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Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

x      ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended December 31, 2009

 

o         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from                      to                     

 

Commission file number:  001-32471

 

BLACK RAVEN ENERGY, INC.

(Exact Name of Registrant as Specified in Its Charter)

 

Nevada

 

20-0563497

(State or Other Jurisdiction of

 

(I.R.S. Employer Identification No.)

Incorporation or Organization)

 

 

 

 

 

1125 Seventeenth Street, Suite 2300

 

 

Denver, Colorado

 

80202

(Address of Principal Executive Offices)

 

(Zip Code)

 

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

 

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

 

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

 

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 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.  o

 

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.

 

Large accelerated filero

 

Accelerated filer o

 

 

 

Non-accelerated filero

 

Smaller reporting company x

(Do not check if a smaller reporting company)

 

 

 

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

 

There is no public market for the registrant’s common stock.  Therefore, the aggregate market value of the registrant’s common stock held by non-affiliates as of June 30, 2009 was $0.

 

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 March 15, 2010, the registrant had 16,658,109 shares of common stock outstanding.

 

 

 



Table of Contents

 

TABLE OF CONTENTS

 

Item

 

Description

 

Page

 

 

PART I

 

 

ITEM 1.

 

Business

 

4

ITEM 1A.

 

Risk Factors

 

6

ITEM 1B.

 

Unresolved Staff Comments

 

12

ITEM 2.

 

Properties

 

13

ITEM 3.

 

Legal Proceedings

 

15

ITEM 4.

 

Reserved

 

15

 

 

PART II

 

 

ITEM 5.

 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

15

ITEM 6.

 

Selected Financial Data

 

16

ITEM 7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

16

ITEM 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

 

21

ITEM 8.

 

Financial Statements and Supplementary Data

 

21

ITEM 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

21

ITEM 9A.

 

Controls and Procedures

 

21

ITEM 9B.

 

Other Information

 

22

 

 

PART III

 

 

ITEM 10.

 

Directors, Executive Officers and Corporate Governance

 

22

ITEM 11.

 

Executive Compensation

 

24

ITEM 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

25

ITEM 13.

 

Certain Relationships and Related Transactions, and Director Independence

 

26

ITEM 14.

 

Principal Accountant Fees and Services

 

26

 

 

PART IV

 

 

ITEM 15.

 

Exhibits and Financial Statement Schedules

 

26

 

 

Signatures

 

28

 

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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:

 

·      Changes in gas prices due to volatility of the market;

 

·      Our ability to evaluate our future performance due to limited operating history;

 

·      The continuance of reserve replacement through development of existing properties in order to sustain production;

 

·      Our ability to insure against liabilities associated with properties or obtain protection from sellers against them;

 

·      Our ability to evaluate projections of acquired property production;

 

·      Our ability to acquire or transact business due to requirements of significant external capital changing our risk and property profile;

 

·      Our ability to manage the risks inherent in operations of gas properties;

 

·      Our exposure to guaranteed indebtedness of our subsidiaries and the covenants in the agreements governing that debt;

 

·      Our ability to manage due to covenants limiting discretion of management in operating our business;

 

·      Our ability to perform certain development operations depends on financing through equity or debt;

 

·      Our ability to successfully integrate future acquisitions; and

 

·      Our ability to attract and retain professional personnel.

 

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.

 

Description of Business

 

Black Raven, formerly known as PRB Energy, Inc. was 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. 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.

 

Black Raven is focused on the development of low-risk shallow gas reserves in the Niobrara formation of the eastern D-J Basin.  The Niobrara formation in this part of the D-J Basin is an unconventional tight gas play characterized by a “chalk” formation.  The Company has 178,000 net acres under lease in the play and operates 100% of its acreage position.  The acreage is located in Sedgwick and Phillips Counties in Colorado and in Perkins, Chase and Dundy Counties in Nebraska.

 

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 discussed below, 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, 2009 is outlined below.  A more thorough description of the properties is presented in Item 2 of this Annual Report.

 

Chapter 11 Bankruptcy Filing and Recent Developments

 

On March 5, 2008, PRB Energy, Inc. (“PRB Energy”) and its subsidiaries filed 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:

 

·      13.5 million shares of New Common Stock to West Coast Opportunity Fund, LLC (“WCOF”), the principal pre-petition secured creditor;

·      1.425 million shares of New Common Stock, on a pro-rata basis, to holders of Class A-4 Claims (as defined in the Plan);

·      75,000 shares of New Common Stock, on a pro-rata basis, to holders of Class B-5 Claims (as defined in the Plan);

·      Warrants to purchase 1.425 million shares of New Common Stock at an exercise price of $2.50 per share, on a pro-rata basis, to holders of Class A-4 Claims; and

·      Warrants to purchase 75,000 shares of New Common Stock at an exercise price of $2.50 per share, on a pro-rata basis, to holders of Class B-5 Claims.

 

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Effective November 1, 2008, control of the Recluse Gathering System was turned over to a receiver appointed by the State Court of Wyoming. PRB Gathering’s Chapter 11 Bankruptcy case was dismissed by the Bankruptcy Court on February 17, 2010.  As a result, we deconsolidated PRB Gathering, Inc. (“PRB Gathering”) during the fourth quarter of 2008 and our net investment is shown as an investment in insolvent subsidiary in our financial statements.

 

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 principle balance and unpaid accrued interest were due on December 31, 2009, with the remainder of the outstanding balance and unpaid accrued interest due on December 31, 2010.  See below for discussion of the second amendment.  The Amended Debenture initially accrued interest at 10% per annum payable quarterly.

 

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.

 

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 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.

 

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.

 

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 directorsThe 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.

 

On November 9, 2009, the amended and restated debenture for $18.45 million was amended to $18.5 million in lieu of paying $50,000 in interest to WCOF.

 

At the Effective Date, we did not meet the requirements under ASC Topic 852 to adopt fresh start accounting. Fresh start accounting requires the debtor to use current fair values in its balance sheet for both assets and liabilities and to eliminate all prior earnings or deficits. The two requirements to fresh start accounting are:

 

·      the reorganization value of the company’s assets immediately before the date of confirmation of the plan of reorganization is less than the total of all post-petition liabilities and allowed claims; and

 

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·      the holders of existing voting shares immediately before confirmation of the plan of reorganization receive less than 50% of the voting shares upon emergence.

 

We refer to these requirements as the “fresh start applicability test.” For purposes of applying the fresh start applicability test, reorganization value is defined in the glossary of the Financial Accounting Standards Board Accounting Standards Codification (“ASC’) Topic 852 as “the value attributed to the reconstituted entity, as well as the expected net realizable value of those assets that will be disposed before reconstitution occurs. Therefore, this value is viewed as the fair value of the entity before considering liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after the restructuring.”

 

As of the Effective Date, our fresh start calculation indicated that we did not meet the requirements to adopt fresh start accounting because the reorganization value of our assets exceeded the total of post-petition liabilities and allowed claims.   The Company recognized a gain on reorganization of $24.6 million upon emergence from bankruptcy.

 

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.  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.

 

Revenues from two customers represented 10% or more of the Company’s sales for the year ended December 31, 2009.  We do not believe that the loss of any one customer would have a significant impact on our financial results.

 

Environmental Regulation

 

Currently, the Company operates wells on state and fee land.  These wells and the facility operated by Black Raven are subject to and comply with all state regulations.

 

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 5 — Asset Retirement Obligations” to our consolidated financial statements in Item 8 of this Annual Report.

 

Employees

 

As of December 31, 2009, 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

 

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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.

 

Our auditors have expressed substantial doubt about our ability to continue as a going concern.

 

The accompanying consolidated financial statements for the year ended December 31, 2009 were prepared under the assumption that we will continue to operate as a going concern. The report of our registered independent public accounting firm on our consolidated financial statements for the year ended December 31, 2009 includes an explanatory paragraph concerning conditions that raise substantial doubt about our ability to continue as a going concern. We incurred operating losses of approximately $2.4 million in the year ended December 31, 2009.  Continued operations are dependent on our ability to secure adequate financing and maintain a reasonable level of liquidity such that we can timely pay our obligations when due.

 

We are currently exploring opportunities to raise capital, including a private placement of our common stock.  There can be no assurances that we will be able to secure this additional financing and, accordingly, our liquidity and ability to execute our business plan and to timely pay our obligations when due could be adversely affected.  Additionally, we may incur operating losses during fiscal year 2010, and in the event that our financial results fall short of our current expectations, we will need to take further actions to reduce operating costs. There can be no assurance that such actions, if taken, will result in cash flows that will be sufficient to meet our ongoing operating needs.

