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 September 30, 2006
Or
o		TRANSITION REPORT PURSUANT TO  SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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     Accelerated filer     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					19
Item 1.			Legal Proceedings		19
Item 1A.			Risk Factors		19
Item 2.			Unregistered Sales of Equity Securities and Use of Proceeds		19
Item 3.			Defaults Upon Senior Securities		19
Item 4.			Submission of Matters to a Vote of Security Holders		19
Item 5.			Other Information		19
Item 6.			Exhibits		20
			Signatures		22

 

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)

		September 30, 2006			December 31, 2005
		(Unaudited)			**
Assets
Current assets:
Cash and cash equivalents		$	12,292		$	6,434
Restricted cash		3,039			—
Accounts receivable		1,490			789
Inventory		929			1,346
Prepaid expenses		779			194
Total current assets		18,529			8,763
Oil and gas properties - successful efforts method of accounting:
Proved properties		5,542			317
Unproved leaseholds		328			136
Wells-in-progress		4,781			1,081
Total oil and gas properties		10,651			1,534
Less: accumulated depreciation, depletion and amortization		(376		)	(3		)
Net oil and gas properties		10,275			1,531
Gathering and other property and equipment		9,437			6,992
Less: accumulated depreciation and amortization		(1,636		)	(968		)
Net gathering and other property and equipment		7,801			6,024
Other non-current assets:
Deferred debt issuance costs		1,143			—
Less: accumulated amortization		(267		)	—
Net deferred debt issuance costs		876			—
Other non-current assets		1,220			1,122
Total other non-current assets		2,096			1,122
TOTAL ASSETS		$	38,701		$	17,440
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable		$	1,633		$	1,652
Accrued expenses and other current liabilities		1,498			107
Total current liabilities		3,131			1,759
Subordinated convertible notes and other debt, less current portion		21,975			17
Other non-current liabilities		2,839			407
Total liabilities		27,945			2,183
Commitments and Contingencies
Stockholders’ equity:
Capital, 50,000,000 shares authorized, par value $0.001, 5,639,000 shares undesignated; Series C Convertible Preferred, 4,361,000 shares authorized; 0 and 40,000 issued and outstanding, respectively		—					*
Common stock, 40,000,000 shares authorized; 8,261,894 issued; 7,471,894 and 7,431,894 outstanding, respectively		8			8
Treasury stock		(800		)	(800		)
Additional paid-in-capital		21,902			21,325
Accumulated deficit		(10,354		)	(5,276		)
Total stockholders’ equity		10,756			15,257
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	38,701		$	17,440

 

*                      amounts less than one thousand

**               derived from audited balance sheet at December 31, 2005

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

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PRB ENERGY, INC.

Consolidated Statements of Operations

(In thousands, except share amounts)

(Unaudited)

		Three Months Ended September 30,						Nine Months Ended September 30,
		2006			2005			2006			2005
Revenues:
Gas gathering and processing		$	314		$	658		$	1,592		$	2,214
Natural gas sales		776			—			882			—
Other		8			66			154			66
Total revenues		1,098			724			2,628			2,280
Operating expenses:
Production taxes		88			—			104			—
Gas gathering and processing		425			418			1,681			1,293
Natural gas lease operating		580			—			737			—
Depreciation, depletion, amortization and accretion		759			281			1,415			838
General and administrative		977			584			3,123			1,311
Impairment and other expense		—			2,372			50			2,372
Total operating expenses		2,829			3,655			7,110			5,814
Operating loss		(1,731		)	(2,931		)	(4,482		)	(3,534		)
Other income (expense):
Interest and other income		583			63			1,054			111
Interest expense		(618		)	—			(1,650		)	(49		)
Net loss		(1,766		)	(2,868		)	(5,078		)	(3,472		)
Convertible preferred stock dividends		—			—			—			(205		)
Net loss applicable to common stockholders		$	(1,766	)	$	(2,868	)	$	(5,078	)	$	(3,677	)
Net loss per share — basic and diluted		$	(0.24	)	$	(0.40	)	$	(0.68	)	$	(0.54	)
Basic and diluted weighted average shares outstanding		7,471,894			7,160,050			7,458,708			6,805,621

 

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

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PRB ENERGY, INC.

Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

		Nine Months Ended
		September 30,
		2006			2005
Cash flows from operating activities:
Net loss		$	(5,078	)	$	(3,472	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depreciation, depletion, amortization and accretion		1,465			838
Asset impairment charge		—			2,372
Amortization of debt issuance costs		267			—
Share-based compensation expense		415			—
Warrants issued for services rendered		70			—
Capitalized interest		(77		)	—
Gain on sale of gathering assets		(311		)	—
Changes in assets and liabilities:
Accounts receivable		(701		)	(1,082		)
Inventory		417			—
Prepaid expenses		(585		)	(44		)
Other non-current assets		(190		)	(35		)
Accounts payable		(19		)	1,012
Accrued expenses and other current liabilities		947			105
Deferred Revenue		44			—
Other non-current liabilities		261			—
Net cash used in operating activities		(3,075		)	(306		)
Cash flows from investing activities:
Capital expenditures		(4,362		)	(584		)
Acquisition of natural gas properties and gathering facilities		(4,922		)	(608		)
Restricted cash related to future liabilities of acquired properties		(3,039		)	—
Sale of gathering assets		350			—
Net cash used in investing activities		(11,973		)	(1,192		)
Cash flows from financing activities:
Proceeds from convertible notes		21,965			—
Issuance costs related to convertible notes		(1,051		)	—
Proceeds from IPO, net of issuance costs		—			11,007
Borrowings under bank loan		—			50
Repayment of proceeds from bank loan		—			(1,550		)
Dividends		—			(338		)
Repayment of term loan		(8		)	—
Net cash provided by financing activities		20,906			9,169
Net increase in cash		5,858			7,671
Cash—beginning of period		6,434			320
Cash—end of period		$	12,292		$	7,991
Supplemental disclosure of cash flow activity
Cash paid for interest		$	1,369		$	49
Supplemental schedule for non-cash activity
Issuance of warrants in connection with public offering		—			$	571
Issuance of warrants in connection with convertible notes		$	92		—
Conversion of Series A,B and C preferred stock		—			$	4
Capital remediation costs		$	1,056		—
Asset retirement obligations		$	2,085		—

 

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

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PRB ENERGY, INC.

Notes to Consolidated Financial Statements

September 30, 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 and oil. In addition, we provide gas gathering, processing and compression services for properties we operate and for third party producers. PRB was initially formed under the name “PRB Transportation, Inc.” in December 2003, and was incorporated in the State of Nevada. On June 14, 2006, PRB’s name was changed to “PRB Energy, Inc.” PRB’s common shares are traded on the American Stock Exchange under the ticker symbol “PRB.” PRB conducts its primary business activities in Wyoming.  PRB operates through two wholly-owned subsidiaries, PRB Oil and Gas, Inc., an oil and gas exploration and production company and PRB Gathering, Inc., a gathering and processing company.

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 September 30, 2006, and for the three and nine months ended September 30, 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. Such reclassifications had no effect on the 2005 net loss. In the opinion of management, these interim financial statements contain all adjustments which are of a normal, recurring nature to fairly present the financial position of PRB as of September 30, 2006 and the results of our operations and cash flows for the nine months ended September 30, 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:

		Nine Months Ended September 30,
		2006		2005
Series C Convertible Preferred		—		411,000
Warrants		300,000		245,000
Options		625,875		390,000
Convertible notes		3,137,857		—
Total potentially dilutive shares excluded		4,063,732		1,046,000

 

Concentrations of Credit Risk

We grant credit in the normal course of business to customers in the United States. Management periodically performs a credit analysis and monitors the financial condition of our customers to reduce credit risk.  Management periodically reviews accounts receivable and reduces the carrying amount by a valuation allowance that reflects management’s best estimate of the amount that may not be collectible.  Allowances for uncollectible accounts receivable are based on information available and historical experience.  As of September 30, 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 and nine months ended September 30, 2006 and 2005 were as follows:

		For the three months ended				For the nine months ended
		September 30,				September 30,
Customer		2006		2005		2006		2005
		(% of total revenue)				(% of total revenue)
A — Exploration and production		58.2	%	—		24.3	%	—
B — Gathering and Processing		—		46.3	%	—		—
C — Gathering and Processing		18.1	%	—		16.3	%	—
D — Gathering and Processing		—		—		24.0	%	51.7	%

 

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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 September 30, 2006 were $876,000 and are being amortized using the effective interest rate method over the life of the Notes.

Note 2—Acquisitions and Significant Contracts

Acquisitions

Recluse gathering system

In the first quarter of 2006, we acquired two gas gathering systems in the Recluse area of Wyoming (together our “Recluse” gathering system) for approximately $1.5 million. Also, in two separate transactions totaling $183,000, we acquired a combination of working interests ranging from 7.5% to 15% in the development of approximately 5,600 net acres in the Recluse and Gap areas that offer us the opportunity to expand both our exploration and production and gas gathering and processing activities.

On August 4, 2006, we closed an acquisition from Maverick Pipeline LLC of approximately 70 miles of gathering lines in the Recluse area which will provide additional opportunities for expanding gathering services to producers in the 100,000 acres surrounding the pipelines. The transaction was effective August 1, 2006, and the $428,000 purchase price was paid in cash.

