UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

Commission file number 001-32471

PRB ENERGY, INC.

(Exact Name of Registrant as Specified in its Charter)

Telephone Number: (303) 308-1330

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  o  Accelerated filer  o  Non-accelerated filer  x

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PRB ENERGY, INC.

Consolidated Balance Sheets

(In thousands, except share amounts)

The accompanying notes are an integral part of these consolidated financial statements.

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PRB ENERGY, INC.

Consolidated Statements of Operations

(In thousands, except share and per share amounts)

(Unaudited)

The accompanying notes are an integral part of these consolidated financial statements.

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PRB ENERGY, INC.

Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

The accompanying notes are an integral part of these consolidated financial statements.

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PRB ENERGY, INC.

Notes to Consolidated Financial Statements

September 30, 2007

(Unaudited)

Note 1—Description of Business, Basis of Presentation and Summary of Significant Accounting Policies

Description of Business

PRB Energy, Inc. and its subsidiaries (“PRB,” “PRB Energy,” “the Company,” “us,” “our” or “we”) operate as an independent energy company engaged in the acquisition, exploitation, development and production of natural gas and oil. In addition, we provide gas gathering, processing and compression services for properties we operate and for third-party producers. We were initially incorporated in Nevada under the name “PRB Transportation, Inc.” in December 2003.  On June 14, 2006, we changed our name to “PRB Energy, Inc.”  Our common stock is traded on the American Stock Exchange (“AMEX”) under the ticker symbol “PRB.”   PRB Energy operates through two wholly-owned subsidiaries, PRB Oil and Gas, Inc., a Colorado corporation formed in July 2005 that focuses on gas and oil exploitation and production, and PRB Gathering, Inc., a Colorado corporation formed in August 2006 that focuses on gathering and processing.  We conduct our business activities in Wyoming, Colorado and Nebraska.

Basis of Presentation

We have prepared this Quarterly Report on Form 10-Q under the rules and regulations of the United States Securities and Exchange Commission. Because this is an interim period filing, using a condensed format, certain information and footnote disclosures normally included in consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted. These interim financial statements should be read in conjunction with the audited consolidated financial statements and the summary of significant accounting policies and notes thereto included in our 2006 Annual Report on Form 10-K.  During interim periods, we follow the same accounting policies outlined in our 2006 Annual Report on Form 10-K, Note 2 — Summary of Significant Accounting Policies. The consolidated financial statements as of September 30, 2007, and for the three and nine months ended September 30, 2007 and September 30, 2006 are unaudited. Certain reclassifications have been made to the 2006 unaudited condensed consolidated financial statements to conform to the 2007 presentation. Such reclassifications had no effect on the 2006 net loss. In the opinion of management, these interim financial statements contain all adjustments which are of a normal, recurring nature to fairly present the financial position of PRB as of September 30, 2007 and the results of our operations for the three and nine months ending September 30, 2007 and September 30, 2006, and cash flows for the nine months ended September 30, 2007 and September 30, 2006. Information for interim periods may not be indicative of our results of operations for the entire year.

Summary of Significant Accounting Policies

Use of Estimates

Management makes estimates and assumptions that affect the amounts reported in the financial statements and the disclosures made in the accompanying notes. Some examples of such estimates are the allowance for accounts receivable, the appropriate levels of various accruals, including asset retirement obligations, determining the remaining economic lives and carrying values of property and equipment and the estimates of gas reserves that affect the depletion calculations and impairments for gas properties and other long-lived assets. In addition, we use assumptions to estimate the fair value of share-based compensation. We believe our estimates and assumptions are reasonable; however, actual results may differ from our estimates.

Share-Based Compensation

Effective January 1, 2006, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Share-Based Payment,” using the modified prospective transition method and, as a result, did not retroactively adjust results from prior periods.  SFAS No. 123(R) requires that share-based compensation expense be measured using estimates of the fair value of all share-based awards and applies to new awards and to awards modified, repurchased or cancelled after December 31, 2005, as well as to the unvested portion of awards outstanding as of January 1, 2006. Under the modified prospective transition method, we are recognizing share-based compensation expense over the remaining vesting period for awards that were outstanding but unvested at January 1, 2006, and we are recognizing share-based compensation expense for the fair value of all awards granted on or after January 1, 2006 as the awards vest. We apply the Black-Scholes option valuation model in determining the fair value of share-based payments to employees.  See Note 7 – 2007 Equity Incentive Plan for further discussion of share-based compensation.

