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 March 31, 2007
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  o  Accelerated filer  o   Non-accelerated filer   x

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

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

 

TABLE OF CONTENTS

PART I — Financial Information
Item 1.	Financial Statements
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.	Quantitative and Qualitative Disclosures About Market Risk
Item 4.	Controls and Procedures
PART II — Other Information
Item 1.	Legal Proceedings
Item 1A.	Risk Factors
Item 6.	Exhibits
	Signatures

 

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

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PRB ENERGY, INC.
Consolidated Balance Sheets
(In thousands, except share amounts)

		March 31,			December 31,
		2007			2006
		(Unaudited)
Assets
Current assets:
Cash and cash equivalents		$	6,917		$	11,157
Restricted cash		2,117			2,078
Accounts receivable		1,263			2,527
Prepaid expenses		1,656			789
Total current assets		11,953			16,551
Oil and gas properties accounted for under the successful efforts method of accounting:
Proved properties		5,745			5,436
Unproved leaseholds		9,240			9,282
Wells-in-progress		6,440			5,794
Total oil and gas properties		21,425			20,512
Less: accumulated depreciation, depletion and amortization		(974		)	(766		)
Net oil and gas properties		20,451			19,746
Gathering and other property and equipment		14,828			11,603
Less: accumulated depreciation and amortization		(2,397		)	(1,919		)
Net gathering and other property and equipment		12,431			9,684
Other non-current assets:
Deferred debt issuance costs		2,198			2,086
Less: accumulated amortization		(625		)	(375		)
Net deferred debt issuance costs		1,573			1,711
Other non-current assets		2,698			2,151
Total other non-current assets		4,271			3,862
Total Assets		$	49,106		$	49,843
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable		$	2,041		$	1,854
Accrued expenses and other current liabilities		584			979
Total current liabilities		2,625			2,833
Secured notes, debentures and other debt, less current portion		36,970			36,972
Discount on debentures, net of amortization		(3,830		)	(4,326		)
Capital lease, less current portion		2,974			—
Other non-current liabilities		3,315			3,140
Total liabilities		42,054			38,619
Commitments and Contingencies
Stockholders’ equity:
Common stock, 40,000,000 shares authorized; 8,601,994 and 8,231,894 issued, and 8,601,994 and 8,601,994 outstanding, respectively		10			10
Treasury stock		(1,257		)	(1,257		)
Additional paid-in-capital		26,664			26,406
Accumulated deficit		(18,365		)	(13,935		)
Total stockholders’ equity		7,052			11,224
Total Liabilities and Stockholders’ Equity		$	49,106		$	49,843

 

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
		March 31,
		2007			2006
Revenues:
Natural gas sales		$	413		$	58
Gas gathering and processing		508			675
Other		4			94
Total revenues		925			827
Natural gas gathering expense		56			12
Natural gas production taxes		40			7
Net revenues		829			808
Operating expenses:
Natural gas lease operating		661			59
Gas gathering and processing		432			588
Exploration expense		—			97
Depreciation, depletion, amortization and accretion		855			320
General and administrative		1,601			1,017
Total operating expenses		3,549			2,081
Operating loss		(2,720		)	(1,273		)
Other income (expense):
Interest and other income		271			187
Interest and other expense		(1,981		)	(408		)
Total other (expense) income		(1,710		)	(221		)
Net loss		$	(4,430	)	$	(1,494	)
Net loss per share — basic and diluted		$	(0.51	)	$	(0.20	)
Basic and diluted weighted average shares outstanding		8,601,994			7,432,561

 

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)