Pennaco wells

On June 30, 2006, we acquired working interests in approximately 580 gross (529 net) coal-bed methane wells on approximately 29,000 acres located in the Powder River Basin of Wyoming from Pennaco Energy, Inc. (“Pennaco”). The purchase price of the acquired interests was approximately $600,000 and the effective date was July 1, 2006. As part of the purchase agreement, we issued a $3 million reducing letter of credit to the benefit of Pennaco to guarantee the funding of the future liability of the plugging costs of wells being purchased from Pennaco. The asset retirement obligation of these wells has been recorded on the balance sheet for $2 million based on the discounted present value of the future liability, as further reflected in Note 3. The letter of credit is collateralized by a $3 million certificate of deposit (“CD”), and is considered restricted cash for purposes of available working capital. The restricted amount of the CD will be released at the same rate annually that the letter of credit is reduced (refer to management’s discussion on Liquidity and Capital Resources in the Management’s Discussion and Analysis section in this report).

Of the 580 gross wells acquired, fewer than 150 wells were commercially producing natural gas. We currently have approximately 220 wells on production and plan to bring an additional 230 shut-in wells back on production, which will require additional capital expenditures. In this regard, an estimate of these capital expenditures by our technical staff of $1.5 million has been included in the 2006 capital budget and was accrued in oil and gas properties in the balance sheet.

Sale of TOP gathering system

As of September 1, 2006 we sold certain gas gathering assets referred to as the TOP Gathering System to Arete Industries, Inc. for $330,000 in cash.  The net gain on the sale of $308,000 is reflected in Other Income in the September 30, 2006 financial statements.

Significant Contracts

Storm Cat Agreement

Effective January 1, 2006, we entered into a gas gathering services agreement (“Agreement”) with Storm Cat, which 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, of which the first five years are noncancelable. The Agreement requires Storm Cat to pay us a minimum of $972,000 in 2006 and an aggregate minimum of $3.1 million in gas gathering fees during the first three years of the Agreement.  The Agreement also provides for our gas gathering rates to decrease during the fourth and fifth years.

During the nine months ended September 30, 2006, we billed Storm Cat $420,000 in gas gathering fees for actual volumes delivered. The Agreement allows for a cash true-up payment at each year-end if the annual volume commitment under the Agreement is not met. We recognize revenues based on our estimate of the average gas gathering rate during the noncancelable term of the Agreement. Accordingly, we deferred $44,000 of gas gathering fees as a non-current liability on our balance sheet at September 30, 2006.

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Rocky Mountain Gas Agreement

 

On March 20, 2006, PRB terminated a Farmout and Development Agreement dated August 1, 2005 (“Farmout Agreement”) with Enterra Energy Trust’s wholly-owned subsidiary Rocky Mountain Gas, Inc. (“RMG”).  We are also the designated field operator under a Joint Operating Agreement (“JOA”) with RMG for certain coal-bed methane properties in Wyoming and Montana that are covered by the JOA.  In February 2006, RMG executed 19 authorizations for expenditure to drill and complete the Moyer coal pilot wells. After termination of the Farmout Agreement, PRB, as operator under the JOA, issued a cash call to RMG for RMG’s share of the estimated well costs for nine wells. In addition, after termination of the Farmout Agreement, RMG requested its full working interest in all wells drilled after the termination date. As of March 31, 2006, the outstanding amount due from RMG was $713,000, which we classified as an account receivable.

PRB did not receive payment from RMG for the well costs as required under the JOA and issued a notice of default to RMG.  The default was not cured within the period prescribed by the JOA and, under the JOA, RMG’s interest was relinquished to PRB until the proceeds from the nine Moyer wells equal 300% of the capital expenditures by PRB on RMG’s behalf.  As a result, we reclassified the $713,000 account receivable from RMG as additional costs of oil and gas properties on our June 30, 2006 balance sheet.

On June 22, 2006, RMG filed an arbitration demand against PRB, asserting that the area of mutual interest provision in the terminated Farmout Agreement continues until August 2007 and, therefore, includes the Pennaco acquisition and that we should pay 100% of the costs of drilling the nine Moyer wells for a 50% working interest.  On August 22, 2006, PRB denied RMG’s arbitration claims, and asserted counterclaims against RMG.  The arbitration is scheduled for February 2007.  At this time, we cannot predict the outcome of the arbitration.

We also agreed upon termination of the Farmout Agreement to continue to provide management services until June 30, 2006.  As of June 30, 2006, we had a receivable due from RMG of $386,000 for management services rendered and certain other amounts due from RMG. RMG disputed the amounts due to us. In July 2006, PRB and RMG entered into an interim agreement under which, among other things, RMG paid us $175,000 of the amount due at June 30, 2006.  The remainder of the amount due is to be settled after a review is jointly completed by RMG and PRB of the transactions covered by the agreement.  It is anticipated that this review will be completed by December 31, 2006.  Any remaining disputed expenses will be presented for resolution at the February 2007 arbitration.  No reserve against this remaining balance has been recorded at September 30, 2006, as we believe the balance to be fully collectible.

