**UNITED STATES  SECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

**FORM 10-K**

**x**                              ANNUALREPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACTOF 1934

**Forthe fiscal year ended December 31, 2006**

**o**                                 TRANSITIONREPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACTOF 1934

**Forthe transition period from                     to**

**Commissionfile number:  001-32471**

**PRB ENERGY, INC.**

(Exact Name of Registrantas specified in its Charter)

| **Nevada**                                |   | **20-0563497**                     |
|-------------------------------------------|--------|------------------------------------|
| (State or other  jurisdiction of          |   | (IRS Employer  Identification No.) |
| incorporation or  organization)           |   |                               |
| ** **                                |   | ** **                         |
| **1875  Lawrence Street, Suite 450** |   | ** **                         |
| **Denver,  Colorado**                     |   | **80202**                          |
| (Address of  Principal Executive Offices) |   | (Zip Code)                         |

 

Registrant’s TelephoneNumber, including area code:**  (303) 308-1330**

(Former name, formeraddress and former fiscal year, if changed since last report):**  None**

**Securitiesregistered pursuant to Section 12(b) of the Act:**

|                                |   | **Name of  Exchange on Which** |
|--------------------------------|--------|--------------------------------|
| **Title of  Each Class**       |   | **Registered**                 |
| Common Stock,  $.001 par value |   | American Stock  Exchange       |

 

**Securitiesregistered pursuant to Section 12(g) of the Act:  None**

Indicate by check mark ifthe registrant is a well-known seasoned issuer, as defined in Rule 405 ofthe Securities Act.  Yes o  No x

Indicate by check mark ifthe registrant is not required to file reports pursuant to Section 13 orsection 15(d) of the Exchange Act.  Yes o  No x

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

Indicate by check mark ifdisclosure of delinquent filers pursuant to Item 405 of Regulation S-K is notcontained herein, and will not be contained, to the best of registrant’sknowledge, in definitive proxy or information statements incorporated byreference in Part III of this Form 10-K or any amendment to thisForm 10-K.  o

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer, or anon-accelerated filer. See definition of accelerated filer and large acceleratedfiler in Rule 12b-2 of the Exchange Act.

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

 

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

The aggregate marketvalue of the registrant’s common stock held by non-affiliates of the registrantas of June 30, 2006 was $33,549,628 computed by reference to the price at whichthe registrant’s common stock was last traded on that date.

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

| **Class**                          |   | **Outstanding  at March 23, 2007** |   |
|------------------------------------|--------|------------------------------------|--------|
| **Common  Stock, $.001 par value** |   | **8,601,994  shares**              |   |

 

**DOCUMENTS INCORPORATED BYREFERENCE**

Portions of the registrant’s definitive proxystatement to be delivered to stockholders in connection with the Annual Meetingof stockholders areincorporated by reference into Part III of this Form 10-K.

 

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**TABLE OF CONTENTS**
| Item       | ** ** | **Description**                                                                                                    | ** ** | **Page** | ** ** |
|------------|------------|--------------------------------------------------------------------------------------------------------------------|------------|----------|------------|
| ** ** | ** ** | **PART I**                                                                                                    |       | 3        |       |
| ITEM 1.    |       | Business                                                                                                           |       | 3        |       |
| ITEM  1A.  |       | Risk Factors                                                                                                       |       | 7        |       |
| ITEM 1B.   |       | Unresolved Staff Comments                                                                                          |       | 10       |       |
| ITEM 2.    |       | Properties                                                                                                         |       | 11       |       |
| ITEM  3.   |       | Legal  Proceedings                                                                                                 |       | 13       |       |
| ITEM 4.    |       | Submission of Matters to a Vote of Security Holders                                                                |       | 14       |       |
|       | ** ** | **PART II**                                                                                                   |       | 15       |       |
| ITEM 5.    |       | Market for Registrant’s Common Equity, Related  Stockholder Matters and Issuer Purchases of Equity Securities |       | 15       |       |
| ITEM  6.   |       | Selected  Financial Data                                                                                           |       | 17       |       |
| ITEM 7.    |       | Management’s Discussion and Analysis of Financial  Condition and Results of Operations                        |       | 18       |       |
| ITEM 7A.   |       | Quantitative and Qualitative Disclosures About Market  Risk                                                        |       | 23       |       |
| ITEM 8.    |       | Consolidated Financial Statements and Supplementary  Data                                                          |       | 23       |       |
| ITEM 9.    |       | Changes in and Disagreements with Accountants on  Accounting and Financial Disclosure                              |       | 23       |       |
| ITEM 9A.   |       | Controls and Procedures                                                                                            |       | 23       |       |
| ITEM  9B.  |       | Other  Information                                                                                                 |       | 23       |       |
|       | ** ** | **PART III**                                                                                                  |       | 24       |       |
| ITEM 10.   |       | Directors, Executive Officers and Corporate Governance                                                             |       | 24       |       |
| ITEM 11.   |       | Executive Compensation                                                                                             |       | 24       |       |
| ITEM 12.   |       | Security Ownership of Certain Beneficial Owners and  Management and Related Stockholder Matters                    |       | 24       |       |
| ITEM 13.   |       | Certain Relationships and Related Transactions and  Director Independence                                          |       | 24       |       |
| ITEM 14.   |       | Principal Accounting Fees and Services                                                                             |       | 24       |       |
|       | ** ** | **PART IV**                                                                                                   |       | 24       |       |
| ITEM 15.   |       | Exhibits, Financial Statement Schedules                                                                            |       | 24       |       |
|       |       | Signatures                                                                                                         |       | 27       |       |

 

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**Cautionary Note RegardingForward-Looking Statements**

The PrivateSecurities Litigation Reform Act of 1995 provides a safe harbor forforward-looking statements made by or on our behalf. We may from time-to-timemake statements that are “forward-looking,” including statements contained inthis Annual Report on Form 10-K and other filings with the Securities andExchange Commission (the “SEC”) and in reports to our shareholders. Suchstatements may, for example, express expectations or projections about futureactions that we may take or about developments beyond our control includingchanges in domestic or global economic conditions. These statements are made onthe basis of our management’s views and assumptions as of the time thestatements are made and we undertake no obligation to update these statements.Our actual results may differ significantly from the results discussed in theforward-looking statements. General factors that might cause such differencesinclude, but are not limited to:

·                 Changesin gas prices due to volatility of the market

·                 Ourability to evaluate our future performance due to limited operating history

·                 Thecontinuance of reserve replacement through development of existing propertiesin order to sustain production

·                 Ourability to insure against liabilities associated with properties or obtainprotection from sellers against them

·                 Ourability to evaluate projections of acquired property production

·                 Ourability to acquire or transact business due to requirements of significant externalcapital changing our risk and property profile.

·                 Ourability to manage the risks inherent in operations of gas properties

·                 Ourexposure to guaranteed indebtedness of our subsidiaries and the covenants inthe agreements governing that debt

·                 Ourability to manage due to covenants limiting discretion of management inoperating our business

·                 Ourability to perform certain development operations depends on financing throughequity or debt

·                 Ourability to successfully integrate future acquisitions

·                 Ourability to attract and retain professional personnel

For moreinformation on these and other risk factors that may affect our business, referto Item 1A “Risk Factors” included in this Annual Report on Form 10-K.

**PART I**

**ITEM1.**            BUSINESS

**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 weoperate and for third-party producers. We were initially incorporated in Nevadaunder the name “PRB Transportation, Inc.” in December 2003.  In January 2004, we acquired certain gasgathering and related assets of our predecessor company, TOP Gathering, LLC (“TOP”),a privately held Colorado company formed in 2001.  On June 14, 2006, we changed our name to “PRBEnergy, Inc.”  Our common stock is tradedon the American Stock Exchange (“AMEX”) under the ticker symbol “PRB.”

PRB Energyoperates as two business segments through two wholly-owned subsidiaries, PRBOil and Gas, Inc., a Colorado corporation, a gas and oil exploitation andproduction company (“E&P”), formed in July, 2005, and PRB Gathering, Inc.,a Colorado corporation, a gathering and processing company (“G&P”), formedin August 2006.  We conduct our businessactivities in Wyoming, Colorado and Nebraska.

**RecentDevelopments**

*CapitalLease** ***On February 12, 2007, we enteredinto a five-year lease agreement with J-W Power Company (“J-W”), effectiveJanuary 24, 2007.  Under the terms of theagreement, J-W will supply us with gas compression equipment and relatedservices.  The compression equipment willservice our gas gathering pipelines in the Powder River Basin.

The lease has beenrecorded in our February 2007 financial statements as a capital lease asset of$3 million, along with the corresponding liability of the same amount, whichrepresents the estimated fair value of the property.  In addition, a cash prepayment of $650,000was made to J-W for future maintenance repairs in connection with thelease.  The capital lease and prepaymentwill be amortized as expense over the term of the lease.  Monthly lease payments, including interestand executory (sales tax and environmental fees) expenses, will reduce theliability.

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*Registrationof Additional Shares of PRB Energy, Inc. Common Stock*  In connection with the borrowing of $15million from 2 private lenders for the Denver-Julesburg Basin acquisition onDecember 28, 2006, we issued 1,250,000 shares of PRB Energy common stock to thelenders.  We also entered into aRegistration Rights Agreement with the lenders requiring us to file a registrationstatement registering the shares issued to the lenders for resale on behalf ofthem under the Securities Act of 1933. We filed the registration statement on Form S-3 with the SEC on February2, 2007.  The SEC staff comments havebeen received and we responded to them on March 22, 2007.

**2006 Acquisitions and Divestitures**

*Pennaco Assets *On June 30, 2006, we acquired workinginterests in approximately 590 gross (531 net) coal-bed methane (“CBM”) wellson approximately 29,000 acres located in the Powder River Basin of Wyoming fromPennaco Energy, Inc. (“Pennaco”). The purchase price of the acquired interestswas approximately $600,000 and the effective date was July 1, 2006. As part ofthe purchase agreement, we issued a $3 million reducing letter of credit forthe benefit of Pennaco to guarantee the funding of the future liability of theplugging costs of wells being purchased from Pennaco. The asset retirementobligation of these wells has been recorded on the balance sheet for $2 millionbased on the discounted present value of the future liability, as furtherreflected in “Note 3 — Concentration of Credit Risk” to our consolidatedfinancial statements included in Item 8 of this report.  The letter of credit is collateralized by a$3 million certificate of deposit (“CD”) and is considered restricted cash forpurposes of available working capital. The restricted amount of the CD will be released at the same rateannually that the letter of credit is reduced (refer to management’s discussionon Liquidity and Capital Resources in the Management’s Discussion and Analysissection in this report).

Of the 590 grosswells acquired, fewer than 130 wells were commercially producing natural gas.We currently have approximately 220 wells on production or dewatering.

*Denver-Julesburg Basin (“D-J Basin”**)*** On December 28, 2006, we closed on the acquisition of 13 wells,consisting of 12 gas wells and 1 water disposal well, and approximately 330,000net acres in northeastern Colorado and southwestern Nebraska, to which we referto as the Properties, for $11.7 million in cash.  The sellers of theProperties were Lance Oil & Gas Company, Inc. and Western Gas Resources,Inc.  In addition to the producing wells, the acquisition includesapproximately 159 drilling locations as identified by 3-D seismic and thelicense to 85 square miles of proprietary 3-D seismic and 115 miles ofproprietary 2-D seismic.

On December 28,2006, in connection with the acquisition of the Properties, we entered into asecurities purchase agreement (“SPA”) with DKR Soundshore Oasis Holding FundLtd. and West Coast Opportunity Fund, LLC, which we refer to as thelenders.  Pursuant to the SPA, in exchange for $15 million of proceeds, weissued and sold to the lenders $15 million of Senior Secured Debentures (the “Debentures”)and we issued and sold to the lenders 1,250,000 shares of common stock.  The Debentures mature and are due and payableon August 31, 2008 and bear interest at 13% per annum, which is due and payablequarterly.  Subject to certain conditions, the Debentures can be prepaidby us with a premium for early prepayment of 110% of the principal amounts. Upon the occurrence of an event of default, as described in theDebentures, the payment of the principal amounts may be accelerated and theinterest rate applicable to the principal amounts will be increased to 18% perannum during the period the default exists. A majority of the proceeds received from the lenders was used for theacquisition of the properties with the balance to be used for general corporatepurposes.

Pursuant to theterms of a pledge and security agreement (“PSA”) entered into by the Companyand the lenders, the Debentures are collateralized by substantially all of ourassets, except for certain excluded assets as described in the PSA. Pursuant to the terms of the PSA, the lenders are entitled to foreclose on, andtake possession of, the pledged assets if an event of default occurs.  Inaddition, pursuant to the terms of the secured guaranty, the Company has agreedto jointly and severally guarantee performance under the Debentures and theother transaction documents.

The shares of ourcommon stock issued to the lenders at the time they were issued represented14.5% of our outstanding common stock on a fully diluted basis.  We alsoentered into a registration rights agreement with the lenders requiring us tofile a registration statement registering the shares issued to the lenders forresale on behalf of them under the Securities Act of 1933.  In the eventthat the registration statement is not declared effective within onehundred-fifty (150) days of December 28, 2006 (by May 28, 2007) or theeffectiveness of the registration statement is not maintained, we are obligatedto pay, on a pro rata basis, to each holder of the shares of common stockissued to the lenders certain delay payments described in the registrationrights agreement.  Such delay payments shall not exceed, in the aggregate,$750,000.  A registration statement wasfiled to register these shares with the SEC on February 2, 2007.

*Recluse Gathering System*  In the first quarter of 2006, we acquired 2gas gathering systems in the Recluse area of Wyoming (together our “Recluse”gathering system) for approximately $1.5 million. Also, in 2 separatetransactions totaling $183,000, we acquired a combination of working interestsranging from 7.5% to 15% in the development of approximately 5,600 net acres inthe Recluse area that offers us the opportunity to expand both our developmentand production and gathering and processing activities in this area.

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

*Sale of TOP Gathering System *As of September 1, 2006 we sold certaingas gathering assets referred to as the TOP Gathering 

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System to Arete Industries, Inc. for $330,000 incash.  The net gain on the sale of $308,000 is reflected in Other Incomein the December 31, 2006 consolidated financial statements included in Item 8of this report.

**Competition**

*Exploitationand Production (E&P) *The Company’s gas exploitation activities take place in a highlycompetitive and speculative business atmosphere.  As an independent producer we have littlecontrol over the price we receive for our natural gas.  As such, higher costs, fees and taxesassessed at the producer level cannot necessarily be passed on to ourcustomers.  In seeking suitable oil andgas properties for development or acquisition, we compete with a number ofother companies, including large oil and gas companies and other independentoperators with greater financial resources. In addition, because we have fewer financial and human resources thanmany companies in our industry, we may be at a disadvantage in bidding forexploratory prospects and producing oil and natural gas properties.

*GasGathering and Processing (G&P) *Gas gathering systems are generallyeither acquired or developed pursuant to long-term contracts with gas producersor the shippers they service.  Thecontracts generally run over a period of time which approximates a majority of theeconomic life of the gas producers’ wells. We believe that having such contracts and an existing gathering systemin place provides a significant barrier of entry to third parties seeking tocompete with us upon the expiration of our contracts.

When developingnew gathering systems in areas where we do not have the advantage of existingsystems in proximity to the development, we may be competing with othergathering system operators or the producer may elect to construct and own thesystem. In the case of other gathering system operators, many possessfinancial, technical and personnel resources substantially greater than ours.

**Environmental Regulation**

All of the waterproduced by our CBM wells is discharged on the surface.  The discharge points are covered by approveddischarge permits from the Wyoming Department of Environmental Quality(WDEQ).  An ongoing requirement ofmaintaining compliance is regular monitoring of the water quality beingdischarged.  We employ a rigorous programof water discharge permit approval and routine water discharge compliancemonitoring.

We operategathering systems in Wyoming and Colorado, for which proper constructionpermits were obtained prior to initial construction.  We have operating permits in place, and wemeet all requirements associated with operation and reporting associated withthese permits.   We have applied for twoadditional operating permits in the Recluse area, which we anticipate beingissued in the second quarter of 2007.

Federal, state andlocal authorities extensively regulate the energy industry.  Legislationand regulations affecting the industry are under constant review for amendmentor expansion, raising the possibility of changes that may affect, among otherthings, the pricing or marketing of gas production.  Noncompliance withstatutes and regulations may lead to substantial penalties, and the overallregulatory burden on the industry increases the cost of doing business and, inturn, decreases profitability.

Governmentalauthorities regulate various aspects of gas drilling and production, includingthe drilling of wells (through permit and bonding requirements), the spacing ofwells, the unitization or pooling of gas properties, environmental matters,safety standards, the sharing of markets, production limitations, plugging andabandonment and restoration.

Our operations arealso subject to complex and constantly changing environmental laws andregulations adopted by federal, state and local governmental authorities injurisdictions where we are engaged in development or productionoperations.  New laws or regulations, or changes to current requirements,could result in material costs or claims with respect to properties we own orhave owned.  We will continue to be subject to uncertainty associated withnew regulatory interpretations and inconsistent interpretations between stateand federal agencies.  We could face significant liabilities togovernmental authorities and third parties for discharges of oil, natural gasor other pollutants into the air, soil or water, and we could have to spendsubstantial amounts on investigations, litigation and remediation. Existing environmental laws or regulations, as currently interpreted orenforced, or as they may be interpreted, enforced or altered in the future, mayhave a material adverse effect on us.

We have reflectedin our consolidated financial statements a reserve for future capitalexpenditures for remediation costs at the end of the life of the wells and lifeof the gathering assets.  Refer to “Note7 — Asset Retirement Obligations” to our consolidated financial statements inItem 8 of this report.

**Intrastate Regulation**

No regulatory bodycontrols the gathering rates we may charge.

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**Safety and Maintenance**

*Exploitationand Production (E&P) *We conduct safety training classes for all of our field employeesdealing with oil and gas development and production. As of December 31,2006, all field employees have participated in these classes and are incompliance with safety regulations.

*GasGathering and Processing (G&P) *With respect to certain gatheringoperations, we contract with third parties to perform preventive and normalmaintenance on some of our gathering systems and make repairs and replacementswhen necessary or appropriate. On our behalf, third parties also conductroutine and required inspections of our gathering and other assets as requiredby applicable code or regulation. External coatings and cathodic protection systems are used to protectagainst external corrosion.  The systemsare continually monitored and tested, and the results recorded, to ensure theearly identification of any problem that may arise.  We have contracted a third party to providethe necessary training to our employees as required by the Occupational Safetyand Health Administration.

**SignificantContracts**

*Storm Cat Agreement* Effective January 1, 2006, we entered into agas gathering services agreement (“the Agreement”) with Storm Cat EnergyCorporation (“Storm Cat”) which requires Storm Cat to pay us gas gathering feeson specific minimum volumes of gas whether or not those volumes are deliveredand transported through our system. The Agreement has a 10-year term, of whichthe first 5 years are non-cancelable. The Agreement requires Storm Cat to make minimum payments in 2006 andduring the first 3 years of the Agreement.  The Agreement also providesfor our gas gathering rates to decrease during the fourth and fifth years.

During the yearended December 31, 2006, we billed Storm Cat for actual volumes delivered.  The Agreement allows for a cash true-uppayment at each year-end if the annual volume commitment under the Agreement isnot met.  We recognize revenues based onour estimate of the average gas gathering rate during the non-cancelable termof the Agreement.  Accordingly, wedeferred the gas gathering fees as a non-current liability on our balance sheetat December 31, 2006.

*Rocky Mountain Gas Agreement*Referto Item 3, “Legal Proceedings” of this report.

**Major Customers**

*Exploitation and Production (E&P) *We sold 22.2% of total consolidatedrevenue on a spot sale basis to United Energy Trading Company during the yearended December 31, 2006. We have the option to sell to a number of othermarketing companies within the region.

*Gathering and Processing (G&P) *Our G&P systems service severalcustomers in the Powder River Basin area of Wyoming.  Storm Cat is our largest gathering andprocessing customer at approximately 21.2% of total consolidated revenue forthe year ended December 31, 2006.

We do not believethe loss of either of the above major customers would have a material adverseaffect on our financial position.  Pleaserefer to our consolidated financial statements included in Item 8 of this report.

**Seasonality**

*Both E&P and G&P Business Segments *Generally, but not always, the demand andprice levels for natural gas increase during the colder winter months and thewarmer summer months.  In addition,pipelines, utilities, local distribution companies and industrial users utilizenatural gas storage facilities and purchase some of their anticipated winterrequirements during the summer, which can lessen seasonal demandfluctuations.  Seasonal anomalies such asmild winters and summers sometimes lessen these fluctuations.

**Employees**

As ofDecember 31, 2006, we had 26 full-time employees compared to December 31,2005 when there were 18 full-time employees.

**Access to Information**

Our websiteaddress is www.prbenergy.com. We make available, free of charge, on theInvestor Relations section of our website, our public informational releases,SEC annual reports on Form 10-K, quarterly reports on Form 10-Q, andcurrent reports on Form 8-K and all amendments to those reports, as soonas reasonably practicable after these reports are electronically filed with orfurnished to the SEC.  We do not intendfor information contained in our website to be part of this report.

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**ITEM 1A.**        RISK FACTORS

*Youshould carefully consider the following risks and other information containedin this report.  These risks couldmaterially affect our business, results of operations or financial conditionand cause the trading price of our common stock to decline.  The risks and uncertainties described beloware not the only risks facing us.  Additionalrisks not presently known to us or which we consider immaterial based oninformation currently available to us may also materially adversely affectus.  If any of the following risks oruncertainties actually occurs, our business, financial condition and results ofoperations could be adversely affected.*

**RisksRelated to the Natural Gas Industry and Our Business**

***We have incurred net losses from operations sinceinception.  Our future performance is difficult to evaluate because wehave a limited operating history.***

Our operations commencedin January 2004.  Since our inception, we have incurred net losses. For the years ended December 31, 2006, 2005 and 2004, we incurred net losses of$8.7 million, $4.8 million and $1.9 million, respectively.  The uncertainty and factors describedthroughout this section may impede our ability to economically find, developand acquire natural gas and oil reserves.  As a result, we may not be ableto achieve or sustain profitability or positive cash flows from operatingactivities in the future.

***Natural gas prices are volatile and a decline in pricescould hurt our profitability, financial condition and ability to grow.***

Our revenues, operatingresults, profitability, future rate of growth and the carrying value of our gasproperties depend heavily on the prices we receive from natural gassales.  Gas prices also affect our cash flows and borrowing base, as wellas the amount and value of our gas reserves.

Historically, the marketsfor gas have been volatile and they are likely to continue to bevolatile.  Wide fluctuations in gas prices may result from relativelyminor changes in the supply of and demand for gas, market uncertainty and otherfactors that are beyond our control, including:

·                  domesticsupplies of natural gas;

·                  technologicaladvances affecting energy consumption;

·                  the price andavailability of alternative fuels;

·                  worldwide anddomestic economic conditions;

·                  the level ofconsumer demand;

·                  the availabilityof transportation facilities;

·                  weather conditions;and

·                  governmentalregulations and taxes.

These factors and thevolatility of gas markets make it very difficult to predict future gas pricemovements with any certainty.  Declines in gas prices would reduce ourrevenues and could also reduce the amount of gas that we can produceeconomically and therefore could have a material adverse effect on us.

***Substantial acquisitions or other transactions could requiresignificant external capital and could change our risk and property profile.***

In order to financeacquisitions of additional producing properties, we may need to alter orincrease our capitalization substantially through the issuance of debt orequity securities, the sale of production payments or other means.  Thesechanges in capitalization may significantly affect our risk profile. Additionally, significant acquisitions or other transactions could change thecharacter of our operations and business.  The character of the newproperties could be substantially different in operating or geological characteristicsor geographic location than our******existing properties.  Furthermore, we may not beable to obtain external funding for future acquisitions or other transactionsor to obtain external funding on terms acceptable to us.

***If we are not able to replace reserves, we will not be ableto sustain production.***

Our future operationsdepend on our ability to find, develop and acquire oil and gas reserves thatare economically recoverable.  Our properties produce gas at a decliningrate over time.  In order to become profitable we must develop ourrecently acquired properties or locate and acquire new oil and gas reserves toreplace those being depleted by production.  We may do this even duringperiods of low oil and gas prices.  Competition for the acquisition ofproducing oil and gas properties is intense and many of our competitors havefinancial and other resources for acquisitions that are substantially greaterthan those available to us.  Therefore, we may not be able to acquire oiland gas properties that contain economically recoverable reserves, or we maynot be able to acquire such properties at prices acceptable to us. Without successful drilling or acquisition activities, our reserves, productionand revenues will decline.

***Properties we acquire may not produce as projected, and wemay be unable to identify liabilities associated with the properties or obtainprotection from sellers against them.***

Our business strategyincludes an acquisition program.  The successful acquisition of producingoil and gas properties requires assessments of many factors, which areinherently inexact and may be inaccurate, including the following:

·                  the amount ofrecoverable reserves;

·                  future oil andnatural gas prices;

·                  estimates ofoperating costs;

·                  estimates offuture development costs;

·                  estimates of thecosts and timing of plugging and abandonment; and

·                  potentialenvironmental and other liabilities.

Our assessment will notreveal all existing or potential problems, and may not permit us to becomefamiliar enough with the properties to fully assess their capabilities anddeficiencies.  In the course of our due diligence, we may not inspectevery well or 

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pipeline.  Inspections may not reveal structuraland environmental problems, such as pipeline corrosion or groundwatercontamination, when they are made.  We may not be able to obtaincontractual indemnities from the seller for liabilities that it created. We may be required to assume the environmental and production risks associatedwith the properties.

***The guarantee of certain indebtedness of our subsidiary andthe covenants in the agreements governing that debt and the guarantee couldnegatively impact our financial condition, results of operations and businessprospects.***

On December 28,2006, we issued $15 million in Debentures to certain lenders.  Weguaranteed payment of this debt and pledged substantially all of our assets ascollateral.  If we fail to comply with the covenants and otherrestrictions in the agreements governing the Debentures, an event of defaultcould occur that would permit the lenders to foreclose on substantially all ofour assets.  Our ability to comply with these covenants and otherrestrictions may be affected by events beyond our control, including prevailingeconomic and financial conditions.  If we cannot make certain paymentsunder the Debentures, we may not have sufficient funds to make the guaranteedpayments.  If we are required but unable to make the guaranteed paymentsunder the Debentures out of cash on hand or from internal cash flow, we couldattempt to refinance the Debentures, sell assets, or repay the Debentures withthe proceeds from an equity or debt offering.  However, we may not be ableto raise sufficient capital through the sale of assets or issuance of equity ordebt to pay or refinance the amounts owed.  The terms of the SecuredGuaranty and the Debentures may also prohibit us from taking such actionswithout first retiring the debt represented by the Debentures.  Factorsthat will affect our ability to raise cash through a sale of assets or a debtor equity offering include financial market conditions and our market value andoperating performance at the time of such offering or other financing.  Wemay, therefore, not be able to successfully complete any such offering or saleof assets.

