UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

For the quarterly period ended March 31, 2006

or

For the transition period from            to           

Commission file number 001-32471

PRB Gas Transportation, 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 ý  No o

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

Indicate by check mark whether the registrant is a shell company (as defined in 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.

TABLE OF CONTENTS

When we refer to “PRB,” “us,” “we,” or “our” we are describing PRB Gas Transportation, Inc. and its subsidiary.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

PRB Gas Transportation, Inc.
Condensed Consolidated Balance Sheets

(In thousands, except share amounts)

*                    amounts less than one thousand

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

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PRB Gas Transportation, Inc.

Condensed Consolidated Statements of Operations

(In thousands, except share amounts)

(Unaudited)

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

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PRB Gas Transportation, Inc.
Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

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

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PRB GAS TRANSPORTATION, INC.
Notes to Condensed Consolidated Financial Statements
March 31, 2006

(Unaudited)

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

Description of Business

PRB is an independent energy company engaged in the acquisition, exploration, development and production of natural gas. In addition, we provide gas gathering, processing and compression services for properties we operate and for third party producers. We also provide management services by operating certain properties by providing technical and administrative support for those properties. PRB was formed in December 2003, and is incorporated in the State of Nevada. On April 12, 2005, our common shares began trading on the American Stock Exchange under the ticker symbol “PRB.” Since our inception, PRB has conducted its activities in the Rocky Mountain states.

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 (“SEC”). Because this is an interim period filing presented 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 2005 Annual Report on Form 10-K. During interim periods, we follow the same accounting policies outlined in our 2005 Annual Report on Form 10-K, Note 2 – Summary of Significant Accounting Policies. The condensed consolidated financial statements as of March 31, 2006, and for the three months ended March 31, 2006 and 2005, are unaudited. We derived the condensed consolidated balance sheet as of December 31, 2005, from the audited balance sheet filed in our 2005 Annual Report on Form 10-K. Certain reclassifications have been made to the 2005 unaudited condensed consolidated financial statements to conform to the 2006 presentation. 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 March 31, 2006 and the results of our operations and cash flows for the three months ended March 31, 2006 and 2005. 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 realizability of inventory, the appropriate levels of various accruals including asset retirement obligations, determining the remaining economic lives and carrying values of property and equipment, oil and gas properties and other long-lived assets.) In addition, we use assumptions to estimate the fair value of share-based compensation. See Share-Based Compensation below and Note 5 - Equity Compensation Plan. We believe our estimates and assumptions are reasonable; however, actual results may differ from our estimates.

Share-Based Compensation

Prior to our January 1, 2006, adoption of Financial Accounting Standards Board (“FASB”) Statement No. 123(R), “Share-Based Payment” (“SFAS No. 123(R)”), we accounted for share-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB No. 25”) and related interpretations.  Accordingly, because the stock option grant price was equal to or greater than the respective market prices of our common stock on the grant dates, no compensation expense was recognized for Company-issued stock options.  In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 123, “Accounting for Stock-based Compensation” (“SFAS No. 123”) and SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” we provided pro-forma net loss and net loss per share disclosures for each period prior to the adoption of SFAS No. 123(R) as if we had applied the fair value-based method in measuring compensation expense for our share-based compensation plans.

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Effective January 1, 2006, we adopted SFAS No. 123(R) 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 valuation model in determining the fair value of share-based payments to employees.  See Note 5 - Equity Compensation 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” (“SFAS No. 128”). 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.

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

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 March 31, 2006 and December 31, 2005, there were no allowances for uncollectible accounts receivable.

Revenues from customers which represented 10% or more of our sales for the three months ended March 31, 2006 and 2005 were as follows:

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Debt Issuance Costs

We include debt issuance costs in other non-current assets. These costs are associated with the senior subordinated convertible notes (“Notes”) we issued in March 2006. The remaining unamortized debt issuance costs at March 31, 2006, was $1.079 million and are being amortized using the effective interest method over the life of the Notes.

Note 2—Acquisitions and Significant Contracts

Acquisitions

On January 1, 2006, we purchased a gas gathering system from Storm Cat Energy Corporation (“Storm Cat”) for $1.0 million. We also entered into a related gas gathering and compression services agreement with Storm Cat covering 6,600 acres in the Recluse area of Wyoming.