 

Our financial statements do not include any adjustments that may result from the outcome of this uncertainty. If we cannot secure additional financing and continue to incur losses, we may be unable to maintain a level of liquidity necessary to continue operating our business.

 

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:

 

·      domestic supplies of natural gas;

·      weather conditions in the United States and wherever our property interests are located;

·      technological advances affecting energy consumption;

·      the price and availability of alternative fuels;

·      worldwide and domestic economic conditions;

·      actions by OPEC, the Organization of Petroleum Exporting Countries;

·      political instability in major oil and gas producing regions;

·      the level of consumer demand;

·      changes in the overall supply and demand for oil and gas;

·      the availability of transportation facilities;

·      the ability of oil and gas companies to raise capital;

·      the discovery rate of new oil and gas reserves;

·      the cost of exploring for, producing and delivering oil and gas;

·      the price of foreign imports of oil and gas; and

·      governmental regulations and taxes, both domestic and foreign.

 

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

 

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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:

 

·      our proved reserves;

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

·      the prices at which natural gas is sold; and

·      our ability to acquire, locate and produce new reserves.

 

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 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

 

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·      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

·      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.  Therefore, 2-D and 3-D seismic data may not accurately identify the presence of natural gas.

 

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 have historically been 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.

 

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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.  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.

 

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We depend on our chief executive officer, our president 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, our president and other executive officers.  We also do not carry key person insurance on their lives.  The loss of the services of our executive officers or our president, 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.

 

In connection with our SEC reports, 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.

 

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 a voluntary filer with the SEC and we may cease reporting at any time.

 

We are not current in our filing obligations with the SEC.  We are currently filing reports with the SEC but we may cease reporting at any time. 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. 

 

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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.  The market for our stock may be further impacted by our status as a voluntary filer with the SEC.  Such status will restrict our common stock from trading on a security exchange.

 

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.

 

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.

 

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ITEM 2.

 

PROPERTIES.

 

Description of Properties

 

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.  The Niobrara formation in this part of the D-J Basin is an unconventional tight gas play characterized by a “chalk” formation.  It is a high porosity/low permeability reservoir, roughly 40 feet thick with widespread structural biogenic gas deposits and extensive faulting.  The Company has 178,000 net acres under lease in the play and operates 100% of its acreage position.  The acreage is located in Sedgwick and Phillips Counties in Colorado and in Perkins, Chase and Dundy Counties in Nebraska.

 

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.

 

In 2007, we drilled twelve wells to the Niobrara.  Eleven wells intercepted a productive section of the Niobrara.  During 2009, the Company continued to operate the existing wells.  No additional wells were drilled and no workovers were conducted.

 

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.  As of December 31, 2009, we continue to hold a working interest position in this property.

 

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

 

Reserves

 

In December 2008, the SEC announced that it had approved revisions to oil and gas reporting requirements.  A key revision to the rules pertains to commodity prices.  The economic producibility of reserves and discounted cash flows are now based on a 12-month average commodity price as opposed to a year-end price in estimating reserves.

 

Additional revisions to the SEC rules provide for the use of new technology to estimate proved reserves.  Additionally, the definition of proved oil and gas reserves had been expanded to include non-traditional resources, which focuses on the marketable product rather than the method of extraction.

 

Application of the new rules resulted in the use of lower prices at December 31, 2009 than would have resulted under the SEC’s previous methodology.

 

The Company’s reserves at December 31, 2009 are as follows:

 

Reserves Category

 

Natural Gas
Reserves

 

 

 

MMcf

 

PROVED

 

 

 

Developed

 

 

 

North America

 

1,721

 

USA

 

1,721

 

 

 

 

 

Undeveloped

 

 

 

North America

 

7,428

 

USA

 

7,428

 

 

 

 

 

TOTAL PROVED

 

9,149

 

 

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A third party reserve audit was prepared by MHA Petroleum Consultants, Inc. (“MHA”).  MHA provides a wide array of reservoir evaluation services including reserve determinations, prospect evaluations and acquisition and divestiture of properties.  MHA’s typical professional has 20 years of oil and gas experience.  The lead consultant overseeing the Company’s reserve report was Leslie S. O’Connor, the president of MHA.  She has over thirty years working as a petroleum industry consultant.  She holds a degree in geology from Northern Arizona University and attended Colorado School of Mines for graduate studies in petroleum engineering.  MHA was incorporated in 1994.  Due to the size of our Company, Black Raven relies on the reserve audit prepared by MHA for its reserve estimates.

 

·      MHA was commissioned by the Company to complete a reserve audit subject to the new SEC regulations with an effective date of January 1, 2010.

 

·      The Company’s complete reserve base is located in Wyoming and Colorado.

 

·      MHA completed an independent decline curve analysis on the Company’s proved producing wells. This analysis is supplemented by experience in the area with the producing formations.  Production volumes were provided to MHA.  All production volumes could be independently verified through public sources.

 

·      MHA completed an analysis of the proved non-producing and proved undeveloped reserves using 3D seismic interpretation, volumetric analyses, and local and regional analogies.

 

·      Additional information provided to MHA included first of the month pricing for 2009 in order to comply with the new SEC regulations, working and revenue interests in each well or property, lease operating expenses, estimated capital costs, and timing for development.

 

·      MHA’s reserve estimates were assigned on the basis of the Securities and Exchange Commission definitions, effective January 1, 2010.

 

Proved Undeveloped Reserves

 

As presented in the chart above, at year end 2009, Black Raven had 7,428 mmcf of proved undeveloped reserves.  At year end 2008, Black Raven had 2,129 mmcf of proved undeveloped reserves.  This increase of 5,299 mmcf was the result of the new SEC Regulations for calculating “proved undeveloped reserves”.  During 2009, the Company conducted no drilling operations in order to increase reserves.

 

In December 2006, Black Raven became the owner and operator of the properties which hold the “proved undeveloped reserves”.  The “PUD” locations were initially booked in Black Raven’s year end 2007 reserve report.

 

Gas Sales

 

The following table summarizes the volumes sold and realized prices from our properties during the years ended December 31, 2009 and December 31, 2008 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.

 

 

 

2009

 

2008

 

 

 

 

 

 

 

Net annual gas sales (Mcf) (1)

 

149,297

 

205,000

 

Average net daily gas sales (Mcf)

 

409

 

562

 

Average realized price of gas per Mcf sold

 

$

3.08

 

$

5.92

 

Lease operating expense per Mcf sold

 

$

3.33

 

$

4.34

 

Production taxes per Mcf sold

 

$

0.31

 

$

0.62

 

Transportation expense per Mcf sold

 

$

1.78

 

$

0.77

 

 


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

 

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Productive Wells

 

As of December 31, 2009 and December 31, 2008, we had working interests in 63 productive wells (31 wells net) and 59 productive wells (27 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

 

The Company did not drill any wells in 2009 or 2008.

 

Acreage

 

The following table details the gross and net acres of developed and undeveloped properties that we hold. As of December 31, 2009, our properties accounted for the following developed and undeveloped acres:

 

 

 

Developed

 

Undeveloped

 

Total

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Wyoming

 

1,011

 

94

 

806

 

74

 

1,817

 

168

 

Colorado

 

960

 

960

 

101,348

 

93,581

 

102,308

 

94,541

 

Nebraska

 

 

 

97,153

 

84,078

 

97,153

 

84,078

 

Total

 

1,971

 

1,054

 

108,307

 

177,733

 

201,278

 

178,787

 

 

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.

 

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.  PRB Gathering, Inc.’s Chapter 11 Bankruptcy case was dismissed on February 17, 2010.  See Item 1 “Chapter 11 Bankruptcy Filing” of this Annual Report.

 

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

 

ITEM 4.

 

RESERVED.

 

PART II

 

ITEM 5.

 

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

 

Principal Market of Common Stock

 

There is no longer an established trading market for the Company’s common stock, as it is not currently traded or quoted on a national securities exchange, the OTC Bulletin Board or the Pink Sheets.

 

As of December 31, 2009, there were approximately 301 record holders of our common stock.

 

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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.

 

ITEM 7.

 

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

 

This Management Discussion and Analysis should be read in conjunction with the accompanying consolidated financial statements which have been prepared assuming we will continue as a going concern. Management’s plans concerning these matters are also described in Note 1 to the consolidated financial statements. The consolidated financial statements do not include any adjustments that might result from this uncertainty.

 

Overview

 

Black Raven is focused on the development of low-risk shallow gas reserves in the Niobrara formation of the eastern D-J Basin.  The Niobrara formation in this part of the D-J Basin is an unconventional tight gas play characterized by a “chalk” formation.  The Company has 178,000 net acres under lease in the play and operates 100% of its acreage position.  The acreage is located in Sedgwick and Phillips Counties in Colorado and in Perkins, Chase and Dundy Counties in Nebraska.