***The agreements governing the Debentures contain variouscovenants limiting the discretion of our management in operating our business.***

The guarantee of,and the agreements governing, the Debentures contain various restrictivecovenants.  In particular, these agreements limit our ability, withoutlenders’ approval, to, among other things:

·                  pay dividendson, redeem or repurchase our capital stock;

·                  make loans toothers;

·                  incur additionalindebtedness or issue preferred stock;

·                  create certainliens; and

·                  purchase or sellassets.

If we fail tocomply with the restrictions in the Secured Guaranty, or the agreementsgoverning, the Debentures, an event of default may allow the creditors toforeclose on substantially all of our assets.  Any such default orforeclosure could have a material adverse effect on us.

***We may be required to make significant cash payments if wefail to satisfy certain registration requirements set forth in the RegistrationRights Agreement.***

In connection withthe $15 million Debentures, we issued 1,250,000 shares of common stock to DKRSoundshore Oasis Holding Fund Ltd. and West Coast Opportunity Fund, LLC andentered into a Registration Rights Agreement.  Pursuant to that agreement,if we fail to:  (i) have the registrationstatement declared effective by the SEC on or before the date that is 150 daysafter December 28, 2006 (an “Effectiveness Failure”) or (ii) maintain theeffectiveness of this registration statement while shares of common stockcovered by the Registration Rights Agreement remain unsold (a “MaintenanceFailure”), then, unless the grace periods set forth in the Registration RightsAgreement apply, as partial relief for the damages to any holder by any suchdelay in or reduction of its ability to sell the shares of common stock, wemust pay to each holder an amount in cash equal to 1% of the aggregate purchaseprice (as such term is defined in the Securities Purchase Agreement for theDebentures) allocable to such holder’s securities on each of the followingdates:  (i) the day of an EffectivenessFailure and on every 30th day thereafter until such Maintenance Failure iscured and (ii) the initial day of a Maintenance Failure and on every 30th daythereafter until such Maintenance Failure is cured.  If we fail to makethese registration delay payments in a timely manner, the registration delaypayments will bear interest at the rate of 2% per month until paid infull.  The aggregate amount of registration delay payments may not exceed$750,000.  We filed the registrationstatement on Form S-3 with the SEC on February 2, 2007.

***Our Senior Subordinated Convertible Notes (the “Notes”) arecollateralized by some of our assets, which could result in a loss of thoseassets if we were to default on those debt instruments.***

During the firstquarter of 2006, we issued through a private offering approximately $22 millionthe Notes that carry an interest rate of 10% per annum, with interest due andpayable on a quarterly basis.  The Notes are collateralized by certain ofour gathering assets.  If we cannot make certain payments under the Notes,we may default upon our obligations and the noteholders under the Notes and ourcreditors could foreclose on these assets.  Under certain circumstances, adefault upon our obligations under the Notes could lead to an event of defaultunder the Debentures.  Any such default or foreclosure could have amaterial adverse effect on us.

***Our development operations require substantial capital andwe may be unable to obtain needed capital or financing on satisfactory terms,which could lead to a disposition of properties and a decline in our naturalgas reserves.***

The energyindustry is capital intensive.  We make and expect to continue to makesubstantial capital expenditures in our business and operations fordevelopment, production and acquisition of oil and natural gas reserves. To date, we have financed capital 

8

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expenditures primarilywith proceeds from the issuance of debt and equity plus cash generated byoperations.  We intend to finance our future capital expenditures withcash flow from operations and from debt or equity capital.  Our cash flowfrom operations and access to capital is subject to a number of variables,including:

**·**                  our provedreserves;

·                  the level ofnatural gas we are able to produce from existing wells;

·                  the prices atwhich natural gas is sold; and

·                  our ability toacquire, locate and produce new reserves.

If our revenues decreaseas a result of lower natural gas prices, operating difficulties, declines inreserves or for any other reason, then we may have limited ability to obtainthe capital necessary to sustain our operations at current levels.  Wemay, from time to time, need to seek additional financing.  There can beno assurance as to the availability or terms of any additional financing.

If additional capital isneeded, then we may not be able to obtain debt or equity financing on termsfavorable to us, or at all.  If cash generated by operations is notsufficient to meet our capital requirements, the failure to obtain additionalfinancing could result in a curtailment of our operations relating todevelopment of our prospects, which in turn could lead to a possibledisposition of properties and a decline in our reserves.

***Drilling for and producing oil and natural gas are high riskactivities with many uncertainties that could adversely affect our business,financial condition or results of operations.***

Drilling and productionactivities are subject to numerous risks, including the risk that nocommercially productive oil or natural gas will be found.  The cost ofdrilling and completing wells is often uncertain, and oil and gas drilling andproduction activities may be shortened, delayed or canceled as a result of avariety of factors, many of which are beyond our control.  These factorsinclude:

·                  unexpecteddrilling conditions;

·                  title problems;

·                  pressure orirregularities in formations;

·                  equipment failuresor accidents;

·                  adverse weatherconditions;

·                  compliance withenvironmental and other governmental requirements;

·                  delays caused byregulatory approvals from state, local and other governmental authorities;

·                  shortages or delays in theavailability of or increases in the cost of drilling rigs and the delivery ofequipment;

·                  lack ofavailability of experienced drilling crews; and

·                  lack of pipelineavailability or pipeline capacity.

The wells we drill maynot be productive and we may not recover all or any portion of our investmentin such wells.  The seismic data and other technologies that we use do notallow us to know conclusively prior to drilling a well that oil or gas ispresent or may be produced economically.  The cost of drilling, completingand operating a well is often uncertain, and cost factors can adversely affectthe economics of a project.  Drilling activities can result in dry holesor wells that are productive but do not produce sufficient net revenues afteroperating and other costs to cover initial drilling costs.

Our future drillingactivities may not be successful, or our overall drilling success rate or ourdrilling success rate for activity within a particular area may decline. Although we have identified numerous potential drilling locations, we may notbe able to economically produce oil or natural gas from them.

The occurrence of any orall of these risks could have a materially adverse effect on our business,financial condition and results of operations.

***Our use of 2-D and 3-D seismic data is subject tointerpretation and may not accurately identify the presence of natural gaswhich could adversely affect the results of our drilling operations.***

Even when properly usedand interpreted, 2-D and 3-D seismic data and visualization techniques are onlytools used to assist geoscientists in identifying subsurface structures andhydrocarbon indicators and do not enable the interpreter to know whetherhydrocarbons are, in fact, present in those structures.

***Substantially all of our producing properties are located inthe Rocky Mountain region, making us vulnerable to risks associated withoperating in one major geographic area.***

Our operations arefocused on the Rocky Mountain region, which means our producing properties aregeographically located in the states of Colorado, Nebraska and Wyoming. As a result, we may be disproportionately exposed to the impact of delays orinterruptions of production from these areas caused by significant governmentalregulation, transportation capacity constraints, curtailment of production orinterruption of transportation of natural gas produced from the wells in thesebasins.

***Our operations are subject to operational hazards andunforeseen interruptions for which we may be inadequately insured, resulting inlosses to us.***

Our operations, includinggathering, processing, exploitation and production, are subject to operationalhazards and unforeseen interruptions such as natural disasters, adverseweather, accidents, fires, explosions, hazardous materials releases, mechanicalfailures and other events beyond our control.  These events might resultin a loss of equipment or life, injury or extensive property damage, as well asan interruption in our operations.  We may not be able to maintain or obtaininsurance of the type and amount we desire at reasonable rates.  In someinstances, certain insurance could become unavailable or available only forreduced amounts of coverage.

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A significant liability for which we were not fullyinsured could adversely affect us.

***Our operations are subject to complex laws and regulations,including environmental regulations, that may result in substantial costs andother risks.***

Federal, state andlocal authorities extensively regulate the energy industry.  Legislationand regulations affecting the industry are under constant review for amendmentor expansion, raising the possibility of changes that may affect, among otherthings, the pricing or marketing of gas production.  Noncompliance withstatutes and regulations may lead to substantial penalties, and the overallregulatory burden on the industry increases the cost of doing business and, inturn, decreases profitability.

Governmentalauthorities regulate various aspects of gas drilling and production, includingthe drilling of wells (through permit and bonding requirements), the spacing ofwells, the unitization or pooling of gas properties, environmental matters,safety standards, the sharing of markets, production limitations, plugging andabandonment and restoration.

Our operations arealso subject to complex and constantly changing environmental laws andregulations adopted by federal, state and local governmental authorities injurisdictions where we are engaged in development or productionoperations.  New laws or regulations, or changes to current requirements,could result in material costs or claims with respect to properties we own orhave owned.  We will continue to be subject to uncertainty associated withnew regulatory interpretations and inconsistent interpretations between stateand federal agencies.  We could face significant liabilities togovernmental authorities and third parties for discharges of oil, natural gasor other pollutants into the air, soil or water, and we could have to spendsubstantial amounts on investigations, litigation and remediation. Existing environmental laws or regulations, as currently interpreted orenforced, or as they may be interpreted, enforced or altered in the future, mayhave a material adverse effect on us.

***Future oil and gas price declines or unsuccessfuldevelopment efforts may result in write-downs of our development and productionasset carrying values, thereby reducing our assets and net worth.***

We follow thesuccessful efforts method of accounting for our oil and gas properties. All property acquisition costs and costs of development wells are capitalizedwhen incurred, pending the determination of whether proved reserves have beendiscovered.

The capitalizedcosts of our oil and gas properties, on a field basis, cannot exceed theestimated future net cash flows of that field.  If net capitalized costsexceed future net revenues, we must write-down the costs of each such field toour estimate of fair market value.  Unproved properties are evaluated atthe lower of cost or fair market value.  Accordingly, a significantdecline in oil or gas prices or unsuccessful development efforts could cause afuture write-down of capitalized costs, reducing our assets and net worth.

We review thecarrying value of our properties quarterly based on prices in effect as of theend of each quarter.  Once incurred, a write-down of oil and gasproperties cannot be reversed at a later date even if oil or gas pricesincrease.

***Competition in our industry is intense and many of ourcompetitors have greater financial and technical resources than we do.***

We face intensecompetition from major oil companies, independent oil and gas exploration andproduction companies, financial buyers and institutional and individualinvestors who are actively seeking oil and gas properties in the Rocky Mountainregion in which we operate and elsewhere.  Many of our competitors havefinancial and technical resources along with equipment, expertise, labor andmaterials significantly exceeding those available to us.  In addition, many properties are sold in acompetitive bidding process in which our competitors may be able to pay morefor development prospects and productive properties, or in which ourcompetitors have technological information or expertise to evaluate andsuccessfully bid for the properties that is not available to us. Shortages of equipment, labor or materials as a result of intense competitionmay result in increased costs or the inability to obtain those resources asneeded.  We, therefore, may not be successful in acquiring and developingprofitable properties in the face of this competition.

***A significant decrease in the supply of natural gas from ourgas gathering customers could reduce our revenue and earnings.***

Investments by ourgas gathering customers in the maintenance of existing wells and the furtherdevelopment of their reserves will affect their production rates and the volumeof gas we gather.  Drilling activity generally decreases as gas pricesdecrease.  We have no control over our customers’ level of drillingactivity, the amount of reserves underlying their wells and the rate at whichtheir production from a well will decline.  Drilling activity of ourcustomers is affected by, among other things, prevailing and projected energyprices, demand for hydrocarbons, geological considerations, governmentalregulation and the availability and cost of capital.  A significantdecrease in the supply of natural gas we are gathering would reduce our revenueand results of operations.

***We depend on our chief executive and chief operatingofficers for critical management decisions and industry contacts.***

We do not haveemployment agreements with our chief executive and chief operating officers anddo not carry key person insurance on their lives.  The loss of theservices of either of these executive officers, through incapacity orotherwise, could have a material adverse effect on our operations and wouldrequire us to seek and retain other qualified personnel.

**ITEM1B.**      UNRESOLVED STAFF COMMENTS

Not applicable.

 

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**ITEM2.**                    PROPERTIES

**Description of Properties**

***Powder River Basin - CBM***

Gas produced from PowderRiver Basin coals is almost 100% methane. The gas is generated during the coalforming process and is trapped in the coal beds by water. In order to producethe coal gas, the formation must first be dewatered. As the water is removedfrom the coal, the gas is desorbed from the coal. All of the coal-bedreservoirs are low pressure and require compression in order for the gas to bedelivered to a pipeline transportation system.

Natural gas wells in thePowder River Basin area typically experience sharp declines in productionvolume in the first several years of production. Production then stabilizes anddeclines more ratably over a gas well’s average life of approximately eight toten years. Other factors which influence the initial and long-term productivityof the coal-bed methane wells are the depths of the coal fields, the initialgas saturation levels of the coal field and the well spacing.

***D-J Basin-Niobrara Formation***

In 1972, MountainPetroleum, Inc. completed five commercial Niobrara wells in Beecher IslandField.  From 1975 to 1982 an additional46 fields were discovered in Colorado, northwestern Kansas, and southwesternNebraska.  Recent activity in the area byBill Barrett Corp., Berry Petroleum, Houston Exploration, Noble Energy,Petroleum Development Corp. and others have included amassing large acreageblocks, performing extensive seismic evaluations and initiating drillingprograms.

Modern methods used toevaluate the Niobrara in the eastern D-J Basin are predominately driven bygeophysics.  Typically, leads aregenerated by 2-D seismic or subsurface mapping. The delineated anomalies are subsequently shot with 3-D seismic,effectively identifying gas by amplitude.

The Niobrara target zonein the eastern portion of the D-J Basin has a relatively low permeability.  Production occurs in depths from 900 to 3,500feet and the reservoir is somewhat under-pressured relative to normalhydrostatic pressure.  Fields aregenerally located on low relief (50 to 200 feet) anticlines or faultedstructures with the downdip portion of the reservoir generally wet.  Completion techniques, as a standardpractice, include hydraulically induced fractures.

***Recluse Gathering Systems***

In 2006, we made threeacquisitions that have been combined into our Recluse Gathering System.  The system now includes 2 compressorstations, interconnects with 2 major transportation lines and 74.5 miles ofsteel pipelines.  We currently havecontracts with two producers, with several other contracts in negotiation.

*NESHCompressor Stations.* We purchased these assets from Storm Cat on January 18, 2006.  Assets include 2 compressor stations and 2miles of 12-inch poly pipe connecting the stations on the low pressureside.  The stations include piping,scrubbers, tanks, and compressor buildings. The compression lease, month to month, with Universal compression wasassigned to us by seller.   We signed agathering agreement with Storm Cat at the same time.

*HighPressure Discharge lines.* We purchased these assets from Clear Creek Natural Gas, LLC on March 1,2006.  Assets include 4.5 miles of 8-inchsteel pipe, 2 miles of 6-inch steel pipe, meter stations at both compressorstations, and an interconnect with Thundercreek, one of the majortransportation lines in the area.  Wealso acquired a fee-based gathering contract with Storm Cat for use of thesefacilities.

*MaverickPipelines*. We purchased approximately 70 miles of 6-inch steel pipeline fromMaverick Pipeline, LLC.  Seven miles ofthis old oil gathering systems have been converted to gas service and we wereassigned a gathering contract associated with this line.  We also acquired an interconnect withWilliston Basin Interstate Pipeline Company.

***South Gillette (Formerly Known as Bear Paw) GatheringSystems***

Effective August 1,2004, we acquired certain gathering systems and related contracts from Bear PawEnergy (“BPE”) located in Campbell County, Wyoming. The systems acquiredinclude the following:

·         Gapgas gathering system;

·         BonePile gas gathering system;

·         AntelopeValley delivery line, and

·         South Kitty deliveryline.

Concurrent withthe acquisition, we entered into an operations agreement with BPE. Theagreement requires BPE to operate the systems for us, including repairs,maintenance and compression services, for a monthly fee of $80,000.  As a result of the consolidation in theBonepile area and a reduction in the compression utilized, this monthly fee wasreduced to $58,000 in June,2006.  Theother significant factor impacting the South Gillette gathering system was ourpurchase of the underlying gas reserves from Pennaco in June 2006.  This resulted in our owning approximately 50%of the gas being gathered.  On January24, 2007 JW Power purchased the compression from BPE and entered into a capitallease agreement with us.  Concurrently wetook over daily operations using our Gillette field employees.  

The Gap andBonepile gathering systems were constructed in 1999 and 2000,respectively.  These systems consist of8, 12, 16 and 20-inch steel pipe totaling 34 miles in length and 152 miles oflow pressure poly pipe.  Collectively,these systems are connected to approximately 650 CBM wells.  The Antelope Valley and South Kitty Deliverylines were installed in 1999 and 2002, respectively.  The Antelope Valley line is a 10-inchpipeline that moves gas from the Antelope Valley Facility to the Fort Union andThunder Creek pipelines.  The South Kittyline is a 12-inch pipeline that moves gas from the north side of the Bonepilegathering system to BPE South Kitty station.

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**Reserves**

We engagedindependent geological and petroleum engineering consultants Netherland, Sewell& Associates, Inc. (“NSAI”) in 2006, and Sproule Associates, Inc. (“Sproule”)in 2005, to estimate our natural gas reserves. We also review the calculations and assumptions these consultants use tocalculate our reserves.  We emphasizethat reserve estimates are imprecise by their nature, and that reserveestimates on new discoveries and developments are less precise than reserveestimates for existing fields. Accordingly, we expect these estimates to change as time passes andinformation as to actual well performance can be included in those futureestimates.

Proved oil and gasreserves are estimates of recoverable quantities of oil, natural gas andnatural gas liquids that are determined using engineering and geological datawith reasonable certainty.  The reserveestimates are based on existing economic and operating conditions and includeonly existing wells from known reservoirs with existing equipment andtechnology.  Our proved reserves arelocated in the Powder River Basin area of Wyoming and the D-J Basin innortheastern Colorado and southwestern Nebraska.

The followingtable summarizes our proved reserves data at December 31, 2006 andDecember 31, 2005, respectively:

|                                                                          | ** ** | **2006** | ** ** | **2005(2)** | ** ** |
|--------------------------------------------------------------------------|------------|----------|------------|-------------|------------|
| Gas (MMcf) (1)                                                           |       | 5,674    |       | 396         |       |
| Standardized measure of discounted future net cash flows (in  thousands) |       | $        | 5,507      |        | $          | 688 |   |
| Proved developed reserves (as % of total proved reserves)                |       | 32.3     | %          | 100         | %          |
|                                                                          |            |          |            |             |            |  |  |

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*(1)**          Million Cubic Feet (“MMcf”)*

*(2)**          These amounts representproved developed producing reserves.*

Due to a marketprice anomaly related to unseasonably warm weather and higher gas storagelevels at the end of 2006, the gas price was substantially lower than thequarters before and after year-end 2006. The New York Mercantile Exchange (“NYMEX”) at year-end reflected a priceof $5.64 per million British thermal units (“MMBtu”) or about 20% to 25% belowthe current gas futures contract prices. The CIG price of $4.46 per MMBtu was at a low point at year-end comparedto the fourth quarter of 2006 and the first quarter of 2007.

Our year-endreport of December 31, 2006 prepared by NSAI calculated estimated provedreserves and future revenues by using the weighted average price for totalproved reserves of $3.39 per thousand cubic feet (“Mcf”) (or approximately$4.00 per MMBtu based on an 85% average conversion factor for theseproperties).  The estimated reserves andfuture revenues would have presented a much different result if similar priceswere in effect at year-end as were experienced during the quarters before andafter year-end 2006, which ranged on average from $7.00 to $8.00 per MMBtu atHenry Hub and $4.50 to $6.50 per MMBtu from CIG, before regional differentialsand transportation and compression charges.

Based on a morerepresentative price range, using CIG prices as a reference, of $5.25 to $6.50per MMBtu, the estimated increase in year-end future net revenues discounted at10% would have been between 35% ($2.0 million) to 75% ($4.0 million) for provedreserves.

**Gas Sales**

The following table summarizes the volumes sold and realized pricesfrom our properties during the years ended December 31, 2006 andDecember 31, 2005, respectively.  **All items listed below arebased on gas sales volume (Mcf). Therefore, these values are net numbers where fuel, lost and unaccountedfor gas, and metering variances have been removed prior to the calculation.**

|                                             | ** ** | **2006** | ** ** | **2005** | ** ** |
|---------------------------------------------|------------|----------|------------|----------|------------|
| Net annual gas  sales (Mcf)(1)              |       | 396,000  |       | 6,000    |       |
| Average net  daily gas sales (Mcf)          |       | 1,085    |       | 85       |       |
| Average realized  price of gas per Mcf sold |       | $        | 4.23       |     | $          | 8.50 |   |
| Lease operating  expense per Mcf sold       |       | $        | 3.20       |     | $          | 4.22 |   |
| Production taxes  per Mcf sold              |       | $        | 0.45       |     | $          | 1.06 |   |
| Transportation expense  per Mcf sold        |       | $        | 0.87       |     | $          | 0.38 |   |

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**(1)****         ****Net gas salesrepresent that portion of gas sold that is owned by us and produced to ourownership interest.**

**ProductiveWells**

As of December 31,2006 and December 31, 2005, respectively we had working interests in 692productive wells (571 wells net) and 10 productive wells (4 wells net).Productive wells are either producing or capable of producing although shut-inor de-watering.  Gross wells representthe total number of wells in which we have a working interest.  Net wells represent the number of gross wellsmultiplied by the percentages of the working interests owned by us.  One or more completions in the same bore holeare counted as one well.

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**Drilling Activity**

Allof our drilling activity is performed by independent drilling contractors.  The following table sets forth certaininformation regarding numbers of wells in our drilling activities for theperiods indicated:

|                            | ** ** | **2006**  | ** ** | **2005** | ** ** |
|----------------------------|------------|-----------|------------|----------|------------|
| ** **                 | ** ** | **Gross** | ** ** | **Net**  | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Exploratory wells drilled: |       |      |       |     |       |   |   |   |   |
| Productive                 |       | 0         |       | 0        |       | 18 |   | 7 |   |
| Development wells drilled: |       |      |       |     |       |   |   |   |   |
| Productive                 |       | 66        |       | 14.3     |       | 6 |   | 3 |   |
| Total wells drilled:       |       |      |       |     |       |   |   |   |   |
| Productive                 |       | 66        |       | 14.3     |       | 24 |   | 10 |   |

 

Gross wellsrepresent wells in which we have a working interest; net wells representour aggregate working interests in the gross wells.

**Acreage**

Thefollowing table details the gross and net acres of developed and undevelopedproperties that we hold. Some of the developed and undeveloped acreage includedherein has been earned as part of the Company’s Farm-In and DevelopmentAgreement with Rocky Mountain Gas.  As ofDecember 31, 2006, our properties accounted for the following developed andundeveloped acres:
| ** ** | ** ** | **Developed** | ** ** | **Undeveloped** | ** ** | **Total** | ** ** |
|------------|------------|---------------|------------|-----------------|------------|-----------|------------|
| ** ** | ** ** | **Gross**     | ** ** | **Net**         | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Montana    |       | —        |       | —          |       | 5,893     |       | 2,357 |   | 5,893 |   | 2,357 |   |
| Wyoming    |       | 29,010        |       | 28,292          |       | 301       |       | 162 |   | 29,311 |   | 28,454 |   |
| Colorado   |       | 520           |       | 520             |       | 165,194   |       | 146,358 |   | 165,714 |   | 146,878 |   |
| Nebraska   |       | —        |       | —          |       | 213,629   |       | 177,583 |   | 213,629 |   | 177,583 |   |
| Total      |       | 29,530        |       | 28,812          |       | 385,017   |       | 326,460 |   | 414,547 |   | 355,272 |   |

 

Gross acresrepresent acres in which we have a working interest; net acres represent ouraggregate working interests in the gross acres.

**OfficeFacilities**

We currently leaseoffice space for our corporate headquarters in Denver, Colorado as well asoffice space for our Gillette, Wyoming field operations office.

**ITEM 3.**                    LEGALPROCEEDINGS

***Rocky Mountain Gas Agreement and Claims Dispute***

On March 20,2006, we terminated a Farmout and Development Agreement (the “Farmout Agreement”)dated August 1, 2005 with Enterra Energy Trust’s wholly-owned subsidiary RockyMountain Gas, Inc. (“RMG”).  We, however,continued as field operator under a Joint Operating Agreement (“JOA”) with RMGfor certain CBM properties in Wyoming and Montana that are covered by theJOA.  In February 2006, RMG executed 19authorizations for expenditure to drill and complete the Moyer coal pilotwells.  After termination of the FarmoutAgreement, we, as operator under the JOA, issued a cash call to RMG for RMG’sshare of the estimated well costs for nine wells.  In addition, after termination of the FarmoutAgreement, RMG requested its full working interest in all wells drilled afterthe termination date.

We did not receivepayment from RMG for the well costs as required under the JOA and issued anotice of default to RMG.  The defaultwas not cured within the period prescribed by the JOA and, under the JOA, RMG’sinterest was relinquished to us until such time as the proceeds from the 9Moyer wells equal 300% of the capital expended by us on RMG’s behalf.

On June 22, 2006,RMG filed an arbitration demand against us, asserting that the area of mutualinterest provision in the terminated Farmout Agreement continues until August2007 and, therefore, would provide RMG the right to participate in the Company’sacquisition of certain oil and gas assets in Wyoming including those acquiredfrom Pennaco.  RMG also asserts that weshould pay 100% of the costs of drilling the 9 Moyer wells for a 50% workinginterest.  On August 22, 2006, we deniedRMG’s arbitration claims, and asserted counterclaims against RMG.  On October 20, 2006, RMG amended itsarbitration demand to add three additional claims.  First, RMG claimed that the Company improperlyfailed to provide RMG with data regarding wells developed by the Company forthe parties’ joint benefit.  Second, RMGalleged that the Company improperly allocated, billed and failed to provideadequate documentation and support for amounts billed under the FarmoutAgreement and Management Services Agreement. Third, RMG alleged that the Company improperly shut in one of RMG’snatural gas wells and dug up its gathering line.