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 nine months ended September 30, 2006 and 2005, is as follows:

		Nine Months Ended
		September 30, 2006			September 30, 2005
		(In thousands)
Asset retirement obligation, beginning of period		$	387		$	65
Acquisition of Recluse system		70			—
Acquisition of Proved properties		27			—
Acquisition of Pennaco wells		2,000			—
Acquisition of True		170			—
Accretion		189			4
Reclamation expenditures		(69		)	—
Asset retirement obligation, end of period		$	2,774		$	69

 

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Note 4—Borrowings

 

As of September 30, 2006 and December 31, 2005, our borrowings consisted of the following:

		September 30, 2006			December 31, 2005
		(In thousands)
Senior subordinated convertible notes		$	21,965		$	—
Other term loans		20			27
		21,985			27
Less current portion		(10		)	(10		)
Total long-term borrowings		$	21,975		$	17

 

Senior Subordinated Convertible Notes

In March 2006, we issued a total principal amount of approximately $22 million in Notes in a private placement. 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. A registration statement applicable to the shares of common stock underlying the Notes was filed in May 2006 and declared effective on June 21, 2006. The Notes do not contain any beneficial conversion features.

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 nine months ended September 30, 2006, we incurred $1.460 million in total interest expense applicable to the Notes.

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 the event that our common stock trades at $14.00 per share or above for 10 consecutive days, we have a call provision that 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. 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.

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 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 are not accounted for as derivatives on our consolidated balance sheet at September 30, 2006.

Note 5—Equity Compensation Plan

We have an Equity Compensation Plan (“Option Plan”) that permits us to grant 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 121,314 shares available for grant under the Option Plan as of September 30, 2006.

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The following table summarizes activity for options:

		Nine Months Ended September 30, 2006					Nine Months Ended September 30, 2005
		Number of Shares		Weighted Avg. Exercise Price			Number of Shares		Weighted Avg. Exercise Price
Outstanding at January 1,		463,250		$	6.74		220,000		$	5.50
Granted		314,250		6.08			230,000		7.86
Forfeited		(151,625	)	7.21			(37,500	)	6.17
Exercised		—		—			—		—
Outstanding at September 30,		625,875		$	6.40		412,500		$	6.75
Exercisable at September 30,		296,875		$	6.46		181,250		$	6.38

 

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 nine months ended September 30, 2006 was $3.68.  The weighted average remaining contractual life for the options outstanding at September 30, 2006 is 6.7 years.   The weighted average remaining contractual life for the options exercisable at September 30, 2006 is 2.4 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 over the vesting period for all share-based payments granted after the effective date and for all unvested awards granted prior to the effective date. In accordance with SFAS No. 123(R), prior period amounts were not restated. During the nine months ended September 30, 2006, we recorded share-based compensation expense of $415,000, which was recognized in general and administrative expense with a corresponding credit to additional paid-in-capital. Of the $415,000, $102,000 was related to unvested options granted prior to January 1, 2006. Compensation expense related to unvested options granted, but not yet recognized as of September 30, 2006, was $928,000. We expect to recognize this compensation expense over the vesting period.  The weighted-average vesting period is 2.4 years.

Prior to the effective date of SFAS No. 123R, 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 nine months ended September 30, 2005, is illustrated in the following table:

 

		Three Months Ended			Nine Months Ended
		September 30, 2005			September 30, 2005
		(In thousands)			(In thousands)
Net loss applicable to common stockholders:
As reported		$	(2,868	)	$	(3,677	)
Less: Total share-based employee compensation expense determined under fair value-based method for all awards, net of related tax effects		49			372
Pro-forma net loss		$	(2,917	)	$	(4,049	)
Net loss per share, basic and diluted:
As reported		$	(.40	)	$	(.54	)
Pro-forma		$	(.41	)	$	(.59	)

 

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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 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 nine months ended September 30, 2006 and 2005:

		SFAS No. 123(R) Expense		SFAS No. 123 Pro-Forma
		Nine Months Ended		Nine Months Ended
		September 30, 2006		September 30, 2005
Expected life of options		2.4 — 6.7 years		5 — 10 years
Expected volatility		80	%	25	%
Risk-free interest rate		4.31 — 5.23	%	3.89 — 4.73	%
Expected dividend yield of stock		0	%	0	%

 

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 makers view results. We consider our chief executive officer and our chief operating officer as our chief operating decision makers. 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 nine months ended September 30, 2006, as earlier described. We charge a fee to our customers for these 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 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 cancelable purchase commitments with third party providers for future field operations, equipment and maintenance activities.

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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 nine months ended September 30, 2006, our exploration and production segment operated in the Powder River Basin area of Wyoming.

Through a management services agreement with RMG, we earned management fee revenues that we have included under Corporate in the following table that details the performance of our segments.  In March 2006, we elected to terminate the management services agreement; however, we agreed to continue to provide services under the agreement through June 30, 2006.