 

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, 2009

 

Summarized Results of Operations

 

 

 

(in thousands)

 

Natural gas sales

 

$

460

 

Operating expense

 

2,862

 

Operating loss

 

(2,402

)

Other expense

 

(1,289

)

Gain on reorganization

 

24,568

 

Other reorganization items

 

(163

)

Net income

 

$

20,714

 

 

The following financial data should be read in conjunction with, and are qualified by reference to, our consolidated financial

 

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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 has a net loss before reorganization items and income taxes of $3.7 million for the year ended December 31, 2009 and faces significant immediate obligations in excess of its existing sources of liquidity.  These conditions raise substantial doubt about the Company’s ability to continue as a going concern. See Note 3 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.

 

E&P Production Taxes  Production taxes are determined by the taxing authority.  In 2009, our production taxes were paid primarily to Colorado included ad valorem charged by the counties based on assessed valuation of the properties, and severance and conservation taxes charged by the state.   A nominal amount was paid to Wyoming in connection with our production within the Homestead Draw area.  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.

 

E&P Operating Expense   E&P natural gas lease production 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.

 

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 after our emergence from bankruptcy in February 2009 on the Amended Debentures payable to West Coast Opportunity Fund in the amount of $18.5 million.

 

Asset Impairment Charge   Assets are evaluated for impairment periodically throughout the year.  In 2009, we did not incur any impairment expense.

 

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

 

Gain on reorganization   The Company recognized a gain on reorganization of $24.6 million upon emergence from bankruptcy.

 

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

 

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, we only operate our gas exploitation and production business segment.

 

E&P revenue decreased to $0.5 million in 2009 from $1.21 million in 2008, a decrease of approximately $753,000, or 62%. Natural gas price decreases of an average $2.84 per mcf resulted in a $424,000 decline in revenue.  Volumetric declines resulted in a $329,000 decline in revenue.  G&P revenue declined to $0 in 2009 from $1.1 million in 2008, due to the Recluse Gathering System being turned over to a court appointed receiver.

 

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, 2009 and 2008:

 

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(in thousands)

 

2009

 

2008

 

Increase
(Decrease)

 

Change

 

Operating costs - E&P

 

$

616

 

$

1,230

 

$

(614

)

(50

)%

Operating costs - G&P

 

$

 

$

376

 

$

(376

)

(100

)%

Depreciation, depletion and amortization - E&P

 

$

252

 

$

515

 

$

(263

)

(51

)%

Depreciation, depletion and amortization - G&P

 

$

 

$

280

 

$

(280

)

(100

)%

General and administrative (including bankruptcy expenses)

 

$

2,126

 

$

3,311

 

$

(1,185

)

(36

)%

Interest expense

 

$

1,303

 

$

3,351

 

$

(2,048

)

(61

)%

 

The changes as explained in the preceding table were primarily related to the following items:

 

Operating costs  The decrease of $0.6 million or 50% was a result of the decrease in operating costs due to the sale of properties in 2008. The Company no longer operates its G&P segment.

 

Depreciation, depletion and amortization.  The decrease of $0.3 million for E&P depletion resulted mainly from the impairment of the Homestead Draw field in 2008, which reduced our asset base on which depletion was calculated for 2009.  The Company no longer operates its G&P segment.

 

General and administrative.  The decrease of $1.2 million, or 36%, 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 2009 and 2008 in connection with our Chapter 11 Bankruptcy.

 

Interest expense.  Interest expense decreased $2.0 million, or 61%, due to the 2.5% interest rate on the Amended Debentures payable to West Coast Opportunity Fund.

 

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.  During 2009, we continued to 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:

 

(in thousands)

 

2008

 

2007

 

Increase
(Decrease)

 

Change

 

Operating costs - E&P

 

$

1,230

 

$

2,383

 

$

(1,153

)

(48

)%

Operating costs - G&P

 

$

376

 

$

1,800

 

$

(1,424

)

(79

)%

Depreciation, depletion and amortization - E&P

 

$

515

 

$

2,429

 

$

(1,914

)

(79

)%

Depreciation, depletion and amortization - G&P

 

$

280

 

$

1,766

 

$

(1,486

)

(84

)%

General and administrative (including bankruptcy expenses)

 

$

3,311

 

$

5,783

 

$

(2,472

)

(43

)%

Interest expense

 

$

3,351

 

$

8,365

 

$

(5,014

)

(60

)%

 

With our decision to exit our G&P product line in 2008, we realized significant cost savings within operating costs, depreciation, and general and administrative expenses. The changes as presented 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.

 

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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.

 

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.

 

Financial Condition, Liquidity and Capital Resources

 

The accompanying audited consolidated financial statements for the year ended December 31, 2009 were prepared under the assumption that we will continue to operate as a going concern, which contemplates the realization of assets and the liquidation of liabilities in the normal course of business.

 

At December 31, 2009, cash and cash equivalents totaled $1.1 million. At December 31, 2009, working capital was $0.8 million.  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. On February 2, 2009, we emerged from bankruptcy.

 

At December 31, 2008, cash and cash equivalents totaled approximately $0.5 million, and working capital was approximately ($16.8) million. The significant increase in working capital from the prior year is primarily due to the classification of $18.5 million of our Debentures as a long-term liability in accordance with the terms and conditions of our Restated and Amended Debentures.  This obligation was previously classified as a current liability as of December 31, 2008. In addition, during the year ended December 31, 2009, we raised approximately $1.5 million in proceeds through the issuance of additional secured Debentures and $3.5 million through the sale of common stock to WCOF in connection with our emergence from bankruptcy.

 

Capital Expenditures Substantial capital is required to replace and grow reserves. During 2009, we spent approximately $0.4 million on capital expenditures, compared to $1.9 million in 2008. 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 ($3.2) million and ($1.2) million during 2009 and 2008, 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 decreased in 2009 compared to 2008 and the Company also experienced volumetric declines. Therefore, we were unable to generate the cash flows from operations necessary to sustain our working capital needs or contribute to our drilling program.

 

Management’s Plans to Obtain Additional Capital

 

Our ability to continue as a going concern is dependent on our ability to obtain additional capital.  Cash and cash equivalents on hand, internally generated cash flows, and proceeds from the common stock sales discussed above will require augmentation from asset sales or equity or debt financing to fund our debt service, working capital requirements, planned drilling, potential acquisitions and other capital expenditures in the future. The amount and allocation of future capital and exploitation expenditures will depend upon several factors including the number and size of acquisitions, drilling opportunities, future cash flows from operating and financing activities, and our ability to assimilate acquisitions. Also, the impact of oil and gas market prices on investment opportunities, the availability of capital and borrowing facilities and the success of our exploitation and development activities, particularly in Colorado, could lead to changes in funding requirements for future development.

 

The Company is currently exploring opportunities to raise capital, including a private placement of its common stock.   There can be no assurances that the Company will be able to secure this additional financing and, accordingly, the Company’s liquidity and ability to execute its business plan and to timely pay its obligations when due could be adversely affected.  If we fail to secure equity financing for future development in a private placement of our common stock, we will pursue other financing options through debt arrangements, joint venture partners, farm-out agreements or the sale of assets.  We may be unable to raise additional capital in a timely manner, on acceptable terms or at all.

 

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Off-Balance Sheet Arrangements As of December 31, 2009, the Company has no material off-balance sheet arrangements.

 

Critical Accounting Policies and Estimates

 

We are engaged in the exploration, exploitation, development, acquisition, and production of natural gas.  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 5 — Asset Retirement Obligations, and Note 11 — Disclosures about Oil and Gas Producing Activities in our consolidated financial statements included in Item 8 of this Annual Report.

 

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 FASB ASC Topic 932 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 for impairment 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.  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.   Historical differences have not been significant.

 

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,

 

20



Table of Contents

 

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.

 

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 FASB ASC Topic 740, “Income Taxes” (“ASC Topic 740”).  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.

 

 

ITEM 7A.            QUALITATIVE AND QUANTITATIVE DISCLOSURE OF MARKET RISK.

 

Not applicable.

 

ITEM 8.                 CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

 

The financial statements required pursuant to this Item 8 are included in Item 15 of this Annual Report and begin on page F-1.

 

ITEM 9.                     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

 

 

ITEM 9A.            CONTROLS AND PROCEDURES

 

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 are effective as of the end of the period covered by this Annual Report on Form 10-K.

 

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

 

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.  The Company’s internal control over financial reporting includes those policies and procedures that:

 

(i)   Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

 

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Table of Contents

 

(ii)  Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

 

(iii) Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that have a material effect on the financial statements.

 

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009. Based on our assessment and those criteria, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2009.

 

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 March 15, 2010 is set forth below.

