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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the transition period from                to               

Commission file number:  001-32471

BLACK RAVEN ENERGY, INC.

(Exact Name of Registrant as Specified in Its Charter)

Registrant’s Telephone Number, including area code:  (303) 308-1330

PRB Energy, Inc.

1875 Lawrence Street, Suite 450

Denver, CO 80202

(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)

Securities registered pursuant to Section 12(b) of the Act:  None.

Securities registered pursuant to Section 12(g) of the Act:

Common Stock, $.001 par value

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o   No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

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

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

                        The aggregate market value of the registrant’s common stock held by non-affiliates of the registrant as of June 30, 2008 was approximately $43,610 computed by reference to the closing price of the registrant’s common stock on June 30, 2008.  For purposes of the calculation of aggregate market value of the registrant’s common stock, all common stock of the registrant was deemed to be held by non-affiliates.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes o  No x

As of December 31, 2008, the registrant had 7,802,094 shares of common stock outstanding, which is net of 919,900 treasury shares held by the Company.

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Explanatory Note

This Annual Report on Form 10-K for the fiscal year ended December 31, 2008 (the “Annual Report”) is being filed by Black Raven Energy, Inc. (the “Company”) in order to become current in its filing obligations under the Securities Act of 1934, as amended.  In addition to this Annual Report, the Company simultaneously filed the following delinquent periodic reports with the Securities and Exchange Commission (“SEC”):

·      Annual Report on Form 10-K for the year ended December 31, 2007; and

·      Quarterly Report on Form 10-Q for the quarter ended September 30, 2009.

This Annual Report should be read together and in connection with the other reports filed with the SEC for a comprehensive description of the Company’s current financial condition and operating results.  In the interest of complete and accurate disclosure, the Company has included current information in this Annual Report and each of the reports listed above for all material events and developments that have taken place through the date of filing of this Annual Report with the SEC.

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Cautionary Note Regarding Forward-Looking Statements

We may from time-to-time make statements that are “forward-looking,” including statements contained in this Annual Report on Form 10-K and other filings with the Securities and Exchange Commission (the “SEC”) and in reports to our shareholders.  Such statements may, for example, express expectations or projections about future actions that we may take or about developments beyond our control including changes in domestic or global economic conditions.  These statements are made on the basis of our management’s views and assumptions as of the time the statements are made and we undertake no obligation to update these statements.  Our actual results may differ significantly from the results discussed in the forward-looking statements.  General factors that might cause such differences include, but are not limited to:

For more information on these and other risk factors that may affect our business, refer to Item 1A “Risk Factors” included in this Annual Report.

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PART I

ITEM 1.              BUSINESS.

Chapter 11 Bankruptcy Filing

On March 5, 2008, PRB Energy, Inc. (“PRB Energy”) and its subsidiaries filed a voluntary petitions for relief for each business entity (“the Chapter 11 Bankruptcy”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Colorado (the “Bankruptcy Court”).  PRB Energy continued to operate its business as a “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.  Due to economic and personnel constraints, PRB Energy was unable to file its annual and quarterly reports with the SEC during its bankruptcy proceedings.  As a result, trading of PRB Energy’s common stock on the American Stock Exchange was suspended and its common stock was delisted from the American Stock Exchange effective April 28, 2008.

On January 16, 2009, the Bankruptcy Court entered an order confirming PRB Energy’s and PRB Oil and Gas, Inc.’s (“PRB Oil”) Modified Second Amended Joint Plan of Reorganization (the “Plan”).  The effective date of the Plan was February 2, 2009 (the “Effective Date”).  Pursuant to the Plan, all 8,721,994 shares of PRB Energy’s outstanding common stock were cancelled and PRB Energy changed its corporate name to Black Raven Energy, Inc (“Black Raven,” “the Company,” “us,” “our” or “we”).  The Plan provided that we continue as a public company following our emergence from bankruptcy and for the issuance of new common stock of Black Raven (“New Common Stock”) to certain claimants, with such New Common Stock to be traded on the OTC Bulletin Board or a nationally recognized securities exchange, subject to compliance with applicable regulations.  After the Effective Date of the Plan, we issued the following securities in accordance with the Plan:

PRB Gathering, Inc. (“PRB Gathering”) remains in Chapter 11 Bankruptcy.  The summary of the Plan is qualified in its entirety by reference to the full text of the Plan filed with the SEC on January 16, 2009 as Exhibit 99.1 to our Current Report on Form 8-K.

On February 2, 2009, in connection with the consummation of the Plan, we, along with our subsidiary PRB Oil, entered into a Limited Waiver, Consent, and Modification Agreement (the “Modification Agreement”) with WCOF.  Under the Modification Agreement, we issued an Amended and Restated Senior Secured Debenture (the “Amended Debenture”), payable to WCOF in the amount of $18,450,000.  The Amended Debenture superseded and amended the senior secured debentures issued by PRB Oil to WCOF and DKR Soundshore Oasis Holding Fund Ltd. on December 28, 2006.  Under the terms of the Amended Debenture, $3.75 million of the outstanding principal balance and unpaid accrued interest are due on December 31, 2009, with the remainder of the outstanding balance and unpaid accrued interest due on December 31, 2010.  The Amended Debenture accrues interest at 10% per annum payable quarterly.  The summary of the Modification Agreement and the Amended Debenture is qualified in its entirety by reference to the full text of these documents, which were filed on February 6, 2009 as Exhibits 10.1 and 4.1, respectively, to our Current Report on Form 8-K.

On the Effective Date, as required by the Plan, William F. Hayworth, Gus J. Blass III and Atticus Lowe were appointed as members of our Board of Directors (the “Board”).  Mr. Hayworth was also appointed to serve as our President and Chief Executive Officer.

On the Effective Date, Amended and Restated Articles of Incorporation (the “Articles”) were filed with the Nevada Secretary of State to change our corporate name to Black Raven Energy, Inc. and we adopted Amended and Restated Bylaws (the “Bylaws”).  Subsequently, PRB Oil was merged into the Company.  The full text of the Articles and Amended Bylaws were filed on February 2, 2009 as Exhibits 3.1 and 3.2, respectively, to our Current Report on Form 8-K.

Effective April 13, 2009, Black Raven, WCOF and the Official Committee of Unsecured Creditors Appointed by the Bankruptcy Court entered into an Agreement Regarding New Equity Raise Under the Modified Second Amended Joint Plan of Reorganization (the “New Equity Agreement”).  The New Equity Agreement modified the obligations of the parties under the Plan and released WCOF from its obligation to raise or guarantee $7.5 million of additional funding for us.  The New Equity Agreement required WCOF to purchase 166,667 shares of the New Common Stock from us for $3.00 per share within 10 business days of the New Equity Agreement and an additional $3 million of New Common Stock, preferred stock or convertible debt securities from time to time prior

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to September 10, 2010, at a purchase price of $2.00 per share.  The New Equity Agreement also modified the interest rate under the Amended Debenture and extended the maturity date of the Amended Debenture to December 31, 2011.  The summary of the New Equity Agreement is qualified in its entirety by reference to the full text of the Plan filed with the SEC on May 1, 2009 as Exhibit 10.1 to our Current Report on Form 8-K.

On April 23, 2009, we entered into a Securities Purchase Agreement with WCOF relating to the sale of 166,667 shares of our common stock to WCOF for an aggregate purchase price of $500,000.  The full text of the Securities Purchase Agreement was filed on May 1, 2009 as Exhibit 10.2 to our Current Report on Form 8-K.

On June 3, 2009, the Board adopted the Black Raven Energy, Inc. Equity Compensation Plan (the “Equity Compensation Plan”) under which we may grant nonqualified stock options, stock appreciation rights, stock awards or other equity-based awards to certain of our employees, consultants, advisors and non-employee directors.  The Board initially reserved 3,791,666 shares of common stock for issuance under the Equity Compensation Plan.

On July 8, 2009, the Board appointed Dan Frederickson as a member of the Board and Tom Riley as Chairman and Chief Executive Officer, subject to the execution of employment agreements.  Concurrently, William F. Hayworth resigned as Chief Executive Officer but retained the position as President and a member of the Board.

On July 9, 2009, we entered into a Securities Purchase Agreement with WCOF relating to the sale of 500,000 shares of our common stock to WCOF for an aggregate purchase price of $1 million.

