANT TOSECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**

** **

**For the quarterly period ended June 30, 2010**

** **

**or**

** **

**o****  TRANSITION REPORT PURSUANT TOSECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**

 

**For the transition period from                    to                    **

 

**Commission file number: 001-33457**

 

**PinnacleGas Resources, Inc.**

(Exact name of registrant as specified in itscharter)

 

| **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’stelephone number, including area code)

 

Indicate by check markwhether the registrant (1) has filed all reports required to be filed bySection 13 or 15(d) of the Securities Exchange Act of 1934 during thepreceding 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 check markwhether the registrant has submitted electronically and posted on its corporateWeb site, if any, every Interactive Data File required to be submitted andposted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter)during the preceding 12 months (or for such shorter period that the registrantwas required to submit and post such files). Yes o No o

 

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

 

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

 

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

 

30,303,427 shares of theregistrant’s Common Stock were outstanding as of August 16, 2010.

 

 

 

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**PINNACLE GAS RESOURCES, INC.**

 

**Index to Form 10-Q**

 
| ** **                                                                                          | **Page** |
|-----------------------------------------------------------------------------------------------------|----------|
| Cautionary Statement Concerning Forward-Looking  Statements                                         | 1        |
| Part I. FINANCIAL INFORMATION                                                                  | 3        |
| Item 1. Financial Statements                                                                        | 3        |
| Balance Sheets as of December 31, 2009 and June  30, 2010 (unaudited)                          | 3        |
| Statements of Operations for the three and six months  ended June 30, 2010 and 2009 (unaudited)     | 4        |
| Statements of Cash Flows for the six months ended June  30, 2010 and 2009 (unaudited)               | 5        |
| Statements of Stockholders’ Equity at June 30, 2010  (unaudited)                               | 6        |
| Notes to Financial Statements (unaudited)                                                           | 7        |
| Item 2. Management’s Discussion and Analysis of  Financial Condition and Results of Operations | 19       |
| Overview                                                                                            | 19       |
| Economic and Natural Gas Pricing Environment                                                        | 19       |
| Credit Facility and Liquidity                                                                       | 20       |
| Critical Accounting Policies                                                                        | 20       |
| Trends Affecting Our Business                                                                       | 24       |
| Results  of Operations                                                                              | 25       |
| Liquidity and Capital Resources                                                                     | 28       |
| Item 3. Quantitative and Qualitative Disclosures About  Market Risk                                 | 31       |
| Item 4T. Controls and Procedures                                                                    | 32       |
| Part II.  OTHER INFORMATION                                                                    | 33       |
| Item  1. Legal Proceedings                                                                          | 33       |
| Item  1A. Risk Factors                                                                              | 33       |
| Item 2. Unregistered Sales of Equity Securities and  Use of Proceeds                                | 34       |
| Item 3. Defaults Upon Senior Securities                                                             | 34       |
| Item 4. Submission of Matters to a Vote of Security  Holders                                        | 34       |
| Item  5. Other Information                                                                          | 34       |
| Item 6. Exhibits                                                                                    | 34       |

 

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**CAUTIONARYSTATEMENT CONCERNING FORWARD-LOOKING STATEMENTS**

 

Weare including the following discussion to inform you of some of the risks anduncertainties that can affect our company and to take advantage of the “safeharbor” protection for forward-looking statements that applicable federalsecurities law affords. Various statements in this prospectus, including thosethat express a belief, expectation, or intention, as well as those that are notstatements of historical fact, are forward looking statements. These includestatements relating to such matters as:

 

· our financial position oroperating results;

 

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

 

· our business strategy;

 

· our budget;

 

· the amount, nature andtiming of capital expenditures;

 

· the drilling of wells;

 

· the development of naturalgas and oil properties and commercial potential of these properties;

 

· the timing and amount offuture production of natural gas and oil;

 

· our operating costs andother expenses;

 

· our estimated future netrevenues from natural gas and oil reserves and the present value thereof;

 

· our cash flow andanticipated liquidity; and

 

· our other plans and objectives for futureoperations

 

Whenwe use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,”“estimate,” “plan,” “predict,” “project,” their negatives, or other similarexpressions, the statements which include those words are usually forwardlooking 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:

 

· theavailability of capital;

 

· fluctuationsin the commodity prices for natural gas and crude oil and their relatedeffects, including on cash flows and potential impairments of oil and gasproperties;

 

· regionalprice differentials;

 

· theextent of our success in discovering, developing and producing reserves,including the risks inherent in exploration and development drilling, wellcompletion and other development activities;

 

· thelack of liquidity of our equity securities;

 

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

 

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· engineering, mechanical ortechnological difficulties with operational equipment, in well completions andworkovers, and in drilling new wells;

 

· the effects of governmentregulation and permitting and other legal requirements;

 

· the uncertainty inherent inestimating future natural gas and oil production or reserves;

 

· production variances fromexpectations;

 

· our ability to develop andreplace reserves;

 

· operating hazards attendantto the natural gas and oil business, including down-hole drilling andcompletion risks that are generally not recoverable from third parties orinsurance;

 

· potential mechanicalfailure or under-performance of significant wells;

 

· environmental-relatedproblems;

 

· the availability and costof materials and equipment;

 

· our dependence upon keypersonnel;

 

· our ability to find andretain skilled personnel;

 

· delays in anticipatedstart-up dates;

 

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

 

· land issues and the costsassociated with perfecting title for natural gas rights in some of ourproperties;

 

· our ability to effectivelymarket our production;

 

· competition from, and thestrength and financial resources of, our competitors; and

 

· generaleconomic conditions.

 

Whenyou consider these forward-looking statements, you should keep in mind thesefactors and the other factors discussed in the “Risk Factors” section of ourannual report on Form 10-K for the year ended December 31, 2009 and thisquarterly report on Form 10-Q.

 

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**Part I. FINANCIAL INFORMATION**

 

**ITEM 1. FINANCIAL STATEMENTS**

 

**PINNACLE GAS RESOURCES, INC.**

**Balance Sheets**

 
| ** **                                                                                                                                                               | ** ** | **June 30,********2010** | ** **   | **December 31,********2009** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------|--------------|-----------------------------------|------------|
| ** **                                                                                                                                                               | ** ** | **(unaudited)**               | ** **   | **(audited)**                     | ** ** |
| ** **                                                                                                                                                               | ** ** | **(in thousands, except**     | ** **   |
| ** **                                                                                                                                                               | ** ** | **share and**                 | ** **   |
| ** **                                                                                                                                                               | ** ** | **per share data)**           | ** **   |
| **Assets**                                                                                                                                                               |       |                          |         |                              |       |
| Current assets                                                                                                                                                           |       |                          |         |                              |       |
| Cash and cash equivalents                                                                                                                                                |       | $                             |  144    |                              | $          |  175 |   |
| Receivables                                                                                                                                                              |       |                          |         |                              |       |
| Accrued gas sales                                                                                                                                                        |       | 866                           |         | 1,240                             |       |
| Joint interest receivables, net of $14 and $100  allowance for doubtful accounts, respectively                                                                           |       | 2,173                         |         | 1,207                             |       |
| Derivative instruments                                                                                                                                                   |       | 903                           |         | —                            |       |
| Inventory of material held for exploration and  development                                                                                                              |       | 56                            |         | 229                               |       |
| Restricted certificates of deposits                                                                                                                                      |       | —                        |         | 142                               |       |
| Prepaid expenses                                                                                                                                                         |       | 22                            |         | 134                               |       |
| Total current assets                                                                                                                                                     |       | 4,164                         |         | 3,127                             |       |
| Property and equipment, at cost, net of  accumulated depreciation                                                                                                        |       | 313                           |         | 1,055                             |       |
| Oil and gas properties, using full cost  accounting, net of accumulated depletion and impairment                                                                         |       |                          |         |                              |       |
| Proved                                                                                                                                                                   |       | 9,694                         |         | 9,477                             |       |
| Unproved                                                                                                                                                                 |       | 49,750                        |         | 48,700                            |       |
| Inventory of material held for exploration and  development                                                                                                              |       | 390                           |         | 223                               |       |
| Deposits                                                                                                                                                                 |       | 57                            |         | 76                                |       |
| Restricted certificates of deposit                                                                                                                                       |       | 499                           |         | 1,842                             |       |
| Total assets                                                                                                                                                             |       | $                             |  64,867 |                              | $          |  64,500 |   |
| **Liabilities and Stockholders’ Equity**                                                                                                                            |       |                          |         |                              |       |
| Current liabilities                                                                                                                                                      |       |                          |         |                              |       |
| Long term debt-current portion                                                                                                                                           |       | $                             |  5,154  |                              | $          |  6,148 |   |
| Derivative instruments, current                                                                                                                                          |       | —                        |         | 1,375                             |       |
| Trade accounts payable                                                                                                                                                   |       | 9,873                         |         | 9,058                             |       |
| Revenue distribution payable                                                                                                                                             |       | 4,632                         |         | 3,328                             |       |
| Drilling prepayments from joint interest owners                                                                                                                          |       | 45                            |         | 63                                |       |
| Asset retirement obligations, current                                                                                                                                    |       | 817                           |         | 721                               |       |
| Accrued liabilities                                                                                                                                                      |       | 4,002                         |         | 3,090                             |       |
| Total current liabilities                                                                                                                                                |       | 24,523                        |         | 23,783                            |       |
| Asset retirement  obligations, non-current                                                                                                                               |       | 2,178                         |         | 2,216                             |       |
| Production taxes, non-current                                                                                                                                            |       | 462                           |         | 385                               |       |
| Long term debt, non-current                                                                                                                                              |       | 727                           |         | 743                               |       |
| Total liabilities                                                                                                                                                        |       | 27,890                        |         | 27,127                            |       |
| Commitments and contingencies                                                                                                                                            |       | —                        |         | —                            |       |
| Stockholders’ equity                                                                                                                                                |       | —                        |         | —                            |       |
| Common stock, $0.01 par value; 100,000,000  authorized and 30,310,893 and 30,108,023 shares issued and outstanding at June  30, 2010 and December 31, 2009, respectively |       | 289                           |         | 289                               |       |
| Additional paid-in capital                                                                                                                                               |       | 151,949                       |         | 151,725                           |       |
| Accumulated deficit                                                                                                                                                      |       | (115,261                      | )            | (114,641                          | )          |
| Total stockholders’ equity                                                                                                                                          |       | 36,977                        |         | 37,373                            |       |
| Total liabilities and stockholders’ equity                                                                                                                          |       | $                             |  64,867 |                              | $          |  64,500 |   |

 

See Notes to Financial Statements (unaudited)

 

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**PINNACLE GAS RESOURCES, INC.**

**Statementsof Operations**

**(unaudited)**

 
| ** **                                                    | ** ** | **Three Months Ended**              | ** ** | **Six Months Ended** | ** ** |
|---------------------------------------------------------------|------------|-------------------------------------|------------|----------------------|------------|
| ** **                                                    | ** ** | **June 30,**                   | ** ** | **June 30,**    | ** ** |
| ** **                                                    | ** ** | **2010**                            | ** ** | **2009**             | ** ** | **2010** | ** ** | **2009** | ** ** |
| ** **                                                    | ** ** | **(in thousands, except share and** | ** ** |
| ** **                                                    | ** ** | **per share data)**                 | ** ** |
| Revenues                                                      |       |                                |       |                 |       |   |   |   |   |
| Gas sales                                                     |       | $                                   | 1,936      |                 | $          | 1,605 |   | $ | 4,782 |   | $ | 4,370 |   |
| Realized gain on derivatives                                  |       | 590                                 |       | 2,053                |       | 124 |   | 3,510 |   |
| Total revenues                                                |       | 2,526                               |       | 3,658                |       | 4,906 |   | 7,880 |   |
| Cost of revenues and expenses                                 |       |                                |       |                 |       |   |   |   |   |
| Lease operating expenses                                      |       | 769                                 |       | 939                  |       | 1,787 |   | 2,124 |   |
| Production taxes                                              |       | 208                                 |       | 140                  |       | 526 |   | 418 |   |
| Marketing and transportation                                  |       | 753                                 |       | 895                  |       | 1,476 |   | 2,145 |   |
| General and administrative, net                               |       | 1,017                               |       | 1,183                |       | 2,424 |   | 2,214 |   |
| Depreciation, depletion, amortization and  accretion          |       | 843                                 |       | 916                  |       | 1,558 |   | 2,744 |   |
| Impairment of oil and gas properties                          |       | —                              |       | 6,431                |       | — |   | 23,250 |   |
| Total cost of revenues and expenses                           |       | 3,590                               |       | 10,504               |       | 7,771 |   | 32,895 |   |
| Operating loss                                                |       | (1,064                              | )          | (6,846               | )          | (2,865 | ) | (25,015 | ) |
| Other income (expense)                                        |       |                                |       |                 |       |   |   |   |   |
| Unrealized gain/(loss) on derivatives                         |       | (610                                | )          | (2,704               | )          | 2,278 |   | (2,133 | ) |
| Interest income                                               |       | 19                                  |       | 26                   |       | 33 |   | 34 |   |
| Other income                                                  |       | 93                                  |       | 95                   |       | 238 |   | 200 |   |
| Interest expense                                              |       | (207                                | )          | (30                  | )          | (304 | ) | (55 | ) |
| Total other income (expense)                                  |       | (705                                | )          | (2,613               | )          | 2,245 |   | (1,954 | ) |
| Net loss before income taxes                                  |       | (1,769                              | )          | (9,459               | )          | (620 | ) | (26,969 | ) |
| Income taxes                                                  |       | —                              |       | —               |       | — |   | — |   |
| Net loss attributable to common stockholders                  |       | $                                   | (1,769     | )                    | $          | (9,459 | ) | $ | (620 | ) | $ | (26,969 | ) |
| Basic and diluted net loss per share                          |       | $                                   | (.06       | )                    | $          | (0.32 | ) | $ | (.02 | ) | $ | (0.92 | ) |
| Weighted average shares outstanding — basic and  diluted |       | 30,318,454                          |       | 29,364,087           |       | 30,282,892 |   | 29,277,885 |   |

 

See Notes to Financial Statements (unaudited)

 

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**PINNACLE GAS RESOURCES, INC.**