 

Directors

 

Thomas E. Riley, age 57, joined us as Chairman and Chief Executive Officer in July 2009.  Prior to joining Black Raven, he spent the prior thirteen years growing Petroleum Development Corp. (PDC) (NASDAQ: PETD). Tom joined PDC in 1996 through a merger with his company Riley Natural Gas Co., and became its President in 2004. Tom founded and managed Riley Natural Gas Co. and RNG Service Co. for ten years prior to joining PDC. In addition, he spent six years at Consolidated Natural Gas Co. and seven years at Berea Oil & Gas Co. Tom holds a Petroleum Engineering degree from West Virginia University. We believe that Mr. Riley’s financial and business expertise, including a diversified background of managing and directing oil and gas companies, gives him the qualifications and skills to serve as a director.

 

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.  We believe that Mr. Blass’s financial and business expertise, including a diversified background of managing and directing public and private companies with substantial real property and serving on other boards of directors, gives him the qualifications and skills to serve as a director.

 

Daniel R. Frederickson, age 63, joined the Board in July 2009.  He was the President of Kinko’s Inc from 1986 to 1997.  He is active in real estate ventures and serves on the Board of Directors for Culligan Water Co. Inc and Cydcor Inc.  He holds a Bachelor of Science degree in Music from Central Missouri University and proudly served in Vietnam with the U.S. Marine Corps.  We believe that Mr. Frederickson’s financial, business and real property expertise in managing and directing several public companies and real estate ventures, gives him the qualifications and skills to serve as a director.

 

William F. Hayworth, age 55, joined us as President, Chief Operating Officer and Director in June 2004.  He served as Chief Executive Officer from January 31, 2008 to July 8, 2009.  He currently serves as our President.  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

 

22



Table of Contents

 

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.  We believe that Mr. Hayworth’s financial and business expertise, including a diversified background of in the oil and gas industry, gives him the qualifications and skills to serve as a director.

 

Atticus Lowe, age 29, is the Chief Investment Officer and a Principal of Black Raven’s largest shareholder, West Coast Asset Management, Inc., a Registered Investment Advisor. In addition to his extensive investment experience, Atticus has experience in the energy industry as a founder and principal of Black Sable Energy, LLC. Atticus is a Co-Author of The Entrepreneurial Investor (Published by John Wiley & Sons) and has been a featured speaker at the Value Investing Congress. He is a CFA Charterholder and holds a Bachelor of Arts degree in Economics and Business from Westmont College.  We believe that Mr. Lowe’s financial, investment and business expertise, including his work in the energy industry, gives him the qualifications and skills to serve as a director.

 

Audit Committee

 

As of December 31, 2009, the Board had an Audit Committee and its members were Atticus Lowe (Chairman), Gus Blass and Dan Frederickson.  Gus Blass and Dan Frederickson satisfied the independence standards specified in 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 Atticus Lowe 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, 2009.

 

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 officers as of December 31, 2009.

 

Name

 

Age

 

Positions

William F. Hayworth

 

55

 

President and Director

 

 

 

 

 

Thomas E. Riley

 

57

 

Chairman and Chief Executive Officer

 

 

 

 

 

Patrick A. Quinn

 

56

 

Chief Financial Officer

 

The principal occupation of each executive officer of the Company as of December 31, 2009, for at least the past five years, is as follows:

 

William F. Hayworth   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 and resigned July 7, 2009.

 

Thomas E. Riley  Chairman and Chief Executive Officer.  More detailed information regarding Mr. Riley’s business experience is set forth under “Directors.”  Mr. Reilly became the Chief Executive Officer on July 8, 2009.

 

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Table of Contents

 

Patrick A. Quinn, age 56, was appointed as contract Chief Financial Officer for the Company on an interim basis as of January 10, 2010. Mr. Quinn brings more than 30 years of accounting experience to Black Raven, including 20 years as the President of Quinn & Associates, P.C., which provides accounting, audit, tax and merger and acquisition consulting services to businesses in the real estate, mining and oil and gas industries. He has served as the Controller of Hamilton Oil Corporation from 1981 to 1986, the contract CFO of Teton Energy Corporation from 2004 to 2006, and the contract CFO of Intrepid Mining, LLC (predecessor to Intrepid Potash, Inc. (NYSE: IPI)) from 2000 to 2008.  Mr. Quinn holds a Bachelor of Science degree in Accounting from Colorado State University.

 

ITEM 11.                 EXECUTIVE COMPENSATION.

 

Summary Compensation Table

 

(a)

 

(b)

 

(c)

 

(d)

 

(e)

 

(f)

 

(g)

 

Name and Principal Position

 

Year

 

Salary
($)

 

Bonus
($)

 

Option
Awards
($)(1)

 

All Other
Compensation
($)(2)

 

Total
($)

 

Thomas E. Riley —Chief Executive Officer and Director (3)

 

2009

 

$

55,385

 

$

 

$

 

$

4,867

 

$

60,252

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

William Hayworth — President,Chief Executive Officer and Director (4)

 

2009

 

$

221,154

 

$

 

$

156,563

 

$

27,733

 

$

405,423

 

 

 

2008

 

$

317,692

 

$

26,923

 

$

 

$

26,180

 

$

370,795

 

 


(1)            The amounts reflect the total recognized for the year ended December 31, 2009 and 2008, in accordance with FASB ASC Topic 718, “Compensation — Stock Compensation” (“ASC Topic 718”),  for stock options and include amounts from awards granted in 2009. Assumptions used in the calculation of this amount under the Black-Scholes method are included in footnote 11 to our audited financial statements for the year ended December 31, 2009.

 

(2)            The amount shown reflects:

 

·                               Matching contributions pursuant to our 401(k) Savings Plan was $6,635 for Mr. Hayworth for 2009 and $8,931 for 2008.  Matching contributions pursuant to our 401(k) Savings Plan was $1,523 for Mr. Riley for 2009.

 

·                               Health Care Medical Plan compensation for 2009 was $21,098 for Mr. Hayworth and $17,249 for 2008.  Health Care Medical Plan compensation for 2009 was $3,344 for Mr. Riley.

 

(3)           Mr. Riley became our Chief Executive Officer on July 8, 2009.

 

(4)           Mr. Hayworth served as our Chief Executive Officer from January 31, 2008 to July 8, 2009 and currently serves as our President.

 

Outstanding Equity Awards at Fiscal Year-End

 

(a)

 

(b)

 

(c)

 

(d)

 

(e)

 

(f)

 

 

 

Option Awards

 

Name

 

Number of
Securities
Underlying
Unexercised
Options (#)
Exercisable
(1)

 

Number of
Securities
Underlying
Unexercised
Options (#)
Unexercisable
(1)

 

Equity Incentive
Plan Awards:
Number of
Securities
Underlying
Unexercised
Unearned Options
(#)

 

Option
Exercise
Price
($)(1)

 

Option
Expiration
Date
(1)

 

William Hayworth

 

 

750,000

 

 

2.00

 

7/1/2019

 

 

 

125,000

(2)

 

 

2.00

 

9/16/2019

 

 


(1)    The options granted under the 2009 Equity Compensation Plan expire in ten years.

 

(2)    These options vested immediately upon grant.

 

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Table of Contents

 

Director Compensation

 

Name

 

Fees
Earned or
Paid in
Cash
($)

 

Stock
Awards
($)

 

Option
Awards
($)

 

Non-Equity
Incentive Plan
Compensation
($)

 

Non-qualified
Deferred
Compensation
Earnings

 

All Other
Compensation
($)

 

Total
($)

 

Gus Blass III

 

$

1,000

 

 

$

32,250

 

 

 

 

$

33,250

 

Daniel Frederickson

 

$

1,000

 

 

$

32,250

 

 

 

 

$

33,250

 

 

ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

 

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, 2009.

 

Plan category

 

Number of securities to
be issued upon exercise of
outstanding options,
warrants and
rights

 

Weighted-average
exercise price of
outstanding options,
warrants and
rights

 

Number of securities
remaining available for
future issuance under
equity compensation
plans

 

Equity Compensation Plan Approved by Security Holders

 

3,791,666

 

$

2.00

 

2,459,166

 

Equity Compensation Plan Not Approved by Security Holders

 

0

 

0

 

0

 

Total

 

3,791,666

 

$

2.00

 

2,459,166

 

 

Beneficial Ownership

 

The following table sets forth information regarding beneficial ownership of our common stock as of December 31, 2009 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 based on 16,660,965 shares of common stock outstanding at March 15, 2010.  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, 2009. All shares listed below are held directly unless otherwise noted.