		Three Months Ended September 30, 2006
		Gathering and Processing			Exploration and Production			Corporate			Total
		(In thousands)
Revenues		$	484		$	776		$	(162	)	$	1,098
Net income (loss) attributable to common stockholders		$	57		$	5		$	(1,828	)	$	(1,766	)

 

		Nine Months Ended September 30, 2006
		Gathering and Processing			Exploration and Production			Corporate			Total
		(In thousands)
Revenues		$	1,908		$	882		$	(162	)	$	2,628
Net loss attributable to common stockholders		$	(363	)	$	(515	)	$	(4,200	)	$	(5,078	)
Identifiable assets:
Property and equipment, net		$	7,312		—			$	489		$	7,801
Oil and gas properties, net		—			$	10,275		—			$	10,275
Other non-current assets		$	1,002		—			$	218		$	1,220

 

The majority of our operations were in only one segment during the nine months ended September 30, 2005 and our management reviewed the results of our operations as a single segment during that period.

Note 7— Related Party Transactions

Susan Wright, our corporate secretary and wife of our chief executive officer, provides corporate secretary services to us on a contract basis. During the nine months ended September 30, 2006 and 2005, Mrs. Wright was paid $68,000 and $15,500, respectively, for contract services.

In January 2006, we issued 40,000 warrants to a former director for services rendered in respect to our offering of the Notes. These warrants immediately vested with an exercise price of $7.00 per share.  We recorded $92,000 as the estimated 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 two of our directors purchased $100,000 and $1.2 million, respectively, of the Notes that were issued in March 2006. During the nine months ended September 30, 2006, we have paid interest of $5,944 and $78,389, respectively, on these Notes.  In addition, a former director purchased $1 million of the Notes and was paid interest of $61,668 during this same period.

Note 8 —Subsequent Events

On October 13, 2006, the Board of Directors authorized the repurchase of up to 10%, or approximately 750,000 shares, of the Company’s outstanding common stock. The stock repurchase authorization is effective immediately and continues through the end of 2006. The repurchases will be made from time to time in open market or in negotiated transactions in such amounts as determined at the discretion of the Company’s management and will be funded out of working capital.

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

 

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

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, 2005.

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, 2005.

General Overview

PRB is an independent energy company engaged in the acquisition, exploration, 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. Through June 30, 2006, we also provided contract management services by operating certain properties for a third party and providing technical and administrative support for those properties. PRB was initially formed under the name “PRB Transportation, Inc.” in December 2003 and was 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.  PRB operates through two wholly-owned subsidiaries: PRB Oil and Gas, Inc., an oil and gas exploration and production company and PRB Gathering, Inc., a gathering and processing company.

Nine Months Ended September 30, 2006 - Operational and Financial Highlights

In the first quarter of 2006, we raised approximately $22 million in cash, before expenses, through a private offering by issuing senior subordinated convertible notes. These funds will be used for our exploration, development, and asset acquisition programs.

Also, in the first quarter of 2006, we acquired two gas gathering systems in the Recluse area of Wyoming (together our “Recluse” gathering system) for approximately $1.5 million. In addition, under two separate transactions totaling $183,000, we acquired a combination of working interests ranging from 7.5% to 15% in the development of approximately 5,600 net acres in the Recluse and Gap gathering system areas that offer us the opportunity to expand both our exploration and production and gas gathering and processing activities.

On June 30, 2006, we acquired working interests in approximately 580 gross (529 net) coal-bed methane wells on approximately 29,000 acres located in the Powder River Basin from Pennaco Energy, Inc. (“Pennaco”). The purchase price of the acquired interests was approximately $600,000 and the effective date was July 1, 2006. As part of the purchase agreement, we issued a $3 million reducing letter of credit to the benefit of Pennaco to guarantee the funding of the future liability of the plugging costs of wells being purchased from Pennaco. The asset retirement obligation of these wells has been recorded on the balance sheet for $2 million based on the discounted present value of the future liability, as further reflected in Note 3 to the financial statements in this report. The letter of credit is collateralized by a $3 million certificate of deposit, and is considered restricted cash for purposes of available working capital (refer to the Liquidity and Capital Resources section).

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Of the 580 gross wells acquired during the third quarter, fewer than 150 wells were commercially producing natural gas at a combined rate of up to 2.5 million cubic feet per day (MMcf/d).  We currently have approximately 220 wells on production and plan to bring an additional 230 shut-in wells back on production, which will require additional capital expenditures.  In this regard, an estimate by our technical staff of $1.5 million has been included in the 2006 capital budget and has been reflected in oil and gas properties in the balance sheet.

On August 4, 2006, we closed on an acquisition of approximately 70 miles of gathering lines in the Recluse area which will provide additional opportunities for expanding gathering services to producers in the 100,000 acres surrounding the pipelines. The transaction was effective August 1, 2006, and the $428,000 purchase price was paid in cash.

In March 2006, we terminated a Farmout and Development Agreement dated August 1, 2005 (“Farmout Agreement”) with Enterra Energy Trust’s wholly-owned subsidiary Rocky Mountain Gas, Inc. (“RMG”).  In June 2006, RMG filed an arbitration demand against PRB.  On August 22, 2006, PRB denied RMG’s arbitration claims, and asserted counterclaims against RMG.  The arbitration is scheduled for February 2007.