**Statementsof Cash Flows**

**(in thousands)**

**(unaudited)**

 
| ** **                                                                                | ** ** | **For the Six Months********Ended********June 30,** | ** ** |
|-------------------------------------------------------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                                                                                | ** ** | **2010**                                                 | ** ** | **2009** | ** ** |
| Cash flows from operating activities                                                      |       |                                                     |       |   |   |
| Net loss                                                                                  |       | $                                                        | (620       | ) | $ | (26,969 | ) |
| Adjustments to reconcile net loss to net cash  provided by (used in) operating activities |       |                                                     |       |   |   |
| Impairment of oil and gas properties                                                      |       | —                                                   |       | 23,250 |   |
| Depreciation, depletion, amortization and  accretion                                      |       | 1,558                                                    |       | 2,723 |   |
| Gain on derivatives                                                                       |       | (2,402                                                   | )          | (1,377 | ) |
| Stock-based compensation                                                                  |       | 224                                                      |       | 508 |   |
| Changes in assets and liabilities                                                         |       |                                                     |       |   |   |
| (Increase) decrease in receivables                                                        |       | (592                                                     | )          | 1,515 |   |
| Decrease in inventory of material held for  exploration and development                   |       | 173                                                      |       | 26 |   |
| Decrease in prepaid expenses                                                              |       | 112                                                      |       | 100 |   |
| Increase in accounts payable and accrued  liabilities                                     |       | 1,798                                                    |       | 820 |   |
| Increase (decrease) in revenue distribution  payable                                      |       | 1,304                                                    |       | (1,714 | ) |
| (Decrease) increase in drilling prepayments                                               |       | (18                                                      | )          | 56 |   |
| Asset retirement obligations settled this period                                          |       | (49                                                      | )          | — |   |
| Net cash provided by (used in) operating  activities                                      |       | 1,488                                                    |       | (1,062 | ) |
| Cash flows from investing activities                                                      |       |                                                     |       |   |   |
| Capital expenditures — exploration and production                                    |       | (1,880                                                   | )          | (2,488 | ) |
| Capital expenditures — property and equipment                                        |       | (90                                                      | )          | (88 | ) |
| Proceeds received from sale of oil and gas  properties                                    |       | —                                                   |       | 3,200 |   |
| Decrease in purchase of restricted certificate of  deposit and deposits                   |       | 1,504                                                    |       | 120 |   |
| Increase in inventory held for exploration and  development                               |       | (167                                                     | )          | (20 | ) |
| Realized gain on derivatives                                                              |       | 124                                                      |       | 3,510 |   |
| Net cash (used in) provided by investing  activities                                      |       | (509                                                     | )          | 4,234 |   |
| Cash flows from financing activities                                                      |       |                                                     |       |   |   |
| Principal payments on note payable                                                        |       | (1,010                                                   | )          | (3,471 | ) |
| Net cash used in financing activities                                                     |       | (1,010                                                   | )          | (3,471 | ) |
| Net decrease in cash and cash equivalents                                                 |       | (31                                                      | )          | (299 | ) |
| Cash and cash equivalents at beginning of the year                                        |       | 175                                                      |       | 346 |   |
| Cash and cash equivalents at June 30, 2010 and  2009, respectively                        |       | $                                                        | 144        |   | $ | 47 |   |
| Noncash investing and financing activities                                                |       |                                                     |       |   |   |
| Capital expenditures included in trade accounts  payable                                  |       | $                                                        | 6,413      |   | $ | 6,740 |   |
| Asset retirement obligation included in oil and  gas properties                           |       | 1                                                        |       | — |   |
| Supplemental cash flow information                                                        |       |                                                     |       |   |   |
| Cash payments for interest, net of amount  capitalized                                    |       | $                                                        | 304        |   | $ | 55 |   |

 

See Notes to Financial Statements (unaudited)

 

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**PINNACLE GAS RESOURCES, INC.**

**Statementof Stockholders’ Equity**

**(in thousands, except for share data)**

 
| ** **                                  | ** ** | **Common Stock** | ** ** | **Additional********Paid-In** | ** ** | **Accumulated** | ** ** | ** **  | ** ** |
|---------------------------------------------|------------|------------------|------------|-------------------------------|------------|-----------------|------------|-------------|------------|
| ** **                                  | ** ** | **Shares**       | ** ** | **Amount**                    | ** ** | **Capital**     | ** ** | **Deficit** | ** ** | **Total** | ** ** |
|                                        |       |             |       |                          |       |            |       |        |       |   |   |
| Balance at December 31, 2009           |       | 30,108,023       |       | $                             | 289        |            | $          | 151,725     |       | $ | (114,641 | ) | $ | 37,373 |   |
| Issuance of restricted shares (unaudited)   |       | 212,502          |       | —                        |       | 187             |       | —      |       | 187 |   |
| Forfeiture of restricted shares (unaudited) |       | (9,632           | )          | —                        |       | —          |       | —      |       | — |   |
| Stock-based compensation (unaudited)        |       | —           |       | —                        |       | 37              |       | —      |       | 37 |   |
| Net loss (unaudited)                        |       | —           |       | —                        |       | —          |       | (620        | )          | (620 | ) |
| Balance at June 30, 2010 (unaudited)        |       | 30,310,893       |       | $                             | 289        |            | $          | 151,949     |       | $ | (115,261 | ) | $ | 36,977 |   |

 

See Notes to Financial Statements (unaudited)

 

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**Notes toFinancial Statements**

**(Unaudited)**

 

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

 

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

 

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

 

OnFebruary 23, 2010, the Company entered into an Agreement and Plan ofMerger with Powder Holdings, LLC, a Delaware limited liability company andPowder Acquisition Co., a direct, wholly owned subsidiary of Powder Holdings (“MergerAgreement”).  Powder Holdings is controlledby an investor group led by Scotia Waterous (USA) Inc. and includes certainmembers of the Company’s management team. On April 2, 2010, the Company filed apreliminary proxy statement relating to the merger and on June 29, 2010, theCompany filed a definitive proxy statement relating to the merger, with theU.S. Securities and Exchange Commission. At the special meeting of the shareholders on August 9, 2010, theshareholders of the Company voted to approve a proposal to adopt the MergerAgreement. The Company anticipates that the closing will occur during the thirdquarter, subject to the satisfaction of customary closing conditions and thereceipt of waivers from the Company’s lender, The Royal Bank of Scotland plc.

 

Althoughthe Company anticipates closing will occur in the third quarter, the Companycontinues to communicate with key vendors to manage its obligations andpayables. The Company has entered into agreements with various vendors to makeminimum monthly payments ranging from $1,000 to $45,000 at interest ratesbetween 2% and 12% for the remainder of 2010. The Company has also implementedvarious cost cutting measures, including reducing general and administrativecosts through staff reductions, wage and benefit cuts and a hiring freeze. TheCompany has reduced lease operating expenses by renegotiating water disposalcontracts, reducing service costs and temporarily shutting-in marginalwells.  Management believes thatappropriate steps, including cost-cutting measures, are being taken to makeoperations sustainable in the future. Although the Company is pursuing variousalternatives to provide additional liquidity, including its shareholderapproved merger with Powder, there is no assurance of the likelihood or timingof any of these transactions.

 

In addition the Company hasexecuted hedges of its gas to secure certain operating cash flow levels duringthe remainder of 2010. From January through April 2010, the Companyhad 5,500 MMbtu per day hedged through fixed price swaps at a weighted averageCIG Rocky Mountain Index price of $4.19 per MMbtu.  From May through December 2010, theCompany has 5,500 MMbtu per day hedged through fixed price swaps at a weightedaverage CIG Rocky Mountain Index price of $5.08 per MMbtu.

 

**Note 2 — Basis of Presentation**

 

The accompanying unaudited financial statements include the Company’sproportionate share of assets, liabilities, income and expenses from theproperties in which the Company has a participating interest.  The Company has no subsidiaries or affiliateswith which intercompany transactions are recorded.

 

The accompanying financial statements are unaudited, and in the opinionof management, reflect all adjustments that are necessary for a fairpresentation of the financial position and results of operations for theperiods presented.  All such adjustmentsare of a normal and recurring nature. The following Notes describe only thematerial changes in accounting policies, account details, or financialstatement Notes during the first six months of 2010.  The results for the three and six monthsending June 30, 2010 are not necessarily indicative of the results expected forthe entire year.  These financialstatements should be read in conjunction with the audited financial statementsand the summary of significant accounting policies for prior years contained inthe reports the Company files with the Securities and Exchange Commission,which can be found on the Company’s website at www.pinnaclegas.com or on theSecurities and Exchange Commission website at *www.sec.gov*.

 

*Use of Estimates*

 

The preparation of the Company’s financial statements in conformitywith accounting principles generally accepted in the United States of Americarequires management to make estimates and assumptions that affect the reportedamount of assets and liabilities, disclosure of contingent assets andliabilities at the date of the financial statements and the reported amounts ofrevenues and expenses during the reporting period. Actual results could differfrom these estimates. Significant estimates with regard to the Company’sfinancial statements include the estimated carrying value of 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 future drilling activity,the estimated cost and timing related to asset retirement obligations, theestimated fair value of derivative assets and liabilities, the realizability ofdeferred tax assets, the estimates of expenses and timing of exercise of stockoptions, accrual of operating costs and capital expenditures and revenue.

 

*Oil and Gas Properties*

 

The Company utilizes 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 surrenderedand abandoned leaseholds, delay lease rentals and the fair value of estimatedfuture costs of site restoration, dismantlement and abandonment activities arecapitalized within a cost center. 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 computedon the unit-of-production method based on proved reserves. Amortizable costsinclude estimates of future development costs of proved undeveloped reservesand asset retirement obligations. The Company invests in unevaluated oil andgas properties for the purpose of exploration for proved reserves. The costs ofsuch assets, including exploration costs on properties where a determination ofwhether proved oil and gas reserves will be established is still underevaluation, and any capitalized interest 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.Abandonment of unproved properties is accounted for as an adjustment tocapitalized costs related to proved oil and gas properties, with no lossesrecognized. No impairment was recorded for unevaluated properties for the threeand six months ended June 30, 2010.

 

Substantially all of theremaining unproved properties are expected to be developed and included in theamortization base over the next three to five years, based on projected cashflow from operations combined with raising additional capital. Salvage value istaken into account in determining depletion rates and is based on the Company’sestimate of the value of equipment and supplies at the time the well isabandoned. As of June 30, 2010 and December 31, 2009, the estimated value wasapproximately $6.8 million.

 

Under the full cost methodof accounting rules, capitalized costs less accumulated depletion and relateddeferred income taxes may not exceed a ‘‘ceiling’’ value which is the sum of(1) the present value discounted at 10% of estimated future net revenueusing current costs and first day of the month twelve month average CIG prices,including the effects of derivative instruments designated as cash flow hedgesbut excluding the future cash outflows associated with settling assetretirement obligations that have been accrued on the balance sheet, less anyrelated income tax effects; plus (2) the cost of properties not beingamortized, if any; plus (3) the lower of costs or estimated fair value ofunproved properties; less (4) the income tax effects related todifferences in the book to tax basis of oil and gas properties. This isreferred to as the ‘‘full cost ceiling limitation.’’ If capitalized costsexceed the limit, the excess must be charged to expense. The expense may not bereversed in future periods. At the end of each quarter, the Company calculatesthe full cost ceiling limitation. At June 30, 2010, the full cost ceilinglimitation exceeded the capitalized cost of the Company’s oil and gasproperties by approximately $5.2 million based on the first day of the month,twelve month average CIG price of approximately $3.76 per Mcf. Therefore, noimpairment was taken for the quarter ended June 30, 2010. An impairment of $6.4million was taken for the quarter ended June 30, 2009 based on a natural gas priceof $3.09 per Mcf.

 

*Per Share Information*

 

Basic loss per share iscomputed by dividing net loss from continuing operations attributable to commonstock by the weighted average number of shares of common stock outstandingduring each period. Diluted earnings per share are computed by adjusting theaverage number of shares of common stock outstanding for the dilutive effect,if any, of common stock equivalents such as stock options and warrants. For thesix months ended June 30, 2010, basic and diluted net loss per share was$0.02.  During the six months ended June 30, 2010, 835,446 options andstock appreciation rights were excluded because they were anti-dilutive.

 

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| ** **                                                   | ** ** | **(in thousands except per share data)**           | ** ** |
|--------------------------------------------------------------|------------|----------------------------------------------------|------------|
| ** **                                                   | ** ** | **Three********Months Ended********June 30,** | ** ** | **Six********Months Ended   June 30,** | ** ** | **Three********Months Ended********June 30,** | ** ** | **Six********Months Ended********June 30,** | ** ** |
| ** **                                                   | ** ** | **2010**                                           | ** ** | **2009** | ** ** |
| Net loss                                                     |       | $                                                  | (1,769     | ) | $ | (620 | ) | $ | (9,459 | ) | $ | (26,969 | ) |
| Common shares outstanding:                                   |       |                                               |       |   |   |   |   |   |   |
| Historical common shares outstanding at beginning  of period |       | 30,247                                             |       | 30,108 |   | $ | 29,188 |   | $ | 29,194 |   |
| Weighted average common shares issued                        |       | 71                                                 |       | 175 |   | 176 |   | 84 |   |
| Weighted average common shares outstanding-basic             |       | 30,318                                             |       | 30,283 |   | 29,364 |   | 29,278 |   |
| Net loss per share-basic and diluted                         |       | (0.06                                              | )          | (0.02 | ) | (0.32 | ) | (0.92 | ) |
|                                                              |            |                                                    |            |  |  |  |  |  |  |  |  |  |  |

 

*Income Taxes*

 

The Company uses the assetand liability method of accounting for income taxes. Deferred tax assets andliabilities are recognized for the expected future tax consequences oftemporary differences between the financial statement and tax bases of assetsand liabilities. If appropriate, deferred tax assets are reduced by a valuationallowance which reflects expectations of the extent to which such assets willbe realized. As of June 30, 2010 and December 31, 2009, the Companyhad recorded a full valuation allowance for its net deferred tax asset.

 

*New Accounting Pronouncements*

 

The Company adopted FASB ASC Update 2010-06, “FairValue Measurements and Disclosures” which amends ASC Update 2010-06 to requireadditional disclosures concerning transfers between Levels 1 and 2, inputs andvaluation techniques used to value Level 2 and 3 measurements, and push down ofpreviously prescribed fair value disclosures to each class of asset andliability for Levels 1, 2, and 3.  These disclosures were effective forthe Company for the quarter ended June 30, 2010.  The adoptionof this pronouncement did not have a material impact on the Company’sconsolidated financial statements.

 

In addition, ASC Update 2010-06 requires thatpurchases, sales, issuances, and settlements for Level 3 measurements bedisclosed.  This portion of the new authoritative guidance is effectivefor interim and annual reporting periods beginning after December 15,2010.  As such, the Company will apply this new authoritative guidance inthe Company’s March 31, 2011, Quarterly Report on Form 10-Q. The adoption of ASC Update 2010-06 will not have a material impact on theCompany’s financial statements.

 

The Company adopted FASB ASC Update 2010-09, “Amendmentsto Certain Recognition and Disclosure Requirements,*”* which eliminates the requirement for SEC filers todisclose the date through which an entity has evaluated subsequentevents.  ASU No. 2010-09 was effective upon issuance and its adoptionhad no impact on the Company’s financial position, results of operations orcash flows.

 

**Note 3 — Asset Retirement Obligations**

 

The Company follows certain accounting provisions that apply to legalobligations associated with the retirement of long-lived assets that resultfrom the acquisition, construction, development and/or the normal operation ofa long-lived asset. These provisions require the Company to recognize anestimated liability for costs associated with the abandonment of its oil andgas properties.

 

A liability for the fair value of an asset 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. The Company’s liability is discounted using its best estimate ofits credit-adjusted risk-free rate. Revisions to the liability could occur dueto changes in estimated abandonment costs, changes in well economic lives or iffederal or state regulators enact new requirements regarding the abandonment ofwells.

 

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Thefollowing is a summary of the Company’s asset retirement obligation activityfor the three and six months ended June 30, 2010 and June 30, 2009(unaudited).

 
| ** **                                     | ** ** | **(in thousands)**                                         | ** ** |
|------------------------------------------------|------------|------------------------------------------------------------|------------|
| ** **                                     | ** ** | **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,** | ** ** |
| ** **                                     | ** ** | **2010**                                                   | ** ** | **2009** | ** ** |
| Beginning balance asset retirement obligations |       | $                                                          | 2,959      |   | $ | 2,937 |   | $ | 3,422 |   | $ | 3,366 |   |
| Additional obligation added during the period  |       | —                                                     |       | 1 |   | — |   | — |   |
| Obligations settled during the period          |       | (18                                                        | )          | (49 | ) | (23 | ) | (23 | ) |
| Accretion expense                              |       | 54                                                         |       | 106 |   | 58 |   | 114 |   |
| Ending balance of asset retirement obligations |       | $                                                          | 2,995      |   | $ | 2,995 |   | $ | 3,457 |   | $ | 3,457 |   |

 

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

 

*Certificates of deposit.*

 

The Company holds a certificate of deposit (“CD”),which expires in July 2011, totalling approximately $160,000. The CD iscollateral for bonding required by the State of Wyoming, the State of Montanaand the Federal Bureau of Land Management. Because the Company intends to renewthe CD in order to maintain its bonding requirements, the Company has includedthe CD in other non-current assets as of June 30, 2010. The issuer of thebond has commenced litigation against the Company to increase its collateralposition, although this litigation was tolled through June 15, 2010 (seeNote 9).