 

Name of Beneficial Owner

 

Number of
Shares
Beneficially
Owned

 

Percent of
Class

 

Stockholders Owning More Than 5%:

 

 

 

 

 

West Coast Opportunity Fund

 

15,166,667

 

91.0

%

 

 

 

 

 

 

Directors and Named Executive Officers:

 

 

 

 

 

William F. Hayworth (1)

 

125,000

 

*

 

Gus Blass III (2)

 

332,536

 

2.0

%

Daniel Frederickson (3)

 

50,000

 

*

 

Atticus Lowe (4)

 

15,166,667

 

91.0

%

 

 

 

 

 

 

Directors and executive officers as a group (6 persons):

 

15,674,203

 

94.0

%

 


*                    Less than 1%

 

25



Table of Contents

 

(1)          Includes 125,000 shares of Common Stock issuable upon exercise of stock options currently exercisable.

(2)          Includes 141,268 Common Stock issuable upon the exercise of warrants.

(3)          Includes 50,000 shares of Common Stock issuable upon exercise of stock options currently exercisable.

(4)          Mr. Lowe serves as Chief Investment Officer of West Coast Opportunity Fund, LLC.  Mr. Lowe’s beneficial ownership includes shares held by West Coast Opportunity Fund, LLC.

 

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

 

Independence of Directors

 

The Board determined that Gus J. Blass III and Dan Frederickson have no material relationship with us, directly or indirectly, that would interfere with the exercise of independent judgment.

 

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

 

The following table presents the aggregate fees billed for the indicated services performed by Deloitte & Touche LLP (“Deloitte”) for the 2009 and 2008 fiscal years

 

Deloitte

 

2009

 

2008

 

Audit fees

 

$

125,000

 

$

65,000

 

Audit-related fees

 

 

 

All other fees

 

 

 

Total fees

 

$

125,000

 

$

65,000

 

 

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, 2009 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.  The Audit Committee approved the 2009 audit fees.

 

Audit-Related Fees.   This category includes the aggregate fees billed for the year ended December 31, 2009 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 2009 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.”

 

PART IV

 

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

 

(1) Consolidated Financial Statements

 

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

 

Reports of Independent Registered Public Accounting Firms

F-1

Consolidated Balance Sheets

F-2

Consolidated Statements of Operations

F-4

Consolidated Statement of Changes in Stockholders’ Equity

F-5

Consolidated Statements of Cash Flows

F-6

Notes to Consolidated Financial Statements

F-7

 

 

26



Table of Contents

 

(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

 

Exhibit
Number

 

Description

2.1

 

Modified Second Amended Joint Plan of Reorganization Filed by PRB Energy, Inc. and PRB Oil & Gas, Inc., dated December 3, 2008 (incorporated herein by reference to Exhibit 99.1 to our Current Report on Form 8-K filed on January 21, 2009)

 

 

 

3.1

 

Amended and Restated Articles of Incorporation of Black Raven Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to our Current Report on Form 8-K filed on February 6, 2009)

 

 

 

3.2

 

Amended and Restated Bylaws of Black Raven Energy, Inc. (incorporated herein by reference to Exhibit 3.2 to our Current Report on Form 8-K filed on February 6, 2009)

 

 

 

4.1

 

Amended and Restated Senior Secured Debenture (incorporated herein by reference to Exhibit 4.1 to our Current Report on Form 8-K filed on February 6, 2009)

 

 

 

4.2

 

Form of Warrant Certificate of Black Raven Energy, Inc. (incorporated herein by reference to Exhibit 10.2 to our Current Report on Form 8-K filed on February 6, 2009)

 

 

 

10.1

 

Limited Waiver, Consent, and Modification Agreement, dated February 2, 2009, by and among PRB Oil & Gas, Inc., Black Raven Energy, Inc. and West Coast Opportunity Fund, LLC (incorporated herein by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on February 6, 2009)

 

 

 

10.2

 

Agreement Regarding New Equity Raise Under the Modified Second Amended Joint Plan of Reorganization, effective as of April 13, 2009, by and among Black Raven Energy, Inc., West Coast Opportunity Fund, LLC and the Official Committee of Unsecured Creditors (incorporated herein by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on May 1, 2009)

 

 

 

10.3

 

Securities Purchase Agreement, dated April 23, 2009, by and between Black Raven Energy, Inc. and West Coast Opportunity Fund, LLC (incorporated herein by reference to Exhibit 10.2 to our Current Report on Form 8-K filed on May 1, 2009)

 

 

 

10.4

 

Securities Purchase Agreement, dated July 9, 2009, by and between Black Raven Energy, Inc. and West Coast Opportunity Fund, LLC (incorporated herein by reference to Exhibit 10.4 to our Annual Report on Form 10-K for the year ended December 31, 2007)

 

 

 

10.5

 

Securities Purchase Agreement, dated August 27, 2009, by and between Black Raven Energy, Inc. and West Coast Opportunity Fund, LLC (incorporated herein by reference to Exhibit 10.5 to our Annual Report on Form 10-K for the year ended December 31, 2007)

 

 

 

10.6

 

Securities Purchase Agreement, dated September 16, 2009, by and between Black Raven Energy, Inc. and West Coast Opportunity Fund, LLC (incorporated herein by reference to Exhibit 10.6 to our Annual Report on Form 10-K for the year ended December 31, 2007)

 

 

 

10.7

 

Black Raven Energy, Inc. Equity Compensation Plan (the “Equity Compensation Plan”) (incorporated herein by reference to Exhibit 10.6 to our Annual Report on Form 10-K for the year ended December 31, 2007)

 

 

 

10.8

 

Form of Option Grant under the Equity Compensation Plan (incorporated herein by reference to Exhibit 10.7 to our Annual Report on Form 10-K for the year ended December 31, 2007)

 

 

 

10.9

 

Form of Restricted Stock Award Agreement under the Equity Compensation Plan (incorporated herein by reference to Exhibit 10.8 to our Annual Report on Form 10-K for the year ended December 31, 2007)

 

 

 

21.1┼

 

List of subsidiaries

 

 

 

23.1┼

 

Consent of MHA Petroleum Consultants, Inc.

 

 

 

24.1

 

Powers of Attorney, incorporated by reference to Signature page attached hereto

 

 

 

31.1┼

 

Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act

 

 

 

31.2┼

 

Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act

 

27



Table of Contents

 

32.1┼

 

Certification of the Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act

 

 

 

99.1┼

 

Report of MHA Petroleum Consultants, Inc., dated February 17, 2010, concerning the audit of oil and gas reserve estimates

 


┼  Filed herewith

 

SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

Black Raven Energy, Inc.

 

 

Date: April 2, 2010

/s/ Thomas E. Riley

 

Thomas E. Riley

Chief Executive Officer

 

POWER OF ATTORNEY

 

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Tom Riley as his attorney-in-fact, with full power of substitution, for him in any and all capacities to sign any amendments to this Annual Report on Form 10-K, and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that said attorneys-in-fact, or their substitutes, may do or cause to be done by virtue hereof.

 

Pursuant to the requirements of the Securities Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

Signature

 

Title

 

Date

 

 

 

 

 

/s/ Thomas E. Riley

 

Chief Executive Officer

 

April 2, 2010

Thomas E. Riley

 

 

 

 

 

 

 

 

 

/s/ Patrick A. Quinn

 

Chief Financial Officer

 

April 2, 2010

Patrick A. Quinn

 

 

 

 

 

 

 

 

 

/s/ William F. Hayworth

 

President and Director

 

April 2, 2010

William F. Hayworth

 

 

 

 

 

 

 

 

 

/s/ Gus J. Blass, III

 

Director

 

April 2, 2010

Gus J. Blass, III

 

 

 

 

 

 

 

 

 

/s/ Atticus Lowe

 

Director

 

April 2, 2010

Atticus Lowe

 

 

 

 

 

 

 

 

 

/s/ Dan Frederickson

 

Director

 

April 2, 2010

Dan Frederickson

 

 

 

 

 

28



Table of Contents

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and Stockholders of

Black Raven Energy, Inc.

Denver, Colorado

 

We have audited the accompanying balance sheets of Black Raven Energy, Inc. and its subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related statements of operations, stockholders’ equity (deficit), and cash flows for each of the two years in the period ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

 

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

 

In our opinion, such financial statements present fairly, in all material respects, the financial position of Black Raven Energy, Inc. and its subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

 

As discussed in Notes 1 and 3 to the financial statements, during 2008 Black Raven Energy, Inc. and its wholly-owned subsidiaries, PRB Oil and Gas, Inc. and PRB Gathering, Inc., filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code.  At December 31, 2009, PRB Gathering, Inc. remains in Chapter 11 bankruptcy.  The accompanying financial statements do not purport to reflect or provide for the consequences of the PRB Gathering, Inc. bankruptcy proceedings. In particular, such financial statements do not purport to show (1) as to PRB Gathering, Inc. assets, their realizable value on a liquidation basis or their availability to satisfy liabilities; (2) as to PRB Gathering, Inc. prepetition liabilities, the amounts that may be allowed for claims or contingencies, or the status and priority thereof; (3) as to the PRB Gathering, Inc. stockholder accounts, the effect of any changes that may be made in the capitalization of PRB Gathering, Inc.; or (4) as to PRB Gathering, Inc.’s operations, the effect of any changes that may be made in its business.