On January 11, 2006, we agreed to gather gas for the Termo Company (“Termo”) and as part of this understanding we paid $83 thousand for a 9.27% working interest in the development of approximately 3,400 existing net acres in the Recluse area of Wyoming and an interest in any future lease acquisitions in or around the existing leases. In addition, Termo designated us as their preferred gatherer for their Homestead Project in the Recluse area.

On February 1, 2006, we acquired a 15% working interest in leaseholds underlying the GAP gas gathering system and we plan to propose a drilling program on these properties during 2006. The leaseholds cover 5 townships and a total of approximately 2,200 net acres. We paid $100 thousand for the assignments in these leaseholds and in addition received two Promissory Notes totaling $100 thousand. These notes bear interest at 7% per annum. Principal and interest is to be paid from the oil and gas revenues generated from the leaseholds. Any unpaid principal and accrued interest is due on or before December 31, 2008. We recorded the estimated fair value of the notes receivable at $20 thousand, and recorded the estimated fair value of the undeveloped leasehold interest at $80 thousand, and have included the transaction in unproved leaseholds acquisitions in our Statements of Cash Flows.

On March 1, 2006, we acquired a high pressure natural gas gathering line from Clear Creek Natural Gas, LLC and paid $453 thousand, including sales tax of $3 thousand. The newly acquired 6.5 miles of 6 and 8-inch steel pipe ties into the gathering and compression assets we purchased in January 2006 from Storm Cat. We will deliver gas from this line to the Thunder Creek interstate pipeline system.

Significant Contracts

Storm Cat Agreement

In January 2006, we entered into a 10-year gas gathering services agreement with Storm Cat which requires Storm Cat to pay us gas gathering fees on specific minimum volumes of gas whether those volumes are delivered and transported through our system or not (the “Take or Pay Agreement”). The Take or Pay Agreement is effective January 1, 2006, has a 10 year term of which the first five years are noncancelable. The Take or Pay Agreement requires Storm Cat to pay us a minimum of $972 thousand in 2006 and a minimum of $3.103 million in gas gathering fees during the first three years of the agreement. Gas gathering fees in excess of the minimum annual requirements in the first two years can be carried over into the next year to satisfy that year’s minimum annual requirement.

During the three months ended March 31, 2006, we billed Storm Cat $112 thousand in gas gathering fees for actual volumes delivered. The Take or Pay Agreement allows for quarterly adjustments when estimates indicate that annual minimum commitment requirements will not be met. We elected to not pursue an adjustment for estimated shortfalls applicable to the three months ended March 31, 2006, and we will monitor this estimated shortfall during future periods.

The Storm Cat Take or Pay Agreement also provides for our gas gathering rates to decrease during the fourth and fifth years of the agreement. We recognize revenues based on our estimate of the average gas gathering rate during the noncancelable term of the agreement. Accordingly, we deferred $12 thousand of gas gathering fees as deferred revenue on our condensed consolidated balance sheet at March 31, 2006.

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Rocky Mountain Gas Agreement

In March 2006, we elected to terminate our Farm-In and Development Agreement and Management Services Agreement with Enterra Energy Trust and its wholly-owned subsidiary Rocky Mountain Gas (“Rocky Mountain Gas”). We agreed to continue to operate Rocky Mountain Gas’ properties and provide management services for at least 60 days from the termination date. PRB also agreed to drill certain wells that had been previously approved by the State of Wyoming and Rocky Mountain Gas. We plan to operate these wells as provided by the terms of the Operating Agreement between PRB and Rocky Mountain Gas. As a result of the termination of the agreements, our working interest was reduced to 10% for all projects initiated after the termination date. Nine exploratory wells were initiated after the termination date through March 31, 2006. Accordingly, we have reclassified 90% of the costs incurred on those wells to accounts receivable, as these costs are being billed to Rocky Mountain Gas. These costs totaled $713 thousand and were outstanding as of March 31, 2006.

Note 3—Asset Retirement Obligations

We recognize an estimated liability for future costs associated with abandoning our property and equipment used in our gas gathering operations as well as for oil and gas properties. A liability for the fair value of an asset retirement obligation is established when the long-lived asset is acquired, constructed and 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, and deplete the amounts recorded in respect to our oil and gas properties, and recognize accretion expense, all over the estimated useful lives of the assets and or 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 8% to 10%. The estimated obligations may be revised due to changes in our gas gathering system configuration, changes in estimates and or changes in regulations.

