UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q/A

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2005

Commission file number 333-120129

PRB GAS TRANSPORTATION, INC.

(Exact name of registrant as specified in its charter)

1875 Lawrence Street, Suite 450, Denver, Colorado 80202

(Address of principal executive offices) (Zip Code)

(303) 308-1330

(Registrant’s telephone number, including area code)

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 o    No ý

Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Exchange Act). Yes o    No ý

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

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

As of November 11, 2005, the registrant had 7,422,094 shares of common stock outstanding.

PRB GAS TRANSPORTATION, INC.

INDEX

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

This Form 10-Q/A for the quarterly period ended September 30, 2005 is being filed for the purpose of restating PRB Gas Transportation, Inc.’s. unaudited financial statements as of and for the three and nine months ended September 30, 2005. The Company acquired a contract effective August 2004.  During June 2005 the Company determined that it had incorrectly invoiced this customer for the period August 2004 through April 2005.  The original invoices for this period did not take into account that the agreement includes a minimum contract billing provision.  The Company invoiced the customer for the difference between the original invoices and the corrected invoices in June 2005.  The Company was not able to determine whether the customer would pay the difference due and as such did not restate its financial statements until collection was assured. The customer paid the Company for the difference due (approximately $304 thousand) during December 2005, including approximately $0 thousand and $63 thousand in respect to the three months and six months ended September 30, 2005, respectively. Accordingly, the Company has restated its financial statements.

Conforming changes have been made to the notes to the financial statements and management’s discussion and analysis of financial condition and results of operations included in the following 10-Q/A. See Note 3 in the notes to the unaudited financial statements for further information on this restatement. This Form 10-Q/A has not been updated for events or information subsequent to the filing of the original Form 10-Q except in relation to the foregoing. Accordingly, this Form 10-Q/A should be read in conjunction with the Company’s filings made with the SEC subsequent to the filing of the original Form 10-Q.

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PRB Gas Transportation, Inc.

Balance Sheets

In thousands except share amounts

* amounts less than one thousand

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

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PRB Gas Transportation, Inc.

Statements of Operations

(Unaudited)

In thousands except share amounts

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

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PRB Gas Transportation, Inc.

Statement of Changes in Stockholders’ Equity

(Unaudited)

In thousands except share amounts

* amount less than one thousand

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

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PRB Gas Transportation, Inc.

Statements of Cash Flows

(Unaudited)

In thousands except share amounts

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

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PRB GAS TRANSPORTATION, INC.

Notes to Unaudited Financial Statements

September 30, 2005

Note 1—Description of Business and Basis of Presentation

Description of Business

PRB Gas Transportation, Inc. (the “Company” or “PRB”) was incorporated in December 2003. The Company was capitalized and commenced operations in January 2004 when the Company acquired certain gas gathering and related assets of TOP Gathering, LLC (“TOP”). In August 2004, the Company acquired certain gas gathering and related assets of Bear Paw Energy, LLC (“BPE”). Both the TOP and BPE systems are located in the Powder River basin of Wyoming. During September 2005 the Company entered into a Farm-In and Development Agreement (“FDA”) and a Management Services Agreement (“MSA”) with Enterra Energy Trust and its wholly-owned subsidiary Rocky Mountain Gas (“RMG”). The FDA establishes an area of mutual interest (“AMI”) in the states of Montana and Wyoming. The FDA provides the Company with the opportunity to earn up to 50% of RMG’s interest in its undeveloped leaseholds in the AMI by spending up to $21.8 million in development and acquisition activities in the AMI. The Company plans to develop the undeveloped leaseholds located in the AMI through September 1, 2007, the termination date of the agreement, subject to its financing plans. The terms of the FDA allow the Company to earn a pro rata percentage of RMG’s undeveloped leasehold interests in the AMI on a sliding scale basis. Under the terms of the MSA the Company provides management services to RMG on a cost-plus 15% basis. Management services include accounting and administration, technical support as well as operating coal bed methane wells. The term of the MSA is through August 1, 2007. The MSA is cancelable by either party with notice and includes a two-year renewal if not earlier terminated. During the third quarter of 2005 the Company expanded its scope of operations to include exploring for, developing, producing, marketing, gathering and transporting natural gas as well as operating coal bed methane properties and providing management services as contract operator.

Restatement

 During June 2005 the Company determined that it had incorrectly invoiced a customer for the period August 2004 through April 2005.  The Company invoiced the customer in June 2005 for the difference between the original invoices and the corrected invoices, approximately $304 thousand.  The customer paid the Company the difference due in December 2005.  For further information on this restatement see Note 3 – Restatement of Results.

Basis of Presentation

The accompanying unaudited interim financial statements have been prepared by the Company in accordance with accounting principles generally accepted in the United States of America for interim financial information and, pursuant to the rules and regulations of the Securities and Exchange Commission, do not include all the information and footnotes required by accounting principles generally accepted in the United States of America for complete financial statements. In the opinion of management, these interim financial statements contain all adjustments, consisting of only normal recurring adjustments, necessary to present fairly the financial position of PRB as of September 30, 2005 and the results of its operations and cash flows for the three months and nine months ended September 30, 2005 and 2004. These financial statements should be read in conjunction with the audited financial statements and the summary of significant accounting policies and notes thereto included in the Company’s Registration Statement on Form S-1 dated April 12, 2005. The results of operations and cash flows for the period are not necessarily indicative of the results of operations or cash flows that can be expected for the year ending December 31, 2005.