We also agreedupon termination of the Farmout Agreement to continue to provide managementservices until June 30, 2006.  As of June30, 2006, we had a receivable due from RMG of $386,000 for management servicesrendered and certain other amounts due 

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from RMG. RMG disputed the amounts due to us. In July2006, the Company and RMG entered into an interim agreement under which, amongother things, RMG paid us $175,000 of the amount due at June 30, 2006.  On October 24, 2006, RMG submitted its auditreport to the Company in which RMG claimed that the Company improperly billedexpenses to RMG under the terms of the agreements between the parties. RMGasserts that it is entitled to an amount in excess of $500,000 as a result ofalleged improper charges by us under the Management Services Agreement (“MSA”)between the parties.  We have also had anindependent audit conducted which disputes the assertions contained in RMG’saudit and concludes that RMG owes us at least $569,000, plus interest of$12,000, under the MSA.  In February2007, RMG paid $176,000 of this amount, leaving a balance due of $405,000 underthe MSA.  At December 31, 2006, we had asecond receivable of $386,000 due from RMG for joint interest billings (“JIB”)on the operated wells, plus interest due of $8,000.

A collectionreserve of $596,000 against the remaining JIB and MSA balances has beenrecorded at December 31, 2006.  Thebalance sheet at December 31, 2006 includes these 2 RMG receivables of $405,000for the MSA and $386,000 for JIB’s totaling $791,000, less the allowance of$596,000, or $195,000.  Any remainingdisputed expenses will be presented for resolution at the May 2007 arbitration.

On January 11,2007, we provided RMG with a Notice of Default for its failure to pay amountsdue under the JOA totaling $324,779.69 plus interest.  RMG did not cure the default by paying theamounts due within the 30-day cure period. On February 5, 2007 RMG provided us with a Notice of Default assertingthat good cause exists to remove us as Operator for its alleged failure toperform its duties under the JOA as a prudent operator.  We deny that we have failed to perform ourduties, and deny that good cause exists to remove us as Operator.  On February 6, 2007, RMG amended itsarbitration demand to assert two additional claims in the pending arbitration.  First, it added a claim based upon ouralleged failure to perform its duties as a prudent operator.  Second, it added a claim that asserts we oweRMG amounts to be determined at the arbitration for our use of RMG’s SurfaceFacilities.  On February 28, 2007 we helda mediation meeting with RMG with no resolution.

The arbitration isscheduled for May 2007.  At this time, wecannot predict the outcome of the arbitration. However, management believes the outcome will not have a materialadverse effect on the Company.

**ITEM 4.**                    SUBMISSION OFMATTERS TO A VOTE OF SECURITY HOLDERS

None.

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**PART II**

**ITEM 5.**                    MARKET FORREGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OFEQUITY SECURITIES

**Principal Market and Price Range ofCommon Stock**

Our common stockhas traded on the American Stock Exchange (“AMEX”) since April 12, 2005under the trading symbol “PRB.”  Thefollowing table presents the reported high and low sales prices for eachquarter since April 12, 2005:

|                | ** ** | **2006  Price Range** | ** ** | **2005  Price Range** | ** ** |
|----------------|------------|----------------------------|------------|----------------------------|------------|
| ** **     | ** ** | **High**                   | ** ** | **Low**                    | ** ** | **High** | ** ** | **Low** | ** ** |
| First Quarter  |       | $                          | 6.67       |                       | $          | 5.36 | * * | (1 | ) | (1 | ) |
| Second Quarter |       | $                          | 5.85       |                       | $          | 4.01 |   | $ | 9.95 |   | $ | 6.21 |   |
| Third Quarter  |       | $                          | 5.50       |                       | $          | 4.16 |   | $ | 10.32 |   | $ | 5.38 |   |
| Fourth Quarter |       | $                          | 5.10       |                       | $          | 2.91 |   | $ | 7.60 |   | $ | 5.41 |   |

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*(1)**          The 2005 amounts areblank for the first quarter as stock was not traded on AMEX until April 12,2005.*

|                                                                      | ** ** | **March 23, 2007** | ** ** | **December 31, 2006** | ** ** | **December 31, 2005** | ** ** |
|----------------------------------------------------------------------|------------|------------------------------|------------|---------------------------------|------------|---------------------------------|------------|
| PRB’s common  stock closing price per share as reported on AMEX |       | $                            | 3.56       |                            | $          | 3.33                            |       | $ | 5.54 |   |
|                                                                      |            |                              |            |                                 |            |                                 |            |  |  |  |

 

The number ofholders of record of our common stock was 22 as of March 23, 2007.

This does notinclude holdings in street or nominee names. On March 23, 2007, the closing price of our common stock was $3.56 pershare.

15

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**Performance Chart**

This graph shallnot be deemed “filed” for purposes of Section 18 of the Securities andExchange Act of 1934 (the “Exchange Act”) or otherwise subject to theliabilities of that section nor shall it be deemed incorporated by reference inany filing under the Securities Act of 1933 or the Exchange Act, regardless ofany general incorporation language in such filing.

Total returnsassume $100 invested on April 12, 2005 in shares of PRB Energy, Inc., the AMEXMarket Value (U.S.), and the AMEX Natural Resources, assuming reinvestment ofdividends for each measurement period.

***$100 invested on 4/12/05 in PRB stock or in index, including reinvestment ofdividends.**

|                           | ** ** | **April 12, 2005** | ** ** | **December 30, 2005** | ** ** | **December 29, 2006** | ** ** |
|---------------------------|------------|------------------------------|------------|---------------------------------|------------|---------------------------------|------------|
| PRB ENERGY, INC.          |       | 100.00                       |       | 71.95                           |       | 43.25                           |       |
| AMEX MARKET  VALUE (U.S.) |       | 100.00                       |       | 110.24                          |       | 127.89                          |       |
| AMEX NATURAL RESOURCES    |       | 100.00                       |       | 139.49                          |       | 160.02                          |       |

 

**Dividend Policy**

We have never paidcash dividends on our common stock and we do not anticipate paying dividends inthe foreseeable future. We expect that we will retain all available earningsgenerated by our operations for the development and growth of our business. Inaddition, under the terms of our Notes and Debentures that were issued in 2006,we are prohibited from declaring or paying cash dividends on our common stockduring the period that any Notes or Debentures are outstanding and unpaid.Payment of any future dividends will be at the discretion of our Board ofDirectors after taking into account many factors, including our operatingresults, financial condition, current and anticipated cash needs, plans forexpansion and the Note and Debenture agreements.

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**ITEM 6.**                    SELECTEDFINANCIAL DATA

The selectedconsolidated financial data for each of the three years in the period endedDecember 31, 2006 and the selected consolidated balance sheet data as ofDecember 31, 2006, 2005 and 2004 are derived from, and qualified byreference to, our audited consolidated financial statements in Item 8 of thisreport. The selected financial data for each of the periods presented endingDecember 31, 2003 and 2002 and the selected balance sheet data as ofDecember 31, 2003 and 2002 are derived from audited financial statementsof TOP, our predecessor company, as referenced in our 2005 form 10-K.

The followingfinancial data should be read in conjunction with, and are qualified byreference to, our consolidated financial statements and related notes theretoin Item 8 of this report and Management’s Discussion and Analysis of FinancialCondition and Results of Operations included in Item 7 of this report.
| ** **                                                                                                               | ** ** | **PRB Energy, Inc.** | ** ** | **TOP Gathering, LLC** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------|------------|----------------------------------|------------|
| ** **                                                                                                               | ** ** | ** **                     | ** ** | ** **                       | ** ** | ** ** | ** ** | **(Predecessor)** | ** ** |
| ** **                                                                                                               | ** ** | **2006**                       | ** ** | **2005**                         | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
| ***(in thousands, except per share amounts and unaudited operating data)*** | ** ** | ** **                     | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Audited  Financial Information**                                                                                       |       |                           |       |                             |       |   |   |   |   |   |   |
| ***Statement  of Operations Data:***                                                                                     |       |                           |       |                             |       |   |   |   |   |   |   |
| Revenue -  E&P                                                                                                       |       | $                              | 1,676      |                             | $          | 51 |   | $ | — |   | $ | — |   | $ | — |   |
| Revenue -  G&P                                                                                                       |       | 2,612                          |       | 2,834                            |       | 2,532 |   | 1,999 |   | 2,097 |   |
| Management and  other revenue                                                                                            |       | 547                            |       | 270                              |       | — |   | — |   | — |   |
| Operating costs  - E&P                                                                                               |       | 1,266                          |       | 17                               |       | — |   | — |   | — |   |
| Operating costs  - G&P                                                                                               |       | 2,469                          |       | 1,755                            |       | 1,314 |   | 1,900 |   | 2,725 |   |
| Production taxes  and other deductions - E&P                                                                         |       | 522                            |       | 17                               |       | — |   | — |   | — |   |
| General and  administrative expenses                                                                                     |       | 5,026                          |       | 2,029                            |       | 1,184 |   | * |   | * | ** ** |
| Depreciation,  depletion & amortization                                                                              |       |                           |       |                             |       |   |   |   |   |   | ** ** |
| DD&A - E&P                                                                                                       |       | 764                            |       | 98                               |       | — |   | — |   | — |   |
| DD&A - G&P                                                                                                       |       | 972                            |       | 944                              |       | 656 |   | * |   | * | ** ** |
| Net (loss)  income (1)                                                                                                   |       | (8,659                         | )          | (4,829                           | )          | (1,863 | ) | 79 |   | (636 | ) |
| Net loss per  share - basic and diluted                                                                                  |       | $                              | (1.16      | )                                | $          | (0.69 | ) | $ | (1.33 | ) | $ | * |   | $ | * | ** ** |
|                                                                                                                     |       |                           |       |                             |       |   |   |   |   |   |   |
| ***Balance  Sheet Data:***                                                                                               |       |                           |       |                             |       |   |   |   |   |   |   |
| Oil and gas  properties, net                                                                                             |       | $                              | 19,746     |                             | $          | 1,531 |   | $ | — |   | $ | — |   | $ | — |   |
| Gathering  assets, net                                                                                                   |       | 6,912                          |       | 5,856                            |       | 8,098 |   | 618 |   | 1,125 |   |
| Total assets                                                                                                             |       | 49,843                         |       | 17,440                           |       | 11,399 |   | 1,603 |   | 1,899 |   |
| Long-term  liabilities                                                                                                   |       | 35,786                         |       | 434                              |       | 65 |   | 86 |   | 260 |   |
| Shareholders’  equity                                                                                               |       | $                              | 11,224     |                             | $          | 15,257 |   | $ | 9,318 |   | $ | 820 |   | $ | 1,241 |   |
|                                                                                                                     |       |                           |       |                             |       |   |   |   |   |   |   |
| ***Operating  Data:***                                                                                                   |       |                           |       |                             |       |   |   |   |   |   |   |
| Cash flow (used  in) provided by operations                                                                              |       | $                              | (4,356     | )                                | $          | (781 | ) | $ | 72 |   | $ | 655 |   | $ | (414 | ) |
| Exploitation and  development of natural gas properties                                                                  |       | (5,184                         | )          | (1,058                           | )          | — |   | — |   | — |   |
| Property/facility  acquisitions                                                                                          |       | (17,453                        | )          | (336                             | )          | (10,606 | ) | (14 | ) | (1,150 | ) |
| Additions to  other fixed assets                                                                                         |       | $                              | (86        | )                                | $          | (921 | ) | $ | (41 | ) | $ | * |   | $ | * | ** ** |
|                                                                                                                     |       |                           |       |                             |       |   |   |   |   |   | ** ** |
| **Unaudited  Operating Data (2)**                                                                                        |       |                           |       |                             |       |   |   |   |   |   |   |
| *Natural  gas operations (per Mcf):*                                                                                     |       |                           |       |                             |       |   |   |   |   |   |   |
| Average sales  price                                                                                                     |       | $                              | 4.23       |                             | $          | 8.50 |   | $ | — |   | $ | — |   | $ | — |   |
| Average operating  cost                                                                                                  |       | 3.20                           |       | 4.22                             |       | — |   | — |   | — |   |
| Average  production cost                                                                                                 |       | 1.32                           |       | 1.44                             |       | — |   | — |   | — |   |
| Average DD&A                                                                                                         |       | $                              | 1.93       |                             | $          | 16.33 |   | $ | — |   | $ | — |   | $ | — |   |
|                                                                                                                     |       |                           |       |                             |       |   |   |   |   |   |   |
| *Sales  (Mcf)*                                                                                                           |       | 396,000                        |       | 6,000                            |       | — |   | — |   | — |   |

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*                    denotesinformation from TOP that is not available in these selected financial datacategories.

Note (1): The net loss in 2006 includes a non-cashimpairment charge of $790,000 ($.10 per basic and diluted share).  The net loss in 2005 includes a non-cashimpairment charge of $2.5 million ($.36 per basic and diluted share) and $76,000for cumulative effect of change in accounting principle ($.01 per basic anddiluted share).  For additionalinformation on these items see “Note 5—Property, Equipment and Contracts” and “Note7—Asset Retirement Obligations” to our consolidated financial statements inItem 8 of this report.

Note(2): All items listedunder this category are based on gas sales volume (Mcf).  Therefore, these values are net numbers wherefuel, lost and unaccounted for gas and metering variances have been removedprior to the calculation.

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**ITEM 7.**                 MANAGEMENT’SDISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

**Overview**

We were originallyorganized as a mid-stream energy company providing gathering and processingservices to CBM gas producers.  During2005 and 2006, we expanded our operations to include developing and producingnatural gas properties and providing management services as contractoperator.  These activities are inaddition to our gas gathering and processing segment.  The strategies to accomplish our goal ofreaching positive cash flow and increasing shareholder value include:

·             Growthin natural gas production and natural gas reserves — in the Powder River Basin,the D-J Basin and other basins in the continental United States

·    Strategic growth of gas gathering andprocessing systems — for ourselves and for third parties

·            Continued asset valuegrowth through identification of undervalued assets which the company believeshold significant upside potential

**NotableItems in 2006**

·                  CompletedPennaco acquisition which provides the development acreage for the Moyer-coaldevelopment program

·                  Acquired385,000 acres in the D-J Basin from Anadarko which included the acreage,producing reserves, a gathering system and 3D and 2D seismic data

·                  Generatedpositive cash flow from G&P assets

·                  Acquiredgathering systems in the Recluse, Wyoming area

·                  IssuedNotes raising approximately $22 million

·                  IssuedDebentures raising approximately $15 million

**Expectationsfor 2007**

·                  Generatepositive cash flow from E&P operations

·                  Initiatedrilling potential locations in the Niobrara formation in the D-J Basin

·                  Initiatedrilling program to develop the Moyer-coal in the Powder River Basin

·                  Locateand complete one or more significant acquisitions

·                  Expand our customerbase and cash flow from G&P operations

**Resultsof Operations**

The following financialdata should be read in conjunction with, and are qualified by reference to, ourconsolidated financial statements and related notes thereto in Item 8 of thisreport.

***Overview***

***Factors affecting comparability***  In 2006, as the result of our entry intoE&P operations with the completion of two substantial acquisitions andrelated financing, our comparability of 2006 to prior years’ revenues andexpenses is markedly different.  The 2006E&P results reflect changes that are several fold increases over prioryears due to our expanded E&P operations.

***Revenue***   Our operations in2006 were focused on developing the E&P segment of the business.  Our revenues for E&P have substantiallyincreased several fold in 2006 primarily due to the start-up of our E&Poperations with the June 30, 2006 acquisition of CBM properties from Pennaco inthe Powder River Basin of Wyoming.  Ourrevenues for E&P of $1.7 million are determined by production from ourexisting properties and price based on market conditions for trading naturalgas product.  These market conditionssuch as weather, pipeline capacity and natural gas storage may have substantialeffect on the revenues generated by our E&P segment.

Our gas gathering feesare based on contractual rates with our customers and will vary with systemthroughput as well as the level of services provided and customer mix.  These fees are not currently regulated by anygovernmental authority.

Our management servicesfees were determined in accordance with our MSA with RMG and varied dependingon the amount of support services that were required to fulfill our obligationsunder this contract determined on a cost plus 15% basis.  On June 30, 2006, we terminated the MSA.

Our natural gas revenuewill vary based on the price of natural gas and the quantities and quality ofthe gas we deliver.

***E&P Operating Expense ***E&P operating expense includes costsassociated with operating the natural gas properties.  Such costs include labor related to pumperand direct field supervision, electricity, surface-use agreements, equipmentrental, fuel, chemicals, road maintenance, permits, supplies and other relevantwell costs incurred to extract the natural gas from the well.

***G&P Operating Expense  ***Gas gathering expense includes compression, site supervision costs, maintenanceand operating supplies, property taxes, insurance, land use and surface rightspayments and contract services, all of which are relatively fixed costs.Operating expenses also include transportation fees paid to others which varywith the throughput on our gathering lines.

***E&P Production Taxes and Other***  E&Pproduction costs include production taxes and deductions necessary to bring thenatural gas product to market. Production taxes are determined by the taxing authority.  In 2006, our production taxes were paidprimarily to Wyoming including, ad valorem charged by the county based onassessed valuation of the properties and severance and conservation  tax charged by the state.  A nominal amount was paid to Colorado inconnection with our acquisition of the Niobrara formation properties whichclosed on December 28, 2006.

***Depreciation, Depletion, Amortization and AccretionExpense  *** Depreciation expense relates to ourcompressor sites, pipelines and other gas gathering equipment, officefurniture, office equipment and computers. Depletion expense relates to developed and undeveloped leaseholds,capitalized development costs and related equipment.  Amortization expense relates to the customercontracts underlying the gas gathering systems. Accretion expense relates to the change in our asset retirementobligation liability due to the passage of time.  Depreciation and amortization expense arebased on estimates of the related assets’ useful lives.  Depletion expense is calculated using theunit-of-production method based on estimated proved or estimated proveddeveloped reserves.  Accretion expense iscalculated using the effective interest method.

***General and Administrative Expense*** General and administrative expense includes the costs associated with ourcorporate office, including personnel costs, professional fees, office rent andother office support costs.  It alsoincludes bad debt expense related to our 2006 allowance of approximately$596,000 for collection of certain RMG receivables discussed under “LEGALPROCEEDINGS” in Item 3 of this report as well as “Note 3 — Concentration ofCredit Risk” to our consolidated financial statements in Item 8 of this report.

***Interest Expense***  During2005, we had a note payable to the Bank of Oklahoma under a line of credit inthe amount of $1.5 million, secured by our gas gathering assets andincurred interest of $49,000.  Followingthe payment of the bank line of credit in full in April 2005, the bankreleased their security interest in the gathering assets and the$1.0 million certificate of deposit pledged by a preferred stockholder.

During the first quarterof 2006, we issued approximately $22 million of Notes and incurred interest of$2 million for the year.  On December 28,2006, we issued $15 million of Debentures and incurred interest of $16,000through year-end.

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***Asset Impairment Charge  ***Assets are evaluated for impairment periodically throughout the year.  In 2005 the company had an impairment chargefor its TOP gathering asset.  In 2006, wehad an impairment charge for E&P properties in the Reno/Dilts field of thePowder River Basin.  More discussion ofimpairment charges is in the “Critical Accounting Policies and Estimates” ofItem 7 of this report.

***Exploration Expense***  Exploration expense includes the costs of drilling unsuccessful exploratorywells.  See the description ofexploration expense in the “Critical Accounting Policies and Estimates” of Item7 of this report.

***2006 Compared to 2005***

Revenue increased$1.7 million, or 53%, in 2006 primarily due to the increase of$1.6 million in E&P gas sales, the majority resulting from revenuesgenerated from the new Pennaco assets beginning in July 2006. Revenue frommanagement fees also increased by $277,000. These revenue increases offset a$222,000 decrease in G&P revenue in 2006 as a result of inter-company eliminationsof revenues that were previously Pennaco third-party recognized revenues. Pennacorepresented 34% of our 2005 total revenues compared to only 13% of 2006 totalrevenues.

***Selected Operating Expenses.***  The following table and theexplanations that follow present information about our operating expenses foreach of the years ended December 31, 2006 and 2005:
| **(in thousands)**                             | ** ** | **2006** | ** ** | **2005** | ** ** | **Increase  (Decrease)** | ** ** | **Change** | ** ** |
|-----------------------------------------------------|------------|----------|------------|----------|------------|--------------------------|------------|------------|------------|
| Operating costs -  E&P                          |       | $        | 1,266      |     | $          | 17                       |       | $          | 1,249      |   | ***** | ** ** |
| Operating costs -  G&P                          |       | $        | 2,469      |     | $          | 1,755                    |       | $          | 714        |   | 41 | % |
| Production taxes and  other deductions - E&P    |       | $        | 522        |     | $          | 17                       |       | $          | 505        |   | ***** | ** ** |
| Depreciation, depletion  and amortization - E&P |       | $        | 764        |     | $          | 98                       |       | $          | 666        |   | ***** | ** ** |
| Depreciation, depletion  and amortization - G&P |       | $        | 972        |     | $          | 944                      |       | $          | 28         |   | 3 | % |
| General and  administrative                         |       | $        | 5,026      |     | $          | 2,029                    |       | $          | 2,997      |   | 148 | % |
| Interest expense                                    |       | $        | 2,287      |     | $          | 49                       |       | $          | 2,238      |   | ***** | ** ** |

----

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

As we remain in astrong commodity price environment, we anticipate that cost pressures withinour industry may continue due to greater field activity and rising servicecosts in general.  Based on currentplans, we are targeting the reduction of costs, principally electricity, thirdparty services, compression expense, surface rentals and other field expenses.  Thechanges as explained in the preceding table were primarily related to thefollowing items:

*·**                 *E&Poperating costs:  2006 was our first fullyear of E&P operations.  Ouracquisition from Pennaco in the Powder River Basin resulted in higherproduction costs as we took over the operations in that area, increased ouroperating personnel, and brought on shut-in properties to ramp up production inthe area.

*·**                 *G&Poperating costs:  Our operating costsincreased as a result of the acquisition of the Recluse gathering system. 

*·**                 *E&PProduction taxes and other deductions: As a result of acquiring the Pennaco properties, we saw an increase inour revenues that directly relates to our production taxes and otherdeductions.

*·**                 *Depreciation,depletion and amortization: Increases for E&P resulted from the additions of properties duringthe year as we developed our upstream energy business.  The increased depreciation, depletion and amortizationfor G&P assets in 2006 resulted from the acquisition of the RecluseGathering Systems which is further discussed in Item 1, “Business -Acquisitions and Divestitures” of this report.

*·**                 *Generaland administrative:  Our increase wasa result of adding to our corporate office support staff, E&P operationsmanagement and staff and overall growth through acquisitions during 2006.  We anticipate these costs will stabilizeduring 2007 with potential increases  inlegal and third party consulting expenses from future operations andacquisitions activity.

*·**                 *Interestexpense:  Interest expense increasedsubstantially in 2006 over 2005 as a result of the financing activities to growour business during 2006.  In the firstquarter of 2006, we issued Notes to facilitate financing needs for futureacquisitions.  The majority of theinterest expense increase was a result of interest incurred on theseNotes.  In addition, on December 28,2006, in connection with the acquisition of properties in the D-J Basin, weissued Debentures.  We expect theinterest expense to increase in 2007 as a result of the added debt.  See “Note 10 — Borrowings” to our consolidated financial statements in Item8 of this report for additional disclosures related to these financingfacilities.

***2005 Compared to 2004***

Revenue increased$623,000, or 25%, in 2005 over 2004 primarily due to an acquisition-timingrelated increase of $1.1 million in gas gathering revenue applicable toour BPE systems which we acquired in August 2004. Revenue from managementfees and natural gas sales, activities that were initiated during the year endedDecember 31, 2005, also increased by $270,000 and $51,000, respectively.These revenue increases offset a $753,000 decrease in gas gathering revenues in2005 from our TOP system resulting from a decline in 

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volumes and the loss of acustomer. This customer represented 11% of our 2004 revenues. We divested ourassets relating to our TOP gathering system in 2006.

***Selected Operating Expenses.***  The following table and the explanationsthat follow present information about our operating expenses for each of theyears ended December 31, 2005 and 2004:
| **(in thousands)**                         | ** ** | **2005** | ** ** | **2004** | ** ** | **Increase  (Decrease)** | ** ** | **Change** | ** ** |
|-------------------------------------------------|------------|----------|------------|----------|------------|--------------------------|------------|------------|------------|
| Operating costs  - E&P                      |       | $        | 17         |     | $          | —                   |       | $          | 17         |   | 100 | % |
| Operating csots  - G&P                      |       | $        | 1,755      |     | $          | 1,314                    |       | $          | 441        |   | 34 | % |
| Production taxes  and other deduction - E&P |       | $        | 17         |     | $          | —                   |       | $          | 17         |   | 100 | % |
| Asset impairment  charge                        |       | $        | 2,487      |     | $          | —                   |       | $          | 2,487      |   | 100 | % |
| Exploration  expense                            |       | $        | 450        |     | $          | —                   |       | $          | 450        |   | 100 | % |
| Depreciation,  depletion and amortization       |       | $        | 1,067      |     | $          | 656                      |       | $          | 411        |   | 63 | % |
| General and  administrative                     |       | $        | 2,029      |     | $          | 1,184                    |       | $          | 845        |   | 71 | % |

 

·                  G&P operating costs:  Costs increased $441,000 or 34% mainly due tothe $721,000 increase in BPE systems operating costs resulting from the timingof the acquisition of this system.  Thesecosts offset a decrease in gas gathering expenses relating to our TOP system asa result of releasing excess compression capacity.

·                  E&P Production taxes and otherdeductions:  We incurred gasproduction costs for the first time in 2005 as a result of our entry intoE&P activities.

·                  Asset Impairment Charge:* * In 2005, we recorded an assetimpairment charge of $2.5 million related to our TOP gas gatheringsystem.  As a result of declining volumesand the loss of a customer, we performed an evaluation of the recoverability ofour carrying value of this system using undiscounted cash flowprojections.  We determined that theestimated fair value of these gathering system assets was less than ourcarrying value.  The estimated fair valuewas determined using discounted values of probability weighted expected cashinflows and an independent appraiser’s valuation of our TOP gas gatheringsystem.  We also evaluated our BPE gasgathering system for recoverability of carrying values and determined that noimpairment was warranted at December 31, 2005.  See also “Note 5—Property, Equipment andContracts” to our consolidated financial statements in Item 8 of this report.

·                  Exploration Expense:  We incurred $450,000 of expense in 2005relating to the drilling costs of 6 unsuccessful wells.  Four of these six wells were lost due tomechanical failure and have been subsequently re-drilled.