 

As also discussed in Notes 1 and 3 to the financial statements, on January 16, 2009, the Bankruptcy Court entered an order confirming the Black Raven Energy, Inc. and PRB Oil and Gas, Inc. plan of reorganization which became effective on February 2, 2009. Under the plan of reorganization, Black Raven Energy, Inc. and PRB Oil and Gas, Inc. are required to comply with certain terms and conditions as more fully described in Note 3 to the financial statements.

 

As discussed in Notes 2 and 11 to the consolidated financial statements, the Company changed its method of oil and gas reserve estimation and related required disclosures in 2009 with the implementation of new accounting guidance.

 

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company’s recurring losses from operations and stockholders’ deficit raise substantial doubt about its ability to continue as a going concern. Management’s plans concerning these matters are also discussed in Note 1 to the financial statements. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

 

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado

April 2, 2010

 

F-1



Table of Contents

 

Black Raven Energy, Inc. (formerly known as PRB Energy, Inc.)

Consolidated Balance Sheets

(In thousands, except share and per share amounts)

 

 

 

December 31, 2009

 

December 31, 2008

 

Assets

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

1,064

 

$

472

 

Accounts receivable, net

 

62

 

81

 

Inventory

 

62

 

43

 

Prepaid expenses

 

108

 

351

 

Total current assets

 

1,296

 

947

 

Oil and gas properties accounted for under the successful efforts method of accounting:

 

 

 

 

 

Proved properties

 

4,626

 

4,085

 

Unproved leaseholds

 

5,842

 

6,127

 

Wells-in-progress

 

483

 

721

 

Total oil and gas properties

 

10,951

 

10,933

 

Less: accumulated depreciation, depletion and amortization

 

(1,212

)

(1,126

)

Net oil and gas properties

 

9,739

 

9,807

 

Gathering and other property and equipment:

 

2,964

 

2,818

 

Less: accumulated depreciation and amortization

 

(925

)

(816

)

Net gathering and other property and equipment

 

2,039

 

2,002

 

Other non-current assets:

 

 

 

 

 

Deferred debt issuance costs, net

 

247

 

360

 

Other non-current assets

 

96

 

65

 

Total other non-current assets

 

343

 

425

 

TOTAL ASSETS

 

$

13,417

 

$

13,181

 

 

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

 

F-2



Table of Contents

 

Black Raven Energy, Inc. (formerly known as PRB Energy, Inc.)

Consolidated Balance Sheets (Continued)

(In thousands, except share and per share amounts)

 

 

 

December 31, 2009

 

December 31, 2008

 

Liabilities and Stockholders’ Deficit

 

 

 

 

 

Liabilities not subject to compromise - current:

 

 

 

 

 

Accounts payable

 

$

238

 

$

917

 

Accrued expenses and other current liabilities

 

308

 

2,325

 

Current portion of secured debentures, net of discount

 

 

14,537

 

Total current liabilities

 

546

 

17,779

 

Secured debentures, net of current portion and discount

 

17,828

 

 

Asset retirement obligation

 

219

 

345

 

Investment in insolvent subsidiary

 

1,072

 

1,072

 

Total liabilities not subject to compromise

 

19,665

 

19,196

 

Liabilities subject to compromise

 

 

24,730

 

Total liabilities

 

19,665

 

43,926

 

Commitments and Contingencies (Note 8)

 

 

 

 

 

Stockholders’ deficit

 

 

 

 

 

Common stock, par value $.001, 150,000,000 shares authorized; 16,660,965 and 8,721,994 issued and 16,660,965 and 7,802,094 outstanding for 2009 and 2008, respectively

 

17

 

10

 

Treasury stock, 0 and 919,900 shares, at cost, respectively

 

 

(1,257

)

Additional paid-in-capital

 

29,441

 

26,922

 

Accumulated deficit

 

(35,706

)

(56,420

)

Total stockholders’ deficit

 

(6,248

)

(30,745

)

TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT

 

$

13,417

 

$

13,181

 

 

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

 

F-3



Table of Contents

 

Black Raven Energy, Inc. (formerly known as PRB Energy, Inc.)

Consolidated Statements of Operations

(In thousands except share and per share amounts)

 

 

 

Years Ended December 31,

 

 

 

2009

 

2008

 

 

 

 

 

 

 

Revenue:

 

 

 

 

 

Natural gas sales

 

$

460

 

$

1,213

 

Gas gathering and processing

 

 

1,130

 

Other

 

 

21

 

Total revenue

 

460

 

2,364

 

Operating expenses:

 

 

 

 

 

Natural gas production expense

 

616

 

1,230

 

Gas gathering and processing expense

 

 

376

 

Exploration expense

 

8

 

17

 

Asset impairment charge

 

 

5,242

 

Depreciation, depletion, amortization and accretion

 

252

 

981

 

General and administrative

 

1,986

 

2,169

 

Total operating expenses

 

2,862

 

10,015

 

Operating loss

 

(2,402

)

(7,651

)

Other income (expense):

 

 

 

 

 

Interest and other income

 

14

 

16

 

Interest expense

 

(1,303

)

(3,351

)

Total other expense

 

(1,289

)

(3,335

)

Loss before reorganization items and income taxes

 

(3,691

)

(10,986

)

Reorganization items:

 

 

 

 

 

Gain on reorganization

 

24,568

 

 

Loss on disposal of assets

 

(26

)

(2

)

Professional fees

 

(140

)

(1,142

)

Interest on accumulated cash resulting from Chapter 11 bankruptcy

 

3

 

33

 

Total reorganization items

 

24,405

 

(1,111

)

Net income (loss) before income taxes

 

20,714

 

(12,097

)

Income tax provision/benefit

 

 

 

Net income (loss)

 

$

20,714

 

$

(12,097

)

Net income (loss) per common share—basic and diluted

 

$

1.37

 

$

(1.39

)

Basic and diluted weighted average shares outstanding

 

15,086,117

 

8,721,994

 

 

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

 

F-4



Table of Contents

 

Black Raven Energy, Inc. (formerly known as PRB Energy, Inc.)

Consolidated Statements of Stockholders’ Equity (Deficit)

Years Ended December 31, 2009 and 2008

(In thousands except share amounts)

 

 

 

 

 

 

 

 

 

 

 

Additional

 

 

 

Total

 

 

 

Common

 

Treasury

 

Paid - In

 

Accumulated

 

Stockholders’

 

 

 

Shares

 

Amount

 

Shares

 

Amount

 

Capital

 

Deficit

 

Equity (Deficit)

 

Balance at January 1, 2008

 

8,721,994

 

$

10

 

919,900

 

$

(1,257

)

$

27,014

 

$

(44,323

)

$

(18,556

)

Share-based compensation

 

 

 

 

 

(92

)

 

(92

)

Net loss

 

 

 

 

 

 

(12,097

)

(12,097

)

Balance at December 31, 2008

 

8,721,994

 

10

 

919,900

 

(1,257

)

26,922

 

(56,420

)

(30,745

)

Cancellation of common stock in bankruptcy

 

(8,721,994

)

(10

)

(919,900

)

1,257

 

(1,247

)

 

 

Issuance of common stock

 

14,994,298

 

15

 

 

 

(15

)

 

 

Sale of common stock

 

1,666,667

 

2

 

 

 

3,498

 

 

3,500

 

Share-based compensation

 

 

 

 

 

283

 

 

283

 

Net income

 

 

 

 

 

 

20,714

 

20,714

 

Balance at December 31, 2009

 

16,660,965

 

$

17

 

 

$

 

$

29,441

 

$

(35,706

)

$

(6,248

)

 

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

 

F-5



Table of Contents

 

Black Raven Energy, Inc. (formerly known as PRB Energy, Inc.)