During the third quarter of 2005 the Company invested in oil and gas undeveloped leaseholds and coal bed methane wells under the FDA discussed above. As such the Company now operates in two segments. However, as the Company’s oil and gas activities for the period ended September 30, 2005 did not include selling oil or gas the Company has not presented segment information for its oil and gas activities in this report.

Certain prior period amounts have been reclassified to conform to the current financial statement presentation.

Note 2—Summary of Significant Accounting Policies

Oil and Gas Producing Activities

The Company has elected to follow the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred. If an exploratory well does not find proved reserves, the costs of drilling the unsuccessful exploratory well are charged to expense. Exploratory dry hole costs are included in cash flows from investing activities as part of capital expenditures in the consolidated statements of cash flows. The costs of development wells, whether productive or not, are capitalized. Geological and geophysical costs and the costs of carrying and retaining unproved properties are expensed as incurred. Depletion, depreciation and amortization (“DD&A”) of capitalized costs of proved oil and gas properties is determined on a field-by-field basis using the units of production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement and abandonment costs and the anticipated proceeds from equipment salvage. The Company has adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations,” which provides guidance on accounting for dismantlement and abandonment costs (see Note 7—Asset Retirement Obligations).

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Revenue Recognition

The Company recognizes gas gathering and management services revenue at the time when the service is rendered.

Impairment of Long-Lived Assets

The Company reviews its long-lived assets and other intangible assets with long lives for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered. An impairment loss is recognized only if the carrying value of the asset is not recoverable and exceeds its market value. The Company estimates market value of long-lived assets using expected future discounted cash flows. See Note 4—Property, Equipment and Contracts in respect to the impairment recorded during the third quarter of 2005.

Stock Based Compensation

As permitted under SFAS No. 123,”Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, the Company accounts for its stock-based compensation for options issued to employees in accordance with the provisions of Accounting Principles Board Opinion No. 25,”Accounting for Stock Issued to Employees” (“APB 25”). As such, the Company accounts for its employee stock-based compensation arrangements using the intrinsic value method under which compensation expense related to employee stock grants is recorded if the fair value of the underlying stock exceeds the exercise price on the grant date. Certain pro forma net loss and loss per share disclosures for employee stock option grants are reflected below as if the fair value method as defined in SFAS No. 123 had been applied. Transactions in equity instruments with non-employees for goods or services are accounted for using the fair value method. Had compensation cost for the options issued under the PRB Transportation, Inc. Equity Compensation Plan been determined based upon the fair value at the grant date for options granted, consistent with the provisions of SFAS No. 123, the Company’s net loss and net loss per share for the three months and nine months ended September 30, 2005 and 2004 would have been increased to the pro forma amounts indicated below:

The following table summarizes activity for options during the nine months ended September 30, 2005:

The weighted average remaining contractual life for the options outstanding at September 30, 2005 is 6.6 years. The fair value of each option granted is estimated on the date of grant using the Black Scholes option pricing model. The weighted average fair value of options outstanding at September 30, 2005 is $2.17. The weighted average fair value of options granted and exercisable at September 30, 2005 is $1.57.

Net Loss Per Share

The Company accounts 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 attributable to common shareholders by the weighted average common shares outstanding without including any potentially dilutive securities. Diluted EPS is computed by dividing the net loss for the period by the weighted average common shares outstanding plus, when their effect is dilutive, common stock equivalents.

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Potentially dilutive securities, which have been excluded from the determination of diluted earnings per share because their effect would be anti-dilutive, are as follows:

Recent Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123R (revised 2004), “Share-Based Payment”. SFAS No. 123R replaced SFAS No. 123 and superseded APB 25. SFAS No. 123R will require compensation cost related to share-based payment transactions to be recognized in financial statements. As permitted by SFAS No. 123, the Company elected to follow the guidance of APB 25, which allowed companies to use the intrinsic value method of accounting to value their share-based payment transactions with employees. Based on this method, the Company did not recognize compensation expense in its financial statements as the stock options granted had an exercise price equal to the fair market value of the underlying common stock on the date of the grant. SFAS No. 123R requires measurement of the cost of share-based payment transactions to employees at the fair value of the award on the grant date and recognition of expense over the requisite service or vesting period. SFAS No. 123R requires implementation using a modified version of prospective application, under which compensation expense for the unvested portion of previously granted awards and all new awards will be recognized on or after the date of adoption. SFAS No. 123R also allows companies to adopt SFAS No. 123R by restating previously issued financial statements, basing the amounts on the expense previously calculated and reported in their pro forma footnote disclosures required under SFAS No. 123. The Company has not decided which adoption method will be used. The provisions of SFAS No. 123R will be adopted by the Company effective January 1, 2006. The effect of the adoption of SFAS No. 123R is expected to be comparable to that disclosed on a pro forma basis as a result of applying the current fair value recognition provisions of SFAS No. 123.