·                  Depreciation, depletion andamortization:  Depreciation,depletion, amortization and accretion expense increased $411,000 or 63% over2004 primarily due to $491,000 of additional depreciation and amortizationexpense applicable to the BPE assets which were acquired inAugust 2004.  This increase wasoffset by lower TOP system depreciation and amortization as a result of the TOPimpairment.

·                  General and administrative:  Expenses in 2005 increased $845,000 or 71% over2004 mainly due to increases of $381,000 in professional fees, $166,000 inadditional expenses associated with being a public company and $134,000 inincreased payroll costs.  Professionalfees increased due to additional legal, accounting and engineering activitiesassociated with our entering the E&P business and expanding our G&Pbusiness.  All other general andadministrative expense increased $164,000 net, during 2005 as compared to 2004.

***Estimated 2007 Selected Operating Expenses***

|                                                  | ** ** | **2007 Anticipated Range** | ** ** |
|--------------------------------------------------|------------|--------------------------------------|------------|
| **(in thousands)**                          | ** ** | **Low**                              | ** ** | **High** | ** ** |
| Operating costs  - E&P                       |       | $                                    | 2,560      |   | $ | 3,464 |   |
| Operating costs  - G&P                       |       | $                                    | 2,932      |   | $ | 3,967 |   |
| Production taxes  and other deductions - E&P |       | $                                    | 2,563      |   | $ | 3,469 |   |
| DD&A -  E&P                              |       | $                                    | 3,379      |   | $ | 4,572 |   |
| DD&A -  G&P                              |       | $                                    | 1,448      |   | $ | 1,959 |   |
| General and  administrative                      |       | $                                    | 4,365      |   | $ | 5,905 |   |
| Interest expense                                 |       | $                                    | 3,506      |   | $ | 4,744 |   |

 

The above table represents a range for our expectations in 2007 for selectedfinancial data.

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**Critical Accounting Policies andEstimates**

Please referto  “Note 2 — Summary of SignificantAccounting Policies” to our consolidated financial statements in Item 8 of thisreport.  In the “Summary of SignificantAccounting Policies” we highlight critical accounting policies and estimatesrelevant to our consolidated financial statements and projections.  Below are highlights related to accountingpolicies and estimates affecting our operations.

***Allowance for RMG receivable***  In 2006, we estimated an allowance fordoubtful accounts of $596,000 pertaining to RMG.  RMG’s receivables totaled $791,000 atDecember 31, 2006 and the remaining balance, after the allowance, is reflectedin the consolidated financial statements as $195,000.  The estimate is based on the amount which isconsidered doubtful as to collection based upon legal proceedings that began in2006 and are continuing into 2007.  Referto Item 3, Legal Proceedings, for additional details regarding the RMGAgreement and Claims Dispute.

***Asset impairment***  Reflected on our December 31, 2006 statementof operations is $790,000 of impairment charge that represents the remainingnet book value of the Reno/Dilts wells previously included in E&P propertyassets and located in the Powder River Basin. In September 2005, pursuant to the farmout agreement with RMG, wedrilled CBM wells in the Reno/Dilts area in order to develop the property.  The target production level was 700 to 800Mcf/day.  Over the remainder of 2005 and2006, the gas production increased to 300 Mcf/day and leveled off.  This project required us to purchase dieselfuel to run the generators and down hole pumps. With the production leveling off, management determined that there wasinsufficient revenue projected to cover the operating expenses of the rentalgenerators and the diesel.  Theseuneconomical properties were subsequently shut in during the first quarter of2007.

For the year ended2005, $2.5 million was charged off to expense related to the TOP gathering system,including $1.6 million for property and equipment and $842,000 for contracts.

***Exploration Costs*** We incurred exploration costs of $50,000,$450,000 and $0 in 2006, 2005 and 2004, respectively.  For 2007, expected costs consist primarily ofgeological and geophysical costs.  Wepurchased 3-D seismic surveys in the acquisition of the D-J Basin acreage.  We are projecting total costs in 2007 ofbetween $4 million and $8 million for the development of probable and possiblereserves in both the Powder River Basin and the D-J Basin.  Management believes it is more likely thannot that most of these costs will ultimately be capitalized as developmentassets due to the 3-D seismic success rate by other operators in drilling inthe D-J Basin.

***Income Taxes***  From inception through December 31, 2006, wegenerated projected, estimated net operating losses on a tax basis ofapproximately $16 million versus $4.6 million at December 31, 2005.  As of December 31, 2006 we had an estimatedtax asset of $2.7 million, which has been fully reserved with a valuationallowance, and thus no tax benefit credit was reported for 2006.  We have incurred start-up expenses andtaxable deductions through drilling activities to date, which combined with thetax loss carryforwards, will offset taxable income from operations for theforeseeable future.  We continue toevaluate the reasonableness and appropriateness of the valuation allowance infuture periods.

***Asset dispositions ***TOPGathering System customers were notified on March 21, 2006 that the TOP systemrates would be increased to cover its cash costs plus 15% for a two-monthperiod.  The buyer of our TOP systemexercised their right as a customer to purchase the TOP System during the thirdquarter of 2006, resulting in a gain of $309,000 reflected as other income inour statement of operations. We have significantly increased and strengthenedour portfolio of assets since 2005 and expect to continue to makeacquisitions.  We do not anticipate significantdivestitures in 2007.  There are no gasproperties and equipment classified as held for sale at December 31, 2006in accordance with SFAS No. 144.

***Estimated oil and gas reserve quantities ***Proved oil and gasreserves are estimates of recoverable quantities of oil, natural gas and naturalgas liquids that are determined using engineering and geological data withreasonable certainty.  Reserve estimatesare prepared by independent petroleum engineers. The reserve estimates arebased on existing economic and operating conditions and include only existingwells from known reservoirs with existing equipment and technology. All of theproved reserves in 2005 were located in the Powder River Basin area ofWyoming.  In 2006 we added proved andunproved reserves in the Denver-Julesburg (D-J) Basin of northeastern Coloradoand southwestern Nebraska.   See also “Note13 — Disclosures about Oil and Gas Producing Activities” to our consolidatedfinancial statements in Item 8 of this report for more information on reserveestimates.

**FinancialCondition, Liquidity and Capital Resources**

Substantialcapital is required to replace and grow reserves.  We achieve reserve replacement and growthprimarily through successful development drilling and the acquisition ofproperties.  Fluctuations in commodityprices and pipeline capacity have been the primary reason for short-termchanges in our cash flow from operating activities.  We expect the net long-term growth in ourcash flow from operating activities will be the result of growth in productionas affected by period to period fluctuations in commodity prices.  In 2006, we financed our growth by acombination of utilization of working capital and issuance of debt securities.

***Capital Expenditures* **Weestablish a capital budget for each calendar year based on our developmentopportunities and the expected cash flow from operations for that year.  Acquisitions made in 2006 have been financedthrough our Notes and Debentures.  Weintend to utilize working capital as well as seek a bank credit facility in2007 to continue to finance future capital expenditures.  We may revise our capital budget during theyear as a result of acquisitions and/or drilling outcomes.  Excess cash generated from operations isexpected to be applied toward acquisitions, debt reduction or other corporatepurposes.

21

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In 2007, we have acapital program for both E&P and G&P, pending additional financing, ofapproximately $25 million.  We intend topay for this development utilizing current working capital, establishing a bankcredit facility and, possibly, raising debt or equity capital during 2007.  Upon commercial production we will proceedwith further development of the deeper Moyer coal zones underlying theproperties acquired from Pennaco.  Weplan to spend 90% of our capital expenditures for E&P operations.  This could be revised due to lower commodityprice expectations, timing of deliveries out of the Powder River basin,equipment availability, permitting or other factors.  The 2007 capital budget is focused primarilyon converting probable and possible reserves as well as developing existingreserves in the Powder River Basin and D-J Basin.

***Working Capital and Cash Flows* **Cashflow from operations is dependent upon the price of natural gas and our abilityto increase production, and manage costs. Natural gas prices decreased in 2006 compared to 2005 and we increasedproduction as a result of our recent acquisitions and development program.

Our workingcapital balance has increased in 2006 over 2005 as a result of the issuance ofthe Notes during the first quarter of 2006 in connection with the acquisitionof interest in the Powder River Basin as well as the Debentures during December2006 in connection with the acquisition of interest in the Niobrara fieldlocated in Northeastern Colorado and Nebraska. For more in depth discussion of this financing please reference “Note 10— Borrowings” and “Note 4 — Acquisitions” to the consolidated financialstatements in Item 8 as well as “2006 Acquisitions and Divestitures” in Item 1of this report.

The table belowcompares financial condition, liquidity and capital resource changes as of andfor the years ended December 31: 

| (in thousands, except for production and average prices) | ** ** | **2006** | ** ** | **2005** | ** ** | **Change** | ** ** |
|---------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|------------|------------|
| Average gas sold  (Mcf/D) (1)                                                               |       | 1,085    |       | 16       | ** ** | *****      | ** ** |
| Average gas  sales prices, per Mcf (1)                                                      |       | $        | 4.23       |     | $          | 8.50       |       | (50.2 | )% |
| Net cash used by  operating activities                                                      |       | $        | 4,356      |     | $          | 781        | ** ** | ***** | ** ** |
| Working capital                                                                             |       | $        | 11,640     |     | $          | 7,004      |       | 66.2 | % |
| Sales of natural  gas                                                                       |       | $        | 1,676      |     | $          | 51         | ** ** | ***** | ** ** |
| Gas gathering  revenue                                                                      |       | $        | 2,612      |     | $          | 2,834      |       | (7.8 | )% |
| Long-term debt                                                                              |       | $        | 36,972     |     | $          | 17         | ** ** | ***** | ** ** |
| Capital expenditures,  including acquisitions                                               |       | $        | 22,723     |     | $          | 2,315      | ** ** | ***** | ** ** |

----

*Percentages greater than 200% and comparisons frompositive to negative values are not shown.

Note (1) All items listedunder natural gas operations are based on gas sales volume per Mcf, or gasvolumes sold per day (Mcf/D).  Therefore,these values are net volumes where fuel, lost and unaccounted for gas, andmetering variances have been removed prior to the calculation.

Due to a marketprice anomaly related to unseasonably warm weather and higher gas storagelevels at the end of 2006, the gas price was substantially lower than thequarters before and after year-end 2006. The New York Mercantile Exchange (“NYMEX”) at year-end reflected a priceof $5.64 per million British thermal units (“MMBtu”) or about 20% to 25% belowthe current gas futures contract prices. The CIG price of $4.46 per MMBtu was at a low point at year-end comparedto the fourth quarter of 2006 and the first quarter of 2007.

Our year-endreport of December 31, 2006 prepared by NSAI calculated estimated provedreserves and future revenues by using the weighted average price of totalproved reserves of $3.39 per thousand cubic feet (“Mcf”) (or approximately$4.00 per MMBtu based on an 85% average conversion factor for theseproperties).  The estimated reserves andfuture revenues would have presented a much different result if similar priceswere in effect at year-end as were experienced during the quarters before andafter year-end 2006, which ranged on average from $7.00 to $8.00 per MMBtu atHenry Hub and $4.50 to $6.50 per MMBtu from CIG, before regional differentialsand transportation and compression charges.

Based on a morerepresentative price range, using CIG prices as a reference, of $5.25 to $6.50per MMBtu, the estimated increase in year-end future net revenues discounted at10% would have been between 35% ($2.0 million) to 75% ($4.0 million) for provedreserves.

***Credit Facility***  We have had recent discussions with some banksand we anticipate obtaining a bank credit facility during 2007.  The primary sources of financing to date havebeen through private placements of debt securities.  In 2007, we have sufficientcapital to meet capital requirements for the first nine months of this year andplan to establish a bank credit line later in the year as reserves grow. Thereis no guarantee that we will be able to obtain a bank credit facility on termsacceptable to us.

22

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**Contractual Obligations**

The followingtable summarizes our future commitments as of December 31, 2006 (inthousands):
| ** **                  | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **Thereafter** | ** ** | **TOTAL** | ** ** |
|-----------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|-----------|------------|
| Long-term debt  obligations |       | $        | 4,176      |     | $          | 39,729   |       | $        | —     |     | $          | —         |       | $         | —     |   | $ | — |   | $ | 43,905 |   |
| Operating leases            |       | 674      |       | 666      |       | 644      |       | 667      |       | 501      |       | 2,024          |       | 5,176     |       |
| Total commitments           |       | $        | 4,850      |     | $          | 40,395   |       | $        | 644        |     | $          | 667            |       | $         | 501        |   | $ | 2,024 |   | $ | 49,081 |   |

 

Theabove table does not include asset retirement obligations, accounts payable orother accrued liabilities recorded on our consolidated balance sheet as ofDecember 31, 2006.  Asset retirementobligations are not included as we cannot determine with accuracy the timing ofsuch payments.  The table does notinclude any commitments entered into after December 31, 2006.  Refer to “Note 17—Subsequent Events” to ourconsolidated financial statements included in Item 8 of this report.

We have acquired gasgathering properties and contracts that include operating leases in respect tosurface-use rights that are cancelable in the event that gas gatheringactivities cease as a result of declining production.  We also have purchased commitments for futurefield operations and maintenance activities with third party providers. Inaddition, we are a party to non-cancelable operating leases for office space,office equipment and other items required for operations.  The table above includes estimated futurepurchase commitments relating to these operations support contracts.  With regard to the operating leases, futureminimum lease payments are calculated based on the contractual rate and period,or if the contract was a surface-use agreement, future minimum lease paymentswere calculated based on the estimated lives of the associated gas reserves(through 2014) and the applicable contract rate.

There is a defaultprovision in the Debentures maturing on August 31, 2008 — please refer to “Note10 — Borrowings” to our consolidated financial statements in Item 8 of thisreport for more information on our senior Debentures.

**ITEM7A.**           QUANTITATIVEAND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to certainmarket risks inherent within the energy industry including natural gas pricevolatility and pipeline capacity. We intend to manage our operations in amanner designed to minimize our exposure to such market risks. Since our gasvolumes produced during 2005 and 2006 were at start-up levels, we did not havethe quantity of product to consider it beneficial to institute a hedging policyto date.

***Credit Risk***

Credit risk is the riskof loss resulting from non-performance of contractual obligations by a customeror joint venture partner. A substantial portion of our accounts receivable arewith customers in the energy industry and are subject to normal industry creditrisk. We assess the financial strength of our customers through regular creditreviews in order to minimize the risk of non-payment.

***Market Risk***

Market risk is the riskof loss arising from adverse changes in market rates and prices.  Because we sell natural gas at spot pricesour financial results will be affected by changes in the price of natural gas.  The estimated reserves and future revenueswould have presented a much different result if similar prices were in effectat year-end as were experienced during the quarters before and after year-end2006, which ranged on average from $7.00 to $8.00 per MMBtu at Henry Hub and$4.50 to $6.50 per MMBtu from CIG, before regional differentials andtransportation and compression charges.

***Interest Rate Risk***

Interest rate risk willexist with respect to new debt offerings that bear interest at floatingrates.  At December 31, 2006 we hadno bank indebtedness.  Refer to “Note10—Borrowings” to our consolidated financial statements included in Item 8 ofthis report with respect to our debt offering of the Notes and Debentures.

**ITEM8.**                    CONSOLIDATEDFINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statementsrequired pursuant to this item are included in Item 15 of this Annual Report onForm 10-K and begin on page F-1.

**ITEM9.**                    CHANGESIN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

**ITEM 9A. CONTROLS AND PROCEDURES**

**Conclusion Regarding theEffectiveness of Disclosure Controls and Procedures**

We maintain disclosurecontrols and procedures as defined in Rules 13 a — 15 (e) and 15 d — 15 (e) ofthe Securities Exchange Act of 1934 designed to provide reasonable assurancethat information required to be disclosed in our reports is recorded,processed, summarized and reported within the time periods specified in the SEC’srules and forms, and that such information is accumulated and communicatedto our management, including our Chief Executive Officer and PrincipalFinancial Officer, to allow timely decisions regarding requireddisclosure.  Significant improvementswere achieved by the end of the fourth quarter of 2006 in satisfactorilyinstituting all of the procedures outlined in our last report to fullyremediate the previously reported deficiencies. Our management, with the participation and oversight of our ChiefExecutive Officer and Principal Financial Officer, evaluated these changes indesign and effectiveness of our disclosure controls and procedures as ofDecember 31, 2006. On the basis of these findings, our Chief ExecutiveOfficer and our Principal Financial Officer have concluded that our disclosurecontrols and procedures were effective, as of December 31, 2006.

**ITEM9B.**           OTHERINFORMATION

None.

23

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**PART III**

**ITEM 10.**             DIRECTORS, EXECUTIVEOFFICERS AND CORPORATE GOVERNANCE

The requiredinformation for this item is incorporated by reference to our Proxy Statementfor the 2007 Annual Meeting of Stockholders. The Proxy Statement will be filed with the SEC not later than 120 daysafter the end of our fiscal year.

Our Board ofDirectors has adopted a Code of Business Conduct & Ethics, included asExhibit 14.1 to this annual report on Form 10-K, that applies to ourDirectors, executives, officers and employees. Our Code of Business Conduct & Ethics can be found on ourwebsite, which is located at www.prbenergy.com. We intend to make all required disclosures concerning any amendments to,or waivers from, our Code of Business Conduct & Ethics on our website.Any person may request a copy of the Code of Ethics, at no cost, by writing tous at the following address:  PRB Energy, Inc., 1875 Lawrence Street,Suite 450, Denver, Colorado 80202, attention: Corporate Secretary.

**ITEM 11.**             EXECUTIVECOMPENSATION

The requiredinformation for this item is incorporated by reference to our Proxy Statementfor the 2007 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and ExchangeCommission not later than 120 days after the end of our fiscal year.

**ITEM 12.**             SECURITY OWNERSHIP OFCERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The requiredinformation for this item is incorporated by reference to our Proxy Statementfor the 2007 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and ExchangeCommission not later than 120 days after the end of our fiscal year.

**ITEM 13.**             CERTAIN RELATIONSHIPSAND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

The requiredinformation for this item is incorporated by reference to our Proxy Statementfor the 2007 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and ExchangeCommission not later than 120 days after the end of our fiscal year.

**ITEM 14.**             PRINCIPAL ACCOUNTINGFEES AND SERVICES

The requiredinformation for this item is incorporated by reference to our Proxy Statementfor the 2007 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and ExchangeCommission not later than 120 days after the end of our fiscal year.

**PART IV**

**ITEM 15.**             EXHIBITS, FINANCIALSTATEMENT SCHEDULES

**15(a)(1) Consolidated FinancialStatements**

Thefollowing consolidated financial statements are filed as part of this report:
| Reports of Independent Registered Public Accounting Firms      |   | F-1a & F-1b |   |
|----------------------------------------------------------------|--------|-----------------|--------|
| Consolidated Balance Sheets                                    |   | F-2             |   |
| Consolidated Statements of Operations                          |   | F-3             |   |
| Consolidated Statement of Changes in Stockholders’ Equity |   | F-4             |   |
| Consolidated Statements of Cash Flows                          |   | F-5             |   |
| Notes to Consolidated Financial Statements                     |   | F-6             |   |

 

**15(a)(2) Financial StatementSchedules**

Schedules are omittedbecause they are not required or because the information is provided elsewherein the consolidated financial statements.

24

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**15(a)(3) 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             |       | Amendment to the Articles of Incorporation to change  the Company’s name                                                                                                                                                                                                       |
| (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 as an exhibit to 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 as an exhibit to Form 10-K filed on April 14, 2006 and  incorporated by reference herein).                                 |
| (4.8)           |       | Form of Senior Secured Debentures (filed as an  exhibit to Form 8-K filed on January 5, 2007 and incorporated by reference  herein)                                                                                                                                                 |
| (4.9)           |       | Pledge and Security Agreement, dated as of December  28, 2006, by and among PRB Energy, Inc., PRB Oil & Gas, Inc., PRB  Gathering, Inc., and the Secured Parties named therein (filed as an exhibit  to Form 8-K filed on January 5, 2007 and incorporated by reference herein) |
| (4.10)          |       | Secured Guaranty, dated as of December 28, 2006,  made by PRB Energy, Inc. and PRB Gathering, Inc. (filed as an exhibit to Form  8-K filed on January 5, 2007 and incorporated by reference herein)                                                                                 |
| (4.11)          |       | Registration Rights Agreement, dated as of December  28, 2006, by and among PRB Energy, Inc. and the Buyers named therein (filed  as an exhibit to Form 8-K filed on January 5, 2007 and incorporated by  reference herein)                                                         |
| (10.1)*         |       | Equity Compensation Plan Filed (filed as an exhibit  to Form S-1 filed on November 1, 2004 and incorporated by reference  herein).                                                                                                                                        |
| (10.2)          |       | Form of Amended and Restated Warrant  Certificate (filed as an exhibit to Form S-1/A filed on March 1,  2005 and incorporated by reference herein).                                                                                                                  |
| (10.4)          |       | Bear Paw Energy, LLC Purchase and Sale Agreement  (filed as an exhibit to Form S-1 filed on November 1, 2004 and  incorporated by reference herein).                                                                                                                      |
| (10.5)          |       | Bear Paw Energy, LLC Mortgage, Security Agreement,  Assignment of Proceeds, and Financing Statement (filed as an exhibit to  Form S-1/A filed on January 28, 2005 and incorporated by reference  herein).                                                                 |
| (10.6)          |       | Bear Paw Energy, LLC Promissory Note (filed as an  exhibit to Form S-1/A filed on January 28, 2005 and incorporated by  reference herein).                                                                                                                                |
| (10.7)          |       | Bear Paw Energy, LLC Operations Agreement (filed as  an exhibit to Form S-1 filed on November 1, 2004 and incorporated  by reference herein).                                                                                                                             |
| (10.8)          |       | Bank of Oklahoma Promissory Note (filed as an  exhibit to Form S-1/A filed on March 1, 2005 and incorporated by reference  herein).                                                                                                                                       |
| (10.9)          |       | Bank of Oklahoma Mortgage and Security Agreement  (filed as an exhibit to Form S-1/A filed on March 1, 2005 and  incorporated by reference herein).                                                                                                                       |
| (10.10)         |       | Gathering Services Agreement—United Energy Trading,  LLC (filed as an exhibit to Form S-1/A filed on March 1, 2005 and  incorporated by reference herein).                                                                                                           |
| (10.11)         |       | Gathering Services Agreement—Pennaco Energy Inc.  (filed as an exhibit to Form S-1/A filed on March 1, 2005 and  incorporated by reference herein).                                                                                                                  |
| (10.12)         |       | Gathering Services Agreement—Natural Gas Fuel  Company, Inc. (filed as an exhibit to Form S-1/A filed on  March 1, 2005 and incorporated by reference herein).                                                                                                  |
| (10.13)         |       | Farmout and Development Agreement dated  August 1, 2005 between Rocky Mountain Gas, Inc. and PRB Energy, Inc.  (filed as an exhibit to Form 8-K filed on September 9, 2005).                                                                               |
| (10.14)         |       | Management Services Agreement dated August 1,  2005 between Rocky Mountain Gas Inc., Enterra Energy Trust and PRB  Energy, Inc. (filed as an exhibit to Form 8-K filed on September 9,  2005).                                                                  |
| (10.15)         |       | Form of Subscription Agreement between the  Company and the subscribers to the Company’s Senior Subordinated Convertible  Notes (filed as an exhibit to Form 10-K filed on April 14, 2006 and  incorporated by reference herein).                                    |
| (10.16)         |       | Gathering Services Agreement - Storm Cat Energy  (USA) Operating Corporation (filed as an exhibit to Form 8-K filed January  27, 2006 and incorporated by reference herein)                                                                                                         |
| (10.17)         |       | Purchase and Sale Agreement between Pennaco Energy,  Inc. and PRB Energy, Inc., dated May 1, 2006 (filed on Form 8-K filed July 7,  2006 and incorporated by reference herein)                                                                                                      |
| 10.18           |       | Purchase and Sale Agreement between PRB Energy,  Inc., and Arête Industries Inc., dated September 1, 2006                                                                                                                                                                      |

 

25

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| 10.19   |   | Letter Agreement between PRB Energy, Inc., and  Maverick Pipeline LLC, dated August 1, 2006                                                                                                                                                                      |
|---------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (10.20) |   | Purchase and Sale Agreement by and between Lance Oil  & Gas Company, Inc., Western Gas Resources, Inc. and PRB Oil & Gas,  Inc. dated December11, 2006. (filed as an exhibit to Form 8-K filed on  January 5, 2007 and incorporated by reference herein) |
| (10.21) |   | Securities Purchase Agreement, dated December 28,  2006, by and among PRB Oil & Gas, Inc., PRB Energy, Inc., and the Buyers  named therein (filed as an exhibit to Form 8-K filed on January 5, 2007 and  incorporated by reference herein)                  |
| (10.22) |   | Master Gas Compression Contract, dated  February 12, 2007, by and between PRB Gathering, Inc. and J-W Power  Company (filed as and exhibit to Form 8-K filed on February 14, 2007 and  incorporated by reference herein)                                    |
| 21.1    |   | List of the Company’s subsidiaries                                                                                                                                                                                                                          |
| 23.1    |   | Consent of Hein & Associates LLP                                                                                                                                                                                                                             |
| 23.2    |   | Consent of Ehrhardt Keefe Steiner & Hottman  PC                                                                                                                                                                                                         |
| 23.3    |   | Consent of Netherland, Sewell & Associates, Inc.                                                                                                                                                                                                             |
| 23.4    |   | Consent of Sproule Associates Limited on behalf of  Sproule Associates Inc.                                                                                                                                                                                      |
| 24.1    |   | Power of Attorney, incorporated by reference to  Signature page attached hereto                                                                                                                                                                             |
| 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    |   | Certification pursuant to 18 U.S.C.  Section 1350, as adopted pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002                                                                                                                               |

 

These exhibits areavailable upon request. Exhibits identified in parentheses below are on filewith the SEC and are incorporated herein by reference. All other exhibits areprovided as part of this electronic submission.

----

(    )         Previously filed.

*                      Managementcontract or compensatory plan or arrangements.

26

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**SIGNATURES**

Pursuantto the requirements of the Securities Exchange Act of 1934, PRBEnergy, Inc. has duly caused this report to be signed on its behalf by theundersigned thereunto duly authorized.
|                      | ** ** | **PRB Energy, Inc.**     |     |     |
|----------------------|------------|-------------------------------|----------|----------|
|                 | ** ** | (Registrant)                  |     |     |
|                 | ** ** |                          |     |     |
|                 | ** ** | /s/ Daniel D. Reichel    |     |     |
| Date: March 29, 2007 |       | Daniel D. Reichel             |     |     |
|                 |       | *Vice President—Finance* | * * | * * |

 

**POWEROF ATTORNEY**

KNOW ALL PERSONSBY THESE PRESENTS, that each person whose signature appears below constitutesand appoints Daniel D. Reichel as his attorney-in-fact, with full power ofsubstitution, for him in any and all capacities to sign any amendments to thisReport on Form 10-K, and to file the same, with exhibits thereto and otherdocuments in connection therewith, with the Securities and Exchange Commission,hereby ratifying and confirming all that said attorneys-in-fact, or theirsubstitutes, may do or cause to be done by virtue hereof.