On August 27, 2009, we entered into a Securities Purchase Agreement with WCOF for the sale of 250,000 shares of our common stock to WCOF for an aggregate purchase price of $500,000.

On September 16, 2009, Black Raven and WCOF entered into a Securities Purchase Agreement for the sale of 750,000 shares of Black Raven common stock to WCOF for an aggregate purchase price of $1,500,000.

Description of Business

Black Raven, formerly known as PRB Energy, Inc. operates as an independent energy company engaged in the acquisition, exploitation, development and production of natural gas and oil in the Rocky Mountain Region of the United States.  During 2008, we also provided gas gathering and compression services for properties we operated and for third-party producers. We were initially incorporated in Nevada under the name “PRB Transportation, Inc.” in December 2003.  On June 14, 2006, we changed our name to “PRB Energy, Inc.” On February 2, 2009, in connection with our emergence from bankruptcy, PRB Energy changed its corporate name to Black Raven Energy, Inc.

Throughout 2007 and into 2008 we operated as two business segments through two wholly-owned subsidiaries, PRB Oil, a gas and oil exploitation and production company (“E&P”) incorporated in Colorado in July 2005, and PRB Gathering, a gathering and processing company (“G&P”) incorporated in Colorado in August 2006. During 2008, we owned and operated the assets listed below through the two subsidiaries.   As of the date of filing of this Annual Report, PRB Gathering remains in Chapter 11 Bankruptcy and we currently only operate our gas exploitation and production business segment.  During the pendency of our Chapter 11 Bankruptcy from March 5, 2008 through February 2, 2009, we sold our Antelope Valley and South Kitty Pipeline, our GAP/Bonepile Gathering System and Coal Bed Methane Fields.  The status of our assets at December 31, 2008 is outlined below.  A more thorough description of the properties is presented in Item 2 of this Annual Report.

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The Company sells gas and natural gas liquids to pipelines, refineries and oil companies.  Revenues from two customers represented 10% or more of the Company’s sales for the year ended December 31, 2008.  We do not believe that the loss of any one customer would have a significant impact on our financial results.

Competition

Our gas exploitation activities take place in a highly competitive and speculative business atmosphere.  As an independent producer, we have little control over the price we receive for our natural gas.  As such, higher costs, fees and taxes assessed at the producer level cannot necessarily be passed on to our customers.  In seeking suitable oil and gas properties for development or acquisition, we compete with a number of other companies, including large oil and gas companies and other independent operators with greater financial resources.  In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Environmental Regulation

Federal, state and local authorities extensively regulate the energy industry.  Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may affect, among other things, the pricing or marketing of gas production.  Noncompliance with statutes and regulations may lead to substantial penalties and the overall regulatory burden on the industry increases the cost of doing business and, in turn, decreases profitability.

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

The ongoing operations of the Company are subject to the Clean Water Act, the Clean Air Act, and other environmental regulations adopted by federal, state and local governmental authorities in jurisdictions where we are engaged in development or production operations.  New laws or regulations, or changes to current requirements, could result in material costs or claims with respect to properties we own or have owned.  We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies.  We could face significant liabilities to governmental authorities and third parties for discharges of oil, natural gas or other pollutants into the air, soil or water, and we could have to spend substantial amounts on investigations, litigation and remediation.  Existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced or altered in the future, may have a material adverse effect on us.

We have reflected in our consolidated financial statements a reserve for future capital expenditures for remediation costs at the end of the life of the wells.  Refer to “Note 6 — Asset Retirement Obligations” to our consolidated financial statements in Item 8 of this Annual Report.

Employees

As of December 31, 2008, we had six full-time employees.

ITEM 1A.                 RISK FACTORS.

You should carefully consider the following risks and other information contained in this report.  These risks could materially affect our business, results of operations or financial condition and cause the trading price of our common stock to decline.  The risks and uncertainties described below are not the only risks facing us.  If any of the following risks or uncertainties actually occurs, our business, financial condition and results of operations could be adversely affected.

Risks Related to the Natural Gas Industry and Our Business

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

Our revenues, operating results, profitability, future rate of growth and the carrying value of our gas properties depend heavily on the prices we receive from natural gas sales.  Gas prices also affect our cash flows and borrowing base, as well as the amount and value of our gas reserves.

Historically, the markets for gas have been volatile and they are likely to continue to be volatile.  Wide fluctuations in gas prices may result from relatively minor changes in the supply of and demand for gas, market uncertainty and other factors that are beyond our control, including:

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These factors and the volatility of gas markets make it very difficult to predict future gas price movements with any certainty.  Declines in gas prices would reduce our revenues and could also reduce the amount of gas that we can produce economically and therefore could have a material adverse effect on us.

The guarantee of certain indebtedness, and the covenants in the agreements governing that debt, could negatively impact our financial condition, results of operations and business prospects.

We guaranteed payment of the Amended Debenture and pledged substantially all of our assets as collateral.  If we fail to comply with the covenants and other restrictions in the agreements governing the Amended Debenture, an event of default could occur that would permit the lenders to foreclose on substantially all of our assets.  Our ability to comply with these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions.  If we are required but unable to make the guaranteed payments under the Amended Debenture out of cash on hand or from internal cash flow, we could attempt to refinance the Amended Debenture, sell assets, or repay the Amended Debenture with the proceeds from an equity or debt offering.  However, we may not be able to raise sufficient capital through the sale of assets or issuance of equity or debt to pay or refinance the amounts owed.  Factors that will affect our ability to raise cash through a sale of assets or a debt or equity offering include financial market conditions and our market value and operating performance at the time of such offering or other financing.  We may, therefore, not be able to successfully complete any such offering or sale of assets.

Our development operations require substantial capital and we 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 natural gas reserves.

The energy industry is capital intensive.  We make and expect to continue to make substantial capital expenditures in our business and operations for development, production and acquisition of oil and natural gas reserves.  To date, we have financed capital expenditures primarily with proceeds from the issuance of debt and equity plus cash generated by operations.  We intend to finance our future capital expenditures with cash flow from operations and from debt or equity capital.  Our cash flow from operations and access to capital is subject to a number of variables, including:

If our revenues decrease as a result of lower natural gas prices, operating difficulties, declines in reserves or for any other reason, then we may have limited ability to obtain the capital necessary to sustain our operations at current levels.  We may, from time to time, need to seek additional financing.  There can be no assurance as to the availability or terms of any additional financing.

If additional capital is needed, then we may not be able to obtain debt or equity financing on terms favorable to us, or at all.  If cash generated by operations is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a possible disposition of properties and a decline in our reserves.

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

Our future operations depend on our ability to find, develop and acquire oil and gas reserves that are economically recoverable.  Our properties produce gas at a declining rate over time.  In order to become profitable, we must develop our properties or locate and acquire new oil and gas reserves to replace those being depleted by production.  We may do this even during periods of low oil and gas prices.  Competition for the acquisition of producing oil and gas properties is intense and many of our competitors have financial and other resources for acquisitions that are substantially greater than those available to us.  Therefore, we may not be able to acquire oil and gas properties that contain economically recoverable reserves, or we may not be able to acquire such properties at prices

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acceptable to us.  Without successful drilling or acquisition activities, our reserves, production and revenues will decline.

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

Our business strategy includes an acquisition program.  The successful acquisition of producing oil and gas properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including the following:

·                  the amount of recoverable reserves;

·                  future oil and natural gas prices;

·                  estimates of operating costs;

·                  estimates of future development costs;

·                  estimates of the costs and timing of plugging and abandonment; and

·                  potential environmental and other liabilities.

Our assessment will not reveal all existing or potential problems, and may not permit us to become familiar enough with the properties to fully assess their capabilities and deficiencies.  In the course of our due diligence, we may not inspect every well or pipeline.  Inspections may not reveal structural and environmental problems, such as pipeline corrosion or groundwater contamination, when they are made.  We may not be able to obtain contractual indemnities from the seller for liabilities that it created.  We may be required to assume the environmental and production risks associated with the properties.

The Amended Debenture contains various covenants limiting the discretion of our management in operating our business.

The Amended Debenture contains various restrictive covenants.  In particular, these covenants limit our ability, without lenders’ approval, to, among other things:

·                  pay dividends on, redeem or repurchase our capital stock;

·                  make loans to others;

·                  incur additional indebtedness or issue preferred stock;

·                  create certain liens; and

·                  purchase or sell assets.