In March 2005, the SEC issued Staff Accounting Bulletin (SAB) No. 107 which expressed the views of the SEC regarding the interaction between SFAS No. 123R and certain SEC rules and regulations. SAB No. 107 provides guidance related to the valuation of share-based payment arrangements for public companies, including assumptions such as expected volatility and expected term. In April 2005, the SEC approved a rule that delayed the effective date of SFAS No. 123R for public companies. As a result, SFAS No. 123R will be effective for PRB on January 1, 2006.

In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets—An Amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions” “SFAS153”. SFAS No. 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets in paragraph 21(b) of APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” and replaces it with an exception for exchanges that do not have commercial substance. SFAS No. 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS No. 153 is effective for the fiscal periods beginning after June 15, 2005. The Company is currently evaluating the effect that the adoption of SFAS No. 153 will have on consolidated results of operations and financial condition but does not expect that it will have a material impact the adoption of SFAS No. 153 will have on consolidated results of operations and financial condition but does not expect that it will have a material impact.

Note 3—Restatement of Results

The Company acquired a contract effective August 2004.  During June 2005 the Company determined that it had incorrectly invoiced this customer for the period August 2004 through April 2005.  The original invoices for this period did not take into account that the agreement includes a minimum contract billing provision.  The Company invoiced the customer for the difference between the original invoices and the corrected invoices in June 2005.  As the Company was not able to determine if the $304 thousand that was invoiced to the customer during June 2005 was going to be paid or was collectible, the Company had not previously recognized the $304 thousand as revenue. The customer paid the Company for the difference due (approximately $304 thousand) during December 2005, including approximately $0 thousand and $142 thousand in respect to the three months and nine months ended September 30, 2005, respectively. The payment of $304 thousand included approximately $63 thousand thousand and $162 thousand in respect to the three months and nine months and year ending September 30, 2004 and December 31, 2004, respectively. Accordingly, the Company has restated its financial statements as summarized below.

The effect of this restatement on the Company’s previously issued Statement of Operations, Balance Sheets, Statements of Cash Flows and Stockholder’s Equity is as follows:

Other line items in these statements such as operating income, current assets, etc. have been restated similarly.  The aforementioned restatement adjustments do not affect total cash flows used in by operating activities, net cash used in investing activities and net cash provided by financing activities, although certain components of cash flows provided by operating activities have been restated.

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Note 4—Property, Equipment and Contracts

Property and equipment consists of the following as of September 30, 2005 and December 31, 2004:

The Company’s gas plant in progress represents engineering services relative to a gas plant that the Company plans to build and install during the first half of 2006. The total cost of this plant is currently estimated at $1.1 million.

The Company’s compressor sites, pipelines, equipment and gas plant in progress are in respect to gas gathering operations. The Company reviewed the carrying value of the TOP system as associated revenue had declined as a result of decreasing producer volumes as well as a lost customer. Based on this review the Company recorded an asset impairment charge of $2.372 million relative to the TOP gas gathering system, during September 2005. The impairment charge included $1.53 million for property and equipment and $842 thousand for contracts. Management estimated the systems fair market value and recorded the impairment charge accordingly as follows. The TOP contracts were impaired in full as described below. The Company’s management determined that it would pursue a sale of the TOP assets (see Note 11—Subsequent Events). In determining expected future cash flows for its fair market value calculation, management assigned probabilities to its estimates of such proceeds and exit costs. Management based its estimate of the TOP system fair market value using a weighted average of the estimated sale proceeds and exit costs determined using the probabilities assigned. The estimated fair market value represents management’s best estimates, and may change in the future.

In accordance with SFAS No. 144 the estimated fair value of the assets becomes the new basis for the assets, and as such accumulated depreciation and amortization of $581 thousand related to these assets, including contracts, was eliminated in connection with our accounting for this impairment. The effect of the impairment charge reduces future period annual depreciation and amortization expense by approximately $205 thousand annually, starting in the fourth quarter of 2005. Future period depreciation is being determined based on a four-year life. Previously a ten-year life was used to calculate the TOP system’s depreciation expense. The Company will assess the affect of the TOP system impairment on its asset retirement obligation accretion expense on a going forward basis.

Depreciation expense in respect to property and equipment totaled $222 thousand and $164 thousand for the three months ended September 30, 2005 and 2004, respectively, and $661 thousand and $278 thousand for the nine months ended September 30, 2005 and 2004, respectively.

Contracts valued at $1.28 million, in respect to the BPE assets, are being amortized over 10 years which is the estimated life of the contracts and the fields underlying the contracts. Amortization expense related to these contracts was $58 thousand and $47 thousand for the three months ended September 30, 2005 and 2004, respectively, and $173 thousand and $98 thousand for the nine months ended September 30, 2005 and 2004, respectively. The TOP system contracts with the producers were impaired in full as management estimated that their current value was not significant.

Note 5—Oil and Gas Properties

Undeveloped leaseholds represents leasehold interests in the Castle Rock area of Montana. The Castle Rock area is operated by Powder River Gas, LLC.

Wells in progress represents the costs of drilling coal bed methane gas wells incurred through September 30, 2005. As of September 30, 2005 the Company was in the process of completing and or evaluating these wells. See Note 11—Subsequent Events.