 

On January 1, 2010 the Company held twoCDs for $604,000 and $964,000. These CDs collateralized letters of credit infavor of Powder River Energy Corporation (“PRECorp”) in order to secure powerlines in the Recluse, Kirby, Deer Creek and Cabin Creek areas. These CDs wereto be renewed annually as the amount of the CDs would decrease over time as theCompany paid down the capital cost recovery amounts on its monthly billing. On February 14,2010, the $604,000 CD was lowered to $513,000 and renewed on February 19,2010. The $964,000 CD was set to expire on May 27, 2010. However, theCompany was presented with an opportunity to pay the capital cost recovery workorders in full which would result in a savings of approximately $282,000 ininterest costs.  On May 18, 2010,the Company cashed the $513,000 CD and received approximately $506,000 inproceeds and on May 21, 2010, the Company cashed the second CD andreceived approximately $966,000 in proceeds. On May 20, 2010 the Companywired $500,000 to PRECorp and on May 28, 2010 the Company wiredapproximately $690,000 to PRECorp which fulfilled its obligation to PRECorp. InMarch 2010 the Company posted a cash security deposit to Powder RiverEnergy Corp. of approximately $225,000 to collateralize electrical usage in itsRecluse, Kirby, Deer Creek and Cabin Creek areas. In April 2007, theCompany issued a $1,000,000 letter of credit (“LOC”), which was collateralizedby a CD in favor of Bitter Creek Pipelines, LLC to secure the constructionof a high pressure pipeline and related compression facilities to the Company’sDeer Creek and Kirby areas. Bitter Creek Pipelines, LLC drew approximately$858,000 on this LOC for compression services provided to the Company in 2009.In January of 2010, Bitter Creek Pipelines, LLC drew the remainingbalance of the CD collateralizing this LOC.

 

*Surety Bonds.*

 

From June 2009 through June 30, 2010, the Company posted idlewell surety for approximately $64,000 to the Wyoming Oil and Gas ConservationCommission. The Commission has requested the Company make 18 monthlyinstallments of $12,777 for surety on wells that will need to be plugged by theCompany. The surety amount may be adjusted downward by the Commission if theCompany successfully plugs the proposed wells in question. In addition, theCompany has included a $50,000 payment for bonding requirements in the Company’sKirby Montana area.

 

*Deposits.*

 

The Company has includedapproximately $57,000 related to royalty payments in deposits. These amountsare included in Deposits in the accompanying balance sheet at June 30,2010.

 

**Note 5 — Derivatives**

 

The Company has elected not to designate its derivatives as cash flowhedges under authoritative guidance prescribed by the FASB. These derivativeinstruments are marked to market at the end of each reporting period andchanges in the fair value are recorded in the accompanying statements ofoperations. The aggregate fair values of these contracts were estimated to bean asset 

 

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totaling$903,000 and an asset of $2,213,000 at June 30, 2010 and 2009,respectively. The Company realized a hedging gain of $590,000 and a hedginggain of $2,053,000 for the quarters ended June 30, 2010 and 2009,respectively. As a result of the change in the fair value of the commodityderivatives, the Company had an unrealized loss of $610,000 for the quarterended June 30, 2010 and unrealized loss of $2,704,000 for the quarterended June 30, 2009. For the six months ended June 30, 2010, theCompany realized a hedging gain of $124,000 compared to a hedging gain of$3,510,000 for the six months ended June 30, 2009. For the six monthsended June 30, 2010, the Company had an unrealized gain of $2,278,000compared to an unrealized loss of $2,133,000 for the six months ended June 30,2009. The aggregate of these contracts resulted in a gain on derivatives of$2,403,000 and $1,377,000 for the six months ended June 30, 2010 and 2009,respectively. Unrealized gains and losses are included in gains or losses onderivatives in the statement of operations. Realized gains and losses areincluded in revenues in the statements of operations.  As of June 30, 2010 and 2009, theCompany had natural gas hedges in place as follows:

 

Asof June 30, 2010 and 2009, the Company had natural gas hedges in place asfollows:

 
| **Product and Type of Hedging Contract** | ** ** | **MMbtu Per********Day** | ** ** | **Fixed Price********Range********CIG Index Price** | ** ** | **Time********Period** | ** ** |
|-------------------------------------------------------------------|------------|-------------------------------|------------|--------------------------------------------------------------------|------------|------------------------|------------|
| June 30, 2010 (unaudited)                                    |       |                          |       |                                                               |       |                   |       |
| Natural Gas—Swap                                             |       | 2,000                         |       | $4.48                                                              |       | 01/10-12/10            |       |
| Natural Gas—Swap                                             |       | 1,000                         |       | $5.50                                                              |       | 01/10-12/10            |       |
| Natural Gas—Swap                                             |       | 2,500                         |       | $5.40                                                              |       | 05/10-12/10            |       |
| 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            |       |

 

TheCompany is exposed to credit risk to the extent of nonperformance by thecounterparties in the derivative contracts discussed above; however, theCompany does not anticipate such nonperformance.

 

**Note 6 — Stock Based Compensation**

 

*Options under Stock Incentive Plan*

 

The Company has adopted a stock incentive plan authorizing the grant ofboth incentive and non-statutory stock options. All options allow for thepurchase of common stock at prices not less than the fair market value of suchstock at the date of grant. If the option holder owns more than 10% of thetotal combined voting power of all classes of the Company’s stock, the exerciseprice cannot be less than 110% of the fair market value of such stock at thedate of grant.

 

Options granted under theplan become vested as directed by the Company’s Board of Directors andgenerally expire seven or ten years after the date of grant, unless the optionholder owns more than 10% of the total combined voting power of all classes ofthe Company’s stock, in which case the non-statutory stock options must beexercised within five years of the date of grant. At June 30, 2010, therewere options to purchase 640,000 shares granted under the plan.

 

Theoptions granted since formation in June 2003 vest in general as follows:

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

 

Duringthe three months ended June 30, 2010, the Company did not grant anyoptions to purchase common stock.  Duringthe three and six months ended June 30, 2010 the Company recognized anexpense of approximately $6,000 and $25,000, respectively, based on the fairvalue of the vested options.

 

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Thefollowing table summarizes stock option activity for the six months ended June 30,2010:

 
| ** **                                  | ** ** | **Number of********Shares** | ** ** | **Weighted Average********Exercise Price********Per Share** | ** ** | **Weighted********Average********Remaining********Contractual Life** | ** ** | **Aggregate********Intrinsic value** | ** ** |
|---------------------------------------------|------------|-----------------------------|------------|-------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|--------------------------------------|------------|
| Outstanding, December 31, 2009         |       | 640,000                     |       | $                                                           | 5.81       |                                                                 |       |                                 |       |   |
| Canceled or forfeited                       |       | —                      |       | —                                                      |       |                                                                 |       |                                 |       |
| Outstanding, June 30, 2010 (unaudited) |       | 640,000                     |       | $                                                           | 5.81       |                                                                 | 1.83       |                                 | $          | — |   |
| Exercisable, June 30, 2010 (unaudited) |       | 640,000                     |       | $                                                           | 5.81       |                                                                 | 1.83       |                                 | $          | — |   |

 

Thefollowing table summarizes information about stock options outstanding at June 30,2010:

 
| ** **          | ** ** | **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                                        |       | 0.3 years                                                            |       | 137,500                       |       | $ | 4.00 |   | Black-Scholes  (minimum value) |   |
| $4.80               |       | 265,000                                        |       | 1.7 years                                                            |       | 265,000                       |       | $ | 4.80 |   | Black-Scholes  (minimum value) |   |
| $5.20               |       | 112,500                                        |       | 2.5 years                                                            |       | 112,500                       |       | $ | 5.20 |   | Black-Scholes |   |
| $8.40               |       | 25,000                                         |       | 3.9 years                                                            |       | 25,000                        |       | $ | 8.40 |   | Black-Scholes |   |
| $11.00              |       | 100,000                                        |       | 3.0 years                                                            |       | 100,000                       |       | $ | 11.00 |   | Black-Scholes |   |
| Total               |       | 640,000                                        |       |                                                                 |       | 640,000                       |       |   |   |   |   |

 

*Stock Appreciation Rights under Stock Incentive Plan*

 

TheCompany has adopted a stock incentive plan authorizing the grant of StockAppreciation Rights (“SARs”). A SAR confers on the participant a right toreceive, upon exercise, the excess of the fair market value of a share ofCommon Stock on the date of the exercise over $1.00. Such excess shall be paidin cash or common stock or a combination thereof to the participant. OnJune 1, 2009, 202,280 SARs were granted and 195,446 were outstanding as ofJune 30, 2010.

 

TheSARs granted in June 2010 vest in general as follows:

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

 

AtJune 30, 2010 the Company had unvested options to purchase 128,025 shareswith a weighted average grant date fair market value of $47,000.

 

Thefollowing table summarizes stock appreciation activity for the six months endedJune 30, 2010:

 
| ** **                                    | ** ** | **Shares** | ** ** | **Weighted-********Average********Grant-Date********Fair Value** | ** ** | **Weighted  Average  Remaining  Contractual  Life** | ** ** |
|-----------------------------------------------|------------|------------|------------|------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| Outstanding at December 31, 2009         |       | 202,280    |       | 0.41                                                             |       |                                                |       |
| Canceled or forfeited                         |       | (6,834     | )          | —                                                           |       | —                                              |       |
| Outstanding at June 30, 2010 (unaudited) |       | 195,446    |       | $                                                                | 0.41       |                                                | 5.9        |   |
|                                               |            |            |            |                                                                  |            |                                                     |            |  |

 

Duringthe three and six months ended June 30, 2010, the Company recognizedcompensation expense of approximately $6,000 and $12,000 respectively, based onthe fair value of the vested shares using a Black-Scholes model.

 

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*Restricted Stock under the Stock Incentive Plan*

 

The Company has an incentiveprogram whereby grants of restricted stock have been awarded to members of theBoard of Directors and certain employees. Restrictions and vesting periods forthe awards are determined at the discretion of the Board of Directors and areset forth in the award agreements. During the three and six months ended June 30,2010, the Company recognized compensation expense of approximately $58,000 and$187,000, respectively, based on the fair value of the vested shares.

 

Asummary of the status and activity of the restricted stock for the six monthsended June 30, 2010 is presented below:

 
| ** **                                  | ** ** | **Shares** | ** ** | **Weighted Average  Grant Date  Fair Value** | ** ** |
|---------------------------------------------|------------|------------|------------|---------------------------------------------------|------------|
| Unvested  at December 31, 2009         |       | 342,993    |       | $                                                 | 2.18       |   |
| Granted                                     |       | 212,502    |       | $                                                 | 0.31       |   |
| Forfeited                                   |       | (9,632     | )          | $                                                 | 1.28       |   |
| Vested                                      |       | (282,424   | )          | $                                                 | 0.43       |   |
| Unvested  at June 30, 2010 (unaudited) |       | 263,439    |       | $                                                 | 2.58       |   |

 

Asof June 30, 2010, the Company had approximately $0.4 million ofunrecognized share-based compensation expense related to non-vested stockawards, which is expected to be amortized over the remaining vesting periods ofthree years.

 

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

 

*Credit Facility*

 

EffectiveFebruary 12, 2007, the Company entered into a credit facility whichpermits borrowings up to the borrowing base as designated by the administrativeagent. As of June 30, 2010 and December 31, 2009, the Company had$5.1 million and $6.1 million, respectively, of debt outstanding under thefacility. As described below, the Company is currently unable to borrowadditional amounts under the credit facility due to covenant and borrowing baselimitations and may be further limited in the future based on borrowing baselimitations.

 

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

 

The borrowing base is determined on a semi-annual basis and at suchother additional times, up to twice yearly, as may be requested by either theCompany or the administrative agent and is determined by the administrativeagent in accordance with customary practices and standards for loans of asimilar nature, although such determination is at the administrative agent’sdiscretion as the credit agreement does not provide a specific borrowing baseformula.

 

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 matured June 15, 2010.

 

The Company’s obligations under the credit facility are secured byliens on (i) no less than 90% of the net present value of the oil and gasto be produced from its oil and gas properties that are included in theborrowing base determination, calculated using a discount rate of 10% per annumand reserve estimates, prices and production rates and costs, (ii) optionsto lease, seismic options, permits, and records related to such properties, and(iii) seismic data.

 

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 weighted average interestrate as of June 30, 2010 was 5.0%. The credit agreement provides forvarious fees, including a quarterly commitment fee of 0.5% per annum andengineering 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.

 

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TheCredit Agreement contains covenants that, among other things, restrict theCompany’s ability, subject to certain exceptions, to do the following:

 

·**               **incur liens;

 

·**               **incur debt;

 

·**               **make investments in otherpersons;

 

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

 

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

 

·**               **enter into certain hedging arrangements;

 

·**               **amend material contracts;and

 

·**               **enter into related partytransactions.

 

Withregard to hedging arrangements, the credit agreement provides that acceptablecommodity hedging arrangements cannot be greater than 80 to 85%, depending onthe measurement date, of the Company’s monthly production from its hydrocarbonproperties that are used in the borrowing base determination and that the fixedor floor price of the Company’s hedging arrangements must be equal to orgreater than the gas price used by the lenders in determining the borrowingbase.

 

Thecredit agreement, as amended, also requires that the Company satisfy certainaffirmative covenants, meet certain financial tests, maintain certain financialratios and make certain customary indemnifications to lenders and theadministrative agent. The financial covenants include requirements to maintain:(i) a ratio of EBITDA to cash interest expense of not less than 3.00 to1.00, (ii) a ratio of current assets to current liabilities of not lessthan 1.00 to 1.00, (iii) a total debt to annualized EBITDA ratio of notmore 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.

 

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

 

After an event of default,the outstanding debt bears interest at the default rate under the terms of thecredit agreement. The default rate is (i) with respect to principal, 2%over the otherwise applicable rate and (ii) with respect to interest, feesand other amounts, the Base Rate (as defined in the credit agreement), plus theApplicable Margin (as defined in the credit agreement), plus 2%. Any defaultinterest is payable on demand. Failure to pay the default interest when theadministrative agent demands would be another default. The lenders’ remediesfor defaults under the credit agreement are to terminate further borrowings,accelerate the repayment of indebtedness and/or ultimately foreclose on thecollateral property.

 

OnApril 14, 2009, the Company and the administrative agent entered into thefourth amendment to the credit agreement which reduced the borrowing base asdescribed above and waived compliance with the current ratio financial covenantas of December 31, 2009 and March 31, 2009 and with the restrictivecovenants related to accounts payable, permitted liens and permitted debt untilthe next borrowing base redetermination, subject to certain financialcaps.  On August 19, 2009, thelenders waived compliance with the current ratio financial covenant under theCredit Agreement for the period ending August 26, 2009 and the quarterending June 30, 2010.

 

On August 26, 2009, the Company entered into a fifth amendment tothe credit agreement which provided a waiver of the current ratio covenantthrough October 26, 2009 and for the quarter ending June 30, 2009.The fifth amendment to the credit agreement also extended restrictive covenantsrelated to accounts payable, permitted liens and permitted debt, untilOctober 26, 2009, subject to certain financial caps.