If we fail to comply with the restrictions of the Amended Debenture, an event of default may allow the creditors to foreclose on substantially all of our assets.  Any such default or foreclosure could have a material adverse effect on us.

The continuing crisis in the financial and credit markets, and volatility in oil and natural gas prices may affect our ability to obtain funding or to obtain funding on acceptable terms. These factors may hinder or prevent us from meeting our future capital needs and/or continuing to meet our obligations and conduct our business.

Global financial markets and economic conditions have recently been, and continue to be, disrupted and volatile. The debt and equity capital markets have become exceedingly distressed. These issues, along with significant asset write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions, have made, and will likely continue to make, it difficult to obtain debt or equity capital funding.

Due to these factors, there can be no assurance that funding will be available to us, if needed, and to the extent required, on acceptable terms. If funding is not available as needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities, or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues, results of operations, financial position and cash flows.

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

Drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas will be found.  The cost of drilling and completing wells is often uncertain, and oil and gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control.  These factors include:

·                  unexpected drilling conditions;

·                  title problems;

·                  pressure or irregularities in formations;

·                  equipment failures or accidents;

·                  adverse weather conditions;

·                  compliance with environmental and other governmental requirements;

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

·                  shortages or delays in the availability of or increases in the cost of drilling rigs and the delivery of equipment;

·                  lack of availability of experienced drilling crews; and

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·                  lack of pipeline availability or pipeline capacity.

The wells we drill may not be productive and we may not recover all or any portion of our investment in such wells.  The seismic data and other technologies that we use do not allow us to know conclusively prior to drilling a well that oil or gas is present or may be produced economically.  The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project.  Drilling activities can result in dry holes or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover initial drilling costs.

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

The occurrence of any or all 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 to interpretation and may not accurately identify the presence of natural gas which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures.

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

Our operations are focused on the Rocky Mountain region, which means our producing properties are geographically located in the states of Wyoming, Colorado and Nebraska.  As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these areas caused by significant governmental regulation, transportation capacity constraints, curtailment of production or interruption of transportation of natural gas produced from the wells in these basins.

Our operations are subject to operational hazards and unforeseen interruptions for which we may be inadequately insured, resulting in losses to us.

Our operations, including gathering, processing, exploitation and production, are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures and other events beyond our control.  These events might result in a loss of equipment or life, injury or extensive property damage, as well as an interruption in our operations.  We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates.  In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage.  A significant liability for which we were not fully insured could adversely affect us.

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

Federal, state and local authorities extensively regulate the energy industry.  Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may affect, among other things, the pricing or marketing of gas production.  Noncompliance with statutes and regulations may lead to substantial penalties, and the overall regulatory burden on the industry increases the cost of doing business and, in turn, decreases profitability.

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

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

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

We follow the successful efforts method of accounting for our oil and gas properties.  All property acquisition costs and costs of development wells are capitalized when incurred, pending the determination of whether proved reserves have been discovered.

The capitalized costs of our oil and gas properties, on a field basis, cannot exceed the estimated future net cash flows of that field. 

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If net capitalized costs exceed future net revenues, we must write-down the costs of each such field to our estimate of fair market value.  Accordingly, a significant decline in oil or gas prices or unsuccessful development efforts could cause a future write-down of capitalized costs, reducing our assets and net worth.

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

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

We face intense competition from major oil companies, independent oil and gas exploration and production companies, financial buyers and institutional and individual investors who are actively seeking oil and gas properties in the Rocky Mountain region in which we operate and elsewhere.  Many of our competitors have financial and technical resources along with equipment, expertise, labor and materials significantly exceeding those available to us.  In addition, many properties are sold in a competitive bidding process in which our competitors may be able to pay more for development prospects and productive properties, or in which our competitors have technological information or expertise to evaluate and successfully bid for the properties that is not available to us.  Shortages of equipment, labor or materials as a result of intense competition may result in increased costs or the inability to obtain those resources as needed.  We, therefore, may not be successful in acquiring and developing profitable properties in the face of this competition.

Substantial acquisitions or other transactions could require significant external capital and could change our risk and property profile.

In order to finance acquisitions of additional producing properties, we may need to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments or other means.  These changes in capitalization may significantly affect our risk profile.  Additionally, significant acquisitions or other transactions could change the character of our operations and business.  The character of the new properties could be substantially different in operating or geological characteristics or geographic location than our existing properties.  Furthermore, we may not be able to obtain external funding for future acquisitions or other transactions or to obtain external funding on terms acceptable to us.

We depend on our chief executive officer and other officers for critical management decisions and industry contacts.

We have a small management team and have employment agreements with our chief executive officer and other executive officers.  We also do not carry key person insurance on their lives.  The loss of the services of our executive officers, through incapacity or otherwise, could have a material adverse effect on our operations and would require us to seek and retain other qualified personnel.

If we are unable to successfully recruit qualified managerial and field personnel having experience in oil and gas exploration, we may not be able to continue our operations.

In order to successfully implement and manage our business plan, we will depend upon, among other things, successfully recruiting qualified managerial and field personnel having experience in the oil and gas exploration business. Competition for qualified individuals is intense. We may not be able to find, attract and retain qualified personnel on acceptable terms. If we are unable to find, attract and retain qualified personnel with technical expertise, our business operations could suffer.

Our business could be adversely impacted if we have deficiencies in our disclosure controls and procedures or internal control over financial reporting.

Our management is required to provide a report on our internal controls over financial reporting including an assessment of the effectiveness of these controls to provide reasonable assurance a material misstatement did not occur in our financial statements.  While our management continues to review the effectiveness of our disclosure controls and procedures and internal control over financial reporting, we cannot assure you that our disclosure controls and procedures or internal control over financial reporting will be effective in accomplishing all control objectives all of the time.  As of December 31, 2008, our internal control over financial reporting and disclosure controls and procedures were not effective due to our failure to timely file periodic reports with the SEC as a result of our lack of capital resources and lack of internal financial and accounting personnel.  We are currently working to remediate these control deficiencies.  Our failure to remediate these control deficiencies and other future material weaknesses or control deficiencies, or to establish and maintain effective systems of internal control over financial reporting and disclosure controls and procedures, may impair our ability to accurately report our financial results and prevent fraud. This failure may result in a restatement of our financial statements and may cause investors to lose confidence in our reported financial information, which could have a material adverse effect on our business, operating results, stock price and reputation, and may increase the cost of any financing we obtain.

Many of these factors are beyond our control, and we cannot predict their potential effects on the price of our common stock. We cannot assure you that the market price of our common stock will not fluctuate or decline significantly in the future. In addition, the stock markets in general can experience considerable price and volume fluctuations.

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Risks Related to our Emergence from Bankruptcy

We have limited operating history since emerging from bankruptcy.

Since emerging from bankruptcy on February 2, 2009, we have not generated significant revenues from operations and we have limited resources.  Any operating losses, together with risks associated with our ability to be competitive in the natural gas industry may have a material adverse affect on our liquidity.  An investor in our common stock must evaluate the risks, uncertainties, and difficulties encountered by a company emerging from Chapter 11 bankruptcy.  There can be no assurance that we will generate sufficient revenues to maintain our business operations.

Recent adverse publicity concerning our Chapter 11 Bankruptcy may harm our ability to compete in a highly competitive environment.

Recent adverse publicity concerning our financial condition may harm our ability to attract new customers and to maintain favorable relationships with existing customers, suppliers and partners.  Any such adverse affect could materially impact our ability to continue our operations.

Risks Related to our Common Stock

We are not current in our reporting obligations with the SEC and our status as a public company could be revoked at any time.

We are not current in our filing obligations with the SEC.  While we are putting forth our best efforts to file all delinquent reports with the SEC, if we are unable to complete those filings before the SEC seeks to bring an administrative action against us, it is likely that we would cease being a public company.  In that event, the liquidity of our common stock would be severely diminished and our ability to continue our operations could be materially affected.

West Coast Opportunity Fund, LLC owns a significant percentage of our Company and can exercise significant influence over us.

As of our emergence from Chapter 11 Bankruptcy on February 2, 2009, WCOF owned approximately 90% of the outstanding shares of our common stock.  Through the purchase of additional shares in 2009, WCOF owned 91% of the outstanding shares of our common stock as of December 31, 2009.  So long as WCOF controls a majority of our outstanding equity, WCOF will continue to have the ability to control any matters submitted for shareholder approval such as mergers, sales of all or substantially all of our assets, amendments to our articles of incorporation, and other corporate matters.  This concentration of ownership by WCOF may discourage additional investors in the Company or prevent us from undergoing a change of control in the future that would otherwise be beneficial to shareholders.