These expenditures were made as part of the FDA as described in Note 1—Description of Business.

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Note 6—Other Non-Current Assets—Deposits

Other non-current assets—deposits primarily represents cash advances made to the operator of the Castle Rock project located in Montana, Powder River Gas, LLC, that had not been spent by the operator as of September 30, 2005. These amounts will be used by the operator relative to joint operations (drilling and or continuing to drill coal bed methane wells and leasehold extension activities) in the upcoming months.

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Note 7—Asset Retirement Obligations

Property and equipment includes platforms to hold the leased compressors at the Company’s TOP gas gathering facilities. The Company is required to dismantle these compressor platforms at the end of their useful lives. In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” the Company recognized the fair value of a liability for an asset retirement obligation (“ARO”) in the amount of $60 thousand. The Company capitalized that cost as a part of the carrying value of the compressor site which is depreciated over the estimated life of the compressors’ use. See Note 4—Property, Equipment and Contracts for discussion of the impairment of the TOP assets. The following table describes all changes to the Company’s asset retirement obligation liability during the three months and nine months ended September 30, 2005 and 2004:

The Company has not yet recorded an asset retirement obligation relating to obligations under certain of the surface use agreements purchased from BPE because a reasonable estimate of the useful lives of the fair market value of the liability cannot currently be made. The Company will continue periodically review available information and will record an ARO in the period that a reasonable estimate of the fair market value of the liability can be made.

The Company has not yet recorded an asset retirement liability relating to wells in progress as current estimates prepared by management are not significant. Management will continue to assess the liability associated with its wells in progress and for wells it completes in future periods and will record the related asset retirement obligations accordingly.

Note 8—Income Taxes

The Company has not recorded an income tax benefit for the current period as realization of the benefit is not expected to be likely during the year. The benefit is also not expected to be realizable as a deferred tax asset at year end as the Company anticipates recording a full valuation allowance for all deferred tax assets, except to the extent of offsetting reversals of expected deferred tax liabilities.

Note 9—Commitments and Contingencies

Possible Rescission of Series C Convertible Preferred Stock Sale

In December 2004, the Company received $1.233 million from the sale of 411,000 shares of Series C Convertible Preferred stock. The Company paid no cash or other commissions or finders’ fees in connection with this offering. In the view of the Securities and Exchange Commission, this placement might not have been eligible for an exemption from registration under the Securities Act of 1933. In the absence of such an exemption, investors could bring suit against the Company to rescind their stock purchases, in which event the Company could be liable for rescission payments to these investors of up to $1.233 million exclusive of interest and costs. In August 2005, the Company filed a registration statement on Form S-1 to register the underlying shares of common stock issuable upon conversion of the Series C Convertible Preferred Stock. The SEC declared the S-1 effective on August 16, 2005. As of September 30, 2005, 330,200 Series C Convertible Preferred shares had been converted to common shares and 80,800 shares remained outstanding.

Bank Loan

At March 31, 2005, the Company had a note payable to the Bank of Oklahoma under a line of credit in the amount of $1.5 million. Interest was payable monthly at a fluctuating interest rate at the JPMorgan Chase Bank prime rate per annum. The annual interest rate was 5.75% at March 31, 2005.

This bank line of credit matured the earlier of May 31, 2005 or within three days following the funding of the initial public offering and was secured by all of the Company’s gathering assets and a pledge of a $1.0 million certificate of deposit by a preferred stockholder. In consideration for this $1.0 million pledge, the Company agreed to pay the preferred stockholder a monthly fee of 0.529% until the bank line of credit was retired and the pledge was released. In April 2005, the Company drew down an additional $50 thousand on the line of credit.

Following the payment of the bank line of credit in full in April 2005, the bank released their security interest in the gathering assets and the $1.0 million certificate of deposit pledged by the preferred stockholder.

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Note 10—Stockholders’ Equity

Initial Public Offering

On April 12, 2005, the Company’s registration statement on Form S-1 was declared effective by the Securities and Exchange Commission and the Company’s stock began trading on the American Stock Exchange under the trading symbol PRB. The Company sold 2,300,000 shares of common stock, including 300,000 shares pursuant to the underwriter’s exercise of its over-allotment option. In conjunction with the offering, holders of Series A and Series B preferred stock converted their shares into an equal number of registered common shares. The Company recorded proceeds of $10.169 million net of underwriter’s discounts, commissions and expenses, including warrants valued at $583 thousand.

The Company entered into an underwriting agreement on April 12, 2005. The agreement called for the underwriter to purchase the shares on a firm commitment basis at an 8% discount to the offering price. The Company’s underwriter also received a 3% non-accountable expense allowance of the aggregate offering price of the shares offered, excluding the 300,000 over-allotment shares. At the closing of the underwriting, the Company sold warrants to the underwriter to purchase 200,000 shares of common stock at a price of $0.0001 per warrant. The warrants have an exercise price of $6.875 (125% of the initial offering price) and are exercisable for four years from the first anniversary of their issuance.