As of September 1, 2006 we sold certain gas gathering assets referred to as the TOP Gathering System (TOP) to Arete Industries, Inc. for $330,000 in cash.  The net gain on the sale of $308,000 is reflected in Other Income in the current quarter’s financial statements.

During the nine months of 2006, we drilled 46 gross (26.5 net) wells which were in various stages of drilling or completion.  In addition, there are 14 gross (7.0 net) wells that are producing gas which had been drilled prior to this year.  We have increased our overall average daily net gas production from 77 thousand cubic feet per day in January 2006, to 3.5 MMcf/d (including the Pennaco wells) in September 2006, substantially increasing our gas production over 2005.

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Results of Operations

 

The financial information with respect to the three months and nine months ended September 30, 2006 and 2005, 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.

Three months ended September 30, 2006 (unaudited) compared to the three months ended September 30, 2005 (unaudited)

								Increase /			Percentage
		Quarter Ended September 30,						(Decrease)			Change
		2006			2005			2006 v 2005			2006 v 2005
		(Dollars in thousands)
Revenue
Gas gathering and processing		$	314		$	658		$	(344	)	-52	%
Natural gas sales		776			—			776			nm
Other		8			66			(58		)	-88	%
Total revenue		1,098			724			374			52	%
Natural gas gathering expenses and taxes		(298		)	—			(298		)	nm
Net revenue		800			724			76			10	%
Operating expenses
Gas gathering and processing operations		425			418			7			2	%
Natural gas lease operating		370			—			370			nm
General and administrative		977			584			393			67	%
Depreciation, depletion and amortization		759			281			478			170	%
Impairment and other		—			2,372			(2,372		)	nm
Total expenses		2,531			3,655			(1,124		)	-31	%
Operating loss		(1,731		)	(2,931		)	1,200			41	%
Other income (expense)
Other income		308			—			308			nm
Interest (expense) income, net		(343		)	63			(406		)	nm
Net loss		$	(1,766	)	$	(2,868	)	$	1,102		38	%

 

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

Revenues

Total revenues increased $374,000, or 52%, for the quarter ended September 30, 2006 compared to last year’s third quarter as the result of natural gas sales of $776,000 offset by a $344,000 decrease in gas gathering and processing from our TOP, GAP and Bonepile systems.  The decrease resulted from the Pennaco acquisition which had the effect of converting previous third-party revenues into PRB’s company-owned subsidiary revenues.  There were no gas sales last year during the third quarter.  We also had management fee revenues during the quarter ended September 30, 2005, but none for 2006, as the RMG agreement (see Note 2) ended on June 30, 2006.

Other 2006 natural gas expenses included gathering charges and production taxes from the acquired properties.

Gas Gathering and Processing Operations Expenses

Gas gathering and processing operations expenses were comparable to last year primarily due to the increase of operating costs in the Recluse gathering system acquired in 2006, offsetting reduced costs of systems sold in 2006.

Natural Gas Lease Operating Expenses

Natural gas lease operating expenses resulted from acquired field operations activities in 2006.  We substantially increased field operation activities this quarter as a result of the Pennaco acquisition.

General and Administrative Expenses

General and administrative expenses had a significant increase of $393,000 due to (1) the recognition of $94,000 of share-based options and warrants compensation expense, (2) employee compensation and benefits increasing by approximately $200,000 over last year as a result of substantial increases (from 7 to 24) in the number of employees added since the third quarter of 2005, and (3) professional fees increasing approximately $106,000 due to public reporting requirements that include legal, auditing, and financial and corporate consulting activities.

Depreciation, depletion, amortization, and impairments

Increased DD&A expense in 2006 resulted from the acquired properties.  An asset impairment charge of $2,372,000 for the TOP system was booked in the third quarter of 2005.

Other Income and Expense

Other income resulted from the sale of the TOP gathering system in the current quarter.  Interest expense resulted from convertible notes issued in the first quarter, offset by interest income.

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Nine months ended September 30, 2006 (unaudited) compared to the nine months ended September 30, 2005 (unaudited)

		Nine months Ended September 30,						Increase / (Decrease)			Percentage Change
		2006			2005			2006 v 2005			2006 v 2005
		(Dollars in thousands)
Revenue
Gas gathering and processing		$	1,592		$	2,214		$	(622	)	-28	%
Natural gas sales		882			—			882			nm
Other		154			66			88			133	%
Total revenue		2,628			2,280			348			15	%
Natural gas gathering expenses and taxes		(344		)	—			(344		)	nm
Net revenue		2,284			2,280			4			nm
Operating expenses
Gas gathering and processing operations		1,681			1,293			388			30	%
Natural gas lease operating		497			—			497			nm
General and administrative		3,123			1,311			1,812			138	%
Depreciation, depletion and amortization		1,415			838			577			69	%
Impairment and other		50			2,372			(2,322		)	nm
Total expenses		6,766			5,814			952			16	%
Operating loss		(4,482		)	(3,534		)	(948		)	-27	%
Other income (expense)
Other income		311			(205		)	516			nm
Interest (expense) income, net		(907		)	62			(969		)	nm
Net loss		$	(5,078	)	$	(3,677	)	$	(1,401	)	-38	%
Cash used in operating activities		$	(3,075	)	$	(306	)	$	2,769		nm
Cash used in investing activities		$	(11,973	)	$	(1,192	)	$	10,781		nm
Cash provided by financing activities		$	20,906		$	9,169		$	11,737		128	%

