UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q

(Mark One)

x		QUARTERLY REPORT PURSUANT TO  SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2007
Or
o		TRANSITION REPORT PURSUANT TO  SECTION 13 OR 15(d) OF THE SECURITIES OF

 

For the transition period from           to          

Commission file number 001-32471

PRB ENERGY, INC.

(Exact Name of Registrant as Specified in its Charter)

 

Telephone Number: (303) 308-1330

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

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

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

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

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

 

TABLE OF CONTENTS

PART I — Financial Information			1
Item 1.	Financial Statements		1
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		12
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		17
Item 4.	Controls and Procedures		17
PART II — Other Information			18
Item 1.	Legal Proceedings		18
Item 1A.		Risk Factors	18
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds		18
Item 3	Defaults Upon Senior Securities		18
Item 4	Submission of Matters to a Vote of Security Holders		18
Item 5	Other Information		19
Item 6.	Exhibits		20
	Signatures		21

 

When we refer to “PRB,” “the Company,” “us,” “we” or “our,” we are describing PRB Energy, Inc. and its subsidiaries.

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PRB ENERGY, INC.

Consolidated Balance Sheets

(In thousands, except share amounts)

		June 30,			December 31,
		2007			2006
		(Unaudited)
Assets
Current assets:
Cash and cash equivalents		$	2,905		$	11,157
Restricted cash		2,157			2,078
Accounts receivable, net		2,871			2,527
Note receivable		2,250
Inventory		51			—
Prepaid expenses		535			789
Total current assets		10,769			16,551
Oil and gas properties accounted for under the successful efforts method of accounting:
Proved properties		5,489			5,436
Unproved leaseholds		9,729			9,282
Wells-in-progress		5,020			5,794
Total oil and gas properties		20,238			20,512
Less: accumulated depreciation, depletion and amortization		(1,245		)	(766		)
Net oil and gas properties		18,993			19,746
Gathering and other property and equipment		15,325			11,603
Less: accumulated depreciation and amortization		(2,911		)	(1,919		)
Net gathering and other property and equipment		12,414			9,684
Other non-current assets:
Deferred debt issuance costs		2,107			2,086
Less: accumulated amortization		(771		)	(375		)
Net deferred debt issuance costs		1,336			1,711
Other non-current assets		2,499			2,151
Total other non-current assets		3,835			3,862
Total Assets		$	46,011		$	49,843
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable		$	1,408		$	1,854
Accrued expenses and other current liabilities		650			979
Deferred gain		883			—
Current portion of debentures		1,125			—
Total current liabilities		4,066			2,833
Secured notes, debentures and other debt, less current portion		35,841			36,972
Discount on debentures, net of amortization		(3,287		)	(4,326		)
Capital lease, less current portion		2,974			—
Other non-current liabilities		3,135			3,140
Total liabilities		42,729			38,619
Commitments and Contingencies
Stockholders’ equity:
Common stock, 40,000,000 shares authorized; 8,601,994 and 8,231,894 issued, respectively, and 8,601,994 outstanding		10			10
Treasury stock		(1,257		)	(1,257		)
Additional paid-in-capital		26,823			26,406
Accumulated deficit		(22,294		)	(13,935		)
Total stockholders’ equity		3,282			11,224
Total Liabilities and Stockholders’ Equity		$	46,011		$	49,843

 

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

1

---

PRB ENERGY, INC.

Consolidated Statements of Operations

(In thousands, except share amounts)

(Unaudited)

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2007			2006			2007			2006
Revenues:
Natural gas sales		$	346		$	48		$	759		$	106
Gas gathering and processing		364			603			872			1278
Other		10			52			14			146
Total revenues		720			703			1,645			1,530
Natural gas gathering expense		(47		)	(15		)	(103		)	(27		)
Natural gas production taxes		(37		)	(5		)	(77		)	(12		)
Net revenues		636			683			1,465			1491
Operating expenses:
Natural gas lease operating		612			—			1,273			—
Gas gathering and processing		593			648			1,026			1217
Depreciation, depletion, amortization and accretion		951			336			1,806			656
General and administrative		1,194			1,129			2,794			2,146
Other expense		—			48			—			223
Total operating expenses		3,350			2,161			6,899			4,242
Operating loss		(2,714		)	(1,478		)	(5,434		)	(2,751		)
Other income (expense):
Interest and other income		582			284			853			471
Gain on RMG settlement and sale of assets, net		240			—			240			—
Interest and other expense:
Convertible notes and debentures		(1,041		)	(523		)	(2,071		)	(869		)
Debt issuance costs and discount on debentures		(804		)	(101		)	(1,550		)	(163		)
Other		(191		)	—			(396		)	—
Total other expense		(1,214		)	(340		)	(2,924		)	(561		)
Net loss		$	(3,928	)	$	(1,818	)	$	(8,358	)	$	(3,312	)
Net loss per share — basic and diluted		$	(0.46	)	$	(0.24	)	$	(0.97	)	$	(0.44	)
Basic and diluted weighted average shares outstanding		8,601,994			7,471,235			8,601,994			7,450,679

 

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

2

---

PRB ENERGY, INC.

Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

		Six Months Ended
		June 30,
		2007			2006
Cash flows from operating activities:
Net loss		$	(8,358	)	$	(3,312	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depreciation, depletion, amortization and accretion		1,806			656
Exploration expense		—			50
Amortization of debt issuance costs		510			164
Amortization of discount on debentures		1,039			—
Non share based warrants issued for services rendered		—			71
Gain on RMG settlement		(384		)	—
Loss on sale of assets		104
Bad debt expense		317			—
Share-based compensation expense		417			392
Capitalized interest		(159		)	(32		)
Changes in assets and liabilities:
Accounts receivable		(873		)	(366		)
Inventory		(5		)	417
Prepaid expenses		254			(472		)
Other non-current assets		(427		)	11
Accounts payable		(461		)	(1,057		)
Accrued expenses and other current liabilities		(246		)	757
Deferred revenue		46			—
Other non-current liabilities		—			6
Net cash used in operating activities		(6,421		)	(2,715		)
Cash flows from investing activities:
Capital expenditures		(2,690		)	(6,204		)
Restricted cash related to future liablities of acquired properties		—			(3,000		)
Sale of fixed assets		—			20
Deferred acquisition costs		—			(18		)
Unproved leasehold acquisitions		—			(183		)
Net cash used in investing activities		(2,690		)	(9,385		)
Cash flows from financing activities:
Proceeds from convertible notes		—			21,965
Proceeds from RMG settlement		1,000			—
Issuance costs related to debentures and convertible notes		(135		)	(1,051		)
Convertible preferred stock dividends		—			(5		)
Repayment of term loan		(6		)	—
Net cash provided by financing activities		859			20,909
Net (decrease) increase in cash		(8,252		)	8,809
Cash—beginning of period		11,157			6,434
Cash—end of period		$	2,905		$	15,243
Supplemental disclosure of cash flow activity:
Cash paid for interest		$	2,626		$	808
Supplemental schedule for non-cash activity:
Issuance of warrants in connection with convertible notes		$	—		$	92
Capital remediation costs		$	46		$	1,500
Asset retirement obligations		$	171		$	2,085
Capital lease		$	3,050		$	—
Deferred gain on RMG settlement		$	883		$	—

 

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

3

PRB ENERGY, INC.

Notes to Consolidated Financial Statements

June 30, 2007

(Unaudited)

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

Description of Business

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

Basis of Presentation

We have prepared this Quarterly Report on Form 10-Q under the rules and regulations of the United States Securities and Exchange Commission.  Because this is an interim period filing which is being 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 2006 Annual Report on Form 10-K.  During interim periods, we follow the same accounting policies outlined in our 2006 Annual Report on Form 10-K, Note 2 — Summary of Significant Accounting Policies.  The consolidated financial statements as of June 30, 2007, and for the three and six months ended, June 30, 2007 and 2006, are unaudited.  Certain reclassifications have been made to the 2006 unaudited condensed consolidated financial statements to conform to the 2007 presentation.  Such reclassifications had no effect on the 2006 net loss.  In the opinion of management, these interim financial statements contain all adjustments which are of a normal, recurring nature to fairly present the financial position of PRB as of June 30, 2007 and the results of our operations for the three and six months ending June 30, 2007 and 2006, and cash flows for the six months ended June 30, 2007 and 2006.  Information for interim periods may not be indicative of our results of operations for the entire year.

Summary of Significant Accounting Policies

Use of Estimates

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

Share-Based Compensation

Effective January 1, 2006, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Share-Based Payment,” using the modified prospective transition method and, as a result, did not retroactively adjust results from prior periods.  SFAS No. 123(R) requires that share-based compensation expense be measured using estimates of the fair value of all share-based awards and applies to new awards and to awards

4

---

modified, repurchased or cancelled after December 31, 2005, as well as to the unvested portion of awards outstanding as of January 1, 2006.  Under the modified prospective transition method, we are recognizing share-based compensation expense over the remaining vesting period for awards that were outstanding but unvested at January 1, 2006 and we are recognizing share-based compensation expense for the fair value of all awards granted on or after January 1, 2006 as the awards vest.  We apply the Black-Scholes option valuation model in determining the fair value of share-based payments to employees.  See Note 7 - Equity Incentive Plan for further discussion of share-based compensation.

Net Loss Per Share

We account for earnings (loss) per share (“EPS”) in accordance with SFAS No. 128, “Earnings per Share.”  Under SFAS No. 128, basic EPS is computed by dividing the net loss applicable to common stockholders by the weighted average common shares outstanding without including any potentially dilutive securities.  Diluted EPS is computed by dividing the net loss applicable to common stockholders for the period by the weighted average common shares outstanding plus, when their effect is dilutive, common stock equivalents.  The following are potentially dilutive shares that are excluded from the calculation as they are anti-dilutive:

		Six Months Ended June 30,
		2007		2006
		(equivalent shares)
Warrants		365,000		300,000
Options		719,750		659,250
Convertible notes		3,137,857		3,137,857
Total potentially dilutive shares excluded		4,222,607		4,097,107

 

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 June 30, 2007 and December 31, 2006, there were balances of $28,000 and $604,000, respectively, as an allowance for uncollectible accounts receivable.  The significant reduction in the balance of the allowance from December 31, 2006 was due to the Rocky Mountain Gas, Inc. (“RMG”) settlement payment.  (See below for the Rocky Mountain Gas Inc. Settlement.)