Series C Preferred Stock

In December 2004, the Company issued 411,000 shares of the convertible preferred series C shares at a price of $3.00 per share resulting in proceeds of approximately $1.231 million, net of offering costs of approximately $2 thousand. See Note 9—Commitments and Contingencies for further discussion on the convertible preferred series C shares.

Dividends

Both the Convertible Preferred Series A and Series B shares included dividend rights that stated that dividends would accrue from the date of issuance until the date paid, whether or not earned or declared. All of the Series A and B preferred shareholders converted to common shares during April 2005, and all of the related dividends were paid through the date of conversion.

Note 11—Subsequent Events

During October 2005, the Company commenced producing and marketing natural gas from wells it had drilled or completed in the Powder River Basin area of Wyoming.

On October 14, 2005 the shareholders approved an amendment to Article Sixth of the Company’s By-Laws, and in addition the Board appointed two new Directors, Mr. Reuben Sandler, PhD., and Mr. James P. Schadt. The Company announced in November that Ms. Marilena Marrelli resigned as a Director and that Mr. Justin W. Yorke had been appointed to its Board of Directors.

In addition, the Company announced in November that it plans to dispose of its TOP gas gathering system, and that it is installing a gas gathering system in North Dakota all as discussed in Note 4—Property, Equipment and Contracts. The Company’s board has approved the sale of the TOP system that the Company plans to sell during 2006.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

This quarterly report includes forward-looking statements. All statements other than statements of historical facts contained herein, including statements regarding our future financial position, business strategy and plans and objectives of management for future operations, are forward-looking statements. The words “believe,” “may,” “will,” “estimate,” “continue,” “anticipate,” “intend,” “should,” “plan,” “expect” and similar expressions, as they relate to us, are intended to identify forward-looking statements. We have based these forward-looking statements largely on our current expectations and projections about future events and financial trends that we believe may affect our financial condition, results of operations, business strategy and financial needs. These forward-looking statements are subject to a number of risks, uncertainties and assumptions.

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 our unaudited financial statements, and the notes thereto, and other financial information appearing elsewhere in this document.

This report contains our restated unaudited financial statements for the period ending September 30, 2005.   During June 2005 we determined that we had incorrectly invoiced a customer for the period August 2004 through April 2005. This customer was acquired as part of our Bear Paw Energy, LLC (“BPE”) acquisition as described below.   The original invoices in respect to this customer for this period did not take into account that the agreement includes a minimum contract billing provision.  We invoiced this customer for the difference between the original invoices and the corrected invoices in June 2005.  As we were not able to determine if the $304 thousand that was invoiced to the customer during June 2005 was going to be paid or was collectible, we had not previously recognized the $304 thousand as revenue. The customer paid the difference due (approximately $304 thousand) during December 2005, including $0 thousand  and $142 thousand in respect to the three months and nine months  ended September, 2005, respectively. For additional information see Note 3 — Restatement of Results in Item 1 of this report.

General Overview

We own and operate natural gas gathering systems and operate gas wells in the Powder River Basin of Wyoming, and have commenced coal bed methane exploration and leasehold acquisition activities in Montana. We commenced operations in January 2004 upon our acquisition of certain gas gathering and related assets of TOP Gathering, LLC (“TOP”). In August 2004 we acquired certain gas gathering and related assets of BPE. In September 2005 we entered into a Farm-In and Development Agreement (“FDA”) as well as a Management Services Agreement (“MSA”) with Enterra Energy Trust and its wholly-owned subsidiary Rocky Mountain Gas (“RMG”). The FDA establishes an area of mutual interest (“AMI”) in the states of Montana and Wyoming. The FDA provides the Company with the opportunity to earn up to 50% of RMG’s interest in its undeveloped leaseholds in the AMI by spending up to $21.8 million in development and acquisition activities in the AMI. We plan to develop the undeveloped leaseholds located in the AMI through September 1, 2007, the termination date of the agreement, subject to its financing plans. The terms of the FDA allow us to earn a pro rata percentage of RMG’s undeveloped leasehold interests in the AMI on a sliding scale basis. Under the terms of the MSA we will provide management services to RMG on a cost-plus 15% basis. Management services include accounting and administration, technical support as well as operating coal bed methane wells. The term of the MSA is through August 1, 2007. The MSA is cancelable by either party with notice and includes a two-year renewal if not earlier terminated. During the third quarter of 2005 we expanded our scope of operations to include exploring for, developing, producing, marketing, gathering and transporting natural gas as well as operating coal bed methane properties and providing management services as contract operator.

As part of the FDA, during the third quarter of 2005 we drilled or completed 14 coal bed methane gas wells in the Powder River Basin in Wyoming. We also provided management services to RMG during this period as part of the MSA, including operating RMG’s producing properties in Wyoming.

We plan to expand and improve our present operations by:

•                enhancing the profitability of present gathering systems through system reconfiguration, improving operating efficiencies as well as through development of oil and gas leases;

•                divesting of the TOP gas gathering system during the next year;

•              designing and building new gathering systems and acquiring existing gathering systems;

•              acquiring working interests in oil and gas producing properties in areas where there are opportunities to build new gathering systems;

•                  entering the gas processing business; and

•                  continuing to evaluate, develop and exploit properties that are in the AMI with RMG as described above.