 

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

Revenues

Total revenues increased $348,000, or 15%, for the period ended September 30, 2006 compared to last year as the result of natural gas sales of $882,000 offset by a $622,000 decrease in gas gathering and processing from our TOP, GAP and Bonepile systems resulting from the Pennaco acquisition which had the effect of converting previous third-party revenues into PRB’s company-owned subsidiary revenues.  There were no gas sales last year during the third quarter.  We also had management fee revenues during the period ended September 30, 2005, but none for 2006, as the RMG agreement (see Note 2) ended on June 30, 2006.

Other 2006 natural gas and lease operating expenses included gathering charges and production taxes resulting from the acquired properties.

 

Gas Gathering and Processing Operating Expenses

Gas gathering and processing expenses increased $388,000, or 30%, over last year primarily due to the increase of the operating costs in the Recluse gathering system acquired in 2006.

Natural Gas Lease Operating Expenses

Natural gas lease operating expenses resulted from acquired field operations activities in 2006.  We substantially increased field operation activities this quarter as a result of the Pennaco acquisition.

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General and Administrative Expenses

General and administrative expenses had a significant increase of $1,812,000 due to (1) the recognition of $556,000 of share-based options and warrants compensation expense, (2) employee compensation and benefits increasing by approximately $600,000 over last year as a result of substantial increases (from 7 to 24) in the number of employees added due to our growth since the nine months ended September 30,2005, and (3) professional fees increasing approximately $496,000 due to public reporting requirements that include legal, auditing, and financial and corporate consulting activities.

Depreciation, depletion,  amortization, and impairments

Increased DD&A expense in 2006 resulted from the acquired properties.  An asset impairment charge of $2,372,000 for the TOP system was booked in the third quarter of 2005.

Other Income and Expense

Other income resulted from the sale of the TOP gathering system in the current quarter.  In 2005 dividend expense was recognized on the convertible preferred stock.  Interest expense resulted from convertible notes issued in the first quarter of 2006, offset by interest income.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

At September 30, 2006, cash and cash equivalents totaled $12.3 million. Additionally, we have $3 million of restricted cash which collateralizes a reducing letter of credit issued in connection with potential plugging liabilities of acquired properties as provided for in the May 1, 2006 purchase and sale agreement  between Pennaco and PRB. The restricted cash will be released at the same rate annually that the letter of credit is reduced. Working capital, excluding the restricted $3 million, was $12 million. During the first quarter of 2006, we raised approximately $22 million, before expenses, by issuing senior subordinated convertible notes. These funds have provided working capital for our exploration, development and asset 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 and capital 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. 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 changes in funding requirements for future development.

Cash Flow Used in Operating Activities

During the nine months ended September 30, 2006, our net loss of $5 million included non-cash charges of $1,415,000 of DD&A expense, $ 415,000 of share-based compensation expense and $267,000 of interest expense resulting from amortization of debt issuance costs.

Cash used in operating activities of $3.1 million during the first nine months of 2006 was $2.8 million greater than the same period of 2005. This increase was mainly attributable to increased debt interest payments, higher general and administrative expense for staff increases and increased gas production operations.

Cash Flow Used in Investing Activities

Cash used in investing activities was $12 million during the first nine months of 2006, representing an increase of $11 million compared to 2005 period.  During 2006, we acquired various segments of the Recluse gathering system for approximately $2 million and acquired interests in Wyoming coal-bed methane (“CBM”) wells for approximately $730,000 which included additional related transaction expenses.  We also invested $ 5.2 million in drilling and completion activities to develop proved properties, $192,000 for undeveloped leaseholds and $700,000 for other plant and equipment.  In addition, as part of the acquisition of the CBM wells, we issued a $3 million reducing letter of credit to the benefit of Pennaco to guarantee the funding of the future liability of the plugging costs of wells being purchased from Pennaco.

At September 30, 2006, capitalized costs of wells-in-progress were approximately $3.7 million and consisted of 46 gross wells in various stages of drilling or 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 drilling, 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 2006 capital expenditure program calls for investing approximately $11 million in oil and gas exploration, development and acquisition projects and gas gathering system projects.  Approximately $1.5 million of that amount has been earmarked for remediation expenditures for the CBM wells acquired in June 2006.