A reconciliation of our asset retirement obligation liability for the three months ended March 31, 2006 and 2005, is as follows:

Note 4—Borrowings

As of March 31, 2006 and December 31, 2005, our borrowings consisted of the following:

Our borrowings at March 31, 2006,  had the following maturities:

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Senior Subordinated Convertible Notes

During the three months ended March 31, 2006, we issued a total of $21.965 million in Notes through a private placement under Rule 144A of the Securities Act of 1933 (“1933 Act”). The Notes are secured by certain gas gathering assets owned by PRB 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 beginning on March 15, 2006.

Debt issuance costs in the amount of $1.051 million, excluding the value of warrants issued,  were deferred as other non-current assets and are being amortized as interest expense using the effective interest method over the 30-month life of each note. For the three months ended March 31, 2006, we incurred $408 thousand in total interest expense applicable to these Notes.

On March 8, 2006, we closed the offering. We plan to file a registration statement applicable to the shares of common stock underlying the Notes. The Notes include a Registration Rights Agreement that provides for liquidated damages in the amount of 1% per month in the event that our registration statement is not declared effective by the 120^th day after the Closing date.

 Note holders have the right, after the shares have been registered, to convert the Notes to common shares at a conversion price of $7.00 per share, which conversion price is subject to certain anti-dilution adjustments. In the event that our common stock trades at $14.00 per share or above for 10 consecutive days, we have a call provision which allows us to retire the Notes upon 10 days prior written notice by paying in cash, the principal amount and any accrued but unpaid interest.

We follow SFAS No. 133, and EITF 00-19, “Accounting for Derivative Financial Instruments Index to, and Potentially Settled in, a Company’s Own Stock” and related pronouncements. We have evaluated the conversion feature embedded in our senior subordinated convertible debt and the liquidated damages provision in the related Registration Rights Agreement and we have determined that the entire amount of these securities are properly classified as long-term debt and are not accounted for as derivatives on our condensed consolidated balance sheet at March 31, 2006.

 In addition, we are prohibited from declaring or paying cash dividends on our common stock during the period that any note is outstanding and unpaid.

Note 5—Equity Compensation Plan

We have an Equity Compensation Plan (“Option Plan”). The Option Plan grants options to purchase shares of our common stock to eligible employees, contractors and non-employee members of the Board of Directors. In accordance with our Option Plan, we reserve shares equal to 10% of our issued and outstanding common stock for issuance under the Option Plan. Our compensation committee 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 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 65,439 shares available for grant under the Option Plan as of March 31, 2006.

The following table summarizes activity for options:

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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 granted during the three months ended March 31, 2006 was $3.84. The weighted average remaining contractual life for the options outstanding at March 31, 2006 is 7.75 years.

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.

Adoption of SFAS No. 123(R)

PRB adopted SFAS No. 123(R) on January 1, 2006 using the modified prospective transition method as described in SFAS No. 123(R). Under this method, compensation expense is recognized for all share-based payments granted after the effective date and for all unvested awards granted prior to the effective date, over the vesting period. In accordance with SFAS No. 123(R), prior period amounts were not restated. During the three months ended March 31, 2006, we recorded share-based compensation expense of $279 thousand, which was recognized in general and administrative expense with a corresponding credit to additional paid-in-capital. Of the $279 thousand, $57 thousand was related to unvested options granted prior to January 1, 2006. Compensation expense related to unvested options granted not yet recognized as of March 31, 2006, was $850 thousand. We expect to recognize this compensation expense over the vesting period. The weighted-average vesting period is 3.25 years.

Prior to the effective date, our option plan transactions were accounted for under APB No. 25 and related interpretations. Pro-forma information regarding the impact of total share-based compensation on net loss and net loss per share for prior periods is required by SFAS No. 123. Such pro-forma information, determined as if we had accounted for our employee stock options under the fair value method during the three months ended March 31, 2005, is illustrated in the following table:

Determining Fair Value

Valuation and Amortization Method. We estimate the fair value of stock options granted using the Black-Scholes option valuation model. For options granted before January 1, 2006, we amortize the fair value on an accelerated basis. For options granted on or after January 1, 2006, we amortize the fair value on a straight-line basis. All options are amortized over the requisite service periods of the awards, which are generally the vesting periods.

Expected Term. The expected term of options granted represents the period of time that they are expected to be outstanding. We estimated the expected term of options granted using the simplified method in accordance with the SEC’s Staff Accounting Bulletin No. 107.