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

		Three Months Ended June 30,				Six Months Ended June 30,
Customer		2007		2006		2007		2006
		(% of total revenue)				(% of total revenue)
A — Exploration and Production		49	%	—		43	%	—
B — Gathering and Processing		—		31	%	—		37	%
C — Gathering and Processing		43	%	17	%	41	%	15	%
D — Gathering and Processing		—		12	%	—		—

 

Debt Issuance Costs and Discount on Debt

 We include debt issuance costs in other non-current assets.  These costs are associated with the senior subordinated convertible notes (“Notes”) we issued in March 2006 and the senior secured debentures (“Debentures”) we issued in December 2006.  The remaining unamortized debt issuance cost was $1,336,000 at June 30, 2007 and is being amortized using the effective interest rate method over the term of the debt.

5

---

The discount on the Debentures of $4,326,000 is reflected as a liability on the balance sheet at December 31, 2006.  The remaining unamortized discount at June 30, 2007 was $3,287,000 and is being amortized using the effective interest rate method over the term of the debt.

Rocky Mountain Gas Inc. Settlement

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

In addition as of June 1, 2007, RMG assigned to PRB all of RMG’s interests, including infrastructure, in the Moyer coal-bed methane wells located in Section 19, T48N, R71W, adjacent to PRB’s acreage.  In turn, PRB assigned to RMG all of PRB’s interests (other than Section 19) in the acreage and wells (“PRB Assets”) originally included in the farmout agreement with RMG.

The net costs for the properties transferred to RMG that were previously incurred by PRB and were related to the RMG agreement were compared to the value of the properties received from RMG.  The net result was compared with the total cash proceeds to be received of $3,250,000, plus interest on the RMG Note of $150,000 and produced a total gain of $1,267,000 for the transaction.  As cash is received, a proportion of the total gain less the interest income component will be recognized as the current period’s gain from the sale of these assets.  The deferred gain will be recognized as income upon receipt of the final payment on the RMG Note on October 31, 2007.  At June 30, 2007, the deferred gain balance was $883,000.  This is computed as follows:

Total computed amount of gain		$	1,267,000
Less: gain recognized in the current quarter		343,000
Less: interest income in the current quarter		41,000
Deferred gain balance		$	883,000

 

Note 2—Recent Accounting Developments

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

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

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which permits an entity to measure certain financial assets and financial liabilities at fair value.  The objective of SFAS No. 159 is to improve financial reporting by allowing entities to mitigate volatility in reported earnings caused by the measurement of related assets and liabilities using different attributes, without having to apply complex hedge accounting provisions.  Under SFAS No. 159, entities that elect the fair value option (by instrument) will report unrealized gains and losses in earnings at each subsequent reporting date.  The fair value option election is irrevocable, unless a new election date occurs.  SFAS No. 159

6

---

establishes presentation and disclosure requirements to help financial statement users understand the effect of the entity’s election on its earnings, but does not eliminate disclosure requirements of other accounting standards.  Assets and liabilities that are measured at fair value must be displayed on the face of the balance sheet.  This Statement is effective beginning January 1, 2008, and we will assess the potential impact of this Statement on our financial statements prior to that date.

Note 3—Significant Agreements

Compressor Lease Agreement

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

The lease meets the criteria under SFAS No. 13, “Accounting for Leases,” for classification as a capital lease on the balance sheet.  As a result, a capital lease asset of $3,050,000, which represents the estimated fair value of the property, was recorded in January 2007.  The related liability, less the current portion of $105,000, is shown as a non-current liability of $2,974,000 on the balance sheet at June 30, 2007.  In addition, a cash payment of $650,000 was made to J-W for future maintenance repairs in connection with the lease.  The capital lease and prepayment will be amortized as expenses over the term of the lease.  Monthly lease payments ranging from $100,000 to $150,000 will reduce the liability and also will include interest and executory (sales tax and environmental fees) expenses.

RMG Settlement Agreement - Consent of Holders of the Debentures

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

Note 4—Asset Retirement Obligations

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

We estimate our future retirement obligations based on our experience, management estimates and regulatory requirements.  We discount the estimated future obligations using an estimated credit adjusted risk-free rate at the time the obligation is incurred or revised.  Historically this rate has been estimated at 8% to 10%.  The estimated obligations may be revised due to changes in expected lives of gas wells, changes in gas gathering system configuration, changes in estimates and changes in regulations.