		Three Months Ended
		March 31,
		2007			2006
Cash flows from operating activities:
Net loss		$	(4,430	)	$	(1,494	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depreciation, depletion, amortization and accretion		855			320
Exploration Expense		—			97
Amortization of debt issuance costs		250			64
Amortization of discount on debentures		494			—
Bad Debt Expense		299			—
Share-based compensation expense		258			279
Capitalized interest		(76		)	—
Changes in assets and liabilities:
Accounts receivable		965			(446		)
Inventory		—			(38		)
Prepaid expenses		(867		)	(86		)
Other non-current assets		(515		)	13
Accounts payable		187			(529		)
Accrued expenses and other current liabilities		(471		)	160
Deferred Revenue		24			—
Other non-current liabilities		16			12
Net cash used in operating activities		(3,011		)	(1,648		)
Cash flows from investing activities:
Capital expenditures		(1,117		)	(2,848		)
Acquisition of natural gas properties and gathering facilities		—			(183		)
Deferred acquisition cost		—			(19		)
Net cash used in investing activities		(1,117		)	(3,050		)
Cash flows from financing activities:
Proceeds from convertible notes		—			21,965
Issuance costs related to debentures and convertible notes		(112		)	(1,053		)
Net cash (used in) provided by financing activities		(112		)	20,912
Net (decrease) increase in cash		(4,240		)	16,214
Cash—beginning of period		11,157			6,434
Cash—end of period		$	6,917		$	22,648
Supplemental disclosure of cash flow activity:
Cash paid for interest		$	1,310		$	246
Supplemental schedule for non-cash activity:
Issuance of warrants in connection with convertible notes		$	—		$	92
Capital remediation costs		$	169		$	—
Asset retirement obligations		$	135		$	85
Capital Lease		$	3,050		$	—

 

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

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PRB ENERGY, INC.

Notes to Consolidated Financial Statements

March 31, 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 as two business segments through two wholly-owned subsidiaries, PRB Oil and Gas, Inc., a Colorado corporation, a gas and oil exploitation and production company (“E&P”), formed in July, 2005 and PRB Gathering, Inc., a Colorado corporation, a gathering and processing company (“G&P”), 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 (“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 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 March 31, 2007, and for the three months there ended, 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 March 31, 2007 and the results of our operations and cash flows for the three months ended March 31, 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 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 7 - Equity Compensation Plan.  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) 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

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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 7 - 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.

Concentrations of Credit Risk

We grant credit in the normal course of business to customers in the United States.  Management periodically performs a credit analysis and monitors the financial condition of our customers to reduce credit risk.  Management periodically reviews accounts receivable and reduces the carrying amount by a valuation allowance that reflects management’s best estimate of the amount that may not be collectible.  Allowances for uncollectible accounts receivable are based on information available and historical experience.  As of March 31, 2007 and December 31, 2006, there were $903,000 and $604,000, respectively of allowances for uncollectible accounts receivable.

Revenues from customers which represented 10% or more of our sales for the three months ended March 31, 2007 and 2006 were as follows:

		For the three months ended
		March 31,
Customer		2007		2006
		(% of total revenue)
A — Exploration and production		36.2	%	—
B — Gathering and Processing		—		42.0	%
C — Gathering and Processing		35.7	%	12.8	%
D — Corporate		—		11.4	%

 

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 costs at March 31, 2007 were $2,198,000 and are being amortized using the effective interest rate method over the life of the debt.

We initially reflected the  discount on the Debentures of $4,326,000 on the balance sheet at December 31, 2006.  The remaining unamortized discount at March 31, 2007 was $3,830,000 and is being amortized using the effective interest rate method over the life of the debt.

Rocky Mountain Gas Inc. (“RMG”) Agreement

On June 22, 2006, RMG filed an arbitration demand against us.  On August 22, 2006, we denied RMG’s arbitration claims and asserted counterclaims against RMG.  The arbitration is scheduled for May 2007.  At this time, we cannot predict the outcome of arbitration.  However, management believes the outcome will not have a material adverse effect on our financial condition.  (Refer to Part I, Item 3, Legal Proceedings to our 2006 Annual Report on Form 10-K regarding the Rocky Mountain Gas Agreement and Claims Dispute.)  The

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accounts receivable balance with RMG at March 31, 2007 was $995,000 and the associated allowance for bad debt was $895,000. The increase of $299,000 in the allowance for the quarter was related to reserving substantially all of the additional charges for the quarter under the prior agreements with RMG.

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 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 Contracts

Compressor Lease Agreement

On February 12, 2007, PRB Gathering, Inc. entered into a five-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 is shown as a capital lease obligation of $3,069,000 on the balance sheet at March 31, 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.