Expected Volatility. Consistent with SFAS No. 123(R) we base our expectations about the future volatility of our stock

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using the weighted average volatilities of similar companies that operate in our industry, taking into consideration stage of life cycle and size.

Risk-Free Interest Rate. We base the risk-free interest rate that we use in the Black-Scholes option valuation model on the implied yield in effect at the time of option grant on U.S. Treasury zero-coupon issues with equivalent remaining terms.

Dividends. We have never paid any cash dividends on our common stock and we do not anticipate paying any cash dividends in the foreseeable future. Consequently, we use an expected dividend yield of zero in the Black-Scholes option valuation model.

Forfeitures. SFAS No. 123(R) requires us to estimate forfeitures at the time of grant and revise those estimates in subsequent periods if actual forfeitures differ from those estimates. We use historical data to estimate pre-vesting option forfeitures and record share-based compensation expense only for those awards that are expected to vest. For purposes of calculating pro-forma information under SFAS No. 123, we accounted for forfeitures as they occurred.

We used the following assumptions to estimate the fair value of options granted for the three months ended March 31, 2006 and 2005:

Note 6—Segment Information

SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” (“SFAS No.131”) 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 two reportable segments, described below, based on factors such as how we manage operations and how the chief operating decision maker views results. We consider our chief executive officer as our chief operating decision maker. During the third quarter of 2005, we entered into the oil and gas exploration and production segment and began producing and selling natural gas during the fourth quarter of 2005.

Gas Gathering and Processing Segment

We own and operate gas gathering and processing systems we acquired in 2004 and during the three months ended March 31, 2006, as earlier described. We charge a fee to our customers for these services based on volumes of gas transported, and/or based on a monthly minimum fee and/or based on the level of compression services provided.

In March 2006, we notified our customers served by the TOP system that we were raising our rates to cover cash costs plus 15% for a two month period. These customers have agreed to the increase. We also advised these customers that we were planning to shut down the TOP system after the two month period has elapsed. We plan to dismantle the TOP site at that time and plan to sell the equipment not required for our other activities. During the twelve months ended December 31, 2005, we recorded an estimated impairment of $2.487 million for the TOP system. We reviewed the carrying value of our TOP system as of March 31, 2006. We expect that the future cash flows that we will receive from shutting-down the system and or selling the system or its component parts will exceed the carrying value. Accordingly, no further impairment has been recorded.

Oil and Gas Exploration and Production Segment

Beginning in the third quarter of 2005, we commenced operations in the exploration and production segment. Our operations in this segment include exploring for, developing, producing and marketing natural gas from coal-bed methane wells. For the three months ended March 31, 2006, our exploration and production segment operated in the Powder River Basin area of Wyoming.

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Through our Management Services Agreement with Rocky Mountain Gas, we earn management fee revenue and we have included that revenue under Corporate in the following table that details the performance of our segments. In March 2006, we elected to terminate the Management Services Agreement. As a result of the termination, we expect to incur approximately $150 thousand of general and administrative expenses during the year ended December 31, 2006, that we will not be able to bill out as management fees. See Note 2 – Acquisitions and Significant contracts for details regarding our Rocky Mountain Gas agreements.

We operated in only one segment during the three months ended March 31, 2005 and our management reviewed the results of our operations as a single segment during that period. Accordingly, segment information is not presented for the three months ended March 31, 2005.

Note 7— Contingencies

Possible Rescission of Series C Convertible Preferred Stock Sale

In December 2004, we received $1.233 million from the sale of 411,000 shares of Series C Convertible Preferred stock. We paid no cash or other commissions or finders’ fees in connection with this offering. In the view of the SEC, this placement might not have been eligible for an exemption from registration under the 1933 Act. In the absence of such an exemption, investors could bring suit against us to rescind their stock purchases, in which event we could be liable for rescission payments to these investors of up to $1.233 million exclusive of interest and costs. In August 2005, we 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 March 31, 2006, 401,000 Series C Convertible Preferred shares had been converted to common shares and 10,000 shares remained outstanding. See Note 9 – Subsequent Events for discussions of subsequent conversions.

Note 8—Related Party Transactions

Susan Wright, our Corporate Secretary and wife of the CEO, provides Corporate Secretary services to us on a contract basis. During the three months ended March 31, 2006 and 2005, Mrs. Wright was paid $12 thousand and $3 thousand, respectively, for contract services.