 

On October 20, 2009, the Company and the Lenders executed thesixth amendment to the credit agreement. This amendment established theBorrowing Base for the following amounts in the following applicable periods:

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

 

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

 

On October 26, 2009, the lenders provided a waiver effectivelyextending the terms of the fifth amendment to the credit agreement throughNovember 16, 2009. On November 16, 2009, the lenders provided anadditional waiver effectively extending the terms of the fifth amendment to thecredit agreement through November 23, 2009.

 

On November 23, 2009, the lenders provided an additional waiverextending the terms of the fifth amendment to the credit agreement throughDecember 1, 2009 and for the quarter ended December 31, 2009.

 

On December 1, 2009 the lenders provided an additional waiverextending the terms of the fifth amendment to the credit agreement throughJanuary 5, 2010.

 

On January 5, 2010 the lenders provided an additional waiverextending the terms of the fifth amendment to the credit agreement throughJanuary 12, 2010.

 

On January 13, 2010, the Company entered into a seventh amendmentand waiver to credit agreement (“*waiveragreement*”) with the lenders party thereto. The waiver agreementprovided that the lenders would waive (i) its compliance with certainrestrictions based on the current ratio in the credit agreement,(ii) certain requirements pertaining to the aging of certain accountspayable, and (iii) certain restrictions regarding the amount of liens theCompany has. Default remedies available to the lenders under the creditagreement include acceleration of all principal and interest amounts due underthe credit agreement. The waiver agreement extends the waiver period for theseitems until the earlier of June 15, 2010 and the date of any defaultarising out of a breach or non-compliance with the credit agreement notexpressly waived in the waiver agreement or a breach of the waiver agreement.

 

In addition, the waiver agreement amends the definition of “FinalMaturity Date” under the credit agreement to the earlier of(i) June 15, 2010 or (ii) the date that is thirty days followingthe earlier of (A) the date the merger is withdrawn or terminated in wholeor in part or (B) the date that the lenders have been advised that the mergerwill not proceed.

 

On July 8, 2010, theCompany was notified by its lender that it failed to make the principal andinterest payments due on July 1, 2010 and that such missed paymentsconstituted an Events of Default under the Credit Agreement. The Companyremains obligated to pay all amounts outstanding under the credit agreement.The current amount outstanding under the credit facility is approximately$5,100,000 plus accrued interest.

 

TheCompany has requested additional waivers from its lender; however, there can beno assurance that it will be able to obtain such waivers or that such waiverswill be obtained on acceptable terms. If the Company is unable to obtain futurewaivers and/or to comply with the restrictive covenants, the lender could forecloseon properties held by liens.  Due to borrowing base limitations and waiverstipulations, the Company is currently unable to incur additional indebtednessunder the credit facility.

 

*Office Building Loan*

 

On November 15, 2005, the Company entered into a mortgage loansecured by its office building in Sheridan, Wyoming in the aggregate principalamount of $829,000. The promissory note provides for monthly payments ofprincipal and interest in the initial amount of $6,400 and unpaid principalthat bore interest at 6.875% until November 15, 2008, currently bearsinterest at a variable base rate plus 0.5% and will bear interest at 18% upon adefault. The variable base rate is based on the lender’s base rate. Thematurity date of this mortgage is November 15, 2015, at which time aprincipal and interest payment of $520,800 will become due. As of June 30,2010, the Company had $717,000 outstanding in principal on this mortgage. OnNovember 15, 2008, the interest rate on the mortgage loan changed from afixed rate of 6.875% to a variable rate. As of June 30, 2010, the variablerate was 4.0%.

 

**Note 8 — Fair Value Measurements**

 

Effective January 1, 2008, the Company adopted the authoritativeguidance that applies to all financial assets and liabilities required to bemeasured and reported on a fair value basis. Beginning January 1, 2009,the Company also applied the guidance to non-financial assets and liabilitiesmeasured at fair value on a nonrecurring basis, including proved oil and gasproperties and other long-lived assets and asset retirement obligationsinitially measured at fair value. The guidance defines fair value as the pricethat would be received to sell an asset or paid to transfer a liability (anexit price) in an orderly transaction between market participants at the 

 

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measurementdate. The guidance establishes a hierarchy for inputs used in measuring fair valuethat maximizes the use of observable inputs and minimizes the use ofunobservable inputs by requiring that the most observable inputs be used whenavailable. Observable inputs are inputs that market participants would use inpricing the asset or liability developed based on market data obtained fromsources independent of the Company. Unobservable inputs are inputs that reflectthe Company’s assumptions of what market participants would use in pricing theasset or liability based on the best information available in thecircumstances. The financial and nonfinancial assets and liabilities areclassified based on the lowest level of input that is significant to the fairvalue measurement. The hierarchy is broken down into three levels based on thereliability of the inputs as follows:

 

·                  Level 1—Quoted pricesin active markets for identical assets or liabilities;

 

·                  Level 2—Quoted pricesin active markets for similar assets and liabilities, that are observable forthe asset or liability; or

 

·                  Level 3—Unobservablepricing inputs that are generally less observable from objective sources, suchas discounted cash flow models or valuations.

 

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, 2010 (in thousands):

 
| ** **                         | ** ** | **Level 1** | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** ** |
|------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|-----------|------------|
| Assets                             |       |             |       |             |       |             |       |      |       |
| Oil and gas derivative instruments |       | $                | —     |             | $          | 903              |       | $         | —     |   | $ | 903 |   |
| Total                              |       | $                | —     |             | $          | 903              |       | $         | —     |   | $ | 903 |   |

 

TheCompany adopted FASB ASC Update 2010-06, “Fair Value Measurements andDisclosures” which amends ASC Update 2010-06 to require additional disclosuresconcerning transfers between Levels 1 and 2, inputs and valuation techniquesused to value Level 2 and 3 measurements, and push down of previouslyprescribed fair value disclosures to each class of asset and liability forLevels 1, 2, and 3. The Company determines the fair value of these swapcontracts under the income approach using a discounted cash flow model.  The valuation model requires a variety ofinputs, including contractual terms, projected gas market prices, discountrate, and credit risk adjustments, as appropriate.  The Company has consistently applied thisvaluation technique in all periods presented and believes it has obtained themost accurate information available for the types of derivative instruments itholds. These disclosures were effective for the Company for the quarter ended June 30, 2010. The adoption of this pronouncement did not have a material impact on theCompany’s consolidated financial statements.

 

The Company’s estimate of the fair value of derivative financialinstruments includes consideration of the counterparty’s credit worthiness, theCompany’s credit worthiness, and the time value of money. The consideration ofthese factors results in an estimated exit-price for each derivative asset orliability under a market place participant’s view.

 

**Note 9 — Commitments and Contingencies**

 

*Operating Lease*

 

Uponpurchase of its building in August 2005, the Company was assigned thelease agreements for existing tenants and executed lease agreements with newtenants in the building. The leases expire from January 2010 toJanuary 2013. Future minimum lease income under noncancelable operatingleases is as follows:

 
| **Year Ending December 31,** | ** ** | ** ** | ** ** |
|-----------------------------------|------------|------------|------------|
| 2010                              |       | $          | 57,000     |   |
| 2011                              |       | 60,000     |       |
| 2012                              |       | 44,000     |       |
| 2013                              |       | 44,000     |       |
| Total minimum lease payments      |       | $          | 205,000    |   |

 

*GasGathering Contracts*

 

TheCompany has entered into gas gathering and compression agreements with serviceproviders in order to compress and transport its gas to the point of sale.Compression agreements and gathering agreements are based on a fee per Mcfeither compressed 

 

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orgathered. The Company accounts for these fees as a marketing and transportationexpense. The Company does not pay or charge marketing fees associated with themovement and sale of natural gas.

 

*Litigation*

 

From time to time, the Company is subject to legal proceedings andclaims that arise in the ordinary course of its business. In addition, likeother natural gas and oil producers and marketers, the Company’s operations aresubject to extensive and rapidly changing federal and state environmental,health and safety and other laws and regulations governing air emissions,wastewater discharges, and solid and hazardous waste management activities. Asa result, it is extremely difficult to reasonably quantify future environmentaland regulatory related expenditures.

 

The following represent legal actions in which the Company is involved.No assurance can be given that these legal actions will be resolved in theCompany’s favor. However, the Company’s management believes, based on itsexperiences to date, that these matters will not have a material adverse impacton the Company’s business, financial position or results of operations.

 

The Company, together with the State of Montana, the Montana Departmentof Environmental Quality, the Montana Board of Oil and Gas Conservation and theDepartment of Natural Resources, were named as defendants in a lawsuit (CivilCause No. DV-05-27) filed on May 19, 2005 in the Montana22nd 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 as operatorand owns a working interest in the minerals under lease. The plaintiff soughtto permanently enjoin the State of Montana and its administrative bodies fromissuing licenses or permits, or authorizing the removal of ground water fromunder the plaintiff’s ranch. In addition, the plaintiff further sought topreliminarily and permanently enjoin the Company on the basis that the Company’soperations lacked adequate safeguards required under the Montana stateconstitution. On August 25, 2005, the district judge issued an orderdenying without prejudice the application for temporary restraining order andpreliminary injunction requested by the plaintiff. The case was appealed by theplaintiff to the Montana Supreme Court. On November 16, 2005, the MontanaSupreme Court issued an order that denied enjoining the Coal Creek POD, andsubsequently, the Montana Supreme Court remanded the case back to the districtcourt for a decision on the merits.

 

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

 

On July 14, 2008, the district court issued a summary judgmentorder in the combined case, and the order was subsequently entered as ajudgment on August 15, 2008. As a result, the Company has continued itsoperations in the two project areas. To date, there has been no appeal by theplaintiff.

 

In April and September 2005, the U.S. Bureau of LandManagement in Miles City, Montana issued suspensions of operations for themajority of the Company’s federal leases in Montana. The suspensions wereissued based upon a court order issued on April 5, 2005 by the U.S.District Court of Montana that required the BLM to complete a SupplementalEnvironmental Impact Statement (SEIS) to address phased development of coal bednatural gas. The U.S. Ninth Circuit Court of Appeals also issued an order onMay 31, 2005 which enjoined the BLM from approving coal bed natural gasproduction projects in the Powder River Basin of Montana. Both of these actionsplaced limitations on lease development until completion of the SEIS.

 

The 2005 injunction was lifted by the Ninth Circuit Court of Appeals onOctober 29, 2007. The record of decision (ROD) for the SEIS was signed bythe 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. The Company has received lettersfrom the BLM with amended lease terms of the affected leases. Leases that weresuspended have been placed back into an active lease status with the primaryterm increasing for approximately three to five years based on the time periodthe leases were in suspension.

 

On July 6, 2009, the Company filed suit (Cause No. DV09-35)against Big Sky Energy LLC and Quaneco L.L.C., in the Twenty-SecondJudicial District Court, Big Horn County, Montana alleging claims for breach ofcontract, breach of implied covenant of good faith and fair dealing, tortuousinterference with business, tortuous interference with contractual relationsand slander of title. The Company is amending the complaint to add aforeclosure action against Big Sky Energy LLC’s and Quaneco L.L.C.’scollective interest in the developed properties in Montana for non payment ofinvoices in the amount of $298,689.

 

The Company will continue to vigorously pursue payment of the amountsowed including interest and attorney’s fees along with foreclosure proceedingsand any other rights and remedies available to us pursuant to the JointOperating Agreement dated June 23, 2003, as amended.

 

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The Company was named as a defendant in litigation brought by RLIInsurance Company (Civil Cause No. 09-CV-157-J) filed in United StatesDistrict Court for the District of Wyoming on July 6, 2009.  The complaint alleged that the Company failedto provide $1,439,360 in additional collateral requested by plaintiff to securecertain bonds issued by plaintiff on behalf of the Company.  Plaintiff sought the additional bondcollateral plus attorney’s fees and costs. On March 18, 2010, Pinnacle Gas Resources, Inc. and RLIInsurance Company entered into a Tolling Agreement.  The agreement stipulated that the partiesdismiss all claims and counterclaims in the litigation captioned RLI InsuranceCompany v. Pinnacle Gas Resources, Inc., Case No. 09-CV-157-J (D.Wyo.), without prejudice.  The agreementfurther stipulated that each party will extend the period within which eitherparty may institute a claim, counterclaim, action or proceeding up to andincluding June 16, 2010.  Theagreement also obligated The Company to continue to solicit market quotes forthe purpose of replacing all bonds or bonding relationships which exist betweenthe Company and RLI Insurance Company. The Tolling Agreement has lapsed and, to the Company’s knowledge on thedate hereof, RLI Insurance Company has not re-filed its claims against theCompany.

 

TheCompany is a party to two stockholder class action lawsuit filed in theDelaware Court of Chancery.  On March 24,2010, the Delaware Court of Chancery entered an order consolidating the twoactions under the caption In re Pinnacle Gas Resources Shareholder Litigation,C.A. No. 5313-CC (Del. Ch.) and appointing co-lead counsel.

 

Theconsolidated complaint generally alleges that our directors breached theirfiduciary duties by, among other things, entering into the merger agreementwith Powder and Powder Holdings, taking actions designed to deter higher offersfrom other potential acquirers and failing to maximize the value of Pinnacle toits stockholders. In addition, the lawsuit alleges that DLJ, as a controllingstockholder of Pinnacle, violated fiduciary duties to Pinnacle stock holdersand that Powder and Merger Sub aided and abetted the alleged breaches offiduciary duties by the other defendants. The lawsuit seeks, among other relief, injunctive relief prohibiting theMerger, and costs of the action including reasonable attorneys’ fees.

 

OnMay 24, 2010, the Company and its directors entered into a Memorandum ofUnderstanding in anticipation of settling the shareholder lawsuit. Under theterms of the Memorandum of Understanding, the Company agreed to make additionalproxy disclosures regarding the interests of our executive officers in thesurviving entity and furnish additional information regarding FBR’s analysisand fairness opinion. In return the shareholders will provide a release oftheir claims against the Company, its directors, Powder and DLJ.  The Company and its directors, Powder and DLJdo not admit any wrongdoing and entered into the Memorandum of Understanding toavoid the distraction, burden and expense of further litigation. The settlementis subject to confirmatory discovery, negotiation of a definitive settlementagreement, and approval by the Delaware Chancery Court. Powder and DLJ haveagreed to the terms of the Memorandum of Understanding.

 

*Regulations*

 

The Company’s oil and gas operations are subject to various federal,state and local laws and regulations. The Company could incur significantexpense to comply with the new or existing laws and non-compliance could have amaterial adverse effect on the Company’s operations.

 

*Environmental*

 

The Company produces significant amounts of water from its wells. Iffuture wells produce water of a lesser quality than allowed under state laws orif water is produced at rates greater than the Company can dispose of, theCompany could incur additional costs to dispose of the water.

 

**Note 10 — *NASDAQ Delisting***

 

On March 16, 2010, The NASDAQ Stock Market notified the Company ofits failure to comply with Listing Rule 5450(a)(1). Thisrule subjects a company’s stock to delisting on the NASDAQ exchange if itsstock price closes below $1 over the previous 30 consecutive business daysand then, after notification, fails to regain compliance within the subsequent180 days. Accordingly, unless the Company appealed this determination, thetrading of the Company’s stock would have been suspended on March 25,2010. The Company filed an appeal, pursuant to NASDAQ listingrule series 5800 on March 22, 2010.

 

OnApril 29, 2010, the Company met with representatives of NASDAQ to formallyrequest a 180 day extension to allow implementation of certain strategies toregain compliance.