Note 4—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

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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 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 expected lives of gas wells, changes in gas gathering system configuration, changes in estimates and changes in regulations.

A reconciliation of our asset retirement obligation liability for the three months ended March 31, 2007 and 2006, is as follows:

		Three Months Ended
(In thousands)		March 31, 2007			March 31, 2006
Asset retirement obligation, beginning of period		$	3,140		$	387
Gathering assets		52			69
Proved properties		(129		)	16
Accretion expense		135			9
Asset retirement obligation, end of period		$	3,198		$	481

 

Note 5—Borrowings

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

(In thousands)		March 31, 2007			December 31, 2006
Senior subordinated convertible notes		$	21,965		$	21,965
Senior secured debentures		15,000			15,000
Other term loans		15			17
		36,980			36,982
Less current portion		(10		)	(10		)
Total long-term borrowings		$	36,970		$	36,972

 

Senior Subordinated Convertible Notes (the “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 from 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 of the Notes in the amount of approximately $1 million, excluding the value of warrants issued, were deferred as other non-current assets and are being amortized as interest expense.  For the quarter ended March 31, 2007, $111,000 of the deferred costs of the Notes was amortized as interest expense and an additional $549,000 of interest paid in cash was expensed.

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.

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 the related pronouncements.  hawse 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 are not accounted for as derivatives on the consolidated balance sheet at March 31, 2007.

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Senior Secured Debentures (the “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 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.

Debt issuance costs of the Debentures of $1,054,000 were deferred as other non-current assets and are being amortized as interest expense.  For the quarter ended March 31, 2007, $139,000 of the deferred costs of the Debentures was amortized as interest expense and an additional $481,000 of interest paid in cash was expensed.  The discount on the Debentures of $494,000 was amortized as interest expense during the current quarter.

Note 6—Income Taxes

A valuation allowance for deferred taxes at December 31, 2006 was $4.6 million.  As of March 31, 2007, no change has been made on the balance sheet to reflect any deferred tax asset, as management believes that this allowance amount continued to be reasonable and appropriate.  The effective income tax rate was 37% for the first quarter of 2007 compared to 37% for the fourth quarter of 2006 and 37% for the first quarter 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 fifty 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 recognize potential accrued interest and penalties 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 accrued at March 31, 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 Colrado tax returns for the tax years 2004 through 2006.

Note 7—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 77,949 shares available for grant under the Option Plan as of March 31, 2007.

 

The following table summarizes activity for options:

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		Three Months Ended					Three Months Ended
		March 31, 2007					March 31, 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		202,500		4.03			239,750		6.51
Forfeited		(37,500	)	7.06			(22,250	)	8.57
Exercised		—		—			—		—
Outstanding at March 31,		782,250		$	5.71		680,750		$	6.60
Exercisable at March 31,		371,063		$	5.76		297,500		$	6.53

 

As of March 31, 2007, the weighted average fair value of options granted during the previous three months was $2.04, 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 pricing 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 three months ended March 31, 2007 and 2006:

		SFAS No. 123(R) Expense		SFAS No. 123 Pro-Forma
		Three Months Ended		Three Months Ended
		March 31, 2007		March 31, 2006
Expected life of options		2.4 — 6.5 years		2.5 – 6.25 years
Expected volatility		70%		80%
Risk-free interest rate		4.81 — 5.00%		4.31 — 4.69%
Expected dividend yield of stock		0%		0%

 

Note 8 — 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.

Gas Gathering and Processing Segment

We own and operate gas gathering and processing systems we acquired from 2004 through March 31, 2007.  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 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.

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Oil and Gas Exploitation and Production Segment

Beginning in the third quarter of 2005, we commenced operations in the exploitation and production segment.  Our operations in this segment include developing, producing and marketing natural gas 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.

Through a management services agreement during the first half of 2006 with Rocky Mountain Gas (“RMG”), we earned management fee revenues that we have included under “Corporate” in the following table that details the performance of our segments.  We terminated this agreement with RMG as of June 30, 2006.