In January 2006, we issued 40,000 warrants to John McGrain, a former Director, for services rendered in respect to our recent convertible debt offering. These warrants immediately vested with an exercise price of $7.00 per share. The estimated fair value of the warrants was $92 thousand at issuance based on the Black-Scholes model, with the following assumptions: a) contractual life of two years; b) expected volatility of 80%; c) risk-free rate of 4.82% and d) expected dividend yield of zero percent. We recorded the fair value of the warrants as deferred debt issuance costs, with a corresponding increase in additional paid-in-capital.

One of our Officers (and Director) and one of our Directors purchased $100 thousand and $200 thousand, respectively, of the Notes, that were issued during the three months ended March 31, 2006. We paid interest on March 15, 2006 of $444 and $888, to our Officer (and Director) and our Director, respectively in respect to these Notes. In addition, a former Director, Mr. John McGrain, purchased $1 million of the Notes issued, and we paid interest of $4,444 to Mr. McGrain.

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Note 9 —Subsequent Events

In April 2006, the remaining 10,000 shares of Series C Convertible Preferred stock were converted to common shares.

On May 12, 2006, PRB signed a definitive Purchase and Sale Agreement to purchase approximately 70 miles of gathering lines located in the Recluse area of Wyoming’s Powder River Basin. PRB, subject to due diligence that will include pipeline integrity testing and environmental review, plans to complete this transaction by the end of June 2006. Also included is a gas gathering agreement in respect to one producer.

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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,” “us,” “we” and “our” refer to PRB Gas Transportation, Inc. and its subsidiary.

Statement of 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.

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 financial statements and related notes in Item I and our Annual Report on Form 10-K for the year ended December 31, 2005.

General Overview

PRB is an independent energy company engaged in the acquisition, exploration, development and production of natural gas. In addition, we provide gas gathering, processing and compression services for properties we operate and for third party producers. PRB was formed in December 2003, and is incorporated in the State of Nevada. On April 12, 2005, our common shares began trading on the American Stock Exchange under the ticker symbol “PRB.” Since our inception, PRB has conducted its activities in the Rocky Mountain states.

First Quarter 2006 Operational and Financial Highlights

During the first quarter of 2006, we raised $21.965 million in cash, before expenses, by issuing senior subordinated convertible notes. We intend to use these funds for our exploration, development, and asset acquisition programs.

During the first quarter of 2006, we acquired two gas gathering systems in the Recluse area of Wyoming (together our “Recluse” gas gathering system) for $1.453 million.

In January 2006, we agreed to gather gas for the Termo Company (“Termo”) and as part of this understanding we paid $83 thousand for a 9.27% working interest in the development of approximately 3,400 existing net acres in the Recluse area of Wyoming and an interest in any future lease acquisitions in or around the existing leases. In addition, Termo designated us as the preferred gatherer for their Homestead project in the Recluse area. There are approximately 30,000 undedicated acres in the Recluse area that offer us the opportunity to expand both our exploration and production and gas gathering and processing activities.

In February 2006, we acquired a 15% working interest in leaseholds underlying the GAP gas gathering system and we plan to propose a drilling program on these properties during 2006. The leaseholds cover 5 townships and a total of approximately 2,200 net acres. We paid $100 thousand for the assignments in these leaseholds and in addition received two Promissory Notes totaling $100 thousand. These notes bear interest at 7% per annum. Principal and interest is to be paid from the oil and gas revenues generated from the leaseholds. Any unpaid principal and accrued interest is due on or before December 31, 2008. We recorded the estimated fair value of the notes receivable at $20 thousand, and recorded the estimated fair value of the undeveloped leasehold interest at $80 thousand, and have included the transaction in unproved leaseholds acquisitions in our Statements of Cash Flows.

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In March 2006, we elected to terminate our Farm-In and Development Agreement and Management Services Agreement with Enterra Energy Trust and its wholly-owned subsidiary Rocky Mountain Gas (“Rocky Mountain Gas”). We agreed to continue to operate Rocky Mountain Gas’ properties and provide management services for at least 60 days from the termination date. PRB also agreed to drill certain wells that had been previously approved by the State of Wyoming and Rocky Mountain Gas. We plan to operate these wells as provided by the terms of the Operating Agreement between PRB and Rocky Mountain Gas. As a result of the termination of the agreements, our working interest was reduced to 10% for all projects initiated after the termination date. Nine exploratory wells were initiated after the termination date through March 31, 2006. Accordingly, we have reclassified 90% of the costs incurred on those wells to accounts receivable, as these costs are being billed to Rocky Mountain Gas. These costs totaled $713 thousand and were outstanding as of March 31, 2006.