Net Loss Per Share

We account for earnings (loss) per share (“EPS”) in accordance with SFAS No. 128, “Earnings per Share.”  Under SFAS No. 128, basic EPS is computed by dividing the net loss applicable to common stockholders by the weighted average common shares outstanding without including any potentially dilutive securities. Diluted EPS is computed by dividing the net loss applicable to common stockholders for the period by the weighted average common shares outstanding, plus, when their effect is dilutive, common stock equivalents. Basic and diluted shares outstanding at September 30, 2007 and September 30, 2006, used for our EPS calculation

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were 8,639,796 and 7,458,708, respectively. The following are potentially dilutive shares that are excluded from the calculation as they are anti-dilutive:

Concentrations of Credit Risk

We grant credit in the normal course of business to customers in the United States. Management periodically performs a credit analysis and monitors the financial condition of our customers to reduce credit risk.  Management periodically reviews accounts receivable and reduces the carrying amount by a valuation allowance that reflects management’s best estimate of the amount that may not be collectible.  Allowances for uncollectible accounts receivable are based on information available and historical experience.  As of September 30, 2007 and December 31, 2006, there were balances of $69,500 and $604,000, respectively, as an allowance for uncollectible accounts receivable. The significant reduction in the balance of the allowance from December 31, 2006 was due to the Rocky Mountain Gas, Inc. (“RMG”) settlement payment. See Note 10 — Subsequent Events.

Revenues from customers which represented 10% or more of our gas sales or gathering fees for the three and nine months ended September 30, 2007 and September 30, 2006 were as follows:

Debt Issuance Costs and Discount on Debt

 We include debt issuance costs in other non-current assets.  These costs are associated with the senior subordinated convertible notes (“Notes”) that we issued in March 2006 and the senior secured debentures (“Debentures”) that we issued in December 2006.  The remaining unamortized debt issuance cost was $1,081,000 at September 30, 2007 and is being amortized using the effective interest rate method over the term of the debt.

The discount on the Debentures of $4,326,000 is reflected as a liability on the balance sheet at December 31, 2006. The remaining unamortized discount at September 30, 2007 was $2,693,000 and is being amortized using the effective interest rate method over the term of the debt.

Capital Initiatives

The Company is in the process of looking for additional capital and/or financing agreements to meet capital budget requirements. Although the Company is actively seeking such financing there can be no assurance that the Company will be able to raise additional capital on acceptable terms or at all.

Note 2—Recent Accounting Pronouncements

In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”) - an interpretation of FASB Statement No. 109, “Accounting for Income Taxes”. FIN 48 requires that realization of an uncertain income tax position must be “more likely than not” (i.e. greater than 50% likelihood of receiving a benefit) before it can be recognized in the financial statements. Further, this interpretation prescribes the benefit to be recorded in the financial statements as the amount most likely to be realized assuming a review by tax authorities having all relevant information and applying current conventions. FIN 48 also clarifies the financial statement classification of tax-related penalties and interest and sets forth new disclosures regarding unrecognized tax benefits. FIN 48 is effective for fiscal years beginning after December 15, 2006, and we adopted this interpretation effective January 1, 2007. See Note 6 – Income Taxes for further discussion.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). This statement defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 will become effective for our fiscal year beginning January 1, 2008, and we will assess its potential impact on our financial statements prior to that date.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”), which permits an entity to measure certain financial assets and financial liabilities at fair value. The objective of

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SFAS No. 159 is to improve financial reporting by allowing entities to mitigate volatility in reported earnings caused by the measurement of related assets and liabilities using different attributes without having to apply complex hedge accounting provisions. Under SFAS No. 159, entities that elect the fair value option (by instrument) will report unrealized gains and losses in earnings at each subsequent reporting date. The fair value option election is irrevocable, unless a new election date occurs. SFAS No. 159 establishes presentation and disclosure requirements to help financial statement users understand the effect of the entity’s election on its earnings but does not eliminate disclosure requirements of other accounting standards. Assets and liabilities that are measured at fair value must be displayed on the face of the balance sheet. SFAS No. 159 is effective beginning January 1, 2008, and we will assess its potential impact on our financial statements prior to that date.

Note 3—Significant Agreements

Compressor Lease Agreement

On February 12, 2007, PRB Gathering, Inc. entered into a 5-year lease agreement with J-W Power Company (“J-W”), effective January 24, 2007.  Under the terms of the agreement, J-W will supply us with gas compression equipment and related services.  The compression equipment will service our gas gathering pipelines in the Powder River Basin.

The lease meets the criteria under SFAS No. 13, “Accounting for Leases,” for classification as a capital lease on the balance sheet.  As a result, a capital lease asset of $3,050,000, which represents the estimated fair value of the property, was recorded in January 2007. The related liability, less the current portion of $84,000, is shown as a non-current liability of $2,974,000 on the balance sheet at September 30, 2007.  In addition, a cash payment of $650,000 was made to J-W for future maintenance repairs in connection with the lease. The capital lease and prepayment will be amortized as expenses over the term of the lease.  Monthly lease payments ranging from $100,000 to $150,000 will reduce the liability and will also include interest and executory (sales tax and environmental fees) expenses.