No established trading market exists for the common stock we issued upon our emergence from bankruptcy, and if one develops, it may not be liquid.

No established trading market exists for the common stock we issued upon our emergence from bankruptcy, and there is no assurance that any active trading market will develop in the future.  There is no assurance that any national securities exchange will approve our new common stock for listing as there is no assurance that we will satisfy the criteria for listing, or be approved for listing on such exchange. Absent an active public market for our common stock, an investment in our shares should be considered illiquid.  There is no assurance that a sufficient market will develop in our stock, in which case it could be difficult for our stockholders to sell their shares.

Trading of our stock may be restricted by the SEC’s penny stock regulations, which may limit a stockholder’s ability to buy and sell our common stock.

The SEC has adopted regulations which generally define “penny stock” to be any equity security that has a market price (as defined) less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions.  Our securities may be covered by the penny stock rules, which impose additional sales practice requirements on broker-dealers who sell to persons other than established customers and “accredited investors”.  The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document in a form prepared by the SEC, which provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and its salesperson in the transaction and monthly account statements showing the market value of each penny stock held in the customer’s account. The bid and offer quotations, and the broker-dealer and salesperson compensation information, must be given to the customer orally or in writing prior to effecting the transaction and must be given to the customer in writing before or with the customer’s confirmation. In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from these rules, the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser’s written agreement to the transaction. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for the stock that is subject to these penny stock rules. Consequently, these penny stock rules may affect the ability of broker-dealers to trade our securities, which ultimately may affect the liquidity of our securities.

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The FINRA sales practice requirements may also limit a stockholder’s ability to buy and sell our stock.

In addition to the “penny stock” rules described above, Financial Industry Regulatory Authority or FINRA has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. The FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.

Our stock price and trading volume may be volatile, which could result in losses for our stockholders.

Even if a market for our common stock is established, the price of our common stock may be volatile.  The equity trading markets have experienced and may experience periods of volatility, which could result in highly variable and unpredictable pricing of equity securities. The market price of our common stock could change in ways that may or may not be related to our business, our industry or our operating performance and financial condition. In addition, the trading volume in our common stock may fluctuate and cause significant price variations to occur. Some of the factors that could negatively affect our share price or result in fluctuations in the price or trading volume of our common stock include:

·                  actual or anticipated quarterly variations in our operating results;

·                  changes in expectations as to our future financial performance or changes in financial estimates, if any, of public market analysts;

·                  announcements relating to our business or the business of our competitors;

·                  conditions generally affecting the oil and natural gas industry, including economic or other conditions that affect the demand for oil and natural gas;

·                  the success of our operating strategy; and

·                  the operating and stock price performance of other comparable companies.

ITEM 1B.       UNRESOLVED STAFF COMMENTS.

Not applicable.

ITEM 2.              PROPERTIES.

Description of Properties

Powder River Basin  - CBM

GAP and Bonepile Fields - The Company operated coal bed methane properties namely the GAP and Bonepile Fields, which were purchased from Marathon Oil Company in 2006.  Due to low gas prices in 2007, the fields were uneconomic to operate and shut in on December 1, 2007.  While in Chapter 11, these assets were sold to WYTEX Ventures effective May 23, 2008.

Homestead Draw Field - In 2006, the Company obtained approximately a 9.0% non-operated working interest in the Homestead Draw CBM Field in Campbell County, Wyoming.  This field produces from multiple coal beds.  We continue to hold a working interest position in this property.

D-J Basin-Niobrara Formation

In December 2006, we purchased approximately 385,000 acres and 13 wells in eastern Colorado and western Nebraska, which were drilled to the Niobrara. In 1972, Mountain Petroleum, Inc. completed five commercial Niobrara wells in Beecher Island Field.  From 1975 to 1982, an additional 46 fields were discovered in Colorado, northwestern Kansas, and southwestern Nebraska.  Recent activity in the area by Noble Energy, Petroleum Development Corp. and others have included amassing large acreage blocks, performing extensive seismic evaluations and initiating drilling programs.

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

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In 2007, we drilled twelve wells to the Niobrara.  Eleven wells intercepted a productive section of the Niobrara. We continue to hold our position in the Niobrara and remain the operator of the existing production.

Recluse Gathering Systems

In 2006, we made three acquisitions that were combined into our Recluse Gathering System.  The system included two compressor stations, with interconnects with two major transportation lines and 74.5 miles of steel pipelines.

NESH Compressor Stations.  We purchased the NESH Compressor Stations from Storm Cat Energy Corporation (“Storm Cat”) on January 18, 2006.  The assets included two compressor stations and two miles of 12-inch poly pipe connecting the stations on the low pressure side.  The stations included piping, scrubbers, tanks, and compressor buildings.  The leases on the stations were assigned to us by Storm Cat.

High Pressure Discharge Lines.  We purchased high pressure discharge lines from Clear Creek Natural Gas, LLC on March 1, 2006.  The assets include 4.5 miles of 8-inch steel pipe, 2 miles of 6-inch steel pipe, meter stations at both compressor stations, and an interconnect with Thundercreek, one of the major transportation lines in the area.

Maverick Pipelines.  We purchased approximately 70 miles of 6-inch steel pipeline from Maverick Pipeline, LLC.  Seven miles of this oil gathering systems has been converted to gas service and we were assigned a gathering contract associated with this line.  We also acquired an interconnect with Williston Basin Interstate Pipeline Company.

The Recluse Gathering System was an asset of PRB Gathering, Inc., which remains in Chapter 11 Bankruptcy.  Effective November 1, 2008, control of the Recluse Gathering System was turned over to a receiver appointed by the State Court of Wyoming.

South Gillette (Formerly Known as Bear Paw) Gathering Systems

Effective August 1, 2004, we acquired certain gathering systems and related contracts from Bear Paw Energy located in Campbell County, Wyoming. The South Gillette Gathering Systems included the following: (1) the Gap gas gathering system, (2) the Bonepile gas gathering system, (3) the Antelope Valley delivery line, and (4) the South Kitty delivery line.  In 2008, during the pendency of our Chapter 11 Bankruptcy, the South Gillette Gathering Systems were sold to WYTEX Ventures, Inc.

Reserves

We engaged independent geological and petroleum engineering consultants MHA (“MHA”) in 2008 to estimate our natural gas reserves.  In 2007, we engaged Netherland, Sewell & Associates, Inc. (“NSAI”), also an independent geological and petroleum engineering consultant, to estimate our natural gas reserves. We reviewed the calculations and assumptions these consultants use to calculate our reserves.  We emphasize that reserve estimates are imprecise by their nature, and that reserve estimates on new discoveries and developments are less precise than reserve estimates for existing fields.  Accordingly, we expect these estimates to change as time passes and information as to actual well performance can be included in those future estimates.

Proved oil and gas reserves are estimates of recoverable quantities of oil, natural gas and natural gas liquids that are determined using engineering and geological data with reasonable certainty.  The reserve estimates are based on existing economic and operating conditions and include only existing wells from known reservoirs with existing equipment and technology.  As of December 31, 2007 our proved reserves were located in the Powder River Basin area of Wyoming and the D-J Basin in northeastern Colorado and southwestern Nebraska.  The Powder River Basin area was sold in 2008.

The following table summarizes our proved reserves data at December 31, 2008 and December 31, 2007, respectively:

(1)  Million Cubic Feet (“MMcf”)

Our year-end report of December 31, 2008 prepared by MHA calculated estimated proved reserves and future revenues by using the weighted average price for total proved reserves of $4.66 per thousand cubic feet (“Mcf”) (or approximately $5.48 per MMBtu based on an 85% average conversion factor for these properties).

Gas Sales

The following table summarizes the volumes sold and realized prices from our properties during the years ended December 31,

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2008 and December 31, 2007 respectively.  All items listed below are based on gas sales volume (Mcf).  Therefore, these values are net numbers where fuel, lost and unaccounted for gas, and metering variances have been removed prior to the calculation.

(1)   Net gas sales represent that portion of gas sold that is owned by us and produced to our ownership interest.