In March 2006, we notified our customers served by the TOP system that we were raising our rates to cover cash costs plus 15% for a two month period. These customers have agreed to the increase. We also advised these customers that we were planning to shut down the TOP system after the two month period has elapsed. We plan to dismantle the TOP site at that time and plan to sell the equipment not required for our other activities.

During the first quarter of 2006, we commenced the drilling of 23 wells. At March 31, 2006, we have a total of 13 wells that are producing natural gas and 30 wells in various stages of drilling or completion.

During the first quarter of 2006, we increased our average daily production of natural gas from 212 thousand cubic feet (“Mcf”) per day at December 31, 2005, to 354 Mcf per day at March 31, 2006, gross and from 85 Mcf per day at December 31, 2005, to 143 Mcf per day at March 31, 2006, net.

Results of Operations

The financial information with respect to the quarter ended March 31, 2006 and 2005, that 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.

nm – percentages greater than 200% and comparisons from positive to negative values are considered not meaningful.

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Revenue

Total revenue decreased $14 thousand, or 2%, primarily due to a $272 thousand decrease in gas gathering revenues from our TOP, GAP and Bonepile systems resulting from declines in volume due to weather related shutdowns. This decrease was offset by gas gathering revenues of $106 thousand applicable to our newly acquired Recluse gas gathering system. We are currently in the process of divesting our assets relating to our TOP gathering system, however we have reached agreements with the producers that they will be charged gas gathering fees based on a cost plus 15% basis for an interim period of two months. We plan to dismantle the TOP site at that time and plan to sell the equipment not required for our other activities. We did not have management fee revenue or natural gas revenue during the quarter ended March 31, 2005.

Gas Gathering Expense

Gas gathering expense increased $97 thousand or 20% mainly due to the $151 thousand increase in Recluse system operating costs resulting from the first quarter 2006 acquisition of this system. These costs offset a $54 thousand decrease in gas gathering expenses relating to our TOP system as a result of releasing excess compression capacity.

Gas Production Costs

We incurred gas production costs beginning in the fourth quarter 2005 as a result of our entry into exploration and production activities. During the first quarter of 2006, gas production costs totaled $78 thousand. Gas production costs exceeded revenue for the quarter primarily due to the impact of severe weather that reduced production and also resulted in increased operational costs.

Exploration Expense

We incurred $97 thousand of exploration expense during the first quarter of 2006 relating to drilling costs applicable to one unsuccessful exploratory well.

Depreciation, Depletion, Amortization and Accretion Expense

Depreciation, depletion, amortization and accretion expense increased $43 thousand or 16% primarily due to $30 thousand of additional depreciation and amortization expense applicable to the Recluse gas gathering assets which were acquired during the first quarter of 2006.

General and Administrative Expense  

General and administrative expense increased $755 thousand mainly due to the recognition of $279 thousand of share-based compensation expense upon the adoption Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Share-Based Payment” (“SFAS No. 123(R)”). In addition, wages and related increased $187 thousand as a result of increased headcount. Professional fees also increased $167 thousand due to additional legal, accounting and engineering activities associated with our entering the exploration and production business and expanding our gas gathering and processing business. All other general and administrative expense increased $122 thousand, net, during the first quarter of 2006 as compared to the first quarter of 2005.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

At March 31, 2006, cash and cash equivalents totaled $22.648 million and we had working capital of $24.157 million. During the first quarter of 2006, we raised $21.965 million, before expenses, by issuing senior subordinated convertible notes. We intend to use these funds for our capital expenditures and acquisition programs.

We believe that our cash and cash equivalents on hand, internally generated cash flows and future financing activities will be sufficient to fund our planned operational, drilling and acquisition expenditures for the foreseeable future. The amount and allocation of future capital and exploration 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 we make. Also, the impact of oil and gas prices on investment opportunities, the availability of capital and borrowing facilities and the success of our exploration and development activities could lead to

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changes in funding requirements for future development.

Cash Flow Used in Operating Activities  

During the first quarter of 2006, our net loss of $1.494 million included non-cash charges of $320 thousand of depreciation, depletion, amortization and accretion expense, $279 thousand of share-based compensation expense and $64 thousand of interest expense resulting from amortization of debt issuance costs. In addition, our net loss includes $97 thousand of exploration expense resulting from writing off one unsuccessful exploratory well.