7

---

 

 

 

Note 5—Borrowings

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

(In thousands)		June 30, 2007			December 31, 2006
Senior subordinated convertible notes		$	21,965		$	21,965
Senior secured debentures		15,000			15,000
Other term loans		11			17
		36,976			36,982
Less current portion		(1,135		)	(10		)
Total long-term borrowings		$	35,841		$	36,972

 

Senior Subordinated Convertible Notes

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

At June 30, 2006, debt issuance costs of the Notes totaling approximately $1 million, excluding the value of warrants issued, were reflected as other non-current assets and have been amortized as interest expense in each applicable period.  For the six months ended June 30, 2007, $225,000 of the deferred cost of the Notes was amortized as interest expense and an additional $1,104,000 of interest paid in cash was expensed.

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

Senior Secured Debentures

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

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

At June 30, 2007, debt issuance costs of the Debentures totaling approximately $1.1 million were reflected as other non-current assets and have been amortized as interest expense in each applicable period.  For the six

8

---

months ended June 30, 2007, $286,000 of the deferred cost of the Debentures was amortized as interest expense and an additional $967,000 of interest paid in cash was expensed.

The amortized portion of the discount on the Debentures of $1,039,000 was recorded as interest expense during the six months ended June 30, 2007.

Note 6—Income Taxes

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

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

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

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

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

Note 7—2007 Equity Incentive Plan

Our shareholders approved the 2007 Equity Incentive Plan (the “2007 Plan”) at our annual shareholders’ meeting held May 31, 2007.  The 2007 Plan replaces our previous Equity Compensation Plan (“Option Plan”) that was adopted in May 2004.  The 2007 Plan allows us to grant non-qualified stock options, shares of restricted stock or other types of equity-based compensation of up to 20% of our outstanding shares to our non-employee directors, officers, employees and consultants.  Some of these award types were not available under the  Option Plan.  The 2007 Plan will be administered by a committee appointed by the Board of Directors, which may grant options on such terms, including vesting and payment forms, as it deems appropriate in its discretion.  However, no option may be exercised more than 10 years after its grant, and the purchase price may not be less than 100% of the fair market value of our common stock on the date of grant.

All options granted to date under both the 2007 Plan and the Option Plan have been granted at exercise prices equal to or greater than the respective market prices of our common stock on the grant dates.  There were 999,399 shares available for grant under the 2007 Plan as of June 30, 2007.

The following table summarizes the activity for options:

9

---

 

		Six Months Ended					Six Months Ended
		June 30, 2007					June 30, 2006
		Number of		Weighted Avg.			Number of		Weighted Avg.
		Shares		Exercise Price			Shares		Exercise Price
Outstanding at January 1,		617,250		$	6.35		463,250		$	6.74
Granted		227,500		3.99			284,500		6.20
Forfeited		(123,750	)	6.19			(88,500	)	7.65
Exercised		—		—			—		—
Outstanding at June 30,		721,000		$	5.71		659,250		$	6.40
Exercisable at June 30,		347,063		$	5.62		333,125		$	6.43

 

As of June 30, 2007, the weighted average fair value of options granted during the previous six months was $2.05, the weighted average remaining contractual life for the options outstanding is 6.5 years and the weighted average remaining contractual life for the options exercisable is 3.0 years.  The fair value of each option granted is estimated on the date of grant using the Black-Scholes option valuation model.

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

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

		SFAS No. 123(R)		SFAS No. 123(R)
		Six Months Ended		Six Months Ended
		June 30, 2007		June 30, 2006
Expected life of options		2.8 — 6.5 years		2.5 — 6.25 years
Expected volatility		70% — 80%		80%
Risk-free interest rate		4.76 — 5.12%		4.31 — 5.23%
Expected dividend yield of stock		0%		0%

 

Note 8 — Segment Information

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

Oil and Gas Exploitation and Production Segment

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

Gas Gathering and Processing Segment

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

10

---

Corporate Segment

This segment contains the overall corporate headquarter functions and costs that are primarily staff G&A, legal and professional services, furniture and equipment and debt financing arrangements.

 

		Six Months Ended June 30, 2007
		Exploration			Gathering
		and			and
(In thousands)		Production			Processing			Corporate			Total
Revenues		$	759		$	872		$	14		$	1,645
Net loss		$	(1,432	)	$	(1,062	)	$	(5,864	)	$	(8,358	)
Identifiable assets:
Oil and gas properties, net		$	18,993		$	—		$	—		$	18,993
Property and equipment, net		$	—		$	11,774		$	640		$	12,414
Other non-current assets		$	—		$	1,389		$	2,446		$	3,835

 

Note 9—Related Party Transactions

Susan Wright, wife of our CEO and a corporate officer, provides services to us as the Corporate Secretary on a contractual basis.  During the six months ended June 30, 2007, Ms. Wright was paid $67,375 for these contract services.

On January 9 and June 1, 2007, we issued 15,000 and 50,000 warrants, respectively, to two former directors for services rendered.  These warrants vested immediately on the date of grant with an exercise price of $4.50 per share.  We recorded approximately $81,000 as the estimated fair value of the warrants as stock-based compensation, with a corresponding increase in additional paid-in-capital.