Productive Wells

As of December 31, 2008 and December 31, 2007, we had working interests in 59 productive wells (27 wells net) and 508 productive wells (391 wells net) respectively. Productive wells are either producing or capable of producing although shut-in or de-watering.  Gross wells represent the total number of wells in which we have a working interest.  Net wells represent the number of gross wells multiplied by the percentages of the working interests owned by us.  One or more completions in the same bore hole are counted as one well.

Drilling Activity

During 2008, the Company did not drill any wells.  During 2007, we drilled 12 total wells, 11 wells of which were retained as producers. All of our drilling activity is performed by independent drilling contractors.  The following table sets forth certain information regarding numbers of wells in our drilling activities for the periods indicated:

Gross represents wells in which we have a working interest; Net represents our aggregate working interests in the gross wells.

Acreage

The following table details the gross and net acres of developed and undeveloped properties that we hold. As of December 31, 2008, our properties accounted for the following developed and undeveloped acres:

Gross represents acres in which we have a working interest; Net represents our aggregate working interests in the gross acres.

During 2008, expired undeveloped leases  in Colorado resulted in an abandonment expense of approximately $3.9 million.

Office Facilities

We currently lease office space for our corporate headquarters at 1125 Seventeenth Street, Denver, Colorado 80202.

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ITEM 3.  LEGAL PROCEEDINGS.

On March 5, 2008, PRB Energy and its subsidiaries filed voluntary petitions for relief for each business entity under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Colorado.  On January 16, 2009, the Bankruptcy Court entered an order confirming PRB Energy’s and PRB Oil’s Modified Second Amended Joint Plan of Reorganization.  On February 2, 2009, PRB Energy and PRB Oil emerged from bankruptcy and PRB Energy changed its name to Black Raven Energy, Inc.  As of the date of filing of this Annual Report, PRB Gathering, Inc. remains in Chapter 11 Bankruptcy.  See Item 1 “Recent Developments” of this Annual Report.

As of the date of filing of this Annual Report, we are not currently party to any other material pending litigation.

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

None.

PART II

Principal Market of Common Stock

PRB Energy’s common stock was delisted from the American Stock Exchange effective April 28, 2008 following its filing of the Chapter 11 Bankruptcy.  From April 28, 2008 to February 4, 2009, PRB Energy’s common stock was quoted on the Pink Sheets under the stock symbol “PPRBQ.”  In connection with our emergence from bankruptcy, all of PRB Energy’s outstanding common stock was cancelled and we issued new common stock to certain claimants under the Plan.  Our common stock is not currently traded or quoted on a national securities exchange, the OTC Bulletin Board or the Pink Sheets.

The following table presents the reported high and low sales prices of PRB Energy’s common stock for each quarter of 2008 and 2007 as listed on the American Stock Exchange and the Pink Sheets during such periods:

As of December 31, 2008, there were approximately 25 record holders of our common stock. There were no unregistered securities sold during the year.

Dividend Policy

We have never paid cash dividends on our common stock and we do not anticipate paying dividends in the foreseeable future. We expect that we will retain all available earnings generated by our operations for the development and growth of our business. In addition, under the terms of the Amended Debenture that was issued on February 2, 2009 in connection with our emergence from Chapter 11 Bankruptcy, we are prohibited from declaring or paying cash dividends on our common stock during the period that the Amended Debenture is outstanding and unpaid.  Payment of any future dividends will be at the discretion of our Board of Directors after taking into account many factors, including our operating results, financial condition, current and anticipated cash needs, plans for expansion and the Amended Debenture.

ITEM 6. SELECTED FINANCIAL DATA.

Not applicable.

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Overview

We were originally organized as a mid-stream energy company providing gathering and processing services to third party natural gas producers.  During 2005 and 2006, we expanded our operations to include developing and producing natural gas properties along with providing management services as contract operator on jointly owned producing properties.  In 2006, we also expanded our gathering services through acquisition of additional gathering systems in the Recluse, Wyoming area.

During 2007, our planned drilling programs within both our D-J and Powder River Basin properties did not generate the revenues and corresponding cash flows necessary to achieve our business expansion initiatives. As a result, all available cash was primarily utilized for general working capital needs rather than growth initiatives. By the end of 2007 and through 2008, our strategic focus was concentrated on recapitalization pursuits to generate the cash necessary to cover our debt service obligations and infuse additional capital required to realize our growth expectations.

On March 5, 2008, PRB Energy and its subsidiaries filed voluntary petitions for relief for each business entity under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the District of Colorado.  PRB Energy continued to operate its business as a “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

On January 16, 2009, the Bankruptcy Court entered an order confirming PRB Energy’s and PRB Oil’s Modified Second Amended Joint Plan of Reorganization.  On February 2, 2009, PRB Energy and PRB Oil emerged from bankruptcy and PRB Energy changed its name to Black Raven Energy, Inc.  PRB Oil was subsequently merged into the Company.  See Item 1 of this Annual Report for a summary of recent developments since our emergence from bankruptcy.

Results of Operations for the Year Ended December 31, 2008

The following financial data should be read in conjunction with, and are qualified by reference to, our consolidated financial statements and related notes thereto in Item 8 of this Annual Report. The financial statements have been prepared assuming the Company will continue as a going concern.  The Company experienced a net loss of $12.1 million for the year ended December 31, 2008 and faced significant immediate obligations in excess of its existing sources of liquidity.  These conditions raised substantial doubt about the Company’s ability to continue as a going concern. See Note 15 of the Financial Statements for a complete discussion of the Company’s reorganization.

Revenue   Our E&P revenues are determined by production from our existing properties and price based on market conditions for trading natural gas product.  These market conditions such as weather, pipeline capacity and natural gas storage may have substantial effect on the revenues generated by our E&P segment.

Our gas gathering fees are based on contractual rates with our customers and will vary with system throughput and quality of gas delivered, as well as the level of services provided and customer mix.  These fees are not currently regulated by any governmental authority.

Other revenues in 2008 and 2007 consisted solely of equipment and inventory storage services provided to a third party at one of our facility locations.

E&P Production Taxes and Gathering Expenses  E&P production and gathering costs include production taxes, internal and third party gathering fees, and other deductions necessary to bring the natural gas product to market.  Production taxes are determined by the taxing authority.  In 2008, our production taxes were paid primarily to Wyoming including ad valorem charged by the county based on assessed valuation of the properties, and severance and conservation taxes charged by the state.  A nominal amount was paid to Colorado in connection with our production within the D-J basin, which property was acquired on December 28, 2006.

E&P Operating Expense  E&P natural gas lease operating expense includes costs associated with operating the natural gas properties.  Such costs include labor related to pumper and direct field supervision, electricity, surface-use agreements, equipment rental, fuel, chemicals, road maintenance, permits, supplies and other relevant well costs incurred to extract the natural gas from the well.

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

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gathering lines.

Depreciation, Depletion, Amortization and Accretion Expense   Depreciation expense relates to our compressor sites, pipelines and other gas gathering equipment, office furniture, office equipment and computers.  Depletion expense relates to developed and undeveloped leaseholds, capitalized development costs and related equipment.  Amortization expense relates to the customer contracts underlying the gas gathering systems.  Accretion expense relates to the change in our asset retirement obligation liability due to the passage of time.  Depreciation and amortization expenses are based on estimates of the related assets’ useful lives.  Depletion expense is calculated using the unit-of-production method based on estimated proved or estimated proved developed reserves.  Accretion expense is calculated using the effective interest method.

General and Administrative Expense  General and administrative expense includes the costs associated with our corporate office, including personnel costs, professional fees, office rent and other office support costs.

Interest Expense  Interest expense primarily includes interest incurred through March 5, 2008 on $22 million of senior subordinated convertible notes issued during the first quarter of 2006, $15 million of senior secured debentures issued December 28, 2006, and a capital lease for gas compression equipment used in our gas gathering operations.  After March 5, 2008, interest expense includes interest incurred on the PRB Funding loan and the two DIP Loans.

Asset Impairment Charge   Assets are evaluated for impairment periodically throughout the year.  In 2008, we incurred total impairment charges of $5.2 million.  An impairment charge of $3.9 million related to our oil and gas properties, and an impairment charge of $894,000 related to our Recluse Gathering System. The Recluse Gathering System was an asset of PRB Gathering, Inc., which remains in Chapter 11 Bankruptcy.  Effective November 1, 2008, control of the Recluse Gathering System was turned over to a receiver appointed by the State Court of Wyoming.