RMG Settlement Agreement

On May 15, 2007, RMG and PRB reached a settlement and terminated their arbitration proceedings. RMG agreed to pay PRB $3,250,000 total, represented by two cash payments of $500,000 each made on May 22^nd and June 21^st, 2007, with the balance due on or before October 31, 2007.  A promissory note dated June 1, 2007 (the “RMG Note”) for the remaining balance was also received from RMG.  The Note bears an interest rate of 10% per annum and is secured by a mortgage.  The interest applicable for financing the RMG Note totaled $150,000, which is payable at maturity of the RMG Note.  This amount will be recognized as interest income over the term of the RMG Note.  The RMG Note balance at September 30, 2007 is $2,250,000 and is reflected as a Notes Receivable on the balance sheet.

On June 15, 2007, as a condition for obtaining the consent of the lenders, who held a security interest in the PRB Assets to be transferred to RMG, we agreed to pay the lenders, as a reduction of our outstanding balance due on the Debentures, one-half of the final $2,250,000 payment to be received from RMG.  Under our agreement with the lenders, upon receipt of the RMG payment we will pay the lenders $1,125,000, plus any associated interest and fees due under the provisions of the Debentures.  The payment to the lenders will partially redeem, on a pro rata basis, a portion of the principal and interest amounts due under the Debentures.

Note 4—Asset Retirement Obligations

We recognize an estimated liability for future costs associated with abandoning our property and equipment used in the production of natural gas from our wells and in our gas gathering operations. A liability for the fair value of an asset retirement obligation is established when the long-lived asset is acquired, constructed or completed, with a corresponding increase in the carrying value of the asset. We depreciate the asset retirement obligations associated with our property and equipment, deplete the amounts recorded in respect to our gas properties, and recognize accretion expense of the liability, all based on the estimated useful lives of the assets and remaining recoverable reserves.

We estimate our future retirement obligations based on our experience, management estimates and regulatory requirements. We discount the estimated future obligations using an estimated credit adjusted risk-free rate at the time the obligation is incurred or revised. Historically this rate has been estimated at 10%. The estimated obligations may be revised due to changes in expected lives of gas wells, gas gathering system configuration, estimates and regulations.

Note 5—Borrowings

As of September 30, 2007 and December 31, 2006, our borrowings consisted of the following:

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Senior Subordinated Convertible Notes

In March 2006, we issued the Notes approximating a principal amount of $22 million in a private placement.  The Notes are secured by certain of our gas gathering assets and mature 30 months from the date of issue.  The Notes bear interest at a fixed rate of 10% per annum, payable quarterly in arrears.  A registration statement applicable to the shares of common stock underlying the Notes was declared effective in June 2006.  The Notes do not contain any beneficial conversion features. Note holders have the right to convert the Notes to common stock at a conversion price of $7.00 per share, which is subject to certain anti-dilution adjustments.  In addition, the Company is prohibited from declaring or paying cash dividends on the common stock during the period that the Notes are outstanding and unpaid.

At September 30, 2006, debt issuance costs of the Notes totaling approximately $1.1 million, excluding the value of issued warrants, were reflected as other non-current assets and have been amortized as interest expense in each applicable period.  For the nine months ended September 30, 2007, $343,000 of the deferred cost of the Notes was amortized as interest expense and an additional $1,666,000 of interest paid in cash was expensed.

We follow SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and EITF 00-19, “Accounting for Derivative Financial Instruments Index to, and Potentially Settled in a Company’s Own Stock” and the related pronouncements.  We have evaluated the conversion feature embedded in the Notes and the liquidated damages provision in the related registration rights agreement and have determined that the entire amount of these securities is properly classified as debt and is not accounted for as a derivative on the consolidated balance sheet at September 30, 2007.

Senior Secured Debentures

In connection with the December 2006 acquisition of the NE Colorado Field in the Niobrara formation, we entered into a Securities Purchase Agreement with two private lenders.  Pursuant to that agreement, we issued to the lenders $15 million in Debentures and 1,250,000 shares of our common stock.

The Debentures are payable on August 31, 2008 and bear interest at a rate of 13% per annum. Interest payments are due quarterly in arrears. Pursuant to the terms of a Pledge and Security Agreement that we entered into with the lenders, the Debentures are collateralized by substantially all of our assets, except for certain excluded assets as described in the Pledge and Security Agreement.

At September 30, 2007, debt issuance costs of the Debentures totaling approximately $1.1 million were reflected as other non-current assets and have been amortized as interest expense in each applicable period. For the nine months ended September 30, 2007, $442,000 of the deferred cost of the Debentures was amortized as interest expense and an additional $1,458,000 of interest paid in cash was expensed.

The amortized portion of the discount on the Debentures of $1,633,000 was recorded as interest expense during the nine months ended September 30, 2007.

Note 6—Income Taxes

The valuation allowance for deferred taxes at December 31, 2006 was $4.6 million.  As of September 30, 2007, no change has been made on the balance sheet to reflect any deferred tax asset, as management believes that this allowance amount continues to be reasonable and appropriate. The effective income tax rate was 37% for 2006 and the nine months ended September 2007.