 

OnMay 10, 2010, the Company received a determination letter from the NASDAQhearings panel granting the Company’s request for continued listing subject toa proxy being filed which included a proposal for a reverse stock split and aclosing bid price of $1.00 or more for a minimum of ten consecutive tradingdays prior to September 13, 2010.

 

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**Note 11 — Recent Developments**

 

Atthe special meeting of the shareholders on August 9, 2010, the ourshareholders voted to approve a proposal to adopt the Agreement and Plan ofMerger dated February 23, 2010 (“Merger Agreement”) by and amongst us,Powder Holdings, LLC, a Delaware LLC, and Powder Acquisition Co. (“Powder”), ADelaware Corporation and wholly-owned subsidiary of Powder. We anticipate thatthe closing will occur during the third quarter, subject to the satisfaction ofcustomary closing conditions and the receipt of waivers from our lender, TheRoyal Bank of Scotland plc.

 

**ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OFFINANCIAL CONDITION AND RESULTS****OF OPERATIONS**

 

*The discussion and analysis that follows should be readtogether 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 onForm 10-K for the year ended December 31, 2009, including in “RiskFactors” and “Cautionary Statement Concerning Forward**Looking Statements,” all of which are difficult topredict. As a result of**theseassumptions, risks and uncertainties, the forward looking matters**discussed may not occur.*

 

**Overview**

 

We are an independent energy company engaged in the acquisition,exploration and development of domestic onshore natural gas reserves. Weprimarily focus our efforts on the development of 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, 2010, we owned natural gas and oilleasehold interests in approximately 406,000 gross (297,000 net) acres,approximately 90% of which were undeveloped. As of December 31, 2009, wehad estimated net proved reserves of approximately 15.0 Bcf based on the firstday of the month, twelve month average CIG index price of approximately $3.04per Mcf.

 

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 and during the first six months of 2010. Therefore,total capital expenditures were limited to $4.2 million in 2009. As aresult of low CIG index prices, the economic climate and our limited capitalresources, we expect to continue operating during 2010 with a reduced capitalexpenditure plan. Under our plan, we will generally make expenditures only asnecessary to secure drilling permits in strategic areas, drill wells thatsecure leasehold positions and construct the necessary infrastructure tocomplete and hook-up wells that have already been drilled. Our capitalexpenditure budget for 2010 will be dependent upon CIG index prices, our cashflows and the availability of additional capital resources.  We had total capital expenditures of $1.9million for the six months ended June 30, 2010.

 

OnFebruary 23, 2010, we entered into an Agreement and Plan of Merger withPowder Holdings, LLC, and Powder Acquisition Co., a direct, wholly ownedsubsidiary of Powder Holdings. Powder Holdings is controlled by an investorgroup led by Scotia Waterous (USA) Inc. and includes certain members of ourmanagement team. On April 2, 2010, we filed a preliminary proxy statementrelating to the merger, with the U.S. Securities and Exchange Commission (SEC).On June 29, 2010, we filed a definitive proxy statement relating to themerger with the SEC. At the special meeting of the shareholders on August 9,2010, our shareholders voted to approve a proposal to adopt the Agreement andPlan of Merger dated February 23, 2010 (“Merger Agreement”) by and amongstus, Powder Holdings, LLC, and Powder Acquisition Co. (“Powder”), a wholly-ownedsubsidiary of Powder. We anticipate that the closing will occur during thethird quarter, subject to the satisfaction of customary closing conditions andthe receipt of waivers from our lender, The Royal Bank of Scotland plc.

 

Shares of our common stock are traded on the NASDAQ Global Market underthe symbol “PINN.”

 

**Economic and Natural Gas PricingEnvironment**

 

During 2009, the global economy experienced a significant downturn. Thedownturn, which began over concerns related to the U.S. financial markets,spread to other industries, including the energy industry. The initial effectsof the downturn restricted the capital and credit markets to a degree that hasnot been seen in a number of decades in the United States. We have been able topartially mitigate the constraints imposed by the current economic climatethrough utilization of cash flows from operations.

 

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The fear of global recession led to an immediate drop in demand fornatural gas, primarily by industrial users, which in turn led to a significantreduction in natural gas prices. The natural gas index price in the RockyMountain region averaged $6.24 per Mcf for the twelve months endedDecember 31, 2008 but only $3.07 per Mcf for the twelve months endedDecember 31, 2009. For the first six months of 2010, the price averaged$4.38.  This volatility in price hascaused us to reevaluate our 2010 business plan. We have curtailed drilling,except for wells that will hold significant blocks of acreage, and have alsoreduced administrative, operating and transportation costs. Even with cost reductionsand a flexible capital spending budget, the current natural gas pricing andeconomic environment remains challenging. We are exploring strategicalternatives to increase our capital resources.

 

**Credit Facility and Liquidity**

 

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

 

On January 13, 2010, we entered into aseventh amendment and waiver to credit agreement (“*waiver agreement*”) with the lenders party thereto. Thewaiver agreement provided that the lenders would waive (i) our compliancewith certain restrictions based on the current ratio in the credit agreement,(ii) certain requirements pertaining to the aging of certain accountspayable, and (iii) certain restrictions regarding the amount of liens wehave. Default remedies available to the lenders under the credit agreementinclude acceleration of all principal and interest amounts due under the creditagreement. The waiver agreement extends the waiver period for these items untilthe earlier of June 15, 2010 and the date of any default arising out of abreach or non-compliance with the credit agreement not expressly waived in thewaiver agreement or a breach of the waiver agreement.

 

In addition, the waiver agreement amends thedefinition of “Final Maturity Date” under the credit agreement to the earlierof (i) June 15, 2010 or (ii) the date that is thirty daysfollowing the earlier of (A) the date the merger (please see Note 10 inthe notes to the financial statements) is withdrawn or terminated in whole orin part or (B) the date that the lenders have been advised that the mergerwill not proceed.

 

On July 8, 2010, wewere notified by our lender that we failed to make the principal and interestpayments due on July 1, 2010 and that such missed payments constituted anEvents of Default under the Credit Agreement. We remain obligated to pay allamounts outstanding under the credit agreement. The current amount outstanding under the credit facility isapproximately $5,100,000.

 

Wehave requested additional waivers from our lender; however, there can be noassurance that we will be able to obtain such waivers or that such waivers willbe obtained on acceptable terms. If we are unable to obtain future waiversand/or to comply with the restrictive covenants, the lender could foreclose onproperties held by liens.  Due to borrowing base limitations and waiverstipulations, we are currently unable to incur additional indebtedness underthe credit facility.

 

We have also implementedvarious cost cutting measures, including reducing general and administrativecosts through staff reductions, wage and benefit cuts and a hiring freeze.  We have reduced lease operating expenses byrenegotiating water disposal contracts, reducing service costs and temporarilyshutting-in marginal wells.  We continueto communicate with key vendors to manage our obligations and payables.  Management believes that appropriate steps,including cost-cutting measures, are being taken to make operations sustainablein the future.  Although we are pursuingvarious alternatives to provide additional liquidity, there is no assurance ofthe likelihood or timing of any of these transactions.****Wealso put additional hedges of our natural gas production in place to securecertain operating cash flow levels during 2010. From January throughApril 2010, we had 5,500 MMbtu per day hedged through fixed price swaps ata weighted average price of $4.19 per MMbtu. From May throughDecember 2010, we have 5,500 MMbtu hedged through fixed price swaps at aweighted average price of $5.08 per MMbtu. Although we are pursuing variousalternatives to provide additional liquidity, there is no assurance of thelikelihood or timing of any of these transactions.

 

**Critical Accounting Policies**

 

Themost subjective and complex judgments used in the preparation of our financialstatements are:

 

·**               **Reserve evaluation anddetermination;

 

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·**               **Estimates of the timing andcost of our future drilling activity;

 

·**               **Estimates of the fairvaluation of hedges in place;

 

·**               **Estimates of timing and costof asset retirement obligations;

 

·**               **Estimates of the expense andtiming of exercise of stock options;

 

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

 

·**               **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 propertiesare all located within the United States, which constitutes a single costcenter. We capitalize certain lease operating expenses associated withexploration and development of unevaluated oil and gas properties. No gain orloss is recognized upon the sale or abandonment of undeveloped or producing oiland gas properties unless the sale represents a significant portion of gasproperties and the gain significantly alters the relationship between capitalizedcosts and proved gas reserves of the cost center. Expenditures for maintenanceand repairs are charged to lease operating expense in the period incurred.

 

Depreciation, depletion and amortization of oil and gas properties arecomputed 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 on unevaluated properties for the three and six monthsended June 30, 2010 and the year ended December 31, 2009,respectively. Abandonment of unproved properties is also accounted for as anadjustment to capitalized costs related to proved oil and gas properties, withno losses recognized.

 

Substantially all remaining unproved property costs are expected to bedeveloped and included in the amortization base ratably over the next three tofive years. Salvage value is taken into account in determining depletion ratesand is based on our estimate of the value of equipment and supplies at the timethe well is abandoned. As of June 30, 2010 and December 31, 2009, theestimated salvage value of equipment was $6.8 million.

 

Underthe full cost method of accounting rules, capitalized costs less accumulateddepletion and related deferred income taxes may not exceed a “ceiling” valuewhich is the sum of (1) the present value discounted at 10% of estimatedfuture net revenue using current costs and the first day of the month, twelve monthaverage CIG price, including the effects of derivative instruments designatedas cash flow hedges but excluding the future cash outflows associated withsettling asset retirement obligations that have been accrued on the balancesheet, less any related income tax effects; plus (2) the cost ofproperties not being amortized, if any; plus (3) the lower of costs orestimated fair value of unproved properties; less (4) the income taxeffects related to differences in the book to tax basis of oil and gas properties.This is referred to as the “full cost ceiling limitation.” If capitalized costsexceed the limit, the excess must be charged to expense. The expense may not bereversed in future periods. At the end of each quarter, we calculate the fullcost ceiling limitation. At June 30, 2010, the full cost ceilinglimitation exceeded the capitalized cost of the Company’s oil and gasproperties by approximately $5.2 million based on the first day of the month,twelve month average CIG price of approximately $3.76 per Mcf. Therefore, noimpairment was taken for the quarter ended June 30, 2010. An impairment of$6.4 million was taken for the quarter ended June 30, 2009 based on anatural gas price of $3.09 per Mcf. A decline in gas prices or an increase inoperating costs subsequent to the measurement date or reductions ineconomically recoverable quantities could result in the recognition ofadditional impairments of our oil and gas properties in future periods.

 

***Gas Sales***

 

Weuse the sales method for recording natural gas sales. Sales of gas applicableto our interest in producing natural gas and oil leases are recorded asrevenues 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 

 

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revenuesunless total sales from the well have exceeded our share of estimated total gasreserves underlying the property at which time such excess is recorded as a gasimbalance liability. At June 30, 2010 and December 31, 2009, therewas no such liability recorded. Although there was no such liability recordedfor prior periods, gas reserves are an estimate and are updated on an annualand interim basis. Gas pricing, expenses and production may impact future gasreserves remaining which, in turn, could impact the recording of liabilities inthe future. Gas sales accruals at June 30, 2010, and December 31,2009 were based on the actual volume statements from our purchasers anddistribution process. If accruals were to change by 10% at June 30, 2010and at December 31, 2009, the impact would have been a change of $87,000and $124,000, respectively.

 

***Asset Retirement Obligations***

 

Wefollow certain accounting provisions that apply to legal obligations associatedwith the retirement of long-lived assets that result from the acquisition,construction, development and/or the normal operation of a long-lived asset.These provisions requires us to recognize an estimated liability for costsassociated with the abandonment of our oil and gas properties.

 

Aliability 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.

 

Theestimated liability is based on historical gas industry experience inabandoning wells, including estimated economic lives, external estimates as tothe 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 $300,000 effect on our asset retirement obligation liability at June 30,2010.

 

Thefollowing is a summary of our asset retirement obligation activity for thethree and six months ended June 30, 2010 and June 30, 2009(unaudited):

 
| ** **                                        | ** ** | **(in thousands)**                                 | ** ** |
|---------------------------------------------------|------------|----------------------------------------------------|------------|
| ** **                                        | ** ** | **Three********Months Ended********June 30,** | ** ** | **Six********Months Ended June 30,** | ** ** | **Three********Months Ended********June 30,** | ** ** | **Six********Months Ended********June 30,** | ** ** |
| ** **                                        | ** ** | **2010**                                           | ** ** | **2009** | ** ** |
| Beginning balance of asset retirement obligations |       | $                                                  | 2,959      |   | $ | 2,937 |   | $ | 3,422 |   | $ | 3,366 |   |
| Additional obligation added during the period     |       | —                                             |       | 1 |   | $ | — |   | $ | — |   |
| Obligations to be settled                         |       | (18                                                | )          | (49 | ) | (23 | ) | (23 | ) |
| Accretion expense                                 |       | 54                                                 |       | 106 |   | 58 |   | 114 |   |
| Ending balance of asset retirement obligations    |       | 2,995                                              |       | 2,995 |   | 3,457 |   | 3,457 |   |
|                                                   |            |                                                    |            |  |  |  |  |  |  |  |  |  |  |

 

***Inventory***

 

We have acquired inventory of oil and gas equipment, primarilytubulars, 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 $45,000 reduction in ourinventory valuation as of June 30, 2010. The market price of steel isevaluated each quarter using prices quoted by authorized vendors in the area.

 

***Property and Equipment***

 

Propertyand equipment is comprised primarily of a building, computer hardware andsoftware, vehicles and equipment, and is recorded at cost. Renewals andbetterments that substantially extend the useful lives of the assets arecapitalized. Maintenance and repairs are expensed when incurred. Depreciationand amortization are provided using the straight-line method over the estimateduseful lives of the assets, ranging as follows: buildings—30 years,computer hardware and software—3 to 5 years, machinery, equipment andvehicles—5 years, and office furniture and equipment—3 to 5 years.

 

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***Long-Lived Assets***

 

Long-livedassets to be held and used in our business are reviewed for impairment wheneverevents or changes in circumstances indicate that the related carrying amountmay not be recoverable. When the carrying amounts of long-lived assets exceedthe fair value, which is generally based on discounted expected future cashflows, we recorded impairment. No impairments were recorded during the sixmonths ended June 30, 2010 and the year ended December 31, 2009.

 

***General and Administrative Expenses***

 

Generaland administrative expenses are reported net of amounts allocated and billed toworking interest owners of gas properties operated by us. The administrativeexpenses billed to working interest owners may change in accordance with theterms of the joint operating agreements. Administrative expenses are charged toworking interest owners based on productive well counts.  A 10% change in well counts for the sixmonths ended June 30, 2010 would have increased or decreased our expensesbilled to working interest owners by approximately $33,000. As we operate anddrill additional wells in the future, additional administrative expenses willbe charged to the working interest owners when the wells become productive.

 

***Income Taxes***

 

Weuse the asset and liability method of accounting for income taxes. Deferred taxassets and liabilities are recognized for the expected future tax consequencesof temporary differences between the financial statement and tax basis ofassets and liabilities. If appropriate, deferred tax assets are reduced by avaluation allowance which reflects expectations of the extent to which suchassets will be realized. As of June 30, 2010 and December 31, 2009,we recorded a full valuation allowance for our net deferred tax asset.