We reviewed the carrying value of the TOP system as associated revenue declined as a result of decreasing producer volumes as well as a lost customer. Based on the decline in revenue and our estimate of the systems fair market value, we recorded an impairment charge of

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$2.372 million during September 2005. Management based the impairment charge on expected future discounted cash flows assuming the system would be sold. See Note 4—Property, Equipment and Contracts in Item 1 of this report for further discussion on this matter.

We intend to sell our TOP gas gathering system during 2006. Our future operations should improve as a result of selling the TOP system assets.

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Financial Operations Overview

Revenue

Our gas gathering fees are based on contractual rates with our customers, and will vary with system throughput as well as the level of services provided and customer mix. Our gas gathering fees are not currently regulated by any governmental authority. To date, we have not taken ownership of the gas that we gather.

Our Management services fees are determined in accordance with our MSA with RMG and will vary depending on the amount of support services that are required to fulfill our obligations under this contract determined on a cost-plus 15% basis.

Operating Expenses—Gas Gathering

Operating expenses—gas gathering include compression, operating agreement expense, site supervision costs, maintenance and operating supplies, property taxes, insurance, land use and surface rights payments and contract services, all of which are relatively fixed costs. Operating expenses also include transportation fees paid to others which vary with the throughput on our gathering lines.

As of September 30, 2005 the Company had not incurred any operating expenses relative to its oil and gas operations.

Asset Impairment Charge

Asset impairment charge represents the difference between our long-lived asset carrying values and their estimated fair market value as required by SFAS No. 144. The asset impairment charge recorded during the third quarter of 2005 of $2.372 million pertains to our TOP gas gathering system (see Note 4—Property, Equipment and Contracts).

Depreciation and Amortization Expense

Depreciation expense relates to our gathering systems and other general property, plant and equipment and amortization expense relates to the customer contracts underlying the gas gathering systems, all based on their estimated useful lives.

General and Administrative Expense

General and administrative expense includes the costs of our Corporate office.

Interest Expense

At March 31, 2005, we had a note payable to the Bank of Oklahoma under a line of credit in the amount of $1.5 million. Interest was payable monthly at a fluctuating interest rate at the JPMorgan Chase Bank prime rate per annum. The annual interest rate was 5.75% at March 31, 2005. This bank line of credit matured the earlier of May 31, 2005 or within three days following the funding of the initial public offering and was secured by all of our gathering assets and a pledge of a $1.0 million certificate of deposit by a preferred stockholder. In consideration for this $1.0 million pledge, we agreed to pay the preferred stockholder a monthly fee of 0.529% until the bank line of credit was retired and the pledge was released. In April 2005, we drew down an additional $50 thousand on the line of credit.

Following the payment of the bank line of credit in full in April 2005, the bank released their security interest in the gathering assets and the $1.0 million certificate of deposit pledged by the preferred stockholder.

We intend to utilize commercial financing when available to support our acquisition and development efforts although we have no such debt at this time. Interest rate risk exists principally with respect to any future indebtedness that will likely bear interest at floating rates.

Critical Accounting Policies

Please see our Registration Statement on Form S-1 dated April 12, 2005.

In addition, during the third quarter of 2005 we adopted the Successful Efforts Method of accounting for our oil and gas activities. For additional information see the Notes to Unaudited Financial Statements in Item 1 of this report.

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Results of Operations

(unaudited)

Three Months ended September 30, 2005 compared to Three Months ended September 30, 2004

 Revenue

Gas gathering revenue of $658 thousand for the three months ended September 30, 2005 decreased by $183 thousand or 22% as compared to the three months ended September 30, 2004. The decline in revenue is attributed to decreases in the TOP system revenue of $174 thousand due to declining volumes and a decrease of $9 thousand of Bear Paw revenue. Management services revenue of $66 thousand for the three months ended September 30, 2005 represents an increase of $66 thousand as the contract in respect to the management services was not in place until the third quarter of 2005.

Operating Expenses—Gas Gathering

Operating expenses—gas gathering of $418 thousand for the three months ended September 30, 2005 increased by $9 thousand, or 2%. The increase is primarily due to the nearly offsetting effects of higher Bear Paw operating expense of $98 thousand, attributed to the timing of the Bear Paw acquisition in August 2004, and lower TOP operating expenses of $97 thousand due to cost reduction activities.

Asset Impairment Charge

We recorded an asset impairment charge of $2.372 million for the three months ended September 30 2005, and had not recorded an asset impairment charge during the three months ended September 30, 2004. The asset impairment charge is in respect to our investment in the TOP gas gathering system (see Note 4—Property, Equipment and Contracts).

Depreciation and Amortization

Depreciation and amortization of $281 thousand for the three months ended September 30, 2005 increased by $69 thousand, or 33% as compared to the three months ended September 30, 2004. This is due to increased Bear Paw depreciation and amortization expense due to the timing of the systems acquisition.