One of our officers (and a director) and three of our directors, in the aggregate, purchased $100,000 and a total of $1,275,000, respectively, of the Notes that were issued in the first quarter of 2006.  During the six months ended June 30, 2007, we paid interest of $5,000 and $64,000, respectively, on these Notes.  In addition, an investment fund, of which one of our former directors is a consultant, purchased on behalf of its investors, $1,000,000 of the Notes.  The investors were paid $50,000 in interest during the same period.

Note 10 —Subsequent Events

Restricted Stock Granted to an Officer

In connection with the approval by the shareholders in May 2007 of the 2007 Equity Incentive Plan, in July 2007 the Board of Directors awarded 120,000 restricted shares of our common stock to our President and COO.  Under the award agreement, the shares will vest based on the satisfaction of certain performance measures over the next three years.

Release of Restricted Cash under the Pennaco Energy, Inc. (“Pennaco”) Agreement

In July 2007, Pennaco released $2,000,000 of restricted cash plus interest in accordance with the Purchase and Sale Agreement between Pennaco and us in connection with a portion of the plugging liability for wells acquired from Pennaco, in June 2006.  This cash is currently available as additional general corporate working capital.

11

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

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

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, including those listed under item 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2006.

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

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

General Overview

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

First Six Months of 2007 - Operational and Financial Highlights

During the first six months of 2007, we had minimal new drilling activities, as we concentrated on dewatering the Wyoming coal-bed methane (“CBM”) wells and preparing the Colorado Niobrara drilling program for the second half of this year.  We had 220 gross (179 net) CBM wells in Wyoming and 9 gross/net Niobrara wells in Colorado producing commercial gas.  In Wyoming, we also had 80 gross (63 net) CBM wells in the dewatering stage.  We sold 149,000 thousand cubic feet (“Mcf”) of gas in Wyoming and 52,000 Mcf in Colorado, which resulted in sales of $571,000 and $188,000, respectively.  Our gathering operations generated revenues of $872,000 for the same period of 2006.

For the first half of 2007, we had a net loss of $8.4 million.  Nearly half of this loss was due to interest expense and amortized costs related to the debt previously incurred in 2006.  These expenses for the first six months consisted of three main categories.  The first category is the interest payments for the Senior Subordinated Convertible Notes (“Notes”) and Senior Secured Debentures (“Debentures”) of $2,071,000.  A second category consists of discount and debt issuance costs related to the Notes and Debentures amortized for $1,550,000.  The last category was $555,000 of interest expense associated with a capital lease obligation, less

12

---

 $159,000 of capitalized interest related to drilling costs of wells.  (See Note 5 of Part I in this Quarterly Report on Form 10-Q.)

The balance of the net loss for the six months was primarily due to our inability to produce or gather gas during severe winter weather conditions and other mechanical problems.  The weather problems affected our Wyoming properties early in the first quarter of 2007 due to water freezing in the gathering lines.  Also, a reciprocating compressor had mechanical problems interrupting gas gathering operations.  These production problems were substantially remedied by the end of the second quarter.  In addition, the average realized price per Mcf for Wyoming and Colorado properties combined declined $.96 or 22% from the first to second quarters of 2007, or $4.27 to $3.31, respectively.  The six-month average realized price for this period of $3.77 per Mcf reflected the downward trend of the basin price index during the second quarter.  The regional Powder River Basin basis differential (discount from Henry Hub gas market pricing index) based on our CIG price index ranged between $1.00 to $2.00 in the first quarter and was further eroded to a range of $3.00 to $5.00 differential in the second quarter.

In the first quarter, we entered into a five-year lease agreement with J-W Power Company (“J-W Power”) in January 2007.  Under the terms of the agreement, J-W Power will supply us with gas compression equipment and related services.  The compression equipment will service our gas gathering pipelines in the Powder River Basin.

In May 2007, we announced that we had reached a settlement with Rocky Mountain Gas Inc. (“RMG”) and terminated the previously reported arbitration proceedings.  RMG agreed to pay PRB $3,250,000 total, represented by two cash payments of $500,000 made on May 22nd and June 21st, 2007, with the balance due on October 31, 2007.  Both cash payments were received on the scheduled dates by PRB.  A promissory note dated June 1, 2007 (the “RMG Note”) for the remaining balance was also received from RMG.  The RMG Note bears an interest rate of 10% per annum and is secured by a mortgage.

In addition as of June 1, 2007, RMG assigned to us all of its interests, including infrastructure, in the Moyer coal-bed methane wells located in Section 19, T48N, R71W, adjacent to PRB’s acreage in .  In turn, we assigned to RMG all of our interests (other than Section 19) in the acreage and wells (“PRB Assets”) originally included in the farmout agreement with RMG.

We will recognize a total reported gain from this settlement of $1,267,000 over the second through fourth quarters of this year.  As cash is received, a proportion of the total gain will be recognized in the financial statements.  The portion of the gain including interest from this settlement that is reflected for the first six months of 2007 is $384,000.