 

On January 1, 2007, we adopted accounting provisions thatprescribe a recognition threshold and measurement attribute for the financialstatement recognition and measurement of a tax position taken or expected to betaken in a tax return. This provision requires that we recognize in ourconsolidated financial statements only those tax positions that are “more-likely-than-not”of being sustained as of the adoption date, based on the technical merits ofthe position. As a result of the implementation of the provision, we performeda comprehensive review of our material tax positions in accordance with theserecognition and measurement standards. As a result of this review, we did notidentify any material deferred tax assets that required adjustment. As of June 30,2010 and December 31, 2009, we had not recorded any material uncertain taxpositions.

 

Ourpolicy is to recognize interest and penalties related to uncertain tax benefitsin income tax expense. As of June 30, 2010 and 2009, we had not recognizedany interest or penalties in our statement of operations or statement offinancial position.

 

Weare subject to the following material taxing jurisdictions: U.S. federal. Wealso have material operations in the state of Wyoming; however, Wyoming doesnot impose a corporate income tax. The tax years that remain open toexamination by the U.S. Internal Revenue Service are years 2005 through 2009.Due to our net operating loss carry forwards, the Internal Revenue Service mayalso adjust the amount of loss realizable under examination back to 2003.

 

***Derivatives***

 

OnJuly 21, 2010, the Dodd-Frank Wall Street Reform and Consumer ProtectionAct was enacted into law.  This financial reform legislation includesprovisions that require over-the-counter derivative transactions to be executedthrough an exchange or centrally cleared.  In addition, the legislationprovides an exemption from mandatory clearing requirements based on regulationsto be developed by the Commodity Futures Trading Commission (CFTC) and theSecurities and Exchange Commission  for transactionsby non-financial institutions to hedge or mitigate commercial risk.  Atthe same time, the legislation includes provisions under which the CFTC mayimpose collateral requirements for transactions, including those that are usedto hedge commercial risk.  However, during drafting of the legislation,members of Congress adopted report language and issued a public letter statingthat it was not their intention to impose margin and collateral requirements oncounterparties that utilize transactions to hedge commercial risk.  Finalrules on major provisions in the legislation will be established throughrulemakings and will not take effect until 12 months after the date ofenactment.   Although we cannot predict the ultimate outcome of theserulemakings, new regulations in this area may result in increased costs andcash collateral requirements for the types of oil and gas derivativeinstruments we use to hedge and otherwise manage our financial risks related tovolatility in oil and gas commodity prices.

 

We use derivative instruments to manage our exposure to fluctuatingnatural gas prices through the use of natural gas swap and option contracts. Weaccount for derivative instruments or hedging activities under authoritiveguidance prescribed by FASB that requires us to record derivative instrumentsat their fair value. If the derivative is designated as a fair value hedge, thechanges in the fair value of the derivative and of the hedged item attributableto the hedged risk are recognized in earnings. If the derivative is designatedas a cash flow hedge, the effective portions of changes in the fair value ofthe derivative are recorded in other comprehensive income (loss) and arerecognized in the statement of operations when the hedged item affects earnings.Ineffective portions of changes in the fair value of cash flow hedges, if any,are recognized in earnings. Changes in the fair value of derivatives that donot qualify for hedge treatment are recognized in earnings.

 

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

 

***Stock-Based Compensation***

 

Effective January 1, 2006, we adopted accounting provisions, whichrequire companies to recognize compensation expense for share-based paymentsbased on the estimated fair value of the awards. We recognized an expense ofapproximately $25,000 for the six months ended June 30, 2010, based on thefair value of vested options.  Werecognized an expense of approximately $187,000 for six months ended June 30,2010, based on the fair value of restricted stock that vested during thequarter.  We recognized an expense ofapproximately $12,000 for the six months ending June 30, 2010, based onthe fair market value of stock appreciation rights. This accounting provisionalso requires that the benefits of tax deductions in excess of compensationcost recognized for stock awards and options (“excess tax benefits”) bepresented as financing cash inflows in the Statement of Cash Flows.

 

***Accounts Receivable***

 

Ourrevenue producing activities are conducted primarily in Wyoming. We grantcredit to qualified customers, which potentially subjects us to credit riskresulting from, among other factors, adverse changes in the industry in whichwe 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 ofapproximately $14,000 and $100,000 at each of June 30, 2010 andDecember 31, 2009 respectively.

 

***Transportation Costs***

 

We account for transportation costs under authoritative guidanceprescribed by the FASB related to the accounting for shipping and handling feesand costs, whereby amounts paid for transportation are classified as operatingexpenses.

 

***Legal Estimates***

 

From time to time, we are subject to legal proceedings and claims thatarise in the ordinary course of business. We account for these costs under anaccounting provision, which states that a loss contingency be recorded if it isprobable that a liability has been incurred and it is reasonably estimatable.At June 30, 2010 and 2009, we recorded no expenses for legal proceedings.

 

***Per Share Information***

 

Basic earnings (loss) per share is computed bydividing net income (loss) from continuing operations attributable to commonstock by the weighted average number of shares of common stock outstandingduring each period. Diluted earnings per share are computed by adjusting theaverage number of shares of common stock outstanding for the dilutive effect,if any, of common stock equivalents such as stock options and warrants. For thesix months ended June 30, 2010, basic and diluted net loss per share was$0.02. During the six months ended June 30, 2010, 835,446 options andstock appreciation rights were excluded because they were anti-dilutive.

 

***Recent Accounting Pronouncements***

 

For information concerning recent accounting pronouncements, please seeNote 2 in the notes to the audited financial statements appearing elsewhere inthis report.

 

**Trends Affecting Our Business**

 

The continued credit crisis and related turmoil inthe global financial system have had an adverse impact on our business and financialcondition. In addition, the prices of oil and natural gas declinedsignificantly in 2008 and have remained low in 2009 and the first and secondquarters of 2010. As a result of low CIG index prices, the economic climate andour limited capital resources, we expect to continue operating during 2010 witha reduced capital expenditure plan for 2010. Under our plan, we will generallymake expenditures only as are necessary to secure drilling permits in strategicareas, drill wells that secure leasehold positions and construct the necessaryinfrastructure to complete and hook-up wells that have already been drilled.

 

Historically, natural gas prices have been extremelyvolatile, and we expect that volatility to continue. For example, during thesix months ended June 30, 2010, the NYMEX natural gas index price rangedfrom a high of $6.00 per MMBtu to a low of $3.84 

 

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perMMBtu, while the CIG natural gas index price ranged from a high of $6.08 perMMBtu to a low of $3.35 per MMBtu. During the year ended December 31,2009, 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. 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 the sixmonths ended June 30, 2010, estimated future gas prices had an impact onboth our revenues and the costs attributable to our future operations. Weexpect that changing natural gas prices will continue to impact our operationsand financial results in the future.

 

Transportation of naturalgas and access to throughput capacity has a direct impact on natural gas pricesin the Rocky Mountain region, where our operations are concentrated. Asdrilling activity increases throughout the Rocky Mountain region, additionalproduction may come on line, which could cause bottlenecks or capacityconstraints. Generally speaking, a surplus of natural gas production relativeto available transportation capacity has a negative impact on prices.Conversely, as capacity increases, and bottlenecks are eliminated, pricesgenerally increase. Although there is currently adequate transportationcapacity out of the Powder River Basin, a surplus of natural gas arriving atkey marketing hubs from the Powder River Basin and elsewhere relative toavailable takeaway capacity from these hubs has caused Rocky Mountain gas togenerally trade at a discount to the NYMEX natural gas index price. Forexample, from January 1, 2010 through June 30, 2010, Rocky Mountaingas traded at a differential to the NYMEX natural gas index price that rangedfrom a premium of $0.27 per Mcf to a discount of $1.00 per Mcf, with an averagedifferential of a discount of $0.38 per Mcf. The Rockies Express Pipeline whichwas completed and placed into service in early 2008, has increased takeawaycapacity by approximately 1.5 Bcf per day from these hubs. We expect that thecompletion of additional proposed pipelines will help reduce the differentialbetween gas produced in the Rocky Mountain region and the NYMEX natural gasindex price. Additional proposed pipelines are scheduled to be completed inlate 2010 and 2011. General economic conditions and the future demand fornatural gas may change the development schedule of proposed pipelines.

 

**Results of Operations**

 

Netloss attributable to stockholders for the quarter ended June 30, 2010 was$1.8 million, or $0.06 per diluted share, on total revenues of $2.5 million.Other income for the quarter ended June 30, 2010 included a $0.6 millionunrealized loss associated with the change in the fair valuation of our naturalgas hedges in place in accordance with certain accounting provisions. Absentsuch change in the valuation of hedges, we would have shown a loss of $1.2million.  This compares to a net lossattributable to stockholders of $9.5 million for the quarter ended June 30,2009 on total revenue of $3.7 million. Adjusted for an unrealized loss in thefair valuation of our natural gas hedges in place of $2.7 million shown inother income, our results for the quarter ended June 30, 2009 would havebeen a net loss attributable to common stockholders of $6.8 million.

 

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 certain accounting provisions which require us to recordderivative instruments at their fair value. Management has chosen not to usehedge accounting for these arrangements. Therefore, in accordance with theseprovisions, changes in the fair market value are recognized in earnings.

 

***Three Months Ended June 30, 2010Compared to Three Months Ended June 30, 2009***

 

*Gas sales volume.*

 

Gassales volume decreased 18%, from 702 MMcf in the three months ended June 30,2009 to 575 MMcf in the three months ended June 30, 2010. Daily salesvolume was 6.3 MMcf for the three months ended June 30, 2010 as comparedto 7.7 MMcf for the three months ended June 30, 2009, a 1.4 MMcf per daydecrease. The decrease resulted primarily from shutting in wells due to lownatural gas prices, reductions in volumes due to compression maintenance andrepairs, and weather related downtime.

 

*Gas sales revenue.*

 

Revenuefrom gas sales increased approximately $0.3 million during the three monthsended June 30, 2010, to approximately $1.9 million, a 21% increasecompared to the three months ended June 30, 2009. This increase wasprimarily due to an increase in the average realized price per Mcf along with areduction in gas sales volume. The average realized price per Mcf increasedapproximately 47%, from $2.29 per Mcf in the three months ended June 30,2009 to $3.37 per Mcf in the three months ended June 30, 2010.

 

*Derivatives.*

 

Forthe three months ended June 30, 2010, we had an unrealized loss of$610,000 compared to an unrealized loss of $2.7 million for the three monthsended June 30, 2009. The unrealized losses are non-cash expenses basedprimarily on the Black-Scholes 

 

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modelfor valuing future cash flows utilizing price volatility with a normal discountrate. Hedges settled during the three months ended June 30, 2010 resultedin a realized gain of $590,000 compared to a realized hedge gain of $2.1million during the three months ended June 30, 2009. The realized hedgegain for the three months ended June 30, 2010 was primarily due to thefact that gas prices were lower than the weighted average floor price of ourhedges in place.

 

*Lease operating expenses.*

 

Leaseoperating expenses decreased $0.2 million in the three months ended June 30,2010 to $0.8 million, a 18% decrease compared to the three months ended June 30,2009. This decrease resulted primarily from a reduction in contract services,fuel, and water management related costs offset partially by an increase insurface use expenses in the productive cycle during the three months ended June 30,2010. On a Mcf basis, lease operating expenses were $1.34 an Mcf for the threemonths ended June 30, 2010 and June 30, 2009.

 

*Production taxes.*

 

Productiontaxes increased $68,000 in the three months ended June 30, 2010 to $0.2million, a 49% increase from the three months ended June 30, 2009.Production taxes generally correlate to gross sales revenue because productiontaxes are based on a percentage of sales value. In Wyoming, the percentageaverages 11% to 13%, depending on rates in effect for the respective year,while in Montana the percentage averages 9%. The decrease in production taxesfor the three months ended June 30, 2010 was primarily due to decreasedrevenues associated with decreased volume and realized pricing. On a Mcf basis,production taxes were $0.36 per Mcf for the three months ended June 30,2010 and $0.20 per Mcf for the three months ended June 30, 2009, a 81%increase, which correlates to the increase in the price per Mcf received in thethree months ended June 30, 2010 from the three months ended June 30,2009.

 

*Marketing and transportation.*

 

Marketingand transportation expenses decreased approximately $0.1 million in the threemonths ended June 30, 2010 to approximately $0.8 million, a 16% decreasefrom the three months ended June 30, 2009. The decrease related primarilyto a decrease in transportation fees and compression due to lower productionvolumes. On an Mcf basis, marketing and transportation expenses increased 3% to$1.31 per Mcf in the three months ended June 30, 2010 from $1.27 per Mcfin the three months ended June 30, 2009.

 

*General and administrative expenses, net.*

 

Generaland administrative expenses are offset by operating income from drilling andproduction activities for which we can charge an overhead fee to nonoperatingworking interest owners. These well operating overhead fees were $332,000 inthe three months ended June 30, 2010 compared to $335,000 for the threemonths ended June 30, 2009. General and administrative expenses netdecreased $0.2 million in the three months ended June 30, 2010 to $1.0million. On a Mcf basis, general and administrative expenses, net increased 5%,from $1.69 per Mcf in the three months ended June 30, 2009 to $1.77 perMcf in the three months ended June 30, 2010. General and administrativeexpenses, for the quarter ended June 30, 2010, include $0.4 million forprofessional services expense incurred in connection with the merger agreementwith Powder and Powder Holdings.

 

*Depreciation, depletion, amortization and accretion.*

 

Depreciation,depletion, amortization and accretion expense decreased $0.1 million for thethree months ended June 30, 2010 to $0.8 million, an 8% decrease comparedto the three months ended June 30, 2009. The decrease was primarily due toa decrease in the capitalized basis in our full cost pool at June 30,2010. On an Mcf basis, the depreciation, depletion, amortization and accretionrate increased to $1.47 per Mcf in the three months ended June 30, 2010from $1.30 per Mcf in the three months ended June 30, 2009.

 

*Impairment.*

 

AtJune 30, 2010, the full cost ceiling limitation of our oil and gas propertiesexceeded the capitalized cost by approximately $5.2 million based upon anatural gas price of approximately $3.76 per Mcf (based on the first day of themonth, twelve month average per Mcf on the Colorado Interstate Gas RockyMountain Index) in effect at that date. Therefore, no impairment was taken forthe three months ended June 30, 2010. An impairment of approximately $6.4million was taken for the three months ended June 30, 2009.  For further information regarding thisimpairment, please see Note 2 — “Basis of Presentation” in the Notes to theunaudited financial statements appearing elsewhere in this quarterly report. Adecline in natural gas prices or an increase in operating costs in economicallyrecoverable quantities could result in the recognition of additionalimpairments of our oil and gas properties in future periods.

 

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***Six Months Ended June 30, 2010Compared to Six Months Ended June 30, 2009***

 

*Gas sales volume.*

 

Gassales volume decreased 23%, from 1,516 MMcf in the six months endedJune 30, 2009 to 1,169 MMcf in the six months ended June 30, 2010.Daily sales volume was 6.5 MMcf for the six months ended June 30, 2010 ascompared to 8.4 MMcf for the six months ended June 30, 2009, 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.

 

*Gas sales revenue.*

 

Revenuefrom gas sales increased approximately $0.4 million during the six months endedJune 30, 2010, to approximately $4.8 million, a 9% increase compared tothe six months ended June 30, 2009. This increase was primarily due to aincrease in the average realized price offset by a decrease in gas sales volumeper Mcf. The average realized price per Mcf increased approximately 42%, from$2.88 per Mcf in the six months ended June 30, 2009 to $4.09 per Mcf inthe six months ended June 30, 2010.