In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes”—an interpretation of FASB Statement No. 109, “Accounting for Income Taxes.”  FIN 48 addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest recognition, penalties on income taxes, accounting for taxes in interim periods, and increased disclosures in financial statements.

We adopted the provisions of FIN 48 effective January 1, 2007 and determined that there was no adjustment required to retained earnings. We recognize potential accrued interest and penalties, if any, related to unrecognized tax benefits in income tax expense, which is consistent with the recognition of these items in prior reporting periods. No interest or penalties related to uncertain tax positions were incurred at September 30, 2007.

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We have not had any material changes to our unrecognized tax benefits since we adopted FIN 48, nor do we anticipate significant changes to the total amount of unrecognized tax benefits within the next 12 months.

As of January 1, 2007, we remain subject to examination of our Federal and Colorado tax returns for the tax years 2004 through 2006.

Note 7—2007 Equity Incentive Plan

Our 2007 Equity Incentive Plan (the “2007 Plan”) allows us to grant non-qualified stock options, shares of restricted stock or other types of equity-based compensation of up to 20% of our outstanding shares to our non-employee directors, officers, employees and consultants. The 2007 Plan replaces our previous Equity Compensation Plan (“Option Plan”) that was adopted in May 2004. The 2007 Plan will be administered by a committee appointed by our Board of Directors, which may grant options on such terms, including vesting and payment forms, as it deems appropriate in its discretion. However, no option may be exercised more than 10 years after its grant, and the purchase price may not be less than 100% of the fair market value of our common stock on the date of grant.

All options granted to date under both the 2007 Plan and the Option Plan have been granted at exercise prices equal to or greater than the respective market prices of our common stock on the grant dates. There were 913,024 shares available for grant under the 2007 Plan as of September 30, 2007.

The following table summarizes the activity for options:

As of September 30, 2007, the weighted average fair value of options granted during the previous nine months was $2.02, the weighted average remaining contractual life for the options outstanding is 6.8 years, and the weighted average remaining contractual life for the options exercisable is 3.2 years. The fair value of each option granted is estimated on the date of grant using the Black-Scholes option valuation model.

The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable. In addition, option valuation models incorporate highly subjective assumptions including the expected stock price volatility. Our stock options have characteristics significantly different from those of traded options and, as changes in the subjective input assumptions can materially affect the fair value estimate, it is management’s opinion that the valuations as determined by the existing models are different from the value that the options would realize if traded in the market.

We used the following assumptions to estimate the fair value of options granted for the nine months ended September 30, 2007 and 2006:

Note 8 — Segment Information

SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” establishes standards for the way in which public companies disclose certain information about operating segments in their financial reports. Consistent with SFAS No. 131, we have defined three reportable segments, described below, based on factors such as the management of our operations and the views of our chief operating decision makers with respect to the results of our operations. We consider our chief executive officer and our chief operating officer as our chief operating decision makers.

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Oil and Gas Exploitation and Production Segment

Our operations during the first three quarters of 2007 in this segment include developing, producing and marketing natural gas primarily from coal-bed methane wells. Our exploitation and production segment currently operates in the Powder River Basin area of Wyoming and the Denver-Julesburg (“D-J”) Basin in Colorado.

Gas Gathering and Processing Segment

We own and operate gas gathering and processing systems that we acquired from 2004 through 2006. We charge a fee to our customers for gathering and processing services based on volumes of gas transported, a monthly minimum fee, and/or the level of compression services provided. We have acquired gas gathering contracts that include operating leases with respect to surface-use rights that are cancelable in the event that gas gathering activities cease as a result of declining production. We also have cancelable purchase commitments with third-party providers for future field operations, equipment and maintenance activities.

Corporate Segment

This segment consists of general corporate functions and costs consisting primarily of administrative, financial, legal and professional staff services, including related office facilities.

Note 9—Related Party Transactions

Susan Wright, wife of our CEO and a corporate officer, provides services to us as the Corporate Secretary on a contractual basis. During the nine months ended September 30, 2007, Ms. Wright was paid $91,000 for these contract services.

One of our officers (and a director) and three of our directors, in the aggregate, purchased $100,000 and a total of $1,275,000, respectively, of the Notes that were issued in the first quarter of 2006. During the nine months ended September 30, 2007, we paid interest of $7,600 and $97,000, respectively, on these Notes. In addition, an investment fund, of which one of our former directors is a consultant, purchased on behalf of its investors, $1,000,000 of the Notes. The investors were paid $76,000 in interest during the nine months ended September 30, 2007.