Cash used in operating activities of $1.648 million during the first quarter of 2006 was $1.790 million greater than the $142 thousand of cash provided by operating activities during the first quarter of 2005. This increase was mainly attributable to higher general and administrative expense and increased accounts receivable offset by a decrease in our accounts payable balance.

Cash Flow Used in Investing Activities

Cash used in investing activities was $3.050 million during the first quarter of 2006 representing an increase of $2.962 million as compared to the first quarter of 2005. During the first quarter 2006, we acquired the Recluse gas gathering system for $1.453 million, invested $1.163 million for wells-in-progress drilling and completion activities, $183 thousand for leasehold acquisitions and $133 thousand for development of proved properties.

During the first quarter of 2006, we added $1.140 million to capitalized exploratory drilling and completion costs, we did not transfer any costs to proved properties and we charged $97 thousand, relating to one well, to exploration expense. At March 31, 2006, $1.742 million of exploratory drilling and completion costs, relating to 30 wells, remained capitalized as wells-in-progress pending the determination of proved reserves. None of these wells are in areas requiring major capital expenditures before production can begin, nor were any of these wells completed more than one year ago. As of March 31, 2006, we were drilling or completing these wells or the wells were undergoing de-watering. We believe that after the wells are de-watered we will be able to determine if we have discovered proved reserves. We believe that this determination will be made for the 30 wells-in-progress prior to December 31, 2006.

Currently, our 2006 capital expenditure program calls for investing approximately $21 million in oil and gas exploration, development and acquisition projects and gas gathering system projects. We believe that cash on hand, cash from operating activities and cash from future financing actives will be sufficient to meet our operating and capital expenditure plans for the foreseeable future.

Cash Flow from Financing Activities  

Cash provided by financing activities of $20.912 million for the first quarter of 2006 represents an increase of $21.185 million as compared to the first quarter of 2005. During the first quarter of 2006, we raised $21.965 million and incurred $1.051 in debt issuance costs, excluding the value of warrants issued, from the issuance of our senior subordinated convertible notes. During the first quarter of 2005, we paid $183 thousand in dividends on our Series A and Series B Convertible Preferred shares and incurred $90 thousand of deferred costs related to our initial public offering.

Off Balance-Sheet Arrangements.  

We do not have any off-balance sheet financing arrangements as of March 31, 2006, except for our Storm Cat gas gathering services agreement. Our agreement requires Storm Cat to pay us gas gathering fees on specific minimum volumes of gas whether those volumes are delivered and transported through our system or not. See Note 2 – Acquisitions and Significant Contracts in Part I, Item 1 of this report.

Contractual Obligations

The following table summarizes our future commitments as of March 31, 2006 (in thousands):

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The above table does not include asset retirement obligations, accounts payable or other accrued liabilities recorded on our consolidated balance sheet as of March 31, 2006. Asset retirement obligations are not included as we cannot determine with accuracy the timing of such payments. The table does not include any commitments entered into after March 31, 2006.

We have acquired gas gathering properties and contracts that include operating leases in 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 purchase commitments for future field operations and maintenance activities with third party providers. In addition, we are a party to non-cancelable operating leases for office space, office equipment and other items required for operations, including a compressor for our TOP gas gathering system. The table above includes estimated future purchase commitments relating to these operations support contracts. With regard to the operating leases, future minimum lease payments are calculated based on the contractual rate and period, or if the contract was a surface-use agreement, future minimum lease payments were calculated based on the estimated lives of the associated gas reserves (through 2014) and the applicable contract rate.

Critical Accounting Policies and Estimates

We refer you to the corresponding section in Part II, Item 7 of our 2005 Annual Report on Form 10-K, and to the footnote disclosures included in Part I, Item 1 of this report.

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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 PRB’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005.

ITEM 4: CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

We maintain disclosure controls and procedures designed to provide reasonable assurance that information required to be disclosed in our reports under the Securities and Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities Exchange Commission (“SEC”) rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Principal Financial Officer, as appropriate, 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 March 31, 2006. In conducting this evaluation, several significant deficiencies were identified in our internal control over financial reporting relating to the preparation and review of financial statements and disclosures, identification and resolution of complex accounting issues, segregation of duties, accounting policies and procedures, information technology systems, and revenue recognition. Management has determined that these significant deficiencies, in the aggregate, constitute a material weakness in internal control over financial reporting. Specifically, our staffing levels were inadequate to facilitate the design, implementation and maintenance of an effective system of internal control.