 

*Derivatives.*

 

Forthe six months ended June 30, 2010, we had an unrealized gain of $2.3million compared to an unrealized loss of $2.1 million for the six months endedJune 30, 2009. The unrealized losses are non-cash expenses based primarilyon the Black-Scholes model for valuing future cash flows utilizing pricevolatility with a normal discount rate. Hedges settled during the six monthsended June 30, 2010 resulted in a realized gain of $0.1 million comparedto a realized hedge gain of $3.5 million during the six months endedJune 30, 2009. The realized hedge gain for the six months ended June 30,2010 was primarily due to the fact that gas prices were lower than the weightedaverage floor price of our hedges in place.

 

*Lease operating expenses.*

 

Leaseoperating expenses decreased $0.3 million in the six months ended June 30,2010 to $1.8 million, a 16% decrease compared to the six months endedJune 30, 2009. This decrease resulted primarily from a reduction in labor,fuel, workover and water management related costs offset partially by anincrease in surface use expenses in the productive cycle during the six monthsended June 30, 2010. On a Mcf basis, lease operating expenses increased 9%from $1.40 per Mcf in the six months ended June 30, 2009 to $1.53 per Mcfin the six months ended June 30, 2010.

 

*Production taxes.*

 

Productiontaxes increased $0.1 million in the six months ended June 30, 2010 to $0.5million, a 26% increase from the six months ended June 30, 2009.Production taxes generally correlate to gross sales revenue because productiontaxes are based on a percentage of sales value. In Wyoming, the percentageaverages 11% to 13%, depending on rates in effect for the respective year,while in Montana the percentage averages 9%. The decrease in production taxesfor the six months ended June 30, 2010 was primarily due to decreasedrevenues associated with decreased volume and realized pricing. On an Mcfbasis, production taxes were $0.45 per Mcf for the six months ended June 30,2010 and $0.28 per Mcf for the six months ended June 30, 2009, a 63%increase, which correlates to the increase in the price per Mcf received in thesix months ended June 30, 2010 from the six months ended June 30,2009.

 

*Marketing and transportation.*

 

Marketingand transportation expenses decreased approximately $0.7 million in the sixmonths ended June 30, 2010 to approximately $1.5 million, a 31% decreasefrom the six months ended June 30, 2009. The decrease related primarily toa slight decrease in transportation fees and compression due to lowerproduction volumes. On an Mcf basis, marketing and transportation expensesdecreased 11% to $1.26 per Mcf in the six months ended June 30, 2010 from$1.41 per Mcf in the six months ended June 30, 2009.

 

*General and administrative expenses, net.*

 

Generaland administrative expenses are offset by operating income from drilling andproduction activities for which we can charge an overhead fee to nonoperatingworking interest owners. These well operating overhead fees were $0.6 millionin the six months ended June 30, 2010 compared to $0.7 million for the sixmonths ended June 30, 2009, a 6% decrease. General and administrativeexpenses, net, increased $0.2 million in the six months ended June 30,2010 to $2.4 million. On an Mcf basis, general and administrative expenses, netincreased 42%, from $1.46 per Mcf in the six months ended June 30, 2009 to$2.07 per Mcf in the six months ended June 30, 2010. The increase ingeneral and administrative expenses was primarily a result of professionalservices expense incurred in connection with the merger agreement with Powder andPowder Holdings.

 

*Depreciation, depletion, amortization and accretion.*

 

Depreciation,depletion, amortization and accretion expense decreased $1.2 million for thesix months ended June 30, 2010 to $1.6 million, a 43% decrease compared tothe six months ended June 30, 2009. The decrease was primarily due to adecrease in the 

 

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capitalizedbasis in our full cost pool. On an Mcf basis, the depreciation, depletion,amortization and accretion rate decreased to $1.33 per Mcf in the six months endedJune 30, 2010 from $1.81 per Mcf in the six months ended June 30,2009.

 

*Impairment.*

 

Inthe six months ending June 30, 2010, the full cost ceiling limitation ofour oil and gas properties exceeded the capitalized cost by approximately $5.2million based upon a natural gas price of approximately $3.76 per Mcf (based onthe first day of the month, twelve month average per Mcf on the ColoradoInterstate Gas Rocky Mountain Index) in effect at that date. Therefore, noimpairment was taken for the quarter ended June 30, 2010. An impairment ofapproximately $23.3 million was taken for the quarter ended June 30,2009.  For further information regardingthis impairment, please see Note 2 — “Basis of Presentation” in the Notes tothe unaudited financial statements appearing elsewhere in this quarterlyreport. A decline in natural gas prices or an increase in operating costs ineconomically recoverable quantities could result in the recognition ofadditional impairments of our oil and gas properties in future periods.

 

**Liquidity and Capital Resources**

 

In the past, our primarysources 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.*

 

EffectiveFebruary 12, 2007, we entered into a credit facility which permitsborrowings up to the borrowing base as designated by the administrative agent.As of June 30, 2010 and December 31, 2009, we had $5.1 million and$11.5 million, respectively, of debt outstanding under the facility. Asdescribed below, we are currently unable to borrow additional amounts under thecredit facility due to covenant limitations and may be further limited in thefuture based on borrowing base limitations.

 

Asof December 31, 2009, the borrowing base under the credit facility wasapproximately $13.2 million. The borrowing base was subject to automaticreductions of approximately $666,667 per month until it reached $10.5 millionon April 1, 2009. As of August 13, 2009, our borrowing base wasreduced to $7.5 million, subject to automatic reductions of $500,000 per monthuntil it reaches $6.5 million on October 1, 2009.  Further borrowing base redeterminations weremade pursuant to a series of waivers and agreements described below.

 

Theborrowing base is determined on a semi-annual basis and at such otheradditional times, up to twice yearly, as may be requested by either us or theadministrative 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.

 

Borrowingsunder this credit facility may be used solely to acquire, explore or developoil and gas properties and for general corporate purposes.

 

Ourobligations under the credit facility are secured by liens on (i) no lessthan 90% of the net present value of the oil and gas to be produced from ouroil and gas properties that are included in the borrowing base determination,calculated using a discount rate of 10% per annum and reserve estimates, pricesand production rates and costs, (ii) options to lease, seismic options,permits, and records related to such properties, and (iii) seismic data.

 

Borrowingsunder our credit facility, as amended, bear interest either: (i) at thegreater of the one month London Interbank Offered Rate, or LIBOR, plus 1.00% ora domestic bank rate, plus in either case an applicable margin of 0.75% to1.75% based on utilization, or (ii) on a sliding scale from the one, two,three or six month LIBOR, plus an applicable margin of 2.00% to 3.00% based onutilization. The weighted average interest rate as of June 30, 2010 was5.0%.  The credit agreement provides forvarious fees, including a quarterly commitment fee of 0.5% per annum andengineering 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.

 

Thecredit agreement contains covenants that, among other things, restrict ourability, subject to certain exceptions, to do the following:

 

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·**               **incur liens;

 

·**               **incur debt;

 

·**               **make investments in otherpersons;

 

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

 

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

 

·**               **enter into certain hedgingarrangements;

 

·**               **amend material contracts;and

 

·**               **enter into related partytransactions.

 

With regard to hedgingarrangements, 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 credit agreement, asamended, also requires that we satisfy certain affirmative covenants, meetcertain financial tests, maintain certain financial ratios and make certaincustomary indemnifications to lenders and the administrative agent. Thefinancial covenants include requirements to maintain: (i) a ratio ofEBITDA to cash interest expense of not less than 3.00 to 1.00, (ii) aratio of current assets to current liabilities of not less than 1.00 to 1.00,(iii) a total debt to annualized EBITDA ratio of not more than 3.0 to 1.0,(iv) a quarterly total senior debt to annualized EBITDA ratio equal to orless than 3.0 to 1.0, and (v) a total proved PV-10 value to total debtratio of at least 1.50 to 1.00.

 

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

 

After an event of default,the outstanding debt bears interest at the default rate under the terms of thecredit agreement. The default rate is (i) with respect to principal, 2%over the otherwise applicable rate and (ii) with respect to interest, feesand other amounts, the Base Rate (as defined in the credit facility), plus theApplicable Margin (as defined in the credit agreement), plus 2%. Any defaultinterest is payable on demand. Failure to pay the default interest when the administrativeagent demands would be another default. The lenders’ remedies for defaultsunder the credit agreement are to terminate further borrowings, accelerate therepayment of indebtedness and/or ultimately foreclose on the collateralproperty.

 

Effective August 4,2009, 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 30,2009, the third amendment, among other things, required that immediately priorto any additional borrowings under the credit agreement, our ratio of currentassets to current liabilities is 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) the greater of the one month LIBOR plus 1.00% or a domestic bank rate,plus in either case an applicable margin of 0.75% to 1.75% based on utilization,or (ii) a sliding scale from the one, two, three or six month LIBOR, plusan applicable margin of 2.00% to 3.00% based on utilization, and provided forthe payment of an amendment fee.

 

OnApril 14, 2009, we and the administrative agent entered into the fourthamendment to the credit agreement which reduced the borrowing base as describedabove and waived compliance with the current ratio financial covenant as of December 31,2009 and June 30, 2009 and with the restrictive covenants related toaccounts payable, permitted liens and permitted debt until the current ratiofinancial covenant and next borrowing base redetermination, subject to certainfinancial caps. On August 19, 2009, the lenders waived compliance with thecurrent ratio financial covenant under the Credit Agreement for the periodending August 26, 2009 and the quarter ending June 30, 2010.

 

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On August 26, 2009, we entered into a fifth amendment to thecredit agreement which provided a waiver of the current ratio covenant throughOctober 26, 2009 and for the quarter ending June 30, 2009. The fifthamendment to the credit agreement also extended restrictive covenants relatedto accounts payable, permitted liens and permitted debt, until October 26,2009, subject to certain financial caps.

 

On October 20, 2009, we and the Lenders executed the sixthamendment to the credit agreement. This amendment established the borrowingbase for the following amounts in the following applicable periods:

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

 

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

 

On October 26, 2009, the lenders provided a waiver effectivelyextending the terms of the fifth amendment to the credit agreement throughNovember 16, 2009. On November 16, 2009, the lenders provided anadditional waiver effectively extending the terms of the fifth amendment to thecredit agreement through November 23, 2009.

 

On November 23, 2009, the lenders provided an additional waiverextending the terms of the fifth amendment to the credit agreement throughDecember 1, 2009 and for the quarter ended December 31, 2009.

 

On December 1, 2009 the lenders provided an additional waiverextending the terms of the fifth amendment to the credit agreement throughJanuary 5, 2010.

 

On January 5, 2010 the lenders provided an additional waiverextending the terms of the fifth amendment to the credit agreement throughJanuary 12, 2010.

 

On January 13, 2010, we entered into a seventh amendment andwaiver to credit agreement (“*waiveragreement*”) with the lenders party thereto. The waiver agreementprovided that the lenders would waive (i) our compliance with certainrestrictions based on the current ratio in the credit agreement,(ii) certain requirements pertaining to the aging of certain accountspayable, and (iii) certain restrictions regarding the amount of liens wehave. Default remedies available to the lenders under the credit agreementinclude acceleration of all principal and interest amounts due under the creditagreement. The waiver agreement extended the waiver period for these itemsuntil the earlier of June 15, 2010 and the date of any default arising outof a breach or non-compliance with the credit agreement not expressly waived inthe waiver agreement or a breach of the waiver agreement.

 

In addition, the waiver agreement amends the definition of “FinalMaturity Date” under the credit agreement to the earlier of(i) June 15, 2010 or (ii) the date that is thirty days followingthe earlier of (A) the date the merger is withdrawn or terminated in wholeor in part or (B) the date that the lenders have been advised that themerger will not proceed.

 

On July 8, 2010, we were notified by our lender that we failed tomake the principal and interest payments due on July 1, 2010 and that suchmissed payments constituted an Events of Default under the Credit Agreement. Weremain obligated to pay all amounts outstanding under the credit agreement. Thecurrent amount outstanding under the credit facility is approximately$5,100,000.

 

Wehave requested additional waivers from our lender; however, there can be noassurance that we will be able to obtain such waivers or that such waivers willbe obtained on acceptable terms. If we are unable to obtain future waiversand/or to comply with the restrictive covenants, the lender could foreclose onproperties held by liens.  Due to borrowing base limitations and waiverstipulations, we are currently unable to incur additional indebtedness underthe credit facility.

 

*Office Building Loan.*

 

On November 15, 2005,we entered into a mortgage loan secured by our office building in Sheridan,Wyoming in the aggregate principal amount of $829,000. The promissory noteprovides for monthly payments of principal and interest in the initial amountof $6,400, and unpaid principal that bore interest at 6.875% untilNovember 15, 2009, currently bears interest at a variable base rate plus0.5% and will bear interest at 18% upon a default. The variable base rate isbased on the lender’s base rate. The maturity date of this mortgage isNovember 15, 2015, at which time a principal and interest payment of$531,300 will become due. As of June

 

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30, 2010, we had $717,000outstanding in principal on this mortgage. On November 15, 2009, theinterest rate on our mortgage loan changed from a fixed rate of 6.875% to avariable rate. As of June 30, 2010, the variable rate was 4.00%.

 

*Capital Expenditure Budget*.

 

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 andremained low in 2009 and six months ending June 30, 2010. Therefore, totalcapital expenditures were limited to $4.2 million in 2009. As a result oflow CIG index prices, the economic climate and our limited capital resources,we expect to continue operating during 2010 with a reduced capital expenditureplan. Under our plan, we will generally make expenditures only as necessary tosecure drilling permits in strategic areas, drill wells that secure leaseholdpositions and construct the necessary infrastructure to complete and hook-upwells that have already been drilled. Our capital expenditure budget for 2010 willbe dependent upon CIG index prices, our cash flows and the availability ofadditional capital resources. We had total capital expenditures of $1.9 millionfor the six months ended June 30, 2010.

 

***Cash Flow from Operating Activities***

 

Net cash provided by operating activities was $1.5 million for the sixmonths ended June 30, 2010, compared to net cash used in operatingactivities of $1.1 million for the six months ended June 30, 2009. Thechange was primarily due to increases in accounts payable, accrued liabilities,and revenue distribution payables.

 

***Cash Flow from Investing Activities***

 

Netcash used in investing activities was approximately $0.5 million for the sixmonths ended June 30, 2010, compared to net cash provided by investingactivities of $4.2 million for the six months ended June 30, 2009. Thechange in 2010 was primarily due to smaller realized gains on derivatives, asale of properties in 2009, and a liquidation of certificate of deposits in2010.

 

***Cash Flow from Financing Activities***

 

Net cash used in financing activities was $1.0 million for the sixmonths ended June 30, 2010, compared to $3.5 million for the six monthsended June 30, 2009. The change in 2010 was primarily due to a reductionin the balance owed on the line of credit for the six months ended June 30,2010.

 

There have been no issuances of shares of common stock since ourinitial public offering except to employees, executive officers and directorspursuant to our incentive stock plan.

 

***Contractual Obligations***

 

Pleasesee Notes 3 and 7 of the Notes to the unaudited financial statements appearingelsewhere in this quarterly report for information regarding our creditfacility and other indebtedness.