Note 10 —Subsequent Events

Amendment to Agreement with RMG

On October 31, 2007, the Company entered into Amendment No. 1 to the RMG Note (the “Amendment”). The Amendment extends the final maturity date of the Note from October 31, 2007 to February 29, 2008. The Amendment also provides that RMG will make payments to the Company of $850,000 on October 31, 2007, $400,000 on each of November 30, 2007, December 31, 2007 and January 31, 2008 and all remaining principal and accrued interest on February 29, 2008. The Company received the $850,000 payment on October 31, 2007.

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

Unless the context requires otherwise, the terms “PRB,” “the Company,” “us,” “we” and “our” refer to PRB Energy, Inc. and its subsidiaries.

Forward-Looking Statements

This quarterly report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements identify prospective information. Important factors could cause actual results to differ, possibly materially, from those in the forward-looking statements. In some cases you can identify forward-looking statements by words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “plan,” “intend,” “may,” “should,” “will” and “would” or other similar words. You should read statements that contain these words carefully because they discuss our future expectations, contain projections of our future results of operations or of our financial position or state other “forward-looking” information. We believe that it is important to communicate our future expectations to our investors. There may, however, be events in the future that we are not able to accurately predict or control. These forward-looking statements are subject to a number of risks, uncertainties and assumptions, including those listed under Item 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2006.

We undertake no obligation to update publicly or revise any forward-looking statements. You should not rely upon forward-looking statements as predictions of future events or performance. We cannot assure you that the events and circumstances reflected in the forward-looking statements will be achieved or occur. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements.

You should read the following discussion in conjunction with the consolidated financial statements and related notes in Item 1 and our Annual Report on Form 10-K for the year ended December 31, 2006.

General Overview

We are an independent energy company engaged in the acquisition, exploitation, development and production of natural gas and oil. In addition, we provide gas gathering, processing and compression services for properties we operate and for third-party producers. We were initially formed under the name “PRB Transportation, Inc.” in December 2003 and were incorporated in the State of Nevada. On June 14, 2006, our name was changed to “PRB Energy, Inc.”  We conduct our primary business activities in Wyoming, Colorado and Nebraska.  We operate through two wholly-owned subsidiaries:  PRB Oil and Gas, Inc., an oil and gas exploitation and production company and PRB Gathering, Inc., a gathering and processing company.

Three and Nine Months Ended September 30, 2007 - Operational and Financial Highlights

For the first nine months of 2007, we had a net loss of $13.4 million, 46% of which was due to interest expense and amortized costs related to the debt incurred in 2006. This debt is comprised of the senior subordinated convertible notes (the “Notes”) and the senior secured debentures (the “Debentures”). The components of these expenses consisted of the following:

The balance of the net loss for the nine months ended September 30, 2007 was primarily due to recognizing amortization of leasehold costs related to producing properties and the incurrence of infrastructure costs necessary to build operational and administrative capability enabling our growth initiatives. Additionally, we experienced severe winter weather conditions and other mechanical inefficiencies inhibiting our production capabilities in the first quarter of 2007. Our revenue stream has also been negatively impacted throughout the first nine months of the year as a result of downward pressure on our realized natural gas sales prices stemming from regional constraints in moving and selling our natural gas production into higher demand markets. However, we expect a significant improvement in natural gas prices with the opening of the Rocky Mountain Express pipeline scheduled for completion in late 2007 or early 2008. With greater access to mid-west markets facilitated via this pipeline, we expect prices on Rockies-area production to be much more competitive as measured against other major producing regions.

A primary focus of our oil and gas exploitation and production segment for the first nine months of 2007 centered on dewatering the Wyoming coal-bed methane (“CBM”) wells to enable production of the underlying gas reserves. As of September 30, 2007, we had 58 gross (54 net) CBM wells in the dewatering stage. Also in Wyoming, we had 113 gross (103 net) CBM wells

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producing commercial gas from which we sold a net 243,000 thousand cubic feet (“Mcf”) of gas, resulting in sales revenue of $792,000 for the nine months ended September 30, 2007. For the comparable nine month period of 2006, we sold 188,000 Mcf of gas resulting in revenues $882,000. The Wyoming well count was down from previous quarters due to uneconomic production wells being shut-in or plugged.

During the third quarter of 2007, we drilled an additional 11 wells (7 wells producing in the third quarter) in continuation of our Colorado Niobrara exploitation program. As of quarter end, we had 17 gross/net wells in production. From our Colorado operations, we sold 93,000 Mcf of gas resulting in sales revenue of $354,000 for the nine months ended September 30, 2007. We had no comparable sales for 2006 as our Colorado operations were not acquired until December 28, 2006.

Our gas gathering and processing segment operations generated revenues of $1,125,000 (net of affiliated revenue) for the first nine months of 2007. We continue to operate our gas gathering systems for the benefit of third-party producers in addition to transporting affiliated segment production.