Consolidated Statements of Cash Flows

(In thousands except share amounts)

 

 

 

Years Ended December 31,

 

 

 

2009

 

2008

 

 

 

 

 

 

 

Cash flows from operating activities

 

 

 

 

 

Net income (loss)

 

$

20,714

 

$

(12,097

)

Adjustments to reconcile net loss to net cash used in operating activities:

 

 

 

 

 

Depreciation, depletion, amortization and accretion

 

252

 

981

 

Asset impairment charge

 

 

5,242

 

Amortization of debt issuance costs

 

113

 

417

 

Amortization of discount on debentures

 

743

 

466

 

Bad debt expense

 

 

4

 

Share-based compensation expense

 

283

 

(92

)

Gain on reorganization

 

(24,568

)

 

(Gain) loss on sale of assets and other

 

26

 

(292

)

Changes in assets and liabilities:

 

 

 

 

 

Accounts receivable

 

19

 

917

 

Inventory

 

(19

)

47

 

Prepaid expenses

 

243

 

(216

)

Other non-current assets

 

(31

)

7

 

Accounts payable

 

(686

)

1,681

 

Accrued expenses and other current liabilities

 

(220

)

1,697

 

Net cash used in operating activities

 

(3,131

)

(1,238

)

Cash flows from investing activities

 

 

 

 

 

Capital expenditures

 

(367

)

(1,885

)

Change in restricted cash

 

 

1,022

 

Investment in insolvent subsidiary

 

 

(272

)

Proceeds from sale of assets

 

1

 

898

 

Net cash used in investing activities

 

(366

)

(237

)

Cash flows from financing activities

 

 

 

 

 

Proceeds from issuance of debt

 

1,500

 

1,114

 

Proceeds from issuance of common stock

 

3,500

 

 

Repayment of term loan

 

(911

)

 

Net cash provided by financing activities

 

4,089

 

1,114

 

Net increase (decrease) in cash

 

592

 

(361

)

Cash and cash equivalents—beginning of year

 

472

 

833

 

Cash and cash equivalents—end of year

 

$

1,064

 

$

472

 

Supplemental disclosure of cash flow activity

 

 

 

 

 

Cash paid for interest

 

358

 

492

 

Supplemental schedule for non-cash activity

 

 

 

 

 

Accrued capital expenditures

 

7

 

407

 

 

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

 

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BLACK RAVEN ENERGY, INC. (formerly known as PRB ENERGY, INC.)

Notes to Consolidated Financial Statements

December 31, 2009

 

Note 1 - General

 

Black Raven Energy, Inc. (“Black Raven,” the “Company,” “us,” “our” or “we”), formerly known as PRB Energy, Inc. (“PRB Energy”), 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, processing 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.”  Throughout 2007 and into 2008 PRB Energy operated as two business segments through two wholly-owned subsidiaries, PRB Oil and Gas, Inc. (“PRB Oil”), a gas and oil exploitation and production company (“E&P”) incorporated in Colorado in July 2005, and PRB Gathering, Inc., (“PRB Gathering”) a gathering and processing company (“G&P”) incorporated in Colorado in August 2006.

 

On March 5, 2008, PRB Energy and its subsidiaries filed voluntary petitions for relief for each business entity (the “Chapter 11 Bankruptcy”) under Chapter 11 of the 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.  Effective April 28, 2008, PRB Energy’s common stock was delisted from the American Stock Exchange.

 

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 (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 common stock were cancelled and PRB Energy changed its corporate name to Black Raven Energy, Inc. 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.

 

Effective November 1, 2008, control of the Recluse Gathering System owned by PRB Gathering was turned over to a receiver appointed by the State Court of Wyoming. Based on this loss of control, the Company deconsolidated the operations of PRB Gathering for financial reporting purposes.  The Company’s investment/obligation with regard to the PRB Gathering business is reflected as an Investment in Insolvent Subsidiary in the accompanying balance sheets as of December 31, 2009 and 2008.  PRB Gathering was dismissed from Chapter 11 Bankruptcy on February 17, 2010.

 

The accompanying financial statements have been prepared assuming the Company will continue as a going concern. As shown in the accompanying financial statements, the Company continues to experience net losses from its operations, reporting a net loss before reorganization items of $3.7 million for the year ended December 31, 2009. Cash and cash equivalents on hand and internally generated cash flows will not be sufficient to execute the Company’s business plan. Future bank financings, asset sales, or other equity or debt financings will be required to fund the Company’s debt service, working capital requirements, planned drilling, potential acquisitions and other capital expenditures. These conditions raise substantial doubt about the Company’s ability to continue as a going concern.

 

The Company is currently exploring opportunities to raise capital, including a private placement of its common stock. There can be no assurances that the Company will be able to secure this additional financing and, accordingly, the Company’s liquidity and ability to execute its business plan and to timely pay its obligations when due could be adversely affected. If we fail to secure equity financing for future development in a private placement of our common stock, we will pursue other financing options through debt arrangements, joint venture partners, farm-out agreements or the sale of assets.  There are no assurances that the Company will be able to raise additional capital in a timely manner, on acceptable terms, or at all.

 

Note 2 - Summary of Significant Accounting Policies

 

Basis of Presentation - The consolidated financial statements include the accounts of the Company and its subsidiaries.  These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).  All inter-company transactions have been eliminated.

 

For the period from March 5, 2008 through the Effective Date, we conducted our business in the ordinary course as debtors-in-possession under the protection of the Bankruptcy Court. We emerged from Chapter 11 Bankruptcy on February 2, 2009.

 

Our consolidated financial statements have been prepared in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 852, “Reorganizations” (“ASC Topic 852”), which requires that financial statements for periods subsequent to our Chapter 11 Bankruptcy filings distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain income, expenses, realized gains and losses and

 

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provisions for losses that were realized or incurred in our Chapter 11 Bankruptcy are recorded as reorganization items on our consolidated statements of operations.

 

At the Effective Date, we did not meet the requirements under ASC Topic 852 to adopt fresh start accounting. Fresh start accounting requires the debtor to use current fair values in its balance sheet for both assets and liabilities and to eliminate all prior earnings or deficits. The two requirements to fresh start accounting are:

 

·                  the reorganization value of the company’s assets immediately before the date of confirmation of the plan of reorganization is less than the total of all post-petition liabilities and allowed claims; and

 

·                  the holders of existing voting shares immediately before confirmation of the plan of reorganization receive less than 50% of the voting shares upon emergence.

 

We refer to these requirements as the “fresh start applicability test.” For purposes of applying the fresh start applicability test, reorganization value is defined by ASC Topic 852 as “the value attributed to the reconstituted entity, as well as the expected net realizable value of those assets that will be disposed before reconstitution occurs. Therefore, this value is viewed as the fair value of the entity before considering liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after the restructuring.”

 

As of the Effective Date, our fresh start calculation indicated that we did not meet the requirements to adopt fresh start accounting because the reorganization value of our assets exceeded the total of post-petition liabilities and allowed claims.   The Company recognized a gain on reorganization of $24.6 million upon emergence from bankruptcy.

 

Use of Estimates - The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Some specific examples of such estimates include the allowance for accounts receivable, accrued expenses, accrued revenue, asset retirement obligations, determining the remaining economic lives and carrying values of property and equipment and the estimates of gas reserves that affect the depletion calculation and impairments for gas properties and other long-lived assets. In addition, we use assumptions to estimate the fair value of share-based compensation. We believe our estimates and assumptions are reasonable; however, actual results may differ from our estimates.

 

Cash and Cash Equivalents - The Company considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents.  The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.  The Company continually monitors its positions with, and the credit quality of, the financial institutions with which it invests.

 

Accounts Receivable - Trade accounts receivable are recorded at the invoiced amount.  The Company assesses credit risk and allowance for doubtful accounts on a customer specific basis.  As of December 31, 2009, the Company had no allowance for doubtful accounts.  At December 31, 2008, the Company had an allowance for doubtful accounts of $22,000.

 

The Company grants credit in the normal course of business to customers in the United States.  The Company periodically performs credit analysis and monitors the financial condition of its customers to reduce credit risk. Management periodically reviews accounts receivable aging reports to assess credit risks, and if appropriate, also reviews updated credit information to further assess such risk.  In the event that management determines the customers’ accounts receivable collectability as less than probable, management reduces the carrying amount by a valuation allowance that reflects management’s best estimate of the amount not collectible.  Allowances for uncollectible accounts receivable are based on information available and historical experience.  For information on the concentration of credit risk by customer in the years ended December 31, 2009 and 2008, see page F-11.

 

Inventory - Inventory is recorded at cost.  The Company periodically reviews the carrying cost of its inventories as compared to current market value for those inventories and adjusts its carrying value to the lower of cost or market.  Inventory at December 31, 2009 and 2008 consisted primarily of tubing, and totaled $62,000 and $43,000, respectively.