 

Thefollowing table summarizes by period our contractual obligations as of June 30,2010:

 
| ** **                                | ** ** | **Total**          | ** ** | **2010** | ** ** | **2011–2012** | ** ** | **2013–2014** | ** ** | **Thereafter** | ** ** |
|-------------------------------------------|------------|--------------------|------------|----------|------------|--------------------|------------|--------------------|------------|----------------|------------|
| ** **                                | ** ** | **(In Thousands)** | ** ** |
| Notes payable in connection with mortgage |       | $                  | 717        |     | $          | 17                 |       | $                  | 71         |           | $          | 76 |   | $ | 553 |   |
| Capital lease                             |       | 65                 |       | 10       |       | 45                 |       | 10                 |       | —         |       |
| Asset retirement obligations              |       | 2,995              |       | 652      |       | 822                |       | 420                |       | 1,101          |       |
| Production and property taxes             |       | 3,735              |       | 3,273    |       | 462                |       | —             |       | —         |       |
| Total                                     |       | $                  | 7,512      |     | $          | 3,952              |       | $                  | 1,400      |           | $          | 506 |   | $ | 1,654 |   |

 

**ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUTMARKET RISK**

 

Theprimary objective of the following information is to provide forward-looking quantitativeand qualitative information about our potential exposure to market risk. Theterm “market risk” refers to the risk of loss arising from adverse changes innatural gas prices. This forward-looking information provides indicators of howwe view and manage our ongoing market risk exposure. All of our market risksensitive instruments were entered into for purposes other than speculativetrading.

 

**Commodity Price Risk**

 

Our major market riskexposure is in the pricing applicable to our natural gas production. The priceswe receive for our production depend on many factors beyond our control. Weseek to reduce our exposure to unfavorable changes in natural gas prices, whichare subject to significant and often volatile fluctuation, through the use of fixed-pricecontracts. Our fixed-price contracts are 

 

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comprised of energy swapsand collars. Fixed price contracts allow us to predict with greater certaintythe effective natural gas prices to be received for hedged production andbenefit operating cash flows and earnings when market prices are less than thefixed prices provided by the contracts. However, we will not benefit frommarket prices that are higher than the fixed prices in the contracts for hedgedproduction. Collar structures provide for participation in price increases anddecreases to the extent of the ceiling prices and floors provided in those contracts.With regard to hedging arrangements, our credit facility provides thatacceptable commodity hedging arrangements cannot cover greater than 80 to 85%,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 borrowingbase.

 

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

 
| ** **                                      | ** ** | **Year Ending  December 31, 2010** | ** ** |
|-------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                      | ** ** | **(Unaudited)**                                   | ** ** |
| **Natural Gas Swaps:**                          |       |                                              |       |
| Contract volumes (MMBtu)                        |       | 1,012,000                                         |       |
| Weighted-average fixed price sales per MMBtu(1) |       | $                                                 | 5.08       |   |
| Fair value, net (thousands)(2)                  |       | $                                                 | 904        |   |
| **Total Natural Gas Contracts:**                |       |                                              |       |
| Contract volumes (MMBtu)                        |       | 1,012,000                                         |       |
| Fixed-price sales                               |       | $                                                 | 5.08       |   |
| Fair value, net (thousands)(2)                  |       | $                                                 | 904        |   |

 

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(1)           Volumes hedged using the CIGindex price published in the first issue of Inside FERC’s Gas Market Report foreach calendar month of the derivative transaction.

 

(2)    Fair value based on CIG index price ineffect for each month as of June 30, 2010.

 

**Interest Rate Risk**

 

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

 

As of June 30, 2010, we had $5.1 million in outstanding indebtednessunder our credit facility. Borrowings under the credit facility bear interesteither: (i) at the greater of the one month LIBOR plus 1.00% or a domesticbank rate, plus in either case an applicable margin of 0.75% to 1.75% based onutilization, or (ii) on a sliding scale from one, two, three, or six monthLIBOR, plus an applicable margin of 2.00% to 3.00% based on utilization. Theweighted average interest rate for borrowings under our credit facility was5.0% for the six months ended June 30, 2010 and for the year endedDecember 31, 2009, respectively. In light of the current economic climate,we expect that interest rates on alternative financing options to range from 8%to 12%. The availability of alternative financing arrangements and the interestrates thereof would depend on the type of financing and our ability torestructure our current indebtness outstanding under our credit facility. Dueto covenant restrictions in our credit facility, we are currently unable toborrow additional amounts.

 

Ahypothetical change of 1% in either the domestic bank rate or the LIBORinterest rates would increase or decrease gross interest expense approximately$51,000 per year based on our outstanding indebtness at June 30, 2010.

 

**ITEM 4T. CONTROLS AND PROCEDURES**

 

**Disclosure Controls and Procedures**

 

Our principal executiveofficer and principal financial officer are responsible for establishing andmaintaining 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.

 

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**Changes inInternal Control over Financial Reporting**

 

Duringthe most recent fiscal quarter, there has been no change in our internalcontrol over financial reporting that has materially affected, or is reasonablylikely to materially affect, our internal control over financial reporting.

 

**PART II. OTHERINFORMATION**

 

**ITEM 1. LEGAL PROCEEDINGS**

 

Fromtime to time, we are subject to legal proceedings and claims that arise in theordinary course of our business. While the outcome of these proceedings cannotbe predicted with certainty, we do not currently expect them to have a materialadverse effect on the financial statements.

 

Therehas been no material developments during the quarter ended June 30, 2010regarding our currently pending legal proceedings. For a discussion of certainof 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**

 

Thefollowing discussion supplements or updates the risk factors set forth underthe heading “Risk Factors” in our annual report on Form 10-K for the yearended December 31, 2009.

 

***Due to the recent financial andcredit crisis, we may not be able to obtain funding, or obtain funding onacceptable terms, to meet our future capital needs, which could negativelyaffect our business, results of operations and financial condition.***

 

The continued credit crisis and the related turmoil in the globalfinancial system have had an adverse impact on our business and financialcondition, and we may face major challenges if conditions in the financial marketsdo not improve. Currently, we are not able to borrow additional amounts underour credit facility. As a result, we curtailed substantially all new drillingin 2009 and if our operating cash flow is not sufficient to carry out ourdrilling plans for 2010, we will be required to reduce the number of wells wedrill or seek alternative sources of financing. However, due to the financialcrisis, financing through the capital markets or otherwise may not be availableto us on acceptable terms or at all. If additional funding is not available, oris available only on unfavorable terms, we may be unable to implement ourdrilling plans, make capital expenditures, withstand a further downturn in ourbusiness or the economy in general, or take advantage of business opportunitiesthat may arise. Any further curtailment of our operations would have anadditional adverse effect on our revenues and results of operations. Inaddition, current economic conditions have led to reduced demand for, and lowerprices of, oil and natural gas, and a sustained decline the price of naturalgas would adversely affect our business, results of operations and financialcondition.  Further, the economicsituation could have an impact on our lenders or customers, causing them tofail to meet their obligations to us, and on the liquidity of our operatingpartners, resulting in delays in operations or their failure to make requiredpayments. Also, market conditions could have an impact on our natural gas andoil derivatives transactions if our counterparties are unable to perform theirobligations or seek bankruptcy protection.

 

***Our contemplated merger agreement may not be consummated.***

 

We have entered an Agreement and Plan of Merger, as further describedin Note 11 in the notes to the unaudited financial statements herein andin the proxy statement filed April 2, 2010. There can be no assurancesthat the contemplated merger transaction will occur. If the merger is notconsummated, we will continue to need additional capital to remain a goingconcern and successfully operate our business.

 

***We are in default pursuant to ourcredit facility.***

 

As described inthe Liquidity and Capital Resources section in this report, the seventhamendment and waiver to credit agreement has expired and we failed to make theprincipal and interest payments due July 1, 2010 and August 1,2010.  As a result, we are in defaultpursuant to the credit facility and our lender may elect to pursue remediesunder the credit facility including foreclosure of our secured assets.

 

***Our credit facility has substantialrestrictions and financial covenants that may affect our ability tosuccessfully operate our business. In addition, we may have difficultyreturning to compliance with certain financial covenants.***

 

Our credit facility imposes certain operational and financialrestrictions on us. These restrictions, among other things, limit our abilityto:

 

·                  incur additionalindebtedness;

 

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·                  create liens;

 

·                  sell our assets orconsolidate or merge with or into other companies;

 

·                  make investments and otherrestricted payments, including dividends; and

 

·                  engage in transactions withaffiliates.

 

These limitations are subject to a number of important qualificationsand exceptions. In addition, our credit facility requires us to maintaincertain financial ratios and to satisfy certain financial conditions which mayrequire us to reduce our debt or to take some other action in order to complywith them. These restrictions in our credit facility could also limit ourability to obtain future financings, make needed capital expenditures,withstand a downturn in our business or the economy in general, or otherwiseconduct necessary corporate activities. We also may be prevented from takingadvantage of business opportunities that arise because of the limitationsimposed on us by the restrictive covenants under our credit facility.

 

We were not in compliance with the current ratio financial covenant andcertain other covenants related to accounts payable, permitted liens andpermitted debt under our credit facility, and would be in default absent awaiver or amendment. On January 13, 2010, the lenders waived compliancewith the current ratio as of December 31, 2009 through June 15, 2010,and with such other restrictive covenants, subject to certain financial caps.We have also not been in compliance with certain financial covenants for the lastseven quarters, but obtained waivers and/or amendments in each instance. Inaddition, the final maturity date of the funds outstanding under our creditfacility was accelerated to June 15, 2010. As a result of suchnon-compliance, we are unable to borrow additional funds under our creditagreement.

 

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

 

**ITEM 2.UNREGISTERED SHARES OF EQUITY SECURITIES AND USE OF PROCEEDS**

 

Not applicable.

 

**ITEM 3.DEFAULTS UPON SENIOR SECURITIES**

 

OnJuly 8, 2010, the Company was notified by its lender that it failed tomake the principal and interest payments due on July 1, 2010 and that suchmissed payments constituted an Events of Default under the CreditAgreement.  The Company was obligated to pay all amounts outstanding underthe credit agreement on or before July 15, 2010, but to date has not paidsuch amounts.  Furthermore, the Company did not make its principal andinterest payment on August 1, 2010. The current amount outstanding under the credit facility isapproximately $5,100,000.

 

Todate, the lender has not accelerated the payment of the amounts due.

 

Thedefault under the terms of the credit agreement is also a default under theterm of the Merger Agreement with Powder, providing Powder the right toterminate the Merger.  Powder has indicated at this time that it will notwaive the default; however, it has not terminated the Merger.  Onecondition to the closing of the Merger is the receipt of waiver of defaultsunder the credit agreement from our lender, The Royal Bank of Scotland.  Although Powder has not terminated theMerger, as discussed below, there is no assurance that the Company will be ableto obtain additional waivers from our lender.

 

TheCompany has requested additional waivers from its lender; however, there can beno assurance that it will be able to obtain such waivers or that such waiverswill be obtained on acceptable terms. If the Company is unable to obtain futurewaivers and/or to comply with the restrictive covenants, the lender couldforeclose on properties held by liens.  Due to borrowing base limitationsand waiver stipulations, the Company is currently unable to incur additionalindebtedness under the credit facility.

 

**ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS**

** **

Notapplicable.

 

**ITEM 5.OTHER INFORMATION**

 

Notapplicable.

 

**ITEM 6. EXHIBITS**

 
| **Exhibit****No.** | ** ** | **Description**                                                                                                                                                                                                                                                                                                                                                                   |
|--------------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 2.1                |       | Amended  and Restated Agreement and Plan of Merger, dated as of February 23,  2010, among Powder Holdings, LLC, Pinnacle Gas Resources, Inc. and  Powder Acquisition, Co. (incorporated by reference to Exhibit 2.1  to the Current Report on Form 8-K (File No. 001-33457) filed by  Pinnacle Gas Resources, Inc. on February 26, 2010). |
| 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                                                                                                                           |

 

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|   |   | Resources, Inc.  on May 10, 2006).                                                                                                                                                                                                                                       |
|--------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.2    | — | Amended  and Restated Bylaws of Pinnacle Gas Resources, Inc. (incorporated herein  by reference to Exhibit 3.2 to the Registration Statement on  Form S-1 (File No. 333-133983) filed by Pinnacle Gas  Resources, Inc. on May 10, 2006).             |
| 4.1    | — | Amended  and Restated Securityholders Agreement, dated February 16, 2006  (incorporated herein by reference to Exhibit 4.1 to the Registration  Statement on Form S-1 (File No. 333-133983) filed by Pinnacle Gas  Resources, Inc. on May 10, 2006). |
| 4.2    | — | Registration  Rights Agreement, dated April 11, 2006 (incorporated herein by reference  to Exhibit 4.2 to the Registration Statement on Form S-1 (File  No. 333-133983) filed by Pinnacle Gas Resources, Inc. on  May 10, 2006).                     |
| 10.21  | — | 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).             |
| 10.22  |   | Waiver  to Credit Agreement, dated as of August 19, 2009 (incorporated herein by  reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q  filed by Pinnacle Gas Resources on August 19, 2009).                                                         |
| 10.23  |   | Fifth  Amendment to the Credit Agreement, dated August 26, 2009 (incorporated  herein by reference to Exhibit 10.1 to the 8-K filed by Pinnacle Gas  Resources, Inc. on August 27, 2009).                                                                      |
| 10.24  |   | Sixth  Amendment to the Credit Agreement, dated October 20, 2009 (incorporated  herein by reference to Exhibit 10.1 to the 8-K filed by Pinnacle Gas  Resources, Inc. on October 22, 2009).                                                                    |
| 10.25  |   | Waiver  and Amendment, dated October 26, 2009 (incorporated herein by reference  to Exhibit 10.1 to the 8-K filed by Pinnacle Gas Resources, Inc. on  October 29, 2009).                                                                                       |
| 10.26  |   | Waiver  and Amendment, dated November 16, 2009 (incorporated herein by reference  to Exhibit 10.1 to the 8-K filed by Pinnacle Gas Resources, Inc. on  November 19, 2009).                                                                                     |
| 10.27  |   | Waiver  and Amendment, dated November 23, 2009 (incorporated herein by reference  to Exhibit 10.1 to the 8-K filed by Pinnacle Gas Resources, Inc. on  November 23, 2009).                                                                                     |
| 10.28  |   | Waiver  and Agreement dated as of January 5, 2010 (incorporated herein by  reference to Exhibit 10.1 to the 8-K filed by Pinnacle Gas  Resources, Inc. on January 8, 2010).                                                                                    |
| 10.29  |   | Seventh  Amendment and Waiver to the Credit Agreement dated as of January 13,  2010 (incorporated herein by reference to Exhibit 10.1 to the 8-K filed  by Pinnacle Gas Resources, Inc. on January 19, 2010).                                                  |
| *31.1  | — | Certification  of President and Chief Executive Officer of Pinnacle Gas Resources, Inc.  pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                      |
| *31.2  | — | Certification  of Senior Vice President, Chief Financial Officer and Secretary of Pinnacle  Gas Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley  Act of 2002.                                                                                              |
| *32.1  | — | Certification  of President and Chief Executive Officer of Pinnacle Gas Resources, Inc.  pursuant to 18 U.S.C. Section 1350, as adopted pursuant to  Section 906 of the Sarbanes-Oxley Act of 2002.                                                                 |
| *32.2  | — | Certification  of Senior Vice President, Chief Financial Officer and Secretary of Pinnacle  Gas Resources, Inc. pursuant to 18 U.S.C. Section 1350, as adopted  pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                                          |

 

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*              Filed herewith

 

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**SIGNATURES**

 

Pursuant to the requirementsof the Securities Exchange Act of 1934, the registrant has duly caused thisreport to be signed on its behalf by the undersigned thereunto duly authorized.

 
|   | PINNACLE  GAS RESOURCES, INC. |
|--------|------------------------------------|
|   |                               |   |
|   | By:                                | /s/ Peter G. Schoonmaker |
|   | Name:                              | Peter G. Schoonmaker |
|   | Title:                             | *President, Chief Executive Officer and Director* |
|   |                               | (Principal Executive Officer) |
|   |                               |   |
|   | Date:                              | August 16,  2010 |
|   |                               |   |
|   | 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 16,  2010 |

 

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