In the second quarter of 2007, we reached a settlement with Rocky Mountain Gas Inc. (“RMG”) in lieu of arbitration, wherein we agreed to transfer our interest in certain well and leasehold assets to RMG in exchange for RMG’s interest in specific wells and a commitment to pay us $3,250,000 plus interest at 10%. During the second quarter of 2007, RMG paid us $1,000,000 according to schedule, and on June 1, 2007, RMG issued a promissory note due October 31, 2007 to us for the remaining $2,250,000 plus interest. On October 31, 2007 RMG paid us $850,000 and issued a revised promissory note to us to pay the remaining $1,400,000 plus interest in installments over a four month period beginning November 30, 2007.

We will recognize a total reported gain from this settlement of $1,267,000 over the second quarter of 2007 through the first quarter of 2008. As cash is received, a proportionate amount of the total gain will be recognized in the financial statements. The portion of the gain from this settlement that is reflected for the first nine months of 2007 is $344,000.

Results of Operations

Three months ended September 30, 2007 (unaudited) compared to the three months ended September 30, 2006 (unaudited)

 The financial information with respect to the three months ended September 30, 2007 and 2006, which is discussed below, is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals, necessary for a fair presentation of the results for such periods. The results of operations for interim periods are not necessarily indicative of the results of operations for the full fiscal year.

*—Percentages greater than 200% and comparisons from positive to negative values are not shown.

Revenues

Natural gas sales for the 2007 third quarter were 50% less in comparison to 2006 due to a combination of unfavorable price and volume variances. The average sales price during the 2007 quarter was $2.10 per Mcf lower than the average sales price for the prior year period ($2.52 for 2007 compared to $4.62 for 2006) resulting in a revenue decline of $322,000. Sales volumes were also lower in 2007 by 14,423 Mcf causing a revenue decline of $67,000 based on third quarter average pricing. Sales volumes decreased primarily as a result of the shut-in or plugging of uneconomic wells within our Wyoming production. Gas gathering revenues for the third quarter of 2007 were lower by $61,000, or 19%, compared to the third quarter of 2006 mainly as a result of decreased throughput volumes as third party shippers reduced production in response to sales price declines.

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Natural Gas Lease Operating Expenses

Natural gas lease operating expenses in 2007 decreased $307,000, or 53%, from 2006 as a result of significant field operations expenditures incurred in the 2006 third quarter in conjunction with the mid-year 2006 Pennaco acquisition.  Similar levels of operations expenditures have not been experienced in 2007 due to cost control initiatives combined with a reduction in production volumes.

Gas Gathering and Processing Operations Expenses

Gas gathering and processing operations expenses increased $127,000, or 38%, for the current quarter compared to last year’s quarter primarily due to maintenance expenses incurred in preparation for winter operating conditions. In 2006, we did not undertake our winterizing preparations until the fourth quarter.

Depreciation, depletion, amortization and impairments (“DD&A”)

DD&A expense for the quarter ending September 30, 2007 increased $651,000, or 86%, compared to last year’s third quarter resulting from the acquisition of additional properties in mid and late 2006.

General and Administrative Expenses

General and administrative (“G&A”) expenses were higher than 2006 by $443,000, or 45%, primarily due to employee compensation and benefits increasing as a result of employees added in response to an increase in operations. We do not anticipate significant G&A expense escalations in the near-term quarters as we believe current staff levels are sufficient to manage our ongoing operations.

Interest and Other Income and Expense

Interest expense for the quarter ended September 30, 2007 increased $1,526,000 over the 2006 quarter due to (1) interest payments on Debentures, (2) amortization of the debt issuance costs and the discount on Debentures and (3) interest on a compressor capital lease. Interest income on cash deposits and notes receivable was lower in the 2007 third quarter by $114,000 and other income was also lower due to the 2006 third quarter recognition of a gain of $308,000 on the sale of gathering assets.

Nine months ended September 30, 2007 (unaudited) compared to the nine months ended September 30, 2006 (unaudited)

 The financial information with respect to the nine months ended September 30, 2007 and 2006, which is discussed below, is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals, necessary for a fair presentation of the results for such periods. The results of operations for interim periods are not necessarily indicative of the results of operations for the full fiscal year.

*—Percentages greater than 200% and comparisons from positive to negative values are not shown.

Revenues

Total revenues decreased $332,000, or 13%, for the nine months ended September 30, 2007 compared to last year’s results. The $264,000 increase in natural gas sales generated from the Pennaco properties acquired in mid 2006 was more than offset by the $467,000 reduction in fees previously received from Pennaco for gathering Pennaco’s production volumes prior to PRB’s acquisition of the

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production assets. Other revenue declined $129,000 due to the discontinuance of management fees recorded in 2006 related to services provided to RMG that ended in conjunction with the RMG settlement.

Natural Gas Lease Operating Expenses

Natural gas lease operating expenses in 2007 increased $754,000, or 102%, over 2006 as a result of the Pennaco field operations acquired in mid 2006.  We substantially increased field operations over the same period last year as a result of the Pennaco (Wyoming) and D-J Basin (Colorado/Nebraska) acquisitions.