 

Income Taxes — The Company recognizes deferred tax liabilities and assets based on the differences between the tax basis of assets and liabilities and their reported amounts in the consolidated financial statements that will result in taxable or deductible amounts in future years. In evaluating the ability to realize net deferred tax assets, the Company will take into account a number of factors, primarily relating to the Company’s ability to generate taxable income. The Company has recognized, before the valuation allowance, a net deferred tax asset attributable to the net operating losses for the years ended December 31, 2009 and 2008, respectively. FASB ASC Topic 740, “Income Taxes” (“ASC Topic 740”), requires that a valuation allowance be recorded against deferred tax assets unless it is more likely than not that the deferred tax asset will be utilized. As a result of this analysis, the Company has recorded a full valuation allowance against its net deferred tax asset.

 

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The Company has adopted the uncertainty provisions of ASC Topic 740, which requires the Company to recognize the impact of a tax position in its financial statements only if the technical merits of that position indicate that the position is more likely than not of being sustained upon audit. We recognize potential accrued interest and penalties, if any, related to unrecognized tax benefits in income tax expense, which is consistent with the recognition of these items in prior reporting periods. Due to the significant net operating losses, no interest and penalties were accrued.

 

Revenue Recognition - Revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if the collectability of the revenue is probable.  The Company derives revenue primarily from the sale of produced natural gas as well as gas gathering and transportation fees.  The Company reports revenue as the gross amount received before taking into account production taxes and transportation costs, which are reported as separate expenses.  Revenue is recorded in the month the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production.  Revenues from the production of gas properties in which the Company has an interest with other producers are recognized on the basis of the Company’s net working interest.  At the end of each month, the Company calculates a revenue accrual based on the estimates of production delivered to or transported for the purchaser.

 

Property, Equipment - Gas Gathering and Other - Gathering assets, including compressor sites and pipelines, are recorded at cost and depreciated using the straight line method over the estimated useful lives of the assets, which ranges from ten to thirty years.  Other property and equipment, such as office furniture, computer and related software and equipment, automobiles and leasehold improvements are recorded at cost.  Depreciation is calculated using the straight-line method over the estimated useful lives of the assets or underlying leases, in respect to leasehold improvements, ranging from three to ten years.

 

Oil and Gas Producing Properties - The Company has elected to follow the successful efforts method of accounting for its oil and gas properties.  Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves.  If an exploratory well does not find proved reserves, the costs of drilling the unsuccessful exploratory well are charged to expense.  Exploratory dry hole costs are included in cash flows from investing activities as part of capital expenditures in the consolidated statements of cash flows.  The cost of development wells, whether productive or not, is capitalized.

 

Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of proved properties and is classified in other operating revenues. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.

 

Depreciation, depletion and amortization (“DD&A”) of capitalized costs of proved oil and gas properties is determined on a field-by-field basis using the units-of-production method based upon proved reserves.  The computation of DD&A takes into consideration restoration, dismantlement and abandonment costs and the anticipated proceeds from equipment salvage.

 

Impairment of Long-Lived Assets - In accordance with FASB ASC Topic 360, “Property, Plant and Equipment” (“ASC Topic 360”), the Company groups assets at the field level and periodically reviews the carrying value of its property and equipment to test whether current events or circumstances indicate that such carrying value may not be recoverable.  If the tests indicate that the carrying value of the asset is greater than the estimated future undiscounted cash flows to be generated by such asset, then an impairment adjustment needs to be recognized.  Such adjustment consists of the amount by which the carrying value of such asset exceeds its fair value.  The Company generally measures fair value by considering sale prices for similar assets or by discounting estimated future cash flows from such asset using an appropriate discount rate.  Considerable management judgment is necessary to estimate the fair value of assets, and accordingly, actual results could vary significantly from such estimates.

 

The Company did not incur any impairment charges during the year ended December 31, 2009.  During 2008, the Company recorded an impairment charge of $0.9 million related to our gathering assets and $4.4 million related to our oil and gas assets.

 

Discount of Debt - The Company recorded a $1.4 million discount on its Amended and Restated Senior Secured Debenture (the “Amended Debenture”) in the first quarter of 2009. The remaining discount on the Amended Debenture at December 31, 2009 of $672,000 is being amortized using the retrospective interest method over the term of the debt, and is included in the balance of the Amended Debenture at December 31, 2009.

 

At December 31, 2008, the remaining discount on the Debentures prior to bankruptcy of $1.6 million was included in the balance of the Debentures.

 

Exploration Expense - The Company accounts for exploration and development activities utilizing the successful efforts method of accounting.  Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases are charged to expense as incurred.  Drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found proved reserves in commercial quantities.  The application of the successful efforts method of accounting requires managerial judgment to determine that proper classification of wells designated as developmental or exploratory is made to

 

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determine the proper accounting treatment of the costs incurred.  The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience.  Wells may be completed that are assumed to be productive but actually deliver oil and gas in quantities insufficient to be economic.  This may result in the abandonment of the wells at a later date.  Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature and an allocation of costs is required to properly account for the results.  The evaluation of oil and leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area.

 

Asset Retirement Obligations - The Company follows FASB ASC Topic 410, “Asset Retirement and Environmental Obligations” (“ASC Topic 410”), to account for its future asset abandonment costs. Estimated future costs associated with the plugging and abandonment of its oil and gas properties are discounted to present values using a risk-adjusted rate over the estimated economic life of the assets.  Such costs are capitalized as part of the cost of the related asset and amortized over the related asset’s estimated useful life.  The associated liability is classified as a long-term liability and is adjusted when circumstances change and for the accretion of expense which is recorded as a component of depreciation, depletion and amortization.  The Company recognizes an estimate of the liability associated with the abandonment of oil and gas properties at the time the well is completed.  The Company estimated its asset retirement obligation liabilities for these wells based on estimated costs to plug and abandon the wells, the estimated life of the wells and its respective ownership percentage in the wells.

 

Share-Based Compensation - At December 31, 2009, the Company had a stock-based employee compensation plan that includes stock options issued to employees and non-employee directors as more fully described in Note 11.  The Company records expense associated with the fair value of stock-based compensation in accordance with FASB ASC Topic 718, “Compensation — Stock Compensation” (“ASC Topic 718”).  The Company currently uses the Black-Scholes option valuation model to determine the fair value of awards and calculate the required disclosures.

 

We have recorded compensation expense associated with all unvested stock options totaling $283,000 and ($92,000) for the years ended December 31, 2009 and 2008, respectively.

 

Net Loss Per Share — The Company accounts for earnings (loss) per share (“EPS”) in accordance with FASB ASC Topic 260, “Earnings per Share” (“ASC Topic 260”).  Under ASC Topic 260, basic EPS is computed by dividing the net loss applicable to common stockholders by the weighted average common shares outstanding without including any potentially dilutive securities.  Diluted EPS is computed by dividing the net loss applicable to common stockholders for the period by the weighted average common shares outstanding plus, when their effect is dilutive, common stock equivalents.

 

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

 

 

 

For the years ended

 

 

 

December 31,

 

 

 

2009

 

2008

 

Warrants

 

1,494,298

 

375,000

 

Options

 

1,332,500

 

551,750

 

Convertible subordinated debt

 

 

3,137,857

 

Restricted stock

 

 

120,000

 

Total potentially dilutive shares excluded

 

2,826,798

 

4,184,607

 

 

Subsequent to December 31, 2009, the Company did not issue any dilutive securities which would have increased the number of potentially dilutive shares.

 

Comprehensive Income (Loss) - We account for comprehensive income (loss) in accordance with FASB ASC Topic 220, “Comprehensive Income” (“ASC Topic 220”), which established standards for the reporting and presentation of comprehensive income in our consolidated financial statements.  For the years ended December 31, 2009 and 2008, comprehensive loss is equal to net loss as reported in our consolidated statement of operations.

 

Off-Balance Sheet Arrangements - 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 (“SPEs”), or SPEs which would have been established for the purpose of facilitating off-balance sheet arrangements or for other contractually narrow or limited purposes.

 

Fair Value of Financial Instruments - The Company’s financial instruments, including cash and cash equivalents, accounts receivable, accounts payable, secured notes and debentures are carried at cost.  At December 31, 2009 and 2008, the fair value of the cash and cash equivalents, accounts receivable, and accounts payable approximates carrying value due to the short term nature of these instruments.  The fair value of the Company’s debentures at December 31, 2009 is $17.8 million, based on a discounted cash flow model using expected future cash flows. The fair value of the Company’s debentures at December 31, 2008 could not be determined.

 

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Concentration of Credit Risk - Revenues from customers which represented 10% or more of the Company’s sales for the years ended December 31, 2009 and 2008 were as follows:

 

 

 

For the year ended

 

 

 

December 31,

 

Customer

 

2009

 

2008

 

 

 

(% of total revenue)

 

 

 

 

 

 

 

A — Exploration and production

 

71.0

%

79.0

%

B — Exploration and production