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

Results of Operations

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

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

13

---

 

								Increase /			Percentage
		Quarter Ended June 30,						(Decrease)			Change
(Dollars in thousands)		2007			2006			2007 v 2006			2007 v 2006
Revenue
Natural gas sales		$	346		$	48		$	298			*
Gas gathering and processing		364			603			(239		)	(40	)%
Other		10			52			(42		)	(81	)%
Total revenue		720			703			17			2	%
Natural gas gathering expenses and taxes		(84		)	(20		)	(64		)		*
Net revenue		636			683			(47		)	(7	)%
Operating expenses
Natural gas lease operating		612			—			612				*
Gas gathering and processing operations		593			648			(55		)	(8	)%
General and administrative		1,194			1,129			65			6	%
Depreciation, depletion and amortization		951			336			615			183	%
Other expense		—			48			(48		)		*
Total expenses		3,350			2,161			1,189			55	%
Operating loss		(2,714		)	(1,478		)	(1,236		)	(83	)%
Interest and other income (expense), net		(1,214		)	(340		)	(874		)		*
Net loss		$	(3,928	)	$	(1,818	)	$	(2,110	)	(116	)%

 

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

Revenues

The $298,000 increase in natural gas sales over 2006 was substantially offset by the $239,000 reduction in gas gathering fees no longer received from Pennaco as a result of the acquisition from Pennaco in June 2006. During the second quarter of 2006, we also had Other Revenue of $52,000 for management fees, but none in 2007, because the RMG agreement ended on June 30, 2006.

Natural Gas Lease Operating Expenses

Natural gas lease operating expenses in 2007 increased $612,000 over 2006 as a result of the field operations acquired in mid 2006.  We substantially increased field operations over the same period last year as a result of the Pennaco (Wyoming) and D-J Basin (Colorado) acquisitions.

Gas Gathering and Processing Operations Expenses

Gas gathering and processing operations expenses decreased $55,000, or 8%, for the current quarter compared to last year’s quarter primarily due to the January 2007 capital lease agreement and to reduced third-party services.

General and Administrative Expenses

General and administrative (“G&A”) expenses increased over 2006 by $65,000, or 6%, due to employee compensation and benefits increasing as a result of employees added in response to an increase in operations, offset by recoveries of expenses allocated to operational projects, including $200,000 of G&A recovery related to the design and engineering services for a processing plant for a third party.

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

DD&A expense in 2007 increased $615,000, or 183%, as a result from the acquired properties in mid and late 2006.

Interest and Other Income and Expense

Interest expense for the quarter ending June 30, 2007 increased $1,412,000, three times over 2006 due to (1) interest payments on Debentures and capital lease and (2) amortization of the debt issuance costs and the

14

---

discount on Debentures.  The interest increase was partially offset by the gain on the sale of the RMG assets of $343,000, net of a loss of approximately $100,000 on the sale of other gathering assets, and other income of $427,000 for the design and engineering services related to a processing plant for a third party, net of a reduction of interest income of approximately $120,000.

Six months ended June 30, 2007 (unaudited) compared to the six months ended June 30, 2006 (unaudited)

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

								Increase /			Percentage
		Six Months Ended June 30,						(Decrease)			Change
		2007			2006			2007 v 2006			2007 v 2006
		(Dollars in thousands)
Revenue
Natural gas sales		$	759		$	106		$	653			*
Gas gathering and processing		872			1,278			(406		)	(32	)%
Other		14			146			(132		)	(90	)%
Total revenue		1,645			1,530			115			8	%
Natural gas gathering expenses and taxes		(180		)	(39		)	(141		)		*
Net revenue		1,465			1,491			(26		)	(2	)%
Operating expenses
Natural gas lease operating		1,273			—			1,273				*
Gas gathering and processing operations		1,026			1,217			(191		)	(16	)%
General and administrative		2,794			2,146			648			30	%
Depreciation, depletion and amortization		1,806			656			1,150			175	%
Other expense		— 0			223			(223		)		*
Total expenses		6,899			4,242			2,657			63	%
Operating loss		(5,434		)	(2,751		)	(2,683		)	(98	)%
Interest and other income (expense), net		(2,924		)	(561		)	(2,363		)		*
Net loss		$	(8,358	)	$	(3,312	)	(5,046		)	(152	)%

 

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

Revenues

Total revenues increased $115,000, or 8%, for the six months ended June 30, 2007 compared to last year’s results of natural gas sales from the Pennaco properties acquired in mid 2006.  The $653,000 increase in natural gas sales was substantially offset by the $406,000 reduction of gas gathering fees no longer received from Pennaco as a result of the acquisition from Pennaco in June 2006. Other Revenue included management fees of $146,000 during the first two quarters of 2006, but none in 2007, because the RMG agreement ended on June 30, 2006.

Natural Gas Lease Operating Expenses

Natural gas lease operating expenses in 2007 increased $1,273,000 over 2006 as a result of the field operations acquired in mid 2006.  We substantially increased field operations over the same period last year as a result of the Pennaco (Wyoming) and D-J Basin (Colorado/Nebraska) acquisitions.