Gas Gathering and Processing Operations Expenses

Gas gathering and processing operations expenses decreased $76,000, or 5%, for the nine months ended September 30, 2007 compared to last year’s results primarily due to the reduced use of third-party services resulting from our cost control initiatives, partially offset by maintenance expenses in preparation for winter operating conditions.

Depreciation, depletion, amortization and impairments (“DD&A”)

DD&A expense in 2007 increased $1,800,000, or 127%, as a result of properties acquired in mid and late 2006.

General and Administrative Expenses

General and administrative expenses increased over 2006 by $1,091,000, or 35%, primarily due to employee compensation and benefits increasing as a result of employees added in response to an increase in operations, partially offset by recovery of $200,000 in administrative services expenses provided to a third party in the design and engineering of a processing plant.

Interest and Other Income and Expense

Interest expense for the nine months ending September 30, 2007 increased $4,512,000 over 2006 due to (1) interest payments on the Notes and Debentures, (2) amortization of the debt issuance costs and the discount on Debentures and (3) interest on a  compressor capital lease. The interest expense increase was partially offset by a $344,000 gain on the sale of the RMG assets less a loss of approximately $100,000 on the sale of other gathering assets.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

At September 30, 2007, cash and cash equivalents totaled $2.4 million. Additionally, we have $1.0 million of restricted cash classified as a current asset which collateralizes a reducing letter of credit issued in connection with potential plugging liabilities of Wyoming properties acquired in June 2006. The restricted cash will be released on or before July 29, 2008. At September 30, 2007, working capital, excluding the restricted cash, was $(36.4) million. The significant decrease in working capital from previous quarters is due to the reclassification of $35.8 million attributed to the Notes and Debentures due in the third quarter of 2008, from non-current to current liabilities.

In 2006, we raised approximately $22 million by issuing the Notes and $15 million, before expenses, by issuing the Debentures. These funds have been utilized in the exploitation, development and acquisition of properties in Wyoming and Colorado. Current levels of cash flows from ongoing operations will be insufficient to meet our repayment obligations on these borrowings when due in the third quarter of 2008. We are actively pursuing supplemental capital raising alternatives, including asset sales, to fund our ongoing debt services and working capital requirements as well as to provide for the further development of our producing assets. Regarding potential asset sales, we have received and are currently evaluating multiple bids for various components of both our natural gas production and gathering assets. While we have initiated actions to immediately resolve the unfavorable working capital position, we cannot assure that we will be able to raise additional capital or obtain financing on acceptable terms, or at all, before such capital or financing will be required.

As noted in our risk factors (See Item 1A of our 2006 Annual Report on Form 10-K and Part II, Item 1A of this Quarterly Report on Form 10-Q), cash and cash equivalents on hand, internally generated cash flows and future financing activities will require augmentation from bank financing, asset sales or other equity or debt financing to fund our debt service, working capital requirements, planned drilling, potential acquisition and other capital expenditures in the future. The amount and allocation of future capital and exploitation expenditures will depend upon a number of factors including the number and size of acquisitions and drilling opportunities, our cash flows from operating and financing activities and our ability to assimilate acquisitions. Also, the impact of oil and gas market prices on investment opportunities, the availability of capital and borrowing facilities and the success of our exploitation and development activities, particularly in Colorado, could lead to changes in funding requirements for future development. If we failed to secure financing for the future development, we would pursue other financial arrangements through joint venture partners, farm-out agreements or the sale of assets.

Cash Flow Used in Operating Activities

During the nine months ended September 30, 2007, our net loss of $13.4 million included non-cash charges of $3.2 million of DD&A expense, $2.4 million of interest expense resulting from amortization of debt issuance costs and discount on the Debentures and $0.5 million of share-based compensation expense.

Cash used in operating activities of $6.1 million during the nine months of 2007 was $3.1 million more than the same period of 2006. The increase was mainly attributable to the higher debt interest payments and increased general and administrative expenses due to staff additions offset by a partial collection of outstanding receivables.

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Cash Flow Used in Investing Activities

Cash used in investing activities was $3.5 million during the nine months ended September 30, 2007 representing a $8.6 million, or 71%, decrease compared to 2006.  The reduction in cash outflows was attributed to the 2006 asset acquisitions of $4.9 million in addition to the availability of $3.0 million cash that had been restricted in 2006. We used $5.0 million of the available cash for capital expenditures related to our drilling and gathering activities in 2007, which was approximately $0.6 million higher than was spent during the comparable 2006 nine-month period. This was offset by $2.1 million release of a restricted CD during the quarter for expiring liabilities related to acquired properties.

Particular to our gas exploitation and production segment, our 2007 capital expenditures of approximately $3.5 million were used for our drilling program in the northeastern Colorado D-J Basin in addition to our de-watering efforts relative to the Wyoming coal-bed methane (“CBM”) wells. At September 30, 2007, we had 17 gross/net wells completed and in production in Colorado and 58 gross (54 net) CBM wells in various stages of completion in Wyoming.  These wells are being completed or are undergoing de-watering processes.  We believe that after the wells have been de-watered, we will be able to commence production.