General and Administrative Expense

General and administrative expenses of $584 thousand for the three months ended September 30, 2005 increased by $361 thousand, or 162% as compared to the three month period ended September 30, 2004. The increase is attributed to higher payroll and related costs and professional fees of $232 thousand, expenses of being a publicly traded company of $43 thousand, and higher expenses for categories associated with the level of business development activities and the number of employees. The Company commenced operations during 2004 and the number of employees at our Corporate office grew from one employee in early 2004 to seven employees as of September 30, 2005. During the three months ended September 30, 2005 the Company relocated its headquarters, allowing for growth, and in addition, entered into a new replacement apartment lease for its Chief Executive Officer.

Nine Months ended September 30, 2005 compared to Nine Months ended September 30, 2004

Revenue

Gas gathering revenue of $2.214 million for the nine months ended September 30, 2005 increased $632 thousand, or 40% as compared to the nine months ended September 30, 2004. Gas gathering revenue from the Bear Paw systems of $1.852 million and $550 thousand are included in the revenue for the nine months ended September 30, 2005 and 2004, respectively. The increase in Bear Paw revenue of $1.302 million during 2005 is attributed to the timing of the acquisition of the system that occurred in August 2004. The Bear Paw revenue increase offsets the decrease of $670 thousand or 65%, for the TOP system. The TOP system revenue declines are attributed to declining gas gathering volumes as well as the loss of a customer—see discussion of asset impairment charges in Note 3 of Item 1 of this report. Management fee revenue of $66 thousand for the nine months ended September 30, 2005 represents an increase of $66 thousand compared to the nine months ended September 30, 2004, as the related management services contract was not in place until the third quarter of 2005.

Operating Expenses—Gas Gathering

Operating expenses—gas gathering of $1.293 million for the nine months ended September 30, 2005 increased by $444 thousand, or 52% compared to the nine months ended September 30, 2004. Bear Paw operating expenses of $907 thousand and $324 thousand are included in operating expenses for the nine months ended September 30, 2005 and 2004, respectively, an increase of $583 thousand or 180%. This increase is due to the timing of the Bear Paw acquisition. The decrease for this period excluding the Bear Paw expenses is $139 thousand, or 31%. This decrease is attributed to lower compressor rental expense at our TOP gas gathering system and lower Bear Paw fees to operate our Bear Paw gas gathering system.

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Asset Impairment Charge

We recorded an asset impairment charge of $2.372 million for the nine months ended September 30 2005. For the period ended September 30, 2004 we had not recorded an asset impairment charge. The asset impairment charge is in respect to our investment in the TOP gas gathering system (see Note 4—Property, Equipment and Contracts).

Depreciation and Amortization

Depreciation and amortization of $838 thousand for the nine months ended September 30, 2005 increased by $459 thousand, or 121%, as compared to the period ended September 30, 2004. Bear Paw depreciation and amortization expenses of $573 thousand and $127 thousand are included in depreciation and amortization expenses for the nine months ended September 30, 2005 and 2004, respectively. Not including the increase of $446 thousand due to the acquisition of the Bear Paw system in August 2004 depreciation expense increased by $13 thousand. This increase is attributed to the purchase of additional fixed assets.

General and Administrative Expenses

General and administrative expenses of $1.311 million for the nine months ended September 30, 2005 increased by $826 thousand or 170% as compared to the nine months ended September 30, 2004. Approximately $540 thousand of the increase is due to higher payroll and related expenses as well as higher outside professional services. In addition, approximately $126 thousand of the increase is associated with the costs of being a public company. Other expense categories associated with the level of business development activities and the number of employees. The Company commenced operations during 2004 and the number of employees at our Corporate office grew from one employee in early 2004 to seven employees as of September 30, 2005.

General Trends and Outlook

We expect our business to continue to be affected by some key trends as discussed below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our expectations may vary materially from actual results.

U.S. Gas Supply and Outlook

We believe that the relatively high levels of demand for natural gas by both the residential and commercial markets will continue to result in steady or increasing natural gas prices which in turn will drive drilling activity. We believe that an increase in U.S. drilling activity and additional sources of supply such as liquefied natural gas, or LNG, imports will be required for the natural gas industry to meet the expected increased demand for, and compensate for the slowing production of, natural gas in the United States.

Rising Interest Rate Environment

The credit markets recently have experienced 50-year record lows in interest rates. During the last several months we have witnessed increases in interest rates. This could affect our ability to access the debt capital markets to pay for acquisitions. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

At September 30, 2005, cash and cash equivalents totaled $7.991 million and we had working capital of $8.378 million. Since our inception, we have principally financed our operating cash flow needs through public and private offerings of our equity securities. We plan to develop and or acquire oil and gas properties as part of our FDA and also in other areas outside of the AMI and also plan on expanding our gas gathering systems in the future. In order to fund these activities we are planning to raise additional funds during the next few months through subordinated debt offerings as well as through bank borrowings. We are in discussions with financial institutions however we have not entered into any definitive agreements. Our cash on hand is sufficient to fund planned expenditures through the end of 2005. The Company plans to spend an additional $2.7 million on drilling and gas gathering prospects during the fourth quarter of 2005. In the event that we do not obtain additional financing as noted herein, we will defer capital expenditures until funding is available.