		Three Months Ended March 31, 2007
		Exploitation			Gathering
		and			and
(In thousands)		Production			Processing			Corporate			Total
Revenues		$	413		$	508		$	4		$	925
Net loss		$	(556	)	$	(539	)	$	(3,335	)	$	(4,430	)
Identifiable assets:
Oil and gas properties, net		$	21,425		$	—		$	—		$	21,425
Property and equipment, net		$	—		$	11,730		$	701		$	12,431
Other non-current assets		$	1,195		$	963		$	1618		$	3,776

 

		Three Months Ended March 31, 2006
		Exploitation			Gathering
		and			and
(In thousands)		Production			Processing			Corporate			Total
Revenues		$	58		$	675		$	94		$	827
Net loss		$	(134	)	$	(203	)	$	(1,157	)	$	(1,494	)
Identifiable assets:
Oil and gas properties, net		$	2,893		$	—		$	—		$	2,893
Property and equipment, net		$	—		$	7,180		$	203		$	7,383
Other non-current assets		$	—		$	1,115		$	1,079		$	2,194

 

Note 9— Related Party Transactions

In October 2005, the Company and JMG Exploration, Inc. (“JMG”) entered into an agreement to build and operate an oil and gas pipeline.  Joseph Skeehan and Reuben Sandler were directors on the Company’s Board and also served on the board of directors of JMG during 2005.  Both of them have continued to serve on the Company’s Board of Directors through the current period.  In January 2006, this project was terminated.  In order to reimburse us for its carrying cost of the pipe, we and JMG entered into an agreement whereby JMG would indemnify us for these costs and resale of the pipe.  The interest rate applied was 10% per annum based on the remaining balance for the pipe that was held in inventory.  The pipe inventory was sold during 2006 and the proceeds were received by the Company and credited to the inventory account.  As of March 31, 2007, JMG owed us $107,000 for interest on the pipe inventory balance.  This amount was subsequently paid by JMG in May 2007.

Susan Wright, wife of the Company’s CEO, provides Corporate Secretary services to us on a contract basis.  During the quarter ended March 31, 2007, Ms. Wright was paid $34,200 for the contract services.

On January 9, 2007, we issued 15,000 warrants to a former director for services rendered.  These warrants vest immediately on the date of grant with an exercise price of $4.50 per share.  We recorded approximately $20,000 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 quarter ended March 31, 2007, we paid interest of $2,500 and $31,875, respectively, on these Notes.  In addition, an

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investment fund, of which one of our former directors is a consultant, purchased on behalf of its investors, $1 million of the Notes.  The investors were paid $25,000 in interest during the same period.

Note 10 —Subsequent Events

Registration of Additional Shares of PRB Energy, Inc. Common Stock

In connection with our issuance of 1,250,000 shares of common stock to two private lenders in December 2006, we entered into a registration rights agreement.  We filed a registration statement to register those shares in February 2007.  The registration was declared effective by the SEC on May 4, 2007.

Formation of New Subsidiary

PRB North Dakota, Inc., a new subsidiary of PRB Energy, was formed in April 2007.

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 Part I, Item 1 of this Quarterly Report on Form 10-Q and in 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.  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.  We were initially formed under the name “PRB Transportation, Inc.” in December 2003 and were incorporated in the State of Nevada.  On June 14, 2006, our name was changed to “PRB Energy, Inc.”  We conduct our primary business activities in Wyoming, Colorado, and Nebraska.  We operate through two wholly-owned subsidiaries:  PRB Oil and Gas, Inc., an oil and gas exploitation and production company and PRB Gathering, Inc., a gathering and processing company.

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First Quarter 2007 Operational and Financial Highlights

During the first quarter of 2007 we had 108 gross wells (102 net) producing commercial gas, as well as 64 gross wells (50 net) in the dewatering stage.  We sold 76,000 Mcf of gas in Wyoming and 21,000 Mcf of gas in northern Colorado, which resulted in sales of $321,000 and $92,000, respectively.  Our gathering operations generated revenues of $508,000 for the first quarter of 2007.