In 2007, we incurred an impairment charge of $7.5 million for our Powder River Basin gathering system assets whose carrying amount was not expected to be recoverable over their remaining expected lives. Having determined that the limited revenues generated from these gathering systems were insufficient to cover their related operating expenses, we opted to sell or otherwise divest of these assets to eliminate the ongoing net operating losses. Anticipating negligible market value for the gathering assets as determined through independent appraisal, all remaining net book value of these gathering system assets was included in impairment expense at December 31, 2007.

Similarly, we incurred an impairment charge in 2007 of approximately $4.8 million for under-performing E&P assets, also located in the Powder River Basin of Wyoming. Production from these properties had depleted to unprofitable levels, prompting us to shut-in the remaining wells in avoidance of unwarranted costs in excess of revenues generated, or in the absence of any revenue as was the case with certain wells still in the dewatering phase.

Exploration Expense   Exploration expense includes the costs of drilling unsuccessful exploratory wells.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Throughout 2007 and through November 1, 2008, we operated as two business segments through two wholly-owned subsidiaries. As of the date of filing of this Annual Report, PRB Gathering, Inc. remains in Chapter 11 bankruptcy and we currently only operate our gas exploitation and production business segment.

E&P revenue decreased to $1.21 million in 2008 from $1.51 million in 2007, a decrease of approximately $300,000, or 20%. Volumetric declines stemming from the sale of wells and shutting in of uneconomic wells resulted in an $884,000 decline in revenue, offset by an increase of $584,000 due to natural gas price increases of an average $2.85 per mcf.  G&P revenue declined to $1.1 million in 2008 from $1.5 million in 2007, due to the partial year operations of our G&P segment.

Selected Operating Expenses.  The following table and the explanations that follow present information about our operating expenses for each of the years ended December 31, 2008 and 2007:

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With our decision to exit our G&P product line in 2008, we expect to realize significant cost savings within operating costs, depreciation, and general and administrative expenses. The changes as explained in the preceding table were primarily related to the following items:

Operating costs — E&P During 2008, the sale of properties, as well as the shutting-in or plugging wells resulted in a decrease of $1.2 million, or 48%, below 2007 operating cost levels.

Operating costs — G&P.  Operating costs for 2008 are through November 1, 2008 in comparison to a full year for 2007, resulting in a decline of $1.4 million or 79%.

Depreciation, depletion and amortization.  The decrease of $1.9 million for E&P depletion mainly resulted from the sale of properties acquired in mid and late 2006.  The decrease of $1.5 million for G&P is also the result of the impairment of gathering assets that remain in Chapter 11 Bankruptcy.

General and administrative.  The decrease of $2.5 million, or 43%, was a result of reduced personnel costs and general office-related expenses incurred after our bankruptcy filing. General and administrative expenses above include the costs for legal and other professional services incurred during 2008 in connection with our Chapter 11 Bankruptcy.

Interest expense.  Interest expense decreased $5.0 million, or 60%, due to the Chapter 11 filing.  No interest expense was accrued or paid on the convertible notes or the senior secured debentures after the declaration of bankruptcy on March 5, 2008.  The interest associated with the compressor capital lease arrangement that was part of the G&P segment was no longer a part of our operations in 2008.. See “Note 10 — Borrowings” to our consolidated financial statements in Item 8 of this Annual Report for additional disclosures related to our financing facilities.

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Revenue decreased $1.8 million, or 37%, in 2007 in large part due to the decrease of $1.1 million in G&P revenue resulting from decreased throughput volumes as third party shippers reduced production in response to sales price declines. Revenue from management fees also decreased by $0.5 million due to the cancellation of the services agreement in conjunction with Rocky Mountain Gas, Inc.  Natural gas sales revenue decreased $0.2 million as a result of volumetric declines stemming from the shut-in or plugging of uneconomic wells in combination with market-driven sales price declines.

Selected Operating Expenses.  The following table and the explanations that follow present information about our operating expenses for each of the years ended December 31, 2007 and 2006:

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Operating costs — E&P.  On December 28, 2006, we closed on the acquisition of 13 wells in the D-J Basin plus additional acreage with identified drilling site locations.  During 2007, we drilled an additional 11 wells within the acquired acreage which resulted in production costs in 2007 that did not exist in 2006.  We also incurred higher operating costs in our existing Wyoming coal bed methane wells as we accelerated dewatering operations to enable production of the underlying gas reserves. The operating costs associated with these expanded production activities resulted in an increase of $0.6 million, or 33%, above 2006 cost levels.

Operating costs — G&P.  Our gathering-related operating costs decreased $0.7 million, or 27%, primarily due to the reduced utilization of third-party services resulting from our cost control initiatives in anticipation of exiting the G&P product line business segment in 2008.

Depreciation, depletion and amortization.  Increases of $1.4 million, or 134%, for E&P depletion mainly resulted from the additions of properties acquired in mid and late 2006.  The increase year over year in G&P asset depreciation, depletion and amortization of $.9 million, or 109%, was primarily due to amortization of the capital lease for gas compression equipment that was entered into in February 2007.

General and administrative.  The increase of $0.8 million, or 15%, was a result of inflationary impacts on personnel costs and general office-related expenses, along with an increase in costs for legal and other professional services incurred during the latter half of 2007 in connection with our refinancing and recapitalization efforts.

Interest expense.  Interest expense increased a total of $6.1 million, or 266% in 2007. $4.8 million of the increase was due to the issuance of $15 million of debentures in connection with the acquisition of properties in the D-J Basin on December 28, 2006.  An additional $1.3 million of the increase in interest expense in 2007 is associated with the compressor capital lease arrangement entered into in February 2007. See “Note 9 — Borrowings” to our consolidated financial statements in Item 8 of this Annual Report for additional disclosures related to our financing facilities.

Financial Condition, Liquidity and Capital Resources

At December 31, 2008, cash and cash equivalents totaled $0.5 million. At December 31, 2008, working capital, was ($42.0) million, including liabilities subject to compromise. As a result of our operating losses in 2007 and our inability to meet our obligations under the senior subordinated convertible notes and senior secured debentures, we filed for relief under Chapter 11 of the Bankruptcy Code in March 2008.

Capital Expenditures Substantial capital is required to replace and grow reserves. During 2008, we spent approximately $1.9 million on capital expenditures, compared to $9.2 million in 2007. The significant decrease is due to limited working capital and our Chapter 11 Bankruptcy filing.

Cash Flows from Operations Cash flows used in operations totaled ($1.3) million and ($6.4) million during 2008 and 2007, respectively.  Cash flow from our E&P operations is dependent upon the price of natural gas and our ability to increase production, and manage costs.  Natural gas prices increased in 2008 compared to 2007, however the Company experienced volumetric declines stemming from the sale of wells and shutting in of uneconomic wells.  Therefore, we were unable to generate the cash flows from operations necessary to sustain our working capital needs or contribute to our drilling program.

Off-Balance Sheet Arrangements As part of its ongoing business, the Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPE”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.  As of December 31, 2008, the Company has not been involved in any unconsolidated SPE transactions.

Critical Accounting Policies and Estimates

We are engaged in the exploration, exploitation, development, acquisition, and production of natural gas and crude oil.  Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements.  The preparation of these consolidated financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses as well as the disclosure of contingent assets and liabilities as of the date of our financial statements.  We base our decisions affecting the estimates we use on historical experience and various other sources that are believed to be reasonable under the circumstances.  Actual results may differ from the estimates we calculate due to changes in business conditions or unexpected circumstances.  Policies we believe are critical to understanding our business operations and results of operations are detailed below.  For additional information on our significant accounting policies refer to Note 2 — Summary of Significant Accounting Policies, Note 6 — Asset Retirement Obligations, and Note 12 — Disclosures about Oil and Gas Producing Activities in our consolidated financial statements included in Item 8 of this Annual Report.