On April 12, 2005, we completed our initial public offering of 2,300,000 shares of common stock at $5.50 per share and our shares commenced trading on the American Stock Exchange under the trading symbol ‘PRB.’ On closing the offering on April 15, 2005 we received proceeds of $11.273 million net of underwriter’s discounts, commissions and expenses. Including the additional costs of the offering of $1.104 million, including warrants valued at $583 thousand, our net proceeds as of September 30, 2005 were $10.169 million.

We used a portion of the proceeds to retire the $1.550 million balance outstanding under our $1.750 bank line of credit. The bank line of credit was cancelled upon payment in full and the security interest in our gathering assets and the $1.0 million certificate of deposit pledged by a preferred stockholder was released.

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Cash Flow Used in Operations

Cash used in operating activities of $306 thousand for the nine months ended September 30, 2005 is $88 thousand less than the cash used in operating activities for the nine months ended September 30, 2004. This decrease is attributed to unfavorable gas gathering volume trends and increased selling, general and administrative expenses as described above. Offsetting the increase in cash used in operating activities as noted above are improvements in working capital.

Cash Flow Used in Investing Activities

Cash used in investing activities was $1.192 million for the nine months ended September 30, 2005, representing a decrease of $1.799 thousand as compared to the nine months ended September 30, 2004. During 2004 we acquired the TOP gas gathering system for $2.960 million. During the nine months ended September 30, 2005 we paid $189 thousand for TOP accrued acquisition costs, and commenced our oil and gas exploration and production activities, investing $584 thousand in exploratory and development drilling activities. In addition we invested $245 thousand for property and equipment, including $104 thousand for the gas plant in progress, and $174 thousand for undeveloped leaseholds.

Cash Flow from Financing Activities

Cash provided by financing activities of $9.169 million for the nine months ended September 30, 2005 represents an increase of $725 thousand as compared to the nine months ended September 30, 2004. During 2005 we raised $11.007 million from our initial public offering and used $1.550 million of those proceeds to retire our bank debt. During the nine months ended September 30, 2004 we raised $9.470 million, net of the costs in respect to our Series A and B preferred private placements, and we repurchased 800,000 common shares for $800 thousand. During both the nine months ended September 30, 2004 and 2005 we paid accrued dividends on our Series A and B preferred shares, with the increase of $92 thousand during the nine months ended September 30, 2005 due to issuance timing.

Preferred Stock Dividends

All of our Series A 10% preferred stockholders and Series B 5% preferred stockholders converted to common stock on April 12, 2005. On April 15, 2005 we paid $155 thousand in accrued dividends up to the conversion date.

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Item 4. Controls and Procedures

The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports under the Securities Exchange Act of 1934, as amended (“Exchange Act”) are communicated, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of the end of the period covered by this quarterly report 10-Q, as required by Rules 13a-15 and 15d-15 of the Exchange Act, an evaluation was carried out under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and the Principal Financial and Accounting Officer, of the effectiveness of the design and operation of disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act). Based upon that evaluation, the Chief Executive Officer and the Principal Financial and Accounting Officer concluded that the design and operation of these disclosure controls and procedures were effective as of that date. No changes in internal controls over financial reporting identified in connection with its evaluation (as required by Rules 13a-15(d) and 15d-15(d) of the Exchange Act) occurred during the quarterly period covered by this report that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.

Although the evaluation did not detect any material weaknesses or significant deficiencies in the Company’s system of internal accounting controls over financial reporting, management had previously identified certain potential deficiencies in its level of staffing, and inherent limitations in its electronic data processing software. The Company has hired additional accounting and administrative personnel during the fourth quarter of 2005 and the Company is also in the process of upgrading its electronic data processing software during the fourth quarter of 2005.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

None.

Item 2. Changes in Securities and Use of Proceeds

(f)            Use of Proceeds

Our registration statement on Form S-1 (file number 333-120129) became effective and our common stock commenced trading on the American Stock Exchange on April 12, 2005. A total of 2,300,000 shares of common stock were registered for the account of PRB for an aggregate offering price of $12.650 million. All of these securities were sold. A total of 3,995,000 shares of common stock were registered for the account of selling shareholders. PRB received no proceeds from the sale of these shares. The managing underwriter was Gilford Securities Incorporated.

Actual expenses incurred in connection with the issuance and distribution of the above securities during the period from the effective date through September 30, 2005 were $2.48 million, representing underwriting discounts and commissions of $1.012 million underwriter expenses of $389.9 thousand and other expenses of $1.079 million (including warrants valued at $583 thousand).

All payments were direct or indirect to others. No payments were direct or indirect payments to: i) directors, officers or general partners of the Company or its associates; ii) persons owning 10% or more of any class of equity security; or iii) affiliates of the Company.

Net proceeds from the offering were $10.169 million after expenses and including the proceeds from the underwriter’s exercise of its over-allotment option.

In April 2005, $1.554 million was used to repay the $1.55 million outstanding on the line of credit from the Bank of Oklahoma plus accrued interest.

No use of proceeds has involved direct or indirect payments to: i) directors, officers or general partners of the Company or its associates; ii) persons owning 10% or more of any class of equity security; or iii) affiliates of the Company. The unutilized portion of the proceeds is presently being invested in highly liquid, short-term investments.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Submission of Matters to a Vote of Security Holders

None.

Item 5. Other Information

None.

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Item 6. Exhibits