For the first quarter of 2007, we had a net loss of $4.4 million.  Approximately half of this loss was due to interest expense related to the debt incurred in 2006.  Interest expense for the quarter consisted of three main categories.  The first category is $280,000 of interest expense associated with a capital lease obligation.  The second category consists of discount and issuance costs related to the Debentures amortized for $635,000.  The last category was the interest payments for the Notes and the Debentures of $1,065,000. (See Part I, Note 5 in this Quarterly Report on Form 10-Q.)

The balance of the net loss for the quarter was primarily due to the inability to gather gas due to weather and mechanical problems.  The weather problems affected the South Gillette, Wyoming area from mid-January through early February due to water freezing in the gathering lines.  Also, a reciprocating compressor had mechanical problems interrupting gas gathering operations for the last three weeks of March 2007.  These problems were coupled with a lower than average realized price for the quarter.

We entered into a five-year lease agreement with J-W Power Company (“J-W Power”) effective January 24, 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.  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 was recorded, as well as the related liability.  In addition, a cash payment of $650,000 was made to J-W Power for future maintenance repairs in connection with the lease.  The capital lease and prepayment will be amortized over the term of the lease.

Results of Operations

The financial information with respect to the three months ended March 31, 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.

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Three months ended March 31, 2007 (unaudited) compared to the three months ended March 31, 2006 (unaudited)

								Increase /			Percentage
		Quarter Ended March 31,						(Decrease)			Change
		2007			2006			2007 v 2006			2007 v 2006
		(Dollars in thousands)
Revenue
Natural gas sales		$	413		$	58		$	355			*
Gas gathering and processing		508			675			(167		)	-25	%
Other		4			94			(90		)	-96	%
Total revenue		925			827			98			12	%
Natural gas gathering expenses and taxes		(96		)	(19		)	(77		)		*
Net revenue		829			808			21			3	%
Operating expenses
Natural gas lease operating		661			59			602				*
Gas gathering and processing operations		432			588			(156		)	-27	%
General and administrative		1,601			1,017			584			57	%
Depreciation, depletion and amortization		855			320			535			167	%
Exploration expense		—			97			(97		)	-100	%
Total expenses		3,549			2,081			1,468			71	%
Operating loss		(2,720		)	(1,273		)	(1,447		)	114	%
Other income (expense)
Interest and other income		271			187			84			45	%
Interest (expense) income, net		(1,981		)	(408		)	(1,573		)		*
Net loss		$	(4,430	)	$	(1,494	)	$	(2,936	)	-197	%

 

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

Revenues

Total revenues increased $98,000, or 12%, for the quarter ended March 31, 2007 compared to last year’s first quarter as the result of natural gas sales from the Pennaco properties acquired in mid 2006.  The $355,000 increase in natural gas sales was substantially offset by the reduced gas gathering fees from third parties as a result of the reduction of revenues that were previously Pennaco third-party fees.  We also had management fee revenues during the first quarter of 2006, but none in 2007, because the Rocky Mountain Gas, Inc. (“RMG”) agreement ended on June 30, 2006.  (See Part II, Item 1 in this Quarterly Report on Form 10-Q.)

Natural Gas Lease Operating Expenses

Natural gas lease operating expenses in 2007 increased to $661,000, ten times over 2006 as a result of the added field operations from the Pennaco (Wyoming) and D-J Basin (Colorado/Nebraska) acquisitions in the second half of 2006.

Gas Gathering and Processing Operations Expenses

Gas gathering and processing operations expenses were 27% lower in 2007 than last year primarily due to the J-W Power arrangement for the leasing of compressors and in reduced third-party gathering services.

General and Administrative Expenses

General and administrative expenses had a significant increase of $584,000, or 57%, due to (1) employee compensation and benefits increasing over last year as a result of substantial increases (from 15 to 27) in the

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number of employees added in response to increased operations, and (2) a reserve for bad debt in the current quarter of nearly $300,000 for the RMG receivable. (See Part I, Note 1 in this Quarterly Report on Form 10-Q.)

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

DD&A expense in 2007 increased to $855,000, nearly double over 2006 resulted from the acquired properties in mid and late 2006.