Pursuant to therequirements of the Securities Act of 1934, this report has been signed onMarch 29, 2007 by the following persons in the capacities indicated.
| Signature                 | ** ** | **Title**                                       |
|---------------------------|------------|-------------------------------------------------|
| ** **                | ** ** | ** **                                      |
| /s/ Robert W.  Wright     |       | Chairman and Chief Executive Officer            |
| Robert W. Wright          |       |                                            |
|                      |       |                                            |
| /s/ William F.  Hayworth  |       | President, Chief Operating Officer and Director |
| William F.  Hayworth      |       |                                            |
|                      |       |                                            |
| /s/ Gus J.  Blass, III    |       | Director                                        |
| Gus J. Blass,  III        |       |                                            |
|                      |       |                                            |
| /s/ Paul L.  Maddock, Jr. |       | Director                                        |
| Paul L. Maddock,  Jr.     |       |                                            |
|                      |       |                                            |
| /s/ Sigmund J.  Rosenfeld |       | Director                                        |
| Sigmund J.  Rosenfeld     |       |                                            |
|                      |       |                                            |
| /s/ Reuben  Sandler       |       | Director                                        |
| Reuben Sandler            |       |                                            |
|                      |       |                                            |
| /s/ James P.  Schadt      |       | Director                                        |
| James P. Schadt           |       |                                            |
|                      |       |                                            |
| /s/ Joseph W.  Sheehan    |       | Director                                        |
| Joseph W.  Skeehan        |       |                                            |

 

27

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**REPORT OFINDEPENDENT REGISTEREDPUBLIC ACCOUNTING FIRM**

To the Board of DirectorsPRB Energy, Inc.Denver, Colorado

We have auditedthe consolidated balance sheet of PRB Energy, Inc. and subsidiaries as ofDecember 31, 2006, and the related consolidated statements of income,retained earnings and cash flows for the year then ended.  These financial statements are theresponsibility of the Company’s management. Our responsibility is to express an opinion on these financialstatements based on our audit.

We conducted ouraudit in accordance with the standards of the Public Company AccountingOversight Board (United States).  Thosestandards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of materialmisstatement.  An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements.  An audit alsoincludes assessing the accounting principles used and significant estimatesmade by management, as well as evaluating the overall financial statementpresentation.  We believe that our auditprovides a reasonable basis for our opinion.

In our opinion,the consolidated financial statements referred to above present fairly, in allmaterial respects, the financial position of PRB Energy, Inc. and subsidiariesas of December 31, 2006, and the results of their operations and their cashflows for the year then ended, in conformity with U.S. generally acceptedaccounting principles.

As discussed in Note2 to the accompanying consolidated financial statements, effectiveJanuary 1, 2006, the Company adopted Statement of Financial AccountingStandards No. 123(R), *Share-BasedPayment*.

/s/ Hein & AssociatesLLP***HEIN****&ASSOCIATES LLP*

Denver, ColoradoMarch 29, 2007

 

F-1a

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**REPORT OFINDEPENDENT REGISTEREDPUBLIC ACCOUNTING FIRM**

Board of Directors andStockholdersPRB Gas Transportation, Inc. and subsidiaryDenver, Colorado

We haveaudited the accompanying consolidated balance sheet of PRB GasTransportation, Inc. and its subsidiary as of December 31, 2005 andthe related consolidated statements of operations, changes in stockholders’equity and cash flows for each of the years in the two-year period endedDecember 31, 2005. These consolidated financial statements are the responsibilityof the Company’s management. Our responsibility is to express an opinion onthese consolidated financial statements based on our audits.

Weconducted our audits in accordance with standards of the Public CompanyAccounting Oversight Board (United States). Those standards require that weplan and perform the audit to obtain reasonable assurance about whether thefinancial statements are free of material misstatement. The Company is notrequired to have, nor were we engaged to perform, an audit of its internalcontrol over financial reporting. Our audit included consideration of internalcontrol over financial reporting as a basis for designing audit procedures thatare appropriate in the circumstances but not for the purpose of expressing anopinion on the effectiveness of the Company’s internal control over financialreporting. Accordingly, we express no such opinion. An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements. An audit also includes assessing the accountingprinciples used and significant estimates made by management, as well asevaluating the overall financial statement presentation. We believe that ouraudits provide a reasonable basis for our opinion.

In ouropinion, the consolidated financial statements referred to above presentfairly, in all material respects, the financial position of PRB GasTransportation, Inc. and its subsidiary as of December 31, 2005, andthe results of their operations and their cash flows for each of the years inthe two-year period ended December 31, 2005, in conformity with accountingprinciples generally accepted in the United States of America.

Asdiscussed in Note 7 to the consolidated financial statements, the Companyadopted Financial Accounting Standards Board Interpretation No. 47, “Accountingfor Conditional Asset Retirement Obligations,” effective December 31,2005.

/s/Ehrhardt Keefe Steiner & Hottman PC

March 30, 2006

 

F-1b

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**PRB Energy, Inc.Consolidated Balance Sheets***(Inthousands except share amounts)*
| ** **                                                                                                                                                                                                             | ** ** | **December 31, 2006** | ** ** | **December 31, 2005** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------|------------|---------------------------------|------------|
| **Assets**                                                                                                                                                                                                             | ** ** | ** **                      | ** ** | ** **                      | ** ** |
| Current assets:                                                                                                                                                                                                        |       |                            |       |                            |       |
| Cash and cash  equivalents                                                                                                                                                                                             |       | $                               | 11,157     |                            | $          | 6,434 |   |
| Restricted cash                                                                                                                                                                                                        |       | 2,078                           |       | —                          |       |
| Accounts  receivable, net                                                                                                                                                                                              |       | 2,527                           |       | 789                             |       |
| Inventory, net                                                                                                                                                                                                         |       | —                          |       | 1,346                           |       |
| Prepaid expenses                                                                                                                                                                                                       |       | 789                             |       | 194                             |       |
| Total current  assets                                                                                                                                                                                                  |       | 16,551                          |       | 8,763                           |       |
| Oil and gas properties  accounted for under the successful efforts method of accounting:                                                                                                                               |       |                            |       |                            |       |
| Proved  properties                                                                                                                                                                                                     |       | 5,436                           |       | 317                             |       |
| Unproved  leaseholds                                                                                                                                                                                                   |       | 9,282                           |       | 136                             |       |
| Wells-in-progress                                                                                                                                                                                                      |       | 5,794                           |       | 1,081                           |       |
| Total oil and  gas properties                                                                                                                                                                                          |       | 20,512                          |       | 1,534                           |       |
| Less:  accumulated depreciation, depletion and amortization                                                                                                                                                            |       | (766                            | )          | (3                              | )          |
| Net oil and gas  properties                                                                                                                                                                                            |       | 19,746                          |       | 1,531                           |       |
| Gathering and other  property and equipment:                                                                                                                                                                           |       | 11,603                          |       | 6,992                           |       |
| Less:  accumulated depreciation and amortization                                                                                                                                                                       |       | (1,919                          | )          | (968                            | )          |
| Net gathering  and other property and equipment                                                                                                                                                                        |       | 9,684                           |       | 6,024                           |       |
| Other non-current  assets:                                                                                                                                                                                             |       |                            |       |                            |       |
| Deferred debt  issuance costs                                                                                                                                                                                          |       | 2,086                           |       | —                          |       |
| Less:  accumulated amortization                                                                                                                                                                                        |       | (375                            | )          | —                          |       |
| Net deferred  debt issuance costs                                                                                                                                                                                      |       | 1,711                           |       | —                          |       |
| Other  non-current assets                                                                                                                                                                                              |       | 2,151                           |       | 1,122                           |       |
| Total other  non-current assets                                                                                                                                                                                        |       | 3,862                           |       | 1,122                           |       |
| TOTAL ASSETS                                                                                                                                                                                                           |       | $                               | 49,843     |                            | $          | 17,440 |   |
| **Liabilities  and Stockholders’ Equity**                                                                                                                                                                         | ** ** | ** **                      | ** ** | ** **                      | ** ** |
| Current liabilities:                                                                                                                                                                                                   |       |                            |       |                            |       |
| Accounts payable                                                                                                                                                                                                       |       | $                               | 1,854      |                            | $          | 1,652 |   |
| Accrued expenses  and other current liabilities                                                                                                                                                                        |       | 979                             |       | 97                              |       |
| Total current  liabilities                                                                                                                                                                                             |       | 2,833                           |       | 1,749                           |       |
| Secured notes,  debentures and other debt, less current portion                                                                                                                                                        |       | 36,972                          |       | 17                              |       |
| Discount on debentures                                                                                                                                                                                                 |       | (4,326                          | )          | —                          |       |
| Other non-current liabilities                                                                                                                                                                                          |       | 3,140                           |       | 417                             |       |
| Total  liabilities                                                                                                                                                                                                     |       | 38,619                          |       | 2,183                           |       |
| Commitments and  Contingencies                                                                                                                                                                                         |       |                            |       |                            |       |
| Stockholders’ equity                                                                                                                                                                                              |       |                            |       |                            |       |
| Capital,  50,000,000 shares authorized, par value $0.001, 5,639,000 shares undesignated  Series A, B and C Convertible Preferred, 4,361,000 shares authorized; 0  and 40,000 issued and outstanding, respectively |       | —                          |       | *                               |       |
| Common stock,  40,000,000 shares authorized; 8,231,894 issued; 8,601,994 and 7,431,894  outstanding, respectively                                                                                                      |       | 10                              |       | 8                               |       |
| Treasury stock                                                                                                                                                                                                         |       | (1,257                          | )          | (800                            | )          |
| Additional  paid-in-capital                                                                                                                                                                                            |       | 26,406                          |       | 21,325                          |       |
| Accumulated  deficit                                                                                                                                                                                                   |       | (13,935                         | )          | (5,276                          | )          |
| Total  stockholders’ equity                                                                                                                                                                                       |       | 11,224                          |       | 15,257                          |       |
| TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY                                                                                                                                                                        |       | $                               | 49,843     |                            | $          | 17,440 |   |

----

****                   *amountsless than one thousand

The accompanyingnotes are an integral part of these consolidated financial statements.

 

F-2

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**PRB Energy, Inc.Consolidated Statements of Operations***(Inthousands except per share amounts)*
| ** **                                                                                     | ** ** | **Years Ended December 31,** | ** ** |
|------------------------------------------------------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                                                                     | ** ** | **2006**                                    | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                                     | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Revenue:                                                                                       |       |                                        |       |   |   |   |   |
| Natural gas  sales                                                                             |       | $                                           | 1,676      |   | $ | 51 |   | $ | — |   |
| Gas gathering  and processing                                                                  |       | 2,612                                       |       | 2,834 |   | 1,840 |   |
| Other                                                                                          |       | 547                                         |       | 270 |   | 692 |   |
| Total revenue                                                                                  |       | 4,835                                       |       | 3,155 |   | 2,532 |   |
| Natural gas gathering  expense                                                                 |       | 340                                         |       | 12 |   | — |   |
| Natural gas production  taxes                                                                  |       | 182                                         |       | 5 |   | — |   |
| Net revenue                                                                                    |       | 4,313                                       |       | 3,138 |   | 2,532 |   |
| Operating expenses:                                                                            |       |                                        |       |   |   |   |   |
| Gas gathering  and processing                                                                  |       | 2,469                                       |       | 1,755 |   | 1,314 |   |
| Natural gas  lease operating expense                                                           |       | 1,266                                       |       | 17 |   | — |   |
| Asset impairment  charge                                                                       |       | 790                                         |       | 2,487 |   | — |   |
| Exploration  expense                                                                           |       | 50                                          |       | 450 |   | — |   |
| Depreciation,  depletion, amortization and accretion                                           |       | 2,332                                       |       | 1,067 |   | 656 |   |
| General and  administrative                                                                    |       | 5,026                                       |       | 2,029 |   | 1,184 |   |
| Total operating  expenses                                                                      |       | 11,933                                      |       | 7,805 |   | 3,154 |   |
| Operating loss                                                                                 |       | (7,620                                      | )          | (4,667 | ) | (622 | ) |
| Other income (expense):                                                                        |       |                                        |       |   |   |   |   |
| Interest and  other income                                                                     |       | 1,248                                       |       | 167 |   | 29 |   |
| Interest expense                                                                               |       | (2,287                                      | )          | (49 | ) | (58 | ) |
| Total other  (expense) income                                                                  |       | (1,039                                      | )          | 118 |   | (29 | ) |
| Net loss before  cumulative effect of change in accounting principle                           |       | (8,659                                      | )          | (4,549 | ) | (651 | ) |
| Cumulative effect of  change in accounting principle                                           |       | —                                      |       | (76 | ) | — |   |
| Net loss                                                                                       |       | (8,659                                      | )          | (4,625 | ) | (651 | ) |
| Convertible Preferred  stock dividends and deemed dividends                                    |       | —                                      |       | (204 | ) | (1,212 | ) |
| **Net loss applicable to common  stockholders**                                                |       | $                                           | (8,659     | ) | $ | (4,829 | ) | $ | (1,863 | ) |
| Net loss per share of  common stock before cumulative effect of change in accounting principle |       | $                                           | (1.16      | ) | $ | (0.68 | ) | $ | (1.33 | ) |
| Cumulative effect of change  in accounting principle per share of common stock                 |       | —                                      |       | (0.01 | ) | (0.00 | ) |
| **Net loss per share—basic and  diluted**                                                 |       | $                                           | (1.16      | ) | $ | (0.69 | ) | $ | (1.33 | ) |
| Basic and diluted weighted average shares outstanding                                          |       | 7,447,940                                   |       | 6,959,025 |   | 1,398,907 |   |

 

The accompanyingnotes are an integral part of these consolidated financial statements.

F-3

----

 

**PRB Energy, Inc.Statements of Stockholders’ EquityYears Ended December 31, 2006, 2005 and 2004***(Inthousands except share amounts)*
| ** **                                                        | ** ** | **Series** | ** ** | **Series** | ** ** | **Series** | ** ** | **Common** | ** ** | **Treasury** | ** ** | **Additional**      | ** ** | **Accumulated** | ** ** | **Stockholders’** | ** ** |
|-------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|--------------|------------|---------------------|------------|-----------------|------------|------------------------|------------|
| ** **                                                        | ** ** | **A**      | ** ** | **B**      | ** ** | **C**      | ** ** | **Stock**  | ** ** | **Stock**    | ** ** | **Paid-in-capital** | ** ** | **Deficit**     | ** ** | **Equity**             | ** ** |
| **Balance at January 1, 2004**                                    | ** ** | **$**      | **—** | ** ** | **$**      | **—** | ** ** | **$**      | **—** | ** **   | **$**      | **—**          | ** ** | **$**           | **—** | ** **             | **$**      | **—** | ** ** | **$** | **—** | ** ** | **$** | **—** | ** ** |
| Series A shares issued  for cash (2,400,000 shares)               |       | 2          |       | —     |       | —     |       | —     |       | —       |       | 4,985               |       | —          |       | 4,987                  |       |
| Series B shares issued  for cash (1,550,000 shares)               |       | —     |       | 2          |       | —     |       | —     |       | —       |       | 4,639               |       | —          |       | 4,641                  |       |
| Serice C shares issued  for cash (411,000 shares)                 |       | —     |       | —     |       | *          |       | —     |       | —       |       | 1,231               |       | —          |       | 1,231                  |       |
| Common stock shares  issued for cash (1,600,000 shares)           |       | —     |       | —     |       | —     |       | 2          |       | —       |       | 18                  |       | —          |       | 20                     |       |
| Purchase of treasury  stock (800,000 shares)                      |       | —     |       | —     |       | —     |       | *          |       | (800         | )          | —              |       | —          |       | (800                   | )          |
| Deemed capital  contribution related to Series A dividend         |       | —     |       | —     |       | —     |       | —     |       | —       |       | 63                  |       | —          |       | 63                     |       |
| Deemed capital  contribution related to Series C issuance         |       | —     |       | —     |       | —     |       | —     |       | —       |       | 1,027               |       | —          |       | 1,027                  |       |
| Issuance of warrants for  consulting services                     |       | —     |       | —     |       | —     |       | —     |       | —       |       | 12                  |       | —          |       | 12                     |       |
| Series A dividends                                                |       | —     |       | —     |       | —     |       | —     |       | —       |       | (375                | )          | —          |       | (375                   | )          |
| Series B dividends                                                |       | —     |       | —     |       | —     |       | —     |       | —       |       | (116                | )          | —          |       | (116                   | )          |
| Series C deemed dividend                                          |       | —     |       | —     |       | —     |       | —     |       | —       |       | (587                | )          | —          |       | (587                   | )          |
| Accrued dividends on  preferred stock                             |       | —     |       | —     |       | —     |       | —     |       | —       |       | (134                | )          | —          |       | (134                   | )          |
| Net loss                                                          |       | —     |       | —     |       | —     |       | —     |       | —       |       | —              |       | (651            | )          | (651                   | )          |
| **Balance at January 1, 2005**                                    | ** ** | **2**      | ** ** | **2**      |       | *          | ** ** | **2**      | ** ** | **(800**     | **)**      | **10,763**          | ** ** | **(651**        | **)**      | **9,318**              | ** ** |
|                                                              |       |       |       |       |       |       |       |       |       |         |       |                |       |            |       |                   |       |
| Series A conversion to  common stock (2,400,000 shares)           |       | (2         | )          | —     |       | —     |       | 2          |       | —       |       | —              |       | —          |       | —                 |       |
| Series B conversion to  common stock (1,550,000 shares)           |       | —     |       | (2         | )          | —     |       | 2          |       | —       |       | —              |       | —          |       | —                 |       |
| Series C conversion to  common stock (371,000 shares)             |       | —     |       | —     |       | *          |       | *          |       | —       |       | —              |       | —          |       | —                 |       |
| Common stock shares  issued for cash (2,300,000 shares)           |       | —     |       | —     |       | —     |       | 2          |       | —       |       | —              |       | —          |       | 2                      |       |
| Exercise of warrants and  options (10,894 shares)                 |       | —     |       | —     |       | —     |       | *          |       | —       |       | 28                  |       | —          |       | 28                     |       |
| Series A Preferred stock  dividends                               |       | —     |       | —     |       | —     |       | —     |       | —       |       | (139                | )          | —          |       | (139                   | )          |
| Series B Preferred stock  dividends                               |       | —     |       | —     |       | —     |       | —     |       | —       |       | (65                 | )          | —          |       | (65                    | )          |
| Proceeds from initial  public offering, net of offering costs     |       | —     |       | —     |       | —     |       | —     |       | —       |       | 10,738              |       | —          |       | 10,738                 |       |
| Net loss                                                          |       | —     |       | —     |       | —     |       | —     |       | —       |       | —              |       | (4,625          | )          | (4,625                 | )          |
| **Balance at December 31, 2005**                                  | ** ** | **—** | ** ** | **—** |       | *          | ** ** | **8**      | ** ** | **(800**     | **)**      | **21,325**          | ** ** | **(5,276**      | **)**      | **15,257**             | ** ** |
|                                                              |       |       |       |       |       |       |       |       |       |         |       |                |       |            |       |                   |       |
| Series C conversion to  common stock (40,000 shares)              |       | —     |       | —     |       | *          |       | *          |       | —       |       | —              |       | —          |       | —                 |       |
| Issuance of warrants                                              |       | —     |       | —     |       | —     |       | —     |       | —       |       | 163                 |       | —          |       | 163                    |       |
| Share-based compensation                                          |       | —     |       | —     |       | —     |       | —     |       | —       |       | 593                 |       | —          |       | 593                    |       |
| Common stock shares  issued for debt financing (1,250,000 shares) |       | —     |       | —     |       | —     |       | 1          |       | —       |       | 4,325               |       | —          |       | 4,326                  |       |
| Purchase of common  shares for cash (119,900 shares)              |       | —     |       | —     |       | —     |       | *          |       | (457         | )          | —              |       | —          |       | (457                   | )          |
| Net loss                                                          |       | —     |       | —     |       | —     |       | —     |       | —       |       | —              |       | (8,659          | )          | (8,659                 | )          |
| **Balance at December 31, 2006**                                  | ** ** | **$**      | **—** | ** ** | **$**      | **—** | ** ** | **$**      | **—** | ** **   | **$**      | **10**              | ** ** | **$**           | **(1,257** | **)**                  | **$**      | **26,406** | ** ** | **$** | **(13,935** | **)** | **$** | **11,224** | ** ** |

----

****                   *amountsless than one thousand

The accompanyingnotes are an integral part of these consolidated financial statements.

F-4

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**PRB Energy, Inc.Consolidated Statements of Cash Flows***(Inthousands)*
| ** **                                                                                 | ** ** | **Years Ended December 31,** | ** ** |
|--------------------------------------------------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                                                                 | ** ** | **2006**                                    | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                                 | ** ** | ** **                                  | ** ** | ** ** |   |   |   |
| **Cash flows from operating  activities**                                                  |       |                                        |       |   |   |   |   |
| Net loss                                                                                   |       | $                                           | (8,659     | ) | $ | (4,625 | ) | $ | (651 | ) |
| Adjustments to  reconcile net loss to net cash (used in) provided by operating activities: |       |                                        |       |   |   |   |   |
| Depreciation,  depletion, amortization and accretion                                       |       | 2,332                                       |       | 1,067 |   | 656 |   |
| Asset impairment  charge                                                                   |       | 790                                         |       | 2,487 |   | — |   |
| Exploration  expense                                                                       |       | 50                                          |       | 450 |   | — |   |
| Amortization of  debt issuance costs                                                       |       | 375                                         |       | — |   | — |   |
| Bad Debt Expense                                                                           |       | 605                                         |       | — |   | — |   |
| Share-based  compensation expense                                                          |       | 663                                         |       | — |   | — |   |
| Warrants issued  for services rendered                                                     |       | 45                                          |       | — |   | — |   |
| Capitalized  interest                                                                      |       | (135                                        | )          | — |   | — |   |
| Cumulative  effect of change in accounting principle                                       |       | —                                      |       | 76 |   | — |   |
| Deemed compensation                                                                        |       | —                                      |       | — |   | 441 |   |
| Gain on sale of  assets                                                                    |       | (311                                        | )          | (2 | ) | — |   |
| Changes in  assets and liabilities:                                                        |       |                                        |       |   |   |   |   |
| Accounts  receivable                                                                       |       | (1,943                                      | )          | (366 | ) | (423 | ) |
| Inventory                                                                                  |       | 1,346                                       |       | (1,346 | ) | — |   |
| Prepaid expenses                                                                           |       | (595                                        | )          | (90 | ) | (104 | ) |
| Other  non-current assets                                                                  |       | (118                                        | )          | (19 | ) | (4 | ) |
| Accounts payable                                                                           |       | 201                                         |       | 1,514 |   | 157 |   |
| Accrued expenses  and other current liabilities                                            |       | 621                                         |       | 73 |   | — |   |
| Deferred revenue                                                                           |       | 69                                          |       | — |   | — |   |
| Other  non-current liabilities                                                             |       | 308                                         |       | — |   | — |   |
| Net cash (used  in) provided by operating activities                                       |       | (4,356                                      | )          | (781 | ) | 72 |   |
| **Cash flows from investing  activities**                                                  |       |                                        |       |   |   |   |   |
| Capital  expenditures                                                                      |       | (5,270                                      | )          | (1,979 | ) | (41 | ) |
| Acquisition of  natural gas properties and gathering facilities                            |       | (17,453                                     | )          | (336 | ) | (10,606 | ) |
| Restricted cash  related to future liabilities of acquired properties                      |       | (3,078                                      | )          | — |   | — |   |
| Sale of  gathering and fixed assets                                                        |       | 350                                         |       | 17 |   | — |   |
| Net cash used in  investing activities                                                     |       | (25,451                                     | )          | (2,298 | ) | (10,647 | ) |
| **Cash flows from financing  activities**                                                  |       |                                        |       |   |   |   |   |
| Proceeds from  IPO, net of issuance costs                                                  |       | —                                      |       | 11,007 |   | — |   |
| Proceeds from  convertible notes and senior secured debentures                             |       | 36,965                                      |       | — |   | — |   |
| Issuance costs  related to convertible notes and senior secured debentures                 |       | (1, 968)                                    |       | — |   | — |   |
| Deferred costs  of raising capital                                                         |       | —                                      |       | — |   | (255 | ) |
| Repurchase of  common stock                                                                |       | (457                                        | )          | — |   | — |   |
| Repurchase of treasury  stock                                                              |       | —                                      |       | — |   | (800 | ) |
| Proceeds from  issuance of common stock                                                    |       | —                                      |       | 28 |   | 20 |   |
| Proceeds from  issuance of Series A, B and C Convertible Preferred Stock                   |       | —                                      |       | — |   | 10,859 |   |
| Borrowings under  bank loan and financing agreement                                        |       | —                                      |       | 50 |   | — |   |
| Repayment of  bank loan                                                                    |       | —                                      |       | (1,550 | ) | 1,500 |   |
| Repayment of  term loan                                                                    |       | (10                                         | )          | — |   | — |   |
| Dividends                                                                                  |       | —                                      |       | (338 | ) | (429 | ) |
| Repayment of  retail installment sale contract                                             |       | —                                      |       | (4 | ) | — |   |
| Net cash  provided by financing activities                                                 |       | 34,530                                      |       | 9,193 |   | 10,895 |   |
| Net increase in cash                                                                       |       | 4,723                                       |       | 6,114 |   | 320 |   |
| Cash—beginning of year                                                                |       | 6,434                                       |       | 320 |   | — |   |
| **Cash—end of year**                                                                  |       | $                                           | 11,157     |   | $ | 6,434 |   | $ | 320 |   |
| **Supplemental disclosure of cash  flow activity**                                         |       |                                        |       |   |   |   |   |
| Cash paid for  interest                                                                    |       | 1,924                                       |       | 49 |   | 58 |   |
| **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 Convertible Preferred stock                          |       | *                                           |       | 4 |   | — |   |
| Common stock  issued related to financing of acquisition                                   |       | 4,326                                       |       | — |   | — |   |
| Capital  remediation costs                                                                 |       | 1,333                                       |       | — |   | — |   |
| Asset retirement  obligations                                                              |       | 2,805                                       |       | 318 |   | 60 |   |
| Retail installment sale  contract used to purchase vehicle                                 |       | —                                      |       | 31 |   | — |   |

----

****                   *amountsless than one thousand

The accompanyingnotes are an integral part of these consolidated financial statements.