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Oil and gas reserve quantities.  Estimated reserve quantities and the related estimates of future net cash flows are critical estimates for an exploration and production company because they affect the perceived value of our Company, are used in comparative financial analysis ratios and are used as the basis for the most significant accounting estimates in our financial statements.  The significant accounting estimates primarily include the periodic calculations of depletion, depreciation, and impairment of our proved oil and gas properties.  Future cash inflows and future production and development costs are determined by applying benchmark prices and costs, including transportation, quality, and basis differentials, in effect at the end of each period to the estimated quantities of oil and gas remaining to be produced as of the end of that period.  Expected cash flows are reduced to present value using a discount rate that depends upon the purpose for which the reserve estimates will be used.  For example, the standardized measure calculations required by Statement of Financial Accounting Standards (“SFAS”) No. 69, Disclosures about Oil and Gas Producing Activities, requires a ten percent discount rate to be applied.  Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves, including using independent reserve engineering consultants.  We expect that periodic reserve estimates will change in the future as additional information becomes available or as oil and gas prices and operating and capital costs change.  We evaluate and estimate our oil and gas reserves at December 31each year, unless factors would indicate to us to evaluate our reserves more frequently.  For purposes of depletion, depreciation, and impairment, reserve quantities are adjusted at all interim periods for the estimated impact of additions and dispositions.  Changes in depletion, depreciation, or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period that the reserve estimates change.

Successful efforts method of accounting.  Generally accepted accounting principles provide for two alternative methods for the oil and gas industry to use in accounting for oil and gas producing activities.  These two methods are generally known in our industry as the full cost method and the successful efforts method.  Both methods are widely used.  The methods are different enough that in many circumstances the same set of facts will provide materially different financial statement results within a given year.  We have chosen the successful efforts method of accounting for our oil and gas producing activities, and a detailed description is included in Note 2 to our consolidated financial statements included in this annual report.

Depreciation, Depletion and Amortization.  Our rate of recording DD&A is dependent upon our estimates of total proved and proved developed reserves, which estimates incorporate various assumptions and future projections.  If the estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, reducing our net income.  Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields.  We are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploitation and development program, as well as future economic conditions.

Revenue recognition.  We derive our revenue primarily from the sale of produced natural gas and crude oil.  We report revenue as the gross amounts we receive before taking into account production taxes and transportation costs.  Revenue is recorded in the month our production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production.  No revenue is recognized unless it is determined that title to the product has transferred to a purchaser.  At the end of each month we make estimates of the amount of production delivered to the purchaser and the price we will receive.  We use our knowledge of our properties, their historical performance, local spot market prices, and other factors as the basis for these estimates.  Variances between our estimates and the actual amounts received are recorded in the month payment is received.

Asset retirement obligations.  We are required to recognize an estimated liability for future costs associated with the abandonment of our oil and gas properties.  We base our estimate of the liability on our historical experience in abandoning oil and gas wells projected into the future based on our current understanding of federal and state regulatory requirements.  Our present value calculations require us to estimate the economic lives of our properties, assume what future inflation rates apply to external estimates, and determine what credit adjusted risk-free rate to use.  The impact to the consolidated statement of operations from these estimates is reflected in our depreciation, depletion, and amortization calculations and occurs over the remaining life of our properties.

Valuation of long-lived and intangible assets.  Our property and equipment are recorded at cost.  Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. An impairment charge is taken on unproven property when we determine that the property will not be developed or the carrying value will not be realized.  We evaluate the realizability of our proved properties and other long-lived assets whenever events or changes in circumstances indicate that impairment may be appropriate.  Our impairment test compares the expected undiscounted future net revenues from property, using escalated pricing, with the related net capitalized cost of the property at the end of each period.  When the net capitalized costs exceed the undiscounted future net revenue of a property, the cost of the property is written down to our estimate of fair value, which is determined by applying a discount rate that we believe is indicative of the current market.  Our criteria for an acceptable internal rate of return are subject to change over time.  Different pricing assumptions or discount rates could result in a different calculated impairment.

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Income taxes.  We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes”.  This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively.  Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not.  Additionally, our federal and state income tax returns are generally not filed before the consolidated financial statements are prepared, therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating and capital loss carry-forwards and carry-backs.  Adjustments related to differences between the estimates we used and actual amounts we report are recorded in the periods in which we file our income tax returns.  These adjustments and changes in our estimates of asset recovery and liability settlement could have an impact on our results of operations.

Evaluation of Disclosure Controls and Procedures.

Under the supervision of our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of the end of the period covered by this Annual Report. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of December 31, 2008 due to our inability to file periodic reports on a timely basis with the SEC as a result of our lack of capital resources and internal financial and accounting personnel.

Management’s Annual Report on Internal Control over Financial Reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act, to provide reasonable assurance that the objectives of the control system are met.  Our management conducted an assessment of our internal control over financial reporting based on the framework established by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework.  Our management has concluded that we did not maintain effective internal control over financial reporting because of lack of capital resources and internal financial and accounting personnel.

This Annual Report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting.  Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report.

ITEM 9B. OTHER INFORMATION.

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

Biographical information, including principal occupation and business experience during the last five years, of each member of our Board as of December 31, 2008 is set forth below.  Upon our emergence from Chapter 11 Bankruptcy on February 2, 2009, our Board was substantially reconstituted.

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Directors

Gus J. Blass III, age 57, joined the Board in June 2006.  He has been a General Partner of Capital Properties LLC since 1981. Capital Properties owns and manages over one million square feet of warehouse space in the Little Rock, Arkansas area and invests in public and private companies. Mr. Blass currently serves on the Board of Directors at Bancorp South, Cajuns Wharf Corporation and NutraCheck, Inc.  Mr. Blass has a Bachelor of Science Degree in Finance and Banking from the University of Arkansas.  As of the date of filing of this Annual Report, Mr. Blass is a current member of our Board.

William F. Hayworth, age 54, joined us as President, Chief Operating Officer and Director in June 2004.  He was appointed as Chief Executive Officer on January 31, 2008.  From 2002 to 2004, he served as a consultant through his wholly-owned company, BAM Energy, Inc., to various energy companies acting as project manager and evaluation specialist for coal-bed methane pilot projects in Kansas, Wyoming, western Colorado and Utah.  From 1997 to 2002, he was Vice President-Operations for Intoil, Inc. in Denver. His responsibilities included management and coordination of the company’s drilling and production activities as well as the design and construction of gathering facilities.  Prior to 1997, he was employed by Unit Corporation in Houston, Texas and was the Engineering/Operations Manager for Patrick Petroleum in Houston, Texas and Jackson, Michigan.  In addition to his responsibilities for supervision of technical staff and field personnel, Mr. Hayworth evaluated potential acquisitions and divestitures for Patrick Petroleum.  He also spent 12 years with Phillips Petroleum where he held various reservoir drilling and production engineering positions in the United Kingdom, Norway, Texas and Oklahoma.  Mr. Hayworth holds a Bachelor of Science degree in Chemical Engineering from the University of Michigan.  He is a member of the American Association of Drilling Engineers, the Rocky Mountain Association of Geologists, the International Association of Drilling Contractors, the Society of Petroleum Engineers and the Energy Finance Group.  As of the date of filing of this Annual Report, Mr. Hayworth serves as our President and is a current member of our Board.

Paul L. Maddock, Jr., age 60,  joined the Board in February 2007.  He has been President and Trustee of the Paul L. Maddock Marital Trust D/B/A The Maddock Companies for the past 20 years.  The Maddock Companies is a diversified commercial and residential real estate management and securities investment company. He has served on the Board of Florida Public Utilities (“FPU”) and Flo Gas Corporation for eight years.  FPU distributes natural gas, propane and electricity throughout Florida. He has also been a member of the Board of Directors of Lydian Bank and Trust where he is Chairman of the Audit Committee and a member of the Corporate Governance Committee.  Formerly, he was Founding Member and Vice Chairman of Island National Bank, Director 1st United Bank, Director of Wachovia Bank of Florida (purchaser of 1st United) and Director of Alamac Knits a North Carolina company.  He graduated from Brown University with an AB in English and a Minor in Political Science and Economics.  Mr. Maddock resigned from the Board on February 2, 2009 in connection with our emergence from Chapter 11 Bankruptcy.

Sigmund J. Rosenfeld, age 78, joined the Board in February 2007. He has been an independent geologist and consultant to the oil and gas industry since 1987. In 1978, he joined Thomas N. Jordan, Jr. as manager of Gulf Coast Venture and, in 1980, was a founder of Valex Petroleum Company, a public company, serving as its President until 1987.  From 1970 to 1978, he was a founder and President of Juniper Petroleum Corporation, another public company. Prior to that, he was Assistant to the Chairman of Inexco Oil Company, worked for Wolf Land Company and was Vice President and Manager of Andex Oil Company in Calgary, Canada. Mr. Rosenfeld began his career in the oil and gas industry in 1955 as an exploration geologist with Shell Oil Company and Monsanto Chemical Company. Mr, Rosenfeld holds a BS degree in Geology from the University of Florida, a MS degree in Geology from Emory University and a JD degree from the University of Denver.  Mr. Rosenfeld resigned from the Board on February 2, 2009 in connection with our emergence from Chapter 11 Bankruptcy..