On the basis of these findings, our Chief Executive Officer and our Principal Financial Officer have concluded that our disclosure controls and procedures were not effective, as of March 31, 2006.

Remediation of the Material Weaknesses

In response to the control deficiencies listed above, we have taken (or plan to take during 2006) the following steps to remediate the significant deficiencies identified above:

•       We plan to increase the accounting staff to provide additional expertise in the areas of SEC reporting and complex accounting issues. Additionally, we have engaged outside help to assist us with complex accounting and financial reporting matters. Continued training of current staff and the need for additional resources will be evaluated from time to time.

•       We plan to implement disclosure controls and procedures and form a Disclosure Committee which will provide additional oversight and control over the completeness and accuracy of the Company’s financial statements and disclosures included in periodic filings with the SEC.

•       We plan to document our accounting policies and procedures and enhance our month end close and financial reporting processes to include additional controls to improve the completeness and accuracy of our periodic financial statements.

•       We are replacing our current general ledger software with a more robust accounting and reporting software package that will enable us to increase our controls over system generated reports.

However, until we have completed a formal review of our internal controls, and even upon completion of such review, there is no assurance that we will have adequately addressed the identified deficiencies, as has been characteristic of companies that have completed their review of internal control and have had to report on the results of such review. Accordingly, our internal control over financial reporting may be subject to additional material weaknesses and significant deficiencies that we have not identified.

On September 21, 2005, the SEC extended the compliance dates related to Section 404 of the Sarbanes-Oxley Act (“Section 404”) for non-accelerated filers. Under this extension a company that is not required to file its annual and quarterly reports on an accelerated basis (non-accelerated filer) must begin to comply with the Section 404 internal control over financial reporting evaluation and reporting requirements for its first fiscal year ending on or after July 15, 2007. We anticipate that we may become an accelerated filer in calendar 2006 and therefore we could be required to comply with these requirements for the year ending December 31, 2006. We are currently in the process of documenting our internal control structure.

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PART II OTHER INFORMATION

ITEM 1: LEGAL PROCEEDINGS

None.

ITEM 1A. RISK FACTORS

For information regarding factors that could affect our results of operations, financial condition and liquidity, see the risk factors discussion provided under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2005. See also, “Forward-Looking Statements” included in Part I, Item 2 of this Quarterly Report on Form 10-Q.

ITEM 2: UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Initial Public Offering

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.

Net proceeds from the offering were $10.752 million after expenses.

At March 31, 2006, net proceeds from this offering were used as follows:

With the exception of dividends paid to an Officer and Directors totaling $3 thousand and $56 thousand to persons who owned 10% or more of our Series A and B Convertible Preferred stock, no use of proceeds has involved direct or indirect payments to: i) our directors, officers or associates; ii) persons owning 10% or more of any class of equity security; or iii) any of our affiliates.

The unutilized portion of the proceeds is presently being invested in highly liquid, short-term investments.

Senior Subordinated Convertible Notes

On March 8, 2006, we completed our offering of $21.965 million in senior subordinated convertible notes (the “Notes”) to accredited investors. This offering was exempt from registration under Section 4(2) of the Securities Act of 1933 and/or Rule 506 promulgated thereunder. We incurred $1.051 million in debt issuance costs, excluding the value of warrants issued, applicable to this offering.

Note holders have the right to convert the Notes to common shares, after the shares have been registered, at a conversion price of $7.00 per share, which conversion price is subject to certain anti-dilution adjustments. In the event that our common stock trades at $14.00 per share or above for 10 consecutive days, we have a call provision which allows us to retire the Notes upon 10 days prior written notice by paying in cash, the principal amount and any accrued but unpaid interest.

ITEM 3: DEFAULTS UPON SENIOR SECURITIES

None.

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ITEM 4: SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5: OTHER INFORMATION

None.

ITEM 6: EXHIBITS

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These exhibits are available upon request. Exhibits identified in parentheses below are on file with the SEC and are incorporated herein by reference. All other exhibits are provided as part of this electronic submission.

( )                Previously filed.

*                    Management contract or compensatory plan or arrangements.

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SIGNATURE

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

Dated: May 15, 2006

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