F-5

----

**PRB ENERGY, INC.Notes to Consolidated Financial StatementsDecember 31, 2006**

**Note1—General**

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 weoperate and for third-party producers. We were initially incorporated in Nevadaunder the name “PRB Transportation, Inc.” in December 2003.  On June 14, 2006, we changed our name to “PRBEnergy, Inc.”  Our common stock is tradedon the American Stock Exchange (“AMEX”) under the ticker symbol “PRB.”   PRB Energy operates as two business segmentsthrough two wholly-owned subsidiaries, PRB Oil and Gas, Inc., a Coloradocorporation, a gas and oil exploitation and production company (“E&P”),formed in July, 2005, and PRB Gathering, Inc., a Colorado corporation, agathering and processing company (“G&P”), formed in August 2006.  We conduct our business activities inWyoming, Colorado and Nebraska.

**Note2—Summary of Significant Accounting Policies**

Basis of Presentation- The consolidated financial statements include the accounts of the Company andits subsidiaries.  All materialinter-company transactions have been eliminated.  Certain prior period amounts have beenreclassified to conform to the current financial statement presentation.

Use of Estimates- The preparation of financial statements in conformity with accountingprinciples generally accepted in the United States of America requiresmanagement to make estimates and assumptions that affect the reported amountsof assets and liabilities, disclosures of contingent assets and liabilities atthe date of the financial statements and the reported amounts of revenues andexpenses during the reporting period. Actual results could differ from those estimates.

Cash and cash equivalents- The Company considers all highly liquid instruments purchased with an originalmaturity of three months or less to be cash equivalents.  The Company continually monitors itspositions with, and the credit quality of, the financial institutions withwhich it invests.  As of the balancesheet date, and periodically throughout the year, the Company has maintainedbalances in various operating accounts in excess of federally insured limits.

Accounts receivable- Trade accounts receivable are recorded at the invoiced amount.  The Company does not have anyoff-balance-sheet credit exposure related to its customers.  The Company assesses credit risk andallowance for doubtful accounts on a customer specific basis.  As of December 31, 2005, the Company did not havean allowance for doubtful accounts.  Asof December 31, 2006 the Company has a combined total allowance for doubtfulaccounts of $605,000 due to evaluation of collection on some customeraccounts.  Of this allowance for doubtfulaccounts, $596,000 pertains to Rocky Mountain Gas, Inc. (“RMG”).  RMG’s receivables totaled $791,000 atDecember 31, 2006 and the remaining balance, after the allowance, of $195,000is reflected in the consolidated financial statements.

Five individual customers accounted for 81% of totalsales and no other individual customer accounted for 10% or more of total salesfor the year ended December 31, 2006. One individual customer accounted for 54% of total sales and no otherindividual customer accounted for 10% or more of total sales for the year endedDecember 31, 2005.

As of December 31, 2006, JMG Exploration, Inc. (“JMG”)had an outstanding balance due of $107,000 for interest charges related tocertain gas gathering pipe held by a third party for resale.  The pipe was originally purchased jointly bythe Company and JMG for a gas gathering project in 2005.  Under a letter agreement dated March 18,2006, JMG agreed to indemnify the Company against any costs associated with thesale of the pipe, including any carrying and storage costs of the pipe.  The agreed upon interest rate to be chargedJMG was 10% per annum.  The interest wascharged from October 28, 2005 to date on the costs incurred by the Company,less any proceeds from the sale of the pipe. The pipe inventory was sold during 2006 and the proceeds were receivedby the Company and credited to the inventory account.

The Company grants credit in the normal course ofbusiness to customers in the United States. The Company periodically performs credit analysis and monitors thefinancial condition of its customers to reduce credit risk. Management periodicallyreviews accounts receivable aging reports to assess credit risks, and ifappropriate, also reviews updated credit information to further assess suchrisk.  In the event that managementdetermines the customers’ accounts receivable collectibility as less thanprobable, management reduces the carrying amount by a valuation allowance thatreflects management’s best estimate of the amount that may not becollectible.  Allowances foruncollectible accounts receivable are based on information available andhistorical experience.  For informationon the concentration of credit risk by customer in the years ended December 31,2006 and 2005 respectively please see Note 3 of these consolidated financialstatements.

F-6

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Inventory- Inventory is recorded at the lower of cost or market.  The Company periodically reviews the carryingcost of its inventories as compared to current market value for thoseinventories and adjusts its carrying value to the lower of cost or market.  At December 31, 2006 the Company had no inventory.

Income Taxes- In accordance with SFAS No. 109, “Accounting for Income Taxes” (“SFAS No. 109”),the Company recognizes deferred tax liabilities and assets based on thedifferences between the tax basis of assets and liabilities and their reportedamounts in the consolidated financial statements that will result in taxable ordeductible amounts in future years.  Inevaluating the ability to realize net deferred tax assets, the Company willtake into account a number of factors, primarily relating to the Company’sability to generate taxable income.  TheCompany has not recorded a deferred tax asset attributable to the net operatingloss for the years ended December 31, 2006 and December 31, 2005 asit is more likely than not that a deferred benefit will not be realized.

Revenue Recognition- The Company recognizes gas gathering revenue at the time when the service isrendered.  The Company recognizes revenuefrom the sale of natural gas during the period the sale of the product occursand title transfers to the buyer.  TheCompany recognizes management services revenue when the service is provided.

Property, Equipment andContracts—Gas Gathering and Other - The Company periodicallyreviews carrying values of long-lived assets for impairment. Gathering assetsare depreciated over 10 years.

Other property andequipment, such as office furniture, computer and related software andequipment, automobiles and leasehold improvements are recorded at cost.  Depreciation is calculated using thestraight-line method over the estimated useful lives of the assets orunderlying leases in respect to leasehold improvements, ranging from 3 to 10years.

Amortization ofcontracts is calculated using the straight-line method over the term of theunderlying contracts or the estimated life of production over ten years.

Oil and Gas ProducingProperties - The Company has elected to follow the successfulefforts method of accounting for its oil and gas properties.  Under this method of accounting, all propertyacquisition costs and costs of exploratory and development wells arecapitalized when incurred.  If anexploratory well does not find proved reserves, the costs of drilling theunsuccessful exploratory well are charged to expense.  Exploratory dry hole costs are included incash flows from investing activities as part of capital expenditures in theconsolidated statements of cash flows. The cost of development wells, whether productive or not, iscapitalized.  Geological and geophysicalcosts and the cost of carrying and retaining unproved properties are expensedas incurred.

Depreciation,depletion and amortization (“DD&A”) of capitalized costs of proved oil andgas properties is determined on a field-by-field basis using theunits-of-production method based upon proved reserves.  The computation of DD&A takes intoconsideration restoration, dismantlement and abandonment costs and theanticipated proceeds from equipment salvage. The Company has adopted the provisions of Statement of FinancialAccounting Standards (“SFAS”) No. 143, “Accounting for Asset RetirementObligations” (“SFAS No. 143”) which provides guidance on accounting fordismantlement and abandonment costs and FASB Interpretation 47, “Accounting forConditional Asset Retirement Obligations” (“FIN No. 47”) which providesguidance in determining estimated dismantlement and abandonment costs insituations where the method and timing of settlement are uncertain. SeeNote 7—Asset Retirement Obligations.

Impairment of Long-LivedAssets - In accordance with SFAS No. 144, “*Accounting for the Impairment or Disposal ofLong-Lived Assets*,” the Company groups assets at the field level andperiodically reviews the carrying value of its property and equipment to testwhether current events or circumstances indicate that such carrying value maynot be recoverable.  If the testsindicate that the carrying value of the asset is greater than the estimatedfuture undiscounted cash flows to be generated by such asset, then animpairment adjustment needs to be recognized. Such adjustment consists of the amount by which the carrying value ofsuch asset exceeds its fair value.  TheCompany generally measures fair value by considering sale prices for similarassets or by discounting estimated future cash flows from such asset using anappropriate discount rate.  Considerablemanagement judgment is necessary to estimate the fair value of assets, andaccordingly, actual results could vary significantly from such estimates.  When assets are sold, the applicable costsand accumulated depreciation and depletion are removed from the accounts andany gain or loss is included in income. Expenditures for maintenance and repairs are expensed as incurred.

The Companyreviews its long-lived assets and other intangible assets with long lives forimpairment whenever events or changes in circumstances indicate that thecarrying amount of the asset may not be recovered.  An impairment loss is recognized only if thecarrying value of the asset is not recoverable and exceeds its fair marketvalue.  The Company estimates the fairmarket value of its long-lived assets using expected future discounted cashflows.

Exploration Expense- The Company accounts for exploration and development activities utilizing thesuccessful efforts method of accounting. Exploration costs, including personnel costs, certain geological andgeophysical expenses and delay rentals for oil and gas leases, are charged toexpense as incurred.  Drilling costs areinitially capitalized, but charged to expense if and when the well is determinednot to have found proved reserves in commercial quantities.  The application of the successful effortsmethod of accounting requires managerial judgment to determine that properclassification of wells designated as developmental or exploratory is made todetermine the proper accounting treatment of the costs incurred.  The results from a drilling operation cantake considerable time to analyze and the determination that commercialreserves have been discovered requires both judgment and industry experience.  Wells may be completed that are assumed to beproductive but actually deliver oil and gas in quantities insufficient to beeconomic.  This may result in theabandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are bothdevelopmental and exploratory in nature and an allocation of costs is requiredto properly account for the results.  Theevaluation of 

F-7

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oil and leaseholdacquisition costs requires managerial judgment to estimate the fair value of thesecosts with reference to drilling activity in a given area.

Asset RetirementObligations - The Company follows SFAS No. 143 and FINNo. 47. Estimated future asset abandonment costs are discounted to presentvalues using a risk-adjusted rate over the estimated economic life of theassets.  Such costs are capitalized aspart of the cost of the related asset and amortized over the related asset’sestimated useful life.  The associatedliability is classified as a long-term liability and is adjusted when circumstanceschange and for the accretion of expense which is recorded as a component ofdepreciation, depletion and amortization. The Company recognizes an estimate of the liability associated with theabandonment of oil and gas properties at the time the well is completed.  The Company estimated its asset retirementobligation liabilities for these wells based on estimated costs to plug andabandon the wells and its respective ownership percentage in the wells.

Stock-Based Compensation- At December 31, 2006, the Company had a stock-based employeecompensation plan that includes stock options issued to employees andnon-employee Directors as more fully described in Note 12—CompensationPlans.  Prior to 2006, the Company hadaccounted for stock-based compensation using the intrinsic value recognitionand measurement principles detailed in Accounting Principles Board OpinionNo. 25, “Accounting for Stock Issued to Employees” and relatedinterpretations.  No stock-basedcompensation expense relating to stock options has been reflected in theCompany’s statements of operations for any period presented as all optionsgranted under the plan had an exercise price equal to or higher than the marketvalue of the underlying common stock on the date of grant.  The Company currently uses the Black-Scholesoption valuation model to calculate required disclosures.  As of January 1, 2006, the Company hasadopted the provisions of SFAS No. 123R, “Share-Based Payment” (“SFASNo. 123R”).  This statement requiresthe Company to record compensation expense associated with the fair value ofstock-based compensation.  As a result ofthe adoption of SFAS No. 123R, the Company expects to record compensationexpense associated with all unvested stock options totaling $605,000 in futureperiods under the modified-prospective adoption method.

In respect to thepro forma disclosures herein, the options are amortized to expense over theoptions’ vesting periods.  Future actualamounts may differ from the pro forma disclosures.  The following table illustrates the pro formaeffect on net loss and loss per share if the Company had applied the fair valuerecognition provisions of SFAS No. 123, “Accounting for Stock—BasedCompensation” (“SFAS No. 123”) to stock-based employee compensation:
| ** **                                                                                                  | ** ** | **For the Year Ended December 31,** | ** ** |
|-------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------------------------|------------|
| ** **                                                                                                  | ** ** | **2005**                                                     | ** ** | **2004** | ** ** |
| ***(in thousands, except per share amounts)***                                     | ** ** | ** **                                                   | ** ** | ** ** | ** ** |
| Net loss  applicable to common stockholders:                                                                |       |                                                         |       |   |   |
| As reported                                                                                                 |       | $                                                            | (4,829     | ) | $ | (1,863 | ) |
| Add: Stock-based employee compensation expense  included in reported net income, net of related tax effects |       | 534                                                          |       | 38 |   |
| Pro forma net loss                                                                                          |       | $                                                            | (5,363     | ) | $ | (1,901 | ) |
| Pro forma basic  and diluted earnings per share                                                             |       | $                                                            | (0.77      | ) | $ | (1.36 | ) |

 

For purposes ofpro forma disclosures, the estimated fair values of the options are amortizedto expense over the options’ vesting periods. The effects of applying SFAS No. 123 in the pro forma disclosureare not necessarily indicative of actual future amounts, particularly since thefuture amortization expense is less than was recorded in 2006, as describedabove.

Net Loss Per Share- The Company accounts for earnings (loss) per share (“EPS”) in accordance withSFAS No. 128, “Earnings per  Share” (“SFAS No. 128”).  Under SFAS No. 128, basic EPS iscomputed by dividing the net loss attributable to common stockholders by theweighted average common shares outstanding without including any potentiallydilutive securities.  Diluted EPS iscomputed by dividing the net loss for the period by the weighted average commonshares outstanding plus, when their effect is dilutive, common stockequivalents.

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

|                                             | ** ** | **For the years ended** | ** ** |
|---------------------------------------------|------------|----------------------------------------|------------|
| ** **                                  | ** ** | **December 31,**                  | ** ** |
| ** **                                  | ** ** | **2006**                               | ** ** | **2005** | ** ** | **2004** | ** ** |
| Series A  Convertible Preferred             |       | —                                 |       | — |   | 2,400,000 |   |
| Series B  Convertible Preferred             |       | —                                 |       | — |   | 1,550,000 |   |
| Series C  Convertible Preferred        |       | —                                 |       | 40,000 |   | 411,000 |   |
| Convertible  subordinated                   |       | 3,137,857                              |       | — |   | — |   |
| Warrants                                    |       | 300,000                                |       | 230,000 |   | 45,000 |   |
| Options                                     |       | 617,250                                |       | 463,250 |   | 220,000 |   |
| Total potentially  dilutive shares excluded |       | 4,055,107                              |       | 733,250 |   | 4,626,000 |   |

 

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Subsequent toDecember 31, 2006 the Company issued the following dilutive securities,which would have increased the number of potentially dilutive shares excluded(above), if these securities were issued prior to December 31, 2006: 

|            | ** ** | **Potential**          | ** ** |
|------------|------------|------------------------|------------|
| ** ** | ** ** | **Common Shares** | ** ** |
| Warrants   |       | 15,000                 |       |
| Options    |       | 172,500                |       |
| Total      |       | 187,500                |       |

 

Off-Balance SheetArrangements - As part of its ongoing business, the Companyhas not participated in transactions that generate relationships withunconsolidated entities or financial partnerships, such as entities oftenreferred to as structured finance or special purpose entities (“SPEs”), or SPEswhich would have been established for the purpose of facilitating off-balancesheet arrangements or other contractually narrow or limited purposes.  As of December 31, 2006, the Company hasnot been involved in any unconsolidated SPE transactions.

***Recent Accounting Pronouncements***

InDecember 2004, the FASB issued SFAS No. 123R. SFAS No. 123Rrequires that compensation costs relating to share-based payment transactionsbe recognized in financial statements based on the fair value of the equity orliability instruments issued.  SFASNo. 123R covers a wide range of share-based compensation arrangementsincluding share options, restricted share plans, performance-based awards,share appreciation rights and employee share purchase plans.  Effective April 2005, the Securities andExchange Commission extended the implementation date to the beginning of aregistrant’s next fiscal year beginning after June 15, 2005.  The provisions of SFAS No. 123R wereadopted by the Company effective January 1, 2006.  As a result of the adoption of SFASNo. 123R, the Company recorded compensation expense associated withunvested stock options totaling $685,000 under the modified-prospectiveadoption method.

InMarch 2005, the FASB issued FIN No. 47 which clarifies that the term “conditionalasset retirement obligation” refers to a legal obligation to perform an assetretirement activity in which the timing and/or method of settlement areconditional on a future event that may or may not be within the control of theentity.  The obligation to perform theasset retirement activity is unconditional even though uncertainty exists aboutthe timing and/or method of settlement. This Interpretation is effective for years ended December 15, 2005or later.  The Company adopted thisInterpretation effective December 31, 2005. See Note 7—Asset RetirementObligations.

In May 2005,the FASB, as part of an effort to conform to international accountingstandards, issued SFAS No. 154, “*AccountingChanges and Error Corrections*” (“SFAS No. 154”), which iseffective for the Company beginning on January 1, 2006. SFAS No. 154requires that all voluntary changes in accounting principles be retrospectivelyapplied to prior financial statements as if that principle had always beenused, unless it is impracticable to do so. When it is impracticable to calculate the effects on all prior periods,SFAS No. 154 requires that the new principle be applied to the earliestperiod practicable.  The adoption of SFASNo. 154 did not have a material effect on the Company’s financial positionor results of operations.

SFAS No. 19, “*Financial Accounting and Reporting by Oil and GasProducing Companies*,” specifies that drilling costs for completedexploratory wells should be expensed if the related reserves cannot beclassified as proved within one year unless certain criteria are met.  In April 2005, the FASB issued FASBStaff Position 19-1, “Accounting for Suspended Well Costs” (“FSP 19-1”). FSP19-1 provides guidance for evaluating whether sufficient progress is being madeto determine whether reserves can be classified as proved. FSP 19-1 iseffective for all reporting periods beginning after April 4, 2005, and theCompany adopted FSP 19-1 upon incurrence of initial exploratory drilling costsduring the fourth quarter of 2005.

In June 2006, theFASB issued Interpretation (FIN) No. 48, “*Accountingfor Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109*.”  This interpretation requires that realizationof 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 recognizedin the financial statements.  Further,this interpretation prescribes the benefit to be recorded in the financialstatements as the amount most likely to be realized assuming a review by taxauthorities having all relevant information and applying currentconventions.  This interpretation alsoclarifies the financial statement classification of tax-related penalties andinterest and sets forth new disclosures regarding unrecognized taxbenefits.  This interpretation iseffective for fiscal years beginning after December 15, 2006, and theCompany will be required to adopt this interpretation in the first quarter of2007.  Based on the Company’s evaluationas of December 31, 2006, it does not believe that the implementation of FIN 48will have a material impact on its financial statements.

In September 2006,Statement of Financial Accounting Standards (SFAS) No. 157, “*Fair Value Measurements*”**was issued by the Financial AccountingStandards Board (FASB).  This statementdefines fair value, establishes a framework for measuring fair value andexpands disclosures about fair value measurements.  SFAS No. 157 will become effective forthe fiscal year beginning January 1, 2008, and the Company is currentlyassessing the potential impact of this Statement on the financial statements.

In September 2006,Staff Accounting Bulletin (“SAB”) No. 108*,*“*Considering the Effects of PriorYear Misstatements when Quantifying Misstatements in Current Year FinancialStatements*.”  Registrants mustquantify the impact on current period financial statements of correcting allmisstatements, including both those occurring in the current period and theeffect of reversing those that have accumulated from prior periods.  This SAB was adopted at December 31,2006.  The adoption ofSAB No. 108 had no effect on the financial position or on the resultsof operations.

In February 2007,the FASB issued SFAS No. 159, “*The FairValue Option for Financial Assets and Financial Liabilities*,” whichpermits an entity to measure certain financial assets and financial liabilitiesat fair value.  The objective of SFAS No.159 is to improve financial reporting by allowing entities to mitigate volatilityin reported earnings caused by the measurement of related assets andliabilities using different attributes, without having to apply complex hedgeaccounting provisions.  Under SFAS No.159, entities 

F-9

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that elect the fair valueoption (by instrument) will report unrealized gains and losses in earnings ateach subsequent reporting date.  The fairvalue option election is irrevocable, unless a new election date occurs.  SFAS No. 159 establishes presentation anddisclosure requirements to help financial statement users understand the effectof the entity’s election on its earnings, but does not eliminate disclosurerequirements of other accounting standards. Assets and liabilities that aremeasured at fair value must be displayed on the face of the balance sheet.  This statement is effective beginning January1, 2008 and the Company is evaluating this pronouncement.

**Note3—Concentration of Credit Risk**

The Company sellsgas and natural gas liquids to pipelines, refineries and oil companies.  Credit is extended based on an evaluation ofthe customer’s financial condition and historical payment record.

Revenuesfrom customers which represented 10% or more of the Company’s sales for thethree and year ended December 31, 2006 and 2005 were as follows:

|                                      | ** ** | **For the year  ended** | ** ** |
|--------------------------------------|------------|---------------------------------------------|------------|
| ** **                           | ** ** | **December 31,**                       | ** ** |
| **Customer**                         | ** ** | **2006**                                    | ** ** | **2005** | ** ** |
| ** **                           | ** ** | **(% of total revenue)**     | ** ** |
| ** **                           | ** ** | ** **                                  | ** ** | ** ** | ** ** |
| A — Exploration  and production |       | 22.2                                        | %          | — |   |
| B — Gathering  and Processing   |       | 13.2                                        | %          | 54 | % |
| C — Gathering  and Processing   |       | 21.2                                        | %          | — |   |
| D — Exploration  and production |       | 13.4                                        | %          | — |   |
| E — Gathering and  Processing   |       | 11.4                                        | %          | — |   |

 

The Company doesnot believe that the loss of any one customer would impact us marketability.

**Note4—Acquisitions**

Recluse

In the firstquarter of 2006, the Company acquired 2 gas gathering systems in the Reclusearea of Wyoming (together “Recluse” gathering system) for approximately $1.5million.  Also, in 2 separatetransactions totaling $183,000, the Company acquired a combination of workinginterests ranging from 7.5% to 15% in the development of approximately 5,600net acres in the Recluse and Gap areas that offer us the opportunity to expandboth E&P and G&P activities.

True Oil Pipeline

The Companyacquired approximately 70 miles of gathering lines in the Recluse, Wyoming areaof the Powder River Basin which will provide gathering opportunities on over100,000 acres.  The transaction is closedon July 15, 2006 and was effective as of July 1, 2006. The purchase price forthese assets was $428,100 and was funded by cash on hand.  The associated ARO booked for the pipelinewas $171,000 in accordance with SFAS No. 143. The purchase was recorded using the purchase method of accounting underSFAS No. 141.  The purchase price,including legal fees and other professional fees incurred, was allocated to thepipeline. 

Gap, Bonepile,Bellnob Fields

On June 30, 2006,the Company acquired working interests in approximately 580 gross (529 net)coal-bed methane (“CBM”) wells on approximately 29,000 acres located in thePowder River Basin of Wyoming from Pennaco Energy, Inc. (“Pennaco”).  The purchase price of the acquired interestswas approximately $600,000 and the effective date was July 1, 2006.  As part of the purchase agreement, theCompany issued a $3 million reducing letter of credit for the benefit ofPennaco to guarantee the funding of the future liability of the plugging costsof wells purchased from Pennaco.  Theasset retirement obligation of these wells has been recorded on the balancesheet for $2 million based on the discounted present value of the futureliability.  The letter of credit iscollateralized by a $3 million certificate of deposit (“CD”) and is consideredrestricted cash for purposes of available working capital. The restrictedamount of the CD will be released at the same rate annually that the letter ofcredit is reduced.  A potion of the CD isclassified under Other Non-current assets on the Balance Sheet for $1 million,based on the terms of the agreement.  Theremaining $2 million is considered a current asset, as the letter of credit isanticipated to be reduced by that estimated amount as of June 30, 2007 underthe terms of the agreement.

Of the 580 grosswells acquired, fewer than 130 wells were commercially producing naturalgas.  The Company currently hasapproximately 220 wells on production.

F-10

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The purchase wasrecorded using the purchase method of accounting under SFAS No. 141.  The purchase price, including legal fees andother professional fees incurred, was allocated to the asset categories as outlinedin the following table based on the estimated fair value of the assetsacquired:
| **Asset category**     | ** ** | **In thousands** | ** ** |
|-----------------------------|------------|-----------------------|------------|
| Proved Property  — ARO |       | $                     | 2,032      |   |
| Producing  Leasehold Costs  |       | 1,190                 |       |
| Lease and Well  Equipment   |       | 746                   |       |
| Total                       |       | $                     | 3,966      |   |

 

Northeast Colorado— Denver-Julesburg (D-J) basin — Niobrara formation

In December 2006,PRB Oil & Gas, Inc. acquired producing wells and approximately 330,000 netacres in the D-J Basin, which is located in northeast Colorado and southwestNebraska.  This acquisition provides the Company with geographic diversityin operations.  In addition, with the use of 3-D seismic, numerouspotential conventional drilling locations have been identified.  Thisacquisition also includes additional proprietary 2-D and 3-D seismic that theCompany believes should provide low-risk exploitation.

In connection withthe December 2006 acquisition, PRB Energy and PRB Oil & Gas, Inc. enteredinto a Securities Purchase Agreement with two private lenders.  Pursuantto that agreement, PRB Oil & Gas, Inc. issued to the lenders $15 million ofsenior secured debentures (the “Debentures”) and PRB Energy issued to thelenders 1,250,000 shares of common stock.  For more information regardingthe issuance of the  Debentures and the1,250,000 shares of the Company’s common stock, see Note 11 — Stockholders’Equity.