In the first quarter of 2007, we entered into a $3.1 million five-year capital lease arrangement for gas compression equipment and related services. The compression equipment is servicing our gas gathering pipelines in the Powder River Basin.

Cash Flow from Financing Activities

Cash provided by financing activities was approximately $0.8 million for the nine months ended September 30, 2007, or a reduction of $20 million from 2006.  During the first quarter of 2006, we raised $22.0 million from the issuance of Notes and incurred approximately $1.1 million in debt issuance costs, excluding the value of warrants issued.  The 2007 financings included the RMG settlement proceeds received of $1.0 million, offset by additional Debenture costs totaling $0.2 million.

Off Balance-Sheet Arrangements

We do not have any off-balance sheet financing arrangements as of September 30, 2007. Previous quarterly reports had disclosed a gas gathering services agreement with a third-party shipper that included a minimum payment arrangement under which the shipper was obligated to pay us gas gathering fees on specific minimum volumes of gas. During the third quarter of 2007, that agreement was rescinded and replaced with a straight gathering services contract with renegotiated gathering rates per volume transported.

Critical Accounting Policies and Estimates

We refer you to the corresponding section in Part II, Item 7 of our 2006 Annual Report on Form 10-K and to the footnote disclosures included in Part I, Item 1 of this report.

ITEM 3:    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes in market risk from the information provided under “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2006.

ITEM 4:    CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures as defined in Section 13 a - 15 (e) and 15 d - 15 (e) of the Securities Exchange Act of 1934, which are designed to provide reasonable assurance that information required to be disclosed in our reports is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Principal Financial Officer to allow timely decisions regarding required disclosure. Our management, with the participation and oversight of our Chief Executive Officer and Principal Financial Officer, evaluated the design and effectiveness of our disclosure controls and procedures as of September 30, 2007. Based on this evaluation, our Chief Executive Officer and our Principal Financial Officer have concluded that our disclosure controls and procedures were effective, as of September 30, 2007.

During the period covered by this report, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II OTHER INFORMATION

ITEM 1:    LEGAL PROCEEDINGS

Rocky Mountain Gas Inc. (“RMG”) filed an arbitration demand against us in 2006.  (Refer to Part I, Item 3 in our 2006 Annual Report on Form 10-K regarding the Rocky Mountain Gas Agreement and Claims Dispute.)

In the quarter ended June 30, 2007, we reached a settlement with RMG, wherein we agreed to transfer our interest in certain well and leasehold assets to RMG in exchange for RMG’s interest in specific wells and a commitment to pay us $3,250,000 plus interest at a rate of 10%. During the quarter ended June 30, 2007, RMG paid us $1,000,000 according to schedule and issued a promissory note to us for the remaining $2,250,000 plus interest which was due on October 31, 2007. On October 31, 2007 RMG paid us $850,000 and issued a revised promissory note to us for the remaining $1,400,000 plus interest in installments over a four month period beginning November 30, 2007.

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ITEM 1A. RISK FACTORS

For information regarding additional factors that could affect our results of operations, financial condition and liquidity, see the risk factors discussion provided under Item 1A of our 2006 Annual Report on Form 10-K. Other than as provided below, there are no material changes from the risk factors discussed in our 2006 Annual Report on Form 10-K. See also “Forward-Looking Statements” included in Part I, Item 2 of this Quarterly Report on Form 10-Q.

Our debt level could negatively impact our financial condition, results of operations and business prospects.

     Our high level of debt could have important consequences to our shareholders, including the following:

     If we are not be able to generate sufficient cash flow to pay our debt service, equity financings or proceeds from the sale of assets may not be available to pay or refinance the amounts owed. We may not be able to successfully complete any such offering or sale of assets. Our debt is collateralized by substantially all of our assets. If we default on our debt payments, the holders of our debt could foreclose on such assets or we could be forced into bankruptcy.

Our development operations and our debt payments require substantial capital and we may be unable to make such debt payments or obtain additional needed capital or financing on satisfactory terms.

     The oil and natural gas industry is capital intensive.  We make and expect to continue to make substantial capital expenditures in our business and operations for development, production and acquisition of oil and natural gas reserves.  To date, we have financed capital expenditures primarily with proceeds from the issuance of debt and equity plus cash generated by operations.  We intend to finance our future capital expenditures with cash flow from operations, sale of properties and our access to other capital.  Our cash flow from operations and access to capital are subject to a number of variables, including:

If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, then we may have limited ability to obtain the capital necessary to sustain our operations at current levels.  We may, from time to time, need to seek additional financing.  There can be no assurance as to the availability or terms of any additional financing.

ITEM 6:    EXHIBITS