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Cash Flow from Financing Activities

Cash provided by financing activities of $21 million for the nine months ended September 30, 2006 represents an increase of $11.7 million as compared to last year.  During the first quarter of 2006, we raised approximately $22 million from the issuance of senior subordinated convertible notes and incurred approximately $1 million in debt issuance costs, excluding the value of warrants issued.  In 2005, we raised $11 million, net of issuance costs, in a public offering, repaid $1.5 million of bank debt and paid $338,000 in convertible preferred stock dividends.

Off Balance-Sheet Arrangements.

We do not have any off-balance sheet financing arrangements as of September 30, 2006, except for our Storm Cat gas gathering services agreement (“Agreement”).  Our 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, of which the first five years are noncancelable. The Agreement requires Storm Cat to pay us a minimum of $972,000 in 2006 and an aggregate minimum of $3.1 million in gas gathering fees during the first three years of the Agreement.  The Agreement also provides for our gas gathering rates to decrease during the fourth and fifth years.  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 2005 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 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 and 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.

Earlier this year, 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. 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, constituted a material weakness in internal control over financial reporting.  Specifically, our earlier staffing levels were inadequate to facilitate the design, implementation and maintenance of an effective system of internal control.

Although progress has been made in the current quarter in remedying these weaknesses, particularly through new hires and experience levels of the staff and by the full implementation of accounting software systems, the conclusions by our Chief Executive Officer and Principal Financial Officer are that our disclosure controls and procedures require additional reviews through the next quarter and were not effective as of September 30, 2006.

Remediation of the Material Weakness

In response to the control deficiencies listed above, we have taken (or plan to take during the remainder of 2006) the following steps to change our internal control over financial reporting to institute procedures to remediate the significant deficiencies and material weakness identified above:

 

·        We have doubled the accounting staff to six experienced accountants to provide the 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 have fully implemented the Enertia accounting software to provide a more robust accounting and reporting software package that will enable us to increase our controls over system generated reports, offering a full range of operations and financial accounting functionality.

·        We plan to complete the implementation of disclosure controls and procedures by year-end 2006 reporting 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 will document our accounting policies and procedures and enhance our month end close and financial reporting processes by year-end 2006 reporting to include additional controls to improve the completeness and accuracy of our periodic financial statements.

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Because a number of these procedures are recent and ongoing this year, and since financial management personnel changes have been made recently, we have not 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 initially 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. A proposal was announced by the SEC on August 9, 2006 that this date may be further extended to fiscal years ending on or after December 15, 2007. The SEC also proposes to extend the date by which non-accelerated filers must begin to comply with the Section 404(b) requirement to provide an auditor’s attestation report on internal control over financial reporting in their annual reports.  This deadline would be moved to the first annual report for a fiscal year ending on or after December 15, 2008.

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PART II OTHER INFORMATION

 ITEM 1:    LEGAL PROCEEDINGS

On June 22, 2006, RMG filed an arbitration demand against PRB.  On August 22, 2006, PRB denied RMG’s arbitration claims, and asserted counterclaims against RMG.  The arbitration is scheduled for February 2007.  At this time, we cannot predict the outcome of arbitration.  (Refer to Part I, Note 2 to our financial statements in this report regarding the Rocky Mountain Gas Agreement.)

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 Annual Report on Form 10-K for the 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

None.

 ITEM 3:    DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5:    OTHER INFORMATION

None.

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ITEM 6:    EXHIBITS

 

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).
(3.2)		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).
(3.3)		Series A Preferred Stock Certificate of Designation (filed as an exhibit to Form S-1 filed on November 1, 2004 and incorporated by reference herein).
(3.4)		Series B Preferred Stock Certificate of Designation Filed (filed as an exhibit to Form S-1 filed on November 1, 2004 and incorporated by reference herein).
(3.5)		Series C Preferred Stock Certificate of Designation Filed (filed as an exhibit to Form S-1/A filed on January 28, 2005 and incorporated by reference herein).
(4.1)		Form of Lockup Agreement—Officers, Directors and 5% Stockholders (filed as an exhibit to Form S-1/A filed on November 1, 2004 and incorporated by reference herein).
(4.2)		Form of Lockup Agreement—Series A and B Preferred Stockholders (filed as an exhibit to Form S-1 filed on November 1, 2004 and incorporated by reference herein).
(4.3)		Form of Underwriter’s Warrant Agreement (filed as an exhibit to Form S-1/A filed on January 28, 2005 and incorporated by reference herein).
(4.4)		Form of Lockup Agreement—Series C Preferred Stockholders (filed as an exhibit to Form S-1/A filed on January 28, 2005 and incorporated by reference herein).
(4.5)		Sample 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 as an exhibit to Form 10-K 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 as an exhibit to Form 10-K on April 14, 2006 and incorporated by reference herein).
10.18		Purchase and Sale Agreement between PRB Energy, Inc., and Arête Industries Inc., dated September 1, 2006
10.19		Purchase and Sale Agreement between PRB Energy, Inc., and Maverick Pipeline LLC, dated August 1, 2006

 

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Exhibit Number		Description
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 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Principal Financial Officer Certification 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.

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