The purchase wasrecorded using the purchase method of accounting under SFAS No. 141.  The purchase price, including legal fees andother professional fees incurred, was allocated to the asset categories as outlinedin the following table based on the estimated fair value of the assetsacquired:
| **Asset category**      | ** ** | **In thousands** | ** ** |
|------------------------------|------------|-----------------------|------------|
| Proved Property  — ARO  |       | $                     | 186        |   |
| Undeveloped  Leasehold Costs |       | 8,917                 |       |
| Producing  Leasehold Costs   |       | 850                   |       |
| Lease and Well  Equipment    |       | 1,933                 |       |
| Total                        |       | $                     | 11,886     |   |

 

**Note5—Property, Equipment and Contracts**

Property andequipment consists of the following:
| ** **                                      | ** ** | **Useful Lives** | ** ** | **December 31, 2006** | ** ** | **December 31, 2005** | ** ** |
|-------------------------------------------------|------------|-----------------------|------------|---------------------------------|------------|---------------------------------|------------|
| ***(in thousands)***                       | ** ** | ** **            | ** ** | ** **                      | ** ** | ** **                      | ** ** |
| Compressor  sites, pipelines and interconnect   |       | 1-10 years       |       | $                               | 10,676     |                            | $          | 6,806 |   |
| Equipment in  stock                             |       | 5 years               |       | 26                              |       | —                          |       |
| Computer  equipment                             |       | 3 years          |       | 313                             |       | 29                              |       |
| Office furniture  and equipment and related     |       | 5-7 years        |       | 254                             |       | 97                              |       |
| Automobiles                                     |       | 3 years          |       | 334                             |       | 60                              |       |
|                                            |       |                  |       | 11,603                          |       | 6,992                           |       |
| Less accumulated  depreciation and amortization |       |                  |       | (1,919                          | )          | (968                            | )          |
| Total                                           |       |                  |       | $                               | 9,684      |                            | $          | 6,024 |   |

 

The Company’scompressor sites, pipeline and equipment are in respect to G&Poperations.  Depreciation expense inrespect to property and equipment totaled $974,000 and $843,000 for the yearsended December 31, 2006 and 2005, respectively.

The Companyreviewed the carrying value of the TOP system as associated revenue haddeclined due to decreasing producer volumes as well as the loss of acustomer.  Based on this review, theCompany recorded an asset impairment charge of $2,487,000 relative to the TOPsystem during the year ended December 31, 2005.  The impairment charge included $1,645,000 forproperty and equipment and $842,000 for contracts.  The Company based its impairment on anindependent evaluation of the fair market value of the system.  As of September 1, 2006 the Company sold thesystem to Arête Industries, Inc. for $330,000 in cash.  The net gain on the sale of $308,000 isreflected in Other Income in the December 31, 2006 consolidated financialstatements.

Contracts valuedat $1,280,000 (on the date of acquisition, August 2004) in respect tothe BPE assets are being amortized over 10 years which is the estimatedlife of the contracts and the natural gas reserves underlying the contracts.  Amortization expense in respect to contractstotaled $128,000 and $213,000 for the years ended December 31, 2006 and2005, respectively.  The amortizationexpense for the year ended December 31, 2005 included amortization of theTOP contracts through September 30, 2005, when the TOP contracts wereimpaired in full.

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Gas Gathering andTransportation Contracts - *BPE*

The Companyassumed a 10-year gas transportation contract with an unrelated third party,Bear Paw Energy, LLC (“BPE”) that was effective in September 2001.  BPEtransports customers’ gas for $0.14 per Mcf.  The Company purchasedcertain assets from BPE effective August 1, 2004.

Future periodamortization expense in respect to the BPE contracts is as follows:

| Year  ending December 31, | ** ** | **In thousands** | ** ** |
|-----------------------------------------------|------------|-----------------------|------------|
| 2007                                          |       | $                     | 128        |   |
| 2008                                          |       | 128                   |       |
| 2009                                          |       | 128                   |       |
| 2010                                          |       | 128                   |       |
| 2011                                          |       | 128                   |       |
| Thereafter                                    |       | 331                   |       |
| Total                                         |       | $                     | 971        |   |

 

Storm Cat Agreement

Effective January1, 2006, we entered into a gas gathering services agreement (“the Agreement”)with Storm Cat Energy Corporation (“Storm Cat”) which requires Storm Cat to payus gas gathering fees on specific minimum volumes of gas whether or not thosevolumes are delivered and transported through our system. The Agreement has aten-year term, of which the first 5 years are non-cancelable.  The Agreement requires Storm Cat to makeminimum payments in 2006 during the first 3 years of the Agreement.  TheAgreement also provides for our gas gathering rates to decrease during thefourth and fifth years.

During the yearended December 31, 2006, we billed Storm Cat for actual volumes delivered.  The Agreement allows for a cash true-uppayment at each year end if the annual volume commitment under the Agreement isnot met.  We recognize revenues based onour estimate of the average gas gathering rate during the non-cancelable termof the Agreement. Accordingly, we deferred the gas gathering fees as anon-current liability on our balance sheet at December 31, 2006.

**Note6—Inventory**

Inventory atDecember 31, 2005 of $1.3 million consisted of approximately 32 miles of 8-inchsteel pipe that was purchased for an oil and gas pipeline project that wasbeing planned to transport a customer’s oil and gas production.  The Company sold the balance of the inventoryduring 2006 at cost.

**Note7—Asset Retirement Obligations**

During the yearsended December 31, 2005 and 2006, the Company reviewed its assetretirement obligations in respect to its BPE assets and determined an estimateof those future liabilities as determined in accordance with FIN No. 47.  The Company was previously unable todetermine a reasonable estimate of the timing of future period estimateddismantlement liabilities in accordance with SFAS No. 143.  Those future liabilities include the removalof pipelines and compressor stations per the associated contracts. The Companyestimated its future obligations in respect to the BPE assets based onestimated probabilities that the surface-use agreement based obligation wouldoccur and also assigned probabilities as to potential settlement dates.  The agreements with the lessors includeprovisions allowing the lessor to decide at a future date whether the lessorrequires that the Company dismantle its sites and lines. Accordingly, theCompany recorded the estimated asset retirement obligation liabilities of$259,000 in respect to the BPE systems effective December 31, 2005, uponadoption of FIN No. 47.  Thisincluded $76,000 of accretion and depreciation expense that has been recordedas a cumulative effect of change in accounting principle in the statement ofoperations for the year ended December 31, 2005.  The $76,000 cumulative effect of change inaccounting principle included $30,000 for the year ended December 31, 2004and $46,000 for the year ended December 31, 2005.

The Companyestimated its future obligation in respect to the True Oil pipeline in theRecluse area and recorded its estimated asset retirement obligation liabilitiesof $178,000 effective December 31, 2006. During the years ended December 31, 2006 and 2005, the Company alsoestablished asset retirement obligations in respect to oil and gas propertiesof $2.7 million and $59,000, respectively.

The followingtable details all changes to the Company’s estimated asset retirementobligation liabilities during the years ended December 31, 2006 and 2005:

|                                                                      | ** ** | **For the**      | ** ** |
|----------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                           | ** ** | **Year Ended**   | ** ** |
| ** **                                                           | ** ** | **December 31,** | ** ** |
| ** **                                                           | ** ** | **2006**              | ** ** | **2005** | ** ** |
| ***(in thousands)***                                            | ** ** | ** **            | ** ** | ** ** | ** ** |
| Asset retirement  obligations, beginning of period                   |       | $                     | 387        |   | $ | 65 |   |
| Sale of TOP  assets                                                  |       | (52                   | )          | — |   |
| Cumulative  effect of change in accounting principle—BPE assets |       | —                |       | 259 |   |
| Gathering assets                                                     |       | 199                   |       | — |   |
| Proved  properties                                                   |       | 2,292                 |       | 59 |   |
| Accretion  expense                                                   |       | 314                   |       | 4 |   |
| Asset retirement  obligations, end of period                         |       | $                     | 3,140      |   | $ | 387 |   |

 

The Company willcontinue to review its asset retirement obligations and will adjust itsestimates when facts and circumstances warrant.

F-12

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**Note 8—Income Taxes**

Income tax benefitfor each of the years ended December 31, 2006, 2005, and 2004 are asfollows:

|                                    | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ***(in thousands)***          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Current:                           |       |       |       |       |       |       |       |
| Federal                            |       | $          | —     |       | $          | —     |       | $ | — |   |
| State                              |       | —     |       | —     |       | —     |       |
| Total current  income tax benefit  |       | —     |       | —     |       | —     |       |
| Deferred:                          |       |       |       |       |       |       |       |
| Federal & State                |       | 2,678      |       | 1,883      |       | 71         |       |
| Valuation allowance                |       | (2,678     | )          | (1,883     | )          | (71        | )          |
| Total deferred  income tax benefit |       | —     |       | —     |       | —     |       |
| Total income tax  benefit          |       | $          | —     |       | $          | —     |       | $ | — |   |

 

The reconciliationof the benefit for income taxes computed at the statutory rate to the provisionfor income taxes as shown in the financial statements of operations for theyears ended December 31, 2006, 2005 and 2004 is as follows: 

|                                                                  | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ***(in thousands)***                                        | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Computed at the  estimated effective tax rate                    |       | $          | 3,155      |       | $          | 1,619      |       | $ | 228 |   |
| Permanent  differences, changes in effective tax rate, and other |       | (477       | )          | (14        | )          | (157       | )          |
| Valuation  allowance                                             |       | (2,678     | )          | (1,605     | )          | (71        | )          |
| Income tax benefit                                               |       | $          | —     |       | $          | —     |       | $ | — |   |

 

The components ofthe net deferred income tax assets (liabilities) are as follows:

|                                     | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|-------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ***(in thousands)***           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Non-current  assets (liabilities):  |       |       |       |       |       |       |       |
| Property and equipment              |       | $          | (591       | )          | $          | (215       | )          | $ | (276 | ) |
| Oil and gas properties              |       | (2,145     | )          | (372       | )          | —     |       |
| Contracts                           |       | 38         |       | 331        |       | 18         |       |
| Organization costs                  |       | 11         |       | 15         |       | 2          |       |
| Asset retirement obligations        |       | 1,162      |       | 135        |       | 23         |       |
| Net operating loss carryforwards    |       | 5,863      |       | 1,987      |       | 304        |       |
| Bonus accrual                       |       | —     |       | 2          |       | —     |       |
| Bad debt expense                    |       | 223        |       | —     |       | —     |       |
| Valuation allowance                 |       | (4,561     | )          | (1,883     | )          | (71        | )          |
| Net deferred tax asset  (liability) |       | $          | —     |       | $          | —     |       | $ | — |   |

 

AtDecember 31, 2006 and 2005, the Company had net operating loss carryforwards, for federal income tax purposes, of approximately $16.0 million and$4.6 million, respectively.  These netoperating loss carry forwards, if not utilized to reduce taxable income infuture periods, will expire in various amounts beginning in 2024 through2026.  This net operating loss carryforward may be subject to U.S. Internal Revenue Code Section 382limitations.

The Company hasestablished a valuation allowance for deferred taxes that offsets its netdeferred tax assets as management currently believes that these losses will notbe utilized in the near term.  Theallowance recorded was $2.7 million and $1.9 million for 2006 and 2005,respectively.  The Company will continueto evaluate the reasonableness and appropriateness of the valuation allowancein future periods.

F-13

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**Note 9—Commitments and Contingencies**

***Rescission of Series C Convertible Preferred Stock Sale***

InDecember 2004, the Company received $1.233 million from the sale of411,000 shares of Series C Convertible Preferred stock.  The Company paid no cash or other commissionsor finders’ fees in connection with this offering.  In the view of the SEC, this placement mightnot have been eligible for an exemption from registration under the SecuritiesAct of 1933.  In the absence of such anexemption, investors could bring suit against the Company to rescind theirstock purchases, in which event the Company could be liable for rescissionpayments to these investors of up to $1.233 million exclusive of interestand costs.  In August 2005, theCompany filed a registration statement on Form S-1 to register theunderlying shares of common stock issuable upon conversion of the Series CConvertible Preferred stock.  The SECdeclared the S-1 effective on August 16, 2005.  As of December 31, 2005 and December 31,2006, respectively, 371,000 shares and 40,000 shares of Series CConvertible Preferred had been converted to common shares.

***Commitments***

As a normal courseof the Company’s business operations, it entered into operating leases foroffice space, office equipment, vehicles and compression equipment.  In addition, the Company has entered intoservice agreements that provide compression equipment and related services on abundled basis.  These agreements, whichpertain to the BPE gas gathering systems, expired in 2006.

In addition, theCompany is a party to surface-use and right-of-way agreements in respect to thegathering systems and E&P properties that are cancelable when gas volumesdecline to a level where the contract is uneconomic to the Company.  The Company has estimated that future minimumlease commitments under these agreements will expire in 2014 based on estimatedreserves in place.

Rental paymentsunder these operating leases and service agreements totaled $1.09 million and$1.78 million for the periods ended December 31, 2006 and 2005,respectively.

Future payments,by year, under these operating leases and service agreements are as follows:

|            | ** ** | **(in thousands)** | ** ** |
|------------|------------|-------------------------|------------|
| 2007       |       | $                       | 674        |   |
| 2008       |       | 666                     |       |
| 2009       |       | 644                     |       |
| 2010       |       | 667                     |       |
| 2011       |       | 501                     |       |
| Thereafter |       | 2,024                   |       |
| Total      |       | $                       | 5,176      |   |

 

**Note 10—Borrowings**

***Senior Subordinated Convertible Notes (the “Notes”)***

*** ***InMarch 2006, the Company issued the Notes of approximately $22 million in aprivate placement.  The Notes are securedby certain gas gathering assets owned by the Company and mature 30 months fromthe date of issue.  The Notes bearinterest at a fixed rate of 10% per annum, payable quarterly in arrearsbeginning on March 15, 2006.  Aregistration statement applicable to the shares of common stock underlying theNotes was filed in May 2006 and declared effective on June 21, 2006.  The Notes do not contain any beneficialconversion features.

Debt issuancecosts in the amount of $1.05 million, excluding the value of warrantsissued, were deferred as other non-current assets and are being amortizedas interest expense using the effective interest method over the 30-month lifeof each Note.  For the year-endedDecember 31, 2006, the Company incurred $2 million in total interest expenseapplicable to the Notes.

Note holders havethe right to convert the Notes to common stock at a conversion price of $7.00per share, which is subject to certain anti-dilution adjustments.  In the event that the common stock trades at$14.00 per share or above for 10 consecutive days, the Company has a callprovision that allows us to retire the Notes upon 10 days prior written noticeby paying in cash the principal amount and any accrued but unpaidinterest.  In addition, the Company isprohibited from declaring or paying cash dividends on the common stock duringthe period that one of the Notes is outstanding and unpaid.

The Companyfollows SFAS No. 133, and EITF 00-19, “*Accounting for Derivative Financial Instruments Indexto, and Potentially Settled in, a Company’s Own Stock*” and relatedpronouncements.  The Company hasevaluated the conversion feature embedded in the senior subordinatedconvertible Notes and the liquidated damages provision in the relatedRegistration Rights Agreement and has determined that the entire amount ofthese securities is properly classified as long-term debt and are not accountedfor as derivatives on the consolidated balance sheet at December 31, 2006.

***Senior Secured Debentures (the “Debentures”)***

In connection withthe December 2006 acquisition of the NE Colorado Field in the Niobraraformation, the Company entered into a Securities Purchase Agreement with twoprivate lenders.  Pursuant to that agreement, the Company issued to thelenders $15 million of the Debentures and the Company issued to the lenders 1,250,000shares of common stock, which are being offered pursuant to thisprospectus.  For more information regarding the issuance of the Debenturesand the 1,250,000 shares of common stock, see Note 11 — Stockholders’ Equity.

The Debenturesmature and are due and payable on August 31, 2008 and bear interest at 13% perannum, which is due and 

F-14

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payable quarterly inarrears.  Subject to certain conditions, the Debentures can be prepaid bythe Company with a premium for early prepayment of 110% of the principal amounts. Upon the occurrence of an event of default, as described in theDebentures, the payment of the principal amounts may be accelerated and theinterest rate applicable to the principal amounts will be increased to 18% perannum during the period the default exists.  A majority of the proceedsreceived from the lenders was used for the acquisition of the Niobraraformation properties on December 28, 2006 with the balance to be used forgeneral corporate purposes.  Refer toPart 1, Item 1-Business on Niobrara formation under Acquisitions andDivestitures.

Debt issuancecosts in the amount of $1 million were deferred as other non-current assets andare being amortized as interest expense using the effective interest methodover the 20-month life of each Note.  Forthe year-ended December 31, 2006, the Company incurred $16,000 in totalinterest expense applicable to the Notes.

Pursuant to theterms of a Pledge and Security Agreement entered into by the Company and thelenders, the Debentures are collateralized by substantially all of the assets,except for certain excluded assets as described in the Pledge and SecurityAgreement.  Pursuant to the terms of the Pledge and Security Agreement,the lenders are entitled to foreclose on, and take possession of the pledgedassets if an event of default occurs.  In addition, pursuant to the termsof the Secured Guaranty, the Company has agreed to jointly and severallyguarantee performance under the Debentures and other transaction documents.

***Promissory Note***

On December 14,2004, the Company signed a promissory note with the Bank of Oklahoma (“BOK”)for a $1.75 million revolving line of credit that was due on the earlier ofMarch 31, 2005 or upon funding of its initial public offering.  This promissory note was paid in full inApril 2005 from proceeds from the initial public offering and the line ofcredit was withdrawn.

***Stockholder Pledge of Certificate of Deposit***

OnDecember 14, 2004, a preferred stockholder pledged a certificate ofdeposit in the amount of $1.0 million as collateral for the BOK line of credit,as discussed above.  The pledge waswithdrawn upon payment of the BOK note in April 2005.

***Retail Installment Sale Contract***

On August 3,2005, the Company purchased a vehicle using a 0% retail installment sale contractfor a total of $31,000.

***Maturities***

Future debtmaturities are reflected on the following table:

|            | ** ** | **(in thousands)** | ** ** |
|------------|------------|-------------------------|------------|
| 2007       |       | $                       | —     |   |
| 2008       |       | 36,965                  |       |
| 2009       |       | —                  |       |
| 2010       |       | —                  |       |
| 2011       |       | —                  |       |
| Thereafter |       | —                  |       |
| Total      |       | $                       | 36,965     |   |

 

**Note11—Stockholders’ Equity**

***Common Shares Issued for Debt Financing***

On December 28,2006, in connection with the acquisition of the D-J Basin properties, theCompany entered into a securities purchase agreement (“SPA”) with two privatelenders.  Pursuant to the SPA, in exchangefor $15 million of proceeds, The Company issued and sold to the lenders $15million of Debentures and the Company issued and sold to the lenders 1,250,000shares of common stock.  The amountincluded in stockholders’ equity and as a discount on Debentures on the balancesheet on December 31, 2006 was $4,326,000 which represented the market value ofthe common stock issued to the lenders on December 28, 2006.

The shares of theCompany’s common stock issued to the lenders, at the time they were issued, represented14.5% of our outstanding common stock on a fully diluted basis.  The Company also entered into a RegistrationRights Agreement with the lenders requiring us to file a registration statementregistering the shares issued to the lenders for resale on behalf of them underthe Securities Act of 1933.  In the eventthat the registration statement is not declared effective within onehundred-fifty (150) days of December 28, 2006 or the effectiveness of theregistration statement is not maintained, the Company is obligated to pay, on apro rata basis, to each holder of the shares of common stock issued to thelenders certain delay payments described in the Registration RightsAgreement.  Such delay payments shall notexceed, in the aggregate, $750,000.  Theregistration statement was filed with the SEC on February 2, 2007 and the SECstaff comments were received and have been responded to on March 22, 2007.

***Initial Public Offering***

On April 12,2005, the Company’s registration statement on Form S-1 was declaredeffective by the SEC and the Company’s stock began trading on the AMEX underthe trading symbol PRB.  The Company sold2,300,000 shares of common stock, including 300,000 shares pursuant to theunderwriter’s exercise of its over-allotment option. In conjunction with theoffering, holders of Series A and Series B preferred stock convertedtheir shares into an equal number of registered common shares.  The Company recorded proceeds of$10.2 million net of underwriter’s discounts, commissions and expenses,including warrants valued at $583,000.

F-15

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***Dividends***

None.

***Warrants***

On June 28,2004, the Company granted 45,000 warrants to consultants as compensation fortheir work on the Company’s initial public offering.  These warrants have a five-year term withimmediate vesting and an exercise price of $5.50.  The estimated fair value of the warrants atDecember 31, 2004 was $12,000 based on the Black-Scholes option pricingmodel.

The Companyentered into an underwriting agreement on April 12, 2005.  The agreement called for the underwriter topurchase the shares on a firm commitment basis at an 8% discount to theoffering price.  The Company’sunderwriter also received a 3% non-accountable expense allowance of theaggregate offering price of the shares offered, excluding the 300,000over-allotment shares.  At the closing ofthe underwriting, the Company sold warrants to the underwriter to purchase200,000 shares of common stock at a price of $0.0001 per warrant.  The warrants have an exercise price of $6.875(125% of the initial offering price) and are exercisable for 4 years from thefirst anniversary of the issuance, or within 2 years following the effectiveregistration date of the shares underlying the warrants, whicheverearlier.  The estimated fair value of thewarrants at issuance was $571,000 based on the Black-Scholes option pricingmodel.

During the yearended December 31, 2004, the Company recorded deferred offering costsof raising capital, with a corresponding increase in additional paid-in-capitalin respect to the 45,000 warrants issued during that period, of $12,000.  In respect to the 200,000 warrants issuedduring April 2005, the fair value of the warrants of $571,000 was alsocharged against additional paid-in-capital.

The following assumptions were used in determining the fair values ofthe warrants as described previously:

| Risk-free interest rate (%) |   | 3.89   | %      |
|-----------------------------|--------|--------|--------|
| Expected life (years)       |   | 5      |   |
| Expected volatility (%)     |   | 25     | %      |
| Expected dividends          |   | — |   |

 

ThroughDecember 31, 2006, 2005, and 2004, respectively, cumulative activity inrespect to warrants is as follows:

|                             | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|-----------------------------|------------|----------|------------|----------|------------|----------|------------|
| Balance, beginning of  year |       | 230,000  |       | 45,000   |       | —   |       |
| Issued                      |       | 70,000   |       | 200,000  |       | 45,000   |       |
| Exercised                   |       | —   |       | (15,000  | )          | —   |       |
| Balance, end of year        |       | 300,000  |       | 230,000  |       | 45,000   |       |

 

The warrantsexercised during the year ended December 31, 2005 were exercised under thecashless exercise provision.

**Note 12—Equity Incentive Plans**

The Company has anEquity Incentive Plan (“Option Plan”). The Plan grants options to purchase shares of the Company’s common stockto eligible employees, contractors and current and former members of the Boardof Directors.  There are 860,199 sharesof the Company’s common stock reserved for issuance under the Plan.  There are no expired shares during the yearof December 31, 2006.

All optionsgranted to date under the Plan have been granted at exercise prices equal to orgreater than the respective market prices of the Company’s common stock on thegrant dates.  There were 284,000 sharesexercisable under the Plan as of December 31, 2006.  As of January 1, 2006, the Company hasadopted the provisions of SFAS No. 123R, “Share-Based Payment” (“SFASNo. 123R”).  This statement requiresthe Company to record compensation expense associated with the fair value ofstock-based compensation.  As a result ofthe adoption of SFAS No. 123R, the Company expects to record compensationexpense associated with all unvested stock options totaling $605,000 in futureperiods under the modified-prospective adoption method.

The following table summarizes activity for options:
| ** **                                                     | ** ** | **For the Year Ended** | ** ** | **For the Year Ended** | ** ** | **For the Year Ended** | ** ** |
|----------------------------------------------------------------|------------|---------------------------------------|------------|---------------------------------------|------------|---------------------------------------|------------|
| ** **                                                     | ** ** | **December 31, 2006**       | ** ** | **December 31, 2005**       | ** ** | **December 31, 2004**       | ** ** |
| ** **                                                     | ** ** | **Number of**                    | ** ** | **Weighted Avg.**                | ** ** | **Number of**                    | ** ** | **Weighted Avg.** | ** ** | **Number of** | ** ** | **Weighted Avg.** | ** ** |
| ** **                                                     | ** ** | **Shares**                            | ** ** | **Exercise Price**               | ** ** | **Shares**                            | ** ** | **Exercise Price** | ** ** | **Shares** | ** ** | **Exercise Price** | ** ** |
| Outstanding, beginning  of year                                |       | 463,250                               |       | $                                     | 6.74       |                                  | 220,000    |   | $ | 5.50 |   | — |   | — |   |
| Granted                                                        |       | 323,500                               |       | $                                     | 6.03       |                                  | 299,000    |   | $ | 7.59 |   | 220,000 |   | $ | 5.50 |   |
| Forfeitures                                                    |       | (169,500                              | )          | $                                     | 7.15       |                                  | (50,750    | ) | $ | 6.51 |   | — |   | — |   |
| Exercised                                                      |       | —                                |       | —                                |       | (5,000                                | )          | $ | 5.50 |   | — |   | — |   |
| Outstanding, end of  year                                      |       | 617,250                               |       | $                                     | 6.35       |                                  | 463,250    |   | $ | 6.74 |   | 220,000 |   | $ | 5.50 |   |
| Exercisable, end of  year                                      |       | 284,000                               |       | $                                     | 6.40       |                                  | 227,500    |   | $ | 6.39 |   | 70,000 |   | $ | 5.50 |   |
| Weighted-average fair value of options granted during the year |       | 323,500                               |       | $                                | 4.02       |                                  | 299,000    |   | $  | 3.19 |   | 220,000 |   | $  | 0.82 |   |

 

The weighted average remaining contractual life forthe options outstanding at December 31, 2006 and 2005, respectively is 6.5years and 7.4 years.  The fair valueof each option granted is estimated on the date of grant using theBlack-Scholes option pricing model.  Theweighted average fair value of options outstanding at December 31, 2006and 2005, respectively, is $2.98 and $2.16. The weighted average fair value of options granted and exercisable atDecember 31, 2006 and 2005, respectively, is $2.46 and $1.63.  

F-16

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SFAS No. 123establishes a fair value method of accounting for stock-based compensationplans through either recognition or disclosure. The Company accounts for stock-based compensation under the intrinsicvalue method pursuant to Accounting Principles Board (“APB”) OpinionNo. 25, “Accounting for Stock Issued to Employees” (“APB No. 25”) andhas elected to adopt SFAS No. 123 through compliance with the disclosurerequirements set forth in the Statement. Because the exercise price of theCompany’s stock options equals the market price or higher of the underlyingstock on the date of the grant, no compensation expense is recognized under APBNo. 25.  Pro forma informationregarding net loss and loss per share is required by SFAS No. 123 and hasbeen determined as if the Company had accounted for its employee stock optionsunder the fair value method of that Statement. See Note 2—Summary of SignificantAccounting Policies for pro forma information.