Gas Gathering and Processing Operations Expenses

Gas gathering and processing operations expenses decreased $191,000, or 16%, for the six months ended June 30, 2007 compared to last year’s results primarily due to the January 2007 capital lease agreement and to reduced third-party services.

15

---

General and Administrative Expenses

General and administrative expenses increased over 2006 by $648,000, or 30%, due to employee compensation and benefits increasing as a result of employees added in response to an increase in operations, offset by recoveries of expenses allocated to operational projects, including $200,000 of G&A recovery related to the design and engineering services for a processing plant for a third party.

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

DD&A expense in 2007 increased $1,150,000, or 175%, as a result of properties acquired in mid and late 2006.

Interest and Other Income and Expense

Interest expense for the six months ending June 30, 2007 increased $2,985,000, nearly four times over 2006 due to (1) interest payments on convertible Notes, Debentures and a capital lease and (2) amortization of the debt issuance costs and the discount on Debentures.  The interest increase was partially offset by the gain on the sale of the RMG assets of $343,000, net of a loss of approximately $100,000 on other gathering assets, and other income of $427,000 for the design and engineering services related to a processing plant for a third party, net of a reduction of interest income of approximately $45,000.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

At June 30, 2007, cash and cash equivalents totaled $2.9 million.  Additionally, we have $3.1 million of restricted cash, of which $2.1 million is classified as a current asset and $1.0 million as a non-current asset.  The $3.1 million collateralizes a reducing letter of credit issued in connection with potential plugging liabilities of Wyoming properties acquired in June 2006.  In July 2007, $2.0 million of the restricted cash plus interest was released under the terms of the letter of credit.  The remaining $1.0 million of restricted cash will be released on or before June 30, 2009.  At June 30, 2007, working capital, excluding the restricted cash, was $4.5 million.

In 2006, we raised approximately $22 million by issuing the Notes and $15 million, before expenses, by issuing the Debentures.  These funds have been utilized in the exploitation, development and acquisition of properties in Wyoming and Colorado and will provide for the further development of these areas.

We believe that our cash and cash equivalents on hand, internally generated cash flows and future financing activities will require augmentation from bank financing, asset sales or other equity or debt financing to fund our operations, planned drilling, acquisition and other capital expenditures in the future.  The amount and allocation of future capital and exploitation expenditures will depend upon a number of factors including the number and size of acquisitions and drilling opportunities, our cash flows from operating and financing activities and our ability to assimilate acquisitions.  Also, the impact of oil and gas market prices on investment opportunities, the availability of capital and borrowing facilities and the success of our exploitation and development activities, particularly in Colorado, could lead to changes in funding requirements for future development.  If we failed to secure financing for the future development, we would pursue other financial arrangements through joint venture partners, farm-out agreements or the sale of assets.

Cash Flow Used in Operating Activities

During the six months ended June 30, 2007, our net loss of $8.4 million included non-cash charges of $1.8 million of DD&A expense, $1.5 million of interest expense resulting from amortization of debt issuance costs and discount on the Debentures and $417,000 of share-based compensation expense.

Cash used in operating activities of $6.5 million during the six months of 2007 was $3.8 million greater than the same period of 2006.  This increase was mainly attributable to higher debt interest payments, general and administrative expenses due to staff increases and increased field operations of acquired and developed gas properties.

Cash Flow Used in Investing Activities

Cash used in investing activities was $2.5 million during the six months ended June, 30 2007 representing a 72% decrease of $6.8 million compared to 2006.   The primary reasons for the reduction were the removal of

16

---

the $3.0 million of restricted cash from available cash balances in 2006, and approximately $3.6 million in reduced drilling and gathering activities in the first half of this year compared to last year.

At June 30, 2007, wells in progress consisted of 80 gross (63 net) CBM wells in various stages of completion.  None of these wells are in an area requiring major capital expenditures before production may begin, nor were any of these wells completed more than one year ago.  These wells are being completed or are undergoing de-watering processes.  We believe that after the wells have been de-watered, we will be able to commence production.

Currently, our 2007 capital expenditures are expected to approximate $21 million, of which $19 million will be related to gas exploitation and development prospects and approximately $2 million to gas gathering system projects.  We spent approximately $1 million, net, during the first six months of 2007, with approximately $18 million in the second half of this year primarily earmarked for the gas exploitation drilling program in the northeastern Colorado D-J Basin.

Cash Flow from Financing Activities

Cash provided by financing activities was $900,000 for the six months ended June 30, 2007, or a reduction of $20 million from 2006.  During the first quarter of 2006, we raised $22 million from the issuance of Notes and incurred approximately $1 million in debt issuance costs, excluding the value of warrants issued.  The 2007 financings included the RMG settlement proceeds received of $1 million, offset by additional Debenture costs totaling $135,000.

Off Balance-Sheet Arrangements.