Other Income and Expense

Interest expense in 2007 increased to $2 million, nearly 5 times over 2006 due to (1) interest payments on convertible Notes, Debentures and capital lease and (2) amortization of the debt issuance costs and the discount on Debentures.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

At March 31, 2007, cash and cash equivalents totaled $6,917,000 compared to $11,157,000 at December 31, 2006. Additionally, we have $3,117,000 of restricted cash which collateralizes a reducing letter of credit issued in connection with potential plugging liabilities of acquired properties in 2006.  Of this amount, $1 million is classified as a non-current asset in the balance sheet.  The restricted cash will be released at the same rate annually that the letter of credit is reduced.  Working capital, excluding the restricted cash, was $7,211,000.  During the first quarter of 2006, we raised approximately $22 million, before expenses, by issuing the Notes.  These funds have provided working capital for our exploitation, development and asset acquisition programs.  During the fourth quarter of 2006, we raised approximately $15 million, before expenses, by issuing the Debentures.  These funds were utilized in the acquisition of properties in the D-J Basin and are for further development of the area.

We believe that our cash and cash equivalents on hand, internally generated cash flows and future financing activities will require augmentation from bank financing or other equity of debt financing to fund our planned operational, drilling and acquisition and capital expenditures in the near 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 prices on investment opportunities, the availability of capital and borrowing facilities and the success of our exploitation and development activities could lead to changes in funding requirements for future development.  If we failed to secure third party 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 three months ended March 31, 2007, our net loss of $4,430,000 included non-cash charges of $855,000 of DD&A expense, $258,000 of share-based compensation expense, $299,000 of bad debt reserve, and $744,000 of interest expense resulting from amortization of debt issuance costs and discount on the Debentures.

Cash used in operating activities of $3,011,000 during the first three months of 2007 was 83% greater than the same period of 2006.  This increase was mainly attributable to increased debt interest payments, higher general and administrative expenses due to staff increases and increased operations of acquired and developed gas properties.

Cash Flow Used in Investing Activities

Cash used in investing activities was $1,117,000 during the first three months of 2007, representing an decrease of 63% compared to 2006.  During the current quarter of 2007, we invested $900,000 in drilling and completion activities to develop proved properties and $208,000 for other surface plant and equipment.

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At March 31, 2007, capitalized costs of wells in progress were approximately $6,511,000 and consisted of 64 gross (50 net) 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 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 2007 capital expenditure program calls for investing approximately $18 million in oil and gas exploration, development and acquisition projects and gas gathering system projects. During the first quarter of 2007, we expended approximately $1.1 million for such projects.

Cash Flow from Financing Activities

Cash used by financing activities of $112,000 for the three months ended March 31, 2007.  During the first quarter of 2006, we raised $21,965,000 from the issuance of Notes and incurred approximately $1,000,000 in debt issuance costs, excluding the value of warrants issued.  During the fourth quarter of 2006, we raised $15 million from the issuance of Debentures and incurred debt issuance costs of approximately $112,000 and $900,000, respectively, during the first quarter of 2007 and the fourth quarter of 2006.

Off Balance-Sheet Arrangements.

We do not have any off-balance sheet financing arrangements as of March 31, 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, 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. The amount billed under the agreement for the first quarter of 2007 was $229,000.

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 March 31, 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 March 31, 2007.

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PART II OTHER INFORMATION

ITEM 1:    LEGAL PROCEEDINGS

Rocky Mountain Gas Inc. (“RMG”) filed an arbitration demand against us in 2006.  The arbitration is scheduled for May 2007.  (Refer to Part I, Item 3 in. our 2006 Annual Report on Form 10-K regarding the Rocky Mountain Gas Agreement and Claims Dispute.)

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.

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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).
(3.3)		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 and exhibit to From 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 and exhibit to From 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 From 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 From 8-K filed on January 5, 2007 and incorporated by reference herein)
(10.22)		Master Gas Compression Contract, dated February 12, 2007, by and between PRB Gathering, Inc. and J-W Power Company (filed as and exhibit to From 8-K filed on February 14, 2007 and incorporated by reference herein)
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.

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SIGNATURE

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

		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: May 14, 2007

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