The fair value ofoptions was measured at the date of grant using the Black-Scholesoption-pricing model.  The fair values ofoptions granted and employee stock purchase plan shares issued were estimatedusing the following weighted-average assumptions:
| ** **                                                                         | ** ** | **December 31,** | ** ** | **December 31,** | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------------------------------|------------|-----------------------|------------|-----------------------|------------|-----------------------|------------|
| **Assumption**                                                                     | ** ** | **2006**              | ** ** | **2005**              | ** ** | **2004**              | ** ** |
| Risk free interest rate  (%)                                                       |       | 4.31-5.25             |       | 3.9-4.5               |       | 3.89-4.73             |       |
| Volatility factor of  the expected market price of the Company’s common stock |       | 69.45-80              | %          | 25                    | %          | 25                    | %          |
| Expected life of the  options (in years)                                           |       | 5-10                  |       | 5-10                  |       | 5-10                  |       |
| Expected dividend                                                                  |       | —                |       | —                |       | —                |       |

 

The Black-Scholesoption valuation model was developed for use in estimating the fair value oftraded options that have no vesting restrictions and are fullytransferable.  In addition, optionvaluation models incorporate highly subjective assumptions including theexpected stock price volatility.  The Company’sstock options have characteristics significantly different from those of tradedoptions and, as changes in the subjective input assumptions can materiallyaffect the fair value estimate, it is management’s opinion that the valuationsas determined by the existing models are different from the value that theoptions would realize if traded in the market.

**Note13—Disclosures about Oil and Gas Producing Activities**

***Costs Incurred in Oil and Gas Producing Activities***

The Companycommenced oil and gas activities during the year ended December 31,2005.  The Company has incurred the followingcosts, both capitalized and expensed, in respect to oil and gas propertyacquisition, exploration and development activities during the year endedDecember 31, 2006 and 2005, respectively:
| ** **                | ** ** | **For the Years Ended December 31,** | ** ** |
|---------------------------|------------|---------------------------------------------------------------|------------|
| ***(in thousands)*** | ** ** | **2006**                                                      | ** ** | **2005** | ** ** |
| Acquisitions:             |       |                                                          |       |   |   |
| Proved                    |       | $                                                             | 4,507      |   | $ | — |   |
| Unproved                  |       | 9,282                                                         |       | 136 |   |
| Exploration               |       | 50                                                            |       | 1,531 |   |
| Development costs         |       | 4,480                                                         |       | 314 |   |
|                      |       | $                                                             | 18,319     |   | $ | 1,981 |   |

 

Included in theabove costs are capitalized asset retirement obligations for the years endedDecember 31, 2006 and 2005, respectively of $2,248,000 and $59,000,respectively.

The followingtable sets forth certain information regarding the results of operations foroil and gas producing activities for the years ended December 31, 2006 and2005, respectively:
| ** **                                   | ** ** | **For the Years Ended December 31,** | ** ** |
|----------------------------------------------|------------|---------------------------------------------------------------|------------|
| ***(in thousands)***                    | ** ** | **2006**                                                      | ** ** | **2005** | ** ** |
| Revenues, net                                |       | $                                                             | 1,154      |   | $ | 34 |   |
| Production Costs                             |       | (1,266                                                        | )          | (17 | ) |
| Asset Impairment (1)                         |       | (790                                                          | )          | — |   |
| Exploration                                  |       | (50                                                           | )          | (450 | ) |
| Depreciation, Depletion  & Accretion (2) |       | (1,039                                                        | )          | (98 | ) |
|                                         |       | $                                                             | (1,991     | ) | $ | (531 | ) |

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*Note (1*):  The $790,000 impairment charge represents theremaining net book value of the Reno/Dilts wells previously included in E&Pproperty assets and located in the Powder River Basin  With the production volumes leveling off,management determined that there was insufficient revenue projected to coverthe operating expenses of the rental generators and the diesel.  These uneconomical properties weresubsequently shut in during the first quarter of 2007.

*Note (2*):  Includes $764,000 of depreciation anddepletion of well costs and $275,000 of accretion of asset retirementobligation for wells.

F-17

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The followingtable details the net changes in capitalized exploratory well costs for theyears ended December 31, 2006 and 2005, respectively:
| ** **                                                                                            | ** ** | **For the Years Ended December 31,** | ** ** |
|-------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ***(in thousands)***                                                                             | ** ** | **2006**                                                      | ** ** | **2005** | ** ** |
| Beginning balance at  January 1,                                                                      |       | $                                                             | 1,081      |   | $ | — |   |
| Additions to  capitalized exploratory well costs pending the determination of proved  reserves        |       | —                                                        |       | 1,531 |   |
| Reclassifications to  wells, facilities, and equipment based on the determination of proved  reserves |       | (1,031                                                        | )          | — |   |
| Capitalized exploratory  well costs charged to expense                                                |       | (50                                                           | )          | (450 | ) |
| Ending Balance at December 31,                                                                        |       | $                                                             | —     |   | $ | 1,081 |   |

 

*Allcapitalized wells-in-progress at year-end 2006 were development wells.*

In 2006, thedrilling programs were related to development drilling due to acquired reservesand established drilling locations in producing or proved formations.  At December 31, 2006, $4.8 million ofdevelopment drilling costs remained capitalized as wells-in-progress.  All wells-in-progress at December 31, 2006were classified as development wells. All capital costs added during 2006 for wells-in-progress that arereflected on the balance sheet at year-end 2006 were incurred within oneyear.  None of these wells are in areasrequiring major capital expenditures before production could beanticipated.  These wells have eitherbeen reclassified to proved producing properties, or are currently beingcompleted and undergoing de-watering. The Company believes that after these wells are de-watered, it will beable to determine if proved reserves have been discovered.  The Company estimates that in mid-2007 itwill be able to make this determination.

During 2005, theexploratory CBM drilling pilot programs were begun.  The Company charged $450,000 of theseexploratory drilling costs, relating to 6 wells, to exploration expense.  At December 31, 2005, $1.1 million ofexploratory drilling costs remained capitalized as wells-in-progress pendingthe determination of proved reserves.

***Oil and Gas Reserve Quantities (Unaudited)***

The Companyengaged independent geological and petroleum engineering consultants,Netherland, Sewell & Associates, Inc. (“NSAI”), in 2006, and SprouleAssociates, Inc. (“Sproule”) in 2005, to estimate our natural gasreserves.  The Company also reviewed thecalculations and assumptions these consultants use to calculate thereserves.  NSAI determined the 2006year-end reserve information included on their report, Estimate of Reserves andFuture Revenue as of December 31, 2006, and Sproule determined the 2005year-end reserve information included on their report, Reserve and EconomicEvaluation as of January 1, 2006.

The Companyemphasizes that the reserve estimates are imprecise by their nature, andreserve estimates on new discoveries and developments are less precise thanreserve estimates for existing fields. Accordingly, the Company expects these estimates to change as time passesand information as to actual well performance can be included in those futureestimates.  The NSAI report was based onthe Henry Hub gas product price of $5.63 per million British Thermal Unit(MMBtu) in effect on December 31, 2006, held constant for the life of theproperties and adjusted by lease for regional price differentials, energycontent, and transportation and compression charges.  As a result, net prices ranged from $3.16 to$3.86 in Wyoming and $5.14 in Colorado. Lease operating costs were also held constant in accordance with SEC guidelines.

Proved oil and gasreserves are estimates of recoverable quantities of oil, natural gas andnatural gas liquids that are determined using engineering and geological datawith reasonable certainty.  The reserveestimates are based on existing economic and operating conditions and includeonly existing wells from known reservoirs with existing equipment andtechnology.  All of the proved reservesin 2005 were located in the Powder River Basin area of Wyoming.  In 2006 the Company added proved and unprovedreserves in the Denver-Julesburg (D-J) Basin of northeastern Colorado andsouthwestern Nebraska.

The followingtable summarizes estimated proved reserves of gas in million cubic feet (MMcf)as of December 31, 2006:
| ***(In MMcf)***               | ** ** | **2006** | ** ** | **2005(1)** | ** ** |
|------------------------------------|------------|----------|------------|-------------|------------|
| Proved developed and  undeveloped: |       |     |       |        |       |
| Beginning of year,  January 1 |       | 396      |       | —      |       |
| Revisions of  previous estimates   |       | 706      |       | —      |       |
| Purchases of  reserves in place    |       | 4,967    |       | —      |       |
| Discoveries                        |       | —   |       | 402         |       |
| Production                         |       | (395     | )          | (6          | )          |
| End of year, December 31      |       | 5,674    |       | 396         |       |

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(1)    Theseamounts represent proved developed producing reserves.

                      *As ofDecember 31, 2006, 32% of the proved reserves are categorized as proveddeveloped producing.*

***Standardized Measure of Discounted Future Net Cash Flows(Unaudited)***

SFAS No. 69, “*Disclosures about Oil and Gas Producing Activities*”(“SFAS 69”) details guidelines of how to determine the standardized measure offuture net cash flows and changes therein relating to estimated provedreserves.  The Company follows theseguidelines that are summarized as follows:

·         Future cash inflows,production and development costs are determined by applying oil and gas pricesand costs in effect at 

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year-end, including overhead expense allocable, transportation, qualityand basis differentials to the year-end quantities of oil and gas to beproduced in the future;

·         Future income taxes areestimated using current income tax rates and estimated future statutory depletion;

·         Future operating anddevelopment costs are based on estimates of expenditures in developing andproducing proved oil and gas reserves in place at year-end, assuming continuityof year-end economic conditions;

·         The resulting cash flowsare reduced to present value using a 10% discount rate; and

·         The Company used thefollowing gas prices as the year end price at Henry Hub of $5.63 per MMBtu fornatural gas on an Mcf basis, as adjusted by lease for regional pricedifferentials, energy content and transportation and compression charges:

·                  NiobraraFormation in NE Colorado = $5.14 per Mcf

·                  PowderRiver Basin North Field = $3.86 per Mcf

·                  PowderRiver Basin Gap/Bonepile acquired from Pennaco = $3.16 per Mcf

·                  PowderRiver Basin Recluse field = $3.36 per Mcf

The followingsummarizes the standardized measure of future net cash flows relating to itsproved gas reserves as of December 31, 2006 as prescribed in SFAS No. 69:

| *(in thousands)*                                    | ** ** | **2006** | ** ** | **2005(1)** | ** ** |
|----------------------------------------------------------|------------|----------|------------|-------------|------------|
| Future cash flows                                        |       | $        | 19,235     |        | $          | 2,089 |   |
| Future production costs                                  |       | (7,394   | )          | (878        | )          |
| Future development  costs                                |       | (4,283   | )          | —      |       |
| Future abandonment  costs                                |       | —   |       | (75         | )          |
| Future income taxes                                      |       | (381     | )          | (316        | )          |
| Future net cash flows                                    |       | 7,177    |       | 820         |       |
| Ten percent discount                                     |       | (1,670   | )          | (132        | )          |
| Standardized measure of discounted future net cash flows |       | $        | 5,507      |        | $          | 688 |   |

 

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(1)             Theseamounts represent proved developed producing reserves.

The followingsummarizes the changes in the standardized measure of discounted future netcash flows relating to its proved gas reserves as of December 31, 2006 asprescribed in SFAS No. 69.  

| *(in thousands)*                                             | ** ** | **2006** | ** ** |
|-------------------------------------------------------------------|------------|----------|------------|
| Standardized measure -  Beginning of year                         |       | $        | 688        |   |
| Sales and transfers,  net of production costs                     |       | 111      |       |
| Net change in sales and  transfer prices, net of production costs |       | (895     | )          |
| Changes in future  development costs                              |       | 156      |       |
| Revisions of quantity  estimates                                  |       | 998      |       |
| Accretion of discount                                             |       | 106      |       |
| Net change in income  taxes                                       |       | 334      |       |
| Purchases of reserves  in place                                   |       | 4,827    |       |
| Changes in production  rates (timing) and other                   |       | (818     | )          |
| Standardized measure of discounted future net cash flows          |       | $        | 5,507      |   |

 

***Note:***The Company initiated its oil and gas activities during the year endedDecember 31, 2005.

**Note 14—SegmentInformation**

SFAS No. 131, “*Disclosures about Segments of an Enterprise andRelated Information*” (“SFAS No.131”) establishes standards for theway in which public companies disclose certain information about operatingsegments in their financial reports. Consistent with SFAS No. 131, the Company has defined two reportablesegments, described below, based on factors such as how the Company managesoperations and how the chief operating decision makers view results.  The Company considers the chief executiveofficer and the chief operating officer as the chief operating decisionmakers.  During the third quarter of2005, the Company entered into the oil and gas exploration and productionsegment and began producing and selling natural gas during the fourth quarterof 2005.

***Oil and Gas Exploitation and Production Segment (“E&P”)***

 Beginning inthe third quarter of 2005, the Company commenced operations in the exploitationand production segment.  Operations inthis segment include developing and producing natural gas from CBM wells.  For the year ended December 31, 2006, ourE&P segment operated in the Powder River Basin area of Wyoming.

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Through amanagement services agreement with RMG, the Company earned management feerevenues that it has included under Corporate in the following table thatdetails the performance of our segments.  In March 2006, the Companyelected to terminate the management services agreement; however, it agreed tocontinue to provide services under the agreement through June 30, 2006.

***Gas Gathering and Processing Segment (“G&P”)***

The Company ownsand operates gas gathering and processing systems it acquired in 2004 andduring the year ended December 31, 2006, as earlier described.  The Company charges a fee to our customersfor these services based on volumes of gas transported, based on a monthly minimumfee and/or based on the level of compression services provided.  The Company has acquired gas gatheringcontracts that include operating leases in respect to surface-use rights thatare cancelable in the event that gas gathering activities cease as a result ofdeclining production.  The Company alsohas cancelable purchase commitments with third party providers for future fieldoperations, equipment and maintenance activities. 
| ** **                                           | ** ** | **For the Year Ended December 31, 2006** | ** ** |
|------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                           | ** ** | **E & P**                                                | ** ** | **G & P** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| ***(in thousands)***                                 | ** ** | ** **                                                             |       |   |   |   |   |   |   |
| Revenues, net of  production taxes and other         |       | $                                                                      | 1,154      |   | $ | 2,612 |   | $ | 547 |   | $ | 4,313 |   |
| Operating expense                                    |       | 1,266                                                                  |       | 2,469 |   | — |   | 3,735 |   |
| Asset impairment charge                              |       | 790                                                                    |       | — |   | — |   | 790 |   |
| Exploration expense                                  |       | 50                                                                     |       | — |   | — |   | 50 |   |
| Depreciation,  depletion, amortization and accretion |       | 764                                                                    |       | 806 |   | 762 |   | 2,332 |   |
| General and  administrative                          |       | —                                                                 |       | — |   | 5,026 |   | 5,026 |   |
| Operating loss                                       |       | (1,716                                                                 | )          | (663 | ) | (5,241 | ) | (7,620 | ) |
| Interest and other, net                              |       | —                                                                 |       | — |   | (1,039 | ) | (1,039 | ) |
| **Net loss attributable to common  stockholders**    |       | $                                                                      | (1,716     | ) | $ | (663 | ) | $ | (6,280 | ) | $ | (8,659 | ) |
| ***Identifiable  assets:***                          |       |                                                                   |       |   |   |   |   |   |   |
| Oil and gas properties,  net of DD&A             |       | $                                                                      | 19,746     |   | — |   | — |   | $ | 19,746 |   |
| Property and equipment,  net of DD&A             |       | —                                                                 |       | $ | 6,912 |   | $ | 2,772 |   | $ | 9,684 |   |
| Other non-current  assets, net of amortization       |       | —                                                                 |       | $ | 971 |   | $ | 1,180 |   | $ | 2,151 |   |

 
| ** **                                           | ** ** | **For the Year Ended December 31, 2005** | ** ** |
|------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                           | ** ** | **E & P**                                                | ** ** | **G & P** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| ***(in thousands)***                                 | ** ** | ** **                                                             |       |   |   |   |   |   |   |
| Revenues, net of  production taxes and other         |       | $                                                                      | 51         |   | $ | 2,834 |   | $ | 270 |   | $ | 3,155 |   |
| Operating expense                                    |       | 34                                                                     |       | 1,755 |   | — |   | 1,789 |   |
| Asset impairment charge                              |       | —                                                                 |       | 2,487 |   | — |   | 2,487 |   |
| Exploration expense                                  |       | 450                                                                    |       | — |   | — |   | 450 |   |
| Depreciation,  depletion, amortization and accretion |       | 4                                                                      |       | 1,041 |   | 22 |   | 1,067 |   |
| General and  administrative                          |       | —                                                                 |       | — |   | 2,029 |   | 2,029 |   |
| Operating loss                                       |       | (437                                                                   | )          | (2,449 | ) | (1,781 | ) | (4,667 | ) |
| Interest and other, net                              |       | —                                                                 |       | — |   | 118 |   | 118 |   |
| Cumulative effect of  change in accounting principle |       | —                                                                 |       | (76 | ) | — |   | (76 | ) |
| Net loss                                             |       | (437                                                                   | )          | (2,525 | ) | (1,663 | ) | (4,625 | ) |
| Preferred stock  dividends                           |       | —                                                                 |       | — |   | 204 |   | 204 |   |
| **Net loss attributable to common  stockholders**    |       | $                                                                      | (437       | ) | $ | (2,525 | ) | $ | (1,867 | ) | $ | (4,829 | ) |
| ***Identifiable  assets:***                          |       |                                                                   |       |   |   |   |   |   |   |
| Oil and gas properties,  net of DD&A             |       | $                                                                      | 1,531      |   | — |   | — |   | $ | 1,531 |   |
| Property and equipment,  net of DD&A             |       | —                                                                 |       | $ | 5,856 |   | $ | 168 |   | $ | 6,024 |   |
| Other non-current assets, net of amortization        |       | —                                                                 |       | $ | 1,099 |   | $ | 23 |   | $ | 1,122 |   |

 

**Note15—Related Persons Transactions**

In October 2005, the Company and JMGExploration, Inc. (“JMG”) entered into an agreement whereby the Companywas to build and operate a 32 mile, 8-inch oil and gas pipeline in exchange fora cost-plus compensation arrangement negotiated on an arms length basis. ThomasJ. Jacobsen, Joseph Skeehan and Reuben Sandler served on the Company’s board asdirector and also served on the board of directors of JMG during 2005.  Thomas Jacobsen retired from the Company’sboard on June 14, 2006.  Joseph Skeehanand Rueben Sandler have continued of serve on the Company’s board through 2006and are current Company board members. In January 2006, this project was terminated.  In order to reimburse the Company for itscarrying cost of the pipe, the Company and JMG entered into an agreementwhereby JMG will indemnify the Company for these costs and resale of the pipe.  The interest rate applied was 10% per annumbased on the remaining balance for the pipe that was held in inventory.  As of December 31, 2006, JMG owed the Companyis $107,000 for interest recorded in accounts receivable.  The pipe inventory was sold during 2006 andthe proceeds were received by the Company and credited to the inventoryaccount.

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Susan Wright, ourCorporate Secretary and wife of the CEO, provides Corporate Secretary servicesto us on a contract basis. During the year ended December 31, 2006 and 2005,Mrs. Wright was paid $81,000 and $19,000, respectively, for contractservices.

InFebruary 2006, we issued 40,000 warrants to a former director for servicesrendered in respect to our recent convertible debt offering.  These warrants vested one year from the dateof grant with an exercise price of $7.00 per share.  We recorded $92,000as the estimated fair value of the warrants as deferred debt issuance costs,with a corresponding increase in additional paid-in-capital.

In April 2006, weissued 30,000 warrants to a former director in exchange for expired options forservices rendered.  These warrants vestone year from the date of grant with an exercise price of $5.50 per sharerelated to 20,000 warrants, and $7.50 per share related to 10,000 warrants.  We recorded $70,000 as the estimated fair valueof the warrants as stock-based compensation, with a corresponding increase inadditional paid-in-capital.

One of ourofficers (and director) and three of our directors, in the aggregate, purchased$100,000 and a total of $1.275 million, respectively, of the Notes that wereissued in March 2006.  During the yearended December 31, 2006, the Company has paid interest of $8,472 and $147,194respectively, on these Notes.  In addition,an investment fund, of which one of our former directors is a consultant, purchasedon behalf of it investors, $1 million of the notes.  The investors were paid $86,944 in interestduring the period.

**Note16—Quarterly Financial Information (Unaudited)**
| ** **                                                                     | ** ** | **First**  | ** ** | **Second** | ** ** | **Third**  | ** ** | **Fourth** | ** ** | **Total**  | ** ** |
|--------------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|
| ***(In thousands, except per share data)***           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **2006**                                                                       |       |       |       |       |       |       |       |       |       |       |       |
| Revenue                                                                        |       | $          | 827        |       | $          | 703        |       | $          | 1,098      |       | $          | 1,685 |   | $ | 4,313 |   |
| Operating loss                                                                 |       | $          | (1,273     | )          | $          | (1,478     | )          | $          | (1,731     | )          | $          | (3,138 | ) | $ | (7,620 | ) |
| Net loss                                                                       |       | $          | (1,494     | )          | $          | (1,818     | )          | $          | (1,766     | )          | $          | (3,581 | ) | $ | (8,659 | ) |
| Net loss per  share—basic and diluted                                     |       | $          | (0.20      | )          | $          | (0.24      | )          | $          | (0.24      | )          | $          | (0.48 | ) | $ | (1.16 | ) |
|                                                                           |       |       |       |       |       |       |       |       |       |       |       |
| **2005**                                                                       |       |       |       |       |       |       |       |       |       |       |       |
| Revenue                                                                        |       | $          | 841        |       | $          | 715        |       | $          | 724        |       | $          | 875 |   | $ | 3,155 |   |
| Operating loss                                                                 |       | $          | (189       | )          | $          | (415       | )          | $          | (2,931     | )          | $          | (1,132 | ) | $ | (4,667 | ) |
| Net loss before  cumulative effect of change in accounting principle           |       | $          | (230       | )          | $          | (375       | )          | $          | (2,868     | )          | $          | (1,076 | ) | $ | (4,549 | ) |
| Cumulative effect of  change in accounting principle                           |       | —     |       | —     |       | —     |       | $          | (76        | )          | $          | (76 | ) |
| Net loss                                                                       |       | $          | (230       | )          | $          | (375       | )          | $          | (2,868     | )          | $          | (1,152 | ) | $ | (4,625 | ) |
| Net loss applicable to  common stockholders                                    |       | $          | (412       | )          | $          | (397       | )          | $          | (2,868     | )          | $          | (1,152 | ) | $ | (4,829 | ) |
| Net loss per share  before cumulative effect of change in accounting principle |       | $          | (0.52      | )          | $          | (0.06      | )          | $          | (0.40      | )          | $          | (0.15 | ) | $ | (0.68 | ) |
| Cumulative effect of  change in accounting principle per share of common stock |       | (0.00      | )          | (0.00      | )          | (0.00      | )          | (0.01      | )          | (0.01      | )          |
| Net loss per  share—basic and diluted                                     |       | $          | (0.52      | )          | $          | (0.06      | )          | $          | (0.40      | )          | $          | (0.16 | ) | $ | (0.69 | ) |
|                                                                           |       |       |       |       |       |       |       |       |       |       |       |
| **2004**                                                                       |       |       |       |       |       |       |       |       |       |       |       |
| Revenue                                                                        |       | $          | 399        |       | $          | 343        |       | $          | 841        |       | $          | 949 |   | $ | 2,532 |   |
| Operating income (loss)                                                        |       | $          | 8          |       | $          | (135       | )          | $          | (3         | )          | $          | (492 | ) | $ | (622 | ) |
| Net income (loss)                                                              |       | $          | 11         |       | $          | (126       | )          | $          | 13         |       | $          | (549 | ) | $ | (651 | ) |
| Net loss applicable to  common stockholders                                    |       | $          | (93        | )          | $          | (280       | )          | $          | (170       | )          | $          | (1,320 | ) | $ | (1,863 | ) |
| Net loss per share—basic and diluted                                      |       | $          | (0.06      | )          | $          | (0.17      | )          | $          | (0.11      | )          | $          | (1.65 | ) | $ | (1.33 | ) |

 

During the fourthquarter of 2006, the Company recorded an impairment charge of $790,000 relatedto the shut-in of Reno/Dilts field operations in February 2007 due touneconomical performance.  Also, duringthe last two quarters of 2006, increased E&P activities from acquisitionsof gas properties resulted in higher G&A expenses for added personnel costsand benefits, plus additive DD&A charges and operating costs of theacquired producing properties.

During the thirdquarter of 2005, the Company recorded an estimated impairment charge in respectto its TOP gas gathering system of $2.372 million, and during the fourthquarter of 2005 recorded an additional $115,000 in respect to this impairment.See Note 5—Property, Equipment and Contracts. During the fourth quarter of 2005the Company recorded a $76,000 cumulative effect of change in accountingprinciple. See Note 7—Asset Retirement Obligations.

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**Note17—Subsequent Events**

***Capital Lease***

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

The lease meets the criteria under Statement of Financial AccountingStandards 13, Accounting for Leases, for classification as a capital lease onthe balance sheet of the Registrant.  Asa result, it is anticipated that a capital lease asset of approximately$3,000,000, which represents the estimated fair value of the property, will berecorded, as well as the related liability. In addition, a cash payment of $650,000 was made by the Company to J-Wfor future maintenance repairs in connection with the lease.  The capital lease and prepayment will beamortized as expenses over the term of the lease.  Monthly lease payments ranging from $100,000to $150,000 will reduce the liability and also will include interest andexecutory (sales tax and environmental fees) expenses.

***Registration of Additional Shares of PRB Energy, Inc. CommonStock***

In connection withour issuance of 1,250,000 shares of common stock to two private lenders, theCompany entered into a registration rights agreement (“RRA”).  Pursuant to that agreement, if we failto:  (i) have the registration statementdeclared effective by the SEC on or before the date that is 150 days afterDecember 28, 2006 (an “Effectiveness Failure”) or (ii) maintain theeffectiveness of this registration statement while shares of common stockcovered by the RRA remain unsold (a “Maintenance Failure”), then, unless thegrace periods set forth in the RRA apply, as partial relief for the damages toany holder by any such delay in or reduction of its ability to sell the sharesof common stock, the Company must pay to each holder an amount in cash equal to1% of the aggregate purchase price (as such term is defined in the securitiespurchase agreement for the Debentures) allocable to such holder’s securitiesincluded in this prospectus on each of the following dates:  (i) the day of an Effectiveness Failure andon every 30th day thereafter until such Maintenance Failure is cured; and (ii)the initial day of a Maintenance Failure and on every 30th day thereafter untilsuch Maintenance Failure is cured.  Ifthe Company fails to make these registration delay payments in a timely manner,the registration delay payments will bear interest at the rate of 2% per monthuntil paid in full.  The aggregate amountof registration delay payments may not exceed $750,000.  The Company filed the registration statementon Form S-3 with the SEC on February 2, 2007.

 

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