Reuben Sandler, Ph.D, age 70, joined the Board in October 2005. He has been Chairman and Chief Executive Officer of Intelligent Optical Systems, Inc., a research and development company developing technologies in optical sensing and instrumentation, since 1999. Before that he was President and Chief Information Officer for MediVox, Inc., a medical software development company, and prior to that was an Executive Vice President for Makoff R&D Laboratories, Inc. Dr. Sandler currently serves on the Board of Directors of JMG Exploration, Inc., Optech Ventures, LLC, and Optisense, LLC. He was a director of PASW, Inc. from 1999 to 2000 and a director of Alliance Medical Corporation from 1999 to 2002.  Dr. Sandler received a Ph.D. from the University of Chicago, is the author of four books on the subject of mathematics and has held professorships at Victoria University of Wellington, the University of Chicago, the University of Illinois, the University of Hawaii and Technion University of Haifa.  Dr. Sandler resigned from the Board on February 2, 2009 in connection with our emergence from Chapter 11 Bankruptcy..

James P. Schadt, age 68, joined the Board in October 2005.  He was appointed Executive Chairman of the Board on January 31, 2008.  He retired as Chairman and Chief Executive of the Reader’s Digest Association in 1997 and has since been involved in various board and private investment activities. He is currently a partner of Contagion, LLC, an operator of magazine publishing services, a director of LEK, a Boston-based consultancy specializing in shareholder value and a Life Trustee of Northwestern University. From 1980 to 1991, Mr. Schadt was with London-based Cadbury Schweppes plc serving on the Board of Directors and rising to Chief Executive Officer of the global beverages business. He has also served several not-for-profit organizations, including the Wallace Reader’s Digest Funds, The American Enterprise Institute and the Norwalk (CT) Hospital. Mr. Schadt began his business career in the marketing department at Procter & Gamble following his graduation from Northwestern University with a BA in Arts and Sciences. 

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Mr. Schadt resigned as Executive Chairman of the Board and member of the Board on February 2, 2009 in connection with our emergence from Chapter 11 Bankruptcy..

Audit Committee

As of December 31, 2008, the Board had an Audit Committee and its members were Paul L. Maddock (Chairman), Reuben Sandler and James P. Schadt. Each member of the Audit Committee satisfied the independence standards specified in the American Stock Exchange listing standards and Rule 10A-3(b)(1) of the Exchange Act.  Each member of the Audit Committee was financially literate and was able to read and understand fundamental financial statements, including the balance sheet, income statement and statement of cash flows.  The Board has determined that James P. Schadt qualified as an audit committee financial expert as defined in the Exchange Act. The Audit Committee operated pursuant to a written charter.  As enumerated in the charter, the Audit Committee makes recommendations concerning the engagement of independent public accountants and reviews our quarterly and annual financial statements with the independent public accountants. The Audit Committee also reviews with the independent accountants the plans and results of the audit engagement, the range of audit and non-audit fees, and the integrity, adequacy and effectiveness of our disclosure controls and internal control over financial reporting. The Audit Committee oversees and periodically confirms the independence of our independent accountants pre-approves services performed by our independent accountants and reviews the results of the audit and the independent accountant’s report for each fiscal year with management and with the independent accountants.  The Audit Committee also reviews all proposed transactions between us and persons that are considered related parties.

Stockholder Procedures to Nominate Directors

There were no material changes to stockholder procedures for nomination of directors during the year ended December 31, 2008.

Code of Ethics

We have adopted a Code of Business Conduct and Ethics to provide guidance on maintaining our commitment to being honest and ethical in our business endeavors. The Code of Business Conduct and Ethics covers a wide range of business practices, procedures and basic principles regarding corporate and personal conduct and applies to all of our directors, executives, officers and employees. A copy of the Code of Business Conduct and Ethics is filed as Exhibit 14.1 to our Annual Report on Form 10-K for the year ended December 31, 2005.  In addition, a copy of the Code of Business Conduct and Ethics may be obtained, without charge, by written request submitted to the Secretary at Black Raven Energy, Inc., 1125 Seventeenth Street, Suite 2300, Denver, Colorado 80202.

Executive Officers

The following table sets forth certain information regarding our executive officer as of December 31, 2008.

The principal occupation of each executive officer of the Company as of December 31, 2008, for at least the past five years, is as follows:

William F. Hayworth   Chief Executive Officer, President and Chief Operating Officer. More detailed information regarding Mr. Hayworth’s business experience is set forth under “Directors.”  Mr. Hayworth became the Chief Executive Officer on January 31, 2008.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our directors and executive officers, and persons who own more than ten percent of our common stock, to file with the SEC and any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes in ownership of our common stock.

To our knowledge, based solely on a review of the copies of such reports furnished to us, we believe that all required reports of our officers, directors and greater than ten percent stockholders under Section 16(a) were timely filed during the year ended December 31, 2008.

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ITEM 11.                   EXECUTIVE COMPENSATION.

Summary Compensation Table

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Outstanding Equity Awards at Fiscal Year-End (3)

Director Compensation

Option awards were granted to the Directors in prior years, and the number of options held at December 31, 2008 were as follows: Gus Blass III 30,000 options, Paul Maddock 30,000 options, Sigmund Rosenfeld 20,000 options, Reuben Sandler 40,000 options and James Schadt 50,000 options.

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Equity Compensation Plan Information

The following table is a summary of the shares of our common stock authorized for issuance under our equity compensation plan as of December 31, 2008.

Beneficial Ownership

The following table sets forth information regarding beneficial ownership of our common stock as of December 31, 2008 by:

·  each of our directors and named executive officers;

·  all executive officers and directors as a group; and

·  each person who is known by us to beneficially own more than 5% of our outstanding common stock.

Beneficial ownership of our common stock is determined in accordance with the rules of the SEC and generally includes any shares of common stock over which a person exercises sole or shared voting or investment powers, or of which such person has a right to acquire ownership at any time within 60 days of December 31, 2008. All shares listed below are held directly unless otherwise noted.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE.

One of our officers (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 were issued in March 2006.  During the year ended December 31, 2008 and 2007, the Company paid interest of $0 and $10,139 respectively, on these Notes.

Independence of Directors

The Board determined that Gus J. Blass III, Paul L. Maddock Jr., Sigmund J. Rosenfeld, Reuben Sandler and James P. Schadt have no material relationship with us, directly or indirectly, that would interfere with the exercise of independent judgment, and are “independent” within the meaning of the American Stock Exchange’s director independence standards.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table presents the aggregate fees billed for the indicated services performed by Hein & Associates (“Hein”) and Deloitte & Touche LLP (“Deloitte”) for the 2008 and 2007 fiscal years

(1)  Audit-related fees include fees for review of registration statements and issuances of letters to underwriters.

For purposes of the preceding table, the professional fees are classified as follows:

Audit Fees.   This category includes the aggregate fees billed for professional services rendered for the audits of our consolidated financial statements for the year ended December 31, 2008 and for the reviews of the financial statements included in our quarterly reports on Form 10-Q during the year.  These services are normally provided by the independent public accountants in connection with statutory and regulatory filings or engagements for the relevant fiscal year.

Audit-Related Fees.   This category includes the aggregate fees billed for the year ended December 31, 2008 for review of internal controls, consents for use of predecessor audited financial reports, transition of audit firms and related services by the independent public accountants that related to the performance of audits or reviews of the financial statements that are not reported above under “Audit Fees.”

All Other Fees.   This category includes the aggregate fees billed for the 2008 financials and reports and consists of out-of-pocket expenses, products and services provided by the independent public accountants that are not reported above under “Audit fees” or “Audit-Related fees.”

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

(1) Consolidated Financial Statements

The following consolidated financial statements are filed as part of this report:

(2) Financial Statement Schedules

All financial statement schedules are omitted because they are not required, are not applicable, or the information is provided elsewhere in the consolidated financial statements or notes thereto.

(3) Exhibit List

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