We do not have any off-balance sheet financing arrangements as of June 30, 2007, except for our Storm Cat gas gathering services agreement (“Agreement”).  The Agreement requires Storm Cat to pay us gas gathering fees on specific minimum volumes of gas, whether or not those volumes are delivered and transported through our system.  The Agreement has a 10-year term expiring January 2016, with certain minimum payments during the first 3 years of the Agreement.  The Agreement allows for a cash true-up payment at each year-end if the annual volume commitment under the Agreement is not met.

Critical Accounting Policies and Estimates

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

ITEM 3:    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4:    CONTROLS AND PROCEDURES

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

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

17

PART II OTHER INFORMATION

ITEM 1:    LEGAL PROCEEDINGS

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

On May 15, 2007, we reached a settlement with RMG and terminated the previously reported arbitration proceedings.  RMG agreed to pay us $3,250,000.  In addition, as of June 1, 2007, RMG assigned to us all of its interests, including infrastructure, for the Moyer CBM wells located in Section 19, T48N, R71W, adjacent to PRB’s acreage.  In turn, we assigned to RMG all of our interests (other than Section 19) in the acreage originally included in the farmout agreement with RMG.

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 Item 1A of our 2006 Annual Report on Form 10-K.  See also “Forward-Looking Statements” included in Part I, Item 2 of this Quarterly Report on Form 10-Q.

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

None.

ITEM 3: DEFAULTS UPON SENIOR SECURITIES

None.

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

On May 31, 2007 the Company held its 2007 Annual Meeting of Shareholders.  Each of the following persons was elected a director of the Company for one-year terms expiring at the earlier of the 2008 Annual Meeting of Stockholders or upon a successor being elected and qualified:

Name		Votes For		Votes Withheld
Gus J. Blass III		7,933,245		120,806
William F. Hayworth		7,933,245		120,806
Reuben Sandler		7,918,645		135,406
James P. Schadt		7,919,645		134,406
Robert W. Wright		7,943,245		110,806
Paul L. Maddock, Jr.		7,928,645		125,406
Sigmund J. Rosenfeld		7,921,145		132,906

 

The shareholders of the Company also approved the adoption of the Company’s 2007 Equity Incentive Plan.  The voting results were as follows:

Votes For:	4,453,510
Votes Against:	375,252

 

18

---

 

Votes Abstain:	14,200
Broker Nonvotes:	3,211,089

 

ITEM 5: OTHER INFORMATION

None.

19

---

ITEM 6:    EXHIBITS

Exhibit
Number		Description
(3.1)		Amended Articles of Incorporation of the Registrant (filed as an exhibit to Form S-1/A filed on January 28, 2005 and incorporated by reference herein).
(3.3)		Amended By-laws of the Registrant (filed as an exhibit to Form S-1/A filed on January 28, 2005 and incorporated by reference herein).
(4.5)		Form of Common Stock Certificate (filed as an exhibit to Form 8-A filed on April 8, 2005).
(4.6)		Form of Senior Subordinated Convertible Note (filed on annual Form 10-K filed on April 14, 2006 and incorporated by reference herein).
(4.7)		Form of Registration Rights Agreement between the Company and the holders of the Company’s Senior Subordinated Convertible Notes (filed on annual Form 10-K filed on April 14, 2006 and incorporated by reference herein).
(4.8)		Form of Senior Secured Debentures (filed as an exhibit to Form 8-K filed on January 5, 2007 and incorporated by reference herein)
(4.9)		Pledge and Security Agreement, dated as of December 28, 2006, by and among PRB Energy, Inc., PRB Oil & Gas, Inc., PRB Gathering, Inc., and the Secured Parties named therein (filed as an exhibit to Form 8-K filed on January 5, 2007 and incorporated by reference herein)
(4.10)		Secured Guaranty, dated as of December 28, 2006, made by PRB Energy, Inc. and PRB Gathering, Inc. (filed as an exhibit to Form 8-K filed on January 5, 2007 and incorporated by reference herein)
(4.11)		Registration Rights Agreement, dated as of December 28, 2006, by and among PRB Energy, Inc. and the Buyers named therein (filed as an exhibit to Form 8-K filed on January 5, 2007 and incorporated by reference herein)
10.24a		RMG Settlement Agreement between PRB Energy, Inc. and Rocky Mountain Gas Inc., dated May 15, 2007
10.24b		RMG Settlement Agreement between PRB Energy, Inc. and Rocky Mountain Gas Inc., dated May 16, 2007
10.25		Letter agreement between PRB Energy, Inc and DKR Soundshore Oasis Holding Fund Ltd. along with West Coast Opportunity Fund, LLC dated June 15, 2007
31.1		Chief Executive Officer Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Principal Financial Officer Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Chief Executive Officer and Principal Financial Officer Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

These exhibits are available upon request.  Exhibits identified in parentheses above 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.

20

---

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.

	PRB Energy, Inc.
	(Registrant)
	By:	/s/ Robert W. Wright
		Name: Robert W. Wright
		Title: Chairman and Chief Executive Officer
	By:	/s/ Daniel D. Reichel
		Name: Daniel D. Reichel
		Title: Vice President—Finance and Treasurer
		(Principal Financial Officer)
Dated: August 14, 2007

 

21